As filed with
the Securities and Exchange Commission on March 24,
2010
Registration
No. 333-
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF
1933
Oxford Resource Partners,
LP
(Exact Name of Registrant as
Specified in Its Charter)
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Delaware
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1221
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77-10695453
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(State or Other Jurisdiction of
Incorporation or
Organization)
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(Primary Standard Industrial
Classification Code Number)
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(I.R.S. Employer Identification
Number)
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544 Chestnut Street
P.O. Box 427
Coshocton, OH 43812
Phone:
(Address, Including Zip Code,
and Telephone Number,
Including Area Code, of
Registrants Principal Executive Offices)
Jeffrey M. Gutman
Senior Vice President,
Chief Financial Officer and
Treasurer
544 Chestnut Street
P.O. Box 427
Coshocton, OH 43812
Phone:
(Name, Address, Including Zip
Code, and Telephone Number,
Including Area Code, of Agent
for Service)
Copies to:
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William N. Finnegan IV
Brett E. Braden
Latham & Watkins LLP
717 Texas Avenue, Suite 1600
Houston, Texas 77002
(713) 546-5400
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G. Michael OLeary
William J. Cooper
Andrews Kurth LLP
600 Travis, Suite 4200
Houston, Texas 77002
(713) 220-4200
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Approximate date of commencement of proposed sale to the
public:
As soon as practicable after this
Registration Statement becomes effective.
If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to
Rule 415 under the Securities Act of 1933, check the
following
box.
o
If this Form is filed to register additional securities for an
offering pursuant to Rule 462(b) under the Securities Act,
check the following box and list the Securities Act registration
statement number of the earlier effective registration statement
for the same
offering.
o
If this Form is a post-effective amendment filed pursuant to
Rule 462(c) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering.
o
If this Form is a post-effective amendment filed pursuant to
Rule 462(d) under the Securities Act, check the following
box and list the Securities Act registration statement number of
the earlier effective registration statement for the same
offering.
o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer
o
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Accelerated
filer
o
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Non-accelerated
filer
þ
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Smaller reporting
company
o
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(Do not check if a smaller
reporting company)
CALCULATION OF REGISTRATION
FEE
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Proposed Maximum
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Amount of
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Aggregate Offering
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Registration
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Title of Securities to be Registered
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Price
(1)(2)
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Fee
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Common units representing limited partner interests
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$
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250,000,000
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$
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17,825
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(1)
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Includes common units issuable upon
exercise of the underwriters option to purchase additional
common units.
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(2)
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Estimated solely for the purpose of
calculating the registration fee pursuant to Rule 457(o).
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The Registrant hereby amends this Registration Statement on
such date or dates as may be necessary to delay its effective
date until the Registrant shall file a further amendment which
specifically states that this Registration Statement shall
thereafter become effective in accordance with Section 8(a)
of the Securities Act of 1933 or until the Registration
Statement shall become effective on such date as the Securities
and Exchange Commission, acting pursuant to said
Section 8(a), may determine
.
The
information in this preliminary prospectus is not complete and
may be changed. We may not sell these securities until the
registration statement filed with the Securities and Exchange
Commission is effective. This preliminary prospectus is not an
offer to sell these securities and it is not soliciting an offer
to buy these securities in any state where the offer or sale is
not permitted.
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Subject
to Completion, dated March 24, 2010
PROSPECTUS
Oxford
Resource Partners, LP
Common
Units
Representing
Limited Partner Interests
This is the initial
public offering of our common units. We are
offering common
units in this offering. No public market currently exists for
our common units.
We intend to apply
to list our common units on the New York Stock Exchange under
the symbol OXF.
We anticipate the
initial public offering price to be between
$ and
$ per common unit.
Investing in our
common units involves risks. See Risk Factors
beginning on page 19 of this prospectus.
These risks include
the following:
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We may not have
sufficient cash to enable us to pay the minimum quarterly
distribution on our common units following the establishment of
cash reserves by our general partner and the payment of costs
and expenses, including reimbursement of expenses to our general
partner.
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Our general partner
and its affiliates have conflicts of interest, and their limited
fiduciary duties to our unitholders may permit them to favor
their own interests to the detriment of our unitholders.
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Decreases in demand
for electricity and changes in coal consumption patterns of
U.S. electric power generators could adversely affect our
business.
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New and future
regulatory requirements limiting greenhouse gas emissions could
adversely affect coal-fired power generation and reduce the
demand for coal as a fuel source, which could cause the price
and quantity of the coal we sell to decline materially.
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Existing and future
regulatory requirements relating to sulfur dioxide and other air
emissions could affect our customers and could reduce the demand
for the high-sulfur coal we produce and cause coal prices and
sales of our high-sulfur coal to decline materially.
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Competition within
the coal industry may materially and adversely affect our
ability to sell coal at an acceptable price.
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We depend on a
limited number of customers for a significant portion of our
revenues, and the loss of, or significant reduction in,
purchases by any of them could adversely affect our results of
operations and cash available for distribution to our
unitholders.
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Our inability to
acquire additional coal reserves that are economically
recoverable may have a material adverse effect on our future
profitability and growth.
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Our unitholders have
limited voting rights and are not entitled to elect our general
partner or its directors or initially to remove our general
partner without its consent.
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Our unitholders will
be required to pay taxes on their share of our income even if
they do not receive any cash distributions from us.
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Per
Common Unit
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Total
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Public Offering Price
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$
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$
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Underwriting Discount
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$
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$
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Proceeds to us (before expenses)
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$
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$
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We have granted the
underwriters a
30-day
option to purchase up to an
additional common
units on the same terms and conditions set forth above if the
underwriters sell more
than common units
in this offering.
Neither the
Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or
passed upon the accuracy or adequacy of this prospectus. Any
representation to the contrary is a criminal offense.
Barclays Capital, on
behalf of the underwriters, expects to deliver the common units
on or
about ,
2010.
Prospectus
dated ,
2010
TABLE OF
CONTENTS
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1
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1
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3
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3
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4
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5
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5
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6
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7
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8
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9
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9
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9
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11
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16
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19
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19
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32
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38
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43
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44
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45
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46
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46
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47
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48
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53
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56
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56
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57
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58
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61
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61
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62
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64
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65
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65
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68
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72
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72
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72
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75
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76
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76
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83
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i
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85
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89
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90
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91
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91
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91
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92
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93
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93
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94
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96
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97
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98
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98
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99
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99
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101
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102
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103
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103
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104
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108
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110
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111
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111
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112
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113
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113
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114
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124
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124
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124
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125
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128
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137
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137
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138
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138
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138
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139
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140
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140
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141
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141
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142
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144
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144
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145
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145
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ii
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145
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146
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146
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147
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147
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148
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148
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153
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156
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156
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156
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156
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158
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158
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158
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158
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158
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159
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159
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160
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161
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163
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163
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164
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164
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165
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165
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165
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165
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166
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166
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167
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169
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170
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171
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171
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173
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173
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178
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182
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184
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185
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185
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188
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iii
You should rely only on the information contained in this
prospectus, any free writing prospectus prepared by or on behalf
of us or any other information to which we have referred you in
connection with this offering. We have not, and the underwriters
have not, authorized any other person to provide you with
information different from that contained in this prospectus.
Neither the delivery of this prospectus nor the sale of common
units means that information contained in this prospectus is
correct after the date of this prospectus. This prospectus is
not an offer to sell or the solicitation of an offer to buy the
common units in any circumstances under which the offer or
solicitation is unlawful.
Until ,
2010 (25 days after the date of this prospectus), all
dealers that buy, sell or trade our common units, whether or not
participating in this offering, may be required to deliver a
prospectus. This is in addition to the dealers obligation
to deliver a prospectus when acting as underwriters and with
respect to their unsold allotments or subscriptions.
iv
SUMMARY
This summary highlights information contained elsewhere in
this prospectus. You should read the entire prospectus
carefully, including the historical and pro forma consolidated
financial statements and the notes to those financial
statements, before purchasing our common units. The information
presented in this prospectus assumes that the underwriters
option to purchase additional common units is not exercised
unless otherwise noted. You should read Risk Factors
beginning on page 19 for information about important risks
that you should consider before purchasing our common units.
Market and industry data and certain other statistical data
used throughout this prospectus are based on independent
industry publications, government publications and other
published independent sources. In this prospectus, we refer to
information regarding the coal industry in the United States and
internationally that was obtained from the U.S. Department
of Energys Energy Information Administration, or the EIA,
John T. Boyd Company and the U.S. Mine Safety and
Health Administration, or MSHA. These organizations are not
affiliated with us.
References in this prospectus to Oxford Resource
Partners, LP, we, our,
us or like terms refer to Oxford Resource Partners,
LP and its subsidiaries, including our wholly owned subsidiary,
Oxford Mining Company, LLC, which is also our accounting
predecessor. References to Oxford Resources GP or
our general partner refer to Oxford Resources GP,
LLC. We include a glossary of some of the terms used in this
prospectus as
Appendix B
.
Oxford
Resource Partners, LP
We are a low cost producer of high value steam coal, and we are
the largest producer of surface mined coal in Ohio. We focus on
acquiring steam coal reserves that we can efficiently mine with
our modern, large scale equipment. Our reserves and operations
are strategically located in Northern Appalachia and the
Illinois Basin to serve our primary market area of Illinois,
Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. We
market our coal primarily to large utilities with coal-fired,
base-load scrubbed power plants under long-term coal sales
contracts. We believe that we will experience increased demand
for our high-sulfur coal from power plants that have or will
install scrubbers. Currently, there is over 54,500 megawatts of
scrubbed base-load electric generating capacity in our primary
market area and plans have been announced to add over 18,400
megawatts of additional scrubbed capacity by the end of 2017. We
also believe that we will experience increased demand for our
coal from power plants that use coal from Central Appalachia as
production in that region continues to decline.
We currently have 19 active surface mines that are managed as
eight mining complexes. During the fourth quarter of 2009, our
largest mine represented 12.5% of our coal production. This
diversity reduces the risk that operational issues at any one
mine will have a material impact on our business or our results
of operations. Consistent coal quality across many of our mines
and the mobility of our equipment fleet allows us to reliably
serve our customers from multiple mining complexes while
optimizing our mining plan. Our operations also include two
river terminals, strategically located in eastern Ohio and
western Kentucky, that further enhance our ability to supply
coal to our customers with river access from multiple mines.
We produced 5.8 million tons of coal during 2009, including
0.4 million tons produced from the reserves we acquired in
western Kentucky from Phoenix Coal on September 30, 2009.
As a result of this acquisition, our coal production during the
fourth quarter of 2009 was 1.8 million tons, or
7.2 million tons on an annualized basis. During 2009, we
sold 6.3 million tons of coal, including 0.5 million
tons of purchased coal. We currently have long-term coal sales
contracts in place for 2010, 2011, 2012 and 2013 that represent
97.2%, 93.0%, 71.4% and 39.7%, respectively, of our 2010
estimated coal sales of 8.5 million tons. Members of our
senior management team have long-standing relationships within
our industry, and we believe those relationships will allow us
to continue to obtain long-term contracts for our coal
production that will continue to provide us with a reliable and
stable revenue base.
As of December 31, 2009, we controlled 91.6 million
tons of proven and probable coal reserves, of which
68.6 million tons were associated with our surface mining
operations and the remaining 23.0 million tons
1
consisted of underground coal reserves that we have subleased to
a third party in exchange for an overriding royalty.
Historically, we have been successful at replacing the reserves
depleted by our annual production and growing our reserve base
by acquiring reserves with low operational, geologic and
regulatory risks and that were located near our mining
operations or that otherwise had the potential to serve our
primary market area. Over the last five years, we have produced
23.6 million tons of coal and acquired 52.9 million
tons of proven and probable coal reserves, including
24.6 million tons of coal reserves that we acquired in
connection with the Phoenix Coal acquisition. We believe that
our existing relationships with owners of large reserve blocks
and our position as the largest producer of surface mined coal
in Ohio will allow us to continue to acquire reserves in the
future.
For the year ended December 31, 2009, we generated revenues
of approximately $293.8 million, net income attributable to
our unitholders of approximately $23.5 million and Adjusted
EBITDA of approximately $50.8 million. Please read
Selected Historical and Pro Forma Consolidated Financial
and Operating Data for our definition of Adjusted EBITDA
and a reconciliation of Adjusted EBITDA to net income (loss)
attributable to our unitholders. The following table summarizes
our mining complexes, our coal production for the year ended
December 31, 2009 and our coal reserves as of
December 31, 2009:
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Production for the
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As of December 31, 2009
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Year Ended
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Proven &
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Average
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Primary
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December 31,
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Probable
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Average
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Sulfur
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Transportation
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Mining Complexes
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2009
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Reserves
(1)
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Heat Value
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Content
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Methods
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(Btu/lb)
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(%)
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(in million tons)
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Surface Mining Operations:
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Northern Appalachia (principally Ohio)
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Cadiz
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1.1
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12.4
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11,520
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3.3
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Barge, Rail
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Tuscarawas County
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0.9
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8.8
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11,570
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3.7
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Truck
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Belmont County
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1.3
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6.6
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11,510
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3.7
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Barge
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Plainfield
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0.5
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6.4
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11,350
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4.4
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Truck
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New Lexington
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0.6
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4.9
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11,260
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4.0
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Rail
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Harrison
(2)
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0.7
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2.8
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12,040
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1.8
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Barge, Rail, Truck
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Noble County
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0.3
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2.5
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11,230
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4.7
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Barge, Truck
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Illinois Basin (Kentucky)
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Muhlenberg
County
(3)
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0.4
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24.2
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11,295
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3.6
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Barge, Truck
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|
|
|
|
|
Total Surface Mining Operations
|
|
|
5.8
|
|
|
|
68.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Underground Coal Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northern Appalachia (Ohio)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tusky
(4)
|
|
|
|
|
|
|
23.0
|
|
|
|
12,900
|
|
|
|
2.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Underground Coal Reserves
|
|
|
|
|
|
|
23.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
91.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Reported as recoverable coal reserves, which is the portion of
the coal that could be economically and legally extracted or
produced at the time of the reserve determination, taking into
account mining recovery and preparation plant yield. For
definitions of proven coal reserves, probable coal reserves and
recoverable coal reserves, please read
Business Coal Reserves.
|
|
(2)
|
|
The Harrison mining complex is owned by Harrison Resources, LLC,
our joint venture with CONSOL Energy, Inc. We own 51% of
Harrison Resources and CONSOL Energy owns the remaining 49%
through one of its subsidiaries. Because the results of
operations of Harrison Resources are included in our
consolidated financial statements for the year ended
December 31, 2009 as required by U.S. generally accepted
accounting principles, or GAAP, coal production and proven and
probable coal reserves attributable to the Harrison mining
complex are presented on a gross basis assuming we owned 100% of
Harrison Resources. Please read Business
Mining Operations Northern Appalachia
Harrison Mining Complex.
|
2
|
|
|
(3)
|
|
Acquired from Phoenix Coal on September 30, 2009. As a
result, production data represents production from the date of
acquisition though December 31, 2009.
|
|
(4)
|
|
Please read Business Coal Reserves
Underground Coal Reserves for more information about our
underground coal reserves at the Tusky mining complex, which we
have subleased to a third party mining company in exchange for
an overriding royalty. During 2009, we received royalty payments
on 0.6 million tons of coal produced from the Tusky mining
complex.
|
Business
Strategies
Our primary business objective is to maintain and, over time,
increase our cash available for distribution by executing the
following strategies:
|
|
|
|
|
Increasing coal sales to large utilities with coal-fired,
base-load scrubbed power plants in our primary market
area
. In 2009, approximately 69% of the total
electricity generated in our primary market area was generated
by coal-fired power plants, compared to approximately 38% for
the rest of the United States. We intend to continue to focus on
marketing coal to large utilities with coal-fired, base-load
scrubbed power plants in our primary market area of Illinois,
Indiana, Kentucky, Ohio, Pennsylvania and West Virginia.
|
|
|
|
Maximizing profitability by maintaining highly efficient,
diverse and low cost surface mining
operations
. We intend to focus on lowering costs
and improving the productivity of our operations. We believe our
focus on efficient surface mining practices results in our cash
costs being among the lowest of our peers in Northern
Appalachia, which we believe will allow us to compete
effectively, especially during periods of declining coal prices.
We are in the process of implementing the same mining practices
that we currently use in Ohio at the mines that we recently
acquired as a part of the Phoenix Coal acquisition.
|
|
|
|
Generating stable revenue by entering into long-term coal
sales contracts.
We intend to continue to enter
into long-term coal sales contracts for substantially all of our
annual coal production, which will reduce our exposure to
fluctuations in market prices.
|
|
|
|
Continuing to grow our reserve base and production
capacity
. We intend to continue to grow our
reserve base by acquiring reserves with low operational,
geologic and regulatory risks that we can mine economically and
that are located near our mining operations or otherwise have
the potential to serve our primary market area. We intend to
continue to grow our production capacity by expanding our fleet
of large scale equipment and opening new mines as our sales
commitments increase over time.
|
Competitive
Strengths
We believe the following competitive strengths will enable us to
execute our business strategies successfully:
|
|
|
|
|
We have an attractive portfolio of long-term coal sales
contracts.
We believe our long-term coal sales
contracts provide us with a reliable and stable revenue base. We
currently have long-term coal sales contracts in place for 2010,
2011, 2012 and 2013 that represent 97.2%, 93.0%, 71.4% and
39.7%, respectively, of our 2010 estimated coal sales of
8.5 million tons.
|
|
|
|
We have a successful history of growing our reserve base and
production capacity
. Historically, we have been
successful at replacing the reserves depleted by our annual
production and growing our reserve base by acquiring reserves
with low operational, geologic and regulatory risks and that are
located near our mining operations or that otherwise have the
potential to serve our primary market area. We have also been
successful in growing our production capacity by expanding our
fleet of large scale equipment and opening new mines to meet our
sales commitments. Over the last five years, we have produced
23.6 million tons of coal and acquired 52.9 million
tons of proven and probable coal reserves, including
24.6 million tons of coal reserves that we acquired in
connection with the Phoenix Coal acquisition.
|
3
|
|
|
|
|
Our mining operations are flexible and
diverse
. During the fourth quarter of 2009, our
largest mine represented 12.5% of our coal production. We
currently have 19 active surface mines that are managed as eight
mining complexes. Consistent coal quality across many of our
mines and the mobility of our equipment fleet allows us to
reliably serve our customers from multiple mining complexes
while optimizing our mining plan.
|
|
|
|
We are a low cost producer of coal
. We use
efficient mining practices that take advantage of economies of
scale and reduce our operating costs per ton. Our use of large
scale equipment, our good labor relations with our non-union
workforce, our employees expertise and knowledge of our
mining practices, our low level of legacy liabilities and our
history of acquiring reserves without large up-front capital
investments have positioned us as one of the lowest cash cost
coal producers in Northern Appalachia.
|
|
|
|
Both production of, and demand for, the coal we produce are
expected to increase in our primary market
area
. According to the EIA, production of coal in
Northern Appalachia and the Illinois Basin is expected to
increase by 29.2% and 33.1% through 2015, respectively. This
expected increase is attributable to anticipated increases in
demand for high-sulfur coal from scrubbed power plants and from
consumers of Central Appalachia coal as production in that
region continues to decline.
|
|
|
|
Our senior management team and key operational employees have
extensive industry experience
. The members of our
senior management team have, on average, 24 years of
experience in the coal industry and have a track record of
acquiring, building and operating businesses profitably and
safely.
|
|
|
|
We have a strong safety and environmental
record.
We operate some of the industrys
safest mines. From 2006 through 2009, our MSHA reportable
incident rate was on average 14.4% lower than the rate for all
surface coal mines in the United States. We have won numerous
awards for our strong safety and environmental record.
|
Recent
Coal Market Conditions and Trends
Coal consumption and production in the United States have been
driven in recent periods by several market dynamics and trends.
The recent global economic downturn has negatively impacted coal
demand in the short-term, but long-term projections for coal
demand remain positive.
|
|
|
|
|
Favorable long-term outlook for U.S. steam coal
market
. Although domestic coal consumption
declined in 2009 due to the global economic downturn, the EIA
forecasts that domestic coal consumption will increase by 14.4%
through 2015 and by 32.2% through 2035, primarily due to the
projected continued growth in coal-fired electric power
generation demand.
|
|
|
|
Increase in coal production in Northern Appalachia and in the
Illinois Basin.
According to the EIA, coal
production in Northern Appalachia and the Illinois Basin is
expected to grow by 29.2% and 33.1%, respectively, through 2015
and by 35.7% and 42.8%, respectively, through 2035.
|
|
|
|
Decline in coal production in Central
Appalachia
. The EIA forecasts that coal
production in Central Appalachia, the nations second
largest coal production area, will decline by 34.5% through 2015
and by 54.1% through 2035. This decline will be offset by
production from other U.S. regions, including Northern
Appalachia and the Illinois Basin.
|
|
|
|
Expected near-term increases in international demand for
U.S. coal exports
. Although down from the
previous year, U.S. exports began to increase in the second
half of 2009, supported by recovering global economies and
continued rapid growth in electric power generation and steel
production capacity in Asia, particularly in China and India.
Also, increased international demand for higher priced
metallurgical coal has resulted in certain coal from Central
Appalachia and Northern Appalachia, which can serve as either
metallurgical or steam coal, being drawn into the metallurgical
coal export market, which further reduces supplies of steam coal
from this region for domestic consumption.
|
4
|
|
|
|
|
Development of new coal-related technologies will lead to
increased demand for coal
. The EIA projects that
new
coal-to-liquids
plants will account for 32 million tons of annual coal
demand in ten years and that amount will more than double to
68 million tons by 2035. In addition, through the American
Recovery and Reinstatement Act, or ARRA, the
U.S. government has targeted over $1.5 billion to carbon
capture and sequestration, or CCS, research and another
$800 million for the Clean Coal Power Initiative, a
ten-year program supporting commercial application of CCS
technology.
|
|
|
|
Increasingly stringent air quality legislation will continue
to impact the demand for coal
. A series of more
stringent requirements related to particulate matter, ozone,
mercury, sulfur dioxide, nitrogen oxide, carbon dioxide and
other air emissions have been proposed or enacted by federal or
state regulatory authorities in recent years. Considerable
uncertainty is associated with these air quality regulations,
some of which have been the subject of legal challenges in
courts, and the actual timing of implementation remains
uncertain.
|
Our
History
We are a Delaware limited partnership that was formed in August
2007 by American Infrastructure MLP Fund, L.P. and our founders,
Charles C. Ungurean, the President and Chief Executive Officer
of our general partner and a member of the board of directors of
our general partner, and Thomas T. Ungurean, the Senior Vice
President, Equipment, Procurement and Maintenance of our general
partner. Each of our two founders has over 37 years of
experience in the coal mining industry. In connection with our
formation, our founders contributed all of their interests in
Oxford Mining Company to us.
Our founders formed Oxford Mining Company in 1985 to provide
contract mining services to a mining division of a major oil
company. In 1989, our founders transitioned Oxford Mining
Company from a contract miner into a producer of its own coal
reserves. In January 2007, Oxford Mining Company entered into a
joint venture, Harrison Resources, with a subsidiary of CONSOL
Energy to mine surface coal reserves purchased from CONSOL
Energy.
In September 2009, we completed the acquisition of Phoenix
Coals active surface mining operations. The Phoenix Coal
acquisition provided us with an entry into the Illinois Basin in
western Kentucky and included one mining complex comprised of
four mines as well as the Island river terminal on the Green
River in western Kentucky. In connection with this acquisition,
we increased our total proven and probable coal reserves by
24.6 million tons.
Our
Sponsors
American Infrastructure MLP Fund, L.P., together with its
subsidiaries and affiliates, or AIM, is a private investment
firm specializing in natural resources, infrastructure and real
property. AIM, along with certain of the funds that AIM advises,
indirectly owns all of the ownership interests in AIM Oxford
Holdings, LLC, or AIM Oxford. Certain directors of our general
partner are principals of AIM and have ownership interests in
AIM. After completion of this offering, AIM Oxford will continue
to hold 66.3% of the ownership interests in our general partner
and will hold % of our common units
and % of our subordinated units
( % of our total units).
C&T Coal, Inc., or C&T Coal, is owned by our founders,
Charles C. Ungurean and Thomas T. Ungurean. After completion of
this offering, C&T Coal will continue to hold 33.7% of the
ownership interests in our general partner and will
hold % of our common units
and % of our subordinated units
( % of our total units).
In connection with the contribution of Oxford Mining Company to
us in August 2007, C&T Coal, Charles C. Ungurean and Thomas
T. Ungurean agreed that they would not compete with us in the
coal mining business in Illinois, Kentucky, Ohio, Pennsylvania,
West Virginia and Virginia. This non-compete agreement is in
effect until August 24, 2014.
5
Summary
of Risk Factors
An investment in our common units involves risks associated with
our business, our partnership structure and the tax
characteristics of our common units. The following list of risk
factors is not exhaustive. Please read Risk Factors
beginning on page 19 carefully for a more thorough
description of these and other risks.
Risks
Related to Our Business
|
|
|
|
|
We may not have sufficient cash to enable us to pay the minimum
quarterly distribution on our common units following the
establishment of cash reserves by our general partner and the
payment of costs and expenses, including reimbursement of
expenses to our general partner.
|
|
|
|
The assumptions underlying the forecast of cash available for
distribution that we include in Cash Distribution Policy
and Restrictions on Distributions are inherently uncertain
and subject to significant risks that could cause actual results
to differ materially from those forecasted. If we do not achieve
the forecasted results, we may not be able to pay the minimum
quarterly distribution or any amount on our common units and the
market price of our common units may decline materially.
|
|
|
|
Decreases in demand for electricity and changes in coal
consumption patterns of U.S. electric power generators
could adversely affect our business.
|
|
|
|
Our long-term coal sales contracts subject us to renewal risks.
|
|
|
|
Our inability to acquire additional coal reserves that are
economically recoverable may have a material adverse effect on
our future profitability and growth.
|
|
|
|
Competition within the coal industry may materially and
adversely affect our ability to sell coal at an acceptable price.
|
|
|
|
New and future regulatory requirements limiting greenhouse gas
emissions could adversely affect coal-fired power generation and
reduce the demand for coal as a fuel source, which could cause
the price and quantity of the coal we sell to decline materially.
|
|
|
|
Existing and future regulatory requirements relating to sulfur
dioxide and other air emissions could affect our customers and
could reduce the demand for the high-sulfur coal we produce and
cause coal prices and sales of our high-sulfur coal to decline
materially.
|
|
|
|
Our coal mining operations are subject to operating risks, which
could result in materially increased operating expenses and
decreased production levels and could have a material adverse
effect on our business, financial condition or results of
operations.
|
|
|
|
We may not receive cash distributions from Harrison Resources in
the future.
|
|
|
|
We depend on a limited number of customers for a significant
portion of our revenues, and the loss of, or significant
reduction in, purchases by any of them could adversely affect
our results of operations and cash available for distribution to
our unitholders.
|
Risks
Inherent in an Investment in Us
|
|
|
|
|
Our partnership agreement limits our general partners
fiduciary duties to our unitholders and restricts the remedies
available to our unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty.
|
|
|
|
Our general partner and its affiliates have conflicts of
interest, and their limited fiduciary duties to our unitholders
may permit them to favor their own interests to the detriment of
our unitholders.
|
|
|
|
Our unitholders have limited voting rights and are not entitled
to elect our general partner or its directors or initially to
remove our general partner without its consent.
|
6
|
|
|
|
|
Our unitholders will experience immediate and substantial
dilution of $ per common unit.
|
|
|
|
The control of our general partner may be transferred to a third
party without unitholder consent.
|
Tax
Risks
|
|
|
|
|
Our tax treatment depends on our status as a partnership for
federal income tax purposes. If the IRS were to treat us as a
corporation for federal income tax purposes, which would subject
us to entity-level taxation, then our cash available for
distribution to our unitholders would be substantially reduced.
|
|
|
|
If we were subjected to a material amount of additional
entity-level taxation by individual states, it would reduce our
cash available for distribution to our unitholders.
|
|
|
|
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.
|
|
|
|
Certain federal income tax preferences currently available with
respect to coal exploration and development may be eliminated in
future legislation.
|
|
|
|
Our unitholders will be required to pay taxes on their share of
our income even if they do not receive any cash distributions
from us.
|
The
Transactions
Immediately prior to the closing of this offering:
|
|
|
|
|
We will distribute approximately
$ million of cash and
accounts receivable to our general partner, C&T Coal, AIM
Oxford and the participants in the Oxford Resource Partners, LP
Long-Term
Incentive Plan, or our LTIP, pro rata, in accordance with their
respective interests in us.
|
In connection with the closing of this offering, the following
will occur:
|
|
|
|
|
we will enter into a new credit facility;
|
|
|
|
our general partner will convert its 2.0% general partner
interest in us, represented
by general
partner units,
into
general partner units representing a 2.0% general partner
interest in us;
|
|
|
|
C&T Coal will convert all of its Class B common units,
representing a % limited partner
interest in us, into:
(i) common
units, representing a % limited
partner interest in us, and
(ii) subordinated
units, representing a % limited
partner interest in us;
|
|
|
|
AIM Oxford will convert all of its Class B common units,
representing a % limited partner
interest in us, into:
(i) common
units, representing a % limited
partner interest in us, and
(ii) subordinated
units, representing a % limited
partner interest in us;
|
|
|
|
the participants in our LTIP will receive a distribution
of
common units for each common unit they currently own, resulting
in their ownership of an aggregate
of
common units, representing an
aggregate % limited partner
interest in us;
|
|
|
|
we will
issue
common units to the public in this offering, representing an
aggregate % limited partner
interest in us; and
|
|
|
|
we will use the net proceeds from this offering and the net
proceeds from borrowings under our new credit facility for the
purposes set forth in Use of Proceeds.
|
7
Organizational
Structure
The following is a simplified diagram of our ownership structure
after giving effect to this offering and the related
transactions.
|
|
|
|
|
Public common units
|
|
|
|
%
|
Interests of C&T Coal, AIM Oxford and Oxford Resources GP:
|
|
|
|
|
Common units held by C&T Coal
|
|
|
|
%
|
Common units held by AIM Oxford
|
|
|
|
%
|
Subordinated units held by C&T Coal
|
|
|
|
%
|
Subordinated units held by AIM Oxford
|
|
|
|
%
|
General partner units held by Oxford Resources GP
|
|
|
2.0
|
%
|
Common units held by participants in our LTIP
|
|
|
|
%
|
|
|
|
|
|
|
|
|
100
|
%
|
8
Management
and Ownership
We are managed and operated by the board of directors and
executive officers of our general partner, Oxford Resources GP.
Currently, and upon the consummation of this offering, C&T
Coal and AIM Oxford will own all of the ownership interests in
our general partner. Our unitholders will not be entitled to
elect our general partner or its directors or otherwise directly
participate in our management or operation. Charles C. Ungurean,
the President and Chief Executive Officer of our general partner
and a member of the board of directors of our general partner,
and Thomas T. Ungurean, the Senior Vice President, Equipment,
Procurement and Maintenance of our general partner, own all of
the equity interests in C&T Coal. In addition, certain
directors of our general partner are principals of AIM and have
ownership interests in AIM. For information about the executive
officers and directors of our general partner, please read
Management. Our general partner will be liable, as
general partner, for all of our debts (to the extent not paid
from our assets), except for indebtedness or other obligations
that are made specifically nonrecourse to it. Whenever possible,
our general partner intends to cause us to incur indebtedness or
other obligations that are nonrecourse to it.
In order to maintain operational flexibility, our operations
will be conducted through, and our operating assets will be
owned by, Oxford Mining Company and its subsidiaries. However,
we, Oxford Mining Company and its subsidiaries do not have any
employees. All of the employees that conduct our business are
employed by our general partner, but we refer to these
individuals in this prospectus as our employees.
Following the consummation of this offering, our general partner
and its affiliates will not receive any management fee or other
compensation in connection with our general partners
management of our business, but will be reimbursed for expenses
incurred on our behalf. These expenses include the costs of
officer and director and other employee compensation and
benefits properly allocable to us, and all other expenses
necessary or appropriate for the conduct of our business and
allocable to us. Our partnership agreement provides that our
general partner will determine in good faith the expenses that
are allocable to us.
Our general partner owns general partner units representing a
2.0% general partner interest in us, which entitles it to
receive 2.0% of all the distributions we make. Our general
partner also owns all of our incentive distribution rights,
which will entitle it to increasing percentages, up to a maximum
of 48%, of the cash we distribute in excess of
$ per unit per quarter, after the
closing of our initial public offering. Please read
Certain Relationships and Related Party Transactions.
Principal
Executive Offices
Our principal executive offices are located at 544 Chestnut
Street, Coshocton, Ohio 43812. Our phone number
is .
Following the completion of this offering, our website will be
located at
http://www.oxfordresources.com.
We expect to make our periodic reports and other information
filed with or furnished to the SEC available, free of charge,
through our website, as soon as reasonably practicable after
those reports and other information are electronically filed
with or furnished to the SEC. Information on our website or any
other website is not incorporated by reference into this
prospectus and does not constitute a part of this prospectus.
Summary
of Conflicts of Interest and Fiduciary Duties
General.
Our general partner and its directors
and officers have a legal duty to manage us in a manner
beneficial to our unitholders. This legal duty originates under
state law in statutes and judicial decisions and is commonly
referred to as a fiduciary duty. However, because
our general partner is owned by C&T Coal and AIM Oxford,
the directors and officers of our general partner also have
fiduciary duties to manage the business of our general partner
in a manner beneficial to C&T Coal and AIM Oxford. As a
result, conflicts of interest may arise in the future between us
and our unitholders, on the one hand, and our general partner
and its affiliates, on the other hand. For a more detailed
description of the conflicts of interest and fiduciary duties of
our general partner, please read Conflicts of Interest and
Fiduciary Duties.
9
Partnership Agreement Modifications of Fiduciary
Duties.
Delaware law provides that Delaware
limited partnerships may, in their partnership agreements,
restrict or expand the fiduciary duties owed by the general
partner to limited partners and the partnership. Our partnership
agreement limits the liability of, and reduces the fiduciary
duties owed by, our general partner and the directors and
officers of our general partner to our unitholders. Our
partnership agreement also restricts the remedies available to
our unitholders for actions that might otherwise constitute
breaches of fiduciary duty by our general partner and its
directors and officers. By purchasing a common unit, our
unitholders are treated as having consented to various actions
contemplated in the partnership agreement and conflicts of
interest that might otherwise be considered a breach of
fiduciary or other duties under applicable law. Please read
Conflicts of Interest and Fiduciary Duties
Fiduciary Duties for a description of the fiduciary duties
imposed on our general partner and its directors and officers by
Delaware law, the material modifications of these duties
contained in our partnership agreement and certain legal rights
and remedies available to our unitholders.
For a description of our other relationships with our
affiliates, please read Certain Relationships and Related
Party Transactions.
10
The
Offering
|
|
|
Common units offered to the public
|
|
common
units.
|
|
|
|
common
units if the underwriters exercise their option to purchase
additional common units in full.
|
|
Units outstanding after this offering
|
|
common
units representing a % limited
partner interest in us
and
subordinated units representing a %
limited partner interest in us.
|
|
|
|
Our general partner will
own
general partner units, representing a 2.0% general partner
interest in us.
|
|
Use of proceeds
|
|
We intend to use the net proceeds from this offering of
approximately $ million
(based on the mid-point of the price range set forth on the
cover page of this prospectus), after deducting underwriting
discounts and commissions but before paying offering expenses,
to (i) repay in full the outstanding balance under our
existing credit facility, (ii) distribute approximately
$ million to C&T Coal,
(iii) distribute approximately
$ million to certain
participants in our LTIP, (iv) pay offering expenses of
approximately $ million and
(v) replenish approximately
$ million of our working
capital. We will use the proceeds from borrowings of
approximately $ million under
our new credit facility to (i) distribute approximately
$ million to AIM Oxford and
(ii) pay fees and expenses relating to our new credit
facility of approximately $ .
|
|
|
|
If the underwriters option to purchase additional common
units is exercised in full, we will use the net proceeds to
redeem from C&T Coal and AIM Oxford a number of common
units equal to the number of common units issued upon such
exercise, at a price per common unit equal to the proceeds per
common unit before expenses but after deducting underwriting
discounts and commissions.
|
|
|
|
Please read Use of Proceeds.
|
|
Cash distributions
|
|
We intend to make a minimum quarterly distribution of
$
per common unit (or $ per common
unit on an annualized basis) to the extent we have sufficient
cash after the establishment of cash reserves by our general
partner and the payment of our costs and expenses, including
reimbursement of expenses to our general partner and its
affiliates.
|
|
|
|
Our ability to pay cash distributions at this minimum quarterly
distribution rate is subject to various restrictions and other
factors described in more detail under Cash Distribution
Policy and Restrictions on Distributions.
|
|
|
|
We will adjust the minimum quarterly distribution for the period
from the closing of this offering
through ,
2010 based on the actual length of the period.
|
|
|
|
Our partnership agreement requires us to distribute all of our
cash on hand at the end of each quarter after the payment of
costs and
|
11
|
|
|
|
|
expenses, less reserves established by our general partner. We
refer to this cash as available cash, and we define
its meaning in our partnership agreement, in How We Make
Cash Distributions Distributions of Available
Cash Definition of Available Cash and in the
glossary of terms attached as
Appendix B
.
|
|
|
|
In general, we will pay any cash distributions we make each
quarter in the following manner:
|
|
|
|
first
, 98% to the holders
of common units and 2.0% to our general partner, until each
common unit has received a minimum quarterly distribution of
$ plus any arrearages from prior
quarters;
|
|
|
|
second
, 98% to the holders
of subordinated units and 2.0% to our general partner, until
each subordinated unit has received a minimum quarterly
distribution of
$ ;
and
|
|
|
|
third
, 98% to all
unitholders, pro rata, and 2.0% to our general partner, until
each unit has received a distribution of
$ .
|
|
|
|
If cash distributions to our unitholders exceed
$ per common and subordinated unit
in any quarter, our unitholders and our general partner will
receive distributions according to the following percentage
allocations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marginal Percentage Interest in
|
Total Quarterly Distribution
|
|
Distributions
|
Target Amount
|
|
Unitholders
|
|
General Partner
|
|
above $ up to
$
|
|
85%
|
|
15%
|
above $ up to
$
|
|
75%
|
|
25%
|
above $
|
|
50%
|
|
50%
|
|
|
|
|
|
Please read How We Make Cash Distribution
General Partner Interest and Incentive Distribution Rights.
|
|
|
|
Historical cash available for distribution generated during the
year ended December 31, 2009 would have been sufficient to
allow us to pay %
and % of the minimum quarterly
distribution ($ per quarter, or
$ on an annualized basis) on our
common units and subordinated units, respectively.
|
|
|
|
Please read Cash Distribution Policy and Restrictions on
Distributions Historical and Forecasted Results of
Operations and Cash Available for Distribution.
|
|
|
|
We have included a forecast of our cash available for
distribution for the twelve months ending June 30, 2011 in
Cash Distribution Policy and Restrictions on
Distributions Historical and Forecasted Results of
Operations and Cash Available for Distribution. We
believe, based on our financial forecast and related
assumptions, that we will have sufficient available cash to
enable us to pay the full minimum quarterly distribution of
$ on all of our common units and
subordinated units and the related distribution on our general
partners 2.0% general partner interest for the four
quarters ending June 30, 2011. The amount of available cash
we need to pay the minimum quarterly distribution for four
quarters on our common units, subordinated units and
|
12
|
|
|
|
|
general partner units to be outstanding immediately after this
offering is approximately
$ million. Based on our
financial forecast and related assumptions, we forecast that our
cash available for distribution for the twelve months ending
June 30, 2011 will be approximately
$ million.
|
|
|
|
Although we do not anticipate any, distributions out of capital
surplus, as opposed to operating surplus, will constitute a
return of capital to our unitholders and will result in a
reduction in the minimum quarterly distribution and target
distribution levels. For a further description of this treatment
of distributions from capital surplus, please read How We
Make Cash Distributions Distributions from Capital
Surplus Effect of a Distribution from Capital
Surplus.
|
|
Subordinated units
|
|
C&T Coal and AIM Oxford will initially own all of our
subordinated units. The principal difference between our common
units and subordinated units is that, in any quarter during the
subordination period, the subordinated units are not entitled to
receive any distributions of available cash until the common
units have received the minimum quarterly distribution plus any
arrearages in the payment of the minimum quarterly distribution
from prior quarters. Subordinated units will not accrue
arrearages.
|
|
Conversion of subordinated units
|
|
The subordination period will end on the first business day
after we have earned and paid from operating surplus generated
in the applicable period at least
(i) $ (the minimum quarterly
distribution on an annualized basis) on each outstanding common
and subordinated unit and the corresponding distribution on our
general partner units for each of three consecutive,
non-overlapping four quarter periods ending on or after
June 30, 2013 or (ii) $
per quarter (150% of the minimum quarterly distribution, which
is $ on an annualized basis) on
each outstanding common and subordinated unit and the
corresponding distributions on our general partner units for
each of four consecutive quarters, in each case provided there
are no arrearages on our common units at that time.
|
|
|
|
In addition, the subordination period will end upon the removal
of our general partner other than for cause if the units held by
our general partner and its affiliates are not voted in favor of
such removal.
|
|
|
|
When the subordination period ends, all subordinated units will
convert into common units on a
one-for-one
basis, and the common units will no longer be entitled to
arrearages. Please read How We Make Cash
Distributions Subordination Period.
|
|
General partners right to reset the target distribution
levels
|
|
Our general partner has the right, at a time when there are no
subordinated units outstanding and it has received incentive
distributions at the highest level to which it is entitled (48%)
for each of the prior four consecutive fiscal quarters, to reset
the initial cash target distribution levels at higher levels
based on the distribution at the time of the exercise of the
reset election. Following a reset election by our general
partner, the minimum
|
13
|
|
|
|
|
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
the same 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 common units and
additional general partner units. The number of common units to
be issued to our general partner will be equal to the number of
common units that would have entitled their holder to an
aggregate quarterly cash distribution equal to the average of
the distributions to our general partner on the incentive
distribution rights in the prior two quarters, assuming a per
unit distribution equal to the average of the distribution for
the prior two quarters. Our general partner will be issued the
number of general partner units necessary to maintain its
general partner interest in us immediately prior to the reset
election. Please read How We Make Cash
Distributions General Partners Right to Reset
Incentive Distribution Levels.
|
|
Issuance of additional units
|
|
Our partnership agreement authorizes us to issue an unlimited
number of additional units without the approval of our
unitholders. Please read Units Eligible for Future
Sale and The Partnership Agreement
Issuance of Additional Securities.
|
|
Limited voting rights
|
|
Our general partner will manage and operate us. Unlike the
holders of common stock in a corporation, our unitholders will
have only limited voting rights on matters affecting our
business. Our unitholders will have no right to elect our
general partner or its directors on an annual or other
continuing basis. Our general partner may not be removed except
by a vote of the holders of at least 80% of the outstanding
units, including any units owned by our general partner and its
affiliates, voting together as a single class. Upon consummation
of this offering, our general partner and its affiliates will
own an aggregate of % of our common
and subordinated units. This will give our general partner the
ability to prevent its involuntary removal. Please read
The Partnership Agreement Voting Rights.
|
|
Limited call right
|
|
If at any time our general partner and its affiliates own more
than 80% of the outstanding common units, our general partner
has the right, but not the obligation, to purchase all of the
remaining common units at a price not less than the then-current
market price of the common units. Please read The
Partnership Agreement Limited Call Right.
|
|
Estimated ratio of taxable income to distributions
|
|
We estimate that if you own the common units you purchase in
this offering through the record date for distributions for the
period ending December 31, 2013, you will be allocated, on
a cumulative basis, an amount of federal taxable income for that
period that will be % or less of
the cash distributed with respect to that period. For example,
if you receive an annual distribution of
$ per unit, we estimate that your
average allocable federal taxable income per year will be no
more than $ per unit. Please read
Material Federal Income Tax Consequences Tax
Consequences
|
14
|
|
|
|
|
of Unit Ownership Ratio of Taxable Income to
Distributions for the basis of this estimate.
|
|
Material federal income tax consequences
|
|
For a discussion of other material federal income tax
consequences that may be relevant to prospective unitholders who
are individual citizens or residents of the United States,
please read Material Federal Income Tax Consequences.
|
|
Exchange listing
|
|
We intend to apply to list our common units on the New York
Stock Exchange under the symbol OXF.
|
15
Summary
Historical and Pro Forma Consolidated Financial and Operating
Data
The following table presents our summary historical consolidated
financial and operating data, as well as that of our accounting
predecessor and wholly owned subsidiary, Oxford Mining Company,
as of the dates and for the periods indicated. The following
table also presents our summary pro forma consolidated financial
and operating data as of the dates and for the periods indicated.
The summary historical consolidated financial data presented for
the period from January 1, 2007 to August 23, 2007 are
derived from the audited historical consolidated financial
statements of Oxford Mining Company that are included elsewhere
in this prospectus. The summary historical consolidated
financial data presented as of December 31, 2007 for the
period from August 24, 2007 to December 31, 2007 and
as of and for the years ended December 31, 2008 and 2009
are derived from our audited historical consolidated financial
statements that are included elsewhere in this prospectus.
The summary pro forma consolidated financial data presented as
of and for the year ended December 31, 2009 are derived
from our unaudited pro forma consolidated financial statements
included elsewhere in this prospectus. Our unaudited pro forma
consolidated financial statements give pro forma effect to
(i) the Phoenix Coal acquisition and (ii) this
offering and the transactions related to this offering described
in Summary The Transactions and the
application of the net proceeds from this offering described in
Use of Proceeds. The unaudited pro forma
consolidated balance sheet assumes this offering occurred as of
December 31, 2009. The unaudited pro forma consolidated
statement of operations for the year ended December 31,
2009 assumes the Phoenix Coal acquisition, this offering and the
transactions related to this offering occurred as of
January 1, 2009. We have not given pro forma effect to
incremental selling, general and administrative expenses of
approximately $3.0 million that we expect to incur as a
result of being a publicly traded partnership.
For a detailed discussion of the following table, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations. The following table
should also be read in conjunction with
Summary The Transactions, Use of
Proceeds, Business Our History,
the historical consolidated financial statements of Oxford
Mining Company, the historical combined financial statements for
the carved-out surface mining operations of Phoenix Coal and our
unaudited pro forma consolidated financial statements and
audited consolidated financial statements included elsewhere in
this prospectus. Among other things, those historical and pro
forma consolidated financial statements include more detailed
information regarding the basis of presentation for the
information in the following table.
The following table presents a non-GAAP financial measure,
Adjusted EBITDA, which we use in our business as it is an
important supplemental measure of our performance. Adjusted
EBITDA represents net income (loss) attributable to our
unitholders before interest, taxes, depreciation, depletion and
amortization, gain from purchase of a business, amortization of
below-market coal sales contracts and non-cash equity
compensation expense. This measure is not calculated or
presented in accordance with GAAP. We explain this measure below
and reconcile it to its most directly comparable financial
measure calculated and presented in accordance with GAAP.
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
Oxford Mining Company
|
|
|
|
|
|
|
|
Oxford Resource
|
|
|
|
|
(Predecessor)
|
|
|
|
Oxford Resource Partners, LP
|
|
|
|
Partners, LP
|
|
|
|
|
Period from January 1,
|
|
|
|
Period from August 24,
|
|
|
|
Year Ended
|
|
|
|
Year Ended
|
|
|
|
Year Ended
|
|
|
|
|
2007 to August 23,
|
|
|
|
2007 to December 31,
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
|
2007
|
|
|
|
2007
|
|
|
|
2008
|
|
|
|
2009
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
(in thousands, except per ton amounts)
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
|
$
|
96,799
|
|
|
|
$
|
61,324
|
|
|
|
$
|
193,699
|
|
|
|
$
|
254,171
|
|
|
|
$
|
312,490
|
|
Transportation revenue
|
|
|
|
18,083
|
|
|
|
|
10,204
|
|
|
|
|
31,839
|
|
|
|
|
32,490
|
|
|
|
|
37,221
|
|
Royalty and non-coal revenue
|
|
|
|
3,267
|
|
|
|
|
1,407
|
|
|
|
|
4,951
|
|
|
|
|
7,183
|
|
|
|
|
7,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
|
118,149
|
|
|
|
|
72,935
|
|
|
|
|
230,489
|
|
|
|
|
293,844
|
|
|
|
|
356,894
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales (excluding DD&A, shown separately)
|
|
|
|
70,415
|
|
|
|
|
40,721
|
|
|
|
|
151,421
|
|
|
|
|
170,698
|
|
|
|
|
213,446
|
|
Cost of purchased coal
|
|
|
|
17,494
|
|
|
|
|
9,468
|
|
|
|
|
12,925
|
|
|
|
|
19,487
|
|
|
|
|
29,792
|
|
Cost of transportation
|
|
|
|
18,083
|
|
|
|
|
10,204
|
|
|
|
|
31,839
|
|
|
|
|
32,490
|
|
|
|
|
37,221
|
|
Depreciation, depletion, and amortization
|
|
|
|
9,025
|
|
|
|
|
4,926
|
|
|
|
|
16,660
|
|
|
|
|
25,902
|
|
|
|
|
31,424
|
|
Selling, general and administrative expenses
|
|
|
|
3,643
|
|
|
|
|
2,114
|
|
|
|
|
9,577
|
|
|
|
|
13,242
|
|
|
|
|
25,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
|
118,660
|
|
|
|
|
67,433
|
|
|
|
|
222,422
|
|
|
|
|
261,819
|
|
|
|
|
337,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
|
(511
|
)
|
|
|
|
5,502
|
|
|
|
|
8,067
|
|
|
|
|
32,025
|
|
|
|
|
19,276
|
|
Interest income
|
|
|
|
26
|
|
|
|
|
55
|
|
|
|
|
62
|
|
|
|
|
35
|
|
|
|
|
39
|
|
Interest expense
|
|
|
|
(2,386
|
)
|
|
|
|
(3,498
|
)
|
|
|
|
(7,720
|
)
|
|
|
|
(6,484
|
)
|
|
|
|
(6,341
|
)
|
Gain from purchase of
business
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,823
|
|
|
|
|
3,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
|
(2,871
|
)
|
|
|
|
2,059
|
|
|
|
|
409
|
|
|
|
|
29,399
|
|
|
|
|
16,797
|
|
Less: Net income attributable to noncontrolling interest
|
|
|
|
(682
|
)
|
|
|
|
(537
|
)
|
|
|
|
(2,891
|
)
|
|
|
|
(5,895
|
)
|
|
|
|
(5,895
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Oxford Resource Partners, LP
unitholders
|
|
|
$
|
(3,553
|
)
|
|
|
$
|
1,522
|
|
|
|
$
|
(2,482
|
)
|
|
|
$
|
23,504
|
|
|
|
$
|
10,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
|
$
|
17,634
|
|
|
|
$
|
(8,478
|
)
|
|
|
$
|
33,951
|
|
|
|
$
|
35,540
|
|
|
|
|
|
|
Investing activities
|
|
|
|
(16,619
|
)
|
|
|
|
(103,336
|
)
|
|
|
|
(23,901
|
)
|
|
|
|
(51,115
|
)
|
|
|
|
|
|
Financing activities
|
|
|
|
(234
|
)
|
|
|
|
111,274
|
|
|
|
|
4,494
|
|
|
|
|
3,762
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA
(2)
|
|
|
$
|
7,832
|
|
|
|
$
|
9,145
|
|
|
|
$
|
20,349
|
|
|
|
$
|
50,799
|
|
|
|
$
|
39,016
|
|
Maintenance capital
expenditures
(3)
|
|
|
|
13,020
|
|
|
|
|
4,841
|
|
|
|
|
21,529
|
|
|
|
|
27,461
|
|
|
|
|
27,461
|
|
Distributions
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12,503
|
|
|
|
|
13,407
|
|
|
|
|
|
|
Balance Sheet Data (at period end):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
$
|
1,175
|
|
|
|
$
|
635
|
|
|
|
$
|
15,179
|
|
|
|
$
|
3,366
|
|
|
|
$
|
30,769
|
|
Trade accounts receivable
|
|
|
|
18,396
|
|
|
|
|
17,547
|
|
|
|
|
21,528
|
|
|
|
|
24,403
|
|
|
|
|
2,000
|
|
Inventory
|
|
|
|
4,824
|
|
|
|
|
4,655
|
|
|
|
|
5,134
|
|
|
|
|
8,801
|
|
|
|
|
8,801
|
|
PPE, net
|
|
|
|
54,510
|
|
|
|
|
106,408
|
|
|
|
|
112,446
|
|
|
|
|
149,461
|
|
|
|
|
149,461
|
|
Total assets
|
|
|
|
90,893
|
|
|
|
|
146,774
|
|
|
|
|
171,297
|
|
|
|
|
203,363
|
|
|
|
|
209,726
|
|
Total debt (current and long-term)
|
|
|
|
43,165
|
|
|
|
|
75,654
|
|
|
|
|
83,977
|
|
|
|
|
95,711
|
|
|
|
|
98,711
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons of coal produced
|
|
|
|
2,693
|
|
|
|
|
1,634
|
|
|
|
|
5,089
|
|
|
|
|
5,846
|
|
|
|
|
7,221
|
|
Tons of coal purchased
|
|
|
|
641
|
|
|
|
|
305
|
|
|
|
|
434
|
|
|
|
|
530
|
|
|
|
|
885
|
|
Tons of coal sold
|
|
|
|
3,333
|
|
|
|
|
1,938
|
|
|
|
|
5,528
|
|
|
|
|
6,311
|
|
|
|
|
8,051
|
|
Average sales price per
ton
(4)
|
|
|
$
|
29.04
|
|
|
|
$
|
31.64
|
|
|
|
$
|
35.04
|
|
|
|
$
|
40.27
|
|
|
|
$
|
38.81
|
|
Cost of coal sales per ton
produced
(5)
|
|
|
$
|
26.15
|
|
|
|
$
|
24.92
|
|
|
|
$
|
29.75
|
|
|
|
$
|
29.20
|
|
|
|
$
|
29.56
|
|
Cost of purchased coal per
ton
(6)
|
|
|
$
|
27.29
|
|
|
|
$
|
31.08
|
|
|
|
$
|
29.81
|
|
|
|
$
|
36.79
|
|
|
|
$
|
33.66
|
|
|
|
|
(1)
|
|
On September 30, 2009, we acquired all of the active
surfacing mining operations of Phoenix Coal. The purchase price
of this acquisition was less than the fair value of the net
assets and liabilities we acquired. We recorded this difference
as a gain of $3.8 million for the year ending
December 31, 2009.
|
|
(2)
|
|
See Selected Historical and Pro Forma Consolidated
Financial and Operating Data for our definition of
Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net
income attributable to our unitholders.
|
17
|
|
|
(3)
|
|
Maintenance capital expenditures are cash expenditures made to
maintain or replace, including over the long term, our operating
capacity, asset base or operating income. Examples of
maintenance capital expenditures include capital expenditures
associated with the replacement of equipment and coal reserves,
whether through the expansion of an existing mine or the
acquisition or development of new reserves, to the extent such
expenditures are made to maintain our operating capacity, asset
base or operating income. Historically, we have not made a
distinction between maintenance capital expenditures and other
capital expenditures. For purposes of this presentation,
however, we have evaluated our historical capital expenditures
to estimate which of them would have been maintenance capital
expenditures had we classified them as such at the time they
were made. The amounts shown reflect our estimates based on that
evaluation.
|
|
(4)
|
|
Represents our coal sales divided by total tons of coal sold.
|
|
(5)
|
|
Represents our cost of coal sales (excluding DD&A) divided
by the tons of coal we produce.
|
|
(6)
|
|
Represents the cost of purchased coal divided by the tons of
coal we purchase.
|
18
RISK
FACTORS
Limited partner interests are inherently different from the
capital stock of a corporation, although many of the business
risks to which we are subject are similar to those that would be
faced by a corporation engaged in a similar business. You should
carefully consider the following risk factors together with all
of the other information included in this prospectus in
evaluating an investment in our common units.
If any of the following risks were to occur, our business,
financial condition, results of operations and cash available
for distribution could be materially adversely affected. In that
case, we might not be able to make distributions on our common
units, the trading price of our common units could decline and
you could lose all or part of your investment.
Risks
Related to Our Business
We may not have sufficient cash to enable us to pay the
minimum quarterly distribution on our common units following the
establishment of cash reserves by our general partner and the
payment of costs and expenses, including reimbursement of
expenses to our general partner.
We may not have sufficient cash each quarter to pay the minimum
quarterly distribution. 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 level of our production and coal sales and the amount of
revenue we generate;
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the level of our operating costs, including reimbursement of
expenses to our general partner;
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changes in governmental regulation of the mining industry or the
electric power industry and the increased costs of complying
with those changes;
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|
our ability to obtain, renew and maintain permits on a timely
basis;
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prevailing economic and market conditions; and
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|
difficulties in collecting our receivables because of credit or
financial problems of major customers.
|
In addition, the actual amount of cash we will have available
for distribution will depend on other factors, such as:
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|
|
the level of capital expenditures we make;
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|
the restrictions contained in our credit agreement and our debt
service requirements;
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the cost of acquisitions;
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fluctuations in our working capital needs;
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our ability to borrow funds and access capital markets; and
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the amount of cash reserves established by our general partner.
|
For a description of additional restrictions and factors that
may affect our ability to make cash distributions, please read
Cash Distribution Policy and Restrictions on
Distributions.
The assumptions underlying the forecast of cash available
for distribution that we include in Cash Distribution
Policy and Restrictions on Distributions are inherently
uncertain and subject to significant risks that could cause
actual results to differ materially from those forecasted. If we
do not achieve the forecasted results, we may not be able to pay
the minimum quarterly distribution or any amount on our common
units and the market price of our common units may decline
materially.
The forecast of cash available for distribution set forth in
Cash Distribution Policy and Restrictions on
Distributions includes our forecast of our results of
operations and cash available for distribution for the twelve
months ending June 30, 2011. The financial forecast has
been prepared by management, and we have neither received nor
requested an opinion or report on it from our or any other
independent auditor. The
19
assumptions underlying the forecast are inherently uncertain and
are subject to significant business, economic, regulatory and
competitive risks, including those discussed below, that could
cause actual results to differ materially from those forecasted.
If we do not achieve the forecasted results, we may not be able
to pay the minimum quarterly distribution or any amount on our
common units or subordinated units and the market price of our
common units may decline materially.
The amount of available cash we need to pay the minimum
quarterly distribution for four quarters on our common units,
subordinated units and general partner units to be outstanding
immediately after this offering is approximately
$ million. Historical cash
available for distribution generated during the year ended
December 31, 2009 would have been sufficient to allow us to
pay %
and % of the minimum quarterly
distribution ($ per quarter, or
$ on an annualized basis) on our
common units and subordinated units, respectively. For a
calculation of our ability to make distributions to unitholders
based on our historical results for the year ended
December 31, 2009 and for a forecast of our ability to pay
the full minimum quarterly distribution on our common units,
subordinated units and general partner units for the twelve
months ending June 30, 2011, please read Cash
Distribution Policy and Restrictions on Distributions.
Decreases in demand for electricity and changes in coal
consumption patterns of U.S. electric power generators could
adversely affect our business.
Our business is closely linked to domestic demand for
electricity. In 2009 we sold approximately 89% of our coal to
domestic electric power generators, and we have long-term
contracts in place with these electric power generators for a
significant portion of our future production. In addition,
because our business is linked to domestic demand for
electricity, any changes in coal consumption by
U.S. electric power generators would likely impact our
business over the long term. The amount of coal consumed by
electric power generation is affected by, among other things:
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|
|
|
|
general economic conditions, particularly those affecting
industrial electric power demand;
|
|
|
|
indirect competition from alternative fuel sources for power
generation, such as natural gas, fuel oil, nuclear,
hydroelectric, wind and solar power, and the location,
availability, quality and price of those alternative fuel
sources;
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|
|
|
environmental and other governmental regulations, including
those impacting coal-fired power plants; and
|
|
|
|
energy conservation efforts and related governmental policies.
|
Historically, demand for electricity has decreased during
periods of economic downturn, such as the recent downturn in the
U.S. economy and financial markets. According to the EIA,
total electricity consumption in the United States fell by
approximately 3.8% during 2009 compared with 2008, primarily
because of the effect of the economic downturn on industrial
electricity demand, and U.S. electric generation from coal
fell by approximately 11.0% in 2009 compared with 2008. Further
decreases in the demand for electricity, such as decreases that
could be caused by a worsening of current economic conditions, a
prolonged economic recession or other similar events, could have
a material adverse effect on the demand for coal and on our
business over the long term.
Changes in the coal industry, such as those caused by decreased
electricity demand and increased competition, may also cause
some of our customers not to renew, extend or enter into new
long-term coal sales contracts with us or to enter into
agreements to purchase reduced quantities of coal than in the
past or on different terms or prices. Indirect competition from
gas-fired generation has the most potential to displace a
significant amount of coal-fired generation in the near term,
particularly older, less efficient coal-powered generators. We
expect that many of the new power plants needed in the future to
meet increased demand for electricity will be fired by natural
gas because gas-fired plants are cheaper to construct and
permits to construct these plants are easier to obtain, and may
be less prone to challenge, because natural-gas fired generators
are viewed as having a lower environmental impact than
coal-fired generators. In addition, uncertainty caused by
federal and state regulations could cause coal customers to be
uncertain of their coal requirements in future years and could
deter them from entering into new, or extending or renewing
existing, long-term coal sales contracts.
20
Our
long-term coal sales contracts subject us to renewal
risks.
We sell most of the coal we produce under long-term coal sales
contracts, which we define as contracts with terms greater than
one year. As a result, our results of operations are dependent
upon the prices we receive for the coal we sell under these
contracts. To the extent we are not successful in renewing,
extending or renegotiating our long-term contracts on favorable
terms, we may have to accept lower prices for the coal we sell
or sell reduced quantities of coal in order to secure new sales
contracts for our coal. Prices and quantities under our
long-term coal sales contracts are generally based on
expectations of future coal prices at the time the contract is
entered into, renewed, extended or re-opened. The expectation of
future prices for coal depends upon factors beyond our control,
including the following:
|
|
|
|
|
domestic and foreign supply and demand for coal, including
demand for U.S. coal exports from eastern U.S. markets;
|
|
|
|
domestic demand for electricity, which tends to follow changes
in general economic activity;
|
|
|
|
domestic and foreign economic conditions;
|
|
|
|
the price, quantity and quality of other coal available to our
customers;
|
|
|
|
competition for production of electricity from non-coal sources,
including the price and availability of alternative fuels and
other sources, such as natural gas, fuel oil, nuclear,
hydroelectric, wind and solar power, and the effects of
technological developments related to these non-coal energy
sources;
|
|
|
|
domestic air emission standards for coal-fired power plants, and
the ability of coal-fired power plants to meet these standards
by installing scrubbers, purchasing emissions allowances or
other means; and
|
|
|
|
legislative and judicial developments, regulatory changes, or
changes in energy policy and energy conservation measures that
would adversely affect the coal industry.
|
Two of our long-term coal sales contracts contain market-based
re-opener provisions that permit the sales price
terms to be adjusted every three years. For 2011, 2012 and 2013,
0.4 million tons, 0.4 million tons and
0.6 million tons of coal, respectively, that we have
committed to deliver under our long-term coal sales contracts
are subject to price re-openers. Under these re-openers, the
failure of the parties to agree on a new market-based price
gives either party the right to terminate the contract. While
these re-openers can benefit us during periods of rising coal
prices, they have the potential to adversely affect us during
periods of declining coal prices.
Our
inability to acquire additional coal reserves that are
economically recoverable may have a material adverse effect on
our future profitability and growth.
Our profitability depends substantially on our ability to mine,
in a cost-effective manner, coal reserves that possess the
quality characteristics our customers desire. Because our
reserves decline as we mine our coal, our future profitability
and growth depend upon our ability to acquire additional coal
reserves that are economically recoverable to replace the
reserves we produce. If we fail to acquire or develop sufficient
additional reserves to replace the reserves depleted by our
production, our existing reserves will eventually be depleted.
Please read Business Coal Reserves.
Competition within the coal industry may materially and
adversely affect our ability to sell coal at an acceptable
price.
We compete for domestic sales with numerous other coal producers
in Northern Appalachia and the Illinois Basin and in other coal
producing regions of the United States, primarily Central
Appalachia and the Powder River Basin, or the PRB. The most
important factors on which we compete are delivered price (i.e.,
the cost of coal delivered to the customer, including
transportation costs, which are generally paid by our customers
either directly or indirectly), coal quality characteristics
(primarily heat, sulfur, ash and moisture content) and
reliability of supply. For example, even though PRB coal must be
transported by rail over long distances at substantial
transportation cost to reach our primary market area, its
delivered cost can be competitive with coal from other domestic
coal-producing regions. Our competitors may have, among other
21
things, greater liquidity, greater access to credit and other
financial resources, newer or more efficient equipment, lower
cost structures, partnerships with transportation companies or
more effective risk management policies and procedures. In
addition, competition within the U.S. coal industry will
increase in periods of reduced foreign demand for domestic coal,
as more domestic coal production is marketed in the United
States. Our failure to compete successfully with our competitors
could have a material adverse effect on our business, financial
condition or results of operations.
New and future regulatory requirements limiting greenhouse
gas emissions could adversely affect coal-fired power generation
and reduce the demand for coal as a fuel source, which could
cause the price and quantity of the coal we sell to decline
materially.
One major by-product of burning coal is carbon dioxide, which is
a greenhouse gas and is a major source of concern with respect
to global warming, also known as climate change. Climate change
continues to attract public and scientific attention, and
increasing government attention is being paid to reducing
greenhouse gas emissions, including from coal-fired power
plants. There are several regulatory proposals under
consideration at the international, federal, state and local
levels to limit emissions of greenhouse gases, including
possible future U.S. treaty commitments, new federal or
state legislation that may establish a
cap-and-trade,
and regulation under existing environmental laws by the
U.S. Environmental Protection Agency, or the EPA. If
enacted, these regulatory proposals and other efforts to reduce
greenhouse gas emissions may require additional controls on, or
the closure of, coal-fired power plants and industrial boilers,
may cause some users of coal to switch from coal to a
lower-carbon fuel, and may result in the construction of fewer
new coal-fired power plants. For a more detailed discussion of
these regulatory proposals, please read
Business Regulation and Laws.
The permitting of new coal-fired power plants has also recently
been contested, at times successfully, by state regulators and
environmental advocacy organizations due to concerns related to
greenhouse gas emissions from the new plants. Additionally, two
U.S. federal appeals courts have allowed lawsuits to
proceed by individuals, state attorneys general and others to
pursue federal common law claims against major utility, coal,
oil and chemical companies on the basis that those companies may
have created a public nuisance due to their emissions of carbon
dioxide.
The enactment of comprehensive laws to limit greenhouse gas
emissions or the potential for liability or permitting issues
based on greenhouse gas emissions may adversely affect the use
of and demand for fossil fuels, particularly coal, which could
have a material adverse effect on our business, financial
condition or results of operations.
Existing and future regulatory requirements relating to
sulfur dioxide and other air emissions could affect our
customers and could reduce the demand for the high-sulfur coal
we produce and cause coal prices and sales of our high-sulfur
coal to decline materially.
Coal-fired power plants are subject to extensive environmental
regulation, particularly with respect to air emissions. For
example, the Clean Air Act Amendments of 1990, or the CAAA, and
similar state and local laws place annual limits on the amount
of sulfur dioxide, particulate matter, nitrogen oxides, mercury
and other compounds that can be emitted into the air by electric
power generators, which are the largest end-users of our coal.
The ability of coal-fired power plants to burn the high-sulfur
coal we produce may be limited unless they:
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|
|
|
|
have already installed or will install costly pollution control
devices such as scrubbers;
|
|
|
|
can purchase and use emission allowances; or
|
|
|
|
blend our high-sulfur coal with low-sulfur coal.
|
Projected demand growth for high-sulfur coal in our primary
market area is largely dependent on planned installations of
scrubbers at new and existing coal-fired power plants that use
or plan to use high-sulfur coal as a fuel. The timing and amount
of these scrubber installations may be affected by, among other
things, anticipated changes in air quality regulations and the
price and availability of sulfur dioxide emissions allowances.
To the extent that these scrubber installations do not occur or
are substantially delayed and
22
sufficient sulfur dioxide allowances are unavailable or are
prohibitively expensive, demand for our high-sulfur coal could
materially decrease, which could have a material adverse effect
on our business, financial condition or results of operations.
Our
coal mining operations are subject to operating risks, which
could result in materially increased operating expenses and
decreased production levels and could have a material adverse
effect on our business, financial condition or results of
operations.
Our coal mining operations are subject to a number of operating
risks beyond our control. Because we maintain very limited
produced coal inventory, various conditions or events could
disrupt operations, adversely affect production and shipments
and increase the cost of mining at particular mines for varying
lengths of time, which could have a material adverse effect on
our business, financial condition or results of operations.
These conditions and events include, among others:
|
|
|
|
|
poor mining conditions resulting from geologic, hydrologic or
other conditions, which may cause instability of highwalls or
spoil-piles or cause damage to nearby infrastructure;
|
|
|
|
adverse weather and natural disasters, such as heavy rains,
flooding and other natural events affecting operations or
transportation;
|
|
|
|
the unavailability of qualified labor and contractors;
|
|
|
|
the unavailability or increased prices of equipment (including
heavy mobile equipment) or other critical supplies such as tires
and explosives, fuel, lubricants and other consumables of the
type, quantity or size needed to meet production expectations;
|
|
|
|
fluctuations in transportation costs and transportation delays
or interruptions, including those caused by river flooding and
lock closures for repairs;
|
|
|
|
delays, challenges to, and difficulties in acquiring,
maintaining or renewing necessary permits, including
environmental permits, or mineral and surface rights;
|
|
|
|
changes in or enhanced enforcement of current and future health,
safety and environmental regulations or changes in
interpretations of current regulations, including the
classification of plant and animal species near our mines as
endangered or threatened species;
|
|
|
|
mine accidents or other unforeseen casualty events;
|
|
|
|
employee injuries or fatalities;
|
|
|
|
increased or unexpected reclamation costs; and
|
|
|
|
the inability to monitor our mining operations due to
disruptions or failures of our information technology systems.
|
These changes, conditions and events may materially increase our
cost of mining and delay or halt production at particular mines
either permanently or for varying lengths of time.
We maintain insurance coverage against some but not all
potential losses to protect against the risks we face. We
generally do not carry business interruption insurance and we
may elect not to carry other types of insurance in the future if
our management believes that the cost of available insurance is
excessive relative to the risks presented. In addition, it is
not possible to ensure fully against pollution and environmental
risks. If a significant accident or other event occurs and is
not fully covered by insurance, then that accident or other
event could have a material adverse effect on our business,
financial condition or results of operations.
We may
not receive cash distributions from Harrison Resources in the
future.
In January 2007, we entered into a joint venture, Harrison
Resources, with CONSOL Energy to mine surface coal reserves
purchased from CONSOL Energy. Since its inception, Harrison
Resources has acquired 3.5 million tons of proven and
probable coal reserves from CONSOL Energy. Pursuant to its
operating agreement, all members of Harrison Resources must
approve cash distributions, other than tax distributions to
23
its members. The members of Harrison Resources have consistently
approved cash distributions from Harrison Resources on a
quarterly basis, including the $6.3 million that we
received in 2009. In the future, however, there can be no
assurance that we will receive regular cash distributions, as
its members may prefer to keep cash in Harrison Resources
instead of approving distributions. As a result, our ability to
receive future distributions from Harrison Resources may be
limited, which could have a material adverse effect on our
ability to make cash distributions to our unitholders.
A
significant portion of the cash available for distribution to
our unitholders is derived from royalty payments we receive on
our underground coal reserves, which we do not
operate.
In June 2005, we sold our underground mining operations at the
Tusky mining complex to an independent coal producer in Northern
Appalachia. As part of the transaction, we subleased our
underground coal reserves to this producer in exchange for an
overriding royalty. Our overriding royalty is equal to a
percentage of the sales price that our sublessee receives for
the coal it produces and sells from our underground reserves.
Our sublessee is also obligated to pay directly to our lessor a
tonnage-based royalty on the production from these reserves. For
the year ended December 31, 2009, we received royalty
payments on our underground coal reserves from our sublessee of
approximately $4.5 million, or approximately 8.9% of our
Adjusted EBITDA for the year ended December 31, 2009. The
royalty payments that we receive from our sublessee could be
adversely affected by any of the following:
|
|
|
|
|
a substantial and extended decline in the sales price our
sublessee receives for the coal it produces;
|
|
|
|
any decisions by our sublessee to reduce or discontinue
production or sales of coal produced from our underground coal
reserves;
|
|
|
|
any failure by our sublessee to properly manage its operations;
|
|
|
|
our sublessees operational risks relating to our
underground coal reserves, which expose our sublessee to
operating conditions and events beyond its control, including
the inability to acquire necessary permits, changes or
variations in geologic conditions, changes in governmental
regulation of the coal industry or the electric power industry,
mining and processing equipment failures and unexpected
maintenance problems, interruptions due to transportation
delays, adverse weather and natural disasters, labor-related
interruptions and fires and explosions; and
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|
|
a material decline in the creditworthiness of our sublessee,
including as a result of the current economic downturn.
|
As we do not operate the Tusky mining complex, our ability to
address the risks discussed above will be limited. If the
royalty payments we receive from our sublessee are reduced, our
ability to make cash distributions to our unitholders could be
adversely affected. In addition, we could lose our lease rights
with our lessor if our sublessee fails to pay the tonnage-based
royalty owed to our lessor and we fail to timely make our lessor
whole for those unpaid royalties.
The
amount of estimated maintenance capital expenditures our general
partner is required to deduct from operating surplus each
quarter is based on our current estimates and 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 major refurbishment or replacement
of mining equipment. Our initial annual estimated maintenance
capital expenditures for purposes of calculating operating
surplus will be $32.3 million. This amount is based on our
current estimates of the amounts of expenditures we will be
required to make in future years to maintain our depleting
capital asset base, which we believe to be reasonable. This
amount has been taken into consideration in calculating our
forecast of cash available for distribution in Cash
Distribution Policy and Restrictions on Distributions. The
initial amount of our estimated annual maintenance capital
expenditures may be more than our initial actual maintenance
capital expenditures, which will reduce the
24
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.
Increases
in the cost of diesel fuel and explosives, or the inability to
obtain a sufficient quantity of those supplies, could increase
our operating expenses, disrupt or delay our production and have
a material adverse effect on our profitability.
We use considerable quantities of diesel fuel in our mining
operations. We typically hedge a large portion of our diesel
fuel needs each year through fixed price forward contracts that
provide for physical delivery (during 2009, we hedged 54.4% of
our diesel fuel needs). We also recover a portion of our total
fuel costs through full or partial cost pass through and
inflation adjustment provisions in our long-term coal sales
contracts. If the price of diesel fuel increases significantly
and we are unable to recover all or a portion of those increases
through these cost pass through or inflation adjustment
provisions, our operating expenses will increase relative to our
revenue, which could have a material adverse effect on our
profitability. A significant amount of explosives are used in
our mining operations. We use third party contractors to provide
blasting services, and they generally pass through to us the
cost of explosives, which are subject to fluctuations.
Additionally, a limited number of suppliers exist for
explosives, and any of these suppliers may divert their products
to other buyers. 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 our contractors to obtain these
supplies.
Extensive
environmental laws and regulations impose significant costs on
our mining operations, and future laws and regulations could
materially increase those costs or limit our ability to produce
and sell coal.
The coal mining industry is subject to increasingly strict
regulation by federal, state and local authorities with respect
to environmental matters such as:
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limitations on land use;
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mine permitting and licensing requirements;
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reclamation and restoration of mining properties after mining is
completed;
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management of materials generated by mining operations;
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storage, treatment and disposal of wastes;
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air quality standards;
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water pollution;
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protection of human health and the preservation of plants and
animals, including endangered or threatened species;
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protection of wetlands;
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discharge of materials into the environment; and
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effects of mining on surface water and groundwater quality and
availability.
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The costs of complying with these laws and regulations are
significant. Although we believe that we are in substantial
compliance, we may, in the future, experience violations that
would subject us to administrative, civil and criminal penalties
and a range of other possible sanctions. We may incur
significant costs and liabilities resulting from claims for
damages to property or injury to persons arising from our
operations.
The enforcement of laws and regulations governing the coal
mining industry has increased substantially for a number of
reasons, including the recent occurrence of mining accidents at
certain mines. Moreover, the trend is towards more stringent
regulations and more vigorous enforcement of those laws and
regulations particularly in light of the renewed focus by
governmental agencies on the mining industry. Thus, the costs of
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compliance with those laws and regulations may become more
costly and the consequences for any non-compliance may become
more significant in the future.
New legislation or administrative regulations or new judicial
interpretations or administrative enforcement of existing laws
and regulations, including proposals related to the protection
of the environment that would further regulate and tax the coal
industry, may also require us to change operations significantly
or incur increased costs. Such changes could have a material
adverse effect on our business, financial condition or results
of operations. Please read Business Regulation
and Laws.
We may
be unable to obtain, maintain or renew permits necessary for our
operations, which would materially reduce our production, cash
flows and profitability.
As is typical in the coal industry, our coal production is
dependent on our ability to obtain the permits and approvals
from federal and state regulatory authorities needed to mine our
coal reserves within the timeline specified in our surface
mining plan. 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, including non-governmental organizations, anti-mining
groups and individuals, have 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
expected production in certain regions, primarily in Central
Appalachia, but could also affect Northern Appalachia, the
Illinois Basin and other regions in the future.
Based on our current surface mining plan, we have proven and
probable coal reserves with active permits that will allow us to
mine for approximately three years. Typically, we submit the
necessary permit applications 12 to 30 months before we
plan to mine a new area. Some of our required mining permits are
becoming increasingly difficult to obtain in a timely manner, or
at all, and in some instances we have had to abandon or
substantially delay the mining of coal in certain areas covered
by the application in order to obtain required permits and
approvals.
The Army Corps of Engineers, or the Corps, the EPA and the
Department of the Interior recently announced an interagency
action plan for an enhanced review of any project
that requires a permit under both the Surface Mining Control and
Reclamation Act of 1977, or SMCRA, and the federal Clean Water
Act, or CWA, designed to reduce the harmful environmental
consequences of mountain-top mining in the Appalachian region.
As part of the June 2009 interagency memorandum of
understanding, the Corps proposed to suspend and modify
Nationwide Permit 21, or NWP 21, in the Appalachian region of
Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West
Virginia to prohibit its use to authorize discharges of fill
material into waters of the United States for mountain-top
mining. Two of our permit applications that cover
1.1 million tons of our coal reserves are currently being
reviewed by the EPA under its enhanced review procedures even
though the mining activities in question do not utilize
mountain-top mining, a method of mining we do not employ. As of
March 19, 2010, the two permits have not been issued.
Additional permits could be delayed in the future if the EPA
continues to apply these enhanced review procedures to
applications for these permits in connection with coal mining in
Appalachia. If the required permits are not issued or renewed in
a timely fashion or at all, or if permits issued or renewed are
conditioned in a manner that restricts our ability to
efficiently and economically conduct our mining activities, we
could suffer a material reduction in our production, and our
operations and there could be a material adverse effect on our
ability to make cash distributions to our unitholders.
26
We
depend on a limited number of customers for a significant
portion of our revenues, and the loss of, or significant
reduction in, purchases by any of them could adversely affect
our results of operations and cash available for distribution to
our unitholders.
We derived 77% of our revenues from coal sales to our five
largest customers for the year ended December 31, 2009, and
as of March 19, 2010, we had long-term coal sales contracts
in place with these same customers for 75% of our estimated coal
production from operations for the year ending December 31,
2010. We expect to continue to derive a substantial amount of
our total revenues from a small number of customers in the
future. However, we may be unsuccessful in renewing long-term
coal sales contracts with our largest customers, and those
customers may discontinue or reduce purchasing coal from us. If
any of our largest customers significantly reduces the
quantities of coal it purchases from us and if we are unable to
sell such excess coal to our other customers on terms
substantially similar to the terms under our current long-term
coal sales contracts, our business, our results of operations
and our ability to make distributions to our unitholders could
be adversely affected.
If the
assumptions underlying our reclamation and mine closure
obligations are materially inaccurate, our costs could be
significantly greater than anticipated.
All of the mines we operate are surface mining operations. The
SMCRA and counterpart state laws and regulations establish
operational, reclamation and closure standards for all aspects
of surface mining. We estimate our total reclamation and
mine-closing liabilities based on permit requirements,
engineering studies, including the estimated life of our mines,
and our engineering expertise related to the permit
requirements. As of December 31, 2009, we had accrued a
reserve of approximately $13.3 million for future
reclamation and mine-closure liabilities. The estimate of
ultimate reclamation liability is reviewed periodically by our
management and engineers. The estimated liability can change
significantly if actual costs vary from our original assumptions
or if governmental regulations change significantly. GAAP
requires that asset retirement obligations be recorded as a
liability based on fair value, which reflects the present value
of the estimated future cash flows. In estimating future cash
flows, we consider the estimated current cost of reclamation and
apply inflation rates and a third-party profit, as necessary.
The third-party profit is an estimate of the approximate markup
that would be charged by contractors for work performed on
behalf of us. The resulting estimated reclamation and mine
closure obligations could change significantly if actual results
change significantly from our assumptions, which could have a
material adverse effect on our financial condition or results of
operations. Please read Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Off-Balance Sheet Arrangements for a
description of these liabilities.
Debt
we incur in the future may limit our flexibility to obtain
financing and to pursue other business
opportunities.
Our future level of debt 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, acquisitions or other
purposes may be impaired or such financing may not be available
on favorable terms;
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our funds available for operations, future business
opportunities and distributions to unitholders will be reduced
by that portion of our cash flow required to make interest
payments on our debt;
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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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Our ability to service our debt 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 future indebtedness, we will be forced
to take actions such as reducing distributions, reducing or
delaying our
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business activities, acquisitions, investments or capital
expenditures, selling assets or seeking additional equity
capital. We may not be able to effect any of these actions on
satisfactory terms or at all.
Restrictions
in our new credit facility could adversely affect our business,
financial condition, results of operations, ability to make
distributions to unitholders and value of our common
units.
We expect to enter into a new credit facility concurrently with
the closing of the offering. Our new credit facility is likely
to limit our ability to, among other things:
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incur additional debt;
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make distributions on or redeem or repurchase units;
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make certain investments and acquisitions;
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incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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merge or consolidate with another company; and
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transfer or otherwise dispose of assets.
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Our new credit facility also will likely contain covenants
requiring us to maintain certain financial ratios.
The provisions of our new credit facility may affect our ability
to obtain future financing and pursue attractive business
opportunities and our flexibility in planning for, and reacting
to, changes in business conditions. In addition, a failure to
comply with the provisions of our new credit facility could
result in a default or an event of default that could enable our
lenders to declare the outstanding principal of that debt,
together with accrued and unpaid interest, to be immediately due
and payable. If the payment of our debt is accelerated, our
assets may be insufficient to repay such debt in full, and our
unitholders could experience a partial or total loss of their
investment.
The
availability and reliability of transportation could impair our
ability to supply coal to our customers.
Our coal is transported to customers by barge, truck and rail.
Disruption of these transportation services because of
weather-related problems (such as river flooding), mechanical
difficulties, train derailment, bridge or structural concerns,
infrastructure damage, whether caused by ground instability,
accidents or otherwise, strikes, lock-outs, lack of fuel or
maintenance items, fuel costs, transportation delays, accidents,
terrorism or domestic catastrophe or other events could
temporarily or over the long term impair our ability to supply
coal to our customers and our customers ability to take
delivery of our coal and, therefore, could have a material
adverse effect on our business, financial condition or results
of operations.
Our
operations may impact the environment or cause environmental
contamination, which could result in material liabilities to
us.
Our operations use hazardous materials, generate limited
quantities of hazardous wastes and may affect runoff or drainage
water. In the event of environmental contamination or a release
of hazardous materials, we could become subject to claims for
toxic torts, natural resource damages and other damages and for
the investigation and clean up 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. Our liability for such claims may be joint and several,
so that we may be held responsible for more than our share of
the contamination or other damages, or even for the entire share.
We maintain coal refuse areas and slurry impoundments at our
Tuscarawas County and Muhlenberg County mining complexes. Such
areas and impoundments are subject to extensive regulation. One
of those impoundments overlies a mined out area, which can pose
a heightened risk of structural failure and of damages arising
out of such failure. When a slurry impoundment experiences a
structural failure, it could
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release large volumes of coal slurry into the surrounding
environment, which in turn can result in extensive damage to the
environment and natural resources, such as bodies of water. A
failure may also result in civil or criminal fines, penalties,
personal injuries and property damages, and damage to wildlife
or natural resources.
Surface or groundwater that comes in contact with materials
resulting from mining activities can become acidic and contain
elevated levels of dissolved metals, a condition referred to as
acid mine drainage, or AMD. We have seven mining
permits that are identified on Ohios Inventory of
Long-Term AMD sites. Only one of these sites, associated with
the Strasburg Wash Plant, requires continuous AMD treatment, for
which we have estimated the present value of the projected
annual treatment cost at less than $10,000 per year. While we
anticipate that AMD treatment will not be required once
reclamation is completed, it is possible that AMD treatment will
be required for some time and current AMD treatment costs could
escalate due to changes in flow or water quality. These and
other similar impacts that our operations may have on the
environment, as well as exposures to hazardous substances or
wastes associated with our operations, could result in costs and
liabilities that could have a material adverse effect on us.
If the
third-party sources from which we purchase coal are unable to
fulfill the delivery terms of their contracts, our results of
operations could be adversely affected.
Based on our expected production for 2010, we will need to
purchase coal from third-party sources to fulfill a portion of
our committed coal deliveries for 2010 under our coal sales
contracts. We have entered into a long-term coal purchase
contract that will cover most of our expected coal purchases for
2010 and a portion of our expected coal purchases for at least
three years thereafter. The price we pay for the coal purchased
under this contract is based on a minimum price and the price we
receive under our long-term coal sales contracts for such coal.
From time to time, we also purchase coal from other producers at
spot prices. Our profitability and exposure to loss on our coal
purchases are dependent upon the price of the coal we purchase
and the reliability, including the financial viability, of the
third-party coal producers from whom we purchase. Operational
difficulties, changes in demand and other factors could affect
the availability, pricing and quality of the coal we purchase
and the price(s) at which we resell such purchased coal.
Disruptions in the quantities or qualities of the coal we
purchase could affect our ability to fill our customer orders or
require us to purchase coal at higher prices from other sources
in order to satisfy those orders. If we are unable to fill a
customer order due to our inability to purchase coal from third
parties in sufficient quantities, qualities or at attractive
prices, our results of operations could be adversely affected.
Our
ability to operate our business effectively could be impaired if
we fail to attract and retain key management
personnel.
Our ability to operate our business and implement our strategies
depends, in part, on the continued contributions of Charles C.
Ungurean and our other executive officers and key employees. In
particular, we depend significantly on Mr. Ungureans
long-standing relationships within our industry. The loss of any
of our senior executives could have a material adverse effect on
our business unless and until we find a qualified replacement. A
limited number of persons exist with the requisite experience
and skills to serve in our senior management positions. We may
not be able to locate or employ qualified executives on
acceptable terms. In addition, we believe that our future
success will depend on our continued ability to attract and
retain highly skilled management personnel with coal industry
experience. Competition for these persons in the coal industry
is intense and we may not be able to successfully recruit, train
or retain qualified managerial personnel. As a publicly traded
partnership, our future success will also depend on our ability
to hire and retain management with relevant experience. We may
not be able to continue to employ key personnel or attract and
retain qualified personnel in the future, and our failure to
retain or attract key personnel could have a material adverse
effect on our ability to effectively operate our business.
A
shortage of skilled labor in the mining industry could reduce
labor productivity and increase costs, which could have a
material adverse effect on our business and results of
operations.
Efficient coal mining using modern techniques and equipment
requires skilled laborers in multiple disciplines such as
equipment operators, mechanics and engineers, among others. We
have from time to time
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encountered shortages for these types of skilled labor. If we
experience shortages of skilled labor in the future, our labor
and overall productivity or costs could be materially and
adversely affected. If coal prices decrease in the future or our
labor prices increase, or if we experience materially increased
health and benefit costs with respect to our employees, our
results of operations could be materially and adversely affected.
Our work force could become unionized in the future, which
could adversely affect the stability of our production and
materially reduce our profitability.
All of our mines are operated by non-union employees. Our
employees have the right at any time under the National Labor
Relations Act to form or affiliate with a union. If our
employees choose to form or affiliate with a union and the terms
of a union collective bargaining agreement are significantly
different from our current compensation and job assignment
arrangements with our employees, these arrangements could
adversely affect the stability of our production and materially
reduce our profitability.
Inaccuracies in our estimates of our coal reserves could
result in lower than expected revenues or higher than expected
costs.
Our future performance depends on, among other things, the
accuracy of the estimates of our proven and probable coal
reserves. The estimates of our proven and probable reserves
associated with our surface mining operations in Ohio are
derived from our internal estimates, which estimates were
audited by John T. Boyd Company, an independent mining and
geological consulting firm. The estimates of our proven and
probable reserves associated with our surface mining operations
in the Illinois Basin and our proven and probable underground
coal reserves are derived from reserve reports prepared by
John T. Boyd Company. These estimates are based on geologic
data, economic data such as cost of production and projected
sale prices and assumptions concerning permitability and
advances in mining technology. The estimates of our proven and
probable coal reserves as to both quantity and quality are
periodically updated to reflect the production of coal from the
reserves, updated geologic models and mining recovery data, coal
reserves recently purchased or otherwise acquired and estimated
costs of production and sales prices. There are numerous factors
and assumptions inherent in estimating the quantities and
qualities of, and costs to mine, coal reserves, any one of which
may vary considerably from actual results. These factors and
assumptions include:
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quality of the coal;
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geologic and mining conditions, which may not be fully
identified by available exploration data or may differ from our
experiences in areas where we currently mine;
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the percentage of coal ultimately recoverable;
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the assumed effects of regulation, including the issuance of
required permits, and taxes, including severance and excise
taxes and royalties, and other payments to governmental agencies;
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assumptions concerning the timing for the development of
reserves; and
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assumptions concerning equipment and productivity, future coal
prices, operating costs, including for critical supplies such as
fuel, tires and explosives, capital expenditures and development
and reclamation costs.
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As a result, estimates of the quantities and qualities of
economically recoverable coal attributable to any particular
group of properties, classifications of reserves based on risk
of recovery, estimated cost of production, and estimates of
future net cash flows expected from these properties as prepared
by different engineers and accounting personnel, or by the same
engineers and accounting personnel at different times, may vary
materially due to changes in the above factors and assumptions.
Actual production recovered from identified reserve areas and
properties, and revenues and expenditures associated with our
mining operations, may vary materially from estimates. Any
inaccuracy in the estimates related to our reserves could have a
material adverse effect on our ability to make cash
distributions.
Our ability to collect payments from our customers could
be impaired if their creditworthiness deteriorates.
Our ability to receive payment for coal sold and delivered
depends on the continued creditworthiness of our customers. The
current economic volatility and tightening credit markets
increase the risk that we may not
30
be able to collect payments from our customers or be required to
continue to deliver coal even if the customers
creditworthiness deteriorates. A continuation or worsening of
current economic conditions or other prolonged global or
U.S. recessions could also impact the creditworthiness of
our customers.
Approximately 12% of our 2009 sales were to coal brokers, who
resell our coal to end users, including utilities. Under some of
these arrangements, we have contractual privity only with the
broker and may not be able to pursue claims against the end
users in connection with these sales if we do not receive
payment from the broker, who may only have limited assets. We
expect our sales through brokers to increase in 2010.
If the creditworthiness of a customer declines, this would
increase the risk that we may not be able to collect payment for
all coal sold and delivered to or on behalf of that customer. If
we determine that a customer is not creditworthy, we may not be
required to deliver coal under the customers coal sales
contract. If we are able to withhold shipments, we may decide to
sell the customers coal on the spot market, which may be
at prices lower than the contract price, or we may be unable to
sell the coal at all. Furthermore, the bankruptcy of any of our
customers could have a material adverse effect on our financial
position. In addition, competition with other coal suppliers
could force us to extend credit to customers and on terms that
could increase the risk of payment default.
Failure to obtain, maintain or renew our security
arrangements, such as surety bonds or letters of credit, in a
timely manner and on acceptable terms could have an adverse
effect on our cash available for distribution to our
unitholders.
Federal and state laws require us to secure the performance of
certain long-term obligations, such as mine closure or
reclamation costs. The amount of these security arrangements is
substantial, with total amounts of surety bonds at
December 31, 2009 of approximately $31.3 million,
which were supported by letters of credit of $6.9 million.
Federal and state governments could increase bonding
requirements in the future. 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 putting up letters of credit or posting
cash collateral, or other terms less favorable to us upon those
renewals. Our ability to obtain or renew our surety bonds could
be impacted by a variety of other factors including lack of
availability, unfavorable market terms, the exercise by
third-party surety bond issuers of their right to refuse to
renew the surety bonds and restrictions on availability of
collateral for current and future third-party surety bond
issuers under the terms of any credit arrangements then in
place. Surety bond issuers may demand terms that are less
favorable to us than the terms we currently receive and there
may be fewer companies willing to issue these bonds. Due to
current 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 and we may
have greater difficulty satisfying the liquidity requirements
under our existing surety bond contracts. 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.
Our management team does not have experience managing our
business as a stand-alone publicly traded partnership, and if
they are unable to manage our business as a publicly traded
partnership our business may be affected.
Our management team does not have experience managing our
business as a publicly traded partnership. If we are unable to
manage and operate our partnership as a publicly traded
partnership, our business and results of operations will be
adversely affected.
We will be required by Section 404 of the
Sarbanes-Oxley Act to evaluate the effectiveness of our internal
controls. If we are unable to establish and maintain effective
internal controls, our financial condition and operating results
could be adversely affected.
We are in the process of evaluating our internal controls
systems to allow management to report on, and our independent
auditors to audit, our internal controls over financial
reporting. We are also in the process of performing the system
and process evaluation and testing (and any necessary
remediation) required to comply with the management
certification and auditor attestation requirements of
Section 404 of the Sarbanes-Oxley Act of 2002. We will be
required to comply with Section 404 for the year ending
December 31, 2011.
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However, we cannot be certain as to the timing of completion of
our evaluation, testing and remediation actions or the impact of
the same on our operations. Furthermore, upon completion of this
process, we may identify control deficiencies of varying degrees
of severity under applicable SEC and Public Company Accounting
Oversight Board rules and regulations that remain unremediated.
As a public company, we will be required to report, among other
things, control deficiencies that constitute a material
weakness or changes in internal controls that, or that are
reasonably likely to, materially affect internal controls over
financial reporting. A material weakness is a
significant deficiency or combination of significant
deficiencies that results in more than a remote likelihood that
a material misstatement of the annual or interim consolidated
financial statements will not be prevented or detected. In
connection with the audit of our financial statements, a
significant deficiency in our internal controls was identified
that related to 2008. This significant deficiency related to the
timeliness and thoroughness of our account reconciliation and
review procedures. Management has taken steps to remediate this
significant deficiency by restructuring and refining its account
reconciliation process and tracking. While we believe that this
significant deficiency has been remediated, we may have
additional significant deficiencies in the future.
If we fail to implement the requirements of Section 404 in
a timely manner, we might be subject to sanctions or
investigation by regulatory authorities such as the SEC. In
addition, failure to comply with Section 404 or the report
by us of a material weakness may cause investors to lose
confidence in our consolidated financial statements, and as a
result our unit price may be adversely affected. If we fail to
remedy any material weakness, our consolidated financial
statements may be inaccurate, we may face restricted access to
the capital markets and our unit price may be adversely affected.
Terrorist attacks and threats, escalation of military
activity in response to these attacks or acts of war could have
a material adverse effect on our business, financial condition
or results of operations.
Terrorist attacks and threats, escalation of military activity
or acts of war may have significant effects on general economic
conditions, fluctuations in consumer confidence and spending and
market liquidity, each of which could materially and adversely
affect our business. Future terrorist attacks, rumors or threats
of war, actual conflicts involving the United States or its
allies, or military or trade disruptions affecting our customers
may significantly affect our operations and those of our
customers. Strategic targets, such as energy-related assets and
transportation assets, may be at greater risk of future
terrorist attacks than other targets in the United States.
Disruption or significant increases in energy prices could
result in government-imposed price controls. It is possible that
any of these occurrences, or a combination of them, could have a
material adverse effect on our business, financial condition and
results of operations.
Risks
Inherent in an Investment in Us
Our partnership agreement limits our general
partners fiduciary duties to our unitholders and restricts
the remedies available to our unitholders for actions taken by
our general partner that might otherwise constitute breaches of
fiduciary duty.
Fiduciary duties owed to our unitholders by our general partner
are prescribed by law and the partnership agreement. The
Delaware Revised Uniform Limited Partnership Act, or the
Delaware Act, provides that Delaware limited partnerships may,
in their partnership agreements, restrict the fiduciary duties
owed by the general partner to limited partners and the
partnership. Our partnership agreement contains provisions that
reduce the standards to which our general partner would
otherwise be held by state fiduciary duty law. For example, our
partnership agreement:
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limits the liability and reduces the fiduciary duties of our
general partner, while also restricting the remedies available
to our unitholders for actions that, without these limitations,
might constitute breaches of fiduciary duty. As a result of
purchasing common units, our unitholders consent to some actions
and conflicts of interest that might otherwise constitute a
breach of fiduciary or other duties under applicable state law;
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permits our general partner to make a number of decisions in its
individual capacity, as opposed to in its capacity as our
general partner. This entitles our general partner to consider
only the interests and
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factors that it desires, and it has no duty or obligation to
give any consideration to any interest of, or factors affecting,
us, our affiliates or any limited partner. Examples include the
exercise of its limited call right, its voting rights with
respect to the units it owns, its registration rights and its
determination whether or not to consent to any merger or
consolidation of the partnership;
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provides that our general partner shall not have any liability
to us or our unitholders for decisions made in its capacity as
general partner so long as it acted in good faith, meaning it
believed that the decision was in the best interests of the
partnership;
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generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by the conflicts committee
of the board of directors of our general partner, or the
Conflicts Committee, and not involving a vote of our unitholders
must be on terms no less favorable to us than those generally
being provided to or available from unrelated third parties or
be fair and reasonable to us and that, in
determining whether a transaction or resolution is fair
and reasonable, our general partner may consider the
totality of the relationships between the parties involved,
including other transactions that may be particularly
advantageous or beneficial to us; and
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provides that our general partner and its officers and directors
will not be liable for monetary damages to us, our limited
partners or assignees for any acts or omissions unless there has
been a final and non-appealable judgment entered by a court of
competent jurisdiction determining that our general partner or
those other persons acted in bad faith or engaged in fraud or
willful misconduct.
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By purchasing a common unit, a common unitholder will become
bound by the provisions of the partnership agreement, including
the provisions described above. Please read Description of
the Common Units Transfer of Common Units.
Our
general partner and its affiliates have conflicts of interest,
and their limited fiduciary duties to our unitholders may permit
them to favor their own interests to the detriment of our
unitholders.
Following the offering, C&T Coal will own
a % limited partner interest in us
(or a % limited partner interest in
us if the underwriters exercise their option to purchase
additional common units in full), AIM Oxford will own
a % limited partner interest in us
(or a % limited partner interest in
us if the underwriters exercise their option to purchase
additional common units in full), and C&T Coal and AIM
Oxford will own and control our general partner. Although our
general partner has certain fiduciary duties 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. Furthermore, since certain executive officers and
directors of our general partner are executive officers or
directors of affiliates of our general partner, conflicts of
interest may arise between C&T Coal and AIM Oxford and
their affiliates, including our general partner, on the one
hand, and us and our unitholders, on the other hand. As a result
of these conflicts, our general partner may favor its own
interests and the interests of its affiliates over the interests
of our unitholders. Please read Our
partnership agreement limits our general partners
fiduciary duties to our unitholders and restricts the remedies
available to our unitholders for actions taken by our general
partner that might otherwise constitute breaches of fiduciary
duty. The risk to our unitholders due to such conflicts
may arise because of the following factors, among others:
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our general partner is allowed to take into account the
interests of parties other than us, such as C&T Coal and
AIM Oxford, 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 owners of our general partner to pursue a business
strategy that favors us. Executive officers and directors of our
general partners owners have a fiduciary duty to make
these decisions in the best interest of their owners, which may
be contrary to our interests;
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our general partner determines the amount and timing of asset
purchases and sales, capital expenditures, borrowings, issuances
of additional partnership securities and reserves, each of which
can affect the amount of cash that is available for distribution
to our unitholders;
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our general partner determines our estimated maintenance capital
expenditures, which reduce operating surplus, and that
determination can affect the amount of cash that is distributed
to our unitholders and the ability of the subordinated units to
convert to common units;
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in some instances, 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 periods;
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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 on terms that are fair and reasonable to us or entering
into additional contractual arrangements with any of these
entities 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 limited 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 owed
to us by it and its affiliates; and
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our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
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In addition, AIM currently holds substantial interests in other
companies in the energy and natural resource sectors. 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, AIM and AIM Oxford are
not prohibited from engaging in other businesses or activities,
including those that might be in direct competition with us. As
a result, they could potentially compete with us for acquisition
opportunities and for new business or extensions of the existing
services provided by us. Please read Conflicts of Interest
and Fiduciary Duties Conflicts of Interest
AIM Oxford and AIM, affiliates of our general partner, may
compete with us.
Pursuant to the terms of our partnership agreement, the doctrine
of corporate opportunity, or any analogous doctrine, does not
apply to our general partner or any of its affiliates, including
its executive officers, directors and owners. 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. Please read Conflicts of Interest
and Fiduciary Duties.
Our unitholders have limited voting rights and are not
entitled to elect our general partner or its directors or
initially to remove our general partner without its
consent.
Unlike the holders of common stock in a corporation, our
unitholders have only limited voting rights on matters affecting
our business and, therefore, limited ability to influence
managements decisions regarding our business. Our
unitholders will have no right to elect our general partner or
its board of directors on an annual or other continuing basis.
The board of directors of our general partner is chosen entirely
by its members and not by our unitholders. Furthermore, if our
unitholders are dissatisfied with the performance of our general
partner, they will have limited ability to remove our general
partner.
Our unitholders will be unable initially to remove our general
partner without its consent because affiliates of our general
partner will own sufficient units upon the consummation of this
offering to be able to prevent removal of our general partner.
The vote of the holders of at least 80% of all outstanding
common units and subordinated units voting together as a single
class is required to remove our general partner.
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Following the closing of this offering, affiliates of our
general partner will own % of our
common units and subordinated units
(or % of our common units and
subordinated units, if the underwriters exercise their option to
purchase additional common units in full). Also, if our general
partner is removed without cause during the subordination period
and units held by our general partner and its affiliates are not
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. A
removal of our general partner under these circumstances would
adversely affect the common units by prematurely eliminating
their distribution and liquidation preference over the
subordinated units, which would otherwise have continued until
we had met certain distribution and performance tests.
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 misconduct in its capacity as our
general partner. Cause does not include most cases of charges of
poor management of the business, so the removal of our general
partner during the subordination period because of our
unitholders dissatisfaction with our general
partners performance in managing our partnership will most
likely result in the termination of the subordination period. 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.
Our unitholders will experience immediate and substantial
dilution of $ per common
unit.
The assumed initial public offering price of
$ per common unit exceeds pro
forma net tangible book value of $
per common unit. As a result, our unitholders will incur
immediate and substantial dilution of
$ per common unit. This dilution
results primarily because the assets contributed to us by
affiliates of our general partner are recorded at their
historical cost and not their fair value. Please read
Dilution.
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 in
us 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, there is no restriction in our
partnership agreement on 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 choices and to control the
decisions and actions of the board of directors and executive
officers of our general partner.
The incentive distribution rights of our general partner
may be transferred to a third party without unitholder
consent.
Our general partner may transfer its incentive distribution
rights to a third party at any time without the consent of our
unitholders. If our general partner transfers its incentive
distribution rights to a third party but retains its general
partner interest, our general partner may not have the same
incentive to grow our partnership and increase quarterly
distributions to unitholders over time as it would if it had
retained ownership of its incentive distribution rights.
Our general partner has a limited call right that may
require our unitholders to sell their common units at an
undesirable time or price.
Upon consummation of this offering, C&T Coal and AIM Oxford
will own an aggregate of % of our
common units and subordinated units
(or % of our common units and
subordinated units, if the underwriters exercise their option to
purchase additional common units in full). 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 not less than the
then-current market price. As a result, our unitholders may be
required to sell their common units at an undesirable time or
price and may not receive any return on their investment. Our
unitholders may also incur a tax liability upon a sale of their
common 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
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partnership agreement that prevents our general partner from
issuing additional common units and exercising its limited call
right. If our general partner exercised its limited call right,
the effect would be to take us private and, if the common units
were subsequently deregistered, we would no longer be subject to
the reporting requirements of the Securities Exchange Act of
1934, or the Exchange Act. For additional information about the
limited call right, please read The Partnership
Agreement Limited Call Right.
We may issue additional units without unitholder approval,
which would dilute unitholder interests.
At any time, we may issue an unlimited number of limited partner
interests of any type without the approval of our unitholders.
Further, our partnership agreement does not prohibit the
issuance of equity securities that may effectively rank senior
to our common units. The issuance by us of additional common
units or other equity securities of equal or senior rank will
have the following effects:
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our 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 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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Our general partner may, without unitholder approval,
elect to cause us to issue common units and general partner
units to it in connection with a resetting of the target
distribution levels related to its incentive distribution
rights. 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 distributions
on its incentive distribution rights at the highest level to
which it is entitled (48%) 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 general partner units. The number of common units to be
issued to our general partner will be equal to that number of
common units that would have entitled their 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.
Our general partner will be issued the number of general partner
units necessary to maintain our general partners interest
in us that existed immediately prior to the reset election. 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 distributions on its incentive distribution rights 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 and general partner units to our general partner in
connection with resetting the target distribution levels. Please
read How We Make Cash Distributions General
Partners Right to Reset Incentive Distribution
Levels.
Cost reimbursements due to our general partner and its
affiliates will reduce cash available for distribution to our
unitholders.
Prior to making any distribution on the common units, we will
reimburse our general partner and its affiliates for all
expenses they incur on our behalf, which will be determined by
our general partner in its sole
36
discretion in accordance with the terms of our partnership
agreement. In determining the costs and expenses allocable to
us, our general partner is subject to its fiduciary duty, as
modified by our partnership agreement, to the limited partners,
which requires it to act in good faith. These expenses will
include all costs incurred by our general partner and its
affiliates in managing and operating us. We are managed and
operated by executive officers and directors of our general
partner. Please read Cash Distribution Policy and
Restrictions on Distributions, Certain Relationships
and Related Party Transactions and Conflicts of
Interest and Fiduciary Duties Conflicts of
Interest. The reimbursement of expenses and payment of
fees, if any, to our general partner and its affiliates could
reduce the amount of available cash for distribution to our
unitholders.
There is no existing market for our common units, and a
trading market that will provide you with adequate liquidity may
not develop. The price of our common units may fluctuate
significantly, and our unitholders could lose all or part of
their investment.
Prior to the offering, there has been no public market for the
common units. After the offering, there will be
only
publicly traded common units
(or
publicly traded common units, if the underwriters exercise their
option to purchase additional common units in full). We do not
know the extent to which investor interest will lead to the
development of a trading market or how liquid that market might
be. Our unitholders may not be able to resell their common units
at or above the initial public offering price. Additionally, the
lack of liquidity may result in wide bid-ask spreads, contribute
to significant fluctuations in the market price of the common
units and limit the number of investors who are able to buy the
common units. The initial public offering price for the common
units has been determined by negotiations between us and the
representative of the underwriters and may not be indicative of
the market price of the common units that will prevail in the
trading market. The market price of our common units may decline
below the initial public offering price. The market price of our
common units may also be influenced by many factors, some of
which are beyond our control, including:
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our quarterly distributions;
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our quarterly or annual earnings or those of other companies in
our industry;
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loss of a large customer;
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announcements by us or our competitors of significant contracts
or acquisitions;
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changes in accounting standards, policies, guidance,
interpretations or principles;
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changes in interest rates;
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general economic conditions;
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the failure of securities analysts to cover our common units
after this offering or changes in financial estimates by
analysts;
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future sales of our common units; and
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the other factors described in these Risk Factors.
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We
will incur increased costs as a result of being a publicly
traded partnership.
We have no history operating as a publicly traded partnership.
As a publicly traded partnership, we will incur significant
legal, accounting and other expenses that we did not incur as a
private company. We expect that complying with the rules and
regulations implemented by the SEC and the New York Stock
Exchange will increase our legal and financial compliance costs
and make activities more time-consuming and costly. For example,
as a result of becoming a publicly traded partnership, we are
required to have three independent directors, create additional
board committees and adopt policies regarding internal controls
and disclosure controls and procedures, including the
preparation of reports on internal controls over financial
reporting. In addition, we will incur additional costs
associated with our publicly traded partnership reporting
requirements.
Our unitholders who fail to furnish certain information
requested by our general partner or who our general partner,
upon receipt of such information, determines are not eligible
citizens will not be entitled to
37
receive distributions or allocations of income or loss on
their common units and their common units will be subject to
redemption.
Our general partner may require each limited partner or assignee
to furnish information about his nationality, citizenship or
related status. If a limited partner or assignee fails to
furnish information about his nationality, citizenship or other
related status within 30 days after a request for the
information or our general partner determines after receipt of
the information that the limited partner or assignee is not an
eligible citizen, the limited partner or assignee may be treated
as a non-citizen assignee. In addition to other limitations on
the rights of an assignee that is not a limited partner, a
non-citizen assignee does not have the right to direct the
voting of his units and may not receive distributions in kind
upon our liquidation. Furthermore, we have the right to redeem
all of the common units and subordinated units of any holder
that is not an eligible citizen or fails to furnish the
requested information. The redemption price will be paid in cash
or by delivery of a promissory note, as determined by our
general partner. Please read The Partnership
Agreement Non-Citizen Assignees; Redemption.
Our unitholders may have liability to repay
distributions.
Under certain circumstances, our unitholders may have to repay
amounts wrongfully returned or distributed to them. Under
Section 17-607
of 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. Purchasers of units who become limited
partners are 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.
Our general partner may mortgage, pledge or grant a
security interest in all or substantially all of our assets
without prior approval of our unitholders.
Our general partner may mortgage, pledge or grant a security
interest in all or substantially all of our assets without prior
approval of our unitholders. If our general partner secures our
obligations or indebtedness by all or substantially all of our
assets and if we are unable to satisfy such obligations or repay
such indebtedness, the lenders could seek to foreclose on our
assets. The lenders may also sell all or substantially all of
our assets under such foreclosure or other realization upon
those encumbrances without prior approval of our unitholders,
which could adversely affect the price of our common units.
Tax
Risks
In addition to reading the following risk factors, please read
Material Federal Income Tax Consequences for a more
complete discussion of the expected material federal income tax
consequences of owning and disposing of common units.
Our
tax treatment depends on our status as a partnership for federal
income tax purposes. If the IRS were to treat us as a
corporation for federal income tax purposes, which would subject
us to entity-level taxation, then our cash available for
distribution to our unitholders would be substantially
reduced.
The anticipated after-tax economic benefit of an investment in
the common units depends largely on our being treated as a
partnership for federal income tax purposes. We have not
requested, and do not plan to request, a ruling from the IRS on
this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under
Delaware law, it is possible in certain circumstances for a
partnership such as ours to be treated as a corporation for
federal income tax purposes. Although we do not believe based
upon our current operations that we are or will be so treated, a
change in our business or a change in current law could cause us
to be treated as a corporation for federal income tax purposes
or otherwise subject us to taxation as an entity.
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If we were treated as a corporation for federal income tax
purposes, we would pay federal income tax on our taxable income
at the corporate tax rate, which is currently a maximum of 35%,
and would likely pay state and local income tax at varying
rates. Distributions would generally be taxed again as corporate
distributions (to the extent of our current and accumulated
earnings and profits), and no income, gains, losses, deductions,
or credits would flow through to you. Because a tax would be
imposed upon us as a corporation, our cash available for
distribution to you would be substantially reduced. Therefore,
if we were treated as a corporation for federal income tax
purposes there would be material reduction in the anticipated
cash flow and after-tax return to our unitholders, likely
causing a substantial reduction in the value of our common units.
Our partnership agreement provides that, if a law is enacted or
existing law is modified or interpreted in a manner that
subjects us to taxation as a corporation or otherwise subjects
us to entity-level taxation for federal, state or local income
tax purposes, the minimum quarterly distribution amount and the
target distribution amounts may be adjusted to reflect the
impact of that law on us.
If we
were subjected to a material amount of additional entity-level
taxation by individual states, it would reduce our cash
available for distribution to our unitholders.
Changes in current state law may subject us to additional
entity-level taxation by individual states. Because of
widespread state budget deficits and other reasons, several
states are evaluating ways to subject partnerships to
entity-level taxation through the imposition of state income,
franchise and other forms of taxation. Imposition of any such
taxes may substantially reduce the cash available for
distribution to you. Our partnership agreement provides that, if
a law is enacted or existing law is modified or interpreted in a
manner that subjects us to entity-level taxation, the minimum
quarterly distribution amount and the target distribution
amounts may be adjusted to reflect the impact of that law on us.
The
tax treatment of publicly traded partnerships or an investment
in our common units could be subject to potential legislative,
judicial or administrative changes and differing
interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded
partnerships, including us, or an investment in our common units
may be modified by administrative, legislative or judicial
interpretation at any time. Recently, members of the
U.S. Congress have considered substantive changes to the
existing federal income tax laws that affect certain publicly
traded partnerships, which, if enacted, may or may not be
applied retroactively. Although we are unable to predict whether
any of these changes or any other proposals will ultimately be
enacted, any such changes could negatively impact the value of
an investment in our common units.
Certain
federal income tax preferences currently available with respect
to coal exploration and development may be eliminated in future
legislation.
Among the changes contained in President Obamas Budget
Proposal for Fiscal Year 2011, or the Budget Proposal, is the
elimination of certain key U.S. federal income tax
preferences relating to coal exploration and development. The
Budget Proposal would (i) eliminate current deductions and
the
60-month
amortization for exploration and development costs relating to
coal and other hard mineral fossil fuels, (ii) repeal the
percentage depletion allowance with respect to coal properties,
(iii) repeal capital gains treatment of coal and lignite
royalties, and (iv) exclude from the definition of domestic
production gross receipts all gross receipts derived from the
sale, exchange, or other disposition of coal, other hard mineral
fossil fuels, or primary products thereof. The passage of any
legislation as a result of the Budget Proposal or any other
similar changes in U.S. federal income tax laws could
eliminate certain tax deductions that are currently available
with respect to coal exploration and development, and any such
change could increase the taxable income allocable to our
unitholders and negatively impact the value of an investment in
our common units.
Our unitholders will be required to pay taxes on their
share of our income even if they do not receive any cash
distributions from us.
Because our unitholders will be treated as partners to whom we
will allocate taxable income which could be different in amount
than the cash we distribute, our unitholders will be required to
pay federal income taxes and, in some cases, state and local
income taxes on their share of our taxable income even if they
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receive no 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 liability that
results from that income.
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 will reduce our cash available
for distribution to our unitholders.
We have not requested a ruling from the Internal Revenue
Service, or the IRS, with respect to our treatment as a
partnership for federal income tax purposes or any other matter
affecting us. The IRS may adopt positions that differ from the
conclusions of our counsel expressed in this prospectus or from
the positions we take. It may be necessary to resort to
administrative or court proceedings to sustain some or all of
our counsels conclusions or the positions we take and such
positions may not ultimately be sustained. A court may not agree
with some or all of our counsels conclusions or the
positions we take. Any contest with the IRS, and the outcome of
any IRS contest, may have a materially adverse impact on the
market for our common units and the price at which they trade.
In addition, our costs of any contest with the IRS will be borne
indirectly by our unitholders and our general partner because
the costs will reduce our cash available for distribution.
Tax gain or loss on the disposition of our common units
could be more or less than expected.
If you sell your common units, you will recognize a gain or loss
for federal income tax purposes equal to the difference between
the amount realized and your tax basis in those common units.
Because distributions in excess of your allocable share of our
net taxable income decrease your tax basis in your common units,
the amount, if any, of such prior excess distributions with
respect to the common units you sell will, in effect, become
taxable income to you if you sell such common units at a price
greater than your tax basis in those common units, even if the
price you receive is less than your original cost. Furthermore,
a substantial portion of the amount realized on any sale of your
common units, whether or not representing gain, may be taxed as
ordinary income due to potential recapture items, including
depreciation recapture. In addition, because the amount realized
includes a unitholders share of our nonrecourse
liabilities, if you sell your common units, you may incur a tax
liability in excess of the amount of cash you receive from the
sale. Please read Material Federal Income Tax
Consequences Disposition of Common Units
Recognition of Gain or Loss for a further discussion of
the foregoing.
Tax-exempt entities and
non-U.S.
persons face unique tax issues from owning our common units that
may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as
employee benefit plans and individual retirement accounts (known
as IRAs), and
non-U.S. persons
raises issues unique to them. For example, virtually all of our
income allocated to organizations that are exempt from federal
income tax, including IRAs and other retirement plans, will be
unrelated business taxable income and will be taxable to them.
Distributions to
non-U.S. persons
will be reduced by withholding taxes at the highest applicable
effective tax rate, and
non-U.S. persons
will be required to file U.S. federal income tax returns
and pay tax on their share of our taxable income. If you are a
tax-exempt entity or a
non-U.S. person,
you should consult a tax advisor before investing in our common
units.
We will treat each purchaser of common units as having the
same tax benefits without regard to the actual common units
purchased. The IRS may challenge this treatment, which could
adversely affect the value of the common units.
Because we cannot match transferors and transferees of common
units and because of other reasons, we will adopt depreciation
and amortization positions that may not conform to all aspects
of existing Treasury Regulations. A successful IRS challenge to
those positions could adversely affect the amount of tax
benefits available to you. Our counsel is unable to opine as to
the validity of such filing positions. 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. Please read Material Federal Income Tax
Consequences Tax Consequences of Unit
Ownership Section 754 Election for a
further discussion of the effect of the depreciation and
amortization positions we will adopt.
40
We prorate our items of income, gain, loss and deduction
between transferors and transferees of our units each month
based upon the ownership of our units on the first day of each
month, instead of on the basis of the date a particular unit is
transferred. The IRS may challenge this treatment, which could
change the allocation of items of income, gain, loss and
deduction among our unitholders.
We will 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 use of this proration method may not be
permitted under existing Treasury Regulations, and, accordingly,
our counsel is unable to opine as to the validity of this
method. If the IRS were to challenge this method or new Treasury
regulations were issued, we may be required to change the
allocation of items of income, gain, loss and deduction among
our unitholders. Please read Material Federal Income Tax
Consequences Disposition of Common Units
Allocations Between Transferors and Transferees.
A unitholder whose common units are loaned to a
short seller to cover a short sale of common units
may be considered as having disposed of those common units. If
so, he would no longer be treated for federal income tax
purposes as a partner with respect to those common units during
the period of the loan and may recognize gain or loss from the
disposition.
Because a unitholder whose common units are loaned to a
short seller to cover a short sale of common units
may be considered as having disposed of the loaned common units,
he may no longer be treated for federal income tax purposes as a
partner with respect to those common units during the period of
the loan to the short seller and the unitholder may recognize
gain or loss from such disposition. Moreover, during the period
of the loan to the short seller, any of our income, gain, loss
or deduction with respect to those common units may not be
reportable by the unitholder and any cash distributions received
by the unitholder as to those common units could be fully
taxable as ordinary income. Our counsel has not rendered an
opinion regarding the treatment of a unitholder where common
units are loaned to a short seller to cover a short sale of
common units; therefore, our unitholders desiring to assure
their status as partners and avoid the risk of gain recognition
from a loan to a short seller are urged to consult a tax advisor
to discuss whether it is advisable to modify any applicable
brokerage account agreements to prohibit their brokers from
loaning their common units.
We will adopt certain valuation methodologies and monthly
conventions that may result in a shift of income, gain, loss and
deduction between our general partner and our unitholders. The
IRS may challenge this treatment, which could adversely affect
the value of the common units.
When we issue additional units or engage in certain other
transactions, we will determine the fair market value of our
assets and allocate any unrealized gain or loss attributable to
our assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating
the value of our assets. In that case, there may be a shift of
income, gain, loss and deduction between certain unitholders and
our general partner, which may be unfavorable to such
unitholders. Moreover, under our valuation methods, subsequent
purchasers of common units may have a greater portion of their
Internal Revenue Code Section 743(b) adjustment allocated
to our tangible assets and a lesser portion allocated to our
intangible assets. The IRS may challenge our valuation methods,
or our allocation of the Section 743(b) adjustment
attributable to our tangible and intangible assets, and
allocations of taxable income, gain, loss and deduction between
our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could
adversely affect the amount of taxable income or loss being
allocated to our unitholders. It also could affect the amount of
taxable gain from our unitholders sale of common units and
could have a negative impact on the value of the common units or
result in audit adjustments to our unitholders tax returns
without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and
profits interests during any
twelve-month
period will result in the termination of our partnership for
federal income tax purposes.
We will be considered to have technically terminated our
partnership for federal income tax purposes if there is a sale
or exchange of 50% or more of the total interests in our capital
and profits within a twelve-month period. For purposes of
determining whether the 50% threshold has been met, multiple
sales of the
41
same interest will be counted only once. Our technical
termination would, among other things, result in the closing of
our taxable year for all unitholders, which would result in us
filing two tax returns (and our unitholders could receive two
Schedules K-1 if relief was not available, as described below)
for one fiscal year and could result in a deferral of
depreciation deductions allowable in computing our taxable
income. In the case of a unitholder reporting on a taxable year
other than a fiscal year ending December 31, the closing of
our taxable year may also result in more than twelve months of
our taxable income or loss being includable in his taxable
income for the year of termination. Our termination currently
would not affect our classification as a partnership for federal
income tax purposes, but instead we would be treated as a new
partnership for tax purposes. If treated as a new partnership,
we must make new tax elections and could be subject to penalties
if we are unable to determine that a termination occurred. The
IRS has recently announced a publicly traded partnership
technical termination relief program whereby, if a publicly
traded partnership that technically terminated requests publicly
traded partnership technical termination relief and such relief
is granted by the IRS, among other things, the partnership will
only have to provide one
Schedule K-1
to unitholders for the year notwithstanding two partnership tax
years. Please read Material Federal Income Tax
Consequences Disposition of Common Units
Constructive Termination for a discussion of the
consequences of our termination for federal income tax purposes.
As a result of investing in our common units, you may
become subject to state and local taxes and return filing
requirements in jurisdictions where we operate or own or acquire
properties.
In addition to federal income taxes, our 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 control 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, our unitholders
may be subject to penalties for failure to comply with those
requirements. We initially expect to conduct business in
Indiana, Kentucky, Michigan, Ohio and Pennsylvania. Each of
these states currently imposes a personal income tax on
individuals. As we make acquisitions or expand our business, we
may control 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. Our counsel
has not rendered an opinion on the state or local tax
consequences of an investment in our common units.
42
USE OF
PROCEEDS
We expect to receive net proceeds of approximately
$ million, after deducting
underwriting discounts and commissions but before paying
offering expenses, from the issuance and sale of common units
offered by this prospectus. We will use the net proceeds from
this offering to:
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repay in full the outstanding balance under our existing credit
facility, which was approximately $93.7 million at
March 19, 2010;
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distribute approximately
$ million to C&T Coal in
respect of its limited partner interest in us;
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distribute approximately
$ million to certain
participants in our LTIP in respect of their limited partner
interests in us; and
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pay offering expenses of approximately
$ million.
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We will retain the remaining net proceeds from this offering to
replenish approximately
$ million of our working
capital.
Immediately following the repayment of the outstanding balance
under our existing credit facility with the net proceeds of this
offering, we will enter into a new credit facility and borrow
approximately $ under that credit
facility. We will use the proceeds from that borrowing to:
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distribute approximately
$ million to AIM Oxford in
respect of its limited partner interest in us; and
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pay fees and expenses relating to our new credit facility of
approximately
$ million.
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A portion of the amounts to be repaid under our existing credit
facility with the net proceeds of this offering were used to
finance our acquisition of the surface mining operations of
Phoenix Coal in September 2009. As of March 19, 2010, we
had approximately $93.7 million of indebtedness outstanding
under our existing credit facility. This indebtedness had a
weighted average interest rate of 6.55% as of
March 19, 2010. Our existing credit facility matures in
August 2012.
Our estimates assume an initial public offering price of
$ per common unit (based upon the
mid-point of the price range set forth on the cover page of this
prospectus) and no exercise of the underwriters option to
purchase additional common units. An increase or decrease in the
initial public offering price of $1.00 per common unit would
cause the net proceeds from the offering, after deducting
underwriting discounts, to increase or decrease by
$ million. If the proceeds
increase due to a higher initial public offering price, we will
use the additional proceeds for general partnership purposes. If
the proceeds decrease due to a lower initial public offering
price, the amount that we have available for general partnership
purposes will decrease by a corresponding amount.
The proceeds from any exercise of the underwriters option
to purchase additional common units will be used to redeem from
C&T Coal and AIM Oxford that number of common units that
corresponds to the number of common units issued upon such
exercise, at a price per common unit equal to the proceeds per
common unit before expenses but after underwriting discounts.
Affiliates of Citigroup Global Markets Inc. are lenders under
our existing credit facility and will receive their
proportionate share of the repayment of the outstanding balance
under our existing credit facility by us in connection with this
offering.
43
CAPITALIZATION
The following table shows:
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our historical capitalization, as of December 31,
2009; and
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our pro forma, as adjusted capitalization as of
December 31, 2009, giving effect to:
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our entry into our new credit facility and the repayment of all
outstanding indebtedness under our existing credit facility;
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our receipt of net proceeds of
$ million from the issuance
and sale
of common
units to the public at an assumed initial offering price of
$ per unit;
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the application of the net proceeds from this offering of
approximately $ million
(based on the mid-point of the price range set forth on the
cover page of this prospectus) in the manner described in
Use of Proceeds; and
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the other transactions described in Summary
The Transactions.
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We derived this table from and it should be read in conjunction
with and is qualified in its entirety by reference to the
historical and pro forma consolidated financial statements and
the accompanying notes included elsewhere in this prospectus.
You should also read this table in conjunction with
Managements Discussion and Analysis of Financial
Condition and Results of Operations.
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As of December 31, 2009
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Pro Forma,
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Actual
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As Adjusted
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(in thousands)
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Cash and cash equivalents
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$
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3,366
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Long-term debt (including current maturities):
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Existing credit
facility
(1)
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90,729
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New credit
facility
(2)
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Other debt
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4,982
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Total long-term debt (including current maturities)
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$
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95,711
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Partners capital:
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Limited partners:
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Common unitholders public
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Common unitholders LTIP
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787
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Common unitholders sponsors
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53,173
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Subordinated unitholders sponsors
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General partner
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1,085
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Total Oxford Resource Partners, LP partners capital
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55,045
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Noncontrolling interest
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2,067
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Total partners capital
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57,112
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Total capitalization
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$
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152,823
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(1)
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As of March 19, 2010, we had
$93.7 million of borrowings under our existing credit
facility. This amount does not include $8.8 million of
letters of credit that were outstanding under our existing
credit facility as of March 19, 2010.
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(2)
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Does not include
$ million
in outstanding letters of credit that will be issued under our
new credit facility.
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44
DILUTION
Dilution is the amount by which the offering price will exceed
the net tangible book value per unit after the offering.
Assuming an initial public offering price of
$ per common unit, on a pro forma
basis as of December 31, 2009, after giving effect to our
entry into our new credit facility and repayment of all
outstanding indebtedness under our existing credit facility, the
issuance and sale
of common
units, the other transactions described in
Summary The Transactions and the
application of the net proceeds from this offering in the manner
described in Use of Proceeds, our net tangible book
value was approximately
$ million, or
$ per common unit. The pro forma
tangible net book value excludes
$ million of deferred
financing costs. Purchasers of common units in this offering
will experience substantial and immediate dilution in net
tangible book value per common unit for financial accounting
purposes, as illustrated in the following table.
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Assumed initial public offering price per common unit
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$
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Net tangible book value per common unit before the
offering
(1)
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$
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Increase in net tangible book value per common unit attributable
to purchasers in the offering
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Less: Pro forma net tangible book value per common unit after
the
offering
(2)
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Immediate dilution in net tangible book value per common unit to
purchasers in the
offering
(3)
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$
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(1)
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Determined by dividing the net tangible book value of the
contributed assets and liabilities by the number of units
( common
units, subordinated
units and the 2.0% general partner interest represented
by
general partner units) held by our general partner and its
affiliates and the participants under our LTIP.
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(2)
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Determined by dividing our pro forma net tangible book value,
after giving effect to the use of the net proceeds from this
offering, by the total number of units
( common
units, subordinated
units and the 2.0% general partner interest represented
by general
partner units) to be outstanding after this offering.
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(3)
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If the initial public offering price were to increase or
decrease by $1.00 per common unit, immediate dilution in net
tangible book value per common unit would increase or decrease
by $1.00.
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The following table sets forth the number of units that we will
issue and the total consideration contributed to us by our
general partner and its affiliates and the participants under
our LTIP in respect of their units and by the purchasers of
common units in this offering upon consummation of the
transactions contemplated by this prospectus.
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Units Acquired
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Total Consideration
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Number
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Percent
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Amount
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Percent
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($ in millions)
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General Partner and its
affiliates
(1)
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$
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%
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$
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%
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New Investors
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%
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%
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Total
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$
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100.0
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%
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$
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100.0
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%
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(1)
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Upon the consummation of the transactions contemplated by this
prospectus, our general partner and its affiliates, and the
participants under our LTIP, will
own
common
units, subordinated
units and a 2.0% general partner interest represented
by general
partner units.
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45
CASH
DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash
distribution policy in conjunction with the specific assumptions
included in this section. In addition, you should read
Forward-Looking Statements and Risk
Factors for information regarding statements that do not
relate strictly to historical or current facts and regarding
certain risks inherent in our business.
For additional information regarding our historical results
of operations, you should refer to our historical audited
consolidated financial statements as of and for the years ended
December 31, 2007, 2008 and 2009 included elsewhere in this
prospectus.
General
Rationale
for Our Cash Distribution Policy
Our cash distribution policy is consistent with the terms of our
partnership agreement, which requires that we distribute all of
our available cash quarterly. Under our partnership agreement,
available cash is generally defined to mean, for each quarter,
cash generated from our business in excess of the amount of cash
reserves established by our general partner to provide for the
conduct of our business, to comply with applicable law, any of
our debt instruments or other agreements or to provide for
future distributions to our unitholders for any one or more of
the next four quarters. Our cash distribution policy reflects a
basic judgment that our unitholders will be better served by
distributing our available cash rather than retaining it,
because, among other reasons, we believe we will generally
finance any expansion capital expenditures from external
financing sources. Because we are not subject to an entity-level
federal income tax, we expect to have more cash to distribute
than would be the case if we were subject to federal income tax.
Limitations
on Cash Distributions and Our Ability to Change Our Cash
Distribution Policy
There is no guarantee that we will distribute quarterly cash
distributions to our unitholders. Our cash distribution policy
is subject to certain restrictions and may be changed at any
time. The reasons for such uncertainties in our stated cash
distribution policy include the following factors:
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Our cash distribution policy will be subject to restrictions on
cash distributions under our new credit facility. Specifically,
we expect our new credit facility to contain financial tests and
covenants that we must satisfy before quarterly cash
distributions can be paid. These financial tests and covenants
are described in Managements Discussion and Analysis
of Financial Condition and Results of Operations
Liquidity and Capital Resources Credit
Facility. Should we be unable to satisfy these
restrictions included in our new credit facility or if we are
otherwise in default under our new credit facility, we would be
prohibited from making cash distributions notwithstanding our
cash distribution policy.
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Our general partner will have the authority to establish cash
reserves for the prudent conduct of our business and for future
cash distributions to our unitholders, and the establishment of
or increase in those reserves could result in a reduction in
cash distributions from levels we currently anticipate pursuant
to our stated cash distribution policy.
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While our partnership agreement requires us to distribute all of
our available cash, our partnership agreement, including the
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 other than in certain
limited circumstances where no unitholder approval is required.
However, after the subordination period has ended our
partnership agreement may 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
C&T Coal and AIM Oxford). At the closing of this offering,
C&T Coal and AIM Oxford will own our general partner,
approximately % of our outstanding
common units and all of our outstanding subordinated units.
Please read The Partnership Agreement
Amendment of Our Partnership Agreement.
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Even if our cash distribution policy is not modified or revoked,
the amount of distributions we pay under our cash distribution
policy and the decision to make any distribution is determined
by our general partner, taking into consideration the terms of
our partnership agreement.
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Under
Section 17-607
of the Delaware Act, we may not make a distribution if the
distribution would cause our liabilities to exceed the fair
value of our assets.
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We may lack sufficient cash to pay distributions to our
unitholders due to reduced revenues from sales of our products
and services or increases in our operating costs, SG&A
expenses, principal and interest payments on our outstanding
debt and working capital requirements.
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If we make distributions out of capital surplus, as opposed to
operating surplus, such distributions will constitute a return
of capital and will result in a reduction in the minimum
quarterly distribution and the target distribution levels.
Please read How We Make Cash Distributions
Distributions from Capital Surplus. We do not anticipate
that we will make any distributions from capital surplus.
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Our ability to make distributions to our unitholders depends on
the performance of our subsidiaries and their ability to
distribute cash to us, including cash distributions from
Harrison Resources, which requires the approval of the
noncontrolling interest holder. The ability of our subsidiaries
to make distributions to us may be restricted by, among other
things, the provisions of existing and future indebtedness,
applicable state partnership and limited liability company laws
and other laws and regulations.
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While we believe, based on our financial forecast and related
assumptions, that we will have sufficient cash to enable us to
pay the full minimum quarterly distribution on all of our common
units and subordinated units for the twelve months ending
June 30, 2011, our cash available for distribution
generated during the year ended December 31, 2009 would
have been sufficient to allow us to
pay %
and % of the minimum quarterly
distribution ($ per unit per
quarter, or $ on an annualized
basis) on our common units and subordinated units, respectively.
This represents % of the total
distributions payable to all of our unitholders and our general
partner.
Our
Ability to Grow is Dependent on Our Ability to Access External
Expansion Capital
We will distribute all of our available cash to our unitholders
on a quarterly basis. As a result, we expect that we will rely
primarily upon external financing sources, including commercial
bank borrowings and the issuance of debt and equity securities,
to fund any future expansion capital expenditures. To the extent
we are unable to finance growth externally, our cash
distribution policy will significantly impair our ability to
grow our asset base. In addition, because we will distribute all
of our available cash, our growth may not be as fast as
businesses that reinvest all of their available cash to expand
ongoing operations. To the extent we issue additional units, 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, which in turn may impact the available
cash that we have to distribute on each unit. There are no
limitations in our partnership agreement, and we do not
anticipate there being any limitations in our new credit
facility, 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.
Minimum
Quarterly Distribution Rate
Upon the consummation of this offering, the board of directors
of our general partner intends to establish a minimum quarterly
distribution of $ per unit for
each complete quarter, or $ per
unit on an annualized basis, to be paid within 45 days
after the end of each quarter. We will adjust our first
distribution for the period from the closing of this offering
through ,
2010 based on the actual length of the period. Our ability to
make cash distributions at the established minimum quarterly
distribution rate pursuant to our cash distribution policy will
be subject to the factors described above under
General Limitations on Cash
Distributions and Our Ability to Change Our Cash Distribution
Policy. The amount of available cash
47
needed to pay the minimum quarterly distribution on all of the
common units, subordinated units and general partner units to be
outstanding immediately after this offering for one quarter and
for four quarters is summarized in the table below:
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|
|
|
|
Number of Units
|
|
|
One Quarter
|
|
|
Four Quarters
|
|
|
Common units
|
|
|
|
|
|
|
|
|
|
|
|
|
Subordinated units
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner units
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of the date of this offering, our general partner will be
entitled to 2.0% of all distributions that we make prior to our
liquidation. Our general partners initial 2.0% interest in
these distributions may be reduced if we issue additional units
in the future and our general partner does not contribute a
proportionate amount of capital to us to maintain its initial
2.0% general partner interest. Our general partner will also
hold the incentive distribution rights, which entitle the holder
to increasing percentages, up to a maximum of 48%, of the cash
we distribute in excess of $ per
unit per quarter.
During the subordination period, before we make any quarterly
distributions to our subordinated unitholders, our common
unitholders are entitled to receive payment of the full minimum
quarterly distribution plus any arrearages in distributions of
the minimum quarterly distribution from prior quarters. Please
read How We Make Cash Distributions
Subordination Period. We cannot guarantee, however, that
we will pay the minimum quarterly distribution on the common
units in any quarter.
We do not have a legal obligation to pay distributions at our
minimum quarterly distribution rate or at any other rate except
as provided in our partnership agreement. Our cash distribution
policy is consistent with the terms of our partnership
agreement, which requires that we distribute all of our
available cash quarterly. Under our partnership agreement,
available cash is generally defined to mean, for each quarter,
cash generated from our business in excess of the amount of cash
reserves established by our general partner to provide for the
conduct of our business, to comply with applicable law, any of
our debt instruments or other agreements or to provide for
future distributions to our unitholders for any one or more of
the next four quarters.
Although holders of our common units may pursue judicial action
to enforce provisions of our partnership agreement, including
those related to requirements to make cash distributions as
described above, our partnership agreement provides that any
determination made by our general partner in its capacity as our
general partner must be made in good faith and that any such
determination will not be subject to any other standard imposed
by the Delaware Act or any other law, rule or regulation or at
equity. Our partnership agreement provides that, in order for a
determination by our general partner to be made in good
faith, our general partner must believe that the
determination is in our best interest. Please read
Conflicts of Interest and Fiduciary Duties.
Our cash distribution policy, as expressed in our partnership
agreement, may not be modified or repealed without amending our
partnership agreement; however, the actual amount of our cash
distributions for any quarter is subject to fluctuations based
on the amount of cash we generate from our business and the
amount of reserves our general partner establishes in accordance
with our partnership agreement as described above.
We will pay our distributions on or about the 15th day of
each of February, May, August and November to holders of record
on or about the 1st day of each such month. If the
distribution date does not fall on a business day, we will make
the distribution on the first business day immediately preceding
the indicated distribution date. We will adjust the quarterly
distribution for the period from the closing of this offering
through ,
2010 based on the actual length of the period.
Historical
and Forecasted Results of Operations and Cash Available for
Distribution
In this section, we present in detail the basis for our belief
that we will be able to pay the minimum quarterly distribution
on all of our common units and subordinated units and make the
related distribution on our general partners 2.0% general
partner interest for the twelve months ending June 30,
2011. We present a
48
table below, consisting of historical and forecasted results of
operations and cash available for distribution for the year
ended December 31, 2009 and the twelve months ending
June 30, 2011, respectively. In the table, we show our
historical results of operations and the amount of cash
available for distribution we would have had for the year ended
December 31, 2009 based on our historical consolidated
statement of operations included elsewhere in this prospectus
and our forecasted results of operations and the forecasted
amount of cash available for distribution for the twelve months
ending June 30, 2011 and the significant assumptions upon
which this forecast is based.
Our historical consolidated financial statements and the notes
to those statements included elsewhere in this prospectus should
be read together with Selected Historical and Pro Forma
Consolidated Financial and Operating Data and
Managements Discussion and Analysis of Financial
Condition and Results of Operations included elsewhere in
this prospectus.
Historical cash available for distribution generated during the
year ended December 31, 2009 would have been approximately
$ million. This amount would
have been sufficient to pay %
and % of the minimum quarterly
distribution ($ per quarter, or
$ on an annualized basis) on our
common units and subordinated units, respectively. This
represents % of the total
distributions payable to all of our unitholders and our general
partner.
The following table also sets forth our calculation of
forecasted cash available for distribution to our unitholders
and our general partner for the twelve months ending
June 30, 2011. We forecast that our cash available for
distribution generated during the twelve months ending
June 30, 2011 will be approximately
$ million. This amount would
be sufficient to pay the full minimum quarterly distribution of
$ per unit on all of our common
units and subordinated units and the related distribution on our
general partners 2.0% general partner interest for each
quarter in the twelve months ending June 30, 2011.
We are providing the financial forecast to supplement our
historical consolidated financial statements in support of our
belief that we will have sufficient cash available to allow us
to pay cash distributions on all of our outstanding common units
and subordinated units and the related distributions on our
general partners 2.0% general partner interest for the
twelve months ending June 30, 2011 at the minimum quarterly
distribution rate. Please read Significant
Forecast Assumptions for further information as to the
assumptions we have made for the financial forecast. Please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations Critical
Accounting Policies and Estimates for information as to
the accounting policies we have followed for the financial
forecast.
Our forecast reflects our judgment as of the date of this
prospectus of conditions we expect to exist and the course of
action we expect to take during the twelve months ending
June 30, 2011. We believe that our actual results of
operations will approximate those reflected in our forecast, but
we can give no assurance that our forecasted results will be
achieved. If our estimates are not achieved, we may not be able
to pay quarterly distributions on our common units and
subordinated units at the minimum quarterly distribution rate of
$ per unit (or
$ per unit on an annualized basis)
or any other rate. The assumptions and estimates underlying the
forecast are inherently uncertain and, though we consider them
reasonable as of the date of this prospectus, are subject to a
wide variety of significant business, economic and competitive
risks and uncertainties that could cause actual results to
differ materially from those contained in the forecast,
including, among others, risks and uncertainties contained in
Risk Factors. Accordingly, there can be no assurance
that the forecast is indicative of our future performance or
that actual results will not differ materially from those
presented in the forecast. Inclusion of the forecast in this
prospectus should not be regarded as a representation by any
person that the results contained in the forecast will be
achieved.
We do not, as a matter of course, make public forecasts as to
future sales, earnings or other results. However, we have
prepared the forecast set forth below to present the estimated
cash available for distribution to our unitholders and general
partner during the forecasted period. The accompanying forecast
was not prepared with a view toward complying with the
guidelines established by the American Institute of Certified
Public Accountants with respect to prospective financial
information, but, in our view, was prepared on a reasonable
basis, reflects the best currently available estimates and
judgments, and presents, to the best of managements
knowledge and belief, the expected course of
49
action and our expected future financial performance.
However, this information is not fact and should not be relied
upon as being necessarily indicative of future results, and
readers of this prospectus are cautioned not to place undue
reliance on the forecast.
Neither our independent auditors, nor any other independent
accountants, have compiled, examined or performed any procedures
with respect to the forecast contained herein, nor have they
expressed any opinion or any other form of assurance on such
information or its achievability, and assume no responsibility
for, and disclaim any association with, the forecast. We do not
intend to update or otherwise revise the forecast to reflect
circumstances existing since its preparation or to reflect the
occurrence of unanticipated events, even if any or all of the
underlying assumptions are shown to be in error. Furthermore, we
do not intend to update or revise the forecast to reflect
changes in general economic or industry conditions.
50
Oxford
Resource Partners, LP
Cash Available for Distribution
|
|
|
|
|
|
|
|
|
|
|
Historical
|
|
|
Forecasted
(1)
|
|
|
|
Year Ended
|
|
|
Twelve Months
|
|
|
|
December 31, 2009
|
|
|
Ending June 30, 2011
|
|
|
|
(in thousands, except per unit and
|
|
|
|
per ton amounts)
|
|
|
Operating data:
|
|
|
|
|
|
|
|
|
Coal produced in tons
|
|
|
5,846
|
|
|
|
8,079
|
|
Coal purchased in tons
|
|
|
530
|
|
|
|
730
|
|
|
|
|
|
|
|
|
|
|
Coal available for sale in tons
|
|
|
6,376
|
|
|
|
8,809
|
|
|
|
|
|
|
|
|
|
|
Coal sold in tons
|
|
|
6,311
|
|
|
|
8,789
|
|
Increase in coal inventory in tons
|
|
|
65
|
|
|
|
20
|
|
Coal sales in tons
sold/committed
(2)
|
|
|
6,311
|
|
|
|
8,121
|
|
Coal sales in tons uncommitted
|
|
|
n/a
|
|
|
|
668
|
|
Average sales price per ton
sold/committed
(2)
|
|
$
|
40.27
|
|
|
$
|
37.87
|
|
Average sales price per ton uncommitted
|
|
|
n/a
|
|
|
$
|
40.32
|
|
Selected financial data:
|
|
|
|
|
|
|
|
|
Coal sales revenue
sold/committed
(2)
|
|
$
|
254,171
|
|
|
$
|
307,638
|
|
Coal sales revenue uncommitted
|
|
|
n/a
|
|
|
|
26,934
|
|
Transportation revenue
|
|
|
32,490
|
|
|
|
44,894
|
|
Royalty and non-coal
revenue
(3)
|
|
|
7,183
|
|
|
|
9,478
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
293,844
|
|
|
|
388,944
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
Cost of coal sales (excluding DD&A, shown separately)
|
|
|
170,698
|
|
|
|
226,382
|
|
Cost of purchased coal
|
|
|
19,487
|
|
|
|
23,379
|
|
Cost of transportation
|
|
|
32,490
|
|
|
|
44,894
|
|
Depreciation, depletion and amortization
|
|
|
25,902
|
|
|
|
37,365
|
|
Selling, general and administrative
expenses
(4)
|
|
|
13,242
|
|
|
|
14,703
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
261,819
|
|
|
|
346,723
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
32,025
|
|
|
|
42,221
|
|
Interest income
|
|
|
35
|
|
|
|
15
|
|
Interest expense
|
|
|
(6,484
|
)
|
|
|
(7,093
|
)
|
Gain from purchase of
business
(5)
|
|
|
3,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
29,399
|
|
|
|
35,143
|
|
Less: income attributable to noncontrolling interest
|
|
|
(5,895
|
)
|
|
|
(7,531
|
)
|
|
|
|
|
|
|
|
|
|
Net income attributable to Oxford Resource Partners, LP
unitholders
|
|
$
|
23,504
|
|
|
$
|
27,612
|
|
|
|
|
|
|
|
|
|
|
Plus:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
25,902
|
|
|
|
37,365
|
|
Interest expense
|
|
|
6,484
|
|
|
|
7,093
|
|
Non-cash equity compensation expense
|
|
|
472
|
|
|
|
433
|
|
Less:
|
|
|
|
|
|
|
|
|
Interest Income
|
|
|
35
|
|
|
|
15
|
|
Gain from purchase of
business
(5)
|
|
|
3,823
|
|
|
|
|
|
Amortization of below-market coal sales contracts
|
|
|
1,705
|
|
|
|
2,132
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA
(6)
|
|
$
|
50,799
|
|
|
$
|
70,356
|
|
Less:
|
|
|
|
|
|
|
|
|
Cash interest expense, net of interest income
|
|
|
5,970
|
|
|
|
6,221
|
|
Maintenance capital
expenditures
(7)
|
|
|
27,461
|
|
|
|
32,269
|
|
|
|
|
|
|
|
|
|
|
Cash available for distribution
|
|
$
|
17,368
|
|
|
$
|
31,866
|
|
|
|
|
|
|
|
|
|
|
Implied cash distributions at the minimum quarterly
distribution rate:
|
|
|
|
|
|
|
|
|
Annualized minimum quarterly distribution per unit
|
|
|
|
|
|
|
|
|
Distributions to public common unitholders
|
|
|
|
|
|
|
|
|
Distributions to participants in LTIP
|
|
|
|
|
|
|
|
|
Distributions to C&T Coal and AIM Oxford common
units
|
|
|
|
|
|
|
|
|
Distributions to C&T Coal and AIM Oxford
subordinated units
|
|
|
|
|
|
|
|
|
Distributions to general partner
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total distributions to unitholders and general
partner
(8)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess (shortfall)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
The forecasted column is based on
the assumptions set forth in Significant
Forecast Assumptions below.
|
51
|
|
|
(2)
|
|
Represents coal sold for 2009 on a
historical basis and coal committed for sale for the twelve
months ending June 30, 2011. The forecast period amount
includes 0.2 million tons that are subject to a price
re-opener under a long-term coal sales contract.
|
|
(3)
|
|
Consists of royalty payments we
receive on our underground coal reserves as well as limestone
sales, barge loading fees and other revenue.
|
|
(4)
|
|
Historical SG&A expenses for
the year ended December 31, 2009 include one-time expenses
of $1.6 million associated with the Phoenix Coal acquisition and
$1.0 million of legal fees incurred in renegotiating our
existing credit facility, but do not include incremental
SG&A expenses of approximately $3.0 million that we
expect to incur as a result of being a publicly traded
partnership. However, forecasted SG&A expenses for the
twelve months ended June 30, 2011 include such incremental
SG&A expenses.
|
|
(5)
|
|
On September 30, 2009, we
acquired all of the active surfacing mining operations of
Phoenix Coal. The purchase price of this acquisition was less
than the fair value of the net assets and liabilities we
acquired. We recorded this difference as a gain of
$3.8 million for the year ending December 31, 2009.
|
|
(6)
|
|
This table presents a
reconciliation of Adjusted EBITDA to net income (loss)
attributable to our unitholders for each of the periods
indicated. Adjusted EBITDA is a non-GAAP financial measure,
which we use in our business as it is an important supplemental
measure of our performance. Adjusted EBITDA represents net
income (loss) attributable to our unitholders before interest,
taxes, depreciation, depletion and amortization, gain from
purchase of a business, amortization of below-market coal sales
contracts and non-cash equity compensation expense. This measure
is not calculated or presented in accordance with GAAP. We
explain this measure below and reconcile it to its most directly
comparable financial measures calculated and presented in
accordance with GAAP.
|
|
|
|
Adjusted EBITDA is used as a
supplemental financial measure by management and by external
users of our financial statements, such as investors and
lenders, to assess:
|
|
|
|
|
|
our financial performance without regard to financing methods,
capital structure or income taxes;
|
|
|
|
our ability to generate cash sufficient to pay interest on our
indebtedness and to make distributions to our unitholders and
our general partner;
|
|
|
|
our compliance with certain financial covenants applicable to
our credit facility; and
|
|
|
|
our ability to fund capital expenditure projects from operating
cash flows.
|
|
|
|
|
|
Adjusted EBITDA should not be
considered an alternative to net income (loss) attributable to
our unitholders, income from operations, cash flows from
operating activities or any other measure of performance
presented in accordance with GAAP. Adjusted EBITDA excludes
some, but not all, items that affect net income (loss)
attributable to our unitholders, income from operations and cash
flows, and these measures may vary among other companies.
Therefore, Adjusted EBITDA as presented below may not be
comparable to similarly titled measures of other companies.
|
|
(7)
|
|
Historically we have not made a
distinction between maintenance capital expenditures and other
capital expenditures. For purposes of this presentation,
however, we have evaluated our 2009 capital expenditures to
determine which of them would have been classified as
maintenance capital expenditures in accordance with our
partnership agreement at the time they were made. Based on this
evaluation, we estimate that our maintenance capital
expenditures for the year ended December 31, 2009 would
have been $27.5 million. The amount of our actual
maintenance capital expenditures may differ substantially from
period to period, which could cause similar fluctuations in the
amounts of operating surplus, adjusted operating surplus and
cash available for distribution to our unitholders, if we
subtracted actual maintenance capital expenditures from
operating surplus. To eliminate these fluctuations, our
partnership agreement will require that an estimate of the
maintenance capital expenditures necessary to maintain our asset
base be subtracted from operating surplus each quarter as
opposed to amounts actually spent on maintenance capital
expenditures. The $32.3 million of maintenance capital
expenditures for the forecasted twelve months ending
June 30, 2011 represents estimated maintenance capital
expenditures as defined in our partnership agreement. 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,
provided that any change must be approved by the Conflicts
Committee. We expect our actual maintenance capital expenditures
during the forecast period to be consistent with our estimated
maintenance capital expenditures for that period. We have not
included any expansion capital expenditures in the forecast
period. To the extent we incur such expenditures during the
forecast period, we expect to fund those with borrowings under
our new credit facility, issuance of debt and equity securities
or other external sources of financings. Please read How
We Make Cash Distributions Operating Surplus and
Capital Surplus Definition of Operating
Surplus for a further discussion of the effects of our use
of estimated maintenance capital expenditures.
|
|
(8)
|
|
Represents the amount that would be
required to pay distributions for four quarters at our minimum
quarterly distribution rate of $
per unit on all of the common and subordinated units that will
be outstanding immediately following this offering and the
related distributions on our general partners 2.0% general
partner interest.
|
52
Significant
Forecast Assumptions
The forecast has been prepared by and is the responsibility of
management. Our forecast reflects our judgment as of the date of
this prospectus of conditions we expect to exist and the course
of action we expect to take during the twelve months ending
June 30, 2011. While the assumptions disclosed in this
prospectus are not all-inclusive, the assumptions listed below
are those that we believe are significant to our forecasted
results of operations. We believe we have a reasonable objective
basis for these assumptions. We believe our actual results of
operations will approximate those reflected in our forecast, but
we can give no assurance that our forecasted results will be
achieved. There will likely be differences between our forecast
and the actual results and those differences could be material.
If the forecast is not achieved, we may not be able to pay cash
distributions on our common units at the minimum quarterly
distribution rate or at all.
Production and Revenues.
We forecast that our
total revenues for the twelve months ending June 30, 2011
will be approximately $389.0 million, as compared to
approximately $293.8 million for 2009. Our forecast of
total revenues is based primarily on the following assumptions:
|
|
|
|
|
We estimate that we will produce approximately 8.1 million
tons of coal during the twelve months ending June 30, 2011,
as compared to approximately 5.8 million tons we produced
in 2009. This estimated volume increase is primarily due to
additional coal production from our Muhlenberg County mining
complex that we acquired in the Phoenix Coal acquisition, as a
result of a full year of production from these properties being
reflected in the forecast period as well as our deployment of
larger equipment and implementation of more efficient mining
practices at that complex. We expect to produce an aggregate of
approximately 2.1 million tons of coal from our Muhlenberg
County mining complex in the forecast period compared to
0.4 million tons of coal during the fourth quarter of 2009
(or 1.6 million tons on an annualized basis). We expect
that our coal production during the forecast period from our
other mining complexes will increase slightly compared to 2009.
|
|
|
|
We estimate that we will sell approximately 8.8 million
tons of coal during the twelve months ending June 30, 2011,
as compared to approximately 6.3 million tons we sold in
2009. We have committed to sell approximately 8.1 million
tons, of which 7.9 million tons are priced and
0.2 million tons are subject to price re-openers under a
long-term coal sales contract. As described below, we expect to
purchase approximately 0.7 million tons to balance our
estimated sales volumes. Our estimates assume that we will be
successful in repricing these 0.2 million tons at slightly
higher prices. Our estimates also assume that our customers with
options to take delivery of additional tons during the forecast
period will not exercise their options.
|
|
|
|
We estimate that the average sales price per ton for committed
tons will be $37.87 for the twelve months ending June 30,
2011, as compared to $40.27 for 2009. This estimate takes into
account prices in our long-term contracts, including our
estimate of the amount of applicable cost pass through or
inflation adjustment provisions, and gives effect to the full
year impact of the lower priced coal sales contracts that we
assumed in connection with the Phoenix Coal acquisition, and the
expiration of a short-term supplemental price increase that took
effect in 2009 in connection with the amendment of a long-term
coal sales contract.
|
|
|
|
We estimate that the average sales price per ton for uncommitted
tons will be $40.32 for the twelve months ending June 30,
2011. Our estimated average sales price for these tons assumes
that we will be successful in selling those uncommitted tons at
prices that reflect managements current estimates of
market conditions and pricing trends.
|
|
|
|
We estimate that our royalty and non-coal revenue, which
consists of royalty payments received on our underground coal
reserves as well as limestone sales, barge loading fees and
other sources of revenue, will be $9.5 million for the
twelve months ending June 30, 2011, as compared to
$7.2 million for 2009. This increase is primarily due to
increased barge-loading fees under a new contract at our Island
river terminal in western Kentucky. We have assumed that the
overriding royalty payments on our underground coal reserves and
all other non-coal revenues during the forecast period will
slightly increase compared to the amounts we received in 2009.
|
53
Purchased Coal.
We estimate that we will
purchase approximately 0.7 million tons of coal from third
parties for the twelve months ending June 30, 2011, as
compared to approximately 0.5 million tons we purchased in
2009. This increase is primarily due to the full year impact of
a long-term coal purchase contract that we assumed in connection
with the Phoenix Coal acquisition under which we purchase
approximately 0.4 million tons annually.
Cost of Coal Sales.
We estimate that our cost
of coal sales will be $226.4 million for the twelve months
ending June 30, 2011, as compared to $170.7 million
for 2009. The increase in cost of coal sales for the forecast
period as compared to 2009 is primarily attributable to
increased coal production, partially offset by a decrease in our
cost of coal sales per ton. We estimate that our cost of coal
sales per ton for the twelve months ending June 30, 2011
will be $28.02, as compared to $29.20 for 2009. This decrease is
attributable to a projected decrease in diesel fuel and
explosives costs on a per ton basis, partially offset by higher
non-commodity-related operating costs on a per ton basis due to
the Phoenix Coal acquisition.
Cost of Purchased Coal.
We forecast our cost
of purchased coal will be $23.4 million for the twelve
months ending June 30, 2011, as compared to
$19.5 million for 2009. This increase is primarily
attributable to more tons of coal being purchased in the
forecast period as compared to 2009, partially offset by a
decrease in the cost per ton of purchased coal. We estimate that
the cost per ton of purchased coal will be $32.02 for the twelve
months ending June 30, 2011, as compared to $36.79 for
2009. During the first quarter of 2009, we bought a higher
percentage of our purchased coal on the spot market in order to
meet our coal sales obligations. Since that time, due to a
long-term coal purchase contract under which we purchase
approximately 0.4 million tons annually, our need for spot
market purchases has declined.
Depreciation, Depletion and Amortization.
We
forecast depreciation, depletion and amortization expense to be
approximately $37.4 million for the twelve months ending
June 30, 2011, as compared to approximately
$25.9 million for 2009. This increase is primarily due to
the full year impact of the Phoenix Coal acquisition.
Selling, General and Administrative
Expenses.
We forecast SG&A expenses to be
approximately $14.7 million for the twelve months ending
June 30, 2011, as compared to approximately
$13.2 million for 2009. This increase is primarily
attributable to $3.0 million in incremental SG&A
expenses that we expect to incur as a result of being a publicly
traded partnership, partially offset by a decrease in
acquisition costs and legal fees, which were higher in 2009 due
to the one-time costs of the Phoenix Coal acquisition and fees
incurred in renegotiating our existing credit facility.
Harrison Resources Distributions.
We estimate
that the aggregate cash distributions we will receive from
Harrison Resources for the twelve months ending June 30,
2011 will be $7.5 million as compared to $6.3 million
in 2009. In the forecast period, we have assumed that the cash
distributions we will receive from Harrison Resources will
constitute substantially all of our Adjusted EBITDA attributable
to Harrison Resources. This assumption is consistent with the
distributions we received from, and the portion of our Adjusted
EBITDA attributable to, Harrison Resources in 2009.
Financing.
We forecast interest expense of
approximately $7.1 million for the twelve months ending
June 30, 2011, as compared to approximately
$6.5 million for 2009. Our interest expense for the twelve
months ending June 30, 2011 is based on the following
assumptions:
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we will repay in full the outstanding borrowings of
$ under our existing credit
facility with a portion of the proceeds from the offering;
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we will borrow approximately
$ million under our new
credit facility;
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for calculating our interest expense, we have assumed a weighted
average interest rate over the forecast period of 5.0% under our
new credit facility, which is lower than the weighted average
interest rate for 2009 under our existing credit
facility; and
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we will maintain a low cash balance.
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Capital Expenditures.
We forecast capital
expenditures for the twelve months ending June 30, 2011
based on the following assumptions:
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Our estimated maintenance capital expenditures for the forecast
period are $32.3 million for the twelve months ending
June 30, 2011, as compared to approximately
$27.5 million of actual maintenance capital expenditures
for 2009. This increase is primarily due to a larger asset base,
including replacement of reserves, following the Phoenix Coal
acquisition. We expect to fund maintenance capital expenditures
from cash generated by our operations and from borrowings under
our new credit facility.
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We have not included any expansion capital expenditures in our
forecast for the twelve months ending June 30, 2011.
Expansion capital expenditures are cash expenditures incurred
for acquisitions or capital improvements, which are (i) any
addition or improvement to our capital assets, (ii) the
acquisition of existing, or the construction of new, capital
assets (including coal mines and related assets), or
(iii) capital contributions to an entity in which we own an
equity interest for our pro rata share of the cost of
acquisitions of existing, or the construction of new, capital
assets by such entity, in each case if such addition,
improvement, acquisition or construction is made to increase our
long-term operating capacity, asset base or operating income.
Examples of expansion capital expenditures include the
acquisition of reserves, equipment or a new mine or the
expansion of an existing mine, to the extent such expenditures
are expected to expand our long-term operating capacity, asset
base or operating income. We had approximately
$23.7 million of actual capital expenditures for 2009 that
we would have classified as expansion capital expenditures if we
had distinguished between expansion capital expenditures and
other capital expenditures during that period. Of the
$23.7 million, approximately $18.3 million was
attributable to the Phoenix Coal acquisition and approximately
$5.4 million was attributable to the purchase of other
additional coal reserves.
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Regulatory, Industry and Economic Factors.
We
forecast for the twelve months ending June 30, 2011 based
on the following assumptions related to regulatory, industry and
economic factors:
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no material nonperformance or credit-related defaults by
suppliers, customers or vendors, or shortage of skilled labor;
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all supplies and commodities necessary for production and
sufficient transportation will be readily available;
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no new federal, state or local regulation of the portions of the
mining industry in which we operate or any interpretation of
existing regulation that in either case will be materially
adverse to our business;
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no material unforeseen geologic conditions or equipment problems
at our mining locations;
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no material accidents, weather-related incidents, unscheduled
downtime or similar unanticipated events;
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no major adverse change in the coal markets in which we operate
resulting from supply or production disruptions, reduced demand
for our coal or significant changes in the market prices of
coal; and
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no material changes in market, regulatory or overall economic
conditions.
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55
HOW WE
MAKE CASH DISTRIBUTIONS
Distributions
of Available Cash
General
Our partnership agreement requires that, within 45 days
after the end of each quarter, we distribute our available cash
to unitholders of record on the applicable record date. We will
adjust the minimum quarterly distribution for the period from
the closing of the offering
through ,
2010 based on the actual length of the period.
Definition
of Available Cash
Available cash generally means, for any quarter, all cash on
hand at the end of the quarter:
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less the amount of cash reserves established by our general
partner at the date of determination of available cash for the
quarter to:
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provide for the proper conduct of our business (including
reserves for our future capital expenditures and anticipated
future credit needs subsequent to that quarter);
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comply with applicable law, any of our debt instruments or other
agreements; and
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provide funds for distributions to our unitholders and to our
general partner for any one or more of the next four quarters;
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plus, if our general partner so determines, all or any portion
of the cash on hand on the date of determination of available
cash for the quarter.
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Intent
to Distribute the Minimum Quarterly Distribution
We intend to make a minimum quarterly distribution to the
holders of our common units and subordinated units of
$ per unit, or
$ on an annualized basis, to the
extent we have sufficient cash from our operations after the
establishment of cash reserves and the payment of costs and
expenses, including reimbursements of expenses to our general
partner. However, there is no guarantee that we will pay the
minimum quarterly distribution on our units in any quarter. Even
if our cash distribution policy is not modified or revoked, the
amount of distributions paid under our policy and the decision
to make any distribution is determined by our general partner,
taking into consideration the terms of our partnership
agreement. Please read Managements Discussion and
Analysis of Financial Condition and Results of
Operations Liquidity and Capital
Resources Credit Facility for a discussion of
the restrictions to be included in our new credit facility that
may restrict Oxford Mining Companys ability to make
distributions to us.
General
Partner Interest and Incentive Distribution Rights
As of the date of this offering, our general partner is entitled
to 2.0% of all quarterly distributions that we make prior to our
liquidation. This general partner interest will be represented
by
general partner units upon the completion of this offering. Our
general partner has the right, but not the obligation, to
contribute a proportionate amount of capital to us to maintain
its current general partner interest. Our general partners
initial 2.0% interest in our distributions may be reduced if we
issue additional limited partner units in the future and our
general partner does not contribute a proportionate amount of
capital to us to maintain its 2.0% general partner interest.
Our general partner also currently holds incentive distribution
rights that entitle it to receive increasing percentages, up to
a maximum of 50.0%, of the cash we distribute from operating
surplus (as defined below) in excess of
$ per unit per quarter. The
maximum distribution of 50.0% includes distributions paid to our
general partner on its 2.0% general partner interest and assumes
that our general partner maintains its general partner interest
at 2.0%. The maximum distribution of 50.0% does not include any
distributions that our
56
general partner may receive on common units or subordinated
units that it owns. Please read General
Partner Interest and Incentive Distribution Rights for
additional information.
Operating
Surplus and Capital Surplus
Overview
All cash distributed to unitholders will be characterized as
either operating surplus or capital
surplus. We treat distributions of available cash from
operating surplus differently than distributions of available
cash from capital surplus.
Definition
of Operating Surplus
We define operating surplus as:
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$ million (as described
below); plus
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all of our cash receipts after the closing of this offering,
excluding cash from interim capital transactions (as defined
below); less
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all of our operating expenditures (as defined below) after the
closing of this offering; less
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the amount of cash reserves established by our general partner
prior to the date of determination of available cash to provide
funds for future operating expenditures.
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As described above, operating surplus does not reflect actual
cash on hand that is available for distribution to our
unitholders. For example, it includes a provision that will
enable us, if we choose, to distribute as operating surplus up
to $ million of cash we
receive in the future from non-operating sources such as asset
sales, issuances of securities and long-term borrowings that
would otherwise be distributed as capital surplus.
We define interim capital transactions as (i) borrowings,
(ii) sales of equity and debt securities, (iii) sales
or other dispositions of assets outside the ordinary course of
business, (iv) capital contributions received,
(v) corporate reorganizations or restructurings and
(vi) the termination of interest rate hedge contracts or
commodity hedge contracts prior to the termination date
specified therein (provided that cash receipts from any such
termination will be included in operating surplus in equal
quarterly installments over the remaining scheduled life of such
contract).
We define operating expenditures as all of our cash
expenditures, including, but not limited to, taxes,
reimbursements of expenses to our general partner, interest
payments, payments made in the ordinary course of business under
interest rate hedge contracts and commodity hedge contracts,
estimated maintenance capital expenditures (as discussed in
further detail below) and non-pro rata repurchases of units
(other than those made with the proceeds of an interim capital
transaction), provided that operating expenditures will not
include:
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payments (including prepayments and prepayment penalties) of
principal of and premium on indebtedness;
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expansion capital expenditures;
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actual maintenance capital expenditures;
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payment of transaction expenses (including taxes) relating to
interim capital transactions; or
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distributions to partners.
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Capital
Expenditures
Maintenance capital expenditures are cash expenditures
(including expenditures for the addition or improvement to our
capital assets) made to maintain or replace, including over the
long term, our operating capacity, asset base or operating
income. Examples of maintenance capital expenditures include
capital
57
expenditures associated with the replacement of equipment and
coal reserves, whether through the expansion of an existing mine
or the acquisition or development of new reserves, to the extent
such expenditures are made to maintain our operating capacity,
asset base or operating income. Maintenance capital expenditures
will also include reclamation expenses.
Because our maintenance capital expenditures can be irregular,
the amount of our actual maintenance capital expenditures may
differ substantially from period to period, which could cause
similar fluctuations in the amounts of operating surplus,
adjusted operating surplus and cash available for distribution
to our unitholders if we subtracted actual maintenance capital
expenditures from operating surplus.
Our partnership agreement requires that an estimate of the
average quarterly maintenance capital expenditures necessary
over the long term be subtracted from operating surplus each
quarter as opposed to the actual amounts spent. The amount of
estimated maintenance capital expenditures deducted from
operating surplus for those periods will be subject to review
and change by our general partner at least once a year. The
estimate will be made annually and whenever an event occurs that
is likely to result in a material adjustment to the amount of
our maintenance capital expenditures on a long-term basis, such
as a major acquisition or the introduction of new governmental
regulations that will impact our business. For purposes of
calculating operating surplus (other than when used to determine
whether the subordination period has ended), any adjustment to
this estimate will be prospective only. For a discussion of the
amounts we have allocated toward estimated maintenance capital
expenditures, please read Cash Distribution Policy and
Restrictions on Distributions.
The use of estimated maintenance capital expenditures in
calculating operating surplus will have the following effects:
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it will reduce the risk that maintenance capital expenditures in
any one quarter will be large enough to render operating surplus
less than the initial quarterly distribution to be paid on all
the units for the quarter and subsequent quarters;
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it will increase our ability to distribute as operating surplus
cash we receive from non-operating sources;
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it will be more difficult for us to raise our distribution above
the minimum quarterly distribution and pay incentive
distributions on the incentive distribution rights held by our
general partner; and
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it will reduce the likelihood that a large maintenance capital
expenditure in a period will prevent our general partners
affiliates from being able to convert some or all of their
subordinated units into common units since the effect of an
estimate is to spread the expected expense over several periods,
thereby mitigating the effect of the actual payment of the
expenditure on any single period.
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Expansion capital expenditures are cash expenditures incurred
for acquisitions or capital improvements, which are (i) any
addition or improvement to our capital assets, (ii) the
acquisition of existing, or the construction of new, capital
assets (including coal mines and related assets), or
(iii) capital contributions to an entity in which we own an
equity interest for our pro rata share of the cost of
acquisitions of existing, or the construction of new, capital
assets by such entity, in each case if such addition,
improvement, acquisition or construction is made to increase our
long-term operating capacity, asset base or operating income.
Examples of expansion capital expenditures include the
acquisition of reserves, equipment or a new mine or the
expansion of an existing mine, to the extent such capital
expenditures are expected to expand our long-term operating
capacity, asset base or operating income. Expansion capital
expenditures are not subtracted from operating surplus.
Subordination
Period
General
Our partnership agreement provides that, during the
subordination period (which we define below), the common units
will have the right to receive distributions of available cash
from operating surplus each quarter in an amount equal to
$ per common unit, which amount is
defined in our partnership agreement as the minimum quarterly
distribution, plus any arrearages in the payment of the minimum
quarterly distribution on the common units from prior quarters,
before any distributions of available cash from operating
surplus may
58
be made on the subordinated units. These units are deemed
subordinated because for a period of time, referred
to as the subordination period, the subordinated units will not
be entitled to receive any distributions until the common units
have received the minimum quarterly distribution plus any
arrearages from prior quarters. Furthermore, no arrearages will
be paid on the subordinated units. The practical effect of the
subordinated units is to increase the likelihood that during the
subordination period there will be available cash to be
distributed on the common units.
Definition
of Subordination Period
The subordination period will begin upon the date of this
offering and will extend until the first business day of any
quarter beginning after June 30, 2013 that each of the
following tests are met:
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distributions of available cash from operating surplus on each
of the outstanding common units, subordinated units and general
partner units equaled or exceeded the minimum quarterly
distribution for each of the three consecutive, non-overlapping
four-quarter periods immediately preceding that date;
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the adjusted operating surplus (as defined below)
generated during each of the three consecutive, non-overlapping
four-quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distributions on all
of the outstanding common units, subordinated units and general
partner units during those periods on a fully diluted basis
during those periods; and
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there are no arrearages in payment of the minimum quarterly
distribution on the common units.
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For purposes of determining whether sufficient adjusted
operating surplus has been generated under the above conversion
test, the Conflicts Committee may adjust operating surplus
upwards or downwards if it determines in good faith that the
amount of estimated maintenance capital expenditures used in the
determination of adjusted operating surplus was materially
incorrect, based on the circumstances prevailing at the time of
the original estimate, for any one or more of the preceding two
four-quarter periods.
Early
Termination of Subordination Period
Notwithstanding the foregoing, the subordination period will
automatically terminate and all of the subordinated units will
convert into common units on a
one-for-one
basis if each of the following occurs:
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distributions of available cash from operating surplus on each
of the outstanding common units, subordinated units and general
partner units equaled or exceeded
$ per quarter (150.0% of the
minimum quarterly distribution) for each calendar quarter in the
immediately preceding four-quarter period;
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the adjusted operating surplus (as defined below)
generated during each calendar quarter in the immediately
preceding four-quarter period equaled or exceeded the sum of
$ (150.0% of the minimum quarterly
distribution) on each of the outstanding common units,
subordinated units and general partner units during that period
on a fully diluted basis; and
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there are no arrearages in payment of the minimum quarterly
distributions on the common units.
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Expiration
of the Subordination Period
When the subordination period ends, each outstanding
subordinated unit will convert into one common unit and will
participate pro-rata with the other common units in
distributions of available cash. In addition, if the unitholders
remove our general partner other than for cause and no units
held by our general partner and its affiliates are voted in
favor of such removal:
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the subordination period will end and each subordinated unit
will immediately convert into one common unit;
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any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
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59
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our general partner will have the right to convert its general
partner interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests.
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Definition
of Adjusted Operating Surplus
Adjusted operating surplus is intended to reflect the cash
generated from operations during a particular period and
therefore excludes net drawdowns of reserves of cash generated
in prior periods. Adjusted operating surplus consists of:
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operating surplus generated with respect to that period; less
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any net decrease in cash reserves for operating expenditures
with respect to that period not relating to an operating
expenditure made with respect to that period; plus
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any net decrease made in subsequent periods to cash reserves for
operating expenditures initially established with respect to
such period to the extent such decrease results in a reduction
in adjusted operating surplus in subsequent periods; plus
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any net increase in cash reserves for operating expenditures
with respect to that period required by any debt instrument for
the repayment of principal, interest or premium.
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Distributions
of Available Cash from Operating Surplus during the
Subordination Period
We will make distributions of available cash from operating
surplus for any quarter during the subordination period in the
following manner:
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first
, 98% to the common unitholders, pro rata, and 2.0%
to our general partner, until we distribute for each outstanding
common unit an amount equal to the minimum quarterly
distribution for that quarter;
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second
, 98% to the common unitholders, pro rata, and 2.0%
to our general partner, until we distribute for each outstanding
common unit an amount equal to any arrearages in payment of the
minimum quarterly distribution on the common units for any prior
quarters during the subordination period;
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third
, 98% to the subordinated unitholders, pro rata, and
2.0% to our general partner, until we distribute for each
subordinated unit an amount equal to the minimum quarterly
distribution for that quarter; and
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thereafter
, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
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The preceding discussion is based on the assumptions that our
general partner maintains its 2.0% general partner interest and
that we do not issue additional classes of equity securities.
Distributions
of Available Cash from Operating Surplus after the Subordination
Period
We will make distributions of available cash from operating
surplus for any quarter after the subordination period in the
following manner:
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first
, 98% to all unitholders, pro rata, and 2.0% to our
general partner, until we distribute for each outstanding unit
an amount equal to the minimum quarterly distribution for that
quarter; and
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thereafter
, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
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The preceding discussion is based on the assumptions that our
general partner maintains its 2.0% general partner interest and
that we do not issue additional classes of equity securities.
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General
Partner Interest and Incentive Distribution Rights
Our partnership agreement provides that our general partner
initially will be entitled to 2.0% of all distributions that we
make prior to our liquidation. Our general partner has the
right, but not the obligation, to contribute a proportionate
amount of capital to us to maintain its 2.0% general partner
interest if we issue additional units. Our general
partners 2.0% interest, and the percentage of our cash
distributions to which it is entitled from such 2.0% interest,
will be proportionately reduced if we issue additional units in
the future and our general partner does not contribute a
proportionate amount of capital to us in order to maintain its
2.0% general partner interest. Our general partner will be
entitled to make a capital contribution in order to maintain its
2.0% general partner interest in the form of the contribution to
us of common units based on the current market value of the
contributed common units.
Incentive distribution rights represent the right to receive an
increasing percentage (13.0%, 23.0% and 48.0%) of quarterly
distributions of available cash from operating surplus after the
minimum quarterly distribution and the target distribution
levels have been achieved. Our general partner currently holds
the incentive distribution rights, but may transfer these rights
separately from its general partner interest, subject to
restrictions in our partnership agreement.
The following discussion assumes that our general partner
maintains its 2.0% general partner interest, that there are no
arrearages on common units and that our general partner
continues to own the incentive distribution rights.
If for any quarter:
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we have distributed available cash from operating surplus to the
unitholders in an amount equal to the minimum quarterly
distribution; and
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we have distributed available cash from operating surplus on
outstanding common units and the general partner interest in an
amount necessary to eliminate any cumulative arrearages in
payment of the minimum quarterly distribution to the common
unitholders;
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then, we will distribute any additional available cash from
operating surplus for that quarter among the unitholders and our
general partner in the following manner:
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first
, 98% to all unitholders, pro rata, and 2.0% to our
general partner, until each unitholder receives a total of
$ per unit for that quarter (the
first target distribution);
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second
, 85% to all unitholders, pro rata, and 15% to our
general partner, until each unitholder receives a total of
$ per unit for that quarter (the
second target distribution);
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third
, 75% to all unitholders, pro rata, and 25% to our
general partner, until each unitholder receives a total of
$ per unit for that quarter (the
third target distribution); and
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thereafter
, 50% to all unitholders, pro rata, and 50% to
our general partner.
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Percentage
Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of
available cash from operating surplus between the unitholders
and our general partner based on the specified target
distribution levels. The amounts set forth under Marginal
Percentage Interest in Distributions are the percentage
interests of our general partner and the unitholders in any
available cash from operating surplus we distribute up to and
including the corresponding amount in the column Total
Quarterly Distribution Per Unit Target Amount. The
percentage interests shown for our unitholders and our general
partner for the minimum quarterly distribution are also
applicable to quarterly distribution amounts that are less than
the minimum quarterly distribution. The percentage interests set
forth below for our general partner include its 2.0% general
partner interest and assume that there are no arrearages on
common units, our general partner has contributed any additional
capital necessary to maintain its 2.0% general partner interest
and our general partner has not transferred its incentive
distribution rights.
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Marginal Percentage Interest
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Total Quarterly Distribution
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in Distributions
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Per Unit Target Amount
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Unitholders
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General Partner
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Minimum Quarterly Distribution
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$
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98
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%
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2
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%
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First Target Distribution
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up to $
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98
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%
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2
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%
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Second Target Distribution
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above $
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up to $
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85
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%
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15
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%
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Third Target Distribution
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above $
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up to $
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75
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%
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25
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%
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Thereafter
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above $
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50
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%
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50
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%
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General
Partners Right to Reset Incentive Distribution
Levels
Our general partner, as the holder of our incentive distribution
rights, has the right under our partnership agreement to elect
to relinquish the right to receive incentive distribution
payments based on the initial cash target distribution levels
and to reset, at higher levels, the minimum quarterly
distribution amount and cash target distribution levels upon
which the incentive distribution payments to our general partner
would be set. Our general partners right to reset the
minimum quarterly distribution amount and the target
distribution levels upon which the incentive distributions
payable to our general partner are based may be exercised,
without approval of our unitholders or the conflicts committee
of our general partner, at any time when there are no
subordinated units outstanding and we have made cash
distributions to the holders of the incentive distribution
rights at the highest level of incentive distribution for each
of the prior four consecutive fiscal quarters. The reset minimum
quarterly distribution amount and target distribution levels
will be higher than the minimum quarterly distribution amount
and the target distribution levels prior to the reset such that
our general partner will not receive any incentive distributions
under the reset target distribution levels until cash
distributions per unit following this event increase as
described below. We anticipate that our general partner would
exercise this reset right in order to facilitate acquisitions or
internal growth projects that would otherwise not be
sufficiently accretive to cash distributions per common unit,
taking into account the existing levels of incentive
distribution payments being made to our general partner.
In connection with the resetting of the minimum quarterly
distribution amount and the target distribution levels and the
corresponding relinquishment by our general partner of incentive
distribution payments based on the target cash distributions
prior to the reset, our general partner will be entitled to
receive a number of newly issued common units and general
partner units based on a predetermined formula described below
that takes into account the cash parity value of the
average cash distributions related to the incentive distribution
rights received by our general partner for the two quarters
prior to the reset event as compared to the average cash
distributions per common unit during that two-quarter period.
Our general partner will be issued the number of general partner
units necessary to maintain our general partners interest
in us immediately prior to the reset election.
The number of common units that our general partner would be
entitled to receive from us in connection with a resetting of
the minimum quarterly distribution amount and the target
distribution levels then in effect would be equal to the
quotient determined by dividing (x) the average amount of
cash distributions received by our general partner in respect of
its incentive distribution rights during the two consecutive
fiscal quarters ended immediately prior to the date of such
reset election by (y) the average of the amount of cash
distributed per common unit during each of that two-quarter
period.
Following a reset election by our general partner, the minimum
quarterly distribution amount will be reset to an amount equal
to the average cash distribution amount per unit for the two
fiscal quarters immediately preceding the reset election (which
amount we refer to as the reset minimum quarterly
distribution) and the target distribution levels will be
reset to be correspondingly higher such that we would distribute
all of our available cash from operating surplus for each
quarter thereafter as follows:
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first
, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until each unitholder receives an amount
equal to 115.0% of the reset minimum quarterly distribution for
that quarter;
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62
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second
, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until each unitholder receives an amount
per unit equal to 125.0% of the reset minimum quarterly
distribution for the quarter;
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third
, 75.0% to all unitholders, pro rata, and 25.0% to
our general partner, until each unitholder receives an amount
per unit equal to 150.0% of the reset minimum quarterly
distribution for the quarter; and
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thereafter
, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
|
The following table illustrates the percentage allocation of
available cash from operating surplus between the unitholders
and our general partner at various cash distribution levels
(i) pursuant to the cash distribution provisions of our
partnership agreement in effect at the closing of this offering,
as well as (ii) following a hypothetical reset of the
minimum quarterly distribution and target distribution levels
based on the assumption that the average quarterly cash
distribution amount per common unit during the two fiscal
quarters immediately preceding the reset election was
$ .
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Marginal Percentage
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Quarterly Distribution
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Interest in Distributions
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Quarterly Distribution Per Unit
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Per Unit Prior to Reset
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Unitholders
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General Partner
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Following Hypothetical Reset
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Minimum Quarterly Distribution
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$
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98%
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2
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%
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|
$
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First Target Distribution
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up to $
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98%
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2
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%
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|
up to $
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(1
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)
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Second Target Distribution
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above $
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up to $
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85%
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15
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%
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above $
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(1)
up
to $
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(2
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)
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Third Target Distribution
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above $
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up to $
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75%
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25
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%
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above $
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(2)
up
to $
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(3
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)
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Thereafter
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above $
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50%
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50
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%
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above $
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(3
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)
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(1)
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This amount is 115.0% of the
hypothetical reset minimum quarterly distribution.
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(2)
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This amount is 125.0% of the
hypothetical reset minimum quarterly distribution.
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(3)
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This amount is 150.0% of the
hypothetical reset minimum quarterly distribution.
|
The following table illustrates the total amount of available
cash from operating surplus that would be distributed to the
unitholders and our general partner, including in respect of
incentive distribution rights, or IDRs, based on an average of
the amounts distributed each quarter for the two quarters
immediately prior to the reset. The table assumes that
immediately prior to the reset there would
be
common units outstanding, our general partner has maintained its
2.0% general partner interest, and the average distribution to
each common unit would be $ for
the two quarters prior to the reset.
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Cash
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Cash Distributions to General Partner Prior to Reset
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Distributions to
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2.0%
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Quarterly
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|
Common
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|
General
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Incentive
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Distribution Per
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Unitholders
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Class C
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Partner
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Distribution
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Total
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Unit Prior to Reset
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Prior to Reset
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Units
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Interest
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Rights
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Total
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|
Distributions
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|
Minimum Quarterly Distribution
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|
|
$
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|
|
$
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|
|
$
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|
|
$
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|
|
$
|
|
|
|
$
|
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|
|
$
|
|
|
First Target Distribution
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|
|
up to $
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Target Distribution
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|
above $
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|
up to $
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Target Distribution
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|
above $
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|
up to $
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thereafter
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|
|
above $
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|
|
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|
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|
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|
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|
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|
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|
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|
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|
|
|
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|
|
|
|
|
|
|
|
|
|
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|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
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|
|
$
|
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|
|
|
|
|
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|
|
|
|
|
|
|
|
|
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|
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|
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|
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|
The following table illustrates the total amount of available
cash from operating surplus that would be distributed to the
unitholders and our general partner, including in respect of
IDRs, with respect to the quarter in which the reset occurs. The
table reflects that as a result of the reset there would
be
common units outstanding, our general partners 2.0%
interest has been maintained, and the average distribution to
each common unit would be $ . The
number of common units to be issued to our general partner upon
the reset was calculated by dividing (i) the average of the
amounts received by our general partner in respect of its IDRs
for the two quarters prior to the reset as shown in the table
above, or $ ; by (ii) the
average
63
available cash distributed on each common unit for the two
quarters prior to the reset as shown in the table above, or
$ .
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Cash
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|
Cash Distributions to General Partner After Reset
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Distributions to
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|
2.0%
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|
|
|
|
|
|
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|
|
|
|
|
|
Common
|
|
|
|
|
|
General
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|
|
Incentive
|
|
|
|
|
|
|
|
|
|
Quarterly Distribution
|
|
Unitholders
|
|
|
Class C
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|
Partner
|
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|
Distribution
|
|
|
|
|
|
Total
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|
|
Per Unit After Reset
|
|
After Reset
|
|
|
Units
|
|
|
Interest
|
|
|
Rights
|
|
|
Total
|
|
|
Distributions
|
|
|
Minimum Quarterly Distribution
|
|
|
|
|
|
$
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
First Target Distribution
|
|
|
|
|
|
up to $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Target Distribution
|
|
above $
|
|
|
|
up to $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Target Distribution
|
|
above $
|
|
|
|
up to $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Thereafter
|
|
|
|
|
|
above $
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our general partner will be entitled to cause the minimum
quarterly distribution amount and the target distribution levels
to be reset on more than one occasion, provided that it may not
make a reset election except at a time when it has received
incentive distributions for the prior four consecutive fiscal
quarters based on the highest level of incentive distributions
that it is entitled to receive under our partnership agreement.
Distributions
from Capital Surplus
How
Distributions from Capital Surplus Will Be Made
We will make distributions of available cash from capital
surplus, if any, in the following manner:
|
|
|
|
|
first
, 98% to all unitholders, pro rata, and 2.0% to our
general partner, until we distribute for each common unit that
was issued in this offering, an amount of available cash from
capital surplus equal to the initial public offering price in
this offering;
|
|
|
|
second
, 98% to all unitholders, pro rata, and 2.0% to our
general partner, until we distribute for each common unit, an
amount of available cash from capital surplus equal to any
unpaid arrearages in payment of the minimum quarterly
distribution on the outstanding common units; and
|
|
|
|
thereafter
, we will make all distributions of available
cash from capital surplus as if they were from operating surplus.
|
The preceding discussion is based on the assumptions that our
general partner maintains its 2.0% general partner interest and
that we do not issue additional classes of equity securities.
Effect
of a Distribution from Capital Surplus
Our partnership agreement treats a distribution of capital
surplus as the repayment of the initial unit price from this
initial public offering, which is a return of capital. The
initial public offering price less any distributions of capital
surplus per unit is referred to as the unrecovered initial
unit price. Each time a distribution of capital surplus is
made, the minimum quarterly distribution and the target
distribution levels will be reduced in the same proportion as
the corresponding reduction in the unrecovered initial unit
price. Because distributions of capital surplus will reduce the
minimum quarterly distribution, after any of these distributions
are made, it may be easier for our general partner to receive
incentive distributions and for the subordinated units to
convert into common units. However, any distribution of capital
surplus before the unrecovered initial unit price is reduced to
zero cannot be applied to the payment of the minimum quarterly
distribution or any arrearages.
Once we distribute capital surplus on a unit issued in this
offering in an amount equal to the initial unit price, we will
reduce the minimum quarterly distribution and the target
distribution levels to zero. We will then make all future
distributions from operating surplus, with 50% being paid to the
unitholders, pro rata, and 50% to our general partner. The
percentage interests shown for our general partner include its
2.0% general partner interest and assume that our general
partner has not transferred the incentive distribution rights.
64
Adjustment
to the Minimum Quarterly Distribution and Target Distribution
Levels
In addition to adjusting the minimum quarterly distribution and
target distribution levels to reflect a distribution of capital
surplus, if we combine our units into fewer units or subdivide
our units into a greater number of units, we will
proportionately adjust:
|
|
|
|
|
the minimum quarterly distribution;
|
|
|
|
the number of common units into which a subordinated unit is
convertible;
|
|
|
|
target distribution levels; and
|
|
|
|
the unrecovered initial unit price.
|
For example, if a
two-for-one
split of the common units should occur, the minimum quarterly
distribution, the target distribution levels and the unrecovered
initial unit price would each be reduced to 50% of its initial
level, and each subordinated unit would be convertible into two
common units. We will not make any adjustment by reason of the
issuance of additional units for cash or property.
In addition, if legislation is enacted or if existing law is
modified or interpreted by a governmental authority, so that we
become taxable as a corporation or otherwise subject to taxation
as an entity for federal, state or local income tax purposes,
our partnership agreement specifies that the minimum quarterly
distribution and the target distribution levels for each quarter
may be reduced by multiplying each distribution level by a
fraction, the numerator of which is available cash for that
quarter and the denominator of which is the sum of available
cash for that quarter plus our general partners estimate
of our aggregate liability for the quarter for such income taxes
payable by reason of such legislation or interpretation. To the
extent that the actual tax liability differs from the estimated
tax liability for any quarter, the difference will be accounted
for in subsequent quarters.
Distributions
of Cash Upon Liquidation
General
If we dissolve in accordance with our partnership agreement, we
will sell or otherwise dispose of our assets in a process called
liquidation. We will first apply the proceeds of liquidation to
the payment of our creditors. We will distribute any remaining
proceeds to the unitholders and our general partner, in
accordance with their capital account balances, as adjusted to
reflect any gain or loss upon the sale or other disposition of
our assets in liquidation.
The allocations of gain and loss upon liquidation are intended,
to the extent possible, to entitle the holders of outstanding
common units to a preference over the holders of outstanding
subordinated units upon our liquidation, to the extent required
to permit common unitholders to receive their unrecovered
initial unit price plus the minimum quarterly distribution for
the quarter during which liquidation occurs plus any unpaid
arrearages in payment of the minimum quarterly distribution on
the common units. However, there may not be sufficient gain upon
our liquidation to enable the holders of common units to fully
recover all of these amounts, even though there may be cash
available for distribution to the holders of subordinated units.
Any further net gain recognized upon liquidation will be
allocated in a manner that takes into account the incentive
distribution rights of our general partner.
Manner
of Adjustments for Gain
The manner of the adjustment for gain is set forth in our
partnership agreement. If our liquidation occurs before the end
of the subordination period, we will allocate any gain to our
partners in the following manner:
|
|
|
|
|
first
, to our general partner and the holders of units
who have negative balances in their capital accounts to the
extent of and in proportion to those negative balances;
|
65
|
|
|
|
|
second
, 98% to the common unitholders, pro rata, and 2.0%
to our general partner, until the capital account for each
common unit is equal to the sum of:
|
(1) the unrecovered initial unit price;
(2) the amount of the minimum quarterly distribution for
the quarter during which our liquidation occurs; and
(3) any unpaid arrearages in payment of the minimum
quarterly distribution;
|
|
|
|
|
third
, 98% to the subordinated unitholders, pro rata, and
2.0% to our general partner, until the capital account for each
subordinated unit is equal to the sum of:
|
(1) the unrecovered initial unit price; and
(2) the amount of the minimum quarterly distribution for
the quarter during which our liquidation occurs;
|
|
|
|
|
fourth
, 98% to all unitholders, pro rata, and 2.0% to our
general partner, until we allocate under this paragraph an
amount per unit equal to:
|
(1) the sum of the excess of the first target distribution
per unit over the minimum quarterly distribution per unit for
each quarter of our existence; less
(2) the cumulative amount per unit of any distributions of
available cash from operating surplus in excess of the minimum
quarterly distribution per unit that we distributed 98% to the
unitholders, pro rata, and 2.0% to our general partner, for each
quarter of our existence;
|
|
|
|
|
fifth
, 85% to all unitholders, pro rata, and 15% to our
general partner, until we allocate under this paragraph an
amount per unit equal to:
|
(1) the sum of the excess of the second target distribution
per unit over the first target distribution per unit for each
quarter of our existence; less
(2) the cumulative amount per unit of any distributions of
available cash from operating surplus in excess of the first
target distribution per unit that we distributed 96% to the
unitholders, pro rata, and 4% to our general partner for each
quarter of our existence;
|
|
|
|
|
sixth
, 75% to all unitholders, pro rata, and 25% to our
general partner, until we allocate under this paragraph an
amount per unit equal to:
|
(1) the sum of the excess of the third target distribution
per unit over the second target distribution per unit for each
quarter of our existence; less
(2) the cumulative amount per unit of any distributions of
available cash from operating surplus in excess of the second
target distribution per unit that we distributed 94% to the
unitholders, pro rata, and 6% to our general partner for each
quarter of our existence;
|
|
|
|
|
thereafter
, 50% to all unitholders, pro rata, and 50% to
our general partner.
|
The percentages set forth above are based on the assumption that
our general partner has not transferred its incentive
distribution rights and that we do not issue additional classes
of equity securities.
If the liquidation occurs after the end of the subordination
period, the distinction between common units and subordinated
units will disappear, so that clause (3) of the second
bullet point above and all of the third bullet point above will
no longer be applicable.
66
Manner
of Adjustments for Losses
If our liquidation occurs before the end of the subordination
period, we will generally allocate any loss to our general
partner and unitholders in the following manner:
|
|
|
|
|
first
, 98% to holders of subordinated units in proportion
to the positive balances in their capital accounts and 2.0% to
our general partner, until the capital accounts of the
subordinated unitholders have been reduced to zero;
|
|
|
|
second
, 98% to the holders of common units in proportion
to the positive balances in their capital accounts and 2.0% to
our general partner, until the capital accounts of the common
unitholders have been reduced to zero; and
|
|
|
|
thereafter
, 100% to our general partner.
|
If the liquidation occurs after the end of the subordination
period, the distinction between common units and subordinated
units will disappear, so that all of the first bullet point
above will no longer be applicable.
Adjustments
to Capital Accounts
We will make adjustments to capital accounts upon the issuance
of additional units. In doing so, we will allocate any
unrealized and, for tax purposes, unrecognized gain or loss
resulting from the adjustments to the unitholders and our
general partner in the same manner as we allocate gain or loss
upon liquidation. In the event that we make positive adjustments
to the capital accounts upon the issuance of additional units,
we will allocate any later negative adjustments to the capital
accounts resulting from the issuance of additional units or upon
our liquidation in a manner which results, to the extent
possible, in our general partners capital account balances
equaling the amount which they would have been if no earlier
positive adjustments to the capital accounts had been made.
67
SELECTED
HISTORICAL AND PRO FORMA CONSOLIDATED
FINANCIAL AND OPERATING DATA
The following table presents our selected historical
consolidated financial and operating data, as well as that of
our accounting predecessor and wholly owned subsidiary, Oxford
Mining Company, as of the dates and for the periods indicated.
The following table also presents our selected pro forma
consolidated financial and operating data as of the dates and
for the periods indicated.
The selected financial data for the year ended December 31,
2005 are derived from the audited historical consolidated
balance sheet of Oxford Mining Company that is not included in
this prospectus. The selected historical consolidated financial
data presented as of and for the year ended December 31,
2006 are derived from the audited historical consolidated
financial statements of Oxford Mining Company that are not
included in this prospectus. The selected historical
consolidated financial data presented for the period from
January 1, 2007 to August 23, 2007 are derived from
the audited historical consolidated financial statements of
Oxford Mining Company that are included elsewhere in this
prospectus. The selected historical consolidated financial data
presented as of December 31, 2007 for the period from
August 24, 2007 to December 31, 2007 and as of and for
the years ended December 31, 2008 and 2009 are derived from
our audited historical consolidated financial statements that
are included elsewhere in this prospectus.
The selected pro forma consolidated financial data presented as
of and for the year ended December 31, 2009 are derived
from our unaudited pro forma consolidated financial statements
included elsewhere in this prospectus. Our unaudited pro forma
consolidated statement of operations and consolidated balance
sheet give pro forma effect to this offering and the
transactions related to this offering described in
Summary The Transactions and Use
of Proceeds. The unaudited pro forma consolidated
statement of operations also gives pro forma effect to the
Phoenix Coal acquisition. The unaudited pro forma consolidated
balance sheet assumes this offering and the transactions related
to this offering occurred as of December 31, 2009. The
unaudited pro forma consolidated statement of operations for the
year ended December 31, 2009 assumes the Phoenix Coal
acquisition, this offering and the transactions related to this
offering occurred as of January 1, 2009. We have not given
pro forma effect to incremental selling, general and
administrative expenses of approximately $3.0 million that
we expect to incur as a result of being a publicly traded
partnership.
For a detailed discussion of the following table, please read
Managements Discussion and Analysis of Financial
Condition and Results of Operations. The following table
should also be read in conjunction with
Summary The Transactions, Use of
Proceeds, Business Our History,
the historical consolidated financial statements of Oxford
Mining Company and our unaudited pro forma consolidated
financial statements and audited consolidated financial
statements included elsewhere in this prospectus. Among other
things, those historical and pro forma consolidated financial
statements include more detailed information regarding the basis
of presentation for the information in the following table.
The following table presents a non-GAAP financial measure,
Adjusted EBITDA, which we use in our business as it is an
important supplemental measure of our performance. Adjusted
EBITDA represents net income (loss) attributable to our
unitholders before interest, taxes, depreciation, depletion and
amortization, gain from purchase of a business, amortization of
below-market coal sales contracts and non-cash equity
compensation expense. This measure is not calculated or
presented in accordance with GAAP. We explain this
68
measure below and reconcile it to net income (loss) attributable
to our unitholders, its most directly comparable financial
measure calculated and presented in accordance with GAAP.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oxford Mining Company
|
|
|
|
|
|
|
|
|
|
|
|
|
(Predecessor)
|
|
|
|
Oxford Resource Partners, LP
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
Oxford Resource
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1,
|
|
|
|
August 24,
|
|
|
|
|
|
|
|
|
|
|
|
Partners, LP
|
|
|
|
|
Year Ended
|
|
|
|
Year Ended
|
|
|
|
2007 to
|
|
|
|
2007 to
|
|
|
|
Year Ended
|
|
|
|
Year Ended
|
|
|
|
Year Ended
|
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
August 23,
|
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
December
|
|
|
|
December 31,
|
|
|
|
|
2005
|
|
|
|
2006
|
|
|
|
2007
|
|
|
|
2007
|
|
|
|
2008
|
|
|
|
31, 2009
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(unaudited)
|
|
|
|
|
(in thousands, except per ton amounts)
|
|
Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
|
|
|
|
|
|
$
|
141,440
|
|
|
|
$
|
96,799
|
|
|
|
$
|
61,324
|
|
|
|
$
|
193,699
|
|
|
|
$
|
254,171
|
|
|
|
$
|
312,490
|
|
Transportation revenue
|
|
|
|
|
|
|
|
|
27,771
|
|
|
|
|
18,083
|
|
|
|
|
10,204
|
|
|
|
|
31,839
|
|
|
|
|
32,490
|
|
|
|
|
37,221
|
|
Royalty and non-coal revenue
|
|
|
|
|
|
|
|
|
6,643
|
|
|
|
|
3,267
|
|
|
|
|
1,407
|
|
|
|
|
4,951
|
|
|
|
|
7,183
|
|
|
|
|
7,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
|
|
|
|
|
|
175,854
|
|
|
|
|
118,149
|
|
|
|
|
72,935
|
|
|
|
|
230,489
|
|
|
|
|
293,844
|
|
|
|
|
356,894
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales (excluding DD&A, shown separately)
|
|
|
|
|
|
|
|
|
106,657
|
|
|
|
|
70,415
|
|
|
|
|
40,721
|
|
|
|
|
151,421
|
|
|
|
|
170,698
|
|
|
|
|
213,446
|
|
Cost of purchased coal
|
|
|
|
|
|
|
|
|
22,159
|
|
|
|
|
17,494
|
|
|
|
|
9,468
|
|
|
|
|
12,925
|
|
|
|
|
19,487
|
|
|
|
|
29,792
|
|
Cost of transportation
|
|
|
|
|
|
|
|
|
27,771
|
|
|
|
|
18,083
|
|
|
|
|
10,204
|
|
|
|
|
31,839
|
|
|
|
|
32,490
|
|
|
|
|
37,221
|
|
Depreciation, depletion, and amortization
|
|
|
|
|
|
|
|
|
12,396
|
|
|
|
|
9,025
|
|
|
|
|
4,926
|
|
|
|
|
16,660
|
|
|
|
|
25,902
|
|
|
|
|
31,424
|
|
Selling, general and administrative expenses
|
|
|
|
|
|
|
|
|
2,097
|
|
|
|
|
3,643
|
|
|
|
|
2,114
|
|
|
|
|
9,577
|
|
|
|
|
13,242
|
|
|
|
|
25,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
|
|
|
|
|
|
171,080
|
|
|
|
|
118,660
|
|
|
|
|
67,433
|
|
|
|
|
222,422
|
|
|
|
|
261,819
|
|
|
|
|
337.618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
|
|
|
|
|
|
4,774
|
|
|
|
|
(511
|
)
|
|
|
|
5,502
|
|
|
|
|
8,067
|
|
|
|
|
32,025
|
|
|
|
|
19,276
|
|
Interest income
|
|
|
|
|
|
|
|
|
30
|
|
|
|
|
26
|
|
|
|
|
55
|
|
|
|
|
62
|
|
|
|
|
35
|
|
|
|
|
39
|
|
Interest expense
|
|
|
|
|
|
|
|
|
(3,672
|
)
|
|
|
|
(2,386
|
)
|
|
|
|
(3,498
|
)
|
|
|
|
(7,720
|
)
|
|
|
|
(6,484
|
)
|
|
|
|
(6,341
|
)
|
Gain from purchase of
business
(1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,823
|
|
|
|
|
3,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
|
|
|
|
|
|
1,132
|
|
|
|
|
(2,871
|
)
|
|
|
|
2,059
|
|
|
|
|
409
|
|
|
|
|
29,399
|
|
|
|
|
16,797
|
|
Less: Net income attributable to noncontrolling interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(682
|
)
|
|
|
|
(537
|
)
|
|
|
|
(2,891
|
)
|
|
|
|
(5,895
|
)
|
|
|
|
(5,895
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Oxford Resource Partners, LP
unitholders
|
|
|
|
|
|
|
|
$
|
1,132
|
|
|
|
$
|
(3,553
|
)
|
|
|
$
|
1,522
|
|
|
|
$
|
(2,482
|
)
|
|
|
$
|
23,504
|
|
|
|
$
|
10,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flows Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
|
|
|
|
|
|
$
|
16,236
|
|
|
|
$
|
17,634
|
|
|
|
$
|
(8,478
|
)
|
|
|
$
|
33,951
|
|
|
|
$
|
35,540
|
|
|
|
|
|
|
Investing activities
|
|
|
|
|
|
|
|
|
(13,547
|
)
|
|
|
|
(16,619
|
)
|
|
|
|
(103,336
|
)
|
|
|
|
(23,901
|
)
|
|
|
|
(51,115
|
)
|
|
|
|
|
|
Financing activities
|
|
|
|
|
|
|
|
|
(2,548
|
)
|
|
|
|
(234
|
)
|
|
|
|
111,274
|
|
|
|
|
4,494
|
|
|
|
|
3,762
|
|
|
|
|
|
|
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDA
(2)
|
|
|
|
|
|
|
|
$
|
17,170
|
|
|
|
$
|
7,832
|
|
|
|
$
|
9,145
|
|
|
|
$
|
20,349
|
|
|
|
$
|
50,799
|
|
|
|
$
|
39,016
|
|
Maintenance capital
expenditures
(3)
|
|
|
|
|
|
|
|
|
11,695
|
|
|
|
|
13,020
|
|
|
|
|
4,841
|
|
|
|
|
21,529
|
|
|
|
|
27,461
|
|
|
|
|
27,461
|
|
Distributions
|
|
|
|
|
|
|
|
|
n/a
|
|
|
|
|
n/a
|
|
|
|
|
|
|
|
|
|
12,503
|
|
|
|
|
13,407
|
|
|
|
|
n/a
|
|
Balance Sheet Data (at period
end):
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
$
|
252
|
|
|
|
$
|
392
|
|
|
|
$
|
1,175
|
|
|
|
$
|
635
|
|
|
|
$
|
15,179
|
|
|
|
$
|
3,366
|
|
|
|
$
|
30,769
|
|
Trade accounts receivable
|
|
|
|
21,979
|
|
|
|
|
16,826
|
|
|
|
|
18,396
|
|
|
|
|
17,547
|
|
|
|
|
21,528
|
|
|
|
|
24,403
|
|
|
|
|
2,000
|
|
Inventory
|
|
|
|
3,884
|
|
|
|
|
3,977
|
|
|
|
|
4,824
|
|
|
|
|
4,655
|
|
|
|
|
5,134
|
|
|
|
|
8,801
|
|
|
|
|
8,801
|
|
PPE, net
|
|
|
|
47,428
|
|
|
|
|
48,001
|
|
|
|
|
54,510
|
|
|
|
|
106,408
|
|
|
|
|
112,446
|
|
|
|
|
149,461
|
|
|
|
|
149,461
|
|
Total assets
|
|
|
|
85,099
|
|
|
|
|
80,533
|
|
|
|
|
90,893
|
|
|
|
|
146,774
|
|
|
|
|
171,297
|
|
|
|
|
203,363
|
|
|
|
|
209,726
|
|
Total debt (current and long-term)
|
|
|
|
46,091
|
|
|
|
|
43,697
|
|
|
|
|
43,165
|
|
|
|
|
75,654
|
|
|
|
|
83,977
|
|
|
|
|
95,711
|
|
|
|
|
98,711
|
|
Operating Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tons of coal produced
|
|
|
|
|
|
|
|
|
3,913
|
|
|
|
|
2,693
|
|
|
|
|
1,634
|
|
|
|
|
5,089
|
|
|
|
|
5,846
|
|
|
|
|
7,221
|
|
Tons of coal purchased
|
|
|
|
|
|
|
|
|
962
|
|
|
|
|
641
|
|
|
|
|
305
|
|
|
|
|
434
|
|
|
|
|
530
|
|
|
|
|
885
|
|
Tons of coal sold
|
|
|
|
|
|
|
|
|
4,872
|
|
|
|
|
3,333
|
|
|
|
|
1,938
|
|
|
|
|
5,528
|
|
|
|
|
6,311
|
|
|
|
|
8,051
|
|
Average sales price per
ton
(5)
|
|
|
|
|
|
|
|
$
|
29.03
|
|
|
|
$
|
29.04
|
|
|
|
$
|
31.64
|
|
|
|
$
|
35.04
|
|
|
|
$
|
40.27
|
|
|
|
$
|
38.81
|
|
Cost of coal sales per ton
produced
(6)
|
|
|
|
|
|
|
|
$
|
27.26
|
|
|
|
$
|
26.15
|
|
|
|
$
|
24.92
|
|
|
|
$
|
29.75
|
|
|
|
$
|
29.20
|
|
|
|
$
|
29.56
|
|
Cost of purchased coal per
ton
(7)
|
|
|
|
|
|
|
|
$
|
23.03
|
|
|
|
$
|
27.29
|
|
|
|
$
|
31.08
|
|
|
|
$
|
29.81
|
|
|
|
$
|
36.79
|
|
|
|
$
|
33.66
|
|
|
|
|
(1)
|
|
On September 30, 2009, we
acquired all of the active surfacing mining operations of
Phoenix Coal. The purchase price of this acquisition was less
than the fair value of the net assets and liabilities we
acquired. We recorded this difference as a gain of
$3.8 million for the year ending December 31, 2009.
|
69
|
|
|
(2)
|
|
Adjusted EBITDA is used as a
supplemental financial measure by management and by external
users of our financial statements, such as investors and
lenders, to assess:
|
|
|
|
|
|
our financial performance without regard to financing methods,
capital structure or income taxes;
|
|
|
|
our ability to generate cash sufficient to pay interest on our
indebtedness and to make distributions to our unitholders and
our general partner;
|
|
|
|
our compliance with certain financial covenants applicable to
our credit facility; and
|
|
|
|
our ability to fund capital expenditure projects from operating
cash flow.
|
|
|
|
|
|
Adjusted EBITDA should not be considered an alternative to net
income (loss) attributable to our unitholders, income from
operations, cash flows from operating activities or any other
measure of performance presented in accordance with GAAP.
Adjusted EBITDA excludes some, but not all, items that affect
net income (loss) attributable to our unitholders, income from
operations and cash flows, and these measures may vary among
other companies. Therefore, Adjusted EBITDA as presented below
may not be comparable to similarly titled measures of other
companies.
|
The following table presents a reconciliation of Adjusted EBITDA
to net income (loss) attributable to our unitholders for each of
the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
|
|
|
|
|
|
Oxford Resource
|
|
|
|
Oxford Mining Company (Predecessor)
|
|
|
|
Oxford Resource Partners, LP
|
|
|
|
Partners, LP
|
|
|
|
|
|
|
Period from
|
|
|
|
Period from
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1,
|
|
|
|
August 24,
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
2007 to
|
|
|
|
2007 to
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
August 23,
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
December 31,
|
|
|
|
2006
|
|
|
2007
|
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
|
|
(unaudited)
|
|
Reconciliation of Adjusted EBITDA to net income (loss)
attributable to Oxford Resource Partners, LP unitholders:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Oxford Resource Partners, LP
unitholders
|
|
$
|
1,132
|
|
|
$
|
(3,553
|
)
|
|
|
$
|
1,522
|
|
|
$
|
(2,482
|
)
|
|
$
|
23,504
|
|
|
|
$
|
10,902
|
|
PLUS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
12,396
|
|
|
|
9,025
|
|
|
|
|
4,926
|
|
|
|
16,660
|
|
|
|
25,902
|
|
|
|
|
31,424
|
|
Interest expense
|
|
|
3,672
|
|
|
|
2,386
|
|
|
|
|
3,498
|
|
|
|
7,720
|
|
|
|
6,484
|
|
|
|
|
6,341
|
|
Non-cash equity compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
468
|
|
|
|
472
|
|
|
|
|
472
|
|
LESS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
30
|
|
|
|
26
|
|
|
|
|
55
|
|
|
|
62
|
|
|
|
35
|
|
|
|
|
39
|
|
Amortization of below-market coal sales contracts
|
|
|
|
|
|
|
|
|
|
|
|
771
|
|
|
|
1,955
|
|
|
|
1,705
|
|
|
|
|
6,261
|
|
Gain from purchase of business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,823
|
|
|
|
|
3,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
17,170
|
|
|
$
|
7,832
|
|
|
|
$
|
9,145
|
|
|
$
|
20,349
|
|
|
$
|
50,799
|
|
|
|
$
|
39,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3)
|
|
Maintenance capital expenditures
are cash expenditures made to maintain or replace, including
over the long term, our operating capacity, asset base or
operating income. Examples of maintenance capital expenditures
include capital expenditures associated with the replacement of
equipment and coal reserves, whether through the expansion of an
existing mine or the acquisition or development of new reserves,
to the extent such expenditures are incurred to maintain our
operating capacity, asset base or operating income.
Historically, we have not made a distinction between maintenance
capital expenditures and other capital expenditures. For
purposes of this presentation, however, we have evaluated our
historical capital expenditures to estimate which of them would
have been classified as maintenance capital expenditures in
accordance with our partnership agreement at the time they were
made. The amounts shown reflect our estimates based on that
evaluation.
|
|
(4)
|
|
The selected financial data for the
year ended December 31, 2005 are derived from the audited
historical consolidated balance sheet of our accounting
predecessor and wholly owned subsidiary, Oxford Mining Company,
that is not included in this prospectus. All other financial
data for 2005 that would be comparable to the selected financial
data for the years ended December 31, 2006, 2007, 2008 and
2009 is not available because we adopted new accounting
|
70
|
|
|
|
|
policies in 2006 after electronic
data for 2005 was purged to conserve limited electronic data
resources. The manual accounting data that we retained is
incomplete and we cannot prepare the comparable selected
historical financial data for 2005 without unreasonable time,
expense and delay. In addition, significant assumptions would be
required to reclassify the operations of certain non-core
businesses that we disposed of in 2005. These non-core
businesses were a small percentage of our 2005 revenues. Due to
the significant assumptions needed to reclassify discontinued
operations, the similarity in business operations and the age of
this information, we believe that the inclusion of this
information would not be materially additive to an
investors understanding of our current business.
|
|
(5)
|
|
Represents our coal sales divided
by total tons of coal sold.
|
|
(6)
|
|
Represents our cost of coal sales
(excluding DD&A) divided by the tons of coal we produce.
|
|
(7)
|
|
Represents the cost of purchased
coal divided by the tons of coal purchased.
|
71
MANAGEMENTS
DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion of the financial
condition and results of operations of Oxford Resource Partners,
LP and its subsidiaries in conjunction with the historical
consolidated financial statements of Oxford Resource Partners,
LP, the historical consolidated financial statements of our
accounting predecessor and wholly owned subsidiary, Oxford
Mining Company, and the unaudited pro forma consolidated
financial statements of Oxford Resource Partners, LP included
elsewhere in this prospectus. Among other things, those
historical and pro forma consolidated financial statements and
the notes related to those statements include more detailed
information regarding the basis of presentation for the
following information.
Overview
We are a low cost producer of high value steam coal, and we are
the largest producer of surface mined coal in Ohio. Our reserves
and operations are strategically located in Northern Appalachia
and the Illinois Basin to serve our primary market area of
Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West
Virginia. We market our coal primarily to large utilities with
coal-fired, base-load scrubbed power plants under long-term coal
sales contracts. We currently have long-term coal sales
contracts in place for 2010, 2011, 2012 and 2013 that represent
97.2%, 93.0%, 71.4% and 39.7%, respectively, of our 2010
estimated coal sales of 8.5 million tons.
We currently have 19 active surface mines that are managed as
eight mining complexes. During the fourth quarter of 2009, our
largest mine represented 12.5% of our coal production. This
diversity reduces the risk that operational issues at any one
mine will have a material impact on our business or our results
of operations. Consistent coal quality across many of our mines
and the mobility of our equipment fleet allows us to reliably
serve our customers from multiple mining complexes while
optimizing our mining plan. Our operations also include two
river terminals, strategically located in eastern Ohio and
western Kentucky, that further enhance our ability to supply
coal to our customers with river access from multiple mines.
We produced 5.8 million tons of coal during 2009, including
0.4 million tons produced from the reserves we acquired in
western Kentucky from Phoenix Coal on September 30, 2009.
As a result of this acquisition, our coal production during the
fourth quarter of 2009 was 1.8 million tons, or
7.2 million tons on an annualized basis. During 2009, we
sold 6.3 million tons of coal, including 0.5 million
tons of purchased coal. We purchase coal in the open market and
under contracts to satisfy a portion of our sales commitments.
As of December 31, 2009, we controlled 91.6 million
tons of proven and probable coal reserves, of which
68.6 million tons were associated with our surface mining
operations and the remaining 23.0 million tons consisted of
underground coal reserves that we have subleased to a third
party in exchange for an overriding royalty. Historically, we
have been successful at replacing the reserves depleted by our
annual production and growing our reserve base by acquiring
reserves with low operational, geologic and regulatory risks and
that were located near our mining operations or that otherwise
had the potential to serve our primary market area. Over the
last five years, we have produced 23.6 million tons of coal
and acquired 52.9 million tons of proven and probable coal
reserves, including 24.6 million tons of coal reserves that
we acquired in connection with the Phoenix Coal acquisition.
For the year ended December 31, 2009, we generated revenues
of approximately $293.8 million, net income attributable to
our unitholders of approximately $23.5 million and Adjusted
EBITDA of approximately $50.8 million. Please read
Selected Historical and Pro Forma Consolidated Financial
and Operating Data for our definition of Adjusted EBITDA
and a reconciliation of Adjusted EBITDA to net income (loss)
attributable to our unitholders.
Evaluating
Our Results of Operations
We evaluate our results of operations based on several key
measures:
|
|
|
|
|
our coal production, sales volume and average sales prices,
which drive our coal sales revenue;
|
72
|
|
|
|
|
our cost of coal sales;
|
|
|
|
our cost of purchased coal; and
|
|
|
|
our Adjusted EBITDA, a non-GAAP financial measure.
|
Coal
Production, Sales Volume and Sales Prices
We evaluate our operations based on the volume of coal we
produce, the volume of coal we sell and the prices we receive
for our coal. Because we sell substantially all of our coal
under long-term coal sales contracts, our coal production, sales
volume and sales prices are largely dependent upon the terms of
those contracts. The volume of coal we sell is also a function
of the productive capacity of our mining complexes, the amount
of coal we purchase and changes in inventory levels. Please read
Cost of Purchased Coal for more
information regarding our purchased coal.
Our long-term coal sales contracts typically provide for a fixed
price, or a schedule of fixed prices, over the contract term.
Two of our long-term coal sales contracts have price re-openers
that provide for a market-based adjustment to the initial price
every three years. These contracts will terminate if we cannot
agree upon a market-based price with the customer. In addition,
most of our long-term coal sales contracts have full or partial
cost pass through or inflation adjustment provisions. Cost pass
through provisions typically provide for increases in our sales
prices in rising operating cost environments and for decreases
in declining operating cost environments. Inflation adjustment
provisions typically provide some protection in rising operating
cost environments.
We evaluate the price we receive for our coal on an average
sales price per ton basis. Our average sales price per ton
represents our coal sales revenue divided by total tons of coal
sold. The following table provides operational data with respect
to our coal production, coal sales volume and average sales
prices per ton for the periods indicated:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP
|
|
Year Ended
|
|
Year Ended
|
|
|
Combined
2007
(1)
|
|
December 31, 2008
|
|
December 31, 2009
|
|
|
(tons in thousands)
|
|
Tons of coal produced
|
|
|
4,327
|
|
|
|
5,089
|
|
|
|
5,846
|
|
Tons of coal purchased
|
|
|
946
|
|
|
|
434
|
|
|
|
530
|
|
Tons of coal sold
|
|
|
5,271
|
|
|
|
5,528
|
|
|
|
6,311
|
|
Tons sold under long-term
contracts
(2)
|
|
|
98.3
|
%
|
|
|
93.8
|
%
|
|
|
97.8
|
%
|
Average sales price per ton
|
|
$
|
30.00
|
|
|
$
|
35.04
|
|
|
$
|
40.27
|
|
|
|
|
(1)
|
|
Please read Results of Operations
Factors Affecting the Comparability of Our Results of
Operations for more information about the non-GAAP
combined 2007 presentation.
|
|
(2)
|
|
Represents the percentage of the tons of coal we sold that were
delivered under long-term coal sales contracts.
|
Cost
of Coal Sales
We evaluate our cost of coal sales, which excludes the cost of
purchased coal, on a cost per ton basis. Our cost of coal sales
per ton produced represents our production costs divided by the
tons of coal we produce. Our production costs include labor,
fuel, oil, explosives, operating lease expenses, repairs and
maintenance and all other costs that are directly related to our
mining operations other than the cost of purchased coal, cost of
transportation and depreciation, depletion and amortization, or
DD&A. Our production costs also exclude any indirect costs,
such as SG&A expenses. Our production costs do not take
into account the effects of any of the inflation adjustment or
cost pass through provisions in our long-term coal sales
contracts, as those provisions result in an adjustment to our
coal sales price.
73
The following table provides summary information for the dates
indicated relating to our cost of coal sales per ton produced:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP
|
|
Year Ended
|
|
Year Ended
|
|
|
Combined
2007
(1)
|
|
December 31, 2008
|
|
December 31, 2009
|
|
|
(tons in thousands)
|
|
Average sales price per ton
|
|
$
|
30.00
|
|
|
$
|
35.04
|
|
|
$
|
40.27
|
|
Cost of coal sales per ton
|
|
$
|
25.69
|
|
|
$
|
29.75
|
|
|
$
|
29.20
|
|
Tons of coal produced
|
|
|
4,327
|
|
|
|
5,089
|
|
|
|
5,846
|
|
|
|
|
(1)
|
|
Please read Results of Operations
Factors Affecting the Comparability of Our Results of
Operations for more information about the non-GAAP
combined 2007 presentation.
|
We use a substantial amount of diesel fuel in our mining
operations. To mitigate our exposure to fluctuations in the
price for diesel fuel we have entered into fixed price forward
contracts for future delivery of diesel fuel for a portion of
our requirements. During 2009, 54.4% of the 16.7 million
gallons of diesel fuel we purchased was delivered under fixed
price forward contracts. In addition, approximately 72.7% of the
tons we delivered under our long-term coal sales contracts
during 2009 were subject to full or partial cost pass through
provisions for diesel fuel which provide additional protection
for a portion of the increase in fuel costs.
Cost
of Purchased Coal
We purchase coal from third parties to fulfill a small portion
of our obligations under our long-term coal sales contracts and,
in certain cases, to meet customer quality specifications. In
connection with the Phoenix Coal acquisition, we assumed a
long-term coal purchase contract that had favorable pricing
terms relative to our production costs. Under this contract we
are obligated to purchase 0.6 million tons of coal in 2010
and 0.4 million tons of coal each year thereafter until the
coal reserves covered by the contract are depleted. Based on the
proven and probable coal reserves in place at December 31,
2009, we expect this contract to continue beyond five years.
We evaluate our cost of purchased coal on a per ton basis. For
the year ended December 31, 2009, we sold 0.5 million
tons of purchased coal. The following table provides summary
information for the dates indicated for our cost of purchased
coal per ton and the tons of purchased coal:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP
|
|
Year Ended
|
|
Year Ended
|
|
|
Combined
2007
(1)
|
|
December 31, 2008
|
|
December 31, 2009
|
|
|
(tons in thousands)
|
|
Average sales price per ton
|
|
$
|
30.00
|
|
|
$
|
35.04
|
|
|
$
|
40.27
|
|
Cost of purchased coal per ton
|
|
$
|
28.51
|
|
|
$
|
29.81
|
|
|
$
|
36.79
|
|
Tons of coal purchased
|
|
|
946
|
|
|
|
434
|
|
|
|
530
|
|
|
|
|
(1)
|
|
Please read Results of Operations
Factors Affecting the Comparability of Our Results of
Operations for more information about the non-GAAP
combined 2007 presentation.
|
Adjusted
EBITDA
Adjusted EBITDA represents net income (loss) attributable to our
unitholders before interest, taxes, DD&A, gain from
purchase of a business, amortization of below-market coal sales
contracts and non-cash equity compensation expense. Although
Adjusted EBITDA is not a measure of performance calculated in
accordance with GAAP, our management believes that it is useful
in evaluating our financial performance and our compliance with
our existing credit facility. Because not all companies
calculate Adjusted EBITDA identically, our calculation may not
be comparable to similarly titled measures of other companies.
Please read Summary for reconciliations
of Adjusted EBITDA to net income (loss) attributable to our
unitholders for each of the periods indicated.
74
Factors
that Impact Our Business
For the past three years over 90% of our coal sales were made
under long-term coal sales contracts and we intend to continue
to enter into long-term coal sales contracts for substantially
all of our annual coal production. We believe our long-term coal
sales contracts reduce our exposure to fluctuations in the spot
price for coal and provide us with a reliable and stable revenue
base. Our long-term coal sales contracts also allow us to
partially mitigate our exposure to rising costs to the extent
those contracts have full or partial cost pass through
provisions or inflation adjustment provisions.
For 2010, 2011, 2012 and 2013, we currently have long-term coal
sales contracts that represent 97.2%, 93.0%, 71.4% and 39.7%,
respectively, of our 2010 estimated coal sales of
8.5 million tons. During 2010, 2011, 2012 and 2013, we have
committed to deliver 8.2 million tons, 7.9 million
tons, 6.1 million tons and 3.4 million tons of coal,
respectively, under long-term coal sales contracts. These
amounts include contracts with re-openers as described below. In
addition, one of our long-term coal sales contracts that ends in
2012 can be extended by the customer for two additional
three-year terms. If this customer elects to extend this
contract, we will be committed to deliver an additional
2.0 million tons in 2013, and our 2013 coal sales
under long-term coal sales contracts, as a percentage of 2010
estimated coal sales, would increase to 63.3%.
The terms of our coal sales contracts result from competitive
bidding and negotiations with customers. As a result, the terms
of these agreements including price re-openers, coal
quality requirements, quantity parameters, permitted sources of
supply, effects of future regulatory changes, extension options,
force majeure, termination and assignment provisions
vary by customer. However, most of our long-term coal sales
contracts have full or partial cost pass through provisions or
inflation adjustment provisions. For 2010, 2011, 2012 and 2013,
61%, 72%, 80% and 100% of the coal, respectively, that we have
committed to deliver under our long-term coal sales contracts
are subject to full or partial cost pass through or inflation
adjustment provisions. Cost pass through provisions increase or
decrease our coal sales price for all or a specified percentage
of changes in the cost of fuel, explosives and, in certain
cases, labor. Inflation adjustment provisions adjust the initial
contract price over the term of the contract either by a
specific percentage or a percentage determined by reference to
various inflation related indices.
Two of our long-term coal sales contracts have price re-openers
that provide for market-based adjustments to the initial price
every three years. These contracts will terminate if we cannot
agree upon a market-based price with the customer. For 2011,
2012 and 2013, 0.4 million tons, 0.4 million tons and
0.6 million tons of coal, respectively, that we have
committed to deliver under our long-term coal sales contracts
are subject to price re-opener provisions.
Certain of our long-term coal sales contracts give the customer
the option to elect to purchase additional tons in the future at
a fixed price. Our long-term coal sales contracts that contain
these option tons typically require the customer to provide us
with six months advance notice of an election for option tons.
For 2010, 2011 and 2012, we have outstanding option tons of
0.7 million, 1.0 million and 0.7 million,
respectively. If our customers do elect to receive these option
tons, we believe we will have the operating flexibility to meet
these requirements through increased production.
We believe the other key factors that influence our business
are: (i) demand for coal, (ii) demand for electricity,
(iii) economic conditions, (iv) the quantity and
quality of coal available from competitors, (v) competition
for production of electricity from non-coal sources,
(vi) domestic air emission standards and the ability of
coal-fired power plants to meet these standards,
(vii) legislative, regulatory and judicial developments,
including delays, challenges to, and difficulties in acquiring,
maintaining or renewing necessary permits or mineral or surface
rights, (viii) market price fluctuations for sulfur dioxide
emission allowances and (ix) our ability to meet
governmental financial security requirements associated with
mining and reclamation activities.
For additional information regarding some of the risks and
uncertainties that affect our business and the industry in which
we operate, please read Risk Factors.
75
Recent
Trends and Economic Factors Affecting the Coal
Industry
Coal consumption and production in the United States have been
driven in recent periods by several market dynamics and trends.
The recent global economic downturn has negatively impacted coal
demand in the short-term, but long-term projections for coal
demand remain positive. Please read The Coal
Industry Industry Trends for the recent trends
and economic factors affecting the coal industry.
Results
of Operations
Factors
Affecting the Comparability of Our Results of
Operations
The comparability of our results of operations is impacted by
(i) the Phoenix Coal acquisition, (ii) an amendment to
a long-term coal sales contract in December 2008 and
(iii) the application of purchase accounting to our
accounting predecessors financial statements in August
2007.
We acquired all of Phoenix Coals active surface mining
operations on September 30, 2009. This acquisition
increased our coal production for the fourth quarter of 2009 by
29%, or 0.4 million tons (1.6 million tons on an
annualized basis).
In December 2008, we and one of our major customers agreed to
amend a long-term coal sales contract. As part of this
amendment, we agreed to give this customer two additional
three-year term extension options with market-based price
adjustments for each extension. In exchange, we received a
substantial increase in the price per ton of coal under the
contract along with inflation adjusters and certain cost pass
through provisions for the remainder of the contract term that
expires at the end of 2012. The 14.9% increase in our average
sales price per ton in 2009 as compared to 2008 is primarily due
to the amendment of this contract.
Oxford Mining Company, our wholly owned subsidiary, was
contributed to us on August 24, 2007. Because Oxford Mining
Company is our accounting predecessor, the financial statements
we have presented for the periods that ended before
August 24, 2007 are the financial statements of Oxford
Mining Company. In addition, because Oxford Mining Company is
now our wholly owned subsidiary, our financial statements that
begin on or after August 24, 2007 include Oxford Mining
Company on a consolidated basis, as required by GAAP. The
contribution of Oxford Mining Company to us on August 24,
2007 resulted in a change of control that triggered a new
fair-value basis of accounting for Oxford Mining Company on that
date. We have analyzed the impact of that transaction on our
consolidated statements of operations and those of our
accounting predecessor.
The operations of the predecessor and successor in 2007 were
substantially the same as all assets and liabilities were
contributed with the exception of the predecessors debt,
which was paid in full, and certain equipment operating leases,
which were paid off. Therefore, the change in control had a
limited impact on the comparability of our 2007 results of
operations. The most notable changes that resulted from the
change in control are set forth below.
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As part of the contribution, we bought out several equipment
operating leases, which had the impact of reducing lease expense
within cost of coal sales and increasing depreciation expense
during the periods after the change in control.
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The fair value basis of accounting had the effect of increasing
the asset value of certain property, plant and equipment as well
as coal reserves, which further increased DD&A expenses
during the periods after the change in control.
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|
In connection with the contribution, Oxford Mining Company
entered into an advisory services agreement with certain
affiliates of AIM Oxford, which resulted in higher SG&A
expenses during the periods after the change in control.
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As a result of the contribution, total borrowings increased,
which resulted in higher interest charges and amortization of
deferred financing fees within interest expense during the
periods after the change in control.
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76
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As part of the accounting for the contribution, we established a
provision for below-market coal sales contracts, which increased
our revenues during the periods after the change in control.
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Based on our analysis, we concluded that the non-GAAP combined
presentation provides for a more meaningful comparison of our
2007 results of operations to other periods. For comparative
purposes, Oxford Mining Companys operating results for the
period from January 1, 2007 to August 23, 2007 and our
operating results for the period from August 24, 2007 to
December 31, 2007 have been combined and are referred to as
non-GAAP combined 2007.
Summary
The following table presents certain of our historical
consolidated financial data and that of our accounting
predecessor, Oxford Mining Company, for the periods indicated.
The following table should be read in conjunction with
Selected Historical and Pro Forma Consolidated Financial
and Operating Data.
Adjusted EBITDA is a non-GAAP financial measure that we use in
analyzing the financial performance of our business as it is an
important supplemental measure of our performance. Adjusted
EBITDA represents net income (loss) attributable to our
unitholders before interest, taxes, DD&A, gain from
purchase of a business, amortization of below-market coal sales
contracts and non-cash equity compensation expense. This measure
is not calculated or presented in accordance with GAAP. We
explain this measure below and reconcile it to net income (loss)
attributable to our unitholders, its most comparable measure
established in accordance with GAAP.
77
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Oxford Mining
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Company
|
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(Predecessor)
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Oxford Resource Partners, LP
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Period from
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Period from
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Non-GAAP
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Year Ended
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Year Ended
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January 1, 2007 to
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August 24, 2007 to
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Combined 2007
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December 31,
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December 31,
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August 23, 2007
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December 31, 2007
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(unaudited)
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2008
|
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2009
|
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(in thousands)
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Statement of Operations Data:
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Revenues:
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Coal sales
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$
|
96,799
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|
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|
$
|
61,324
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$
|
158,123
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|
|
$
|
193,699
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|
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$
|
254,171
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Transportation revenue
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|
|
18,083
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|
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10,204
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|
|
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28,287
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|
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|
31,839
|
|
|
|
32,490
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|
Royalty and non-coal revenue
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|
3,267
|
|
|
|
|
1,407
|
|
|
|
4,674
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|
|
|
4,951
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|
|
|
7,183
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total revenues
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118,149
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|
|
|
|
72,935
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|
|
|
191,084
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|
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|
230,489
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|
|
|
293,844
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Costs and expenses:
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|
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|
|
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|
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|
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Cost of coal sales (excluding DD&A, shown separately)
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70,415
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|
|
|
|
40,721
|
|
|
|
111,136
|
|
|
|
151,421
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|
|
|
170,698
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|
Cost of purchased coal
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17,494
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9,468
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26,962
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|
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12,925
|
|
|
|
19,487
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Cost of transportation
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18,083
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|
|
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10,204
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28,287
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31,839
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32,490
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Depreciation, depletion, and amortization
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9,025
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4,926
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13,951
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16,660
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|
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25,902
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Selling, general and administrative expenses
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3,643
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2,114
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5,757
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|
|
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9,577
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|
|
|
13,242
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|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
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Total costs and expenses
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118,660
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|
|
|
|
67,433
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186,093
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|
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222,422
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|
|
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261,819
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Income from operations
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|
|
(511
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)
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|
5,502
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|
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4,991
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|
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8,067
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|
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|
32,025
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Interest income
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|
|
26
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|
|
|
|
55
|
|
|
|
81
|
|
|
|
62
|
|
|
|
35
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Interest expense
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|
(2,386
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)
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|
(3,498
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)
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(5,884
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)
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(7,720
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)
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(6,484
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)
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Gain from purchase of
business
(1)
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|
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3,823
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|
|
|
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|
|
|
|
|
|
|
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|
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|
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Net income (loss)
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|
(2,871
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)
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|
2,059
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|
|
|
(812
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)
|
|
|
409
|
|
|
|
29,399
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Net income attributable to noncontrolling interest
|
|
|
(682
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)
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|
|
|
(537
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)
|
|
|
(1,219
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)
|
|
|
(2,891
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)
|
|
|
(5,895
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)
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Net income (loss) attributable to Oxford Resource Partners, LP
unitholders
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$
|
(3,553
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)
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$
|
1,522
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$
|
(2,031
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)
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$
|
(2,482
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)
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$
|
23,504
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Other Financial Data:
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Adjusted
EBITDA
(2)
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$
|
7,832
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$
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9,145
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$
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16,977
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$
|
20,349
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$
|
50,799
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(1)
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On September 30, 2009, we
acquired all of the active western Kentucky surface mining
operations of Phoenix Coal. The purchase price of this
acquisition was less than the fair value of the net assets and
liabilities we acquired. We recorded this difference as a gain
of $3.8 million for the year ending December 31, 2009.
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(2)
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Adjusted EBITDA is used as a
supplemental financial measure by management and by external
users of our financial statements, such as investors and
lenders, to assess:
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our financial performance without
regard to financing methods, capital structure or income taxes;
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our ability to generate cash
sufficient to pay interest on our indebtedness and to make
distributions to our unitholders and our general partner;
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our compliance with certain
financial covenants included in our existing credit facility; and
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our ability to fund capital
expenditure projects from operating cash flow.
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78
Adjusted EBITDA should not be considered an alternative to net
income (loss) attributable to our unitholders, income from
operations, cash flows from operating activities or any other
measure of performance presented in accordance with GAAP.
Adjusted EBITDA excludes some, but not all, items that affect
net income (loss) attributable to our unitholders, income from
operations and cash flows, and these measures may vary among
other companies. Therefore, Adjusted EBITDA as presented below
may not be comparable to similarly titled measures of other
companies. The following table presents a reconciliation of
Adjusted EBITDA to net income (loss) attributable to our
unitholders for each of the periods indicated:
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Oxford Mining
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
Company
|
|
|
|
|
|
|
|
|
|
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|
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|
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(Predecessor)
|
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|
|
|
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|
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|
|
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Period from
|
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|
Oxford Resource Partners, LP
|
|
|
|
January 1, 2007
|
|
|
|
Period from
|
|
|
Non-GAAP
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
to August 23,
|
|
|
|
August 24, 2007 to
|
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Combined
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
|
December 31, 2007
|
|
|
2007
|
|
|
2008
|
|
|
2009
|
|
|
|
(in thousands)
|
|
Reconciliation of Adjusted EBITDA to net income (loss)
attributable to Oxford Resource Partners, LP unitholders:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Oxford Resource Partners, LP
unitholders
|
|
$
|
(3,553
|
)
|
|
|
$
|
1,522
|
|
|
$
|
(2,031
|
)
|
|
$
|
(2,482
|
)
|
|
$
|
23,504
|
|
PLUS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
9,025
|
|
|
|
|
4,926
|
|
|
|
13,951
|
|
|
|
16,660
|
|
|
|
25,902
|
|
Interest expense
|
|
|
2,386
|
|
|
|
|
3,498
|
|
|
|
5,884
|
|
|
|
7,720
|
|
|
|
6,484
|
|
Non-cash equity compensation expense
|
|
|
|
|
|
|
|
25
|
|
|
|
25
|
|
|
|
468
|
|
|
|
472
|
|
LESS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
26
|
|
|
|
|
55
|
|
|
|
81
|
|
|
|
62
|
|
|
|
35
|
|
Amortization of below-market coal sales contracts
|
|
|
|
|
|
|
|
771
|
|
|
|
771
|
|
|
|
1,955
|
|
|
|
1,705
|
|
Gain from purchase of business
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
7,832
|
|
|
|
$
|
9,145
|
|
|
$
|
16,977
|
|
|
$
|
20,349
|
|
|
$
|
50,799
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31, 2009 Compared to Year Ended
December 31, 2008
Overview.
Our coal production increased 14.9%
to 5.8 million tons in 2009 compared to 5.1 million
tons in 2008. We sold 6.3 million tons of coal in 2009, an
increase of 14.2% when compared to the 5.5 million tons we
sold in 2008. Our average sales price per ton increased 14.9%,
or $5.23 per ton, in 2009 when compared with 2008. Our total
revenues for 2009 increased 27.5% to $293.8 million from
$230.5 million in 2008. We generated net income
attributable to our unitholders of approximately
$23.5 million during 2009 as compared to net loss
attributable to our unitholders of $2.5 million for 2008.
Our Adjusted EBITDA increased 149.6% in 2009 to
$50.8 million from $20.3 million in 2008.
Coal Production.
Our tons of coal produced
increased 14.9% to 5.8 million tons in 2009 from
5.1 million tons in 2008. This increase was primarily the
result of increased coal production in the fourth quarter of
2009 due to the Phoenix Coal acquisition of 0.4 million
tons and higher production at certain of our other mining
complexes. We increased our coal production for 2009 to match
the increase in the tons that we were committed to deliver under
our long-term coal sales contracts during 2009.
Sales Volume.
Our tons of coal sold increased
14.2% to 6.3 million tons in 2009 from 5.5 million
tons in 2008. The increase in the tons sold in 2009 was
primarily attributable to the 0.6 million tons of coal we sold
during the fourth quarter of 2009 as a result of the Phoenix
Coal acquisition and an increase in the tons we were committed
to deliver under our long-term coal sales contracts in 2009 as
compared with 2008.
79
Average Sales Price Per Ton.
Our average sales
price per ton increased 14.9% to $40.27 in 2009 from $35.04 in
2008. This increase was primarily attributable to the amendment
of a long-term coal sales contract with a major customer in
December 2008. As part of this amendment, we agreed to give this
customer two additional three-year term extension options with
market-based price adjustments for each extension. In exchange,
we received a substantial increase in the price per ton under
the contract along with inflation adjusters and certain cost
pass through provisions through the remainder of the contract
term that expires at the end of 2012.
Coal Sales Revenue.
Our coal sales for 2009
increased by $60.5 million, or 31.2%, over 2008. The
majority of the increase, or $33.5 million, was
attributable to the 14.9% increase in our average sales price
per ton for 2009 as compared to 2008. In addition,
$26.9 million of this increase was attributable to the
14.2% increase in our tons sold for 2009 as compared to 2008.
Royalty and Non-Coal Revenue.
In June 2005, we
sold our underground mining operations at the Tusky mining
complex and subleased our related underground coal reserves to
the purchaser in exchange for an overriding royalty. Our
overriding royalty is equal to a percentage of the sales price
our sublessee receives for the coal produced from our
underground coal reserves. Our sublessee is also obligated to
pay the tonnage based royalty that we owe to the lessor of our
underground coal reserves. Our royalty and non-coal revenue
includes our overriding royalty revenue, revenue from the sale
of limestone that we recover in connection with our coal mining
operations and various fees we receive for performing services
for others. Our royalty and non-coal revenue increased to
$7.2 million in 2009 from $5.0 million in 2008. This
increase was primarily attributable to increases in our royalty
revenue from our underground coal reserves of $3.2 million
partially offset by decreases in other revenue of $1.0 million.
During 2009, our royalty revenue from our underground coal
reserves increased to $4.5 million from $1.3 million
in 2008. This increase was attributable to significant increases
in coal production and sales to third parties by the sublessee
of our underground coal reserves. In 2009, our sublessee sold
its underground coal production to third parties for the full
year as compared to 2008 when it sold its production to third
parties for approximately six months.
Cost of Coal Sales (Excluding DD&A).
Cost
of coal sales (excluding DD&A) increased 12.7% in 2009 to
$170.7 million from $151.4 million in 2008. This
increase was primarily attributable to the increase in our tons
of coal produced, partially offset by lower operating costs per
ton. During 2009, our cost of coal sales per ton produced
decreased 1.9% primarily as a result of lower fuel, oil and
explosives prices partially offset by higher operating lease
expenses and higher contract labor costs. Our diesel fuel cost
per ton of coal produced decreased from $8.47 per ton in 2008 to
$6.56 per ton in 2009. Our motor and hydraulic oil cost per ton
decreased from $1.17 per ton in 2008 to $0.85 per ton in 2009,
and our explosives cost per ton decreased from $3.44 per ton in
2008 to $3.24 per ton in 2009. Our operating lease expenses per
ton increased to $0.79 per ton in 2009 from $0.31 per ton in
2008 as we expanded our fleet of large equipment at our Cadiz
and Harrison mining complexes. In addition, our contract labor
costs per ton increased to $1.44 per ton in 2009 from $0.62 per
ton in 2008 as a result of a full year of the costs associated
with a highwall mining contractor that we retained in July 2008.
Cost of Purchased Coal.
Cost of purchased coal
increased 50.8% in 2009 to $19.5 million from
$12.9 million in 2008. This increase was primarily
attributable to a $6.98 per ton increase in the average cost of
purchased coal per ton and a 0.1 million ton increase in
the volume of coal purchased during 2009 as compared to 2008.
Our average cost of purchased coal per ton increased by 23.4% to
$36.79 per ton in 2009 from $29.81 per ton in 2008. During the
first quarter of 2009, we purchased a higher percentage of our
purchased coal on the spot market in order to meet our coal
sales obligations. For the fourth quarter of 2009, we purchased
a higher percentage of our purchased coal under a long-term coal
purchase contract. During 2009 the volume of coal we purchased
increased by 0.1 million tons over 2008 primarily as a
result of one quarter of coal purchases under the long-term coal
purchase contract that we assumed in connection with the Phoenix
Coal acquisition.
Depreciation, Depletion and
Amortization.
DD&A expense for 2009 was
$25.9 million as compared to $16.7 million for 2008,
an increase of $9.2 million. Depreciation expense
attributable to equipment upgrades that occurred during 2009
accounted for $7.6 million of this increase and the assets
we acquired in the Phoenix Coal acquisition increased our
depreciation expense by $1.8 million.
80
Selling, General and Administrative
Expenses.
SG&A expenses for 2009 were
$13.2 million as compared to $9.6 million for 2008, an
increase of $3.6 million. The increase in SG&A
expenses was primarily due to increased headcount and expenses
in our accounting and administrative departments in anticipation
of becoming a publicly traded partnership, as well as one-time
costs of $1.6 million associated with the Phoenix Coal
transaction and $1.0 million of legal fees incurred in
renegotiating our existing credit facility.
Transportation Revenue and Expenses.
Our
transportation expenses represent the cost to transport our coal
by truck or rail from our mines to our river terminals, our rail
loading facilities and our customers. Our long-term coal sales
contracts have these transportation costs built into the price
of our coal. Our transportation revenue reflects the portion of
our total revenues that is attributable to reimbursements for
transportation expenses. Our transportation revenue fluctuates
based on a number of factors, including the volume of coal we
transport by truck or rail under those contracts and the related
transportation costs. The 2.0% increase in transportation
revenue in 2009 as compared to 2008 was a function of the
increase in tons of coal sold partially offset by lower trucking
rates.
Interest Expense.
Interest expense for 2009
was $6.5 million as compared to $7.7 million for 2008,
a decrease of $1.2 million or 16.0%. The decrease in
interest expense was primarily attributable to lower effective
weighted average interest rates in 2009 under our existing
credit facility as compared to 2008 and a gain of
$1.7 million on our interest rate swap in 2009. These
decreases were partially offset by an increase of
$1.3 million in interest expense due to the write off of
capitalized financing costs as a result of an amendment in 2009
to our existing credit facility.
Gain from Purchase of Business.
On
September 30, 2009, we acquired all of the active surface
mining operations of Phoenix Coal. The purchase price of this
acquisition was less than the fair value of the net assets and
liabilities we acquired. We recorded this difference as a
one-time gain of $3.8 million for 2009.
Net Income Attributable to Noncontrolling
Interest.
In 2007, we entered into a joint
venture, Harrison Resources, with CONSOL Energy to mine surface
coal reserves purchased from CONSOL Energy. We own 51% of
Harrison Resources and CONSOL Energy owns the remaining 49%
indirectly through one of its subsidiaries. We manage all of the
operations of, and perform all of the contract mining and
marketing services for, Harrison Resources. Net income
attributable to noncontrolling interest relates to the 49% of
Harrison Resources that we do not own. For the year ended
December 31, 2009, net income attributable to the
noncontrolling interest was $5.9 million as compared to
$2.9 million for 2008. This increase of $3.0 million
was primarily attributable to an increase of 64% in tons of coal
sold by Harrison Resources in 2009 compared to 2008, as well as
to increased sales prices.
Year
Ended December 31, 2008 Compared to Non-GAAP Combined
2007
Overview.
Our coal production increased 17.6%
to 5.1 million tons in 2008 compared to 4.3 million
tons in non-GAAP combined 2007. We sold 5.5 million tons of
coal in 2008, an increase of 4.9% when compared to the
5.3 million tons we sold in non-GAAP combined 2007. Our
average sales price per ton increased 16.8%, or $5.04 per ton,
in 2008 when compared with non-GAAP combined 2007. Our total
revenues for 2008 increased 20.6% to $230.5 million from
$191.1 million in non-GAAP combined 2007. We had a net loss
attributable to our unitholders of approximately
$2.5 million during 2008 as compared to a net loss
attributable to our unitholders of $2.0 million for
non-GAAP combined 2007. Our Adjusted EBITDA increased 19.9% in
2008 to $20.3 million from $17.0 million in non-GAAP
combined 2007.
Coal Production.
Our tons of coal produced
increased 17.6% to 5.1 million tons in 2008 from
4.3 million tons in non-GAAP combined 2007. This increase
was primarily due to higher production in 2008 from reserves
acquired during non-GAAP combined 2007 at our Belmont and Cadiz
mining complexes and the additional reserves acquired by
Harrison Resources from CONSOL during 2008. We increased our
production in 2008 to meet the requirements of a new long-term
coal sales contract which started in 2008.
Sales Volume.
Our tons of coal sold increased
4.9% to 5.5 million tons in 2008 from 5.3 million tons
in non-GAAP combined 2007 primarily as a result of an increase
of 0.8 million tons in coal production partially offset by a
decrease of 0.5 million tons in purchased coal.
81
Average Sales Price Per Ton.
Our average sales
price per ton increased 16.8% to $35.04 in 2008 from $30.00 in
non-GAAP combined 2007. This increase was due to the replacement
of expiring long-term coal sales contracts with higher priced
long-term coal sales contracts.
Coal Sales Revenue.
Our coal sales for 2008
increased by $35.6 million, or 22.5%, over non-GAAP
combined 2007. The majority of the increase, or
$27.9 million, was attributable to the 16.8% increase in
our average sales price per ton for 2008 as compared to non-GAAP
combined 2007. In addition, $7.7 million of this increase
was attributable to the 4.9% increase in our tons of coal sold
for 2008 as compared to non-GAAP combined 2007.
Royalty and Non-Coal Revenue.
We began
receiving royalty revenues on our underground coal reserves in
June 2008 as the sublessee began selling coal produced from our
underground coal reserves directly to third parties. Before June
2008 we purchased, processed and sold all of the coal produced
by our sublessee from our underground coal reserves and, as a
result, we did not receive an overriding royalty.
Cost of Coal Sales (Excluding DD&A).
Cost
of coal sales (excluding DD&A) increased 36.2% in 2008 to
$151.4 million from $111.1 million in non-GAAP
combined 2007. This increase was primarily attributable to the
increase in our tons of coal produced and higher operating
costs. During 2008, our cost of coal sales per ton produced
increased 15.8% primarily as a result of higher fuel costs as
compared to non-GAAP combined 2007. Our diesel fuel cost per ton
of coal produced increased to $8.47 per ton in 2008 from $6.33
per ton in non-GAAP combined 2007.
Cost of Purchased Coal.
Cost of purchased coal
decreased 52.1% in 2008 to $12.9 million from
$27.0 million in non-GAAP combined 2007. This decrease was
primarily attributable to a 0.5 million ton decrease in the
volume of coal we purchased during 2008 as compared to non-GAAP
combined 2007 partially offset by the $1.30 increase in the
average cost of purchased coal per ton in 2008 as compared to
non-GAAP combined 2007. The decrease in the volume of purchased
coal was primarily due to the discontinuation of coal purchases
from the sublessee of our underground coal reserves in June
2008. Our average cost of purchased coal per ton increased by
4.3% to $29.81 per ton in 2008 from $28.51 per ton in non-GAAP
combined 2007.
Depreciation, Depletion and
Amortization.
DD&A expense for 2008 was
$16.7 million as compared to $14.0 million for
non-GAAP combined 2007, an increase of $2.7 million. This
increase was primarily the result of a full year of depreciation
on the higher asset values that resulted from the new asset
basis for Oxford Mining Company due to the change of control
that occurred on August 24, 2007. Because a new asset basis
can inhibit meaningful comparison of historical results before
and after the change of control, DD&A expense for non-GAAP
combined 2007 is not comparable to 2008.
Selling, General and Administrative
Expenses.
SG&A expenses for 2008 were
$9.6 million as compared to $5.8 million for non-GAAP
combined 2007, an increase of $3.8 million. The increase in
SG&A expenses was primarily due to increases in accounting
and administrative personnel expenses of $1.3 million,
increases in professional fees of $1.5 million and the
one-time write off of costs associated with an acquisition that
we did not complete of $0.4 million.
Transportation Revenue and Expenses.
The 12.6%
increase in transportation revenue in 2008 as compared to
non-GAAP combined 2007 was a function of the increase in tons of
coal sold and higher trucking costs due to increased fuel prices
in 2008.
Interest Expense.
Interest expense for 2008
was $7.7 million as compared to $5.9 million for
non-GAAP combined 2007, an increase of $1.8 million. This
increase was primarily attributable to an increase in our
weighted average interest rates and average outstanding balances
under our existing credit facility during 2008 as compared to
non-GAAP combined 2007.
Net Income Attributable to Noncontrolling
Interest.
Net income attributable to the
noncontrolling interest was $2.9 million for 2009 as
compared to $1.2 million for non-GAAP combined 2007. This
increase of $1.7 million was primarily attributable to an
increase of 97% in tons sold by Harrison Resources in 2008
compared to non-GAAP combined 2007 as well as increases in
average sales prices.
82
Liquidity
and Capital Resources
Liquidity
Our business is capital intensive and requires substantial
capital expenditures for purchasing, upgrading and maintaining
equipment used in mining our reserves, as well as complying with
applicable environmental laws and regulations. Our principal
liquidity requirements are to finance current operations, fund
capital expenditures, including acquisitions from time to time,
service our debt and pay cash distributions to our unitholders.
Our primary sources of liquidity to meet these needs have been
cash generated by our operations, borrowings under our existing
credit facility and contributions from our partners.
The principal indicators of our liquidity are our cash on hand
and availability under our existing credit facility. As of
December 31, 2009, our available liquidity was
$10.7 million, including cash on hand of $3.4 million
and $7.3 million available under our existing credit
facility.
We believe that our expected sources of liquidity after this
offering, which include our working capital, cash flows from
operations, borrowing capacity under our new credit facility and
future issuances of debt and equity securities, will be
sufficient to meet our financial commitments, debt service
obligations, contingencies and anticipated capital expenditures
for the near term. However, we are subject to business and
operational risks that could adversely affect our cash flows. A
material decrease in our cash flows would likely produce a
corollary adverse effect on our borrowing capacity.
Please read Capital Expenditures for a
further discussion on the impact of capital expenditures on
liquidity.
Cash
Flows
The following table reflects cash flows for the applicable
periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oxford Mining Company
|
|
|
|
|
|
|
|
|
(Predecessor)
|
|
Oxford Resource Partners, LP
|
|
|
January 1, 2007 to
|
|
August 24, 2007 to
|
|
Year Ended December 31,
|
|
|
August 23, 2007
|
|
December 31, 2007(1)
|
|
2008
|
|
2009
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating activities
|
|
$
|
17,634
|
|
|
$
|
(8,478
|
)
|
|
$
|
33,951
|
|
|
$
|
35,540
|
|
Investing activities
|
|
$
|
(16,619
|
)
|
|
$
|
(103,336
|
)
|
|
$
|
(23,901
|
)
|
|
$
|
(51,115
|
)
|
Financing activities
|
|
$
|
(234
|
)
|
|
$
|
111,274
|
|
|
$
|
4,494
|
|
|
$
|
3,762
|
|
|
|
|
(1)
|
|
Please read Note 1 to our
historical consolidated financial statements included elsewhere
in this prospectus.
|
Year Ended December 31, 2009 Compared to Year Ended
December 31, 2008.
Net cash provided by
operating activities was $35.5 million for 2009 as compared
to $34.0 million for 2008. This $1.5 million increase
was primarily due to the combined effects of the
$26.0 million increase in net income (loss) attributable to
our unitholders, the $9.2 million impact from the increase
in DD&A expense, as well as higher other non-cash
adjustments of $1.2 million, partially offset by a decrease
in the cash provided by changes in assets and liabilities of
$34.9 million.
Net cash used in investing activities was $51.1 million in
2009 as compared to $23.9 million for 2008. This
$27.2 million increase was primarily attributable to the
$18.3 million we spent in connection with the Phoenix Coal
acquisition as well as increased purchases of coal properties in
2009 as compared to 2008.
Net cash provided by financing activities was $3.8 million
for 2009 as compared to $4.5 million for 2008. This
$0.7 million decrease was primarily attributable to
increased distributions to the noncontrolling interest holder in
Harrison Resources during 2009 compared to 2008.
Year Ended December 31, 2008 Compared to
Non-GAAP Combined 2007.
Net cash provided by
operating activities was $34.0 million for 2008 as compared
to $9.2 million for non-GAAP combined 2007.
83
This $24.8 million change was primarily due to a
$22.1 million increase in cash provided by changes in
assets and liabilities and an increase of $2.7 million
associated with higher DD&A expense.
Our net cash provided by (used in) investing activities and
financing activities for 2007 includes the impact of the
transactions relating to the contribution of Oxford Mining
Company to us in August 2007. Please read
Results of Operations Factors
Affecting the Comparability of our Results of Operations,
and Note 1 to our historical consolidated financial
statements included elsewhere in this prospectus.
Credit
Facility
In connection with our initial public offering, we will pay off
our existing credit facility and enter into a new credit
facility that will include (i) a
$ million revolver and
(ii) a $ million term
loan. The revolver and term loan will mature
in ,
and borrowings will bear interest, at a variable rate per annum
equal to the lesser of LIBOR or the Base Rate, as the case may
be, plus the Applicable Margin (LIBOR, Base Rate and Applicable
Margin will each be defined in the credit agreement that
evidences our new credit facility). Under our new credit
facility, in addition to the uses described in Use of
Proceeds, we expect that borrowings may be used for
(i) the refinancing and repayment of certain existing
indebtedness, (ii) working capital and other general
partnership purposes and (iii) capital expenditures.
Borrowings under our new credit facility will be secured by a
first-priority lien on and security interest in substantially
all of our assets. The credit agreement that evidences our new
credit facility will contain customary covenants, including
restrictions on our ability to incur additional indebtedness,
make certain investments, loans or advances, make distributions
to our unitholders, make dispositions or enter into sales and
leasebacks, or enter into a merger or sale of our property or
assets, including the sale or transfer of interests in our
subsidiaries.
The events that constitute an Event of Default under our new
credit agreement are expected to be customary for loans of this
size and type.
Contractual
Obligations
We have contractual obligations that are required to be settled
in cash. The amounts of our contractual obligations as of
December 31, 2009 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments due by period
|
|
|
|
|
|
|
Less Than
|
|
|
|
|
|
|
|
|
More Than
|
|
|
|
Total
|
|
|
1 Year
|
|
|
1-3 Years
|
|
|
4-5 Years
|
|
|
5 Years
|
|
|
|
(in thousands)
|
|
|
Long-term debt
obligations
(1)
|
|
$
|
105,507
|
|
|
$
|
5,591
|
|
|
$
|
99,916
|
|
|
$
|
|
|
|
$
|
|
|
Other long-term
debt
(2)
|
|
|
5,435
|
|
|
|
3,642
|
|
|
|
1,783
|
|
|
|
10
|
|
|
|
|
|
Operating lease obligations
|
|
|
18,425
|
|
|
|
6,289
|
|
|
|
12,013
|
|
|
|
123
|
|
|
|
|
|
Fixed price diesel fuel purchase contracts
|
|
|
9,446
|
|
|
|
9,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term coal purchase
contract
(3)
|
|
|
83,627
|
|
|
|
14,103
|
|
|
|
29,796
|
|
|
|
19,864
|
|
|
|
19,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
222,440
|
|
|
$
|
39,071
|
|
|
$
|
143,508
|
|
|
$
|
19,997
|
|
|
$
|
19,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Amounts relate to our existing
credit facility that will be repaid in full in connection with
this offering. Please read Use of Proceeds. Assumes
a current LIBOR of 1.0% plus the applicable margin, which
remains constant for all periods.
|
|
(2)
|
|
Represents various notes payable
with interest rates ranging from 4.6% to 9.25%.
|
|
(3)
|
|
We assumed a long-term coal
purchase contract as a result of the Phoenix Coal acquisition.
Please read Note 17 to our historical financial statements
included elsewhere in this prospectus.
|
Capital
Expenditures
Our mining operations require investments to expand, upgrade or
enhance existing operations and to comply with environmental
regulations. Our capital requirements primarily consist of
maintenance capital expenditures and expansion capital
expenditures. Maintenance capital expenditures are those capital
84
expenditures required to maintain or replace, including over the
long term, our operating capacity, asset base or operating
income. Expansion capital expenditures are those capital
expenditures made to increase our
long-term
operating capacity, asset base or operating income. Examples of
maintenance capital expenditures include the replacement of
equipment and coal reserves, whether through the expansion of an
existing mine or the acquisition (by lease or otherwise) of new
reserves, to the extent such expenditures are incurred to
maintain or replace our operating capacity, asset base or
operating income. Examples of expansion capital expenditures
include the acquisition (by lease or otherwise) of reserves,
equipment or a new mine or the expansion of an existing mine, to
the extent such expenditures are incurred to increase our
long-term operating capacity, asset base or operating income.
For the year ending December 31, 2010, we have budgeted
$32.8 million in maintenance capital expenditures. We
expect to fund maintenance capital expenditures primarily from
cash generated by our operations. To the extent we incur
expansion capital expenditures, we expect to fund those
expenditures with the proceeds of borrowings under our new
credit facility, issuance of debt and equity securities or other
external sources of financings.
Off-Balance
Sheet Arrangements
In the normal course of business, we are a party to certain
off-balance sheet arrangements. These arrangements include
guarantees and financial instruments with off-balance sheet
risk, such as bank letters of credit, surety bonds, performance
bonds and road bonds. No liabilities related to these
arrangements are reflected in our consolidated balance sheet,
and we do not expect any material adverse effects on our
financial condition, results of operations or cash flows to
result from these off-balance sheet arrangements.
Federal and state laws require us to secure certain long-term
obligations such as mine closure and reclamation costs and other
obligations. We typically secure these obligations by using
surety bonds, an off-balance sheet instrument. The use of surety
bonds is less expensive for us than the alternative of posting a
100% cash bond and we typically use bank letters of credit to
secure our surety bonding obligations. To the extent that surety
bonds become unavailable, we would seek to secure our
reclamation obligations with letters of credit, cash deposits or
other suitable forms of collateral. We also post performance
bonds to secure our performance of various contractual
obligations and road bonds to secure our obligations to repair
local roads.
As of December 31, 2009, we had approximately
$31.3 million in surety bonds outstanding to secure the
performance of our reclamation obligations, which were supported
by approximately $6.9 million in letters of credit. As of
December 31, 2009, we had approximately $12.3 million
of performance bonds outstanding and $0.6 million of road
bonds outstanding, none of which were secured by letters of
credit.
Critical
Accounting Policies and Estimates
Our preparation of financial statements in conformity with GAAP
requires that we make estimates and assumptions that affect the
amounts reported in the consolidated financial statements and
accompanying notes. We base our judgments, estimates and
assumptions on historical information and other known factors
that we deem relevant. Estimates are inherently subjective as
significant management judgment is required regarding the
assumptions utilized to calculate accounting estimates. The most
significant areas requiring the use of management estimates and
assumptions relate to
units-of-production
amortization calculations, asset retirement obligations, useful
lives for depreciation of fixed assets and estimates of fair
values for asset impairment purposes. Our significant accounting
policies are more fully described in Note 2 to our
historical consolidated financial statements included elsewhere
in this prospectus. This section describes those accounting
policies and estimates that we believe are critical to
understanding our historical consolidated financial statements
and that we believe will be critical to understanding our
consolidated financial statements subsequent to this offering.
Inventory
Inventory consists of coal that has been completely uncovered or
that has been removed from the pit and stockpiled for crushing,
washing or shipment to customers. Inventory also consists of
supplies, primarily spare
85
parts and fuel. Inventory is valued at the lower of average cost
or market. The cost of coal inventory includes labor, equipment
operating expenses and certain transportation and operating
overhead.
Property,
Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures
that extend the useful lives of existing plant and equipment are
capitalized. Maintenance and repairs that do not extend the
useful life or increase productivity are charged to operating
expense as incurred. Exploration expenditures are charged to
operating expense as incurred, including costs related to
locating coal deposits and drilling and evaluation costs
incurred to assess the economic viability of such deposits.
Plant and equipment are depreciated principally on the
straight-line method over the estimated useful lives of the
assets based on the following schedule:
|
|
|
Buildings and tipple
|
|
25 39 years
|
Machinery and equipment
|
|
7 12 years
|
Vehicles
|
|
5 7 years
|
Furniture and fixtures
|
|
3 7 years
|
Railroad siding
|
|
7 years
|
We acquire our reserves through purchases or leases of coal
reserves. Coal reserves are recorded at fair value under
purchase accounting at our formation date of August 24,
2007, or as part of the Phoenix Coal acquisition. We deplete our
reserves using the
units-of-production
method, without residual value, on the basis of tonnage mined in
relation to estimated recoverable tonnage. At December 31,
2009 and 2008, all of our reserves were attributed to mine
complexes engaged in mining operations or leased to third
parties. We believe that the carrying value of these reserves
will be recovered. Residual surface values are classified as
land and not depleted.
Exploration expenditures are charged to operating expense as
incurred, including costs related to locating coal deposits and
drilling and evaluation costs incurred to assess the economic
viability of such deposits. Once the economic viability of such
deposits is established, future expenditures are classified as
mine development costs and are capitalized until production
commences. Amortization of these mine development costs is
initiated when the mine begins production using the
units-of-production
method based upon the estimated recoverable tonnage.
Advance
Royalties
A substantial portion of our reserves are leased. Advance
royalties are advance payments made to lessors under terms of
mineral lease agreements that are recoupable through a reduction
in royalties payable on future production. Amortization of
leased coal interests is computed using the
units-of-production
method over estimated recoverable tonnage.
Long-Lived
Assets
We follow authoritative guidance that requires projected future
cash flows from use and disposition of assets to be compared
with the carrying amounts of those assets when impairment
indicators are present. When the sum of projected cash flows is
less than the carrying amount, impairment losses are indicated.
If the fair value of the assets is less than the carrying amount
of the assets, an impairment loss is recognized. In determining
such impairment losses, discounted cash flows or asset
appraisals are utilized to determine the fair value of the
assets being evaluated. Also, in certain situations, expected
mine lives are shortened because of changes to planned
operations. When that occurs and it is determined that the
mines underlying costs are not recoverable in the future,
reclamation and mine closure obligations are accelerated. To the
extent it is determined that an assets carrying value will
not be recoverable during a shorter mine life, the asset is
written down to its recoverable value. No impairment triggers
occurred and therefore no impairment losses were recognized
during any of the years or periods presented.
86
Identifiable
Intangible Assets
Identifiable intangible assets are recorded in other assets in
the accompanying consolidated balance sheets. We capitalize
costs incurred in connection with borrowings or the
establishment of credit facilities. These costs are amortized as
an adjustment to interest expense over the life of the borrowing
or term of the credit facility using the interest method.
We also have recorded intangible assets and liabilities at fair
value associated with certain customer relationships and
below-market coal sales contracts, respectively. These balances
arose from the use of purchase accounting for business
combinations and so the assets and liabilities were adjusted to
fair value. These intangible assets are being amortized over
their expected useful lives.
Asset
Retirement Obligation
Our asset retirement obligations, or AROs, arise from the SMCRA
and similar state statutes, which require that mine property be
restored in accordance with specified standards and an approved
reclamation plan. Our AROs are recorded initially at fair value.
It has been our practice, and we anticipate that it will
continue to be our practice, to perform a substantial portion of
the reclamation work using internal resources. Hence, the
estimated costs used in determining the carrying amount of our
AROs may exceed the amounts that are eventually paid for
reclamation costs if the reclamation work was performed using
internal resources.
To determine the fair value of our AROs, we calculate on a mine
by mine basis the present value of estimated reclamation cash
flows. This process requires us to estimate the current
disturbed acreage subject to reclamation, estimates of future
reclamation costs and assumptions regarding the mines
productivity. These cash flows are discounted at the
credit-adjusted, risk free interest rate based on
U.S. Treasury bonds with a maturity similar to the expected
lives of our mines.
When the liability is initially recorded for the costs to open a
new mine site, the offset is recorded to the producing mine
asset. Over time, the ARO liability is accreted to its present
value, and the capitalized cost is depreciated over the
units-of-production
for the related mine. The liability is also increased as
additional land is disturbed during the mining process. The
timeline between digging the mining pit and extracting the coal
is relatively short; therefore, much of the liability created
for active mining is expensed within a month or so of
establishment because the related coal has been extracted. If
the assumptions used to estimate the ARO do not materialize as
expected or regulatory changes occur, reclamation costs or
obligations to perform reclamation and mine closure activities
could be materially different than currently estimated. We
review our entire reclamation liability at least annually and
make necessary adjustments for permit changes as granted by
state authorities, additional costs resulting from revisions to
cost estimates and the quantity of disturbed acreage during the
current year.
Income
Taxes
As a limited partnership, we are not a taxable entity for
federal or state income tax purposes; the tax effect of our
activities passes through to our unitholders. Therefore, no
provision or liability for federal or state income taxes is
included in our financial statements. Net income for financial
statement purposes may differ significantly from taxable income
reportable to our unitholders as a result of timing or permanent
differences between financial reporting under GAAP and the
regulations promulgated by the IRS.
Revenue
Recognition
Revenue from coal sales is recognized and recorded when shipment
or delivery to the customer has occurred, prices are fixed or
determinable and the title or risk of loss has passed in
accordance with the terms of the sales contract. Under the
typical terms of these contracts, risk of loss transfers to the
customers at the mine or port when the coal is loaded on the
rail, barge or truck.
Freight and handling costs paid to third-party carriers and
invoiced to customers are recorded as cost of transportation and
transportation revenue, respectively.
87
Royalty and non-coal revenue consists of coal royalty income,
service fees for providing land-fill earth moving services,
commissions that we receive from a third party who sells
limestone that we recover during our coal mining process,
service fees for operating a coal unloading facility for a third
party and fees that we receive for trucking ash for two
municipal utility customers. Revenues are recognized when
earned, or when the services are performed. Royalty revenue
relates to the overriding royalty we receive on our underground
coal reserves that we sublease to a third party mining company.
By June 2008, our sublessee had completed the installation of
its processing infrastructure and began to sell its coal
production to other third parties.
Coal
Sales Contracts
Our below-market coal sales contracts that were acquired through
the Phoenix Coal acquisition and in connection with our
acquisition of Oxford Mining Company in 2007 are contracts for
which the prevailing market price was in excess of the contract
price. The fair value was based on discounted cash flows
resulting from the difference between the below-market contract
price and the prevailing market price at the date of
acquisition. The difference between the below-market
contracts cash flows and the cash flows at the prevailing
market price is amortized into coal sales on the basis of tons
shipped over the term of the respective contract.
Unit-Based
Compensation
We account for unit-based awards in accordance with applicable
guidance, which establishes standards of accounting for
transactions in which an entity exchanges its equity instruments
for goods or services. Unit-based compensation expense is
recorded based upon the fair value of the award at the grant
date. Such costs are recognized as expense on a straight-line
basis over the corresponding vesting period. The fair value of
our LTIP units is determined based on the sale price of our
limited partner units in arms length transactions. The
unit price fair value was increased in September 2009 in
connection with the Phoenix Coal acquisition where additional
units were purchased by C&T Coal and AIM Oxford
disproportionately to their respective ownership interests to
help fund the acquisition. This resulted in C&T Coals
previous ownership interest being diluted. We verified the
reasonableness of the new valuation of our units using
traditional valuation techniques for publicly traded
partnerships.
New
Accounting Standards Issued and Adopted
In June 2009, the FASB issued a new standard establishing the
FASB Accounting Standards Codification
(Codification) as the sole source of authoritative
generally accepted accounting principles. The Codification
reorganized existing U.S. accounting and reporting
standards issued by the FASB and other related private sector
standard setters into a single source of authoritative
accounting principles arranged by topic. The Codification
supersedes all existing U.S. accounting standards; all
other accounting literature not included in the Codification
(other than SEC guidance for publicly traded companies) is
considered non-authoritative. This standard is effective for
interim and annual reporting periods ending after
September 15, 2009. The Codification does not change
existing GAAP.
In September 2009, the FASB issued Accounting Standards Update
(ASU)
2009-06,
Implementation Guidance on Accounting for Uncertainty in
Income Taxes and Disclosure Amendments for Nonpublic
Entities
. This update addresses the need for additional
implementation guidance on accounting for uncertainty in income
taxes for all entities. The update clarifies that an
entitys tax status as a pass through or tax-exempt
not-for-profit entity is a tax position subject to recognition
requirements of the standard and therefore must use the
recognition and measurement guidance when assessing their tax
positions. The ASU
2009-06
updates are effective for interim and annual periods ending
after September 15, 2009. The adoption of the guidance in
ASU
2009-06
during the third quarter of 2009 did not have a material impact
on our consolidated financial statements.
In May 2009, the FASB issued new guidance for accounting for
subsequent events that established the accounting for and
disclosure of events that occur subsequent to the balance sheet
date but before financial statements are issued or are available
to be issued. The standard provides guidance on
managements
88
assessment of subsequent events and incorporates this guidance
into accounting literature. The standard is effective
prospectively for interim and annual periods ending after
June 15, 2009. We adopted this standard for the year ended
December 31, 2009 and the adoption did not impact our
consolidated financial statements.
In December 2007, the FASB issued revised guidance on business
combinations. This new guidance establishes principles and
requirements for the acquirer of a business to recognize and
measure in its financial statements. This amendment applies to
all business combinations and establishes guidance for
recognizing and measuring identifiable assets, liabilities,
noncontrolling interests in the acquiree and goodwill. Most of
these items are recognized at their full fair value on the
acquisition date, including acquisitions where the acquirer
obtains control but less than 100% ownership in the acquiree.
The amendment also requires expensing acquisition-related costs
as incurred and establishes disclosure requirements to enable
the evaluation of the nature and financial effects of the
business combination. This guidance is effective for business
combinations with an acquisition date in fiscal years beginning
after December 15, 2008. We have recorded the acquisition
of the surface coal mining assets of Phoenix Coal dated
September 30, 2009 under this revised guidance. The impact
of adoption was to expense $379,000 of previously capitalized
acquisition costs as of January 1, 2009.
In December 2007, the FASB issued new guidance on the accounting
for noncontrolling ownership interests in a subsidiary and for
the deconsolidation of a subsidiary. The guidance requires that
noncontrolling ownership interests in consolidated subsidiaries
be presented in the consolidated balance sheet within
partners capital as a separate component from the
parents equity as opposed to mezzanine equity.
Consolidated net income will now be disclosed as the amount
attributable to both the parent and the noncontrolling
interests. The guidance also provides for changes in the
parents ownership interest in a subsidiary, including
transactions where control is retained and where control is
relinquished; it also requires expanded disclosures in the
consolidated financial statements that clearly identify and
distinguish between the interests of the parent owners and the
interests of the noncontrolling owners of a subsidiary. This
guidance requires retrospective application to all periods
presented, as included in our consolidated financial statements.
New
Accounting Standards Issued and Not Yet Adopted
In August 2009, the FASB issued ASU
2009-05,
Measuring Liabilities at Fair Value. The amendment provides
clarification that in circumstances in which a quoted price in
an active market for the identical liability is not available, a
reporting entity is required to measure fair value using one or
more of the alternative valuation methods outlined in the
guidance. It also clarifies that restrictions preventing the
transfer of a liability should not be considered as a separate
input or adjustment in the measurement of its fair value. This
amendment was effective as of the beginning of interim and
annual reporting periods that begin after August 27, 2009.
The adoption of this guidance did not impact our consolidated
financial statements.
In June 2009, the FASB amended guidance for the consolidation of
a variable interest entity (VIE). This guidance
updated the determination of whether an enterprise is the
primary beneficiary of a VIE, and is, therefore, required to
consolidate an entity, by requiring a qualitative analysis
rather than a quantitative analysis. This standard also requires
continuous reassessments of whether an enterprise is the primary
beneficiary of a VIE. Previously, reconsideration was required
only when specific events had occurred. This guidance also
requires enhanced disclosure about an enterprises
involvement with a VIE. The provisions of these updates are
effective as of the beginning of interim and annual reporting
periods that begin after November 15, 2009. We do not
believe that this standard will have a material impact on our
consolidated financial statements.
Quantitative
and Qualitative Disclosures about Market Risk
We define market risk as the risk of economic loss as a
consequence of the adverse movement of market rates and prices.
We believe our principal market risks are commodity price risks
and interest rate risk.
Commodity
Price Risk
Historically, we have principally managed the commodity price
risks from our coal sales through the use of long-term coal
sales contracts of varying terms and durations, rather than
through the use of derivative instruments. Please read
Factors that Impact our Business for more
information about our long-term coal sales contracts.
89
We believe that the price risk associated with diesel fuel is
significant because of possible price volatility. Taking into
account full or partial diesel fuel cost pass through provisions
in our long-term coal sales contracts and our fixed price
forward contracts for delivery of diesel fuel, we estimate that
a hypothetical increase of $0.10 per gallon for diesel fuel
would have reduced net income attributable to our unitholders
for the year ended December 31, 2009 by $0.3 million.
Interest
Rate Risk
We have exposure to changes in interest rates on our
indebtedness associated with our credit facility. On
September 11, 2009, we entered into an interest rate cap
agreement to hedge our exposure to rising interest rates during
2010. This agreement, which has an effective date of
January 4, 2010 and a notional amount of
$50.0 million, provides for a LIBOR interest rate cap of 2%
using three-month LIBOR. LIBOR was 0.251% as of
December 31, 2009. We paid a fixed fee of $85,000 for this
agreement which has quarterly settlement dates and matures on
December 31, 2010. At December 31, 2009, the value of
the interest rate cap is $34,000 and is recorded in other assets
and the
mark-to-market
decrease in value of $51,000 was recorded to interest expense in
our consolidated statement of operations for the year ended
December 31, 2009.
A hypothetical increase or decrease in interest rates by 1%
would have changed our interest expense by $0.3 million for
the year ended December 31, 2009, which reflects the impact
of an interest rate swap that terminated in August 2009.
Seasonality
Our business has historically experienced only limited
variability in its results due to the effect of seasons. Demand
for coal-fired power can increase due to unusually hot or cold
weather as power consumers use more air conditioning or heating.
Conversely, mild weather can result in softer demand for our
coal. Adverse weather conditions, such as blizzards or floods,
can impact our ability to mine and ship our coal and our
customers ability to take delivery of coal.
90
THE COAL
INDUSTRY
Introduction
Coal is an abundant natural resource that is used primarily as
an efficient and affordable fuel for the generation of electric
power. According to the most recent estimate of the EIA, there
are approximately 929.3 billion tons of worldwide
recoverable coal reserves. Approximately 262.7 billion
tons, or 28.3%, of those reserves are located in the United
States, more than in any other country. U.S. coal reserves
represent over 200 years of domestic supply based on
current production rates. Coal is also the most abundant
domestic fossil fuel, accounting for approximately 94% of the
nations fossil energy reserves.
Coal is ranked by heat content, with bituminous,
sub-bituminous
and lignite coal representing the highest to lowest heat
ranking, respectively. Coal is also categorized as either steam
coal or metallurgical coal. Steam coal is used by utilities and
independent power producers to generate electricity and
metallurgical coal is used by steel companies to produce
metallurgical coke for use in blast furnaces. Steam coal
comprises the vast majority of total coal resources, accounting
for approximately 87% and 95% of the total global and
U.S. coal production, respectively. Please read
Special Note Regarding the EIAs Market
Data and Projections below.
Industry
Trends
Coal consumption and production in the United States have been
driven in recent periods by several market dynamics and trends.
The recent global economic downturn has negatively impacted coal
demand in the short-term, but long-term projections for coal
demand remain positive. These market dynamics and trends include
the following:
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Favorable long-term outlook for U.S. steam coal
market
. Although domestic coal consumption
declined in 2009 due to the global economic downturn, the EIA
forecasts that domestic coal consumption will increase by 14.4%
through 2015 and by 32.2% through 2035, primarily due to the
projected continued growth in coal-fired electric power
generation demand. The EIA also forecasts that coal-fired
electric power generation will increase by 13.0% through 2015
and by 27.0% through 2035, with coal remaining the dominant fuel
source in the future.
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Increasing demand for coal produced in Northern Appalachia
and the Illinois Basin.
Coal production in
Northern Appalachia and, to a greater extent the Illinois Basin
began to decline after the adoption of the CAAA, which among
other things, limited sulfur dioxide emissions from coal-fired
electric power plants. According to the EIA, coal production in
Northern Appalachia and the Illinois Basin is expected to grow
by 29.2% and 33.1%, respectively, through 2015 and by 35.7% and
42.8%, respectively, through 2035. We believe that this
projected increase will be driven by a combination of the
continued decline in coal production in Central Appalachia and
the new scrubber installations at coal-fired power plants in our
primary market area. According to public announcements,
approximately 18,400 megawatts of additional scrubbed generating
capacity are expected to come online in our primary market area
by 2017, including 4,750 megawatts in Ohio in the next three
years.
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Decline in coal production in Central
Appalachia.
Although Central Appalachia is
currently the nations second largest coal production area
after the PRB, the EIA forecasts that coal production in Central
Appalachia will decline by 34.5% through 2015 and by 54.1%
through 2035. This decline will be offset by production from
other U.S. regions, including Northern Appalachia and the
Illinois Basin. The combination of reserve depletion and
increasing regulatory enforcement, mining costs and geologic
complexity in Central Appalachia is expected to lead to
substantial production declines over the long term.
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Expected near-term increases in international demand for
U.S. coal exports
. Although down from the
previous year, U.S. exports began to increase in the second
half of 2009, supported by recovering global economies and
continued rapid growth in electric power generation and steel
production
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91
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capacity in Asia, particularly in China and India. In addition,
traditional coal exporting countries such as Australia,
Indonesia, Colombia and South Africa have been unable to
increase exports rapidly enough for a variety of reasons,
including geologic and logistical issues and increased domestic
consumption. Furthermore, increased international demand for
higher priced metallurgical coal has resulted in certain coal
from Central Appalachia and Northern Appalachia, which can serve
as either metallurgical or steam coal, being drawn into the
metallurgical coal export market, which further reduces supplies
of steam coal from this region for domestic consumption. Because
of these trends, the United States is expected to continue to be
an increasingly important swing supplier of coal to the global
marketplace in the near term.
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Development of new coal-related technologies will lead to
increased demand for coal
. The EIA projects that
new
coal-to-liquids
plants will account for 32 million tons of annual coal
demand in ten years with that amount more than doubling to
68 million tons by 2035. In addition, through the ARRA the
federal government has targeted over $1.5 billion to CCS
research and another $800 million for the Clean Coal Power
Initiative, a ten-year program supporting commercial application
of CCS technology.
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Increasingly stringent air quality legislation will continue
to impact the demand for coal.
A series of more
stringent requirements related to particulate matter, ozone,
mercury, sulfur dioxide, nitrogen oxides, carbon dioxide and
other air emissions have been proposed or enacted by federal or
state regulatory authorities in recent years. Considerable
uncertainty is associated with these air quality regulations,
some of which have been the subject of legal challenges in
courts, and the actual timing of implementation remains
uncertain. However, we believe that it is likely that additional
air quality regulations ultimately will be adopted in some form
at the federal or state level. While it is currently not
possible to determine the impact of any such regulatory
initiatives on future demand for coal, it may be materially
adverse. See Risk Factors Risks Related to Our
Business Existing and future regulatory requirements
relating to sulfur dioxide and other air emissions could affect
our customers and could reduce the demand for the high-sulfur
coal we produce and cause coal prices and sales of our
high-sulfur coal to decline materially.
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Coal
Consumption and Demand
The majority of coal consumed in the United States is used to
generate electricity, with the balance used by a variety of
industrial users to heat and power foundries, cement plants,
paper mills, chemical plants and other manufacturing and
processing facilities. Metallurgical coal is predominately
consumed in the production of metallurgical coke used in
steelmaking blast furnaces. In 2009, coal-fired power plants
produced approximately 45% of all electric power generation,
more than natural gas and nuclear, the two next largest domestic
fuel sources, combined. Steam coal used by utilities and
independent power producers to generate electricity, accounted
for 92% of total coal consumption in 2009.
In 2009, total coal consumption in the United States decreased
by approximately 11% from 2008 levels, reflecting the effects of
the economic recession. The drop in coal consumption was driven
primarily by the reduction in electric power demand and the
steep decline in natural gas prices that encouraged coal to
natural gas switching among electric utilities. The decreased
electric power demand was particularly apparent in the
industrial sector where demand fell by an estimated 18.3% in
2009. Unusually cool summer temperatures in some areas of the
country where coal is the predominant source of electric power
generation also resulted in lower coal consumption.
Going forward, the EIA forecasts that total U.S. coal
consumption will increase in 2010 by over 3% due to anticipated
increases in electricity demand resulting from increased
economic activity and higher natural gas prices. In addition,
over the long term, the EIA forecasts in its 2010 reference case
that total coal consumption will grow by 14% though 2015 and 32%
through 2035, primarily due to gradual increases in coal-fired
electric power generation and the introduction of
coal-to-liquids
plants.
92
The following table sets forth actual coal consumption for 2008,
estimated consumption for 2009 and 2010 and the EIAs
projected coal consumption by sector through 2035 for the
periods indicated.
U.S. Coal
Consumption by Sector
(tons in millions)
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Total
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Total
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Actual
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Estimate
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Estimate
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Forecast
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Growth
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Forecast
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Growth
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2008
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2009
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2010
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2015
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2009-2015
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2035
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2009-2035
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Electric Power
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1,042
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934
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961
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1,044
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11.7
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%
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1,183
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26.7
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%
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Other Industrial
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54
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44
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43
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54
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19.1
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%
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51
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14.6
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%
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Coke Plants
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22
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16
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22
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20
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28.2
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%
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14
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(10.3
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)%
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Residential/ Commercial
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4
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3
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3
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3
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%
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3
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%
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Coal-to-Liquids
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20
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n/m
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68
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n/m
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Total U.S. Consumption
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1,122
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997
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1,029
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1,141
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14.4
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%
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1,319
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32.2
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%
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Source: EIA.
In the United States, the reliance on coal-fired generation is
attributable to the abundance and low cost of coal. According to
the EIA, coal is expected to remain the dominant energy source
for electric power generation for the foreseeable future.
U.S.
Scrubber Market
The CAAA imposed increasingly stringent regulations regarding
the emissions of sulfur dioxide and nitrogen oxides. In response
to these regulations, emission control technologies such as flue
gas desulfurizers, also known as scrubbers, were developed to
reduce emissions of sulfur dioxide. The use of scrubbers has
addressed a wide array of technological and economic challenges
and has become the predominant sulfur dioxide emissions control
technology used by U.S. coal-fired power plants. Scrubbers
have the additional benefit of being able to reduce mercury
emissions. This widespread installation of scrubbers is expected
to significantly increase demand for higher sulfur coal,
particularly in our primary market area.
Nationwide, there are currently over 148,000 megawatts of
scrubbed electric generating capacity, including 18,900
megawatts that were added in 2009. According to public
announcements, we expect 76,200 megawatts of additional scrubbed
electric generating capacity to be added by 2017. Currently, in
our primary market area there are over 54,500 megawatts of
scrubbed electric generating capacity. According to public
announcements, we expect approximately 18,400 megawatts of
additional scrubbed electric generating capacity in our primary
market area to come online by 2017, including 4,750 megawatts in
Ohio in the next three years. This additional scrubbed capacity
represents approximately 24% of the total scrubbed capacity to
be added nationwide during that period.
The following map of the United States shows coal-fired power
plants with existing or announced scrubbers:
[Map to come]
Coal
Consumption in Our Primary Market Area
Coal is the dominant fuel source for electric power generation
in our primary market area and is expected to remain so for the
foreseeable future. As shown in the table below, 69.1% of the
electricity in our market area is generated by coal-fired power
plants as compared to 38.2% for the rest of the United States.
In addition, approximately 27.7% of coal consumption nationwide
is burned by coal-fired power plants in our primary market area.
93
2009
Coal-Fired Electricity Generation
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Total
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Electricity
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Coal-Fired Electricity
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Generation
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Generation
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GWh
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GWh
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% of total
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Ohio
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135,949
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113,824
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83.7
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%
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Indiana
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116,668
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108,591
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93.1
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%
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Pennsylvania
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218,377
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104,927
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48.0
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%
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Illinois
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193,214
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90,949
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47.1
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%
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Kentucky
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90,988
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84,380
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92.7
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%
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West Virginia
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70,774
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68,136
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96.3
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%
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Total Our Primary Market Area
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825,970
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570,807
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69.1
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%
|
Total Rest of United States
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3,125,137
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|
1,193,679
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38.2
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%
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|
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Total United States
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3,951,107
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1,764,486
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44.7
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%
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Source: EIA.
U.S. Coal
Production
Estimated total U.S. coal production in 2009 was
1.1 billion tons, a decrease of 7.7% from 2008. This
decrease is due to the global economic downturn, which
significantly reduced domestic demand for coal-fired electric
power and led to a decline in exports. The EIA has forecasted a
6.7% increase in coal production through 2015 and an 18.7%
increase through to 2035.
The following table sets forth historical and forcasted
production statistics in each of the major U.S. coal
producing regions for the periods indicated based on the
EIAs data and projections.
U.S. Coal
Production
Coal
Producing Regions
Coal is mined in over half of the states in the United States,
but domestic coal production is primarily attributed to one of
three coal producing regions: Appalachia, the Interior and the
Western region. Within those three regions, the major producing
centers are Northern and Central Appalachia, the Illinois Basin
in the Interior region and the PRB in the Western region. The
type, quality and characteristics of coal vary by, and within
each, region.
94
Northern Appalachia.
Northern Appalachia
includes Ohio, Pennsylvania, Maryland and northern West
Virginia. The area includes reserves of bituminous coal with
mid-to-high
heat content (generally ranging from 10,300 to
13,000 Btu/lb) and
mid-to-high
sulfur content (typically ranging from 1.0% to 4.0%). Coal
produced in Northern Appalachia is marketed primarily to
electric utilities, industrial consumers and the export market,
with some metallurgical coal marketed to steelmakers. The
widespread installation of scrubbers by electric utilities is
expected to significantly increase demand for high-sulfur coal
from Northern Appalachia, providing a positive outlook for the
area.
Estimated coal production in Northern Appalachia for 2009 was
121.5 million tons, a decline of 10.5% from 2008. In 2010,
the EIA forecasts that coal production in Northern Appalachia
will increase slightly to 122.1 million tons. The EIA
forecasts that coal production in Northern Appalachia will
increase by 29.2% through 2015 and by 35.7% through 2035.
Central Appalachia.
Central Appalachia
includes eastern Kentucky, southern West Virginia, Virginia and
northern Tennessee. The area includes reserves of bituminous
coal with a high heat content (typically
12,000 Btu/lb
or greater) and relatively low sulfur content (typically ranging
from 0.5% to 1.5%). Coal produced in Central Appalachia is
marketed primarily to electric utilities, with metallurgical
coal marketed to steelmakers. The combination of reserve
depletion and increasing regulatory enforcement, mining costs
and geologic complexity in Central Appalachia is expected to
lead to substantial production declines over the long term. In
addition, the widespread installation of scrubbers is expected
to enable higher sulfur coal from Northern Appalachia and the
Illinois Basin to replace coal from Central Appalachia.
Estimated coal production in Central Appalachia for 2009 was
215.5 million tons, a decline of 8.0% from 2008. In 2010,
the EIA estimates that production in Central Appalachia will
decline by another 13.9%. The EIA forecasts that coal
production in Central Appalachia will decline by 34.5% through
2015, causing total production in Central Appalachia to fall
below forecasted production levels for Northern Appalachia. The
EIA forecasts the coal production in Central Appalachia will
decline by more than half through 2015.
The following map of the United States shows domestic electric
generating plants that receive coal shipments from Central
Appalachia:
[Map to come]
Illinois Basin.
The Illinois Basin includes
western Kentucky, Illinois and Indiana. The area includes
reserves of bituminous coal with a mid-level heat content
(typically ranging from 10,100 to
12,600 Btu/lb)
and
mid-to-high
sulfur content (typically ranging from 1.0% to 4.3%). Illinois
Basin coal also can have high ash and chlorine content. Most of
the coal produced in the Illinois Basin is used to produce
electricity, with small amounts used in industrial applications.
The EIA forecasts that production of high sulfur coal in the
Illinois Basin, which has trended down since the early 1990s
when many coal-fired plants switched to lower sulfur coal to
reduce sulfur dioxide emissions after the passage of the CAAA,
will rebound as existing coal-fired capacity is retrofitted with
scrubbers and new coal-fired capacity with scrubbers is added.
In addition, planned
coal-to-liquids
facilities, which are backed by state support and incentives and
are indifferent to the sulfur content of coal, are poised to
become substantial new consumers of Illinois Basin coal.
Estimated coal production in the Illinois Basin was
93.4 million tons for 2009, a decrease of 5.9% from 2008.
In 2010, the EIA forecasts that coal production in the Illinois
Basin will increase slightly to 97.3 million tons. The EIA
forecasts that coal production in the Illinois Basin will
increase by 33.1% through 2015 and by 42.8% through 2035.
Powder River Basin.
The PRB is located in
Wyoming and Montana. In terms of production, the PRB is the
dominant coal producing region in the world, with its coal-seam
geology allowing for high volume, low cost surface mining. The
PRB produces
sub-bituminous
coal with low sulfur content (typically ranging from 0.2% to
0.9%) and low level heat content (typically ranging from 8,000
to 9,500 Btu). After strong growth in production over the
past 20 years, growth in demand for PRB coal is expected to
moderate in the future due to the slowing demand for low sulfur,
low Btu coal as scrubbers proliferate and concerns about
increases in rail transportation rates and rising operating
costs grow.
95
Estimated coal production in the PRB was 417.7 million tons
for 2009, a decrease of 7.5% from 2008. In 2010, the EIA
forecasts that coal production in the PRB will increase to
434.9 million tons. The EIA forecasts that coal production
in the PRB will increase by 12.6% through 2015 and by 31.9%
through 2035.
Coal
Imports and Exports
Almost all of the coal consumed in the United States is produced
from domestic sources. Coal imports represent a small portion of
domestic coal consumption, averaging only about 2% of total
U.S. coal consumption. Coal is imported into the United
States primarily from Colombia, Indonesia and Venezuela.
Imported coal generally serves coastal states along the Gulf of
Mexico and the eastern seaboard. We do not expect U.S. coal
imports to increase significantly in the near term due to rising
demand in Asia and infrastructure limitations in the United
States.
Although down from the previous year, U.S. exports began to
increase in the second half of 2009, supported by recovering
global economies and continued rapid growth in electric power
generation and steel production capacity in Asia, particularly
in China and India. In addition, traditional coal exporting
countries such as Australia, Indonesia, Colombia and South
Africa have been unable to increase exports rapidly enough for a
variety of reasons, including geologic and logistical issues and
increased domestic consumption. Furthermore, increased
international demand for higher priced metallurgical coal has
resulted in certain coal from Central Appalachia and Northern
Appalachia, which can serve as either metallurgical or steam
coal, being drawn into the metallurgical coal export market,
which further reduces supplies of steam coal from this region
for domestic consumption. Because of these trends, the United
States is expected to continue to be an increasingly important
swing supplier of coal to the global marketplace in the near
term.
Coal
Mining Methods
Coal is mined using two primary methods, underground mining and
surface mining.
Surface
Mining
Surface mining is generally used when coal is found relatively
close to the surface, when multiple seams in close vertical
proximity are being mined or when conditions otherwise warrant.
Surface mining involves removing the overburden (earth and rock
covering the coal) with heavy earth moving equipment and
explosives, loading out the coal, replacing the overburden and
topsoil after the coal has been excavated and reestablishing
vegetation and plant life. There are four primary surface mining
methods in use in Northern Appalachia and the Illinois Basin:
area, contour, auger and highwall.
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Area Mining.
Area mining removes coal from
broad areas where the land is relatively flat. An initial cut of
overburden is removed and placed in a location that will
facilitate final reclamation. After the coal is removed from the
initial cut, a second cut of overburden is removed and placed in
the initial cut, exposing the coal for removal in the second
mine cut. This process is repeated until the mining cuts have
advanced through the reserve area.
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Contour Mining.
Contour mining removes coal
from more hilly terrain. Contour mining is characterized by mine
cuts that follow the contour of the hill and are generally
smaller than the mine cuts common in area mining. A wedge of
overburden is removed along the coal outcrop on the side of a
hill, forming a bench at the level of the coal. After the coal
is removed, overburden from subsequent mine cuts is placed back
on the bench to return the hill to its natural slope.
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Auger Mining.
Auger mining recovers coal that
is uneconomic to mine by the area and contour mining methods due
to the large amount of overburden overlying the coal. The auger
is placed at the exposed coal face and bores into the coal seam.
Pillars of undisturbed coal are left in place to support the
overlying overburden.
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Highwall Mining.
Highwall mining is similar to
auger mining. A highwall miner consists of a launch vehicle,
push beams and a continuous miner head. This system utilizes the
continuous miner
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96
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to cut into the exposed coal face. The push beams contain augers
or conveyor belts that transport the coal back to the launch
vehicle as the continuous miner advances. The launch vehicle
applies hydraulic pressure on the push beams to push the
continuous miner against the face as it advances into the coal
seam. As in the auger mining method, pillars of undisturbed coal
are left in place to support the overburden. Both the auger and
highwall mining methods allow recovery of coal that would
otherwise have been lost due to the depth of the coal seam below
the surface.
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Surface mining produces the majority of U.S. coal output,
accounting for nearly 70% of U.S. production in 2009, with
large surface mines (mines producing greater than
10 million tons per annum) contributing over 40% of the
total. Productivity for surface mines in the eastern United
States in 2009 averaged 3.64 tons per employee per hour.
Underground
Mining
Underground mining is generally used when the coal seam is too
deep to permit surface mining. There are two principal
underground mining methods: room and pillar and longwall.
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Room and Pillar Mining.
In room and pillar
mining, rooms are cut into the coal bed leaving a series of
pillars, or columns of coal, to help support the mine roof and
control the flow of air. Continuous mining equipment is used to
cut the coal from the mining face. The room and pillar method is
often used to mine smaller coal blocks or thin seams.
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Longwall Mining.
The other underground mining
method commonly used in the United States is the longwall mining
method. In longwall mining, a rotating drum is trammed
mechanically across the face of coal, and a hydraulic system
supports the roof of the mine while it advances through the
coal. Chain conveyors then move the loosened coal to an
underground mine conveyor system for delivery to the surface.
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Productivity for underground mines in the eastern United States
in 2009 averaged 3.02 tons per employee per hour.
Coal
Quality Characteristics
Coal quality is differentiated primarily by its heat content as
measured in British thermal units per pound (Btu/lb). In
general, coal with low moisture and ash content has high heat
content. Coal with higher heat content commands higher prices
because less coal is needed to generate a given quantity of
electric power.
Coal quality is also differentiated by sulfur content. When coal
is burned sulfur dioxide and other air emissions are released.
Sub-bituminous
coal (e.g. PRB coal) typically has lower sulfur content than
bituminous coal. Coal in southern West Virginia, eastern
Kentucky, Colorado and Utah, however, also generally has low
sulfur content. A coals sulfur content can be further
classified as compliance or non-compliance. Compliance coal is a
term used in the United States to describe coal that, when
burned, emits less than 1.2 lbs of sulfur dioxide per million
Btu and complies with the requirements of the CAAA without the
use of scrubbers. The primary reserves of compliance coal are
found in both the PRB and Central Appalachia.
High sulfur coal can be burned in electric utility plants
equipped with sulfur-reduction technology, such as scrubbers,
which can reduce sulfur dioxide emissions by more than 90%.
Plants without scrubbers can burn high sulfur coal by blending
it with lower sulfur coal, or by purchasing emission allowances
on the open market.
Coal ash and chlorine content also can influence the
marketability of a particular coal. Ash is the inorganic residue
remaining after the combustion of coal. As with sulfur content,
ash content varies from seam to seam. Ash content is also an
important characteristic of coal because electric generating
plants must handle and dispose of ash following combustion. The
chlorine content of coal is important to generating station
operators since high levels can adversely impact boiler
performance directly by both high and low temperature corrosion
and indirectly by reacting with other coal impurities to cause
ash fouling. Coal found in the central
97
Illinois Basin (primarily within the state of Illinois)
typically exhibits higher chlorine concentrations than the coal
found in western Kentucky and Indiana.
Transportation
The U.S. coal industry is dependent on the availability of
a consistent and responsive transportation network connecting
the various supply regions to the domestic and international
markets. Railroads and barges comprise the foundation of the
domestic coal distribution system, collectively handling about
three-quarters of all coal shipments. Truck and conveyor systems
typically move coal over shorter distances.
Although the purchaser typically pays the freight,
transportation costs are still important to coal mining
companies because the purchaser may choose a supplier largely
based on the total delivered cost of coal, which includes the
cost of transportation. Coal used for domestic consumption is
generally sold
free-on-board
at the mine, or FOB mine, which means the purchaser normally
bears the transportation costs. Transportation can be a large
component of a purchasers total cost.
While coal can sometimes be moved by one transportation method
to market, it is common for two or more modes to be used to ship
coal (i.e., inter-modal movements). The method of transportation
and the delivery distance greatly impact the total cost of coal
delivered to the consumer.
Special
Note Regarding the EIAs Market Data and
Projections
Coal industry market data and projections referred to in this
section and elsewhere in this prospectus and prepared by the EIA
reflect statements of what might happen in the coal industry
given the assumptions and methodologies used by the EIA.
Industry projections of the EIA are subject to numerous
assumptions and methodologies chosen by the EIA. In addition,
these projections assume that the laws and regulations in effect
at the time of the projections remain unchanged and that no
pending or proposed federal or state carbon emissions
legislation has been enacted and that additional coal-fired
power plants will be built during the period. Therefore, the
EIAs projections do not take into account potential
regulation of greenhouse gas emissions pursuant to proposed or
future U.S. treaty obligations, statutory or regulatory
changes under the Clean Air Act, or federal or additional state
adoption of a greenhouse gas regulatory scheme or reductions in
greenhouse gas emissions mandated by courts or through other
legally enforceable mechanisms. The EIAs projections with
respect to the demand for coal may not be met, absent other
factors, if comprehensive carbon emissions legislation is
enacted. In addition, these projections may assume certain
general economic conditions or industry conditions and commodity
prices for alternative energy sources at the time of the
projection that may or may not reflect actual economic or
industry conditions during the forecast period, including with
respect to planned and unplanned additional electricity
generating capacity. The economic conditions accounted for in
the EIAs industry projections reflect existing and
projected economic conditions at the time the projections were
made and do not necessarily reflect current economic conditions
or any subsequent deterioration of economic conditions. Actual
results may differ from those results projected by the EIA,
including projections related to the demand for additional
electricity generating capacity, because of changes in economic
conditions, laws or regulations, pricing for other energy
sources, unanticipated production cuts, or because of other
factors not anticipated in the EIAs projections.
98
BUSINESS
Overview
We are a low cost producer of high value steam coal, and we are
the largest producer of surface mined coal in Ohio. We focus on
acquiring steam coal reserves that we can efficiently mine with
our modern, large scale equipment. Our reserves and operations
are strategically located in Northern Appalachia and the
Illinois Basin to serve our primary market area of Illinois,
Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. We
market our coal primarily to large utilities with coal-fired,
base-load scrubbed power plants under long-term coal sales
contracts. We believe that we will experience increased demand
for our high-sulfur coal from power plants that have or will
install scrubbers. Currently, there is over 54,500 megawatts of
scrubbed base-load electric generating capacity in our primary
market area and plans have been announced to add over 18,400
megawatts of additional scrubbed capacity by the end of 2017. We
also believe that we will experience increased demand for our
coal from power plants that use coal from Central Appalachia as
production in that region continues to decline.
We currently have 19 active surface mines that are managed as
eight mining complexes. During the fourth quarter of 2009, our
largest mine represented 12.5% of our coal production. This
diversity reduces the risk that operational issues at any one
mine will have a material impact on our business or our results
of operations. Consistent coal quality across many of our mines
and the mobility of our equipment fleet allows us to reliably
serve our customers from multiple mining complexes while
optimizing our mining plan. Our operations also include two
river terminals, strategically located in eastern Ohio and
western Kentucky, that further enhance our ability to supply
coal to our customers with river access from multiple mines.
We produced 5.8 million tons of coal during 2009, including
0.4 million tons produced from the reserves we acquired in
western Kentucky from Phoenix Coal on September 30, 2009.
As a result of this acquisition, our coal production during the
fourth quarter of 2009 was 1.8 million tons, or
7.2 million tons on an annualized basis. During 2009, we
sold 6.3 million tons of coal, including 0.5 million
tons of purchased coal. We currently have long-term coal sales
contracts in place for 2010, 2011, 2012 and 2013 that represent
97.2%, 93.0%, 71.4% and 39.7%, respectively, of our 2010
estimated coal sales of 8.5 million tons. Members of our
senior management team have long-standing relationships within
our industry, and we believe those relationships will allow us
to continue to obtain long-term contracts for our coal
production that will continue to provide us with a reliable and
stable revenue base.
As of December 31, 2009, we controlled 91.6 million
tons of proven and probable coal reserves, of which
68.6 million tons were associated with our surface mining
operations and the remaining 23.0 million tons consisted of
underground coal reserves that we have subleased to a third
party in exchange for an overriding royalty. Historically, we
have been successful at replacing the reserves depleted by our
annual production and growing our reserve base by acquiring
reserves with low operational, geologic and regulatory risks and
that were located near our mining operations or that otherwise
had the potential to serve our primary market area. Over the
last five years, we have produced 23.6 million tons of coal
and acquired 52.9 million tons of proven and probable coal
reserves, including 24.6 million tons of coal reserves that
we acquired in connection with the Phoenix Coal acquisition. We
believe that our existing relationships with owners of large
reserve blocks and our position as the largest producer of
surface mined coal in Ohio will allow us to continue to acquire
reserves in the future.
For the year ended December 31, 2009, we generated revenues
of approximately $293.8 million, net income attributable to
our unitholders of approximately $23.5 million and Adjusted
EBITDA of approximately $50.8 million. Please read
Selected Historical and Pro Forma Consolidated Financial
and Operating Data for our definition of Adjusted EBITDA
and a reconciliation of Adjusted EBITDA to net income (loss)
attributable
99
to our unitholders. The following table summarizes our mining
complexes, our coal production for the year ended
December 31, 2009 and our coal reserves as of
December 31, 2009:
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Production for
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As of December 31, 2009
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the Year Ended
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Proven &
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Average
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Average
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Primary
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December 31,
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Probable
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Heat
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Sulfur
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Transportation
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Mining Complexes
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2009
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Reserves
(1)
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Value
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Content
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Methods
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(in million tons)
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(Btu/lb)
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(%)
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Surface Mining Operations:
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Northern Appalachia (principally Ohio)
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Cadiz
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1.1
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12.4
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11,520
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3.3
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Barge, Rail
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Tuscarawas County
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0.9
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8.8
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11,570
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3.7
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Truck
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Belmont County
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1.3
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6.6
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11,510
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3.7
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Barge
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Plainfield
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0.5
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6.4
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11,350
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4.4
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Truck
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New Lexington
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0.6
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4.9
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11,260
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4.0
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Rail
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Harrison
(2)
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0.7
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2.8
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12,040
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1.8
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Barge, Rail, Truck
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Noble County
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0.3
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2.5
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11,230
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4.7
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Barge, Truck
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Illinois Basin (Kentucky)
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Muhlenberg
County
(3)
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0.4
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24.2
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11,295
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3.6
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Barge, Truck
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Total Surface Mining Operations
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5.8
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68.6
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Underground Coal Reserves:
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Northern Appalachia (Ohio)
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Tusky
(4)
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23.0
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12,900
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2.1
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Total Underground Coal Reserves
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23.0
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Total
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91.6
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(1)
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Reported as recoverable coal reserves, which is the portion of
the coal that could be economically and legally extracted or
produced at the time of the reserve determination, taking into
account mining recovery and preparation plant yield. For
definitions of proven coal reserves, probable coal reserves and
recoverable coal reserves, please read Coal
Reserves.
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(2)
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The Harrison mining complex is owned by Harrison Resources, our
joint venture with CONSOL Energy. We own 51% of Harrison
Resources and CONSOL Energy owns the remaining 49% through one
of its subsidiaries. Because the results of operations of
Harrison Resources are included in our consolidated financial
statements for the year ended December 31, 2009 as required
by GAAP, coal production and proven and probable coal reserves
attributable to the Harrison mining complex are presented on a
gross basis assuming we owned 100% of Harrison Resources. Please
read Mining Operations Northern
Appalachia Harrison Mining Complex.
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(3)
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Acquired from Phoenix Coal on September 30, 2009. As a
result, production data represents production from the date of
acquisition though December 31, 2009.
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(4)
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Please read Coal Reserves
Underground Coal Reserves for more information about our
underground coal reserves at the Tusky mining complex, which we
have subleased to a third party in exchange for an overriding
royalty. During 2009, we received royalty payments on
0.6 million tons of coal produced from the Tusky mining
complex.
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100
[Map to
come]
Business
Strategies
Our primary business objective is to maintain and, over time,
increase our cash available for distribution by executing the
following strategies:
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Increasing coal sales to large utilities with coal-fired,
base-load scrubbed power plants in our primary market
area.
In 2009, approximately 69% of the total
electricity generated in our primary market area was generated
by coal-fired power plants, compared to approximately 38% for
the rest of the United States. We intend to continue to focus on
marketing coal to large utilities with coal-fired, base-load
scrubbed power plants in our primary market area of Illinois,
Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. We
believe that we will experience increased demand for our
high-sulfur coal from power plants that have or will install
scrubbers. Currently, there is over 54,500 megawatts of scrubbed
base-load electric generating capacity in our primary market
area and plans have been announced to add over 18,400 megawatts
of additional scrubbed capacity by the end of 2017. We also
believe that we will experience increased demand for our coal
from power plants that use coal from Central Appalachia as
production in that region continues to decline.
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Maximizing profitability by maintaining highly efficient,
diverse and low cost surface mining
operations
. We intend to focus on lowering costs
and improving the productivity of our operations. We utilize
surface mining methods that allow us to leverage our large scale
mobile equipment and experienced work force to minimize our
mining costs while balancing our production with near-term coal
sales commitments without incurring large start up costs. We
believe our focus on efficient surface mining practices results
in our cash costs being among the lowest of our peers in
Northern Appalachia, which we believe will allow us to compete
effectively, especially during periods of declining coal prices.
We are in the process of implementing the same mining practices
that we currently use in Ohio at the mines that we recently
acquired as part of the Phoenix Coal acquisition. We currently
have 19 active surface mines that are managed as eight mining
complexes, with our largest mine comprising 12.5% of our coal
production during the fourth quarter of 2009. This diversity and
focus on reserves with low regulatory risks reduce the
likelihood that operational or permitting issues at any one mine
will have a material impact on our business or our results of
operations.
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Generating stable revenue by entering into long-term coal
sales contracts
. We intend to continue to enter
into long-term coal sales contracts for substantially all of our
annual coal production, which will reduce our exposure to
fluctuations in the market prices. We believe our senior
managements longstanding relationships within our industry
will allow us to continue to obtain long-term contracts for
substantially all of our production. We believe our long-term
coal sales contracts provide us with a reliable and stable
revenue base, and we intend to seek cost pass through or
inflation adjustment provisions in our long-term coal sales
contracts to mitigate our exposure to rising costs.
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Continuing to grow our reserve base and production
capacity
. We intend to continue to grow our
reserve base by acquiring reserves with low operational,
geologic and regulatory risks that we can mine economically and
that are located near our mining operations or otherwise have
the potential to serve our primary market area. We are focused
primarily on acquisitions that are consistent with our target
customer base in terms of location and coal quality. We believe
this strategy will allow us to expand our presence in our
primary market area, target new customers and increase our
annual coal production. We believe that our existing
relationships with owners of large reserve blocks and our
position as the largest producer of surfaced mined coal in Ohio
will allow us to acquire additional reserves in the future. We
intend to continue to grow our production capacity by expanding
our fleet of large scale equipment and opening new mines as our
sales commitments increase over time.
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101
Competitive
Strengths
We believe the following competitive strengths will enable us to
execute our business strategies successfully:
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We have an attractive portfolio of long-term coal sales
contracts
. We believe our long-term coal sales
contracts provide us with a reliable and stable revenue base. We
currently have long-term coal sales contracts in place for 2010,
2011, 2012 and 2013 that represent 97.2%, 93.0%, 71.4% and
39.7%, respectively, of our 2010 estimated coal sales of
8.5 million tons. A majority of our estimated annual coal
production for 2010 will be delivered to utilities that are
investment grade. Our long-term coal sales contracts typically
contain full or partial cost pass through or inflation
adjustment provisions that provide some protection in rising
operating cost environments. Members of our senior management
team have long-standing relationships within our industry, and
we believe those relationships will allow us to continue to
obtain long-term contracts for substantially all of our
production.
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We have a successful history of growing our reserve base and
production capacity
. Historically, we have been
successful at replacing the reserves depleted by our annual
production and growing our reserve base by acquiring reserves
with low operational, geologic and regulatory risks and that are
located near our mining operations or that otherwise have the
potential to serve our primary market area. We have also been
successful in growing our production capacity by expanding our
fleet of large scale equipment and opening new mines to meet our
sales commitments. Over the last five years, we have produced
23.6 million tons of coal and acquired 52.9 million
tons of proven and probable coal reserves, including
24.6 million tons of coal reserves that we acquired in
connection with the Phoenix Coal acquisition. As a result of the
Phoenix Coal acquisition and production increases in Ohio, our
coal production for the fourth quarter of 2009 on an annualized
basis was 7.2 million tons, an increase of 41% over our
actual 2008 production.
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Our mining operations are flexible and
diverse
. During the fourth quarter of 2009, our
largest mine represented 12.5% of our coal production. We
currently have 19 active surface mines that are managed as eight
mining complexes. This diversity reduces the risk that
operational or production issues at any one mine will have a
material impact on our business or our results of operations.
Consistent coal quality across many of our mines and the
mobility of our equipment fleet allows us to reliably serve our
customers from multiple mining complexes while optimizing our
mining plan. Additionally, we have the flexibility to add mining
hours to our work week, which allows us to respond to increasing
customer demand and to compensate for unexpected disruptions at
any one mine by increasing the production at other mines. Our
operations also include two river terminals, strategically
located in eastern Ohio and western Kentucky, that enhance our
ability to supply coal to our customers with river access from
multiple mines. Our river terminals also give us access to power
plants in our primary market area that receive coal by barge,
which is the lowest cost coal transportation alternative.
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We are a low cost producer of coal
. We use
efficient mining practices that take advantage of economies of
scale and reduce operating costs per ton. For example, in
Northern Appalachia we operate some of the largest mobile
equipment in use east of the Mississippi River. The productive
capacity of this equipment helps us to maintain low overburden
removal costs and allows us to mine coal reserves that are not
efficiently mineable with smaller equipment. Our use of large
scale equipment, our good labor relations with our non-union
workforce, our employees expertise and knowledge of our
mining practices, our low level of legacy liabilities and our
history of acquiring reserves without large up-front capital
investments have positioned us as one of the lowest cash cost
coal producers in Northern Appalachia. In addition, we are in
the process of deploying the same mining practices that we
currently use in Ohio at the mines that we acquired as part of
the Phoenix Coal acquisition.
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Both production of, and demand for, the coal we produce are
expected to increase in our primary market
area
. According to the EIA, production of coal in
Northern Appalachia and the Illinois
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Basin is expected to increase by 29.2% and 33.1% through 2015,
respectively. This compares to an expected increase in total
coal production in the United States of 6.7% over the same
period. According to the EIA, this expected increase in coal
production in Northern Appalachia and the Illinois Basin is
attributable to anticipated increases in demand for high-sulfur
coal from scrubbed power plants. The EIA also forecasts
increased demand from consumers of Central Appalachia coal as
coal production in that region continues to decline.
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Our senior management team and key operational employees have
extensive industry experience
. The members of our
senior management team have, on average, 24 years of
experience in the coal industry and have a track record of
acquiring, building and operating businesses profitably and
safely. In addition, our key operational employees have
extensive mining experience and have been with us for an average
of 22 years. We believe our operational employees are one
of the key strengths to our business because their knowledge and
skills allow us to operate our mines in a safe and efficient
manner.
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We have a strong safety and environmental
record
. We operate some of the industrys
safest mines. Over the last four years, our MSHA reportable
incident rate was on average 14.4% lower than the rate for all
surface coal mines in the United States. In addition, we are
committed to maintaining a system that controls and reduces the
environmental impacts of mining operations. We have won numerous
awards for our strong safety and environmental record. In
January 2010, the West Virginia Coal Association awarded us
their Surface Mine North Award for our past reclamation efforts
in West Virginia. In addition, in 2008 the Appalachian Regional
Reforestation Initiative awarded us their Regional Award for
Excellence in Reforestation for exemplary performance using the
forestry reclamation approach for reclaiming coal mined lands.
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Our
History
We are a Delaware limited partnership that was formed in August
2007 by AIM and our founders, Charles C. Ungurean, the President
and Chief Executive Officer of our general partner and a member
of the board of directors of our general partner, and Thomas T.
Ungurean, the Senior Vice President, Equipment, Procurement and
Maintenance of our general partner. Each of our two founders has
over 37 years of experience in the coal mining industry. In
connection with our formation, our founders contributed all of
their interests in Oxford Mining Company to us.
Our founders formed Oxford Mining Company in 1985 to provide
contract mining services to a mining division of a major oil
company. In 1989, our founders transitioned Oxford Mining
Company from a contract miner into a producer of its own coal
reserves. In January 2007, Oxford Mining Company entered into a
joint venture, Harrison Resources, with a subsidiary of CONSOL
Energy to mine surface coal reserves purchased from CONSOL
Energy.
In September 2009, we completed the acquisition of Phoenix
Coals active surface mining operations. The Phoenix Coal
acquisition provided us with an entry into the Illinois Basin in
western Kentucky and included one mining complex comprised of
four mines as well as the Island river terminal on the Green
River in western Kentucky. In connection with this acquisition,
we increased our total proven and probable coal reserves by
24.6 million tons.
Our
Sponsors
AIM is a private investment firm specializing in natural
resources, infrastructure and real property. AIM, along with
certain of the funds that AIM advises, indirectly owns all of
the ownership interests in AIM Oxford. Certain directors of our
general partner are principals of AIM and have ownership
interests in AIM. After completion of this offering, AIM Oxford
will continue to hold 66.3% of the ownership interests in our
general partner and will hold % of
our common units and % of our
subordinated units ( % of our total
units).
103
C&T Coal is owned by our founders, Charles C. Ungurean and
Thomas T. Ungurean. After completion of this offering, C&T
Coal will continue to hold 33.7% of the ownership interests in
our general partner and will hold %
of our common units and % of our
subordinated units ( % of our total
units).
In connection with the contribution of Oxford Mining Company to
us in August 2007, C&T Coal, Charles C. Ungurean and Thomas
T. Ungurean agreed that they would not compete with us in the
coal mining business in Illinois, Kentucky, Ohio, Pennsylvania,
West Virginia and Virginia. This non-compete agreement is in
effect until August 24, 2014.
Mining
Operations
We currently have 19 active surface mines that are managed
as eight mining complexes. We define a mining complex as a group
of mines that are located in close proximity to each other or
that routinely sell coal to the same customer. Our
transportation facilities include two river terminals and two
rail loading facilities. Our mining facilities include two wash
plants, six blending facilities and nine crushing facilities.
Our surface mining operations use area, contour, auger and
highwall mining methods. Our area mining operations use
truck/shovel and truck/loader equipment fleets along with large
dozers. Our contour mining operations use truck/loader equipment
fleets and large dozers. We own and operate seven augers and
move these machines between mining complexes as needed. We
currently own and utilize one Superior highwall miner at our
Tuscarawas County mining complex, and a third party contractor
operates one Superior highwall miner at our Belmont County
mining complex. Both highwall miners are mobile and are moved
among our mining complexes as necessary.
In Northern Appalachia we operate large electric and hydraulic
shovels matched with a fleet of 240-ton haul trucks and 200-ton
haul trucks, which are some of the largest in use east of the
Mississippi River. We also deploy a fleet of over 65 large
Caterpillar D-11 and similar class dozers. We employ preventive
maintenance and rebuild programs to ensure that our equipment is
well-maintained. The rebuild programs are performed by
third-party contractors. We assess the equipment utilized in our
mining operations on an ongoing basis and replace it with new,
more efficient units on an as-needed basis.
Our transportation facilities include our Bellaire river
terminal that is located on the Ohio River in eastern Ohio, our
Cadiz rail loadout facility located on the Ohio Central Railroad
near Cadiz, Ohio, our New Lexington rail facility located on the
Ohio Central Railroad in Perry County, Ohio and our Island river
terminal and transloading facility located on the Green River in
western Kentucky. Our Bellaire river terminal, which is located
on the Ohio River in Bellaire, Ohio, has an annual throughput
capacity of over 4 million tons with a sustainable barge
loading rate of 2,000 tons per hour. The barge harbor for this
terminal can simultaneously hold up to 25 loaded barges and 30
empty barges. We control our Bellaire river terminal through a
long-term lease agreement with a third party, and we have
11 years remaining on this lease. We own our Island river
terminal and transloading facility that is located on the Green
River in western Kentucky. Our Island river terminal has an
annual throughput capacity of approximately 3 million tons
with a sustainable barge loading rate of 1,500 tons per hour.
Depending on coal quality and customer requirements, in most
cases our coal is crushed and shipped directly from our mines to
our customers. However, blending different types or grades of
coal may be required from time to time to meet the coal quality
and specifications of our customers. Coal of various sulfur and
ash contents can be mixed or blended to meet the
specific combustion and environmental needs of customers.
Blending is typically done at one of our six blending facilities:
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our Barb Tipple blending and coal crushing facility that is
adjacent to one of our customers power plants near
Coshocton, Ohio;
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our Strasburg wash plant near Strasburg, Ohio;
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our Bellaire river terminal on the Ohio River;
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our Island river terminal on the Green River in western Kentucky;
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our Stonecreek coal crushing facility located in Tuscarawas
County, Ohio; and
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our Schoate wash plant located in Muhlenberg County, Kentucky.
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[Map to come]
Northern
Appalachia
We operate seven surface mining complexes in Northern
Appalachia, substantially all of which are located in eastern
Ohio. For the year ended December 31, 2009, our mining
complexes in Northern Appalachia produced an aggregate of
5.4 million tons of steam coal. The following table
provides summary information regarding our mining complexes in
Northern Appalachia as of December 31, 2009:
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Number
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Tons Produced
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Transportation Facilities Utilized
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Transportation
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of Active
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for the Year Ended December 31,
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Mining Complex
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River Terminal
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Rail Loadout
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Method
(1)
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Mines
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2007
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2008
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2009
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(in millions)
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Cadiz
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Bellaire
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Cadiz
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Barge, Rail
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2
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1.1
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1.4
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1.1
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Tuscarawas County
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Truck
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4
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1.1
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1.0
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0.9
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Belmont County
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Bellaire
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Barge
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4
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0.8
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0.9
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1.3
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Plainfield
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Truck
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1
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0.3
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0.5
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0.5
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New Lexington
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New Lexington
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Rail
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1
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0.6
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0.7
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0.6
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Harrison
(2)
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Bellaire
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Cadiz
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Barge, Rail, Truck
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1
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0.2
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0.4
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0.7
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Noble County
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Bellaire
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Barge, Truck
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2
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0.2
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0.2
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0.3
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Total
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15
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4.3
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5.1
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5.4
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(1)
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Barge means transported by truck to our Bellaire river terminal
and then transported to the customer by barge. Rail means
transported by truck to a rail facility and then transported to
the customer by rail. Truck means transported to the customer by
truck.
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(2)
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The Harrison mining complex is owned by Harrison Resources, our
joint venture with CONSOL Energy. We own 51% of Harrison
Resources and CONSOL Energy owns the remaining 49% through one
of its subsidiaries. Because the results of operations of
Harrison Resources are included in our consolidated financial
statements for the year ended December 31, 2009 as required
by GAAP, coal production attributable to the Harrison mining
complex is presented on a gross basis assuming we owned 100% of
Harrison Resources. Please read Harrison
Mining Complex.
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Cadiz Mining Complex.
The Cadiz mining complex
is located in Harrison County, Ohio and includes reserves
located in Jefferson County, Ohio and Washington County,
Pennsylvania and consists of the Daron and County Road 29 mines.
We began our mining operations at this mining complex in 2000.
Operations at the Cadiz mining complex target the
Pittsburgh #8, Redstone #8A and Meigs Creek #9
coal seams. As of December 31, 2009, the Cadiz mining
complex included 12.4 million tons of proven and probable
coal reserves. The infrastructure at this mining complex
includes a coal crusher, a truck scale and the Cadiz rail
loadout. Coal produced from the Cadiz mining complex is trucked
either to our Bellaire river terminal on the Ohio River and then
transported by barge to the customer, or trucked to our Cadiz
rail loadout facility on the Ohio Central Railroad and then
transported by rail to the customer. This mining complex uses
area and auger methods of surface mining. This mining complex
produced 1.1 million tons of coal for the year ended
December 31, 2009.
Tuscarawas County Mining Complex.
The
Tuscarawas County mining complex is located in Tuscarawas,
Columbiana and Stark Counties, Ohio, and consists of the
Stonecreek, Stillwater, Chumney and Strasburg mines. We began
our mining operations at this mining complex in 2003. Operations
at this mining complex target the Brookville #4, Lower
Kittanning #5, Middle Kittanning #6, Upper
Freeport #7 and Mahoning #7A coal seams. As of
December 31, 2009, the Tuscarawas County mining complex
included 8.8 million tons of proven and probable coal
reserves. The infrastructure at this mining complex includes two
coal crushers with truck scales and the Strasburg wash plant.
Coal produced from the Tuscarawas County
105
mining complex is trucked directly to our customers, our Barb
Tipple blending and coal crushing facility or our Strasburg wash
plant. Coal trucked to our Barb Tipple blending and coal
crushing facility or our Strasburg wash plant is then
transported by truck to the customer after processing is
completed. This mining complex uses the area, contour, auger and
highwall miner methods of surface mining. This mining complex
produced 0.9 million tons of coal for the year ended
December 31, 2009.
Belmont County Mining Complex.
The Belmont
County mining complex is located in Belmont County, Ohio, and
consists of the Lafferty, Boswell, Flushing and Wheeling Valley
mines. We began our mining operations at this mining complex in
1999. Operations at the Belmont County mining complex target the
Pittsburgh #8 and Meigs Creek #9 coal seams. As of
December 31, 2009, the Belmont County mining complex
included 6.6 million tons of proven and probable coal
reserves. Coal produced from the Belmont County mining complex
is primarily transported by truck to our Bellaire river terminal
on the Ohio River. Coal produced from this mining complex is
crushed and blended at the Bellaire river terminal before it is
loaded onto barges for shipment to our customers on the Ohio
River. This mining complex uses area, contour, auger and
highwall miner methods of surface mining. This mining complex
produced 1.3 million tons of coal for the year ended
December 31, 2009.
Plainfield Mining Complex.
The Plainfield
mining complex is located in Muskingum, Guernsey and Coshocton
Counties, Ohio, and consists of the Plainfield mine. We began
our mining operations at this mining complex in 1990. Operations
at the Plainfield mining complex target the Middle
Kittanning #6 coal seam. As of December 31, 2009, the
Plainfield mining complex included 6.4 million tons of
proven and probable coal reserves. The infrastructure at this
mining complex includes our Barb Tipple blending and coal
crushing facility. Substantially all of the coal we produce from
the Plainfield mining complex is sold to AEP. The majority of
the coal produced from the Plainfield mining complex is trucked
to our Barb Tipple facility for crushing and blending or
directly to AEPs Conesville generating station. Coal
trucked to our Barb Tipple facility is transported by truck to
AEP after processing is completed. Some of the coal production
from this mining complex is trucked to our Strasburg wash plant
and then transported by truck to the customer. This mining
complex uses contour, auger and highwall miner methods of
surface mining. This mining complex produced 0.5 million
tons of coal for the year ended December 31, 2009.
New Lexington Mining Complex.
The New
Lexington mining complex is located in Perry, Athens and Morgan
Counties, Ohio, and consists of the New Lexington mine. We began
our mining operations at this mining complex in 1993. Operations
at the New Lexington mining complex target the Lower
Kittanning #5 and Middle Kittanning #6 coal seams. As
of December 31, 2009, the New Lexington mining complex
included 4.9 million tons of proven and probable coal
reserves. The infrastructure at this mining complex includes a
coal crusher, a truck scale and the New Lexington rail loadout.
Coal produced from the New Lexington mining complex is delivered
via-off highway trucks to our New Lexington rail loadout
facility on the Ohio Central Railroad where it is then
transported by rail to the customer. This mining complex uses
the area method of surface mining. This mining complex produced
0.6 million tons of coal for the year ended
December 31, 2009.
Harrison Mining Complex.
The Harrison mining
complex is located in Harrison County, Ohio, and consists of the
Harrison mine. Mining operations at this mining complex began in
2007. The Harrison mining complex is owned by Harrison
Resources. We own 51% of Harrison Resources and CONSOL Energy
owns the remaining 49% indirectly through one of its
subsidiaries. We entered into this joint venture in 2007 to mine
coal reserves purchased from CONSOL Energy. We manage all of the
operations of, and perform all of the contract mining and
marketing services for, Harrison Resources. Because the results
of operations of Harrison Resources are included in our
consolidated financial statements for the year ended
December 31, 2009 as required by GAAP, coal production and
proven and probable coal reserves attributable to the Harrison
mining complex are presented on a gross basis assuming we owned
100% of Harrison Resources.
Since its formation in 2007, Harrison Resources has acquired
3.5 million tons of proven and probable coal reserves from
CONSOL Energy. We believe that CONSOL Energy controls additional
reserves in Harrison County, Ohio, that could be acquired by
Harrison Resources in the future. However, CONSOL
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Energy has no obligation to sell those reserves to Harrison
Resources, and we cannot assure you that Harrison Resources
could acquire those reserves from CONSOL Energy on acceptable
terms.
Operations at the Harrison mining complex target the
Pittsburgh #8, Redstone #8A and Meigs Creek #9
coal seams. As of December 31, 2009, the Harrison mining
complex included 2.8 million tons of proven and probable
coal reserves. The infrastructure at this mining complex
includes a coal crusher and a truck scale. Coal produced from
the Harrison mining complex is trucked to our Bellaire river
terminal, our Cadiz rail loadout facility or directly to
customers. Coal trucked to our Bellaire river terminal is
transported to the customer by barge and coal trucked to our
Cadiz rail loadout facility is transported to the customer by
rail. This mining complex uses the area method of surface
mining. This mining complex produced 0.7 million tons of
coal for the year ended December 31, 2009.
Noble County Mining Complex.
The Noble County
mining complex is located in Noble and Guernsey Counties, Ohio,
and consists of the Long-Sears and Halls Knob mines. We
began our mining operations at this mining complex in 2006.
Operations at the Noble County mining complex target the
Pittsburgh #8 and Meigs Creek #9 coal seams. As of
December 31, 2009, the Noble County mining complex included
2.5 million tons of proven and probable coal reserves. Coal
produced from the Noble County mining complex is trucked to our
Bellaire river terminal on the Ohio River or to our Barb Tipple
facility. Coal trucked to our Bellaire river terminal is then
transported by barge to the customer. Coal trucked to our Barb
Tipple blending and coal crushing facility is transported by
truck to the customer after processing is completed. This mining
complex uses the area, contour and auger methods of surface
mining. This mining complex produced 0.3 million tons of
coal for the year ended December 31, 2009.
Illinois
Basin
We operate one surface mining complex in the Illinois Basin,
which is located in western Kentucky. We acquired this operation
from Phoenix Coal on September 30, 2009. For the period
beginning on October 1, 2009 and ending on
December 31, 2009, this mining complex produced an
aggregate of 0.4 million tons of steam coal. The following
table provides summary information regarding our mining complex
in the Illinois Basin as of December 31, 2009:
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Transportation
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Tons Produced for
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Facilities Utilized
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the Year Ended
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River
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Rail
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Transportation
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Number of
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December 31,
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Mining Complex
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Terminal
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Loadout
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Method
(1)
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Active Mines
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2009
(2)
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Muhlenberg County
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Island
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Barge, Truck
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4
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0.4
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(1)
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Barge means transported by truck to our Island river terminal
and then transported to the customer by barge. Truck means
transported to customer by truck.
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(2)
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Acquired in the Phoenix Coal acquisition that occurred on
September 30, 2009. As a result, production data is limited
to the fourth quarter of 2009.
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Muhlenberg County Mining Complex.
The
Muhlenberg County mining complex is located in Muhlenberg and
McClean Counties, which is in western Kentucky, and consists of
the Schoate/431, Winn, Jessup and KO mines. We began our mining
operations at this mining complex in October 2009. Operations at
the Muhlenberg County mining complex target
the #5, #6, #9, #10, #11, #12
and #13 coal seams of the Illinois Basin. As of
December 31, 2009, the Muhlenberg County mining complex
included 24.2 million tons of proven and probable coal
reserves. The infrastructure at this mining complex includes the
Schoate wash plant, the Winn, Jessup, and KO coal crushers and
our Island river terminal. Coal produced from this mining
complex is usually crushed at the mine site and then trucked to
our Island river terminal on the Green River or directly to the
customer. Coal trucked to our Island river terminal is then
transported to the customer by barge. Some of the production
from this mining complex is washed at our Schoate wash plant
prior to being transported either by truck directly to the
customer, or by truck to our Island river terminal and then
transported by barge to the customer. This mining complex uses
the area method of surface mining. This mining complex produced
0.4 million tons of steam coal during the fourth quarter of
2009.
107
Coal
Reserves
The estimates of our proven and probable reserves associated
with our surface mining operations in Ohio are derived from our
internal estimates, which estimates were audited by John T.
Boyd Company, an independent mining and geological consulting
firm. The estimates of our proven and probable reserves
associated with our surface mining operations in the Illinois
Basin and our proven and probable underground coal reserves are
derived from reserve reports prepared by John T. Boyd
Company. These estimates are based on geologic data, economic
data such as cost of production and projected sale prices and
assumptions concerning permitability and advances in mining
technology. Our coal reserves are reported as recoverable
coal reserves, which is the portion of the coal that could
be economically and legally extracted or produced at the time of
the reserve determination, taking into account mining recovery
and preparation plant yield. These estimates are periodically
updated to reflect past coal production, new drilling
information and other geologic or mining data. Acquisitions or
dispositions of coal properties will also change these
estimates. Changes in mining methods may increase or decrease
the recovery basis for a coal seam, as will changes in
preparation plant processes. We maintain reserve information in
secure computerized databases, as well as in hard copy. The
ability to update or modify the estimates of our coal reserves
is restricted to our engineering group and the modifications are
documented.
Reserves
are defined by SEC Industry Guide 7
as that part of a mineral deposit which could be economically
and legally extracted or produced at the time of the reserve
determination. Industry Guide 7 divides reserves between
proven (measured) reserves and probable
(indicated) reserves, which are defined as follows:
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Proven (Measured) Reserves.
Reserves for
which (a) quantity is computed from dimensions revealed in
outcrops, trenches, workings or drill holes; and grade
and/or
quality are computed from the results of detailed sampling and
(b) the sites for inspection, sampling and measurement are
spaced so closely and the geologic character is so well defined
that size, shape, depth and mineral content of reserves are
well-established.
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Probable (Indicated) Reserves.
Reserves for
which quantity and grade
and/or
quality are computed from information similar to that used for
proven (measured) reserves, but the sites for inspection,
sampling, and measurement are farther apart or are otherwise
less adequately spaced. The degree of assurance, although lower
than that for proven (measured) reserves, is high enough to
assume continuity between points of observation.
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As of December 31, 2009, all of our proven and probable
coal reserves were assigned reserves, which are coal
reserves that can be mined without a significant capital
expenditure for mine development.
As of December 31, 2009, we owned 17.4% of our coal
reserves and leased 82.6% of our coal reserves from various
third-party landowners. The majority of our leases have terms
denominated in years and we believe that the term of years will
allow the recoverable coal reserves to be fully extracted in
accordance with our projected mining plan. Some of our leases
have an initial term denominated in years but also provide for
the term of the lease to continue until exhaustion of the
mineable and merchantable coal in the lease area so
long as we comply with the terms of the lease.
It generally takes us from 12 to 30 months to obtain a
SMCRA permit. Permits are issued for an initial five year term
and must be renewed if mining is to continue after the end of
the term. We submit and obtain new mining permits on a
continuing basis to replace existing permits as they are
depleted. Based on our current surface mining plan, we have
proven and probable coal reserves with active permits that will
allow us to mine for approximately the next three years. We do
not expect to have any material delays in obtaining or renewing
permits on our remaining coal reserves associated with our
mining operations.
108
The following table provides information as of December 31,
2009 on the location of our operations and the amount and
ownership of our coal reserves:
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Total Tons of Proven and Probable Coal
Reserves
(1)
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Mining Complex
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Total
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Owned
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Leased
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(in million tons)
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Surface Mining Operations:
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Northern Appalachia (principally Ohio)
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Cadiz
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12.4
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7.5
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4.9
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Tuscarawas
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8.8
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0.1
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8.7
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Belmont County
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6.6
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1.9
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4.7
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Plainfield
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6.4
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0.7
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5.7
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New Lexington
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4.9
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2.8
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2.1
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Harrison
(2)
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2.8
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2.8
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Noble County
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2.5
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0.1
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2.4
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Total Northern Appalachia
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44.4
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15.9
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28.5
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Illinois Basin (Kentucky)
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Muhlenberg County
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24.2
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24.2
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Total Illinois Basin
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24.2
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24.2
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Total Surface Mining Operations
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68.6
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15.9
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52.7
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|
|
|
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Underground Coal Reserves:
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|
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Tusky
(3)
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23.0
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|
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23.0
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|
|
|
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|
|
|
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Total Underground Coal Reserves
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23.0
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23.0
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Total
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91.6
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15.9
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75.7
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Percentage of Total
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100
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%
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17.4
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%
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|
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82.6
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%
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|
|
|
|
|
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|
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(1)
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Reported as recoverable coal reserves. All proven and probable
coal reserves are assigned coal reserves, which are
coal reserves that can be mined without a significant capital
expenditure for mine development.
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(2)
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The Harrison mining complex is owned by Harrison Resources. We
own 51% of Harrison Resources and CONSOL Energy owns the
remaining 49% through one of its subsidiaries. Because the
results of operations of Harrison Resources are included in our
consolidated financial statements for the year ended
December 31, 2009 as required by GAAP, proven and probable
coal reserves attributable to the Harrison mining complex are
presented on a gross basis assuming we owned 100% of Harrison
Resources. Please read Mining
Operations Northern Appalachia Harrison
Mining Complex.
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(3)
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Please read Underground Coal Reserves
for more information about our underground coal reserves at the
Tusky mining complex, which we have leased to a third party in
exchange for royalty payments. During 2009, we received royalty
payments on 0.6 million tons of coal produced from the
Tusky mining complex.
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109
The following table provides information on particular
characteristics of our coal reserves as of December 31,
2009:
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As received
Basis
(1)
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# of
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Proven and Probable Coal Reserves
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SO2/mm
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Sulfur
Content
(1)
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Mining Complex
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% Ash
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% Sulfur
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Btu/lb.
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Btu
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Total
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<2%
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2-4%
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>4%
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(in million tons)
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Surface Mining Operations:
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|
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Northern Appalachia (principally Ohio)
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|
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|
|
|
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|
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Cadiz
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11.6
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3.3
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11,520
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5.7
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12.4
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1.1
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6.1
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5.2
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Tuscarawas County
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10.5
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3.7
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11,570
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6.3
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|
|
|
8.8
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|
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1.6
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|
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3.5
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|
|
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3.7
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Belmont County
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|
|
12.6
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|
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3.7
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11,510
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6.4
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|
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6.6
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|
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4.6
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2.0
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Plainfield
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10.7
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|
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4.4
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|
|
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11,350
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7.7
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6.4
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|
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|
|
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0.7
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|
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5.7
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New Lexington
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|
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11.1
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|
|
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4.0
|
|
|
|
11,260
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|
|
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7.1
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|
|
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4.9
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|
|
|
|
|
|
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2.0
|
|
|
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2.9
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Harrison
(2)
|
|
|
11.9
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|
|
|
1.8
|
|
|
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12,040
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|
|
|
3.0
|
|
|
|
2.8
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|
|
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2.1
|
|
|
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0.7
|
|
|
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Noble County
|
|
|
13.2
|
|
|
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4.7
|
|
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11,230
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8.4
|
|
|
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2.5
|
|
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|
|
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0.3
|
|
|
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2.2
|
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Illinois Basin (Kentucky)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Muhlenberg County
|
|
|
11.2
|
|
|
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3.6
|
|
|
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11,295
|
|
|
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6.4
|
|
|
|
24.2
|
|
|
|
|
|
|
|
23.0
|
|
|
|
1.2
|
|
Underground Coal Reserves:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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Tusky
(3)
|
|
|
5.4
|
|
|
|
2.1
|
|
|
|
12,900
|
|
|
|
3.3
|
|
|
|
23.0
|
|
|
|
3.8
|
|
|
|
19.2
|
|
|
|
|
|
|
|
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(1)
|
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As received represents an analysis of a sample as received at a
laboratory operated by a third party.
|
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(2)
|
|
The Harrison mining complex is owned by Harrison Resources. We
own 51% of Harrison Resources and CONSOL Energy Inc owns the
remaining 49% through one of its subsidiaries. Because the
results of operations of Harrison Resources are included in our
consolidated financial statements for the year ended
December 31, 2009 as required by U.S. generally accepted
accounting principles, proven and probable coal reserves
attributable to the Harrison mining complex are presented on a
gross basis assuming we owned 100% of Harrison Resources. Please
read Mining Operations Northern
Appalachia Harrison Mining Complex.
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(3)
|
|
Please read Underground Coal Reserves
for more information about our underground coal reserves at the
Tusky mining complex, which we have leased to a third party in
exchange for royalty payments. During 2009, we received royalty
payments on 0.6 million tons of coal produced from the
Tusky mining complex.
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Underground
Coal Reserves
We originally leased our underground coal reserves from a third
party in 2003 in exchange for a royalty based on tonnage sold.
We began our underground mining operation in late 2003. In June
2005, we sold the Tusky mining complex, and we subleased our
underground coal reserves associated with that complex to the
purchaser in exchange for an overriding royalty. Our overriding
royalty is equal to a percentage of the sales price received by
our sublessee for the coal produced from our underground coal
reserves. In addition, our sublessee is obligated to pay the
royalty we owe to our lessor. We have at least 15 years
remaining on the lease for our underground coal reserves, and
our sublessee has at least 15 years remaining on its
sublease from us.
Reclamation
We are committed to minimizing our environmental impact during
the mining process. However, there is always some degree of
impact. To minimize the long-term environmental impact of our
mining activities, we plan and monitor each phase of our mining
projects as well as our post-mining reclamation efforts. As of
December 31, 2009, we had approximately $31.3 million
in surety bonds outstanding to secure the performance of our
reclamation obligations, which were supported by approximately
$6.9 million in letters of
110
credit. In addition to providing surety bonds, we have also made
a significant investment to complete the required reclamation
activities in a timely and professional manner to cause our
surety bonds to be released. We have historically performed, and
expect to continue to perform, reclamation activities on a
continuous basis as our mining activities progress.
Over 95% of our active surface mining permits are associated
with reserves that were mined by other coal producers prior to
the implementation of SMCRA. We are able to economically mine
these reserves due to increased coal pricing and improved mining
technologies compared to the pre-SMCRA period. Reclamation
standards prior to SMCRA were considerably lower than
todays standards. These pre-SMCRA mining areas have
unreclaimed highwalls and often have water quality or vegetation
deficiencies. Our mining activities not only recover coal that
was left behind by previous operators, but also significantly
reduce the environmental and safety hazards created by their
mining activities. Although we have reclamation obligations with
respect to these pre-SMCRA mining areas, these obligations are
typically no greater than the reclamation obligations for newly
mined reserves.
Surface or groundwater that comes in contact with materials
resulting from mining activities can become acidic and contain
elevated levels of dissolved metals, a condition referred to as
AMD. We have seven mining permits that are identified on
Ohios Inventory of Long-Term AMD sites. Only one of these
sites, associated with the Strasburg wash plant, requires
continuous AMD treatment, for which we have estimated the
present value of the projected annual treatment cost at less
than $10,000 per year. While we anticipate that AMD treatment
will not be required once reclamation is completed, it is
possible that AMD treatment will be required for some time and
current AMD treatment costs could escalate due to changes in
flow or water quality. One site on the AMD Inventory List has
been recommended by Ohio for removal from the AMD Inventory List
and the remaining sites are being monitored to assess long-term
AMD treatment issues. Moreover, we anticipate that one of these
sites being monitored will receive final surety bond release in
2010 and will be removed from the AMD Inventory List.
Limestone
At our Cadiz mining complex, we remove limestone in order to
mine the underlying coal. We sell this limestone to a third
party that crushes and processes the limestone before it is sold
to local governmental authorities, construction companies and
individuals. The third party pays us for this limestone based on
a percentage of the revenue it receives from sales of this
limestone. Our revenues for the year ended December 31,
2009 include $1.4 million in limestone sales.
In 2009, we produced 0.5 million tons of limestone. Based
on estimates from our internal engineers, our Cadiz mining
complex includes 8.0 million tons of proven and probable
limestone reserves as of December 31, 2009. All of these
limestone reserves were assigned reserves, which are limestone
reserves that can be recovered without a significant capital
expenditure for mine development.
Other
Operations
During 2009, we generated $1.3 million of revenue from a
variety of services we perform in connection with our surface
mining operations. This revenue included the following:
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services fees we earn for operating a transloader for a third
party that offloads coal from railcars on the Ohio Central
Railroad at one of our customers power plants;
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service fees we earn for providing operational services for
Tunnel Hill Partners, LP, an entity owned by our sponsors that
owns a landfill; and
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service fees we earn for hauling and disposing of ash at a third
party landfill for two municipal utilities.
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For more information regarding our relationships and our
sponsors relationships with Tunnel Hill Partners, please
read Certain Relationships and Related Party
Transactions.
111
Customers
General
We market the majority of the coal we produce to base-load power
plants in our six-state market area under long-term coal sales
contracts. Our primary customers are major electric utilities,
municipalities and cooperatives and industrial customers. For
the year ended December 31, 2009, we derived 70% of our
revenues from coal sales to electric utilities (including sales
through brokers), 19% of our revenues from coal sales to
municipalities and cooperatives, 9% of our revenues from coal
sales to industrial customers and 2% of our revenues from a
mixture of sales of non-coal material such as limestone, royalty
payments on our underground coal reserves and fees for services
we perform for third parties.
Long-Term
Coal Sales Contracts
For the year ended December 31, 2009, we generated
approximately 95.8% of our revenues from coal delivered under
our long-term coal sales contracts, and we expect to continue
selling a significant portion of our coal under long-term coal
sales contracts in the future. We define long-term contracts as
those with a term of one year or longer and our long-term coal
sales contracts typically have terms ranging from one to eight
years. For 2010, 2011, 2012 and 2013, we currently have
long-term coal sales contracts that represent 97.2%, 93.0%,
71.4% and 39.7%, respectively, of our 2010 estimated coal sales
of 8.5 million tons. During 2010, 2011, 2012 and 2013, we
have committed to deliver 8.2 million tons,
7.9 million tons, 6.1 million tons and
3.4 million tons of coal, respectively, under long-term
coal sales contracts. These amounts include contracts with
re-openers as described below. In addition, one of our long-term
coal sales contracts that ends in 2012 can be extended by the
customer for two additional three-year terms. If this customer
elects to extend this contract, we will be committed to deliver
an additional 2.0 million tons in 2013, and our 2013 coal
sales under long-term coal sales contracts, as a percentage of
2010 estimated coal sales, would increase to 63.3%.
The terms of our coal sales contracts result from competitive
bidding and negotiations with customers. As a result, the terms
of these agreements including price re-openers, coal
quality requirements, quantity parameters, permitted sources of
supply, effects of future regulatory changes, extension options,
force majeure, termination and assignment provisions
vary by customer. However, most of our long-term coal sales
contracts have full or partial cost pass through provisions or
inflation adjustment provisions. For 2010, 2011, 2012 and 2013,
61%, 72%, 80% and 100% of the coal, respectively, that we have
committed to deliver under our long-term coal sales contracts
are subject to full or partial cost pass through or inflation
adjustment provisions. Cost pass through provisions increase or
decrease our coal sales price for all or a specified percentage
of changes in the cost of fuel, explosives and, in certain
cases, labor. Inflation adjustment provisions adjust the initial
contract price over the term of the contract either by a
specific percentage or a percentage determined by reference to
various inflation related indices.
Two of our long-term coal sales contracts have price re-openers
that provide for market-based adjustments to the initial price
every three years. These contracts will terminate if we cannot
agree upon a market-based price with the customer. For 2011,
2012 and 2013, 0.4 million tons, 0.4 million tons and
0.6 million tons of coal, respectively, that we have
committed to deliver under our long-term coal sales contracts
are subject to price re-opener provisions.
Certain of our long-term coal sales contracts give the customer
the option to elect to purchase additional tons in the future at
a fixed price. Our long-term coal sales contracts that contain
these option tons typically require the customer to provide us
with six months advance notice of an election for option tons.
For 2010, 2011 and 2012, we have outstanding option tons of
0.7 million, 1.0 million and 0.7 million,
respectively. If our customers do elect to receive these option
tons, we believe we will have the operating flexibility to meet
these requirements through increased production.
Quality and volumes for the coal are stipulated in our coal
sales contracts, and in some instances our customers have the
option to vary annual or monthly volumes. Most of our coal sales
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 quality specifications can result
112
in economic penalties, suspension or cancellation of shipments
or ultimately termination of the agreements. Some of our coal
sales contracts specify approved locations from which coal must
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 transportation disruptions that
affect us as well as unanticipated customer plant outages that
may effect our customers ability to receive coal
deliveries.
Customer
Concentration
We derived 90% of our total revenues from coal sales to our ten
largest customers for the year ended December 31, 2009,
with our top five customers accounting for 77% of our total
revenues. In addition, for the year ended December 31, 2009
we derived 34.7%, 14.7% and 14.6% of our revenues from AEP, East
Kentucky Power Cooperative and Duke Energy, respectively.
Transportation
Our coal is delivered to our customers by barge, truck or rail.
Over 55% of the coal we shipped in 2009 was transported by our
to our customers by barge, which is generally cheaper than
transporting coal by truck or rail. We operate river terminals
on the Ohio River in eastern Ohio and the Green River in western
Kentucky, which have annual throughput capacities of
approximately 4 million tons and 3 million tons,
respectively. We also use third-party trucking to transport coal
to our customers. In addition, certain of our mines are located
near rail lines. On April 1, 2006, we entered into a
long-term transportation contract for rail services, which has
been amended and extended through March 31, 2011. Our
customers typically pay the transportation costs to their
location when coal is shipped by barge. We typically pay for the
cost to transport coal to our customers by truck and rail and to
our river terminals and rail loadout facilities. However, our
sales contracts typically have these transportation costs built
into the price. For the year ended December 31, 2009,
55.0%, 42.0% and 3.0% of our coal sales tonnage was shipped by
barge, truck and rail, respectively.
We believe that we have good relationships with rail carriers
and truck companies due, in part, to our modern coal-loading
facilities and the working relationships and experience of our
transportation and distribution employees.
Suppliers
For the year ended December 31, 2009, expenses we incurred
to obtain goods and services in support of our mining operations
were $97.8 million, excluding capital expenditures.
Principal supplies and services used in our business include
diesel fuel, oil, explosives, maintenance and repair parts and
services, and tires and lubricants. For the year ended
December 31, 2009, we hedged 54.4% of our diesel fuel usage
using fixed priced forward contracts that provide for physical
delivery. These fixed priced forward contracts have terms
ranging from six months to one year and generally do not have
collateral requirements.
We use third-party suppliers for a significant portion of our
equipment rebuilds and repairs and for blasting services. We
also use a third party contractor for highwall mining services.
We use bidding processes to promote competition between
suppliers and we seek to develop relationships with those
suppliers whose focus is on lowering our costs. We seek
suppliers that 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, L.P., Alpha
Natural Resources, Inc., Armstrong Coal Company, Buckingham Coal
Co., Inc., The Cline Group, CONSOL Energy, Massey Energy
Company, Murray Energy Corporation, Patriot Coal Corp., Peabody
Energy, Inc. and Rhino Mining Inc.
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The most important factors on which we compete are coal price,
coal quality and characteristics, transportation costs and
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, quality, price and availability of competing
sources of fuel such as natural gas, oil and nuclear sources,
and alternative energy sources such as hydroelectric power and
wind.
Regulation
and Laws
Federal, state and local authorities regulate the U.S. coal
mining industry with respect to environmental, health and safety
matters such as employee health and safety, permitting and
licensing requirements, air and water pollution, plant and
wildlife protection, and the reclamation and restoration of
mining properties after mining has been completed. These laws
and regulations have had, and will continue to have, a
significant effect on production costs and may impact our
competitive advantages. Future laws, regulations or orders, as
well as future interpretations and more rigorous enforcement of
existing laws, regulations or orders, may substantially increase
operating costs, result in delays and disrupt operations, the
extent of which cannot be predicted with any degree of
certainty. Future laws, regulations or orders may also cause
coal to become a less attractive source of energy, thereby
reducing its market share as fuel used to generate electricity.
Thus, future laws, regulations or enforcement priorities may
adversely affect our mining operations, cost structure or the
demand for coal.
We endeavor to conduct our mining operations in compliance with
all applicable federal, state and local laws and regulations.
However, due in part to the complexity, extent and nature of the
various regulatory requirements, violations can and do occur
from time to time. We cannot assure complete compliance at all
times with all applicable laws and regulations.
Mining
Permits and Approvals
Numerous federal, state or local governmental permits or
approvals are required to conduct coal mining and reclamation
operations. When we apply for these permits and approvals, we
are required to prepare and present data to governmental
authorities pertaining to the effect or impact that any proposed
production or processing of coal may have upon the natural or
human environment. The authorization and permitting requirements
imposed by governmental authorities are costly and increasingly
take more time to obtain and may delay commencement or
continuation of mining operations.
In order to obtain mining permits and approvals from federal and
state regulatory authorities, mine operators or applicants must
submit a reclamation plan for restoring the mined land to its
prior productive or other approved use. Typically, we submit the
necessary permit applications 12 to 30 months before we
plan to mine a new area. Some required mining permits are
becoming increasingly difficult to obtain in a timely manner, or
at all and, in some instances, we have had to abandon coal in
certain areas of the application in order to obtain permit
approvals. The application review process takes longer to
complete and is increasingly being challenged by
environmentalists and other advocacy groups, although we are not
aware of any such challenges to any of our pending permit
applications.
Violations of federal, state and local laws, regulations or any
permit or approval issued under such authorization can result in
substantial fines and penalties, including revocation or
suspension of mining permits. In certain circumstances, criminal
sanctions may be imposed for failure to comply with these laws
in addition to fines and civil penalties.
Surface
Mining Control and Reclamation Act
SMCRA establishes mining, reclamation and environmental
protection standards for all aspects of surface coal mining,
including the surface effects of underground coal mining. Mining
operators must obtain SMCRA permits and permit renewals from the
Office of Surface Mining, or the OSM, or from the applicable
state
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agency if the state has obtained primacy. A state may achieve
primacy if it develops a regulatory program that is no less
stringent than the federal program and is approved by OSM. Our
mines are located in Ohio, Pennsylvania, West Virginia and
Kentucky, which have primacy to administer the SMCRA program.
SMCRA permit provisions include a complex set of requirements,
which include, among other things, coal exploration, mine plan
development, topsoil or a topsoil removal alternative, storage
and replacement, selective handling of overburden materials,
mine pit backfilling and grading, disposal of excess spoil,
protection of the hydrologic balance, surface runoff and
drainage control, establishment of suitable post mining land
uses and re-vegetation. The process of preparing a mining permit
application begins by collecting baseline data to adequately
characterize the pre-mining environmental conditions of the
permit area. This work is typically conducted by third-party
consultants with specialized expertise and typically includes
surveys or assessments of the following: cultural and historical
resources, geology, soils, vegetation, aquatic organisms,
wildlife, potential for threatened, endangered or other special
status species, surface and groundwater hydrology, climatology,
riverine and riparian habitat and wetlands. The geologic data
and information derived from the other surveys or assessments
are used to develop the mining and reclamation plans presented
in the permit application. The mining and reclamation plans
address the provisions and performance standards of the
states equivalent SMCRA regulatory program, and are also
used to support applications for other authorizations or permits
required to conduct coal mining activities. Also included in the
permit application is information used for documenting surface
and mineral ownership, variance requests, public road use,
bonding information, mining methods, mining phases, other
agreements that may relate to coal, other minerals, oil and gas
rights, water rights, permitted areas, and ownership and control
information required to determine compliance with OSMs
Applicant Violator System, including the mining and compliance
history of officers, directors and principal owners of the
entity.
Once a permit application is prepared and submitted to the
regulatory agency, it goes through a completeness and technical
review. Also, before a SMCRA permit is issued, a mine operator
must submit a bond or otherwise secure the performance of all
reclamation obligations. After the 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 this process to take from 12 to 30 months
for a SMCRA mine permit application. This variability in time
frame for permitting is a function of the discretion vested in
the various regulatory authorities handling of comments
and objections relating to the project received from the
governmental agencies involved and the general public. The
public also has the right to comment on and otherwise engage in
the administrative process including at the public hearing and
through judicial challenges to an issued 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 to be and are not permit-blocked.
We have subleased our underground coal reserves at the Tusky
mining complex to a third party in exchange for an overriding
royalty. Under our sublease, our sublessee is contractually
obligated to comply with all federal, state and local laws,
including the reclamation and restoration of the mined areas by
grading, shaping and reseeding the soil as required under SMCRA.
Regulatory authorities may attempt to assign the SMCRA
liabilities of our sublessee to us if it is not financially
capable of fulfilling those obligations and it is determined
that we own or control the
sublessees mining operation. To our knowledge, no such
claims have been asserted against us to date. If such claims are
ever asserted against us, we will contest them vigorously on the
basis that, among other things, receiving an overriding royalty
under a sublease does not alone meet the legal or regulatory
test of ownership or control so as to
subject us to the SMCRA liabilities of our sublessee.
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In 1983, the OSM adopted the stream buffer zone
rule, or SBZ Rule, which prohibited mining disturbances
within 100 feet of streams if there would be a negative
effect on water quality. In December 2008, the OSM finalized a
revised SBZ Rule, which purported to clarify certain aspects of
the 1983 SBZ Rule. Several organizations challenged the 2008
revision to the SBZ Rule in two related actions filed in the
United States District Court for the District of Columbia. In
April 2009, the United States filed motions seeking the
voluntary vacation of the revised SBZ Rule. In June 2009, the
Interior Department and the U.S. Army entered into a
memorandum of understanding on how to protect waterways from
degradation if the revised SBZ Rule were vacated due to the
litigation. In August 2009, the District Court denied the
Governments motion, and concluded that the revised SBZ
Rule could not be vacated without following the Administrative
Procedure Act and other related requirements. On
November 30, 2009, the OSM published a notice of a proposed
rulemaking to further revise the SBZ Rule and solicited comments
until December 30, 2009. The OSM suggested several
alternative regulatory approaches in the rulemaking notice, and
indicated that they will prepare a supplemental environmental
impact study on the proposed revisions prior to adoption. Based
on the memorandum of understanding and the proposals in the
notice, the requirements of the revised SBZ Rule, when adopted,
could be more adverse than the prior SBZ Rule, and may adversely
affect our business and operations. In addition, Congress has
proposed legislation in the past and may propose legislation in
the future to restrict the placement of mining material in
streams. Such legislation could also have an adverse impact on
our business.
In addition to the bond requirement for an active or proposed
permit, the Abandoned Mine Land Fund, which was created by
SMCRA, imposes a fee on all coal produced. The proceeds of the
fee are used to restore mines closed or abandoned prior to
SMCRAs adoption in 1977. The current fee is $0.315 per ton
of coal produced from surface mines. In 2009, we recorded
$1.7 million of expense related to these reclamation fees.
Surety
Bonds
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. The cost of surety bonds
have fluctuated in recent years, and the market terms of these
bonds have generally become more unfavorable to mine operators.
These changes in the terms of the bonds have been accompanied at
times by a decrease in the number of companies willing to issue
surety bonds. Some mine operators have therefore used letters of
credit to secure the performance of a portion of our reclamation
obligations.
As of December 31, 2009, we had approximately
$31.3 million in surety bonds outstanding to secure the
performance of our reclamation obligations, which were supported
by approximately $6.9 million in letters of credit.
Mine
Safety and Health
Stringent health and safety standards have been in effect since
Congress enacted the Coal Mine Health and Safety Act of 1969.
The Federal Mine Safety and Health Act of 1977, or the Mine Act,
significantly expanded the enforcement of safety and health
standards and imposed safety and health standards on all aspects
of mining operations. In addition to federal regulatory
programs, all of the states in which we operate have state
programs for mine safety and health regulation and enforcement.
Collectively, federal and state safety and health regulation in
the coal mining industry is among the most comprehensive systems
for protection of employee health and safety affecting any
segment of U.S. industry. The Mine Act requires mandatory
inspections of surface and underground coal mines and requires
the issuance of citations or orders for the violation of a
mandatory health and safety standard. A civil penalty must be
assessed for each citation or order issued. Serious violations
of mandatory health and safety standards 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 also imposes
criminal liability for corporate operators who knowingly or
willfully violates a mandatory health and safety standard, or
order and provides that civil and criminal penalties may be
assessed against individual agents, officers and directors who
knowingly or
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willfully violate a mandatory health and safety standard or
order. In addition, criminal liability may be imposed against
any person for knowingly falsifying records required to be kept
under the Mine Act and standards. In response to recent
underground mine accidents, Congress, in 2006, enacted the Mine
Improvement and New Emergency Response Act, or MINER Act, which
imposed additional burdens on coal operators, including, among
other matters, (i) obligations related to (a) the
development of new emergency response plans that address
post-accident communications, tracking of miners, breathable
air, lifelines, training and communication with local emergency
response personnel, (b) establishing additional
requirements for mine rescue teams, and (c) promptly
notifying federal authorities of incidents that pose a
reasonable risk of death and (ii) increased penalties for
violations of the applicable federal laws and regulations. The
penalty regulations promulgated in 2007 as a result of this
legislation included new heightened penalty categories for
certain types of violations and have resulted in the imposition
of penalty assessment amounts that doubled between fiscal years
2007 and 2008 in the coal industry and are expected to increase.
In the wake of the 2006 legislation, enforcement scrutiny also
increased, including more inspection hours at mine sites,
increased numbers of inspections and increased issuance of the
number and the severity of enforcement actions. Various states
also have enacted their own new laws and regulations addressing
many of these same subjects. Our compliance with these or any
new mine health and safety regulations could increase our mining
costs.
Under the Black Lung Benefits Revenue Act of 1977 and the Black
Lung Benefits Reform Act of 1977, as amended in 1981, each coal
mine operator must pay federal black lung benefits to claimants
who are current and former employees and also make payments to a
trust fund for the payment of benefits and medical expenses to
claimants who last worked in the coal industry prior to
January 1, 1970. The trust fund is funded by an excise tax
on production of up to $1.10 per ton for deep-mined coal and up
to $0.55 per ton for surface-mined coal, neither amount to
exceed 4.4% of the gross sales price. The excise tax does not
apply to coal shipped outside the United States. In 2009, we
recorded $3.1 million of expense related to this excise
tax. The Affordable Health Choices Act currently being debated
in the U.S. Congress proposes potentially significant
changes to the federal black lung program, including provisions,
retroactive to 2005, which would (i) provide an automatic
survivor benefit paid upon the death of a miner with an awarded
black lung claim, without requiring proof that the death was due
to pneumoconiosis and (ii) establish 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 or similar proposed changes,
if enacted, could have a material impact on our costs expended
in association with the federal Black Lung program. In addition,
we are liable under various state statutes for black lung claims.
Clean
Air Act
The federal Clean Air Act and state laws that regulate air
emissions affect coal mining operations both directly and
indirectly. Direct impacts on coal mining and processing
operations include Clean Air Act permitting requirements and
control requirements for particulate matter, which includes
fugitive dust from roadways, parking lots, and equipment such as
conveyors and storage piles. The Clean Air Act indirectly
affects coal mining operations by extensively regulating the
emissions of particulate matter, sulfur dioxide, nitrogen
oxides, carbon monoxide, ozone, mercury and other compounds
emitted by coal-fired power plants. In addition to greenhouse
gas emissions discussed below, air emission control programs
that affect our operations, directly or indirectly, include, but
are not limited to, the following:
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Acid Rain.
Title IV of the Clean Air Act
requires reductions of sulfur dioxide emissions by electric
utilities. Affected power plants have sought to reduce sulfur
dioxide emissions by switching to lower sulfur fuels, installing
pollution control devices, reducing electricity generating
levels or purchasing or trading sulfur dioxide emissions
allowances. These efforts will make it more costly to operate
coal-fired power plants and could make coal a less attractive
fuel alternative in the planning and building of power plants in
the future.
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Particulate Matter.
The Clean Air Act requires
the EPA to set standards, referred to as National Ambient Air
Quality Standards, or NAAQS, for certain pollutants. Areas that
are not in compliance (referred to as non-attainment
areas) with these standards must take steps to reduce
emissions levels. Although our operations are not currently
located in non-attainment areas, should any of the
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areas in which we operate be designated as non-attainment areas
for particulate matter, our mining operations may be directly
affected by any NAAQS implementation.
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Ozone.
The EPA issued revised ozone NAAQS
imposing more stringent limits that took effect in May 2008.
Nitrogen oxides, which are a by-product of coal combustion, are
classified as an ozone precursor. Under the revised ozone NAAQS,
significant additional emissions control expenditures may be
required at coal-fired power plants. Attainment dates for the
new standards range between 2013 and 2030, depending on the
severity of the non-attainment. In July 2009, the
U.S. Court of Appeals for the District of Columbia vacated
part of a rule implementing the ozone NAAQs and remanded certain
other aspects of the rule to the EPA for further consideration.
Notwithstanding the decision, we expect that additional
emissions control requirements may be imposed on new and
expanded coal-fired power plants and industrial boilers in the
years ahead. The combination of these actions may impact demand
for coal nationally, the impact of which we are unable to
predict to any reasonable degree of certainty.
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NOx, or Nitrogen Oxides State Implementation Plan, or SIP
Call
. The NOx SIP Call program was established by
the EPA in October 1998 to reduce the transport of nitrogen
oxide and ozone on prevailing winds from the Midwest and South
to states in the Northeast that alleged they could not meet
federal air quality standards because of NOx emissions. The
program is designed to reduce NOx emissions by one million tons
per year in 22 eastern states and the District of Columbia. As a
result of this program, many power plants have been or will be
required to install additional emission control measures, such
as selective catalytic reduction, or SCR, devices. Installation
of additional emission control measures will make it more costly
to operate coal-fired power plants, which could make coal a less
competitive fuel.
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Clean Air Interstate Rule.
The EPAs CAIR
calls for power plants in 28 eastern states and the District of
Columbia to reduce emission levels of sulfur dioxide and
nitrogen oxide pursuant to a cap and trade program similar to
the system now in effect for acid rain. In July 2008, the
U.S. Court of Appeals for the District of Columbia Circuit
vacated the EPAs CAIR in its entirety and directed the EPA
to commence new rule-making. After a petition for rehearing, the
court ruled in December 2008 that to completely vacate CAIR
would sacrifice public health and environmental benefits and
that CAIR should remain in effect while the EPA modifies the
rule. It is uncertain how the EPA will proceed to modify CAIR,
although the EPA has indicated that it intends to propose a
replacement rule in 2010 and to issue a final rule by early
2011. Under CAIR and any replacement rule, some coal-fired power
plants might be required to install additional pollution control
equipment, such as scrubbers
and/or
SCR
equipment that could lead plants with these controls to become
less sensitive to the sulfur-content of coal and more sensitive
to delivered price, thereby making our high sulfur coal more
competitive.
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Mercury.
In February 2008, the U.S. Court
of Appeals for the District of Columbia Circuit vacated the
EPAs Clean Air Mercury Rule, or CAMR, which had
established a cap and trade program to reduce mercury emissions
from power plants. At present, there are no federal regulations
that require monitoring and reducing of mercury emissions at
existing power plants. As a result of the decision to vacate the
CAMR, in February 2009 the EPA announced that it would regulate
mercury emissions by issuing Maximum Achievable Control
Technology standards, or MACT, that will likely impose stricter
limitations on mercury emissions from power plants than the
vacated CAMR. The EPA is under a court deadline to issue a final
rule requiring MACT for power plants by November, 2011. In
conjunction with these efforts, on December 24, 2009, EPA
approved an Information Collection Request (ICR) requiring all
US power plants with coal-or oil-fired electric generating units
to submit emissions information for use in developing air toxic
emissions standards. EPA has stated that it intends to propose
air toxic emissions standards for coal- and oil-fired electric
generating units by March 10, 2011. In the meantime,
case-by-case
MACT determinations for mercury may be required for new and
reconstructed coal-fired power plants. Apart from CAMR, several
states have enacted or proposed regulations requiring reductions
in mercury emissions from coal-fired power plants, and federal
legislation to reduce mercury emissions from power plants has
been proposed. The Obama
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Administration has also indicated a desire to begin negotiations
on an international treaty to reduce mercury pollution. More
stringent regulation of mercury emissions by the EPA, states,
Congress, or pursuant to an international treaty may decrease
the future demand for coal, but we are unable to predict the
magnitude of any such impact with any reasonable degree of
certainty.
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There are lawsuits pending or threatened legal actions that have
named coal producers as defendants for personal injury and
property damage resulting from mercury emissions from coal-fired
plants (e.g. by entering human pathways of exposure).
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Regional Haze.
The EPA has initiated a
regional haze program designed to protect and improve visibility
at and around national parks, national wilderness areas and
international parks. This program may result in additional
emissions restrictions from new coal-fired power plants whose
operation may impair visibility at and near such federally
protected areas. This program may also require certain existing
coal-fired power plants to install additional control measures
designed to limit haze-causing emissions, such as sulfur
dioxide, nitrogen oxides, ozone and particulate matter. These
limitations could also affect the future market for coal, to the
extent of which we are unable to predict with any reasonable
degree of certainty.
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New Source Review or, or NSR.
A number of
pending regulatory changes and court actions will affect the
scope of the EPAs NSR program, which requires, among other
emission sources, new coal-fired power plants and certain
modifications to existing coal-fired power plants to install the
same air emissions control equipment as new plants. The changes
to the NSR program may impact demand for coal nationally, but we
are unable to predict the magnitude of any such impact with any
reasonable degree of certainty.
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Climate
Change
Carbon dioxide is a greenhouse gas, the man-made
emissions of which are of major concern under any regulatory
framework intended to control climate change or prevent global
warming. Carbon dioxide is a by-product of the combustion
process, a primary source of which are coal-fired power plants.
In 2005, the Kyoto Protocol to the 1992 United Nations Framework
Convention on Climate Change, which establishes a binding set of
emission targets for greenhouse gases, became binding on all
those countries that had ratified it. To date, the U.S. has
not ratified the Kyoto Protocol, which expires in 2012. The
United States is participating in international discussions
currently underway to develop a treaty to replace the Kyoto
Protocol after its expiration in 2012. Any replacement treaty or
other international arrangement requiring additional reductions
in greenhouse gas emissions will have a potentially significant
impact on the demand for coal if the United States were to adopt
such requirements.
Future regulation of greenhouse gases in the United States could
occur pursuant to future U.S. treaty commitments, new
domestic legislation that may impose a carbon emissions tax, a
cap-and-trade
program or other programs aimed at carbon reduction, or by
regulatory programs that may be established by the EPA under its
existing authority. Congress is actively considering various
proposals to reduce greenhouse gas emissions, mandate
electricity suppliers to use renewable energy sources to
generate a certain percentage of power, promote the use of clean
energy and require energy efficiency measures. In June 2009, the
House of Representatives passed a comprehensive climate change
and energy bill, the American Clean Energy and Security Act, and
the Senate has considered similar legislation that would, among
other things, impose a nationwide cap on greenhouse gas
emissions and require major sources, including coal-fired power
plants, to obtain allowances to meet that cap. The
Senate is also crafting a compromise bill that may favor
expansion of domestic energy production and limit the imposition
of a cap and trade approach. Passage of such comprehensive
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
have a material adverse affect on our business and the results
of our operations.
Even in the absence of new federal legislation, greenhouse gas
emissions may be regulated in the future by the EPA pursuant to
the Clean Air Act. In response to the 2007 U.S. Supreme
Court ruling
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Massachusetts v. EPA
that the EPA has authority to
regulate carbon dioxide emissions under the Clean Air Act, the
EPA has taken several steps towards implementing regulations
regarding the emission of greenhouse gases. In December 2009,
the EPA issued a finding that carbon dioxide and certain other
greenhouse gases emitted by motor vehicles endanger public
health and the environment. This finding allows the EPA to begin
regulating greenhouse gas emissions under existing provisions of
the Clean Air Act. In anticipation of this finding, in October
2009, the EPA published a proposed rule that makes it clear that
the EPA anticipates regulating the emission of greenhouse gases
from certain stationary sources with an initial focus on
facilities that release more than 25,000 tons of greenhouse
gases a year, and which would require best available control
technology for greenhouse gas emissions whenever such facilities
are built or significantly modified. If the EPA were to set
emission limits for carbon dioxide from electric utilities, the
amount of coal our customers purchase from us could decrease.
Moreover, in October 2009, the EPA published a final rule
requiring certain emitters of greenhouse gases, including
coal-fired power plants, to monitor and report their greenhouse
gas emissions to the EPA beginning in 2011 for emissions
occurring in 2010.
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. In December 2005, seven
northeastern states (Connecticut, Delaware, Maine, New
Hampshire, New Jersey, New York, and Vermont) signed the
Regional Greenhouse Gas Initiative agreement, or RGGI, calling
for implementation of a cap and trade program by 2009 aimed at
reducing carbon dioxide emissions from power plants in the
participating states. The RGGI program calls for signatory
states to stabilize carbon dioxide emissions to current levels
from 2009 to 2015, followed by a 2.5% reduction each year from
2015 through 2018. Since its inception, several additional
northeastern states and Canadian provinces have joined as
participants or observers. RGGI has begun holding quarterly
carbon dioxide allowance auctions for its initial three-year
compliance period from January 1, 2009 to December 31,
2011 to allow utilities to buy allowances to cover their carbon
dioxide emissions.
Midwestern states and Canadian provinces have also adopted
initiatives to reduce and monitor greenhouse gas emissions. In
November 2007, Illinois, Indiana, Iowa, Kansas, Michigan,
Minnesota, Ohio, South Dakota and Wisconsin and Manitoba signed
the Midwestern Greenhouse Gas Reduction Accord to develop and
implement steps to reduce greenhouse gas emissions. The draft
recommendations, released in June 2009, call for a 20% reduction
below 2005 emissions levels by 2020 and additional reductions to
80% below 2005 emissions levels by 2080. Climate change
initiatives are also being considered or enacted in some western
states.
Also, two U.S. federal appeals courts have allowed lawsuits
by individuals, state attorneys general and others to pursue
claims against major utility, coal, oil and chemical companies
on the basis that those companies have created a public nuisance
due to their emissions of carbon dioxide.
In addition to direct regulation of greenhouse gases,
28 states have adopted 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. An
additional five states have renewable portfolio standard goals
that are not yet legal requirements. 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.
These and other current or future climate change rules, court
orders or other legally enforceable mechanisms may in the future
require, additional controls on coal-fired power plants and
industrial boilers and may even cause some users of coal to
switch from coal to a lower carbon dioxide emitting fuels or
shut-down coal-fired power plants. There can be no assurance at
this time that a carbon dioxide cap and trade program, a carbon
tax or other regulatory regime, if implemented by the states in
which our customers operate or at the federal level, or future
court orders or other legally enforceable mechanisms, will not
affect the future market for coal in those regions. The
permitting of new coal-fired power plants has also recently been
contested by some state regulators and environmental
organizations based on concerns relating to greenhouse gas
emissions.
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Increased efforts to control greenhouse gas emissions could
result in reduced demand for coal. If mandatory restrictions on
carbon dioxide emissions are imposed, the ability to capture and
store large volumes of carbon dioxide emissions from coal-fired
power plants may be a key mitigation technology to achieve
emissions reductions while meeting projected energy demands. A
number of recent legislative and regulatory initiatives to
encourage the development and use of carbon capture and storage
technology have been proposed or enacted. For example, the
U.S. Department of Energy announced in May 2009 that it
would provide $2.4 billion of federal stimulus funds under
the ARRA to expand and accelerate the commercial deployment of
large-scaled CCS technology. However, there can be no assurances
that cost-effective CCS capture and storage technology will
become commercially feasible in the near future.
Clean
Water Act
The CWA and corresponding state and local laws and regulations
affect coal mining operations by restricting the discharge of
pollutants, including the discharge of dredged or fill
materials, into waters of the United States. The CWA provisions
and associated state and federal regulations are complex and
subject to amendments, legal challenges and changes in
implementation. Legislation that seeks to clarify the scope of
CWA jurisdiction is under consideration by Congress. Recent
court decisions, regulatory actions and proposed legislation
have created uncertainty over CWA jurisdiction and permitting
requirements that could either increase or decrease the cost and
time we expend on CWA compliance.
CWA requirements that may directly or indirectly affect our
operations include the following:
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Wastewater Discharge.
Section 402 of the
CWA regulates the discharge of pollutants into
navigable waters of the United States. The National Pollutant
Discharge Elimination System, or NPDES, requires a permit for
any such discharges and entails regular monitoring, reporting
and compliance with performance standards that govern
discharges. Failures to comply with the CWA or the NPDES permits
can lead to the imposition of penalties, compliance costs and
delays in coal production.
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The CWA and corresponding state laws also protect waters that
states have designated for special protections including those
designated as: impaired (i.e., as not meeting present water
quality standards) through Total Maximum Daily Load, or TMDL,
regulations; and high quality/exceptional use
streams through anti-degradation regulations which restrict or
prohibit discharges which result in degradation. Other
requirements require the treatment of discharges from coal
mining properties for non-traditional pollutants, such as
chlorides, selenium and dissolved solids; and
protecting streams, wetlands, other regulated water
sources and associated riparian lands from surface mining
and/or
the
surface impacts of underground mining. Individually and
collectively, these requirements may cause us to incur
significant additional costs that could adversely affect our
operating results, financial condition and cash flows.
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Dredge and Fill Permits.
Many mining
activities, including the development of settling ponds and
other impoundments, may require a Section 404 permit from
the Corps, prior to conducting such mining activities where they
involve discharges of fill into navigable waters of
the United States. The Corps is empowered to issue
nationwide permits for specific categories of
filling activities that are determined to have minimal
environmental adverse effects in order to save the cost and time
of issuing individual permits under Section 404 of the
Clean Water Act. Using this authority, the Corps issued NWP 21,
which authorizes the disposal of
dredge-and-fill
material from mining activities into the waters of the United
States. Individual Section 404 permits are required for
activities determined to have more significant impacts to waters
of the United States.
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Since 2003, environmental groups have pursued litigation
primarily in West Virginia and Kentucky challenging the validity
of NWP 21 and various individual Section 404 permits
authorizing valley fills associated with surface coal mining
operations (primarily mountain-top removal operations). This
litigation has resulted in delays in obtaining these permits and
has increased permitting costs. The most recent major decision
in this line of litigation is the opinion of the U.S. Court of
Appeals for the Fourth Circuit in
Ohio Valley Environmental
Council v. Aracoma Coal Company
, 556 F.3d
121
177 (2009) (
Aracoma
), issued on February 13, 2009.
In
Aracoma
the Court rejected all of the substantive
challenges to the Section 404 permits involved in the case
primarily by deferring to the expertise of the Corps in review
of the permit applications. We currently have only one pending
NWP 21 authorization, and we do not anticipate seeking NWP 21
authorizations in the future. As a result, we do not believe the
outcome of this case will be material to us. However, the
U.S. Supreme Court granted certiorari for this case on
August 26, 2009, and it remains pending. If reversed, such
a result could have an adverse effect on the surface mining
industry.
After this decision was published, however, the EPA undertook
several initiatives to address the issuance of Section 404
permits for coal mining activities in the Eastern
U.S. First, the EPA began to comment on Section 404
permit applications pending before the Corps raising many of the
same issues decided in favor of the coal industry in
Aracoma
. Many of the EPAs comment letters were
submitted long after the end of the EPAs comment period
based on what the EPA contended was new information
on the impacts of valley fills on stream water quality
immediately downstream of valley fills. These letters have
created regulatory uncertainty regarding the issuance of
Section 404 permits for coal mining operations and have
substantially expanded the time required for issuance of these
permits.
In June 2009, the Corps, the EPA and the Department of the
Interior announced an interagency action plan for an
enhanced review of any project that requires both a
SMCRA and a CWA permit designed to reduce the harmful
environmental consequences of mountain-top mining in the
Appalachian region. As part of this interagency memorandum of
understanding, the Corps proposed to suspend and modify NWP 21
in the Appalachian region of Kentucky, Ohio, Pennsylvania,
Tennessee, Virginia and West Virginia to prohibit its use to
authorize discharges of fill material into waters of the United
States for mountain-top mining. Two of our applications for
permits are currently being reviewed by EPA under this enhanced
review procedure even though the mining activities in question
do not utilize mountain-top mining, a method of mining we do not
employ. Collectively, the permits covered by these applications
cover 1.1 million tons of our proven and probable coal
reserves.
The EPA is also taking a more active role in its review of NPDES
permit applications for coal mining operations in Appalachia,
and announced in September 2009 that it was delaying the
issuance of 74 Section 404 permits in central Appalachia.
This is especially true in West Virginia, where the EPA
plans to review all applications for NPDES permits even though
the State of West Virginia is authorized to issue NPDES permits
in West Virginia. These initiatives have extended the time
required to obtain permits for coal mining and we anticipate
further delays in obtaining permits and that the costs
associated with obtaining and complying with those permits will
increase substantially. Additionally, while it is unknown
precisely what other future changes will be implemented as a
result of the interagency action plan, any future changes could
further restrict our ability to obtain other new permits or to
maintain existing permits.
Resource
Conservation and Recovery Act
The Resource Conservation and Recovery Act, or RCRA, was enacted
in 1976 to establish requirements for the management of
hazardous wastes from the point of generation through treatment
of disposal. RCRA does not apply to most of the wastes generated
at coal mines, overburden and coal cleaning wastes, because they
are not considered hazardous wastes as EPA applies that term.
Only a small portion of the total amount of wastes generated at
a mine are regulated as hazardous wastes.
Although this act has the potential to apply to wastes from the
combustion of coal, the EPA determined that coal combustion
wastes do not warrant regulation as hazardous wastes under RCRA
in May 2000. Most state solid waste laws also regulate coal
combustion wastes as non-hazardous wastes. The EPA is currently
considering whether national non-hazardous waste regulations
under RCRA are warranted for certain wastes generated from coal
combustion, such as coal ash, when used as mine-fill.
122
Comprehensive
Environmental Response, Compensation and Liability
Act
The Comprehensive Environmental Response, Compensation and
Liability Act, CERCLA or Superfund, and similar state laws
affect coal mining operations by, among other things, imposing
cleanup requirements for threatened or actual releases of
hazardous substances. Under CERCLA and similar state laws, joint
and several liability may be imposed on waste generators, site
owners, lessees and others regardless of fault or the legality
of the original disposal activity. Although the EPA excludes
most wastes generated by coal mining and processing operations
from the hazardous waste laws, such wastes can, in certain
circumstances, constitute hazardous substances for the purposes
of CERCLA. In addition, the disposal, release or spilling of
some products used by coal companies in operations, such as
chemicals, could trigger the liability provisions of CERCLA or
similar state laws. Thus, we may be subject to liability under
CERCLA and similar state laws for coal mines that we currently
own, lease or operate or that we or our predecessors have
previously owned, leased or operated, and sites to which we or
our predecessors sent waste materials. This includes the Tusky
mining complex where we have subleased our underground coal
reserves to a third party in exchange for an overriding royalty.
We may be liable under CERCLA or similar state laws for the
cleanup of hazardous substance contamination and natural
resource damages at sites where we own surface rights.
Endangered
Species Act
The federal Endangered Species Act, or ESA, and counterpart
state legislation protect species threatened with possible
extinction. The U.S. Fish and Wildlife Service, or USFWS,
works closely with the OSM and state regulatory agencies to
ensure that species subject to the ESA are protected from
mining-related impacts. A number of species indigenous to the
areas in which we operate, specifically the Indiana bat, are
protected under the ESA, and compliance with ESA requirements
could have the effect of prohibiting or delaying us from
obtaining mining permits. These requirements may also include
restrictions on timber harvesting, road building and other
mining or agricultural activities in areas containing the
affected species or their habitats. Should more stringent
protective measures be applied, this could result in increased
operating costs, heightened difficulty in obtaining future
mining permits, or the need to implement additional mitigation
measures.
Use of
Explosives
We use third party contractors for blasting services and our
surface mining operations are subject to numerous regulations
relating to blasting activities. Pursuant to these regulations,
we incur costs to design and implement blast schedules and to
conduct pre-blast surveys and blast monitoring. In addition, the
storage of explosives is subject to regulatory requirements. We
presently do not engage in blasting activities. All of our
blasting activities are conducted by independent contractors
that use certified blasters.
Other
Environmental Laws and Matters
We are required to comply with numerous other federal, state and
local environmental 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.
We maintain coal refuse areas and slurry impoundments at our
Tuscarawas County and Muhlenberg County mining complexes. Such
areas and impoundments are subject to extensive regulation. One
of those impoundments overlies a mined out area, which can pose
a heightened risk of structural failure and of damages arising
out of such failure. When a slurry impoundment experiences a
structural failure, it could release large volumes of coal
slurry into the surrounding environment, which in turn can
result in extensive damage to the environment and natural
resources, such as bodies of water. A failure may also result in
civil or criminal fines, penalties, personal injuries and
property damages, and damage to wildlife or natural resources.
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Office
Facilities
We lease and own office space in Columbus and Coshocton, Ohio,
respectively, that is used by our executive and administrative
employees. Our lease expires in 2015.
Employees
To carry out our operations, our general partner employed over
800 full-time employees as of December 31, 2009. None
of these employees are subject to collective bargaining
agreements or are members of any unions. We believe that we have
good relations with these employees, and we continually seek
their input with respect to our operations. Since our inception,
we have had no history of work stoppages or union organizing
campaigns.
Legal
Proceedings
Although we are, from time to time, involved in litigation and
claims arising out of our operations in the normal course of
business, we do not believe that we are a party to any
litigation that will have a material adverse impact on our
financial condition or results of operations. We are not aware
of any significant legal or governmental proceedings against us,
or contemplated to be brought against us. We maintain such
insurance policies with insurers in amounts and with coverage
and deductibles as our general partner believes are reasonable
and prudent. However, we cannot assure you that this insurance
will be adequate to protect us from all material expenses
related to potential future claims for personal and property
damage or that these levels of insurance will be available in
the future at economical prices.
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MANAGEMENT
We are managed and operated by the directors and executive
officers of our general partner, Oxford Resources GP, LLC. Our
general partner is not elected by our unitholders and will not
be subject to re-election in the future. C&T Coal owns
33.7% of the ownership interests in our general partner and AIM
Oxford owns the remaining 66.3% of the ownership interests in
our general partner. Oxford Resources GP has a board of
directors, and our unitholders are not entitled to elect the
directors or directly or indirectly participate in our
management or operations. Charles C. Ungurean, the President and
Chief Executive Officer of our general partner and a member of
the board of directors of our general partner, and Thomas T.
Ungurean, the Senior Vice President, Equipment, Procurement and
Maintenance of our general partner, own all of the equity
interests in C&T Coal. In addition, certain directors of
our general partner are principals of AIM and have ownership
interests in AIM. Our general partner owes certain fiduciary
duties to our unitholders as well as a fiduciary duty to its
owners. Our general partner will be liable, as general partner,
for all of our debts (to the extent not paid from our assets),
except for indebtedness or other obligations that are made
specifically nonrecourse to it. Whenever possible, we intend to
incur indebtedness that is nonrecourse to our general partner.
Our partnership agreement provides for the Conflicts Committee,
as circumstances warrant, to review conflicts of interest
between us and our general partner or between us and affiliates
of our general partner. The Conflicts Committee, which will
consist solely of one independent director, will determine if
the resolution of a conflict of interest that has been presented
to it by our general partner is fair and reasonable to us. The
members of the Conflicts Committee may not be executive officers
or employees of our general partner or directors, executive
officers or employees of its affiliates. In addition, the
members of the Conflicts Committee must meet the independence
and experience standards established by the New York Stock
Exchange and the Exchange Act. Any matters approved by the
Conflicts Committee will be conclusively deemed to be fair and
reasonable to us, approved by all of our partners and not a
breach by our general partner of any duties it may owe us or our
unitholders. In addition, we will have an audit committee, or
Audit Committee, that complies with the New York Stock Exchange
requirements, and we will have a compensation committee, or
Compensation Committee.
Even though most companies listed on the New York Stock Exchange
are required to have a majority of independent directors serving
on the board of directors of the listed company, the New York
Stock Exchange does not require a listed limited partnership
like us to have a majority of independent directors on the board
of directors of its general partner.
Gerald A. Tywoniuk, along with two other independent board
members to be appointed, will serve as the members of the Audit
Committee. Mr. Tywoniuk serves as the chair of the Audit
Committee. In compliance with the rules of the New York Stock
Exchange, the members of the board of directors named below will
appoint to the Audit Committee one additional independent member
within 90 days of the listing and one additional
independent member within twelve months of the listing.
Thereafter, our general partner is generally required to have at
least three independent directors serving on its board at all
times.
Brian D. Barlow, Matthew P. Carbone and Gerald A. Tywoniuk serve
as the members of the Compensation Committee. Mr. Barlow
serves as the chair of the Compensation Committee.
Directors are appointed for a term of one year and hold office
until their successors have been elected or qualified or until
the earlier of their death, resignation, removal or
disqualification. Officers serve at the
125
discretion of the board. The following table shows information
for the directors and executive officers of our general partner.
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Name
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Age
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Position
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George E. McCown
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|
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74
|
|
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Chairman of the Board
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Charles C. Ungurean
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60
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Director, President and Chief Executive Officer
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Jeffrey M. Gutman
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44
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Senior Vice President, Chief Financial Officer and Treasurer
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Gregory J. Honish
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53
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Senior Vice President, Operations
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Thomas T. Ungurean
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58
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Senior Vice President, Equipment, Procurement and Maintenance
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Michael B. Gardner
|
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55
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Secretary and General Counsel
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Denise M. Maksimoski
|
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35
|
|
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Senior Director of Accounting
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Brian D. Barlow
|
|
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39
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Director
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Matthew P. Carbone
|
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43
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Director
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Gerald A. Tywoniuk
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48
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Director
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George E. McCown
was elected Chairman of the board of
directors of our general partner in August 2007. Mr. McCown
has been a Managing Director of AIM since he co-founded AIM in
July 2006. Additionally, Mr. McCown has been a Managing
Director of McCown De Leeuw & Co., or MDC, a private
equity firm based in Foster City, California that specializes in
buying and building industry-leading middle-market companies in
partnership with management, since he co-founded MDC in 1983.
Mr. McCown is Chairman of the board of directors of the
general partner of Tunnel Hill Partners, an affiliate of AIM and
C&T Coal. Mr. McCown received an MBA from Harvard
University and a B.S. in mechanical engineering from Stanford
University, where he served as a trustee from 1980 to 1985 and
chaired the Finance Committee and Investment Policy Subcommittee
of Stanfords board of trustees.
Mr. McCowns over 40 years of experience in
buying and building companies, as well as his in-depth knowledge
of the coal industry generally and our partnership in
particular, provide him with the necessary skills to be a member
of the board of directors of our general partner.
Charles C. Ungurean
was elected President and Chief
Executive Officer and a member of the board of directors of our
general partner in August 2007. In 1985, Mr. Ungurean
co-founded our predecessor and wholly owned subsidiary, Oxford
Mining Company. He served as President and Treasurer of our
predecessor from 1985 to August 2007. He has served as the
President and Chief Executive Officer of our general partner
since its formation in August 2007. Mr. Ungurean
currently serves on the board of directors of the National
Mining Association. In addition, Mr. Ungurean served as
Chairman of the Ohio Coal Association from July 2002 to July
2004. Mr. Ungurean is the brother of Thomas T. Ungurean,
the Senior Vice President, Equipment, Procurement and
Maintenance of our general partner.
Mr. Ungureans 37 years of experience in the coal
industry, over 25 of which have been spent running our
operations or the operations of our predecessor and wholly owned
subsidiary, Oxford Mining Company, provide him with the
necessary skills to be a member of the board of directors of our
general partner.
Jeffrey M. Gutman
has served as Senior Vice President,
Chief Financial Officer and Treasurer of our general partner
since April 2008. Prior to joining us, from 1991 to March 2008,
Mr. Gutman served in a number of positions with The
Williams Companies, Inc., an integrated natural gas company
based in Tulsa, Oklahoma. His positions at the Williams
Companies included Director of Capital Services from February
1998 to April 2000, Director of Structured Finance from April
2000 to December 2002, Chief Financial Officer of Gulf Liquids,
a wholly-owned subsidiary of the Williams Companies, from
December 2002 to December 2005, Director of Planning &
Market Analysis from April 2005 to February 2008, and Commercial
Development from December 2005 until joining our general partner
in April 2008. Prior to joining the Williams Companies,
Mr. Gutman was with Deloitte & Touche, LLP in
their Tulsa office. Mr. Gutman is a certified public
accountant in Oklahoma and holds a B.S. in Business
Administration in Accounting from Oklahoma State University.
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Gregory J. Honish
has served as Senior Vice President,
Operations of our general partner since March 2009.
Mr. Honish has served in other capacities with us and our
predecessor since January 1999, including Vice President, Mining
and Business Development from September 2007 to March 2009 and
Senior Mining Engineer from January 1999 to September 2007.
Mr. Honish has held a balanced spectrum of engineering,
operations and management positions in the coal mining industry
during his 30 year professional career at mines in Northern
Appalachia, Central Appalachia, the Illinois Basin and the PRB.
He is a Licensed Professional Engineer in Ohio and West Virginia
and a Certified Surface Mine Foreman in Ohio and Wyoming.
Mr. Honish holds a B.S. in Mining Engineering from the
University of Wisconsin.
Thomas T. Ungurean
has served as Senior Vice President,
Equipment, Procurement and Maintenance of our general partner
since March 2010, prior to which he was Vice President of
Equipment from August 2007 to February 2010. In 1985,
Mr. Ungurean co-founded our predecessor and wholly owned
subsidiary, Oxford Mining Company. Since then he has served in
various capacities with our predecessor, including Vice
President and Secretary from September 2000 to August 2007.
Mr. Ungurean is the brother of Charles C. Ungurean, the
President and Chief Executive Officer and a member of the board
of directors of our general partner.
Michael B. Gardner
has served as Secretary and General
Counsel of our general partner since September 2007. Prior to
joining us, from June 2004 until May 2007, Mr. Gardner
served as Associate General Counsel of Murray Energy
Corporation, the largest privately-owned coal mining company in
the United States. While at Murray Energy, Mr. Gardner
served as an officer of several Murray Energy subsidiaries,
including Vice President of UMCO Energy, Inc. and Secretary of
UMCO Energy, Inc., Maple Creek Mining, Inc., Maple Creek
Processing, Inc., The Ohio Valley Coal Company, The Ohio Valley
Transloading Company, Ohio Valley Resources, Inc., and Sunburst
Resources, Inc., and represented these entities in a variety of
corporate, financial, real property, labor, litigation,
environmental, health, safety, governmental affairs and public
relations matters. Mr. Gardner is a licensed attorney in
Ohio with more than 30 years of experience in the coal
industry and in environmental regulatory compliance management.
He is an alternate member of the Board of Directors of the Ohio
Coal Association. Mr. Gardner received a J.D. from Case
Western Reserve University, an MBA from Ashland University and a
B.S. in Environmental Biology from Ohio University.
Denise M. Maksimoski
has served as Senior Director of
Accounting of our general partner since December 2009, prior to
which she was Director, Financial Reporting and General
Accounting from August 2008 to December 2009. Prior to joining
us, from 1997 to 2008 Ms. Maksimoski was with
Deloitte & Touche, LLP in Washington, D.C. and
Columbus, Ohio in various positions including most recently as
an Audit Senior Manager from August 2005 to August 2008 and as
an Audit Manager from August 2003 to August 2005. While at
Deloitte, Ms. Maksimoski gained extensive SEC reporting
experience through leading large audit teams on public clients
primarily in the energy and financial services industries.
Ms. Maksimoski is a certified public accountant in the
states of Ohio, Maryland and Virginia and in the District of
Columbia. She received a B.A. degree in Accounting and Actuarial
Studies from Thiel College.
Brian D. Barlow
was elected as a member of the board of
directors of our general partner in August 2007. Mr. Barlow
has been a Principal with AIM since January 2007. Prior to
joining AIM, he was a Senior Securities Analyst for Scion
Capital, a private investment partnership located in Cupertino,
California, from August 2004 to August 2006 and was
self-employed from August 2006 to January 2007. Mr. Barlow
has 18 years of investing experience in both the public and
private equity markets; and while at Scion, he focused on public
and private investments in the energy and natural resources
sectors. He received an MBA from Columbia Business School and a
B.A. from the University of Washington.
Mr. Barlows 18 years of investing experience, as
well as his in-depth knowledge of the coal industry generally
and our partnership in particular, provide him with the
necessary skills to be a member of the board of directors of our
general partner.
Matthew P. Carbone
was elected as a member of the board
of directors of our general partner in August 2007.
Mr. Carbone has been a Managing Director of AIM since he
co-founded AIM in July 2006. Prior to co-founding AIM, from
January 2005 until July 2006, Mr. Carbone was a Managing
Director of MDC. Mr. Carbone has spent nearly 20 years
in private equity and investment banking. Prior to MDC, he led
Wit
127
Capital Groups West Coast operations and worked in the
investment banking divisions of Morgan Stanley, First Boston
Corporation and Smith Barney. Mr. Carbone is a member of
the board of directors of the general partner of Tunnel Hill
Partners, an affiliate of AIM and C&T Coal.
Mr. Carbone is also a member of the board of directors of
the general partner of American Midstream Partners, LP. He
received an MBA from Harvard Business School and a B.A. in
Neuroscience from Amherst College.
Mr. Carbones nearly 20 years of experience in
corporate finance, as well as his in-depth knowledge of the coal
industry generally and our partnership in particular, provide
him with the necessary skills to be a member of the board of
directors of our general partner.
Gerald A. Tywoniuk
was elected as a member of the board
of directors of our general partner in January 2009. He is the
Chief Financial Officer and acting Chief Executive Officer of
Pacific Energy Resources Ltd., an oil and gas acquisition,
exploitation and development company, and has been in that
position since September 2009. Mr. Tywoniuk previously
acted as an independent consultant in accounting and finance
from March 2007 to June 2008. From December 2002 through
November 2006, Mr. Tywoniuk was Senior Vice President
and Chief Financial Officer of Pacific Energy Partners, LP. From
November 2006 to March 2007, Mr. Tywoniuk assisted with the
integration of Pacific Energy Partners, LP after it was acquired
by Plains All American Pipeline, L.P. Mr. Tywoniuk holds a
Bachelor of Commerce degree from The University of Alberta,
Canada, and is a Canadian chartered accountant.
Mr. Tywoniuk joined Pacific Energy Resources Ltd. in June
2008 as Senior Vice President, Finance to help the management
team work through the companys financially distressed
situation. In August 2008, he was appointed as the
companys Chief Financial Officer. The board of the company
elected to file for Chapter 11 protection in March 2009
and, in September 2009, following the departure of the CEO and
the President, Mr. Tywoniuk assumed the role of acting CEO.
In December 2009, the company completed the sale of its assets,
and is now working through the remaining steps of liquidation.
Mr. Tywoniuk has 28 years of experience in accounting
and finance, including 12 years as the Chief Financial
Officer of three public companies and Controller of a fourth
public company. Mr. Tywoniuks extensive accounting,
financial and executive management experience, as well as his
in-depth knowledge of the mining industry generally and our
partnership in particular, and his prior experience with
publicly traded partnerships, provide him with the necessary
skills to be Chair of the Audit Committee of the board of
directors of our general partner, where he also qualifies as an
audit committee financial expert.
Compensation
Discussion and Analysis
The following is a discussion of the compensation policies and
decisions of the board of directors of our general partner, or
the Board, and the Compensation Committee with respect to the
following individuals, who are executive officers of our general
partner and referred to as the named executive
officers:
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Charles C. Ungurean, President and Chief Executive Officer;
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Jeffrey M. Gutman, Senior Vice President, Chief Financial
Officer and Treasurer;
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Thomas T. Ungurean, Senior Vice President, Equipment,
Procurement and Maintenance;
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Gregory J. Honish, Senior Vice President, Operations; and
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Michael B. Gardner, Secretary and General Counsel.
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Our compensation program is designed to recruit and retain as
executive officers individuals with the highest capacity to
develop, grow and manage our business, and to align their
compensation with our short-term and long-term goals. To do
this, our compensation program for executive officers is made up
of the following components: (i) base salary, designed to
compensate our executive officers for work performed during the
fiscal year; (ii) short-term incentive programs, designed
to reward our executive officers for our yearly performance and
for their individual performances during the fiscal year; and
(iii) equity-based awards, meant to align our executive
officers interests with our long-term performance.
128
Role
of the Board, the Compensation Committee and
Management
Our general partner, under the direction of the Board, is
responsible for the management of our operations and employs all
of the employees that operate our business. Historically, from
our formation in August 2007 through compensation decisions made
in early 2010, decisions with respect to the compensation of
executive officers were made by the Board, based primarily on
negotiations between our management group and the directors on
our Board that were not employees of our general partner. In
connection with this offering, we have revised certain policies
and practices with respect to executive compensation. In
particular, the Board has appointed the Compensation Committee
to help the board administer certain aspects of the compensation
policies and programs for our executive officers and certain
other employees and to make recommendations to the Board
relating to the compensation of the directors and executive
officers of our general partner. The Compensation Committee and
the Board are charged with, among other things, the
responsibility of reviewing executive officer compensation
policies and practices to ensure (i) adherence to our
compensation philosophies and (ii) that the total
compensation paid to our executive officers is fair, reasonable
and competitive.
The compensation programs for our executive officers consist of
base salaries, annual incentive bonuses and awards under the
Oxford Resource Partners, LP Long-Term Incentive Plan, which we
refer to as our LTIP, in the form of equity-based phantom units,
as well as other customary employment benefits. We expect that
total compensation of our executive officers and the components
and relative emphasis among components of their annual
compensation will be reviewed on at least an annual basis by the
Compensation Committee with any proposed changes recommended to
the Board for final approval.
During 2009, the Board discussed compensation issues at several
meetings. The Compensation Committee expects to hold
compensation-related meetings for 2010 and in future years.
Topics discussed and to be discussed at these meetings included
and will include, among other things, (i) assessing the
performance of the Chief Executive Officer, or the CEO, and
other senior officers with respect to our results for the prior
year, (ii) reviewing and assessing the personal performance
of the senior officers for the preceding year and
(iii) determining the amount of the bonus pool to be
approved by the Board and paid to our executive officers for a
given year after taking into account the target bonus levels
established for those executive officers at the outset of the
year. In addition, at these meetings, and after taking into
account the recommendations of our CEO with respect to executive
officers other than our CEO, base salary levels and target bonus
levels (representing the bonus that may be awarded expressed as
a percentage of base salary or as a dollar amount for the year)
for our executive officers to be recommended to the Board will
be established by the Compensation Committee. In addition, the
Compensation Committee will make its recommendations to the
Board with respect to any awards under the LTIP.
Compensation
Objectives and Methodology
The principal objective of our executive compensation program is
to attract and retain individuals of demonstrated competence,
experience and leadership who share our business aspirations,
values, ethics and culture. A further objective is to provide
incentives to and reward our executive officers and other key
employees for positive contributions to our business and
operations, and to align their interests with our
unitholders interests.
In setting our compensation programs, we consider the following
objectives:
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to create unitholder value through sustainable earnings and cash
available for distribution;
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to provide a significant percentage of total compensation that
is at-risk or variable;
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to encourage significant equity holdings to align the interests
of executive officers and other key employees with those of
unitholders;
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to provide competitive, performance-based compensation programs
that allow us to attract and retain superior talent; and
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129
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to develop a strong linkage between business performance,
safety, environmental stewardship, cooperation and executive
compensation.
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Taking account of the foregoing objectives, we structure total
compensation for our executives to provide a guaranteed amount
of cash compensation in the form of competitive base salaries,
while also providing a meaningful amount of annual cash
compensation that is at risk and dependent on our performance
and individual performances of the executives, in the form of
discretionary annual bonuses. We also seek to provide a portion
of total compensation in the form of equity-based awards under
our LTIP, in order to align the interests of executives and
other key employees with those of our unitholders and for
retention purposes. Historically, we have not made regular
annual grants of awards under our LTIP. Instead, such awards
have typically been made in connection with our formation, upon
commencement of employment for executives who joined us after
our formation, and in discrete circumstances to reward service
or performance. Going forward, we expect that equity-based
awards will be made more regularly and that equity-based awards
will become more prominent in our annual compensation
decision-making process.
Compensation decisions for individual executive officers are the
result of the subjective analysis of a number of factors,
including the individual executive officers experience,
skills or tenure with us and changes to the individual executive
officers position. In measuring the contributions of
executive officers and our performance, a variety of financial
measures are considered, including non-GAAP financial measures
used by management to assess our financial performance, such as
Adjusted EBITDA and cash available for distribution. For a
definition of Adjusted EBITDA, please read Selected
Historical and Pro Forma Consolidated Financial and Operating
Data. For a discussion of the general concept of
cash available for distribution, please read
Cash Distribution Policy and Restrictions on
Distributions. In addition, a variety of factors related
to the individual performance of the executive officer are taken
into consideration.
In making individual compensation decisions, the Board
historically has not relied on pre-determined performance goals
or targets. Instead, determinations regarding compensation have
been and are expected to continue to be the result of the
exercise of judgment based on all reasonably available
information and, to that extent, are discretionary. Each
executive officers current and prior compensation is
considered in setting future compensation. The amount of each
executive officers current compensation is considered as a
base against which determinations are made as to whether
increases are appropriate to retain the executive officer in
light of competition or in order to provide continuing
performance incentives. The Board has discretion to adjust any
of the components of compensation to achieve our goal of
recruiting, promoting and retaining as executive officers,
individuals with the skills necessary to execute our business
strategy and develop, grow and manage our business.
Prior to 2010, we did not review executive compensation against
a specific group of comparable companies. Rather, the Board has
historically relied upon the judgment and industry experience of
its non-employee directors in making decisions with respect to
total compensation and with respect to the allocation of total
compensation among our three main components of compensation.
Going forward, we expect that the Compensation Committee will
make compensation recommendations to the Board based upon trends
occurring within our industry, including from a peer group of
companies that our Compensation Committee has recently
identified, which includes the following coal companies and
similar-sized publicly traded partnerships: Alliance Resource
Partners, L.P., National Coal Corp., Westmoreland Coal Co.,
James River Coal Co., International Coal Group, Inc., Patriot
Coal Corporation, Vanguard Natural Resources, LLC, Global
Partners LP, Legacy Reserves LP, Copano Energy LLC, Suburban
Propane Partners LP and Crosstex Energy Inc.
Elements
of the Compensation Programs
Overall, the executive officer compensation programs are
designed to be consistent with the philosophy and objectives set
forth above. The principal elements of our executive officer
compensation programs are summarized in the table below,
followed by a more detailed discussion of each compensation
element.
130
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Element
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Characteristics
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Purpose
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Base Salaries
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Fixed annual cash compensation. Executive officers are eligible
for periodic increases in base salaries. Increases may be based
on performance or such other factors as the Board or the
Compensation Committee may determine.
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Keep our annual compensation competitive with the defined market
for skills and experience necessary to execute our business
strategy.
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Annual Incentive
Bonuses
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Performance-related annual cash incentives earned based on our
objectives and individual performance of the executive officers.
Beginning in 2010, trends for our peer group will be taken into
account in setting future annual cash incentive awards for our
executive officers.
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Align performance to our objectives that drive our business and
reward executive officers for achievement of both our
performance objectives and individual performance objectives.
Amounts earned for achievement of target performance levels are
designed to provide competitive total direct compensation;
potential for awards above or below target amounts are intended
to motivate executive officers to achieve or exceed our
financial and operational goals.
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Equity-Based Awards
(phantom-units)
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Performance-related, equity-based awards granted at the
discretion of the Board. Awards are based on our performance
and, beginning in 2010, will be based on competitive practices
at peer companies. Grants typically vest ratably over four years
and will be settled upon vesting with either a net cash payment
or an issuance of common units, at the discretion of the Board.
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Align interests of executive officers with unitholders and
motivate and reward executive officers to increase unitholder
value over the long term. Ratable vesting over a four-year
period is designed to facilitate retention of executive
officers.
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131
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Element
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Characteristics
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Purpose
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Retirement Plan
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Qualified retirement plan benefits are available for our
executive officers and all other regular full-time employees.
Through 2009, we maintained a defined contribution money
purchase pension plan to which we made contributions for the
benefit of the participants. Effective with 2010, we have
adopted and are maintaining a tax-deferred or after-tax 401(k)
plan in which all eligible employees can elect to defer
compensation for retirement up to IRS imposed limits. The 401(k)
plan permits us to make annual discretionary contributions to
the plan, even if the participants do not contribute, as a
percentage of the eligible compensation of participants in the
plan. Annual contributions of 3% or more of such eligible
compensation will maintain safe harbor tax-qualified
status for the plan, and while it is discretionary, we intend
generally to make annual contributions at that level or higher.
For 2010, we have committed to make an employer discretionary
contribution of 4% of such eligible compensation.
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Provide our executive officers and other employees with the
opportunity to save for their future retirement.
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Health and Welfare
Benefits
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Health and welfare benefits (medical, dental, vision, disability
insurance and life insurance) are available for our executive
officers and all other regular full-time employees.
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Provide benefits to meet the health and wellness needs of our
executive officers and other employees and their families.
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Base
Salaries
Design.
Base salaries for our executive
officers are determined annually by an assessment of our overall
financial and operating performance, each executive
officers performance evaluation and changes in executive
officer responsibilities. While many aspects of performance can
be measured in financial terms, senior management is also
evaluated in areas of performance that are more subjective.
These areas include the development and execution of strategic
plans, the exercise of leadership in the development of
management and other employees, innovation and improvement in
our business activities and each executive officers
involvement in industry groups and in the communities that we
serve. We seek to compensate executive officers for their
performance throughout the year with annual base salaries that
are fair and competitive within our marketplace. We believe that
executive officer base salaries should be competitive with
salaries for executive officers in similar positions and with
similar responsibilities in our marketplace and adjusted for
financial and operating performance and each executive
officers performance evaluation, length of service with us
and previous work experience. Individual salaries have
historically been established by the Board based on the general
industry knowledge and experience of the directors on our Board
that were not employees of our general partner, in alignment
with these considerations and with reference to industry survey
data, to ensure the attraction, development and retention of
superior talent. Going forward, we expect that determinations
will continue to focus on the above considerations and will also
be made based upon relevant market data, including data from our
peer group.
132
Base salaries are reviewed annually to ensure continuing
consistency with market levels and our level of financial
performance during the previous year. Future adjustments to base
salaries and salary ranges will reflect average movement in the
competitive market as well as individual performance. Annual
base salary adjustments, if any, for the CEO have been
determined by the directors on our Board that are not employees
of our general partner, or the Non-employee Directors. After
this offering, annual base salary adjustments for the CEO will
be approved by the Non-employee Directors based upon
recommendations from the Compensation Committee. Annual base
salary adjustments, if any, for the other executive officers
have been determined by the Board taking into account input from
the CEO. After this offering, annual base salary adjustments for
the other executive officers will be approved by the Board based
upon recommendations from the Compensation Committee, which
recommendations may take into account input from the CEO.
Actions Taken With Respect to Base Salaries in
2009.
Effective May 1, 2009 (except
effective March 30, 2009 in the case of Gregory J. Honish),
the Board provided base salary increases to each of the named
executive officers as provided in the table below. These base
salary increases were provided as merit increases
based on the Boards subjective assessment of each named
executive officers performance in 2008 and early 2009,
considering a variety of factors, none of which was individually
material to such assessment, and to ensure that the base
salaries for the named executive officers remained competitive
with other companies in our industry. In addition, for Gregory
J. Honish, the increase reflected in part his promotion to
Senior Vice President, Operations.
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Base Salary at
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Base Salary Increase
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2009 Base Salary
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Name
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Start of 2009
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in 2009
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Following Increase
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Charles C. Ungurean
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$
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300,000
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$
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75,000
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$
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375,000
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Jeffrey M. Gutman
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250,000
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10,000
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260,000
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Thomas T. Ungurean
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200,000
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25,000
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225,000
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Gregory J. Honish
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110,000
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40,000
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150,000
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Michael B. Gardner
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133,000
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12,000
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145,000
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Annual
Incentive Bonuses
Design.
As one way of accomplishing
compensation objectives, executive officers are rewarded for
their contribution to our financial and operational success
through the award of discretionary annual cash incentive
bonuses. Annual incentive awards, if any, for the CEO have been
determined by the Non-employee Directors. After this offering,
annual incentive awards, if any, for the CEO will be approved by
the Non-employee Directors based upon recommendations from the
Compensation Committee. Annual incentive awards, if any, for the
other executive officers have been determined by the Board
taking into account input from the CEO. After this offering,
annual incentive awards for the other executive officers will be
approved by the Board based upon recommendations from the
Compensation Committee, which recommendations may take into
account input from the CEO.
While target bonuses for our executive officers are initially
set at percentages or dollar amounts that are 50% to 75% of
their base salaries, the Board has broad discretion to retain,
reduce or increase the award amounts when making its final bonus
determinations. For executive officers other than Charles C.
Ungurean and Thomas T. Ungurean, certain target bonus amounts
were individually negotiated with the executive officers and are
set forth in their employment agreements, which are discussed in
more detail under Employment and Severance
Agreements below. Although the employment agreements for
Charles C. Ungurean and Thomas T. Ungurean provide that these
executives are not eligible to receive annual incentive bonuses,
the Board has historically paid annual bonuses to these
executive officers in order to motivate them to achieve superior
performance and to provide them with competitive amounts of
total compensation.
The annual incentive bonus award for each executive officer is
contingent on the executive officers continued employment
with our general partner at the time of the award. Further,
bonuses (similar to other elements of the compensation provided
to executive officers) are not based on a prescribed formula or
pre-determined goals or specified performance targets but rather
have been determined on a subjective basis and generally have
been based on a subjective evaluation of individual,
company-wide and industry performances.
133
The Board and the Compensation Committee believe that this
approach to assessing performance results in a more
comprehensive evaluation for compensation decisions. The Board
has recognized, and the Compensation Committee will recognize,
the following factors in making discretionary annual bonus
recommendations and determinations:
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a subjective performance evaluation based on company-wide
financial and individual qualitative performance, as determined
in the Boards discretion; and
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the scope, level of expertise and experience required for the
executive officers position.
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These factors were selected as the most appropriate measures
upon which to base the annual incentive cash bonus decisions
because our Board believes that they help to align individual
compensation with competency and contribution. With respect to
its evaluation of company-wide financial performance, although
no pre-determined numerical goals are established, the Board
generally reviews our results with respect to Adjusted EBITDA
and cash available for distribution in making annual bonus
determinations.
Following its performance assessment, and based on our financial
performance with respect to these criteria and the Boards
qualitative assessment of individual performance, and in order
to provide total cash compensation for the year that was
competitive and consistent with total cash compensation provided
by other companies in our industry, as determined by the
directors on the Board who are not employees of our general
partner and based on their industry knowledge and experience,
the Board determined to award the incentive bonus amounts set
forth in the table below to our named executive officers for
performance in 2009. For the named executive officers with
target bonus amounts set forth in their employment agreements,
these awards represented approximately 85%-90% of the applicable
target bonus amounts.
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Name
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2009
Bonus
(1)
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Charles C. Ungurean
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$
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225,000
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Jeffrey M. Gutman
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112,500
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Thomas T. Ungurean
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175,000
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Gregory J. Honish
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63,750
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Michael B. Gardner
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61,625
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(1)
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Amounts shown in this column do not include vacation pay amounts
included in bonus amounts in the Summary Compensation Table for
2009 below.
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Beginning in 2010, the Compensation Committee expects that it
will base annual incentive compensation award recommendations on
additional company-wide criteria as well as industry criteria,
recognizing the following factors as part of its determination
of annual incentive bonuses (without assigning any particular
weighting to any factor):
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financial performance for the prior fiscal year, including
Adjusted EBITDA and cash available for distribution, in
comparison to guidance provided to the marketplace during the
prior fiscal year;
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distribution performance for the prior fiscal year compared to
the peer group;
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unitholder total return for the prior fiscal year compared to
the peer group; and
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competitive compensation data of executive officers in the peer
group.
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These factors were selected as the most appropriate measures
upon which to base the annual cash incentive bonus decisions
going forward because the Compensation Committee believes that
they will most directly correlate to increases in long-term
value for our unitholders.
Equity-Based
Awards
Design.
The LTIP was adopted in 2007 in
connection with our formation. In adopting the LTIP, the Board
recognized that it needed a source of equity to attract new
members to and retain members of the
134
management team, as well as to provide an equity incentive to
other key employees. We believe the LTIP promotes a long-term
focus on results and aligns executive and unitholder interests.
The LTIP is designed to encourage responsible and profitable
growth while taking into account non-routine factors that may be
integral to our success. Long-term incentive compensation in the
form of equity grants are used to incentivize performance that
leads to enhanced unitholder value, encourage retention and
closely align the executive officers interests with
unitholders interests. Equity grants provide a vital link
between the long-term results achieved for our unitholders and
the rewards provided to executive officers and other key
employees. The equity grants we made upon adoption of the LTIP
were designed to be comparable with long-term incentive plans of
other coal production companies and coal master limited
partnerships, based upon the industry knowledge and experience
of the directors on the Board who are not employees of our
general partner, and on individual negotiations with the named
executive officers.
Phantom Units.
The only awards made under the
LTIP since its adoption have been phantom units. Phantom units
are a notional unit granted under the LTIP that entitles the
holder to receive an amount of cash equal to the fair market
value of one common unit upon vesting of the phantom unit,
unless the Board elects to pay such vested phantom unit with a
common unit in lieu of cash. Unvested phantom units are
forfeited at the time the holder terminates employment. In
general, phantom units awarded under our LTIP vest as to 25% of
the award on the initial vesting date established at the time of
the award and on each of the first three anniversaries of that
initial vesting date.
Equity-Based Award Policies.
Prior to 2010,
equity-based awards were granted by the Board and were limited
to the grants at our formation in 2007 (or for executives who
joined us after our formation, upon or in connection with their
commencement of employment) and grants that were made in certain
limited circumstances to reward individual service and
performance. In early 2010, the Board delegated a portion of its
duties and responsibilities under the LTIP to the Compensation
Committee. Going forward, we expect that equity-based awards
will be awarded more regularly, as part of the ongoing total
annual compensation package for executive officers, rather than
only in such discrete circumstances. After this offering, annual
equity compensation grants, if any, for the CEO will be approved
by the Non-employee Directors based upon recommendations from
the Compensation Committee. Equity compensation grants, if any,
for the other executive officers have been determined by the
Board taking into account input from the CEO. After this
offering, annual equity compensation grants for the other
executive officers will be approved by the Board based upon
recommendations from the Compensation Committee, which
recommendations may take into account input from the CEO.
Equity-Based Awards for 2009.
None of our
named executive officers received any equity-based awards under
the LTIP in 2009. However, in January 2010, Jeffrey M. Gutman
received an award of 14,984 phantom units in recognition of his
performance in connection with a restructuring of certain of our
indebtedness and the completion of the Phoenix Coal acquisition
in September 2009. In making this award, the Board also took
into account its determination that the initial equity awards
granted to Mr. Gutman in connection with his commencement
of employment in 2008 were, in the Boards view based on
its general industry knowledge and experience, below the level
of equity participation granted to similarly situated executives
at many other companies in our industry.
Deferred
Compensation
Tax-deferred retirement plans are a common way that companies
assist employees in preparing for retirement. Through 2009, we
maintained a defined contribution money purchase pension plan to
which we made contributions for the benefit of the participants,
including named executive officers. Effective beginning in 2010,
we provide our eligible executive officers and other employees
with an opportunity to participate in our tax-deferred or
after-tax 401(k) savings plan. The plan allows executive
officers and other employees to defer compensation for
retirement up to IRS imposed limits (for 2010, $16,500 for
participants age 49 and under and $22,000 for participants
age 50 and over). The 401(k) plan permits us to make annual
discretionary contributions to the plan as a percentage of the
eligible compensation of participants in the plan. Annual
contributions of 3% or more of such eligible compensation will
maintain safe harbor tax-qualified status for
135
the plan, and while it is discretionary we intend generally to
make annual contributions at that level or higher. For 2010, we
have committed to make an employer discretionary contribution of
4% of such eligible compensation. Decisions regarding this
element of compensation do not impact any other element of
compensation.
Perquisites
and Other Benefits
Although perquisites are not a significant factor in our
compensation programs, we provide certain limited perquisite and
personal benefits to certain of the named executive officers,
including the use primarily for business purposes (with personal
usage being limited to usage for commuting purposes) of
company-owned automobiles for Charles C. Ungurean and Thomas T.
Ungurean. We provide these benefits to assist the executive
officers in performing their services for us and they are not
factored into the Boards determinations with respect to
other elements of total compensation. In addition, under our
company-wide policy in effect through 2009, we maintained for
all salaried employees including the executive officers a
vacation program that provided additional annual payments to
each of our salaried employees including the executive officers
in the amount of his or her base salary over a period equal to
the vacation time allotted to him or her. This payment was in
addition to continuing the payment of base salaries for all
salaried employees including the executive officers during
periods when they were on vacation. Effective in 2010, the
vacation policy was changed so that no such additional payments
are made but base salaries will continue to be paid to the
salaried employees including the executive officers while they
are on vacation. The additional vacation-related payments made
to the named executive officers for 2009 are included in bonus
amounts and set forth in a footnote to the Summary Compensation
Table for 2009 below.
Recoupment
Policy
We currently do not have a recoupment policy applicable to
annual incentive bonuses or equity awards. The Compensation
Committee expects to continue to evaluate the need to adopt such
a policy, in light of current legislative policies as well as
economic and market conditions.
Employment
and Severance Arrangements
The Board and the Compensation Committee consider the
maintenance of a sound management team to be essential to
protecting and enhancing our best interests. To that end, we
recognize that the uncertainty that may exist among management
with respect to their at-will employment with our
general partner may result in the departure or distraction of
management personnel to our detriment. Accordingly, our general
partner has entered into employment agreements with each of our
named executive officers, which employment agreements contain
severance arrangements that we believe are appropriate to
encourage the continued attention and dedication of members of
our management. These employment agreements are described more
fully below under Potential Payment Upon
Termination or Change in Control Employment
Agreements with Named Executive Officers.
136
Summary
Compensation Table for 2009
The following table sets forth certain information with respect
to the compensation paid to the named executive officers for the
year ended December 31, 2009.
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All Other
|
|
|
|
|
|
|
Bonus
|
|
Compensation
|
|
Total
|
Name and Principal Position
|
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Salary
($)
(1)
|
|
($)
(2)
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|
($)
(3)
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($)
|
|
Charles C. Ungurean
President and Chief Executive Officer
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|
$
|
375,002
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|
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$
|
248,077
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|
|
$
|
17,702
|
|
|
$
|
640,781
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|
Jeffrey M. Gutman
Senior Vice President, Chief Financial Officer and Treasurer
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|
|
261,385
|
|
|
|
125,481
|
|
|
|
15,370
|
|
|
|
402,236
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|
Thomas T. Ungurean
Senior Vice President, Equipment, Procurement and Maintenance
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|
|
233,333
|
|
|
|
190,385
|
|
|
|
16,079
|
|
|
|
439,797
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Gregory J. Honish
Senior Vice President, Operations
|
|
|
142,116
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|
|
|
70,096
|
|
|
|
12,771
|
|
|
|
224,983
|
|
Michael B. Gardner
Secretary and General Counsel
|
|
|
152,083
|
|
|
|
75,567
|
|
|
|
13,560
|
|
|
|
241,210
|
|
|
|
|
(1)
|
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Amounts shown in this column represent base salaries paid to the
named executive officers in 2009 and include pro-rated amounts
based on the increases in base salaries that occurred in 2009.
|
|
(2)
|
|
The bonus amounts for the named executive officers reflect
bonuses paid in late 2009 and early 2010 that relate to services
performed in 2009, in the following amounts for each of the
named executive officers: Charles C. Ungurean: $225,000; Jeffrey
M. Gutman: $112,500; Thomas T. Ungurean: $175,000; Gregory J.
Honish: $63,750; and Michael B. Gardner: $61,625. The bonus
amounts also include vacation payments in 2009 (including in the
case of Michael B. Gardner an additional payment in early 2010
with respect to cancelled vacation time in late 2009 during
which he performed services for us), as follows: Charles C.
Ungurean: $23,077; Jeffrey M. Gutman: $12,981; Thomas T.
Ungurean: $15,385; Gregory J. Honish: $6,346; and Michael B.
Gardner: $13,942.
|
|
(3)
|
|
Amounts shown in this column include contributions being made to
our defined contribution money purchase pension plan for each of
the named executive officers with respect to services performed
in 2009, payments made in 2009 with respect to life insurance
benefits provided to each of the named executive officers and a
holiday-related allowance paid in 2009 to each of the named
executive officers. For each of Charles C. Ungurean and Thomas
T. Ungurean, who are provided company-owned automobiles
primarily for business use (with personal use being limited to
usage for commuting purposes), the amount shown also includes
the cost to us of providing an automobile to them for their use
for the estimated personal usage portion thereof for commuting
purposes (20% of the total cost in the case of Charles C.
Ungurean and 5% of the total cost in the case of Thomas T.
Ungurean) in the amount of $2,248 and $660, respectively.
|
Grants of
Plan-Based Awards for 2009
The named executive officers received no grants of plan-based
awards during the year ended December 31, 2009.
Outstanding
Equity-Based Awards at December 31, 2009
The following table provides information regarding outstanding
equity-based awards held by the named executive officers as of
December 31, 2009. All such equity-based awards consist of
phantom units granted
137
under the LTIP. Neither Charles C. Ungurean nor Thomas T.
Ungurean held any outstanding equity-based awards at
December 31, 2009. None of the named executive officers
hold outstanding option awards.
|
|
|
|
|
|
|
|
|
|
|
Unit Awards
|
|
|
|
|
Market Value of
|
|
|
Number of Phantom
|
|
Phantom Units That
|
|
|
Units That have Not
|
|
Have Not Vested
|
Name
|
|
Vested
(1)
|
|
($)
(2)
|
|
Jeffrey M. Gutman
Senior Vice President, Chief Financial Officer and Treasurer
|
|
|
14,848
|
|
|
$
|
258,801
|
|
Gregory J. Honish
Senior Vice President, Operations
|
|
|
5,128
|
|
|
|
89,381
|
|
Michael B. Gardner
Secretary and General Counsel
|
|
|
3,204
|
|
|
|
55,846
|
|
|
|
|
(1)
|
|
Mr. Gutmans remaining unvested units, which were
granted in 2008, will vest 50% on March 31, 2010 and 50% on
March 31, 2011. Messrs. Honishs and
Gardners remaining unvested units, which were granted in
2007, will vest 50% on December 1, 2010 and 50% on
December 1, 2011.
|
|
(2)
|
|
Based on the fair market value of our common units of $17.43 on
December 31, 2009.
|
Units
Vested in 2009
The following table shows the phantom unit awards that vested
during 2009. Charles C. Ungurean and Thomas T. Ungurean did not
hold or vest in any phantom unit awards in 2009 and none of the
named executive officers held or exercised any stock options in
2009.
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
Units Acquired
|
|
Value Realized on
|
Name
|
|
on Vesting (#)
|
|
Vesting ($)
|
|
Jeffrey M. Gutman
Senior Vice President, Chief Financial Officer and
Treasurer
(1)
|
|
|
7,425
|
|
|
$
|
83,160
|
|
Gregory J. Honish
Senior Vice President,
Operations
(2)
|
|
|
2,564
|
|
|
|
44,691
|
|
Michael B. Gardner
Secretary and General
Counsel
(2)
|
|
|
1,603
|
|
|
|
27,940
|
|
|
|
|
(1)
|
|
Mr. Gutmans units vested on March 31, 2009, and
the value realized amount reflects a unit value of $11.20 per
unit, the fair market value on such vesting date.
|
|
(2)
|
|
Units vested on December 1, 2009, and the value realized
amounts reflect a unit value of $17.43 per unit, the fair
market value on such vesting date.
|
Pension
Benefits
The named executive officers do not participate in any pension
plans and received no pension benefits (other than with respect
to our defined contribution money purchase pension plan) during
the year ended December 31, 2009.
Nonqualified
Deferred Compensation
The named executive officers do not participate in any
nonqualified deferred compensation plans and received no
nonqualified deferred compensation during the year ended
December 31, 2009.
138
Potential
Payment Upon Termination or Change in Control
Employment
Agreements with Named Executive Officers
Messrs. Charles Ungurean, Gutman, Thomas Ungurean, Honish
and Gardner have each entered into employment agreements with
our general partner. Each of the employment agreements had an
initial term of two years, with the exception of that of
Mr. Gardner which had an initial term of one year. The
employment agreements are each automatically renewable for
successive one-year periods unless terminated by providing at
least 90 days written notice prior to the commencement of
the next succeeding one-year period. The agreements establish
customary employment terms including base salaries, bonuses and
other incentive compensation and other benefits.
The employment agreements provide for, among other things, the
payment of severance benefits and in some cases the continuation
of certain benefits following certain terminations of employment
by our general partner prior to the expiration of the term
described in each of the employment agreements or the
termination of employment for Good Reason (as
defined in each of the employment agreements) by the executive
officer. If the executives employment is terminated by the
general partner without Cause (as defined in the
employment agreements) or the executive resigns for Good Reason,
the executive will have the right to a lump sum cash payment by
our general partner equal to one times (two times with respect
to Charles C. Ungurean and Thomas T. Ungurean) the
executives annual base salary on the date of such
termination, which will be subject to reimbursement by us to our
general partner. In addition, for Messrs. Charles Ungurean
and Thomas Ungurean, in the event of a termination due to death
or disability (as such term is defined in the employment
agreements), or by our general partner without Cause, the
executive and his dependents will be entitled to continued
participation in our general partners employee benefit
plans and insurance arrangements providing medical and dental
benefits in which they are enrolled at the time of such
termination for the remainder of the employment term, provided
that the continuation is permitted at the time of termination
under the terms of our general partners employee benefit
plans and insurance arrangements. Each of the foregoing
severance benefits are conditioned on the executive executing a
release of claims in favor of our general partner and its
affiliates including us.
Cause is defined in each employment agreement as the
executive having (i) engaged in gross negligence, gross
incompetence or willful misconduct in the performance of the
duties required of him hereunder, (ii) refused without
proper reason to perform the duties and responsibilities
required of him hereunder, (iii) willfully engaged in
conduct that is materially injurious to our general partner or
its affiliates including us (monetarily or otherwise),
(iv) committed an act of fraud, embezzlement or willful
breach of fiduciary duty to our general partner or an affiliate
including us (including the unauthorized disclosure of
confidential or proprietary material information of our general
partner or an affiliate including us or, in the case of
Mr. Gutmans employment agreement only, including
instead the unauthorized disclosure of information that is, and
is known or reasonably should have been known to the executive
to be, confidential or proprietary information of our general
partner or an affiliate including us) or (v) been convicted
of (or pleaded no contest to) a crime involving fraud,
dishonesty or moral turpitude or any felony. Good
Reason is defined in each employment agreement as a
termination by the executive in connection with or based upon
(i) a material diminution in the executives
responsibilities, duties or authority, (ii) a material
diminution in the executives base compensation or
(iii) a material breach by us of any material provision of
the employment agreement (and, in the case of
Mr. Gutmans employment agreement, a breach of
obligations with respect to his LTIP awards).
Each employment agreement also contains certain confidentiality
covenants prohibiting each executive officer from, among other
things, disclosing confidential information relating to our
general partner or any of its affiliates including us. The
employment agreements also contain non-competition and
non-solicitation restrictions continuing for a period of two
years (one year in the case of the employment agreements for
Messrs. Honish and Gardner) following termination of
employment.
Mr. Gutmans employment agreement also provides that,
upon a change in control with respect to us or our general
partner, Mr. Gutman will be entitled to accelerated vesting
of all of his unvested awards under the LTIP. Assuming that a
change in control with respect to us or our general partner had
occurred on December 31, 2009, Mr. Gutman would have
been entitled to accelerated vesting with respect to 14,848
139
phantom units that he held as of such date, having a fair market
value on such date of $258,801. In addition,
Mr. Gutmans employment agreement provides that, at
the time of an initial public offering involving us in which a
profits interest plan is adopted by our general partner,
Mr. Gutman will receive a 0.5% profits participation
interest in our general partner. The interest would vest over
the four-year period following the date of grant of the
interest, and would be subject to accelerated vesting upon a
change in control.
The following table shows the value of the severance benefits
and other benefits for the named executive officers under the
employment agreements, assuming each named executive officer had
terminated employment on December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Death or
|
|
Termination
|
|
Resignation for
|
|
|
|
|
Disability
|
|
Without Cause
|
|
Good Reason
|
Name
|
|
Payment Type
|
|
($)
|
|
($)
|
|
($)
|
|
Charles C. Ungurean
|
|
Cash severance
|
|
|
|
|
|
$
|
750,000
|
|
|
$
|
750,000
|
|
|
|
Benefit continuation
|
|
$
|
10,769
|
|
|
|
10,769
|
|
|
|
|
|
|
|
Total
|
|
|
10,769
|
|
|
|
760,769
|
|
|
|
750,000
|
|
Thomas T. Ungurean
|
|
Cash severance
|
|
|
|
|
|
|
450,000
|
|
|
|
450,000
|
|
|
|
Benefit continuation
|
|
|
9,212
|
|
|
|
9,212
|
|
|
|
|
|
|
|
Total
|
|
|
9,212
|
|
|
|
459,212
|
|
|
|
450,000
|
|
Jeffrey M. Gutman
|
|
Cash severance
|
|
|
|
|
|
|
260,000
|
|
|
|
260,000
|
|
Gregory J. Honish
|
|
Cash severance
|
|
|
|
|
|
|
150,000
|
|
|
|
150,000
|
|
Michael B. Gardner
|
|
Cash severance
|
|
|
|
|
|
|
145,000
|
|
|
|
145,000
|
|
Long-Term
Incentive Plan
The board of directors of our general partner has adopted our
LTIP for employees, consultants and directors of our general
partner and affiliates who perform services for us. The LTIP
includes five components: options, distribution equivalent
rights, phantom units, restricted units and unit awards. The
LTIP limits the number of units that may be delivered pursuant
to awards of common units. Units withheld to satisfy exercise
prices or tax withholding obligations are available for delivery
pursuant to other awards. The plan is administered by the board
of directors of our general partner or a committee thereof
(effective in 2010, the Compensation Committee), which we refer
to as the plan administrator.
The plan administrator may terminate or amend the LTIP at any
time with respect to any units for which a grant has not yet
been made. The plan administrator also has the right to alter or
amend the LTIP or any part thereof from time to time, including
increasing the number of units that may be granted, subject to
unitholder approval as required by the exchange upon which the
common units are listed at that time. However, no change in any
outstanding grant may be made that would materially reduce the
benefits of the participant without the consent of the
participant. The plan will expire when units are no longer
available under the plan for grants, upon its termination by the
plan administrator or upon the tenth anniversary of the date
that the LTIP was adopted by our general partner (or such
earlier anniversary, if any, required by the rules of the
exchange on which our common units are listed at that time).
Retirement
Plan
We provide qualified retirement plan benefits to our executive
officers and all other eligible employees. Through 2009, we
maintained a defined contribution money purchase pension plan to
which we made contributions for the benefit of the participants.
Effective with 2010, we adopted a tax-deferred or after-tax
401(k) plan in which all eligible employees can elect to defer
compensation for retirement. We use the 401(k) plan to assist
our eligible employees in saving for retirement on a
tax-deferred or after-tax basis. The 401(k) plan permits all
eligible employees to make voluntary pre-tax contributions to
the plan, subject to applicable tax limitations. Employee
contributions are subject to annual dollar limitations (for
2010, $16,500 for participants age 49 and under and $22,000
for participants age 50 and over), which are periodically
adjusted for inflation. The tax deferred 401(k) plan is intended
to be tax-qualified under section 401(a) of the Internal
Revenue Code so that contributions to the plan, and income
earned on plan contributions, are not taxable to employees until
withdrawn from the plan and so that tax-deferred contributions,
if any, will be deductible
140
when made. The plan permits us to make annual discretionary
contributions to the plan as a percentage of the eligible
compensation of participants in the plan. Annual contributions
of 3% or more of such eligible compensation will maintain
safe harbor tax-qualified status for the plan, and
while it is discretionary we intend generally to make annual
contributions at that level or higher. For 2010, we have
committed to make an employer discretionary contribution of 4%
of such eligible compensation.
Compensation
of Directors
Our general partners non-employee directors are
compensated for their service as directors under our general
partners Non-Employee Director Compensation Plan. Our
non-employee directors are directors that (i) are not an
officer or employee of our general partner or any of its
subsidiaries or affiliates, (ii) are not affiliated with or
related to any party that receives compensation from our general
partner or any of its subsidiaries and affiliates, and
(iii) have not entered into an arrangement with our general
partner or any of its subsidiaries and affiliates to receive
compensation from any such entity other than in respect of his
services as a member of the Board. Each non-employee director
will receive an annual compensation package consisting of the
following: (i) a $30,000 cash retainer,
(ii) restricted common units valued at $20,000 in the
aggregate and (iii) where applicable, a $10,000 cash
retainer for each committee chair position held. In addition,
each non-employee director will receive per meeting fees of:
(i) $1,000 for Board meetings attended in person,
(ii) where applicable, $500 for Board committee meetings
attended in person and (iii) $500 for telephonic Board
meetings and committee meetings greater than one hour in length.
Furthermore, each non-employee director may elect, with approval
of the Compensation Committee, to receive the cash components,
as outlined above, in the form of restricted common units
representing an equivalent value at the date of issuance. The
annual compensation package is paid to each non-employee
director based on his or her service on the Board for the period
beginning upon the date of his or her appointment to the Board.
If a non-employee directors service on the Board commences
on or after the first day of a fiscal year, such non-employee
director will receive a prorated annual compensation package for
such fiscal year. Restricted units awarded to non-employee
directors under the annual compensation package or upon first
election to the Board are granted under the LTIP and vest on the
date of grant. Cash distributions are to be paid on these
restricted units. Each non-employee director is also reimbursed
for
out-of-pocket
expenses in connection with attending meetings of the Board or
its committees. Each director will be fully indemnified by us
for actions associated with being a director of our general
partner to the extent permitted under Delaware law.
Director
Compensation Table for 2009
The following table sets forth the compensation paid to our
non-employee directors for the year ended December 31,
2009, as described above. None of our non-employee directors
held any unvested units as of December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fees Earned or
|
|
|
|
|
Name
|
|
Paid in Cash ($)
|
|
Unit Awards
($)
(1)
|
|
Total ($)
|
|
Gerald A. Tywoniuk
|
|
$
|
30,000
|
|
|
$
|
20,010
|
|
|
$
|
50,010
|
|
|
|
|
(1)
|
|
The amount in this column represents unit awards made to
directors under the LTIP in 2009. These awards were granted and
vested on December 1, 2009 and had a fair value of $17.43
per unit on such date.
|
141
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information regarding the
beneficial ownership of units following the consummation of this
offering and the related transactions by:
|
|
|
|
|
each person who is known to us to beneficially own more than 5%
or more of such units to be outstanding;
|
|
|
|
our general partner;
|
|
|
|
each of the named directors and executive officers of our
general partner; and
|
|
|
|
all of the directors and executive officers of our general
partner as a group.
|
All information with respect to beneficial ownership has been
furnished by the respective directors, officers or 5% or more
unitholders as the case may be.
Our general partner is owned 33.7% by C&T Coal and 66.3% by
AIM Oxford (both of which are reflected as 5% or more
unitholders in the table below). C&T Coal is owned by
Charles C. Ungurean and Thomas T. Ungurean, each a member of our
management team, and AIM Oxford is owned by AIM Coal LLC and
certain investment partnerships affiliated with AIM.
The amounts and percentage of units beneficially owned are
reported on the basis of regulations of the SEC governing the
determination of beneficial ownership of securities. Under the
rules of the SEC, a person is deemed to be a beneficial
owner of a security if that person has or shares
voting power, which includes the power to vote or to
direct the voting of such security, or investment
power, which includes the power to dispose of or to direct
the disposition of such security. Except as indicated by
footnote, the persons named in the table below have sole voting
and investment power with respect to all units shown as
beneficially owned by them, subject to community property laws
where applicable.
The percentage of units beneficially owned is based on a total
of common units
and
subordinated units outstanding immediately following this
offering.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
|
Subordinated
|
|
|
Subordinated
|
|
|
Percentage of
|
|
|
|
Common Units
|
|
|
Common Units
|
|
|
Units to be
|
|
|
Units to be
|
|
|
Total Units to be
|
|
|
|
to be Beneficially
|
|
|
to be Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
|
Beneficially
|
|
Name of Beneficial Owner
|
|
Owned
|
|
|
Owned
|
|
|
Owned
|
|
|
Owned
|
|
|
Owned
|
|
|
AIM Oxford Holdings,
LLC
(1)(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
C&T Coal,
Inc.
(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
George E.
McCown
(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Brian D.
Barlow
(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Matthew P.
Carbone
(2)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Gerald A.
Tywoniuk
(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Charles C.
Ungurean
(3)(4)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Thomas T.
Ungurean
(3)(4)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Jeffrey M.
Gutman
(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Gregory J.
Honish
(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Michael B.
Gardner
(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
Denise M.
Maksimoski
(3)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
All directors and executive officers as a group (consisting of
10 persons)
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
|
%
|
|
|
|
*
|
|
An asterisk indicates that the person or entity owns less than
one percent.
|
|
(1)
|
|
AIM Oxford Holdings, LLC is governed by its sole manager, AIM
Coal Management, LLC, a Delaware limited liability company. AIM
Coal Management, LLCs members consist of George E. McCown
and
|
142
|
|
|
|
|
Matthew P. Carbone, both directors of our general partner, and
Robert B. Hellman, Jr. Messrs. McCown, Carbone and Hellman,
in their capacity as members of AIM Coal Management, LLC, share
voting and investment power with respect to the common and
subordinated units owned by AIM Oxford Holdings, LLC.
|
|
(2)
|
|
The address for this person or entity is 950 Tower Lane,
Suite 800, Foster City, California 94404.
|
|
(3)
|
|
The address for this person or entity is 544 Chestnut Street,
P.O. Box 427, Coshocton, Ohio 43812.
|
|
(4)
|
|
Charles C. Ungurean and Thomas T. Ungurean, as the shareholders
of C&T Coal, Inc., share voting and investment power with
respect to the common and subordinated units owned by C&T
Coal, Inc.
|
143
CERTAIN
RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
After this offering, C&T Coal will
own
common units
and subordinated
units representing a combined %
limited partner interest in us
(or
common units
and
subordinated units representing a
combined % limited partner interest
in us, if the underwriters exercise their option to purchase
additional common units in full), and AIM Oxford will
own
common units
and subordinated
units representing a combined %
limited partner interest in us
(or
common units
and subordinated
units representing a combined %
limited partner interest in us, if the underwriters exercise
their option to purchase additional common units in full).
C&T Coal and AIM Oxford will own and control our general
partner which owns a 2.0% general partner interest in us and all
of our incentive distribution rights.
Distributions
and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to
be made by us to our general partner and its affiliates in
connection with the formation, ongoing operation and liquidation
of Oxford Resource Partners, LP. These distributions and
payments were determined by and among affiliated entities and,
consequently, are not the result of arms-length
negotiations.
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Pre-IPO Stage
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The consideration received by our general partner and its
affiliates prior to this offering
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common
units;
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subordinated
units;
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all of our incentive distribution
rights;
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2.0% general partner interest; and
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approximately
$ million in cash and
accounts receivable.
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Post-IPO Stage
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Distributions of available cash to our general partner and its
affiliates
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We will generally make cash distributions 98% to the
unitholders, including affiliates of our general partner, as the
holders of an aggregate
of
common units and all of the subordinated units and 2.0% to our
general partner. In addition, if distributions exceed the
minimum quarterly distribution and target distribution levels,
our general partner will be entitled to increasing percentages
of the distributions, up to 48% of the distributions above the
highest target distribution level.
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Assuming we have sufficient available cash to pay the full
minimum quarterly distribution on all of our outstanding units
for four quarters, our general partner and its affiliates would
receive an annual distribution of approximately
$ million on the 2.0% general
partner interest and approximately
$ million on their common
units and subordinated units.
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Payments to our general partner and its affiliates
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Our general partner will not receive a management fee or other
compensation for its management of Oxford Resource Partners, LP.
Our general partner and its affiliates will be reimbursed for
expenses incurred on our behalf. Our partnership agreement
provides that our general partner will determine the amount of
these expenses.
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Withdrawal or removal of our general partner
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If our general partner withdraws or is removed, its general
partner interest and its incentive distribution rights will
either be sold to the new general partner for cash or converted
into common units, in each case for an amount equal to the fair
market value of those interests. Please read The
Partnership Agreement Withdrawal or Removal of Our
General Partner.
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Liquidation Stage
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Liquidation
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Upon our liquidation, the partners, including our general
partner, will be entitled to receive liquidating distributions
according to their particular capital account balances.
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Ownership
Interests of Certain Executive Officers and Directors of Our
General Partner
Upon the closing of this offering, C&T Coal and AIM Oxford
will continue to own 100% of our general partner. Charles C.
Ungurean, the President and Chief Executive Officer of our
general partner, and Thomas T. Ungurean, the Senior Vice
President, Equipment, Procurement and Maintenance of our general
partner, own all of the equity interests in C&T Coal. In
addition, certain directors of our general partner are
principals of AIM and have ownership interests in AIM.
In addition to the 2.0% general partner interest in us, our
general partner owns the incentive distribution rights, which
entitle the holder to increasing percentages, up to a maximum of
48%, of the cash we distribute in excess of
$ per quarter, after the closing
of our initial public offering. Upon the closing of this
offering, C&T Coal will
own common
units
and
subordinated units, and AIM Oxford will
own
common units
and
subordinated units.
Advisory
Services Agreement
Upon our formation in August 2007, Oxford Mining Company entered
into an advisory services agreement with American Infrastructure
MLP Management, L.L.C. and American Infrastructure MLP PE
Management, L.L.C., which are affiliates of AIM, AIM Oxford and
certain directors of our general partner. Our advisors performed
financial and advisory services to us under this agreement,
which will be terminated in connection with this offering. Our
advisors received annual compensation in the amount of $250,000
plus a fee determined by a formula, taking into account the
increase in our gross revenue over the prior year. During 2009
we paid our advisors in excess of $307,000 for these services,
as well as $1.0 million in fees for services relating to an
amendment to our existing credit facility. During 2008 we paid
our advisors $225,000 for these services, and we did not pay our
advisors for these services in 2007. We were also obligated to
reimburse our advisors for expenses incurred by them in the
performance of their services to us.
Administrative
and Operational Services Agreement
On August 24, 2007, we entered into an administrative and
operational services agreement with Oxford Mining Company and
our general partner. Under the terms of the agreement, our
general partner provides services to us and is reimbursed for
all related costs incurred on our behalf. The services that our
general partner provides include, among other things, general
administrative and management services, human resources,
information technology, finance and accounting, corporate
development, real property, marketing, engineering, operations
(including mining operations), geologic services, risk
management and insurance services. During 2009, 2008 and 2007,
we paid our general partner approximately $45.2 million,
$14.3 million and $139,000, respectively, for services,
primarily related to payroll, performed under the agreement. Any
party may terminate the administrative and operational services
agreement by providing at least 30 days written
notice to the other parties of its intention to terminate the
agreement.
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Contribution
Agreements
In August 2007 we entered into a contribution and sale agreement
with our general partner, C&T Coal, AIM Oxford, Charles C.
Ungurean and Thomas C. Ungurean. Pursuant to the contribution
and sale agreement, each of C&T Coal, Charles C. Ungurean
and Thomas T. Ungurean (and any of their related parties) agreed
not to directly or indirectly compete with us or to disseminate
confidential information or trade secrets regarding us and our
subsidiaries.
In March 2008 we entered into a contribution agreement with our
general partner and AIM Oxford. Pursuant to this contribution
agreement, we received a contribution of $8,820,000 from AIM
Oxford as consideration for the issuance to AIM Oxford of
787,500 Class B common units. We also received a
contribution of $180,000 from our general partner as
consideration for the issuance to our general partner of
approximately 16,071 general partner units.
In September 2008 we entered into a contribution agreement with
our general partner, C&T Coal and AIM Oxford. Pursuant to
this contribution agreement, we received a contribution of
$686,000 from C&T Coal and a contribution of $1,274,000
from AIM Oxford as consideration for the issuance to C&T
Coal and AIM Oxford of 61,250 Class B common units and
113,750 Class B common units, respectively. We also
received a contribution of $40,000 from our general partner as
consideration for the issuance to our general partner of
approximately 3,571 general partner units.
In August 2009 we entered into a contribution agreement with
C&T Coal and AIM Oxford. Pursuant to this contribution
agreement, we received a contribution of $1,050,000 from
C&T Coal and $1,950,000 from AIM Oxford as consideration
for the issuance to C&T Coal and AIM Oxford of 35 deferred
participation units and 65 deferred participation units,
respectively.
In September 2009 we entered into a contribution and conversion
agreement with our general partner, C&T Coal and AIM
Oxford. Pursuant to the contribution and conversion agreement,
we received a contribution of $1,469,993.91 from C&T Coal
and $6,860,012.25 from AIM Oxford as consideration for the
issuance to C&T Coal and AIM Oxford of 84,337 Class B
common units and 393,575 Class B common units,
respectively. We also received a contribution of $231,224.62
from our general partner as consideration for the issuance to
our general partner of approximately 13,266 general partner
units. In connection with the execution of the contribution and
conversion agreement, C&T Coal and AIM Oxford elected to
convert their deferred participation units into approximately
60,241 Class B common units and approximately 111,876
Class B common units, respectively.
Investors
Rights Agreement
We entered into an investors rights agreement on
August 24, 2007 with our general partner, C&T Coal,
AIM Oxford, Charles C. Ungurean and Thomas C. Ungurean. Pursuant
to such agreement and subject to certain restrictions, C&T
Coal was granted certain demand and piggyback
registration rights. Pursuant to the terms of the agreement,
C&T Coal has the right to require us to file a registration
statement for the public sale of all of the common and
subordinated units it owns at any time after the offering. In
addition and subject to certain restrictions, if we sell any
common units in a registered underwritten offering, C&T
Coal will have the right to include its common units in that
offering; provided, however, that the managing underwriter or
underwriters of any such offering will have the right to limit
the number of common units to be included in such sale.
We will pay all expenses relating to any demand or piggyback
registration, except for fees and disbursements of any counsel
retained by C&T Coal and any underwriter or brokers
commission or discounts.
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Tunnel
Hill Partners, LP
The vast majority of the ownership interest in Tunnel Hill
Partners, LP is directly or indirectly owned by T&C Holdco,
LLC and AIM Tunnel Hill Holdings II, LLC. T&C Holdco is
wholly-owned by Charles C. Ungurean and Thomas T. Ungurean. AIM
Tunnel Hill Holdings II, LLC is indirectly owned by AIM.
We are a party to an environmental services agreement with
Tunnell Hill Reclamation LLC, a wholly owned subsidiary of
Tunnel Hill Partners, LP, pursuant to which we provide certain
landfill operational services. Receipts for these services for
2009 and 2008 were approximately $0.6 million and
$1.1 million, respectively. We had no such receipts for
2007.
In addition, pursuant to a mining agreement, Tunnell Hill
Reclamation LLC has granted us access to certain properties for
the purpose of conducting mining operations. As consideration
for such access, we have authorized the construction by Tunnel
Hill Reclamation LLC of future landfills or other waste disposal
facilities on such properties.
Policies
and Procedures for Review and Approval of Related Party
Transactions
We expect that we will adopt policies for the review, approval
and ratification of transactions with related persons as
required by Item 404(a) of
Regulation S-K.
Upon our adoption of governance guidelines, a director of our
general partner would be expected to bring to the attention of
the CEO or the board any conflict or potential conflict of
interest that may arise between the director or any affiliate of
the director, on the one hand, and the partnership or our
general partner, on the other hand. The resolution of any such
conflict or potential conflict should, at the discretion of the
board in light of the circumstances, be determined by a majority
of the disinterested directors.
If a conflict or potential conflict of interest arises between
us and our general partner, the resolution of any such conflict
or potential conflict should be addressed by the board in
accordance with the provisions of our partnership agreement. At
the discretion of the board in light of the circumstances, the
resolution may be determined by the board in its entirety or by
the Conflicts Committee.
Upon our adoption of a Code of Business Conduct, any executive
officer of our general partner will be required to avoid
conflicts of interest unless approved by the board of directors.
In the case of any sale of our equity in which an owner or
affiliate of an owner of our general partner participates, we
anticipate that our practice will be to obtain general approval
of the full board for the transaction. In connection therewith,
the board may elect to delegate authority to set the specific
terms to a pricing committee, consisting of the CEO and one
independent director, with the actions by the pricing committee
requiring unanimous approval.
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CONFLICTS
OF INTEREST AND FIDUCIARY DUTIES
Conflicts
of Interest
Conflicts of interest exist and may arise in the future as a
result of the relationships between our general partner and its
affiliates (including C&T Coal and AIM Oxford), on the one
hand, and us and our unaffiliated limited partners, on the other
hand. The directors and executive officers of our general
partner have fiduciary duties to manage our general partner in a
manner beneficial to its owners. At the same time, our general
partner has a fiduciary duty to manage us in a manner beneficial
to us and our unitholders.
Whenever a conflict arises between our general partner or its
affiliates, on the one hand, and us and our limited partners, on
the other hand, our general partner will resolve that conflict.
Our partnership agreement contains provisions that modify and
limit our general partners fiduciary duties to the
unitholders. Our partnership agreement also restricts the
remedies available to unitholders for actions taken by our
general partner that, without those limitations, might
constitute breaches of its fiduciary duty.
Our general partner will not be in breach of its obligations
under the partnership agreement or its fiduciary duties to us or
our unitholders if the resolution of the conflict is:
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approved by the Conflicts Committee, although our general
partner is not obligated to seek such approval;
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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
or any of its affiliates;
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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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fair and reasonable to us, taking into account the totality of
the relationships between the parties involved, including other
transactions that may be particularly favorable or advantageous
to us.
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Our general partner may, but is not required to, seek the
approval of such resolution from the Conflicts Committee. In
connection with a situation involving a conflict of interest,
any determination by our general partner involving the
resolution of the conflict of interest must be made in good
faith, provided that, if our general partner does not seek
approval from the Conflicts Committee and its board of directors
determines that the resolution or course of action taken with
respect to the conflict of interest satisfies either of the
standards set forth in the third and fourth bullet points 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. Unless the resolution of
a conflict is specifically provided for in our partnership
agreement, our general partner or the Conflicts Committee may
consider any factors it determines in good faith to consider
when resolving a conflict. When our partnership agreement
requires someone to act in good faith, it requires that person
to believe that he is acting in the best interests of the
partnership.
Conflicts of interest could arise in the situations described
below, among others.
AIM
Oxford and AIM, 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 (or as general partner of
another company of which we are a partner or member) or those
activities incidental to its ownership of interests in us. In
addition, C&T Coal and its affiliates are prohibited from
competing with us in Illinois, Kentucky, Ohio, Pennsylvania,
West Virginia and Virginia until August 2014. However, certain
affiliates of our general partner, including AIM Oxford and AIM
and its investment funds, are not prohibited from engaging in
other businesses or activities, including those that might be in
direct competition with us. Additionally, AIM, through its
investment funds and managed accounts, makes investments and
purchases entities in various areas of the energy sector,
including the coal industry. These investments and acquisitions
may include entities or assets that we would have been
interested in acquiring.
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Pursuant to the terms of our partnership agreement, the doctrine
of corporate opportunity, or any analogous doctrine, will not
apply to our general partner or any of its affiliates, including
its executive officers, directors, C&T Coal and AIM Oxford.
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.
Therefore, AIM Oxford may compete with us for investment
opportunities and may own an interest in entities that compete
with us. Until August 2014, C&T Coal and its affiliates may
only compete with us outside the six states referred to above.
Our general partner is allowed to take into account the
interests of parties other than us, such as C&T Coal and
AIM Oxford, in resolving conflicts.
Our partnership agreement contains provisions that 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. This entitles our general
partner to consider only the interests and factors that it
desires, and it has no duty or obligation to give any
consideration to any interest of, or factors affecting, us, our
affiliates or any limited partner. Examples include the exercise
of our general partners limited call right, its voting
rights with respect to the units it owns, its registration
rights and its determination whether or not to consent to any
merger or consolidation of the partnership.
Our partnership agreement limits the liability and reduces
the fiduciary duties owed by our general partner, and also
restricts the remedies available to our unitholders for actions
that, without those limitations, might constitute breaches of
its fiduciary duty.
In addition to the provisions described above, our partnership
agreement contains provisions that restrict the remedies
available to our unitholders for actions that might otherwise
constitute breaches of our general partners fiduciary
duty. For example, our partnership agreement:
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provides that our general partner shall not have any liability
to us or our unitholders for decisions made in its capacity as
general partner so long as such decisions are made in good faith
and with the belief that the decision was in our best interest;
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provides generally that affiliated transactions and resolutions
of conflicts of interest not approved by the Conflicts Committee
and not involving a vote of unitholders must either be
(1) on terms no less favorable to us than those generally
being provided to or available from unrelated third parties or
(2) fair and reasonable to us, as determined by
our general partner in good faith, provided that, in determining
whether a transaction or resolution is fair and
reasonable, our general partner may consider the totality
of the relationships between the parties involved, including
other transactions that may be particularly advantageous or
beneficial to us; and
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provides that our general partner and its executive officers and
directors will not be liable for monetary damages to us or our
limited partners or their assignees 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 executive officers
or directors acted in bad faith or engaged in fraud or willful
misconduct or, in the case of a criminal matter, acted with
knowledge that their conduct was criminal.
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Except
in limited circumstances, our general partner has the power and
authority to conduct our business without unitholder
approval
Under our partnership agreement, our general partner has full
power and authority to do all things, other than those items
that require unitholder approval or with respect to which our
general partner has sought
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Conflicts Committee approval, on such terms as it determines to
be necessary or appropriate to conduct our business including,
but not limited to, the following:
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the making of any expenditures, the lending or borrowing of
money, the assumption or guarantee of or other contracting for,
indebtedness and other liabilities, the issuance of evidences of
indebtedness, including indebtedness that is convertible into
our securities, and the incurring of any other obligations;
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the purchase, sale or other acquisition or disposition of our
securities, or the issuance of additional options, rights,
warrants and appreciation rights relating to our securities;
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the mortgage, pledge, encumbrance, hypothecation or exchange of
any or all of our assets;
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the negotiation, execution and performance of any contracts,
conveyances or other instruments;
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the distribution of our cash;
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the selection and dismissal of employees and agents, outside
attorneys, accountants, consultants and contractors and the
determination of their compensation and other terms of
employment or hiring;
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the maintenance of insurance for our benefit and the benefit of
our partners;
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the formation of, or acquisition of an interest in, the
contribution of property to, and the making of loans to, any
limited or general partnership, joint venture, corporation,
limited liability company or other entity;
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the control of any matters affecting our rights and obligations,
including the bringing and defending of actions at law or in
equity, otherwise engaging in the conduct of litigation,
arbitration or mediation and the incurring of legal expense, the
settlement of claims and litigation;
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the indemnification of any person against liabilities and
contingencies to the extent permitted by law;
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the making of tax, regulatory and other filings, or the
rendering of periodic or other reports to governmental or other
agencies having jurisdiction over our business or
assets; and
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the entering into of agreements with any of its affiliates to
render services to us or to itself in the discharge of its
duties as our general partner.
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Our partnership agreement provides that our general partner must
act in good faith when making decisions on our
behalf, and our partnership agreement further provides that in
order for a determination to be made in good faith,
our general partner must believe that the determination is in
our best interests. Please read The Partnership
Agreement Voting Rights for information
regarding matters that require unitholder approval.
Actions
taken by our general partner may affect the amount of cash
available for distribution to unitholders or accelerate the
right to convert subordinated units.
The amount of cash that is available for distribution to
unitholders is affected by decisions of our general partner
regarding such matters as:
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the amount and timing of asset purchases and sales;
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cash expenditures and the amount of estimated maintenance
capital expenditures;
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borrowings;
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the issuance of additional units; and
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the creation, reduction or increase of reserves in any quarter.
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Our general partner determines the amount and timing of any
capital expenditures and whether a capital expenditure is
classified as an estimated maintenance capital expenditure,
which reduces operating surplus, or an expansion capital
expenditure, which does not reduce operating surplus. This
determination can affect the
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amount of cash that is distributed to our unitholders and to our
general partner and the ability of the subordinated units to
convert into common units.
In addition, our general partner may use an amount, initially
equal to $ million, which
would not otherwise constitute available cash from operating
surplus, in order to permit the payment of cash distributions on
its units and incentive distribution rights. All of these
actions may affect the amount of cash distributed to our
unitholders and our general partner and may facilitate the
conversion of subordinated units into common units. Please read
How We Make Cash Distributions.
In addition, borrowings by us and our affiliates do not
constitute a breach of any duty owed by our general partner to
our unitholders, including borrowings that have the purpose or
effect of:
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enabling our general partner or its affiliates to receive
distributions on any subordinated units held by them or the
incentive distribution rights; or
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hastening the expiration of the subordination period.
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For example, in the event we have not generated sufficient cash
from our operations to pay the minimum quarterly distribution on
our common units and our subordinated units, our partnership
agreement permits us to borrow funds, which would enable us to
make this distribution on all outstanding units. Please read
How We Make Cash Distributions Subordination
Period.
Our partnership agreement provides that we and our subsidiaries
may borrow funds from our general partner and its affiliates.
Our general partner and its affiliates may not borrow funds from
us, or our operating company and its operating subsidiaries.
We
will reimburse our general partner and its affiliates for
expenses.
We will reimburse our general partner and its affiliates for
costs incurred in managing and operating us. Our partnership
agreement provides that our general partner will determine the
expenses that are allocable to us in good faith, and it will
charge on a fully allocated cost basis for services provided to
us. The fully allocated basis charged by our general partner
does not include a profit component. Please read Certain
Relationships and Related Party Transactions.
Contracts
between us, on the one hand, and our general partner and its
affiliates, on the other, will not be the result of
arms-length negotiations.
Our partnership agreement allows our general partner to
determine, in good faith, any amounts to pay itself or its
affiliates for any services rendered to us. Our general partner
may also enter into additional contractual arrangements with any
of its affiliates on our behalf. Neither our partnership
agreement nor any of the other agreements, contracts, and
arrangements between us and our general partner and its
affiliates are or will be the result of arms-length
negotiations. Similarly, agreements, contracts or arrangements
between us and our general partner and its affiliates that are
entered into following the closing of this offering will not be
required to be negotiated on an arms-length basis,
although, in some circumstances, our general partner may
determine that the Conflicts Committee may make a determination
on our behalf with respect to such arrangements.
Our general partner will determine, in good faith, the terms of
any of these transactions entered into after the close of this
offering.
Our general partner and its affiliates will have no obligation
to permit us to use any facilities or assets of our general
partner and its affiliates, except as may be provided in
contracts entered into specifically for such use. There is no
obligation of our general partner and its affiliates to enter
into any contracts of this kind.
Our
general partner intends to limit its liability regarding our
obligations.
Our general partner intends to limit its liability under
contractual arrangements so that counterparties to such
agreements have recourse only against our assets and not against
our general partner or its assets or any
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affiliate of our general partner or its assets. Our partnership
agreement provides that any action taken by our general partner
to limit its liability is not a breach of our general
partners fiduciary duties, even if we could have obtained
terms that are more favorable without the limitation on
liability.
Common
units are subject to our general partners limited call
right.
Our general partner may exercise its right to call and purchase
common units, as provided in our partnership agreement, or may
assign this right to one of its affiliates or to us. Our general
partner may use its own discretion, free of fiduciary duty
restrictions, in determining whether to exercise this right. As
a result, a common unitholder may have to sell his common units
at an undesirable time or price. Please read The
Partnership Agreement Limited Call Right.
Common
unitholders will have no right to enforce obligations of our
general partner and its affiliates under agreements with
us.
Any agreements between us, on the one hand, and our general
partner and its affiliates, on the other, will not grant to the
unitholders, separate and apart from us, the right to enforce
the obligations of our general partner and its affiliates in our
favor.
Our
general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
The attorneys, independent accountants and others who perform
services for us have been retained by our general partner.
Attorneys, independent accountants and others who perform
services for us are selected by our general partner or the
Conflicts Committee and may perform services for our general
partner and its affiliates. We may retain separate counsel for
ourselves or the holders of common units in the event of a
conflict of interest between our general partner and its
affiliates, on the one hand, and us or the holders of common
units, on the other, depending on the nature of the conflict. We
do not intend to do so in most cases.
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 partners incentive
distribution rights without the approval of the Conflicts
Committee or our unitholders. This election may result in lower
distributions to our common unitholders in certain
situations.
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%)
for each of the prior four consecutive fiscal quarters, to reset
the initial target distribution levels at higher levels based on
our cash distribution at the time of the exercise of the reset
election. Following a reset election by our general partner, the
minimum quarterly distribution will be reset to an amount equal
to the average cash distribution per common unit for the two
fiscal quarters immediately preceding the reset election (such
amount is referred to as the reset minimum quarterly
distribution), and the target distribution levels will be
reset to correspondingly higher levels based on percentage
increases above the reset minimum quarterly distribution.
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; however,
it is possible that our general partner could exercise this
reset election at a time when we are experiencing declines in
our aggregate cash distributions or at a time when our general
partner expects that we will experience declines in our
aggregate cash distributions in the foreseeable future. In such
situations, our general partner may be experiencing, or may
expect to experience, declines in the cash distributions it
receives related to its incentive distribution rights and may
therefore desire to be issued our common units, which are
entitled to specified priorities with respect to our
distributions and which therefore may be more advantageous for
the general partner to own in lieu of the right to receive
incentive distribution payments based on target distribution
levels that are less certain to be achieved in the then current
business environment. As a result, a reset election may cause
our common unitholders to experience dilution in the amount of
cash distributions that they would have otherwise received had
we not issued new common units to
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our general partner in connection with resetting the target
distribution levels related to our general partners
incentive distribution rights. Please read How We Make
Cash Distributions Distributions of Available
Cash General Partner Interest and Incentive
Distribution Rights.
Fiduciary
Duties
Our general partner is accountable to us and our unitholders as
a fiduciary. Fiduciary duties owed to unitholders by our general
partner are prescribed by law and the partnership agreement. The
Delaware Act provides that Delaware limited partnerships may, in
their partnership agreements, modify or eliminate, except for
the contractual covenant of good faith and fair dealing, the
fiduciary duties owed by the general partner to limited partners
and the partnership.
Our partnership agreement contains various provisions
restricting the fiduciary duties that might otherwise be owed by
our general partner. We have adopted these provisions to allow
our general partner or its affiliates to engage in transactions
with us that would otherwise be prohibited by state-law
fiduciary standards and to take into account the interests of
other parties in addition to our interests when resolving
conflicts of interest. Without such modifications, such
transactions could result in violations of our general
partners state-law fiduciary duty standards. We believe
this is appropriate and necessary because the board of directors
of our general partner has fiduciary duties to manage our
general partner in a manner beneficial both to its owners, as
well as to our unitholders. Without these modifications, our
general partners ability to make decisions involving
conflicts of interest would be restricted. The modifications to
the fiduciary standards enable our general partner to take into
consideration the interests of all parties involved, so long as
the resolution is fair and reasonable to us. These modifications
also enable our general partner to attract and retain
experienced and capable directors. These modifications
disadvantage the common unitholders because they restrict the
rights and remedies that would otherwise be available to
unitholders for actions that, without those limitations, might
constitute breaches of fiduciary duty, as described below, and
permit our general partner to take into account the interests of
third parties in addition to our interests when resolving
conflicts of interest. The following is a summary of the
material restrictions of the fiduciary duties owed by our
general partner to the limited partners:
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State law fiduciary duty standards
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Fiduciary duties are generally considered to include an
obligation to act in good faith and with due care and loyalty.
The duty of care, in the absence of a provision in a partnership
agreement providing otherwise, would generally require a general
partner to act for the partnership in the same manner as a
prudent person would act on his own behalf. The duty of
loyalty, in the absence of a provision in a partnership
agreement providing otherwise, would generally prohibit a
general partner of a Delaware limited partnership from taking
any action or engaging in any transaction where a conflict of
interest is present.
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Partnership agreement modified standards
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Our partnership agreement contains provisions that waive or
consent to conduct by our general partner and its affiliates
that might otherwise raise issues as to compliance with
fiduciary duties or applicable law. For example, our
partnership agreement provides that when our general partner is
acting in its capacity as our general partner, as opposed to in
its individual capacity, it must act in good faith
and will not be subject to any other standard under applicable
law. In addition, when our general partner is acting in its
individual capacity, as opposed to in its capacity as our
general partner, it may act without any fiduciary obligation to
us or our limited partners whatsoever. These standards reduce
the obligations to which our general partner would otherwise be
held.
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Our partnership agreement generally provides that affiliated
transactions and resolutions of conflicts of interest not
involving a vote of unitholders or that are not approved by the
Conflicts Committee must be:
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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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fair and reasonable to us,
taking into account the totality of the relationships between
the parties involved (including other transactions that may be
particularly favorable or advantageous to us).
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If our general partner does not seek approval from the Conflicts
Committee and its board of directors determines that the
resolution or course of action taken with respect to the
conflict of interest satisfies either of the standards set forth
in the bullet points above, then it will be presumed that, in
making its decision, the board of directors, which may include
board members affected by the conflict of interest, 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. These standards reduce the obligations to
which our general partner would otherwise be held.
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In addition to the other more specific provisions limiting the
obligations of our general partner, our partnership agreement
further provides that our general partner and its officers and
directors will not be liable for monetary damages to us, our
limited partners or assignees for errors of judgment or for any
acts or omissions unless there has been a final and
non-appealable judgment by a court of competent jurisdiction
determining that our general partner or its officers and
directors 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 unlawful.
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Rights and remedies of unitholders
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The Delaware Act generally provides that a limited partner may
institute legal action on behalf of the partnership to recover
damages from a third party where a general partner has refused
to institute the action or where an effort to cause a general
partner to do so is not likely to succeed. These actions
include actions against a general partner for breach of its
fiduciary duties or of the partnership agreement. In addition,
the statutory or case law of some jurisdictions may permit a
limited partner to institute legal action on behalf of himself
and all other similarly situated limited partners to recover
damages from a general partner for violations of its fiduciary
duties to the limited partners.
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In order to become one of our limited partners, a common
unitholder is required to agree to be bound by the provisions of
the partnership agreement, including the provisions discussed
above. Please read Description of the Common
Units Transfer of Common Units. This is in
accordance with the policy of the Delaware Act favoring the
principle of freedom of contract and the enforceability of
partnership agreements. The failure of a limited partner or
assignee to sign a partnership agreement does not render the
partnership agreement unenforceable against that person.
Under our partnership agreement, we must indemnify our general
partner and its officers, directors and managers, to the fullest
extent permitted by law, against liabilities, costs and expenses
incurred by our general partner or these other persons. We must
provide this indemnification unless there has been a final and
non-appealable judgment by a court of competent jurisdiction
determining that these persons 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 unlawful. We
also must provide this indemnification for criminal proceedings
when our general partner or these other persons acted with no
knowledge that their conduct was unlawful. Thus, our general
partner could be indemnified for its negligent acts if it met
the requirements set forth above. To the extent that these
provisions purport to include indemnification for liabilities
arising under the Securities Act of 1933, or the Securities Act,
in the opinion of the SEC, such indemnification is contrary to
public policy and therefore unenforceable. Please read The
Partnership Agreement Indemnification.
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DESCRIPTION
OF THE COMMON UNITS
The
Units
The common units represent limited partner interests in us. The
holders of common units, along with the holders of subordinated
units, are entitled to participate in partnership distributions
and are entitled to exercise the rights and privileges available
to limited partners under our partnership agreement. For a
description of the relative rights and preferences of holders of
common units and subordinated units and our general partner in
and to partnership distributions, please read this section and
How We Make Cash Distributions. For a description of
the rights and privileges of limited partners under our
partnership agreement, including voting rights, please read
The Partnership Agreement.
Transfer
Agent and Registrar
Duties
will serve as registrar and transfer agent for the common units.
We pay all fees charged by the transfer agent for transfers of
common units, except the following that must be paid by our
unitholders:
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surety bond premiums to replace lost or stolen certificates, or
to cover taxes and other governmental charges in connection
therewith;
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special charges for services requested by a holder of a common
unit; and
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other similar fees or charges.
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There is no charge to our unitholders for disbursements of our
cash distributions. We will indemnify the transfer agent, its
agents and each of their respective stockholders, directors,
officers and employees against all claims and losses that may
arise out of acts performed or omitted for its activities in
that capacity, except for any liability due to any gross
negligence or intentional misconduct of such person or entity.
Resignation
or Removal
The transfer agent may resign, by notice to us, or be removed by
us. The resignation or removal of the transfer agent will become
effective upon our appointment of a successor transfer agent and
registrar and its acceptance of the appointment. If no successor
has been appointed and has accepted the appointment within
30 days after notice of the resignation or removal, our
general partner may act as the transfer agent and registrar
until a successor is appointed.
Transfer
of Common Units
The transfer of the common units to persons that purchase
directly from the underwriters will be accomplished through the
proper completion, execution and delivery of a transfer
application by the investor. Any later transfers of the common
units will not be recorded by the transfer agent or recognized
by us unless the transferee executes and delivers a properly
completed transfer application. By executing and delivering a
transfer application, a transferee of common units:
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becomes the record holder of the transferred common units and is
an assignee until admitted into our partnership as a limited
partner;
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automatically requests admission as a limited partner in our
partnership;
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executes and agrees to be bound by the terms and conditions of
our partnership agreement;
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represents that such transferee has the capacity, power and
authority to enter into the partnership agreement;
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grants powers of attorney to the executive officers of our
general partner and any liquidator of us as specified in the
partnership agreement; and
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gives the consents, covenants, representations and approvals
contained in our partnership agreement, such as the approval of
all transactions and agreements we are entering into in
connection with this offering.
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An assignee will become a limited partner of our partnership for
the transferred common units automatically upon the recording of
the transfer on our books and records. Our general partner will
cause any unrecorded transfers for which a properly completed
and duly executed transfer application has been received to be
recorded on our books and records no less frequently than
quarterly.
A transferees broker, agent or nominee may complete,
execute and deliver a transfer application. We are entitled to
treat the nominee holder of common units as the absolute owner
thereof. In that case, the beneficial holders rights are
limited solely to those that it has against the nominee holder
as a result of any agreement between the beneficial owner and
the nominee holder.
Common units are securities and are transferable according to
the laws governing transfer of securities. In addition to other
rights acquired upon transfer, the transferor gives the
transferee the right to request admission as a limited partner
in our partnership for the transferred common units. A purchaser
or transferee of common units who does not execute and deliver a
properly completed transfer application obtains only:
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the right to transfer such common units to a purchaser or other
transferee; and
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the right to transfer the right to seek admission as a limited
partner in our partnership with respect to the transferred
common units.
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Thus, a purchaser or transferee of common units who does not
execute and deliver a properly completed transfer application:
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will not receive cash distributions;
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will not be allocated any of our income, gain, deduction, losses
or credits for federal income tax or other tax purposes;
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may not receive some federal income tax information or reports
furnished to record holders of common units; and
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will have no voting rights;
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unless the common units are held in a nominee or street
name account and the nominee or broker has executed and
delivered a transfer application and certification as to itself
and any beneficial holders.
The transferor of common units has a duty to provide the
transferee with all information that may be necessary to
transfer such common units. The transferor does not have a duty
to ensure the execution of the transfer application by the
transferee and has no liability or responsibility if the
transferee neglects or chooses not to execute and deliver a
properly completed transfer application to the transfer agent.
Please read The Partnership Agreement Status
as Limited Partner or Assignee.
Until common units have been transferred on our books, we and
the transfer agent may treat the record holder of such common
units as the absolute owner for all purposes, except as
otherwise required by law or stock exchange regulations.
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THE
PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our
partnership agreement. The form of our partnership agreement is
included in this prospectus as
Appendix A.
We will
provide prospective investors with a copy of this agreement upon
request at no charge.
We summarize the following provisions of our partnership
agreement elsewhere in this prospectus:
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with regard to distributions of available cash, please read
How We Make Cash Distributions;
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with regard to the fiduciary duties of our general partner,
please read Conflicts of Interest and Fiduciary
Duties;
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with regard to the transfer of common units, please read
Description of the Common Units Transfer of
Common Units; and
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with regard to allocations of taxable income and taxable loss,
please read Material Federal Income Tax Consequences.
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Organization
and Duration
We were organized in August 2007 and have a perpetual existence.
Purpose
Our purpose under the partnership agreement is limited to any
business activities that are approved by our general partner and
in any event that lawfully may be conducted by a limited
partnership organized under Delaware law; provided that our
general partner may not cause us to engage, directly or
indirectly, in any business activity that our general partner
determines would cause us to be treated as an association
taxable as a corporation or otherwise taxable as an entity for
federal income tax purposes.
Although our general partner has the power to cause us, our
operating company and its subsidiaries to engage in activities
other than coal mining and marketing, our general partner may
decline to do so free of any fiduciary duty or obligation
whatsoever to us or the limited partners, including any duty to
act in good faith or in the best interests of us or the limited
partners. However, any decision by our general partner to cause
us or our subsidiaries to invest in activities will be subject
to its fiduciary duties as modified by our partnership
agreement. In general, our general partner is authorized to
perform all acts it determines to be necessary or appropriate to
carry out our purposes and to conduct our business.
Power of
Attorney
Each limited partner and each person who acquires a unit from a
unitholder and executes and delivers a transfer application and
certification, grants to our general partner and, if appointed,
a liquidator, a power of attorney to, among other things,
execute and file documents required for our qualification,
continuance, or dissolution. The power of attorney also grants
our general partner the authority to amend, and to make consents
and waivers under, our partnership agreement.
Capital
Contributions
Unitholders are not obligated to make additional capital
contributions, except as described below under
Limited Liability.
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Voting
Rights
The following matters require the limited partner vote specified
below. Various matters require the approval of a unit
majority, which means:
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during the subordination period, the approval of a majority of
the outstanding common units, excluding those common units held
by our general partner and its affiliates, and a majority of the
outstanding subordinated units, each voting as a separate
class; and
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after the subordination period, the approval of a majority of
the outstanding common units.
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By virtue of the exclusion of those common units held by our
general partner and its affiliates from the required vote, and
by their ownership of all of the subordinated units, during the
subordination period our general partner and its affiliates do
not have the ability to ensure passage of, but do have the
ability to ensure defeat of, any amendment that requires a unit
majority.
In voting their common and subordinated units, our general
partner and its affiliates will have no fiduciary duty or
obligation whatsoever to us or our limited partners, including
any duty to act in good faith or in the best interests of us and
our limited partners.
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Issuance of additional units
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No approval rights.
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Amendment of our partnership agreement
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Certain amendments may be made by our general partner without
the approval of our limited partners. Other amendments
generally require the approval of a unit majority. Please read
Amendment of Our Partnership Agreement.
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Merger of our partnership or the sale of all or substantially
all of our assets
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Unit majority in certain circumstances. Please read
Merger, Sale or Other Disposition of
Assets.
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Continuation of our partnership upon dissolution
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Unit majority. Please read Termination and
Dissolution.
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Withdrawal of our general partner
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No approval rights. Please read Withdrawal or
Removal of Our General Partner.
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Removal of our general partner
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Not less than 80% of the outstanding common units and
subordinated units, voting as a single class, including common
units and subordinated units held by our general partner and its
affiliates. Please read Withdrawal or Removal of
Our General Partner.
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Transfer of our general partner interest
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After 2020, our general partner may transfer all or any of its
general partner interest in us without approval. Prior to such
date, the approval of a majority of the outstanding common
units, excluding common units held by our general partner and
its affiliates, is required for a transfer of the general
partner interest. Please read Transfer of General
Partner Interest.
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Transfer of incentive distribution rights
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No approval rights. Please read Transfer of
Incentive Distribution Rights.
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Transfer of ownership interests in our general partner
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No approval required at any time. Please read
Transfer of Ownership Interests in Our General Partner.
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Limited
Liability
Assuming that a limited partner does not participate in the
control of our business within the meaning of the Delaware Act
and that it otherwise acts in conformity with the provisions of
our partnership agreement, its
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liability under the Delaware Act will be limited, subject to
possible exceptions, to the amount of capital they are obligated
to contribute to us for their common units plus their share of
any undistributed profits and assets. If it were determined,
however, that the right of, or exercise of the right by, the
limited partners as a group:
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to remove or replace our general partner;
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to approve some amendments to our partnership agreement; or
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to take other action under our partnership agreement;
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constituted participation in the control of our
business for the purposes of the Delaware Act, then the limited
partners could 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 who reasonably believe that a 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. While this
does not mean that a limited partner could not seek legal
recourse, we know of no precedent for such a claim in Delaware
case law.
Under the Delaware Act, a limited partnership may not make a
distribution to a partner if, after the distribution, all
liabilities of the limited partnership, other than liabilities
to partners on account of their partnership interests and
liabilities for which the recourse of creditors is limited to
specific property of the partnership, would exceed the fair
value of the assets of the limited partnership. For the purpose
of determining the fair value of the assets of a limited
partnership, the Delaware Act provides that the fair value of
property subject to liability for which recourse of creditors is
limited shall be included in the assets of the limited
partnership only to the extent that the fair value of that
property exceeds the nonrecourse liability. The Delaware Act
provides that a limited partner who receives a distribution and
knew at the time of the distribution that the distribution was
in violation of the Delaware Act shall be liable to the limited
partnership for the amount of the distribution for three years.
Under the Delaware Act, an assignee who becomes a limited
partner of a limited partnership is liable for the obligations
of its assignor to make contributions to the partnership, except
the assignee is not obligated for liabilities unknown to him at
the time he became a limited partner and that could not be
ascertained from the partnership agreement.
Our subsidiaries conduct business in Kentucky and Ohio. Our
subsidiaries may conduct business in other states in the future.
Maintenance of our limited liability as a member of our
operating company may require compliance with legal requirements
in the jurisdictions in which our operating company conducts
business, including qualifying our subsidiaries to do business
there.
Limitations on the liability of limited partners for the
obligations of a limited partnership have not been clearly
established in many jurisdictions. If, by virtue of our
membership interest in our operating company or otherwise, it
were determined that we were conducting business in any state
without compliance with the applicable limited partnership or
limited liability company statute, or that the right or exercise
of the right by the limited partners as a group to remove or
replace our general partner, to approve some amendments to our
partnership agreement, or to take other action under our
partnership agreement constituted participation in the
control of our business for purposes of the statutes of
any relevant jurisdiction, then the limited partners could be
held personally liable for our obligations under the law of that
jurisdiction to the same extent as the general partner under the
circumstances. We will operate in a manner that our general
partner considers reasonable and necessary or appropriate to
preserve the limited liability of the limited partners.
Issuance
of Additional Securities
Our partnership agreement authorizes us to issue an unlimited
number of additional partnership securities for the
consideration and on the terms and conditions determined by our
general partner without the approval of our limited partners.
It is possible that we will fund acquisitions through the
issuance of additional common units, subordinated units or other
partnership securities. Holders of any additional common units
we issue will be entitled to share equally with the
then-existing holders of common units in our distributions of
available cash.
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In addition, the issuance of additional common units or other
partnership securities may dilute the value of the interests of
the then-existing holders of common units in our net assets.
In accordance with Delaware law and the provisions of our
partnership agreement, we may also issue additional partnership
securities that, as determined by our general partner, may have
rights to distributions or special voting rights to which the
common units are not entitled. In addition, our partnership
agreement does not prohibit the issuance by our subsidiaries of
equity securities, which may effectively rank senior to the
common units.
Our general partners 2.0% general partner interest is
subject to dilution. If we issue additional partnership
securities in the future, our general partner must either make
additional capital contributions to us to maintain its 2.0%
general partner interest or its interests will be effectively
diluted. In addition, our general partner will have the right,
which it may from time to time assign in whole or in part to any
of its affiliates, to purchase common units, subordinated units
or other partnership securities to the extent necessary to
maintain its and its affiliates limited partner percentage
interest in us, whenever, and on the same terms that, we issue
those securities to persons other than our general partner and
its affiliates. The holders of common units will not have
preemptive rights to acquire additional common units or other
partnership securities.
Amendment
of Our Partnership Agreement
General
Amendments to our partnership agreement may be proposed only by
our general partner. However, our general partner will have no
duty or obligation to propose any amendment and may decline to
do so free of any fiduciary duty or obligation whatsoever to us
or our limited partners, including any duty to act in good faith
or in the best interests of us or our limited partners. In order
to adopt a proposed amendment, other than the amendments
discussed below, our general partner must seek written approval
of the holders of the number of units required to approve the
amendment or call a meeting of the limited partners to consider
and vote upon the proposed amendment. Except as described below,
an amendment must be approved by a unit majority.
Prohibited
Amendments
No amendment may:
(1) enlarge the obligations of any limited partner without
its consent, unless approved by at least a majority of the type
or class of limited partner interests so affected; or
(2) enlarge the obligations of, restrict in any way any
action by or rights of, or reduce in any way the amounts
distributable, reimbursable or otherwise payable by us to our
general partner or any of its affiliates without the consent of
our general partner, which may be given or withheld at its
option.
The provision of our partnership agreement preventing the
amendments having the effects described in clauses (1) and
(2) above can be amended upon the approval of the holders
of at least 90% of the outstanding units voting together as a
single class (including units owned by our general partner and
its affiliates). Upon the consummation of this offering,
affiliates of our general partner will
own % of the outstanding common and
subordinated units as a single class
(or % of the outstanding common and
subordinated units as a single class, if the underwriters
exercise their option to purchase additional common units in
full).
No
Unitholder Approval
Our general partner may generally make amendments to the
partnership agreement without the approval of any limited
partner or assignee to reflect:
(1) a change in our name, the location of our principal
place of business, our registered agent or our registered office;
(2) the admission, substitution, withdrawal or removal of
partners in accordance with our partnership agreement;
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(3) a change that our general partner determines to be
necessary or appropriate for us to qualify or to continue our
qualification as a limited partnership or a partnership in which
the limited partners have limited liability under the laws of
any state or to ensure that neither we, our operating company,
nor its subsidiaries will be treated as an association taxable
as a corporation or otherwise taxed as an entity for federal
income tax purposes;
(4) a change in our fiscal year or taxable year and related
changes;
(5) an amendment that is necessary, in the opinion of our
counsel, to prevent us or our general partner or its directors,
officers, agents, or trustees from in any manner being subjected
to the provisions of the Investment Company Act of 1940, the
Investment Advisors Act of 1940, or plan asset
regulations adopted under the Employee Retirement Income
Security Act of 1974 (ERISA), whether or not
substantially similar to plan asset regulations currently
applied or proposed;
(6) an amendment that our general partner determines to be
necessary or appropriate for the authorization of additional
partnership securities or rights to acquire partnership
securities;
(7) any amendment expressly permitted in our partnership
agreement to be made by our general partner acting alone;
(8) an amendment effected, necessitated, or contemplated by
a merger agreement that has been approved under the terms of our
partnership agreement;
(9) any amendment that our general partner determines to be
necessary or appropriate for the formation by us of, or our
investment in, any corporation, partnership, joint venture,
limited liability company or other entity, as otherwise
permitted by our partnership agreement;
(10) mergers with, conveyances to or conversions to another
limited liability entity that is newly formed and has no assets,
liabilities or operations at the time of the merger, conveyance
or conversion other than those it receives by way of the merger,
conveyance or conversion; or
(11) any other amendments substantially similar to any of
the matters described above.
In addition, our general partner may make amendments to the
partnership agreement without the approval of any limited
partner or assignee if our general partner determines that those
amendments:
(1) do not adversely affect the limited partners (or any
particular class of limited partners) in any material respect;
(2) are necessary or appropriate to satisfy any
requirements, conditions, or guidelines contained in any
opinion, directive, order, ruling, or regulation of any federal
or state agency or judicial authority or contained in any
federal or state statute;
(3) are necessary or appropriate to facilitate the trading
of limited partner interests or to comply with any rule,
regulation, guideline, or requirement of any securities exchange
on which the limited partner interests are or will be listed for
trading;
(4) are necessary or appropriate for any action taken by
our general partner relating to splits or combinations of units
under the provisions of our partnership agreement; or
(5) are required to effect the intent expressed in the
contribution agreement, this prospectus or the intent of the
provisions of our partnership agreement or are otherwise
contemplated by our partnership agreement.
Opinion
of Counsel and Limited Partner Approval
Our general partner will not be required to obtain an opinion of
counsel that an amendment will not result in a loss of limited
liability to the limited partners or result in our being treated
as an entity for federal income tax purposes in connection with
any of the amendments described above under No
Unitholder Approval. No other amendments to our
partnership agreement will become effective without the approval
of
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holders of at least 90% of the outstanding units voting as a
single class unless we first obtain an opinion of counsel to the
effect that the amendment will not affect the limited liability
under applicable law of any of our limited partners.
In addition to the above restrictions, any amendment that would
have a material adverse effect on the rights or preferences of
any type or class of outstanding units in relation to other
classes of units will require the approval of at least a
majority of the type or class of units so affected. Any
amendment that reduces the voting percentage required to take
any action must be approved by the affirmative vote of limited
partners whose aggregate outstanding units constitute not less
than the voting requirement sought to be reduced.
Merger,
Sale or Other Disposition of Assets
A merger or consolidation of us requires the prior consent of
our general partner. However, our general partner will have no
duty or obligation to consent to any merger or consolidation and
may decline to do so free of any fiduciary duty or obligation
whatsoever to us or the limited partners, including any duty to
act in good faith or in the best interest of us or our limited
partners.
In addition, our partnership agreement generally prohibits our
general partner, without the prior approval of the holders of a
unit majority, from causing us to, among other things, sell,
exchange, or otherwise dispose of all or substantially all of
our and our subsidiaries assets in a single transaction or
a series of related transactions, including by way of merger,
consolidation, other combination or sale of ownership interests
of our subsidiaries. Our general partner may, however, mortgage,
pledge, hypothecate, or grant a security interest in all or
substantially all of our and our subsidiaries assets
without that approval. Our general partner may also sell all or
substantially all of our and our subsidiaries assets under
a foreclosure or other realization upon those encumbrances
without that approval.
If the conditions specified in our partnership agreement are
satisfied, our general partner may convert us or any of our
subsidiaries into a new limited liability entity or merge us or
any of our subsidiaries into, or convey some or all of our
assets to, a newly formed entity if the sole purpose of that
merger or conveyance is to effect a mere change in our legal
form into another limited liability entity. The limited partners
are not entitled to dissenters rights of appraisal under
our partnership agreement or applicable Delaware law in the
event of a conversion, merger or consolidation, a sale of
substantially all of our assets, or any other transaction or
event.
Our general partner may consummate any merger or consolidation
without the approval of our limited partners if we are the
surviving entity in the transaction, the transaction would not
result in an amendment to our partnership agreement that the
general partner could not adopt unilaterally, each of our units
will be an identical unit of our partnership following the
transaction, the units to be issued do not exceed 20% of our
outstanding units immediately prior to the transaction and our
general partner has received an opinion of counsel regarding
certain limited liability and tax matters.
Termination
and Dissolution
We will continue as a limited partnership until terminated under
our partnership agreement. We will dissolve upon:
(1) the withdrawal or removal of our general partner or any
other event that results in its ceasing to be our general
partner other than by reason of a transfer of its general
partner interest in accordance with our partnership agreement or
withdrawal or removal following approval and admission of a
successor general partner;
(2) the election of our general partner to dissolve us, if
approved by the holders of a unit majority;
(3) the entry of a decree of judicial dissolution of our
partnership; or
(4) at any time there are no limited partners, unless the
partnership is continued without dissolution in accordance with
the Delaware Act.
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Upon a dissolution under clause (1), the holders of a unit
majority may also elect, within specific time limitations, to
continue our business on the same terms and conditions described
in our partnership agreement and appoint as a successor general
partner an entity approved by the holders of a unit majority,
subject to our receipt of an opinion of counsel to the effect
that:
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the action would not result in the loss of limited liability of
any limited partner; and
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neither our partnership nor any of our subsidiaries would be
treated as an association taxable as a corporation or otherwise
be taxable as an entity for federal income tax purposes upon the
exercise of that right to continue (to the extent not already so
treated or taxed).
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Liquidation
and Distribution of Proceeds
Upon our dissolution, unless we are continued as a limited
partnership, the liquidator authorized to wind up our affairs
will, acting with all of the powers of our general partner that
are necessary or appropriate, liquidate our assets and apply the
proceeds of the liquidation as described in How We Make
Cash Distributions Distributions of Cash Upon
Liquidation. The liquidator may defer liquidation or
distribution of our assets for a reasonable period of time or
distribute assets to partners in kind if it determines that a
sale would be impractical or would cause undue loss to our
partners.
Withdrawal
or Removal of Our General Partner
Our general partner may withdraw as general partner without
obtaining approval of any unitholder by giving
90 days written notice, and that withdrawal will not
constitute a violation of our partnership agreement. In
addition, our partnership agreement permits our general partner
in some instances to sell or otherwise transfer all of its
general partner interest and incentive distribution rights in us
without the approval of the limited partners. Please read
Transfer of General Partner Interest and
Transfer of Incentive Distribution
Rights.
Upon a voluntary withdrawal of our general partner after giving
written notice to all partners, a unit majority may select a
successor to that withdrawing general partner. If a successor is
not elected, or is elected but an opinion of counsel regarding
limited liability and tax matters cannot be obtained, we will be
dissolved, wound up, and liquidated, unless within a specified
period of time after that withdrawal, the holders of a unit
majority agree in writing to continue our business and to
appoint a successor general partner. Please read
Termination and Dissolution.
Our general partner may not be removed unless that removal is
approved by the vote of the holders of not less than 80% of all
outstanding units, voting together as a single class, including
units held by our general partner and its affiliates, and we
receive an opinion of counsel regarding limited liability and
tax matters. Any removal of our general partner is also subject
to the approval of a successor general partner by the vote of
the holders of a majority of the outstanding common units and
subordinated units, voting as separate classes. The ownership of
more than 20% of the outstanding units by our general partner
and its affiliates would give them the practical ability to
prevent our general partners removal. At the closing of
this offering, affiliates of our general partner will
own % of the outstanding units
(or % of the outstanding units, if
the underwriters exercise their option to purchase additional
common units in full).
Our partnership agreement also provides that if our general
partner is removed as our general partner without cause and no
units held by our general partner and its affiliates are voted
in favor of that removal:
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the subordination period will end and all outstanding
subordinated units will immediately convert into common units on
a
one-for-one
basis;
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any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
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our general partner will have the right to convert its general
partner interest and its incentive distribution rights into
common units or to receive cash in exchange for those interests
based on the fair market value of the interests at the time.
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164
In the event of removal of our general partner under
circumstances where cause exists or withdrawal of our general
partner where that withdrawal violates our partnership
agreement, a successor general partner will have the option to
purchase the general partner interest and incentive distribution
rights of the departing general partner for a cash payment equal
to the fair market value of those interests. Under all other
circumstances where our general partner withdraws or is removed
by the limited partners, the departing general partner will have
the option to require the successor general partner to purchase
the general partner interest of the departing general partner
and its incentive distribution rights for their fair market
value. In each case, this fair market value will be determined
by agreement between the departing general partner and the
successor general partner. If no agreement is reached, an
independent investment banking firm or other independent expert
selected by the departing general partner and the successor
general partner will determine the fair market value. Or, if the
departing general partner and the successor general partner
cannot agree upon an expert, then an expert chosen by agreement
of the experts selected by each of them will determine the fair
market value.
If the option described above is not exercised by either the
departing general partner or the successor general partner, the
departing general partners general partner interest and
its incentive distribution rights will automatically convert
into common units equal to the fair market value of those
interests as determined by an investment banking firm or other
independent expert selected in the manner described in the
preceding paragraph.
In addition, we will be required to reimburse the departing
general partner for all amounts due to it, including, without
limitation, all employee-related liabilities, including
severance liabilities, incurred for the termination of any
employees employed by the departing general partner or its
affiliates for our benefit.
Transfer
of General Partner Interest
Prior
to 2020,
our general partner may not transfer all or any part of its
general partner interests in us to another person.
After 2020,
our general partner may transfer all or any part of its general
partner interest in us to another person without the approval of
the unitholders. As a condition of this transfer, the transferee
must, among other things, assume the rights and duties of our
general partner, agree to be bound by the provisions of our
partnership agreement, and furnish an opinion of counsel
regarding limited liability and tax matters.
Our general partner and its affiliates may at any time transfer
units to one or more persons, without unitholder approval,
except that they may not transfer subordinated units to us.
Transfer
of Ownership Interests in Our General Partner
At any time, the owners of our general partner may sell or
transfer all or part of their ownership interests in our general
partner to an affiliate or a third party without the approval of
our unitholders.
Transfer
of Incentive Distribution Rights
Our general partner or any other holder of incentive
distribution rights may transfer any or all of its incentive
distribution rights without unitholder approval.
Change of
Management Provisions
Our partnership agreement contains specific provisions that are
intended to discourage a person or group from attempting to
remove our general partner or otherwise change our management.
If any person or group other than our general partner and its
affiliates acquires beneficial ownership of 20% or more of any
class of units, that person or group loses voting rights on all
of its units. This loss of voting rights does not apply to any
person or group that acquires the units from our general partner
or its affiliates and any transferees of that person or group
approved by our general partner or to any person or group who
acquires the units with the prior approval of the board of
directors of our general partner.
165
If our general partner is removed without cause and no units
held by our general partner and its affiliates are voted in
favor of that removal, our partnership agreement provides that,
among other things, (i) all outstanding subordinated units
will immediately convert into common units, (ii) any
existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished and
(iii) our general partner will have the right to convert
its general partner interest and incentive distribution rights
into common units or receive cash in exchange for those
interests. Please read Withdrawal or Removal
of Our General Partner.
Limited
Call Right
If at any time our general partner and its affiliates own more
than 80% of the outstanding limited partner interests of any
class, our general partner will have the right, which it may
assign in whole or in part to any of its affiliates or to us, to
acquire all, but not less than all, of the remaining limited
partner interests of the class held by unaffiliated persons as
of a record date to be selected by our general partner, on at
least 10 but not more than 60 days notice. The purchase
price in the event of this purchase is the greater of:
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the highest cash price paid by either of our general partner or
any of its affiliates for any partnership securities of the
class purchased within the 90 days preceding the date on
which our general partner first mails notice of its election to
purchase those partnership securities; and
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the current market price as of the date three days before the
date the notice is mailed.
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As a result of our general partners right to purchase
outstanding limited partner interests, a holder of limited
partner interests may have his limited partner interests
purchased at an undesirable time or price. The tax consequences
to a unitholder of the exercise of this call right are the same
as a sale by that unitholder of his common units in the market.
Please read Material Federal Income Tax
Consequences Disposition of Common Units.
Meetings;
Voting
Except as described below regarding a person or group owning 20%
or more of any class of units then outstanding, unitholders or
assignees who are record holders of units on the record date
will be entitled to notice of, and to vote at, meetings of our
limited partners and to act upon matters for which approvals may
be solicited. Common units that are owned by an assignee who is
a record holder, but who has not yet been admitted as a limited
partner, will be voted by our general partner at the written
direction of the record holder. Absent direction of this kind,
the common units will not be voted, except that, in the case of
common units held by our general partner on behalf of
non-citizen assignees, our general partner will distribute the
votes on those common units in the same ratios as the votes of
limited partners on other units are cast.
Our general partner does not anticipate that any meeting of
unitholders will be called in the foreseeable future. Any action
that is required or permitted to be taken by the unitholders may
be taken either at a meeting of the unitholders or without a
meeting if consents in writing describing the action so taken
are signed by holders of the number of units necessary to
authorize or take that action at a meeting. Meetings of the
unitholders may be called by our general partner or by
unitholders owning at least 20% of the outstanding units of the
class for which a meeting is proposed. Unitholders may vote
either in person or by proxy at meetings. The holders of a
majority of the outstanding units of the class or classes for
which a meeting has been called, represented in person or by
proxy, will constitute a quorum unless any action by the
unitholders requires approval by holders of a greater percentage
of the units, in which case the quorum will be the greater
percentage. The units representing the general partner interest
are units for distribution and allocation purposes, but do not
entitle our general partner to any vote other than its rights as
general partner under our partnership agreement, will not be
entitled to vote on any action required or permitted to be taken
by the unitholders and will not count toward or be considered
outstanding when calculating required votes, determining the
presence of a quorum, or for similar purposes.
Each record holder of a unit has a vote according to its
percentage interest in us, although additional limited partner
interests having special voting rights could be issued. Please
read Issuance of Additional
166
Securities. However, if at any time any person or group,
other than our general partner and its affiliates, or a direct
or subsequently approved transferee of our general partner or
its affiliates, acquires, in the aggregate, beneficial ownership
of 20% or more of any class of units then outstanding, that
person or group will lose voting rights on all of its units and
the units may not be voted on any matter and will not be
considered to be outstanding when sending notices of a meeting
of unitholders, calculating required votes, determining the
presence of a quorum, or for other similar purposes. Common
units held in nominee or street name account will be voted by
the broker or other nominee in accordance with the instruction
of the beneficial owner unless the arrangement between the
beneficial owner and its nominee provides otherwise. Except as
our partnership agreement otherwise provides, subordinated units
will vote together with common units as a single class.
Any notice, demand, request, report, or proxy material required
or permitted to be given or made to record holders of common
units under our partnership agreement will be delivered to the
record holder by us or by the transfer agent.
Status as
Limited Partner or Assignee
Except as described above under Limited
Liability, the common units will be fully paid, and
unitholders will not be required to make additional
contributions.
An assignee of a common unit, after executing and delivering a
transfer application, but pending its admission as a limited
partner, is entitled to an interest equivalent to that of a
limited partner for the right to share in allocations and
distributions from us, including liquidating distributions. Our
general partner will vote and exercise other powers attributable
to common units owned by an assignee that has not become a
limited partner at the written direction of the assignee. Please
read Meetings; Voting. Transferees who
do not execute and deliver a transfer application and
certification will not be treated as assignees or as record
holders of common units, and will not receive cash
distributions, federal income tax allocations, or reports
furnished to holders of common units unless the common units are
held in a nominee or street name account and the
nominee or broker has executed and delivered a transfer
application and certification as to itself and any beneficial
holders. Please read Description of the Common
Units Transfer of Common Units.
Non-Citizen
Assignees; Redemption
If we are or become subject to federal, state, or local laws or
regulations that, in the determination of our general partner,
create a substantial risk of cancellation or forfeiture of any
property in which we have an interest in because of the
nationality, citizenship or other related status of any limited
partner or assignee, our general partner may require each
limited partner or assignee to furnish information about his
nationality, citizenship or related status. If a limited partner
or assignee fails to furnish information about his nationality,
citizenship or other related status within 30 days after a
request for the information or our general partner determines
after receipt of the information that the limited partner or
assignee is not an eligible citizen, the limited partner or
assignee may be treated as a non-citizen assignee. In addition
to other limitations on the rights of an assignee that is not a
limited partner, a non-citizen assignee does not have the right
to direct the voting of his units and may not receive
distributions in kind upon our liquidation.
Furthermore, we have the right to redeem all of the common and
subordinated units of any holder that our general partner
concludes is not an eligible citizen or fails to furnish the
information requested by our general partner. The redemption
price in the event of such redemption for each unit held by such
unitholder will be the lesser of (i) their current market
price and (ii) the price paid for each such unit by the
unitholder. The redemption price will be paid in cash or by
delivery of a promissory note, as determined by our general
partner. Any such promissory note will bear interest at the rate
of 5% annually and be payable in three equal annual installments
of principal and accrued interest, commencing one year after the
redemption date.
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Indemnification
Under our partnership agreement, we will indemnify the following
persons in most circumstances, to the fullest extent permitted
by law, from and against all losses, claims, damages, or similar
events:
(1) our general partner;
(2) any departing general partner;
(3) any person who is or was an affiliate of our general
partner or any departing general partner;
(4) any person who is or was an officer, director, member,
partner, fiduciary or trustee of any entity described in (1),
(2) or (3) above or any of their subsidiaries;
(5) any person who is or was serving as a director,
officer, member, partner, fiduciary or trustee of another person
at the request of our general partner or any departing general
partner or any of their affiliates; and
(6) any person designated by our general partner.
Any indemnification under these provisions will only be out of
our assets. Unless it otherwise agrees, our general partner will
not be personally liable for, or have any obligation to
contribute or loan funds or assets to us to enable us to
effectuate, indemnification. We may purchase insurance against
liabilities asserted against and expenses incurred by persons
for our activities, regardless of whether we would have the
power to indemnify the person against liabilities under our
partnership agreement.
Reimbursement
of Expenses
Our partnership agreement requires us to reimburse our general
partner for all direct and indirect expenses it incurs or
payments it makes on our behalf and all other expenses allocable
to us or otherwise incurred by our general partner in connection
with operating our business. 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 general
partner is entitled to determine in good faith the expenses that
are allocable to us.
Books and
Reports
Our general partner is required to keep appropriate books of our
business at our principal offices. The books will be maintained
for both tax and financial reporting purposes on an accrual
basis. For fiscal and tax reporting purposes, we use the
calendar year.
We will furnish or make available (by posting on our website or
other reasonable means) to record holders of common units,
within 120 days after the close of each fiscal year, an
annual report containing audited financial statements and a
report on those financial statements by our independent public
accountants. Except for our fourth quarter, we will also furnish
or make available summary financial information within
90 days after the close of each quarter.
We will furnish each record holder of a unit with information
reasonably required for tax reporting purposes within
90 days after the close of each calendar year. This
information is expected to be furnished in summary form so that
some complex calculations normally required of partners can be
avoided. Our ability to furnish this summary information to
unitholders will depend on the cooperation of unitholders in
supplying us with specific information. Every unitholder will
receive information to assist him in determining its federal and
state tax liability and filing its federal and state income tax
returns, regardless of whether he supplies us with information.
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Right to
Inspect Our Books and Records
Our partnership agreement provides that a limited partner can,
for a purpose reasonably related to its interest as a limited
partner, upon reasonable demand and at its own expense, have
furnished to him:
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a current list of the name and last known address of each
partner;
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a copy of our tax returns;
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information as to the amount of cash, and a description and
statement of the agreed value of any other property or services,
contributed or to be contributed by each partner and the date on
which each became a partner;
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copies of our partnership agreement, the certificate of limited
partnership of the partnership, related amendments, and powers
of attorney under which they have been executed;
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information regarding the status of our business and financial
condition; and
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any other information regarding our affairs as is just and
reasonable.
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Our general partner may, and intends to, keep confidential from
the limited partners trade secrets or other information the
disclosure of which our general partner believes in good faith
is not in our best interests or that we are required by law or
by agreements with third parties to keep confidential.
Registration
Rights
Under our partnership agreement, we have agreed to register for
resale under the Securities Act and applicable state securities
laws any common units, subordinated units, or other partnership
securities proposed to be sold by our general partner or any of
its affiliates or their assignees if an exemption from the
registration requirements is not otherwise available. These
registration rights continue for two years following any
withdrawal or removal of Oxford Resources GP as our general
partner. We are obligated to pay all expenses incidental to the
registration, excluding underwriting discounts and commissions.
Please read Units Eligible for Future Sale.
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UNITS
ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered by this prospectus,
C&T Coal and AIM Oxford will hold an aggregate
of
and
common units
and
and subordinated
units, respectively
(or
and
common units
and
and subordinated
units if the underwriters exercise their option to purchase
additional units in full). All of the subordinated units will
convert into common units at the end of the subordination
period. The sale of these common and subordinated units could
have an adverse impact on the price of the common units or on
any trading market that may develop.
The common units sold in this offering will generally be freely
transferable without restriction or further registration under
the Securities Act, except that any common units held by an
affiliate of ours may not be resold publicly except
in compliance with the registration requirements of the
Securities Act or under an exemption under Rule 144 or
otherwise. Rule 144 permits securities acquired by an
affiliate of the issuer to be sold into the market in an amount
that does not exceed, during any three-month period, the greater
of:
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1% of the total number of the securities outstanding; or
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the average weekly reported trading volume of the common units
for the four weeks prior to the sale.
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Sales under Rule 144 are also subject to specific manner of
sale provisions, holding period requirements, notice
requirements and the availability of current public information
about us. A person who is not deemed to have been an affiliate
of ours at any time during the three months preceding a sale,
and who has beneficially owned his common units for at least six
months (provided we are in compliance with the current public
information requirement) or one year (regardless of whether we
are in compliance with the current public information
requirement), would be entitled to sell common units under
Rule 144 without regard to the rules public
information requirements, volume limitations, manner of sale
provisions and notice requirements.
Our partnership agreement provides that we may issue an
unlimited number of limited partner interests of any type
without a vote of the unitholders at any time. Any issuance of
additional common units or other equity securities would result
in a corresponding decrease in the proportionate ownership
interest in us represented by, and could adversely affect the
cash distributions to and market price of, common units then
outstanding. Please read The Partnership
Agreement Issuance of Additional Securities.
Under our partnership agreement, our general partner and its
affiliates have the right to cause us to register under the
Securities Act and applicable state securities laws the offer
and sale of any common units that they hold. Subject to the
terms and conditions of the partnership agreement, these
registration rights allow our general partner and its affiliates
or their assignees holding any common units to require
registration of any of these common units and to include any of
these common units in a registration by us of other common
units, including common units offered by us or by any
unitholder. Our general partner and its affiliates will continue
to have these registration rights for two years following the
withdrawal or removal of our general partner. In connection with
any registration of this kind, we will indemnify each unitholder
participating in the registration and its officers, directors,
and controlling persons from and against any liabilities under
the Securities Act or any applicable state securities laws
arising from the registration statement or prospectus. We will
bear all costs and expenses incidental to any registration,
excluding any underwriting discounts and commissions. Except as
described below, our general partner and its affiliates may sell
their common units in private transactions at any time, subject
to compliance with applicable laws.
C&T Coal, AIM Oxford, our general partner and the
executive officers and directors of our general partner have
agreed not to sell any common units they beneficially own for a
period of 180 days from the date of this prospectus. Please
read Underwriting for a description of these
lock-up
provisions.
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MATERIAL
FEDERAL INCOME TAX CONSEQUENCES
This section is a summary of the material tax considerations
that may be relevant to prospective unitholders who are
individual citizens or residents of the U.S. and, unless
otherwise noted in the following discussion, is the opinion of
Latham & Watkins LLP, counsel to our general partner
and us, insofar as it relates to legal conclusions with respect
to matters of U.S. federal income tax law. This section is
based upon current provisions of the Internal Revenue Code of
1986, as amended (the Internal Revenue Code),
existing and proposed Treasury regulations promulgated under the
Internal Revenue Code (the Treasury Regulations) and
current administrative rulings and court decisions, all of which
are subject to change. Later changes in these authorities may
cause the tax consequences to vary substantially from the
consequences described below. Unless the context otherwise
requires, references in this section to us or
we are references to Oxford Resource Partners, LP
and our operating subsidiaries.
The following discussion does not comment on all federal income
tax matters affecting us or our unitholders. Moreover, the
discussion focuses on unitholders who are individual citizens or
residents of the U.S. and has only limited application to
corporations, estates, trusts, nonresident aliens or other
unitholders subject to specialized tax treatment, such as
tax-exempt institutions, foreign persons, IRAs, real estate
investment trusts (REITs) or mutual funds. In addition, the
discussion only comments, to a limited extent, on state, local,
and foreign tax consequences. Accordingly, we encourage each
prospective unitholder to consult, and depend on, his own tax
advisor in analyzing the federal, state, local and foreign tax
consequences particular to him of the ownership or disposition
of common units.
No ruling has been or will be requested from the IRS regarding
any matter affecting us or prospective unitholders. Instead, we
will rely on opinions of Latham & Watkins LLP. Unlike
a ruling, an opinion of counsel represents only that
counsels best legal judgment and does not bind the IRS or
the courts. Accordingly, the opinions and statements made herein
may not be sustained by a court if contested by the IRS. Any
contest of this sort with the IRS may materially and adversely
impact the market for the common units and the prices at which
common units trade. In addition, the costs of any contest with
the IRS, principally legal, accounting and related fees, will
result in a reduction in cash available for distribution to our
unitholders and our general partner and thus will be borne
indirectly by our unitholders and our general partner.
Furthermore, the tax treatment of us, or of an investment in us,
may be significantly modified by future legislative or
administrative changes or court decisions. Any modifications may
or may not be retroactively applied.
All statements as to matters of federal income tax law and legal
conclusions with respect thereto, but not as to factual matters,
contained in this section, unless otherwise noted, are the
opinion of Latham & Watkins LLP and are based on the
accuracy of the representations made by us.
For the reasons described below, Latham & Watkins LLP
has not rendered an opinion with respect to the following
specific federal income tax issues: (i) the treatment of a
unitholder whose common units are loaned to a short seller to
cover a short sale of common units (please read
Tax Consequences of Unit Ownership
Treatment of Short Sales); (ii) whether our monthly
convention for allocating taxable income and losses is permitted
by existing Treasury Regulations (please read
Disposition of Common Units
Allocations Between Transferors and Transferees); and
(iii) whether our method for depreciating Section 743
adjustments is sustainable in certain cases (please read
Tax Consequences of Unit Ownership
Section 754 Election).
Partnership
Status
A partnership is not a taxable entity and incurs no federal
income tax liability. Instead, each partner of a partnership is
required to take into account his share of items of income,
gain, loss and deduction of the partnership in computing his
federal income tax liability, regardless of whether cash
distributions are made to him by the partnership. Distributions
by a partnership to a partner are generally not taxable to the
partnership or the partner unless the amount of cash distributed
to him is in excess of the partners adjusted basis in his
partnership interest.
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Section 7704 of the Internal Revenue Code provides that
publicly traded partnerships will, as a general rule, be taxed
as corporations. However, an exception, referred to as the
Qualifying Income Exception, exists with respect to
publicly traded partnerships of which 90% or more of the gross
income for every taxable year consists of qualifying
income. Qualifying income includes income and gains
derived from the mining, production, transportation, storage and
marketing of coal and certain other natural resources. Other
types of qualifying income include interest (other than from a
financial business), dividends, gains from the sale of real
property and gains from the sale or other disposition of capital
assets held for the production of income that otherwise
constitutes qualifying income. We estimate that less
than % of our current gross income
is not qualifying income; however, this estimate could change
from time to time. Based upon and subject to this estimate, the
factual representations made by us and our general partner and a
review of the applicable legal authorities, Latham &
Watkins LLP is of the opinion that at least 90% of our current
gross income constitutes qualifying income. The portion of our
income that is qualifying income may change from time to time.
No ruling has been or will be sought from the IRS and the IRS
has made no determination as to our status or the status of our
operating subsidiaries for federal income tax purposes or
whether our operations generate qualifying income
under Section 7704 of the Internal Revenue Code. Instead,
we will rely on the opinion of Latham & Watkins LLP on
such matters. It is the opinion of Latham & Watkins
LLP that, based upon the Internal Revenue Code, its regulations,
published revenue rulings and court decisions and the
representations described below, we will be classified as a
partnership and our operating subsidiaries (other than Harrison
Resources) will be disregarded as an entity separate from us for
federal income tax purposes. Harrison Resources will be treated
as a partnership for federal income tax purposes.
In rendering its opinion, Latham & Watkins LLP has
relied on factual representations made by us and our general
partner. The representations made by us and our general partner
upon which Latham & Watkins LLP has relied are:
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Neither we nor the operating subsidiaries has elected or will
elect to be treated as a corporation; and
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For each taxable year, more than 90% of our gross income has
been and will be income of the type that Latham &
Watkins LLP has opined or will opine is qualifying
income within the meaning of Section 7704(d) of the
Internal Revenue Code; and
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We believe that these representations have been true in the past
and expect that these representations will continue to be true
in the future.
If we fail to meet the Qualifying Income Exception, other than a
failure that is determined by the IRS to be inadvertent and that
is cured within a reasonable time after discovery (in which case
the IRS may also require us to make adjustments with respect to
our unitholders or pay other amounts), we will be treated as if
we had transferred all of our assets, subject to liabilities, to
a newly formed corporation, on the first day of the year in
which we fail to meet the Qualifying Income Exception, in return
for stock in that corporation, and then distributed that stock
to the unitholders in liquidation of their interests in us. This
deemed contribution and liquidation should be tax-free to
unitholders and us so long as we, at that time, do not have
liabilities in excess of the tax basis of our assets.
Thereafter, we would be treated as a corporation for federal
income tax purposes.
If we were taxed as a corporation in any taxable year, either as
a result of a failure to meet the Qualifying Income Exception or
otherwise, our items of income, gain, loss and deduction would
be reflected only on our tax return rather than being passed
through to our unitholders, and our net income would be taxed to
us at corporate rates. In addition, any distribution made to a
unitholder would be treated as taxable dividend income, to the
extent of our current and accumulated earnings and profits, or,
in the absence of earnings and profits, a nontaxable return of
capital, to the extent of the unitholders tax basis in his
common units, or taxable capital gain, after the
unitholders tax basis in his common units is reduced to
zero. Accordingly, taxation as a corporation would result in a
material reduction in a unitholders cash flow and
after-tax return and thus would likely result in a substantial
reduction of the value of the units.
The discussion below is based on Latham & Watkins
LLPs opinion that we will be classified as a partnership
for federal income tax purposes.
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Limited
Partner Status
Unitholders who have become limited partners of Oxford Resource
Partners, LP will be treated as partners of Oxford Resource
Partners, LP for federal income tax purposes. Also, unitholders
whose common units are held in street name or by a nominee and
who have the right to direct the nominee in the exercise of all
substantive rights attendant to the ownership of their common
units will be treated as partners of Oxford Resource Partners,
LP for federal income tax purposes.
A beneficial owner of common units whose units have been
transferred to a short seller to complete a short sale would
appear to lose his status as a partner with respect to those
units for federal income tax purposes. Please read
Tax Consequences of Unit Ownership
Treatment of Short Sales.
Income, gain, deductions or losses would not appear to be
reportable by a unitholder who is not a partner for federal
income tax purposes, and any cash distributions received by a
unitholder who is not a partner for federal income tax purposes
would therefore appear to be fully taxable as ordinary income.
These holders are urged to consult their own tax advisors with
respect to their tax consequences of holding common units in
Oxford Resource Partners, LP. The references to
unitholders in the discussion that follows are to
persons who are treated as partners in Oxford Resource Partners,
LP for federal income tax purposes.
Tax
Consequences of Unit Ownership
Flow-Through of Taxable Income.
We will not
pay any federal income tax. Instead, each unitholder will be
required to report on his income tax return his share of our
income, gains, losses and deductions without regard to whether
we make cash distributions to him. Consequently, we may allocate
income to a unitholder even if he has not received a cash
distribution. Each unitholder will be required to include in
income his allocable share of our income, gains, losses and
deductions for our taxable year ending with or within his
taxable year. Our taxable year ends on December 31.
Treatment of Distributions.
Distributions by
us to a unitholder generally will not be taxable to the
unitholder for federal income tax purposes, except to the extent
the amount of any such cash distribution exceeds his tax basis
in his common units immediately before the distribution. Our
cash distributions in excess of a unitholders tax basis
generally will be considered to be gain from the sale or
exchange of the common units, taxable in accordance with the
rules described under Disposition of Common
Units below. Any reduction in a unitholders share of
our liabilities for which no partner, including the general
partner, bears the economic risk of loss, known as
nonrecourse liabilities, will be treated as a
distribution by us of cash to that unitholder. To the extent our
distributions cause a unitholders at-risk
amount to be less than zero at the end of any taxable year, he
must recapture any losses deducted in previous years. Please
read Limitations on Deductibility of
Losses.
A decrease in a unitholders percentage interest in us
because of our issuance of additional common units will decrease
his share of our nonrecourse liabilities, and thus will result
in a corresponding deemed distribution of cash. This deemed
distribution may constitute a non-pro rata distribution. A
non-pro rata distribution of money or property may result in
ordinary income to a unitholder, regardless of his tax basis in
his common units, if the distribution reduces the
unitholders share of our unrealized
receivables, including depreciation recapture, depletion
recapture
and/or
substantially appreciated inventory items, each as
defined in the Internal Revenue Code, and collectively,
Section 751 Assets. To that extent, the
unitholder will be treated as having been distributed his
proportionate share of the Section 751 Assets and then
having exchanged those assets with us in return for the non-pro
rata portion of the actual distribution made to him. This latter
deemed exchange will generally result in the unitholders
realization of ordinary income, which will equal the excess of
(i) the non-pro rata portion of that distribution over
(ii) the unitholders tax basis (generally zero) for
the share of Section 751 Assets deemed relinquished in the
exchange.
Ratio of Taxable Income to Distributions.
We
estimate that a purchaser of common units in this offering who
owns those common units from the date of closing of this
offering through the record date for distributions for the
period ending December 31, 2013, will be allocated, on a
cumulative basis, an amount of federal taxable income for that
period that will be % or less of
the cash distributed with respect to that
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period. Thereafter, we anticipate that the ratio of allocable
taxable income to cash distributions to the unitholders will
increase. These estimates are based upon the assumption that
gross income from operations will approximate the amount
required to make the minimum quarterly distribution on all units
and other assumptions with respect to capital expenditures, cash
flow, net working capital and anticipated cash distributions.
These estimates and assumptions are subject to, among other
things, numerous business, economic, regulatory, legislative,
competitive and political uncertainties beyond our control.
Further, the estimates are based on current tax law and tax
reporting positions that we will adopt and with which the IRS
could disagree. Accordingly, we cannot assure you that these
estimates will prove to be correct. The actual percentage of
distributions that will constitute taxable income could be
higher or lower than expected, and any differences could be
material and could materially affect the value of the common
units. For example, the ratio of allocable taxable income to
cash distributions to a purchaser of common units in this
offering will be greater, and perhaps substantially greater,
than our estimate with respect to the period described above if:
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gross income from operations exceeds the amount required to make
minimum quarterly distributions on all units, yet we only
distribute the minimum quarterly distributions on all
units; or
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we make a future offering of common units and use the proceeds
of the offering in a manner that does not produce substantial
additional deductions during the period described above, such as
to repay indebtedness outstanding at the time of this offering
or to acquire property that is not eligible for depreciation or
amortization for federal income tax purposes or that is
depreciable or amortizable at a rate significantly slower than
the rate applicable to our assets at the time of this offering.
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Basis of Common Units.
A unitholders
initial tax basis for his common units will be the amount he
paid for the common units plus his share of our nonrecourse
liabilities. That basis will be increased by his share of our
income and by any increases in his share of our nonrecourse
liabilities. That basis will be decreased, but not below zero,
by distributions from us, by the unitholders share of our
losses, by any decreases in his share of our nonrecourse
liabilities and by his share of our expenditures that are not
deductible in computing taxable income and are not required to
be capitalized. A unitholder will have no share of our debt that
is recourse to our general partner, but will have a share,
generally based on his share of profits, of our nonrecourse
liabilities. Please read Disposition of Common
Units Recognition of Gain or Loss.
Limitations on Deductibility of Losses.
The
deduction by a unitholder of his share of our losses will be
limited to the tax basis in his units and, in the case of an
individual unitholder, estate, trust, or corporate unitholder
(if more than 50% of the value of the corporate
unitholders stock is owned directly or indirectly by or
for five or fewer individuals or some tax-exempt organizations)
to the amount for which the unitholder is considered to be
at risk with respect to our activities, if that is
less than his tax basis. A common unitholder subject to these
limitations must recapture losses deducted in previous years to
the extent that distributions cause his at-risk amount to be
less than zero at the end of any taxable year. Losses disallowed
to a unitholder or recaptured as a result of these limitations
will carry forward and will be allowable as a deduction to the
extent that his at-risk amount is subsequently increased,
provided such losses do not exceed such common unitholders
tax basis in his common units. Upon the taxable disposition of a
unit, any gain recognized by a unitholder can be offset by
losses that were previously suspended by the at-risk limitation
but may not be offset by losses suspended by the basis
limitation. Any loss previously suspended by the at-risk
limitation in excess of that gain would no longer be utilizable.
In general, a unitholder will be at risk to the extent of the
tax basis of his units, excluding any portion of that basis
attributable to his share of our nonrecourse liabilities,
reduced by (i) any portion of that basis representing
amounts otherwise protected against loss because of a guarantee,
stop loss agreement or other similar arrangement and
(ii) any amount of money he borrows to acquire or hold his
units, if the lender of those borrowed funds owns an interest in
us, is related to the unitholder or can look only to the units
for repayment. A unitholders at-risk amount will increase
or decrease as the tax basis of the unitholders units
increases or decreases, other than tax basis increases or
decreases attributable to increases or decreases in his share of
our nonrecourse liabilities.
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In addition to the basis and at-risk limitations on the
deductibility of losses, the passive loss limitations generally
provide that individuals, estates, trusts and some closely-held
corporations and personal service corporations can deduct losses
from passive activities, which are generally trade or business
activities in which the taxpayer does not materially
participate, only to the extent of the taxpayers income
from those passive activities. The passive loss limitations are
applied separately with respect to each publicly traded
partnership. Consequently, any passive losses we generate will
only be available to offset our passive income generated in the
future and will not be available to offset income from other
passive activities or investments, including our investments or
a unitholders investments in other publicly traded
partnerships, or salary or active business income. Passive
losses that are not deductible because they exceed a
unitholders share of income we generate may be deducted in
full when he disposes of his entire investment in us in a fully
taxable transaction with an unrelated party. The passive loss
limitations are applied after other applicable limitations on
deductions, including the at-risk rules and the basis limitation.
A unitholders share of our net income may be offset by any
of our suspended passive losses, but it may not be offset by any
other current or carryover losses from other passive activities,
including those attributable to other publicly traded
partnerships.
Limitations on Interest Deductions.
The
deductibility of a non-corporate taxpayers
investment interest expense is generally limited to
the amount of that taxpayers net investment
income. Investment interest expense includes:
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interest on indebtedness properly allocable to property held for
investment;
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our interest expense attributed to portfolio income; and
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the portion of interest expense incurred to purchase or carry an
interest in a passive activity to the extent attributable to
portfolio income.
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The computation of a unitholders investment interest
expense will take into account interest on any margin account
borrowing or other loan incurred to purchase or carry a unit.
Net investment income includes gross income from property held
for investment and amounts treated as portfolio income under the
passive loss rules, less deductible expenses, other than
interest, directly connected with the production of investment
income, but generally does not include gains attributable to the
disposition of property held for investment or qualified
dividend income. The IRS has indicated that the net passive
income earned by a publicly traded partnership will be treated
as investment income to its unitholders. In addition, the
unitholders share of our portfolio income will be treated
as investment income.
Entity-Level Collections.
If we are
required or elect under applicable law to pay any federal,
state, local or foreign income tax on behalf of any unitholder
or our general partner or any former unitholder, we are
authorized to pay those taxes from our funds. That payment, if
made, will be treated as a distribution of cash to the
unitholder on whose behalf the payment was made. If the payment
is made on behalf of a person whose identity cannot be
determined, we are authorized to treat the payment as a
distribution to all current unitholders. We are authorized to
amend our partnership agreement in the manner necessary to
maintain uniformity of intrinsic tax characteristics of units
and to adjust later distributions, so that after giving effect
to these distributions, the priority and characterization of
distributions otherwise applicable under our partnership
agreement is maintained as nearly as is practicable. Payments by
us as described above could give rise to an overpayment of tax
on behalf of an individual unitholder in which event the
unitholder would be required to file a claim in order to obtain
a credit or refund.
Allocation of Income, Gain, Loss and
Deduction.
In general, if we have a net profit,
our items of income, gain, loss and deduction will be allocated
among our general partner and the unitholders in accordance with
their percentage interests in us. At any time that distributions
are made to the common units in excess of distributions to the
subordinated units, or incentive distributions are made to our
general partner, gross income will be allocated to the
recipients to the extent of these distributions. If we have a
net loss, that loss will be allocated first to our general
partner and the unitholders in accordance with their percentage
interests in us to the extent of their positive capital accounts
and, second, to our general partner.
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Specified items of our income, gain, loss and deduction will be
allocated to account for (i) any difference between the tax
basis and fair market value of our assets at the time of an
offering and (ii) any difference between the tax basis and
fair market value of any property contributed to us by the
general partner and its affiliates that exists at the time of
such contribution, together, referred to in this discussion as
the Contributed Property. The effect of these
allocations, referred to as Section 704(c) Allocations, to
a unitholder purchasing common units from us in this offering
will be essentially the same as if the tax bases of our assets
were equal to their fair market values at the time of this
offering. In the event we issue additional common units or
engage in certain other transactions in the future,
reverse Section 704(c) Allocations, similar to
the Section 704(c) Allocations described above, will be
made to the general partner and all of our unitholders
immediately prior to such issuance or other transactions to
account for the difference between the book basis
for purposes of maintaining capital accounts and the fair market
value of all property held by us at the time of such issuance or
future transaction. In addition, items of recapture income will
be allocated to the extent possible to the unitholder who was
allocated the deduction giving rise to the treatment of that
gain as recapture income in order to minimize the recognition of
ordinary income by some unitholders. Finally, although we do not
expect that our operations will result in the creation of
negative capital accounts, if negative capital accounts
nevertheless result, items of our income and gain will be
allocated in an amount and manner sufficient to eliminate the
negative balance as quickly as possible.
An allocation of items of our income, gain, loss or deduction,
other than an allocation required by the Internal Revenue Code
to eliminate the difference between a partners
book capital account, credited with the fair market
value of Contributed Property, and tax capital
account, credited with the tax basis of Contributed Property,
referred to in this discussion as the Book-Tax
Disparity, will generally be given effect for federal
income tax purposes in determining a partners share of an
item of income, gain, loss or deduction only if the allocation
has substantial economic effect. In any other case, a
partners share of an item will be determined on the basis
of his interest in us, which will be determined by taking into
account all the facts and circumstances, including:
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his relative contributions to us;
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the interests of all the partners in profits and losses;
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the interest of all the partners in cash flow; and
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the rights of all the partners to distributions of capital upon
liquidation.
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Latham & Watkins LLP is of the opinion that, with the
exception of the issues described in
Section 754 Election and
Disposition of Common Units
Allocations Between Transferors and Transferees,
allocations under our partnership agreement will be given effect
for federal income tax purposes in determining a partners
share of an item of income, gain, loss or deduction.
Treatment of Short Sales.
A unitholder whose
units are loaned to a short seller to cover a short
sale of units may be considered as having disposed of those
units. If so, he would no longer be treated for tax purposes as
a partner with respect to those units during the period of the
loan and may recognize gain or loss from the disposition. As a
result, during this period:
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any of our income, gain, loss or deduction with respect to those
units would not be reportable by the unitholder;
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any cash distributions received by the unitholder as to those
units would be fully taxable; and
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all of these distributions would appear to be ordinary income.
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Latham & Watkins LLP has not rendered an opinion
regarding the tax treatment of a unitholder whose common units
are loaned to a short seller to cover a short sale of common
units; therefore, unitholders desiring to assure their status as
partners and avoid the risk of gain recognition from a loan to a
short seller are urged to modify any applicable brokerage
account agreements to prohibit their brokers from borrowing and
loaning their units. The IRS has previously announced that it is
studying issues relating to the tax
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treatment of short sales of partnership interests. Please also
read Disposition of Common Units
Recognition of Gain or Loss.
Alternative Minimum Tax.
Each unitholder will
be required to take into account his distributive share of any
items of our income, gain, loss or deduction for purposes of the
alternative minimum tax. The current minimum tax rate for
noncorporate taxpayers is 26% on the first $175,000 of
alternative minimum taxable income in excess of the exemption
amount and 28% on any additional alternative minimum taxable
income. Prospective unitholders are urged to consult with their
tax advisors as to the impact of an investment in units on their
liability for the alternative minimum tax.
Tax Rates.
Under current law, the highest
marginal U.S. federal income tax rate applicable to
ordinary income of individuals is 35% and the highest marginal
U.S. federal income tax rate applicable to long-term
capital gains (generally, capital gains on certain assets held
for more than twelve months) of individuals is 15%. However,
absent new legislation extending the current rates, beginning
January 1, 2011, the highest marginal U.S. federal
income tax rate applicable to ordinary income and long-term
capital gains of individuals will increase to 39.6% and 20%,
respectively. Moreover, these rates are subject to change by new
legislation at any time.
Section 754 Election.
We will make the
election permitted by Section 754 of the Internal Revenue
Code. That election is irrevocable without the consent of the
IRS. The election will generally permit us to adjust a common
unit purchasers tax basis in our assets (inside
basis) under Section 743(b) of the Internal Revenue
Code to reflect his purchase price. This election does not apply
with respect to a person who purchases common units directly
from us. The Section 743(b) adjustment belongs to the
purchaser and not to other unitholders. For purposes of this
discussion, the inside basis in our assets with respect to a
unitholder will be considered to have two components:
(i) his share of our tax basis in our assets (common
basis) and (ii) his Section 743(b) adjustment to
that basis.
We will adopt the remedial allocation method as to all our
properties. Where the remedial allocation method is adopted, the
Treasury Regulations under Section 743 of the Internal
Revenue Code require a portion of the Section 743(b)
adjustment that is attributable to recovery property that is
subject to depreciation under Section 168 of the Internal
Revenue Code and whose book basis is in excess of its tax basis
to be depreciated over the remaining cost recovery period for
the propertys unamortized Book-Tax Disparity. Under
Treasury
Regulation Section 1.167(c)-1(a)(6),
a Section 743(b) adjustment attributable to property
subject to depreciation under Section 167 of the Internal
Revenue Code, rather than cost recovery deductions under
Section 168, is generally required to be depreciated using
either the straight-line method or the 150% declining balance
method. Under our partnership agreement, our general partner is
authorized to take a position to preserve the uniformity of
units even if that position is not consistent with these and any
other Treasury Regulations. Please read
Uniformity of Units.
Although Latham & Watkins LLP is unable to opine as to
the validity of this approach, we intend to depreciate the
portion of a Section 743(b) adjustment attributable to
unrealized appreciation in the value of Contributed Property, to
the extent of any unamortized Book-Tax Disparity, using a rate
of depreciation or amortization derived from the depreciation or
amortization method and useful life applied to the
propertys unamortized Book-Tax Disparity, or treat that
portion as
non-amortizable
to the extent attributable to property which is not amortizable.
This method is consistent with the methods employed by other
publicly traded partnerships but is arguably inconsistent with
Treasury Regulation
Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets. To the extent this Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may take a depreciation or amortization position under which
all purchasers acquiring units in the same month would receive
depreciation or amortization, whether attributable to common
basis or a Section 743(b) adjustment, based upon the same
applicable rate as if they had purchased a direct interest in
our assets. This kind of aggregate approach may result in lower
annual depreciation or amortization deductions than would
otherwise be allowable to some unitholders. Please read
Uniformity of Units. A unitholders
tax basis for his common units is reduced by his share of our
deductions (whether or not such deductions were
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claimed on an individuals income tax return) so that any
position we take that understates deductions will overstate the
common unitholders basis in his common units, which may
cause the unitholder to understate gain or overstate loss on any
sale of such units. Please read Disposition of
Common Units Recognition of Gain or Loss. The
IRS may challenge our position with respect to depreciating or
amortizing the Section 743(b) adjustment we take to
preserve the uniformity of the units. If such a challenge were
sustained, the gain from the sale of units might be increased
without the benefit of additional deductions.
A Section 754 election is advantageous if the
transferees tax basis in his units is higher than the
units share of the aggregate tax basis of our assets
immediately prior to the transfer. In that case, as a result of
the election, the transferee would have, among other items, a
greater amount of depreciation and depletion deductions and his
share of any gain or loss on a sale of our assets would be less.
Conversely, a Section 754 election is disadvantageous if
the transferees tax basis in his units is lower than those
units share of the aggregate tax basis of our assets
immediately prior to the transfer. Thus, the fair market value
of the units may be affected either favorably or unfavorably by
the election. A basis adjustment is required regardless of
whether a Section 754 election is made in the case of a
transfer of an interest in us if we have a substantial
built in loss immediately after the transfer, or if
we distribute property and have a substantial basis reduction.
Generally a built in loss or a basis reduction is
substantial if it exceeds $250,000.
The calculations involved in the Section 754 election are
complex and will be made on the basis of assumptions as to the
value of our assets and other matters. For example, the
allocation of the Section 743(b) adjustment among our
assets must be made in accordance with the Internal Revenue
Code. The IRS could seek to reallocate some or all of any
Section 743(b) adjustment allocated by us to our tangible
assets to goodwill instead. Goodwill, as an intangible asset, is
generally nonamortizable or amortizable over a longer period of
time or under a less accelerated method than our tangible
assets. We cannot assure you that the determinations we make
will not be successfully challenged by the IRS and that the
deductions resulting from them will not be reduced or disallowed
altogether. Should the IRS require a different basis adjustment
to be made, and should, in our opinion, the expense of
compliance exceed the benefit of the election, we may seek
permission from the IRS to revoke our Section 754 election.
If permission is granted, a subsequent purchaser of units may be
allocated more income than he would have been allocated had the
election not been revoked.
Tax
Treatment of Operations
Accounting Method and Taxable Year.
We use the
year ending December 31 as our taxable year and the accrual
method of accounting for federal income tax purposes. Each
unitholder will be required to include in income his share of
our income, gain, loss and deduction for our taxable year ending
within or with his taxable year. In addition, a unitholder who
has a taxable year ending on a date other than December 31 and
who disposes of all of his units following the close of our
taxable year but before the close of his taxable year must
include his share of our income, gain, loss and deduction in
income for his taxable year, with the result that he will be
required to include in income for his taxable year his share of
more than twelve months of our income, gain, loss and deduction.
Please read Disposition of Common
Units Allocations Between Transferors and
Transferees.
Initial Tax Basis, Depreciation and
Amortization.
The tax basis of our assets will be
used for purposes of computing depreciation and cost recovery
deductions and, ultimately, gain or loss on the disposition of
these assets. The federal income tax burden associated with the
difference between the fair market value of our assets and their
tax basis immediately prior to (i) this offering will be
borne by our general partner and its affiliates, and
(ii) any other offering will be borne by our general
partner and all of our unitholders as of that time. Please read
Tax Consequences of Unit Ownership
Allocation of Income, Gain, Loss and Deduction.
To the extent allowable, we may elect to use the depreciation
and cost recovery methods that will result in the largest
deductions being taken in the early years after assets subject
to these allowances are placed in service. Please read
Uniformity of Units. Property we
subsequently acquire or construct may be depreciated using
accelerated methods permitted by the Internal Revenue Code.
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If we dispose of depreciable property by sale, foreclosure or
otherwise, all or a portion of any gain, determined by reference
to the amount of depreciation previously deducted and the nature
of the property, may be subject to the recapture rules and taxed
as ordinary income rather than capital gain. Similarly, a
unitholder who has taken cost recovery or depreciation
deductions with respect to property we own will likely be
required to recapture some or all of those deductions as
ordinary income upon a sale of his interest in us. Please read
Tax Consequences of Unit Ownership
Allocation of Income, Gain, Loss and Deduction and
Disposition of Common Units
Recognition of Gain or Loss.
The costs we incur in selling our units (called
syndication expenses) must be capitalized and cannot
be deducted currently, ratably or upon our termination. There
are uncertainties regarding the classification of costs as
organization expenses, which may be amortized by us, and as
syndication expenses, which may not be amortized by us. The
underwriting discounts and commissions we incur will be treated
as syndication expenses.
Valuation and Tax Basis of Our Properties.
The
federal income tax consequences of the ownership and disposition
of units will depend in part on our estimates of the relative
fair market values, and the initial tax bases, of our assets.
Although we may from time to time consult with professional
appraisers regarding valuation matters, we will make many of the
relative fair market value estimates ourselves. These estimates
and determinations of basis are subject to challenge and will
not be binding on the IRS or the courts. If the estimates of
fair market value or basis are later found to be incorrect, the
character and amount of items of income, gain, loss or
deductions previously reported by unitholders might change, and
unitholders might be required to adjust their tax liability for
prior years and incur interest and penalties with respect to
those adjustments.
Coal Income.
Section 631 of the Internal
Revenue Code provides special rules by which gains or losses on
the sale of coal may be treated, in whole or in part, as gains
or losses from the sale of property used in a trade or business
under Section 1231 of the Internal Revenue Code.
Specifically, Section 631(c) provides that if the owner of
coal held for more than one year disposes of that coal under a
contract by virtue of which the owner retains an economic
interest in the coal, the gain or loss realized will be treated
under Section 1231 of the Internal Revenue Code as gain or
loss from property used in a trade or business.
Section 1231 gains and losses may be treated as capital
gains and losses. Please read Sales of Coal
Reserves. In computing such gain or loss, the amount
realized is reduced by the adjusted depletion basis in the coal,
determined as described in Coal
Depletion. For purposes of Section 631(c), the coal
generally is deemed to be disposed of on the day on which the
coal is mined. Further, Treasury regulations promulgated under
Section 631 provide that advance royalty payments may also
be treated as proceeds from sales of coal to which
Section 631 applies and, therefore, such payment may be
treated as capital gain under Section 1231. However, if the
right to mine the related coal expires or terminates under the
contract that provides for the payment of advance royalty
payments or such right is abandoned before the coal has been
mined, we may, pursuant to the Treasury regulations, file an
amended return that reflects the payments attributable to
unmined coal as ordinary income and not as received from the
sale of coal under Section 631.
Our royalties from coal leases generally will be treated as
proceeds from sales of coal to which Section 631 applies.
Accordingly, the difference between the royalties paid to us by
the lessees and the adjusted depletion basis in the extracted
coal generally will be treated as gain from the sale of property
used in a trade or business, which may be treated as capital
gain under Section 1231. Please read
Sales of Coal Reserves. Our royalties
that do not qualify under Section 631(c) generally will be
taxable as ordinary income in the year of sale.
Coal Depletion.
In general, we are entitled to
depletion deductions with respect to coal mined from the
underlying mineral property. We generally are entitled to the
greater of cost depletion limited to the basis of the property
or percentage depletion. The percentage depletion rate for coal
is 10%.
Depletion deductions we claim generally will reduce the tax
basis of the underlying mineral property. Depletion deductions
can, however, exceed the total tax basis of the mineral
property. The excess of our percentage depletion deductions over
the adjusted tax basis of the property at the end of the taxable
year is subject to tax preference treatment in computing the
alternative minimum tax. Please read Tax
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Consequences of Unit Ownership Alternative Minimum
Tax. Upon the disposition of the mineral property, a
portion of the gain, if any, equal to the lesser of the
deductions for depletion which reduce the adjusted tax basis of
the mineral property plus deductible development and mining
exploration expenses (discussed below), or the amount of gain
recognized upon the disposition, will be treated as ordinary
income to us. In addition, a corporate unitholders
allocable share of the amount allowable as a percentage
depletion deduction for any property will be reduced by 20% of
the excess, if any, of that partners allocable share of
the amount of the percentage depletion deductions for the
taxable year over the adjusted tax basis of the mineral property
as of the close of the taxable year.
Mining Exploration and Development
Expenditures.
We will elect to currently deduct
mining exploration expenditures that we pay or incur to
determine the existence, location, extent or quality of coal
deposits prior to the time the existence of coal in commercially
marketable quantities has been disclosed.
Amounts we deduct for mine exploration expenditures must be
recaptured and included in our taxable income at the time a mine
reaches the production stage, unless we elect to reduce future
depletion deductions by the amount of the recapture. A mine
reaches the producing stage when the major part of the coal
production is obtained from working mines other than those
opened for the purpose of development or the principal activity
of the mine is the production of developed coal rather than the
development of additional coal for mining. This recapture is
accomplished through the disallowance of both cost and
percentage depletion deductions on the particular mine reaching
the producing stage. This disallowance of depletion deductions
continues until the amount of adjusted exploration expenditures
with respect to the mine have been fully recaptured. This
recapture is not applied to the full amount of the previously
deducted exploration expenditures. Instead, these expenditures
are reduced by the amount of percentage depletion, if any, that
was lost as a result of deducting these exploration expenditures.
We generally elect to defer mine development expenses,
consisting of expenditures incurred in making coal accessible
for extraction, after the exploration process has disclosed the
existence of coal in commercially marketable quantities, and
deduct them on a ratable basis as the coal benefited by the
expenses is sold.
Mine exploration and development expenditures are subject to
recapture as ordinary income to the extent of any gain upon a
sale or other disposition of our property or of your common
units. See Disposition of Common Units.
Corporate unitholders are subject to an additional rule that
requires them to capitalize a portion of their otherwise
deductible mine exploration and development expenditures.
Corporate unitholders, other than some S corporations, are
required to reduce their otherwise deductible exploration
expenditures by 30%. These capitalized mine exploration and
development expenditures must be amortized over a
60-month
period, beginning in the month paid or incurred, using a
straight-line method and may not be treated as part of the basis
of the property for purposes of computing depletion.
When computing the alternative minimum tax, mine exploration and
development expenditures are capitalized and deducted over a ten
year period. Unitholders may avoid this alternative minimum tax
adjustment of their mine exploration and development
expenditures by electing to capitalize all or part of the
expenditures and deducting them over ten years for regular
income tax purposes. You may select the specific amount of these
expenditures for which you wish to make this election.
Sales of Coal Reserves.
If any coal reserves
are sold or otherwise disposed of in a taxable transaction, we
will recognize gain or loss measured by the difference between
the amount realized (including the amount of any indebtedness
assumed by the purchaser upon such disposition or to which such
property is subject) and the adjusted tax basis of the property
sold. Generally, the character of any gain or loss recognized
upon that disposition will depend upon whether our coal reserves
or the mined coal sold are held by us:
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for sale to customers in the ordinary course of business (i.e.,
we are a dealer with respect to that property),
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for use in a trade or business within the meaning of
Section 1231 of the Internal Revenue Code, or
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as a capital asset within the meaning of Section 1221 of
the Internal Revenue Code.
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In determining dealer status with respect to coal reserves and
other types of real estate, the courts have identified a number
of factors for distinguishing between a particular property held
for sale in the ordinary course of business and one held for
investment. Any determination must be based on all the facts and
circumstances surrounding the particular property and sale in
question.
We intend to hold our coal reserves for use in a trade or
business and achieving long-term capital appreciation. Although
our general partner may consider strategic sales of coal
reserves consistent with achieving long-term capital
appreciation, our general partner does not anticipate frequent
sales of coal reserves. Thus, the general partner does not
believe we will be viewed as a dealer. In light of the factual
nature of this question, however, there is no assurance that our
purposes for holding our properties will not change and that our
future activities will not cause us to be a dealer
in coal reserves.
If we are not a dealer with respect to our coal reserves and we
have held the disposed property for more than a one-year period
primarily for use in our trade or business, the character of any
gain or loss realized from a disposition of the property will be
determined under Section 1231 of the Internal Revenue Code.
If we have not held the property for more than one year at the
time of the sale, gain or loss from the sale will be taxable as
ordinary income.
A unitholders distributive share of any Section 1231
gain or loss generated by us will be aggregated with any other
gains and losses realized by that unitholder from the
disposition of property used in the trade or business, as
defined in Section 1231(b) of the Internal Revenue Code,
and from the involuntary conversion of such properties and of
capital assets held in connection with a trade or business or a
transaction entered into for profit for the requisite holding
period. If a net gain results, all such gains and losses will be
long-term capital gains and losses; if a net loss results, all
such gains and losses will be ordinary income and losses. Net
Section 1231 gains will be treated as ordinary income to
the extent of prior net Section 1231 losses of the taxpayer
or predecessor taxpayer for the five most recent prior taxable
years to the extent such losses have not previously been offset
against Section 1231 gains. Losses are deemed recaptured in
the chronological order in which they arose.
If we are not a dealer with respect to our coal reserves and
that property is not used in a trade or business, the property
will be a capital asset within the meaning of
Section 1221 of the Internal Revenue Code. Gain or loss
recognized from the disposition of that property will be taxable
as capital gain or loss, and the character of such capital gain
or loss as long-term or short-term will be based upon our
holding period of such property at the time of its sale. The
requisite holding period for long-term capital gain is more than
one year.
Upon a disposition of coal reserves, a portion of the gain, if
any, equal to the lesser of (1) the depletion deductions
that reduced the tax basis of the disposed mineral property plus
deductible development and mining exploration expenses or
(2) the amount of gain recognized on the disposition, will
be treated as ordinary income to us.
Deduction for U.S. Production
Activities.
Subject to the limitations on the
deductibility of losses discussed above and the limitation
discussed below, unitholders will be entitled to a deduction,
herein referred to as the Section 199 deduction, equal to a
specified percentage of our qualified production activities
income that is allocated to such unitholder. The percentage is
currently 9% for qualified production activities income.
Qualified production activities income is generally equal to
gross receipts from domestic production activities reduced by
cost of goods sold allocable to those receipts, other expenses
directly associated with those receipts, and a share of other
deductions, expenses and losses that are not directly allocable
to those receipts or another class of income. The products
produced must be manufactured, produced, grown or extracted in
whole or in significant part by the taxpayer in the United
States.
For a partnership, the Section 199 deduction is determined
at the partner level. To determine his Section 199
deduction, each unitholder will aggregate his share of the
qualified production activities income allocated to him from us
with the unitholders qualified production activities
income from other sources. Each unitholder must take into
account his distributive share of the expenses allocated to him
from our qualified production activities regardless of whether
we otherwise have taxable income. However, our expenses that
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otherwise would be taken into account for purposes of computing
the Section 199 deduction are only taken into account if
and to the extent the unitholders share of losses and
deductions from all of our activities is not disallowed by the
basis rules, the at-risk rules or the passive activity loss
rules. Please read Tax Consequences of Unit
Ownership Limitations on Deductibility of
Losses.
The amount of a unitholders Section 199 deduction for
each year is limited to 50% of the IRS
Form W-2
wages actually or deemed paid by the unitholder during the
calendar year that are deducted in arriving at qualified
production activities income. Each unitholder is treated as
having been allocated IRS
Form W-2
wages from us equal to the unitholders allocable share of
our wages that are deducted in arriving at qualified production
activities income for that taxable year. It is not anticipated
that we or our subsidiaries will pay material wages that will be
allocated to our unitholders, and thus a unitholders
ability to claim the Section 199 deduction may be limited.
Disposition
of Common Units
Recognition of Gain or Loss.
Gain or loss will
be recognized on a sale of units equal to the difference between
the amount realized and the unitholders tax basis for the
units sold. A unitholders amount realized will be measured
by the sum of the cash or the fair market value of other
property received by him plus his share of our nonrecourse
liabilities. Because the amount realized includes a
unitholders share of our nonrecourse liabilities, the gain
recognized on the sale of units could result in a tax liability
in excess of any cash received from the sale.
Prior distributions from us that in the aggregate were in excess
of cumulative net taxable income for a common unit and,
therefore, decreased a unitholders tax basis in that
common unit will, in effect, become taxable income if the common
unit is sold at a price greater than the unitholders tax
basis in that common unit, even if the price received is less
than his original cost.
Except as noted below, gain or loss recognized by a unitholder,
other than a dealer in units, on the sale or
exchange of a unit will generally be taxable as capital gain or
loss. Capital gain recognized by an individual on the sale of
units held for more than twelve months will generally be taxed
at a maximum U.S. federal income tax rate of 15% through
December 31, 2010 and 20% thereafter (absent new
legislation extending or adjusting the current rate). However, a
portion of this gain or loss, which will likely be substantial,
will be separately computed and taxed as ordinary income or loss
under Section 751 of the Internal Revenue Code to the
extent attributable to assets giving rise to depreciation
recapture or other unrealized receivables or to
inventory items we own. The term unrealized
receivables includes potential recapture items, including
depreciation and depletion recapture. Ordinary income
attributable to unrealized receivables, inventory items and
depreciation recapture may exceed net taxable gain realized upon
the sale of a unit and may be recognized even if there is a net
taxable loss realized on the sale of a unit. Thus, a unitholder
may recognize both ordinary income and a capital loss upon a
sale of units. Net capital losses may offset capital gains and
no more than $3,000 of ordinary income, in the case of
individuals, and may only be used to offset capital gains in the
case of corporations.
The IRS has ruled that a partner who acquires interests in a
partnership in separate transactions must combine those
interests and maintain a single adjusted tax basis for all those
interests. Upon a sale or other disposition of less than all of
those interests, a portion of that tax basis must be allocated
to the interests sold using an equitable
apportionment method, which generally means that the tax
basis allocated to the interest sold equals an amount that bears
the same relation to the partners tax basis in his entire
interest in the partnership as the value of the interest sold
bears to the value of the partners entire interest in the
partnership. Treasury Regulations under Section 1223 of the
Internal Revenue Code allow a selling unitholder who can
identify common units transferred with an ascertainable holding
period to elect to use the actual holding period of the common
units transferred. Thus, according to the ruling discussed
above, a common unitholder will be unable to select high or low
basis common units to sell as would be the case with corporate
stock, but, according to the Treasury Regulations, he may
designate specific common units sold for purposes of determining
the holding period of units transferred. A unitholder electing
to use the actual holding period of common units transferred
must consistently use that identification method for all
subsequent sales or
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exchanges of common units. A unitholder considering the purchase
of additional units or a sale of common units purchased in
separate transactions is urged to consult his tax advisor as to
the possible consequences of this ruling and application of the
Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the
taxation of some financial products and securities, including
partnership interests, by treating a taxpayer as having sold an
appreciated partnership interest, one in which gain
would be recognized if it were sold, assigned or terminated at
its fair market value, if the taxpayer or related persons
enter(s) into:
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a short sale;
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an offsetting notional principal contract; or
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a futures or forward contract with respect to the partnership
interest or substantially identical property.
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Moreover, if a taxpayer has previously entered into a short
sale, an offsetting notional principal contract or a futures or
forward contract with respect to the partnership interest, the
taxpayer will be treated as having sold that position if the
taxpayer or a related person then acquires the partnership
interest or substantially identical property. The Secretary of
the Treasury is also authorized to issue regulations that treat
a taxpayer that enters into transactions or positions that have
substantially the same effect as the preceding transactions as
having constructively sold the financial position.
Allocations Between Transferors and
Transferees.
In general, our taxable income and
losses will be determined annually, will be prorated on a
monthly basis and will be subsequently apportioned among the
unitholders in proportion to the number of units owned by each
of them as of the opening of the applicable exchange on the
first business day of the month, which we refer to in this
prospectus as the Allocation Date. However, gain or
loss realized on a sale or other disposition of our assets other
than in the ordinary course of business will be allocated among
the unitholders on the Allocation Date in the month in which
that gain or loss is recognized. As a result, a unitholder
transferring units may be allocated income, gain, loss and
deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the
Internal Revenue Code and most publicly traded partnerships use
similar simplifying conventions, the use of this method may not
be permitted under existing Treasury Regulations. Recently, the
Department of the Treasury and the IRS issued proposed Treasury
Regulations that provide a safe harbor pursuant to which a
publicly traded partnership may use a similar monthly
simplifying convention to allocate tax items among transferor
and transferee unitholders, although such tax items must be
prorated on a daily basis. Existing publicly traded partnerships
are entitled to rely on these proposed Treasury Regulations;
however, they are not binding on the IRS and are subject to
change until final Treasury Regulations are issued. Accordingly,
Latham & Watkins LLP is unable to opine on the
validity of this method of allocating income and deductions
between transferor and transferee unitholders. If this method is
not allowed under the Treasury Regulations, or only applies to
transfers of less than all of the unitholders interest,
our taxable income or losses might be reallocated among the
unitholders. We are authorized to revise our method of
allocation between transferor and transferee unitholders, as
well as unitholders whose interests vary during a taxable year,
to conform to a method permitted under future Treasury
Regulations.
A unitholder who owns units at any time during a quarter and who
disposes of them prior to the record date set for a cash
distribution for that quarter will be allocated items of our
income, gain, loss and deductions attributable to that quarter
but will not be entitled to receive that cash distribution.
Notification Requirements.
A unitholder who
sells any of his units is generally required to notify us in
writing of that sale within 30 days after the sale (or, if
earlier, January 15 of the year following the sale). A purchaser
of units who purchases units from another unitholder is also
generally required to notify us in writing of that purchase
within 30 days after the purchase. Upon receiving such
notifications, we are required to notify the IRS of that
transaction and to furnish specified information to the
transferor and transferee. Failure to notify us of a purchase
may, in some cases, lead to the imposition of penalties.
However, these
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reporting requirements do not apply to a sale by an individual
who is a citizen of the U.S. and who effects the sale or
exchange through a broker who will satisfy such requirements.
Constructive Termination.
We will be
considered to have been terminated for tax purposes if there are
sales or exchanges which, in the aggregate, constitute 50% or
more of the total interests in our capital and profits within a
twelve-month period. For purposes of measuring whether the 50%
threshold is reached, multiple sales of the same interest are
counted only once. A constructive termination results in the
closing of our taxable year for all unitholders. In the case of
a unitholder reporting on a taxable year other than a fiscal
year ending December 31, the closing of our taxable year
may result in more than twelve months of our taxable income or
loss being includable in his taxable income for the year of
termination. A constructive termination occurring on a date
other than December 31 will result in us filing two tax returns
(and unitholders could receive two Schedules K-1 if the relief
discussed below is not available) for one fiscal year and the
cost of the preparation of these returns will be borne by all
common unitholders. We would be required to make new tax
elections after a termination, including a new election under
Section 754 of the Internal Revenue Code, and a termination
would result in a deferral of our deductions for depreciation. A
termination could also result in penalties if we were unable to
determine that the termination had occurred. Moreover, a
termination might either accelerate the application of, or
subject us to, any tax legislation enacted before the
termination. The IRS has recently announced a relief procedure
whereby if a publicly traded partnership that has technically
terminated requests publicly traded partnership technical
termination relief and the IRS grants such relief, among other
things, the partnership will only have to provide one
Schedule K-1
to unitholders for the year notwithstanding two partnership tax
years.
Uniformity
of Units
Because we cannot match transferors and transferees of units, we
must maintain uniformity of the economic and tax characteristics
of the units to a purchaser of these units. In the absence of
uniformity, we may be unable to completely comply with a number
of federal income tax requirements, both statutory and
regulatory. A lack of uniformity can result from a literal
application of Treasury
Regulation Section 1.167(c)-1(a)(6).
Any non-uniformity could have a negative impact on the value of
the units. Please read Tax Consequences of
Unit Ownership Section 754 Election.
We intend to depreciate the portion of a Section 743(b)
adjustment attributable to unrealized appreciation in the value
of Contributed Property, to the extent of any unamortized
Book-Tax Disparity, using a rate of depreciation or amortization
derived from the depreciation or amortization method and useful
life applied to the propertys unamortized Book-Tax
Disparity, or treat that portion as nonamortizable, to the
extent attributable to property the common basis of which is not
amortizable, consistent with the regulations under
Section 743 of the Internal Revenue Code, even though that
position may be inconsistent with Treasury
Regulation Section 1.167(c)-1(a)(6),
which is not expected to directly apply to a material portion of
our assets. Please read Tax Consequences of
Unit Ownership Section 754 Election. To
the extent that the Section 743(b) adjustment is
attributable to appreciation in value in excess of the
unamortized Book-Tax Disparity, we will apply the rules
described in the Treasury Regulations and legislative history.
If we determine that this position cannot reasonably be taken,
we may adopt a depreciation and amortization position under
which all purchasers acquiring units in the same month would
receive depreciation and amortization deductions, whether
attributable to a common basis or Section 743(b)
adjustment, based upon the same applicable methods and lives as
if they had purchased a direct interest in our property. If this
position is adopted, it may result in lower annual depreciation
and amortization deductions than would otherwise be allowable to
some unitholders and risk the loss of depreciation and
amortization deductions not taken in the year that these
deductions are otherwise allowable. This position will not be
adopted if we determine that the loss of depreciation and
amortization deductions will have a material adverse effect on
the unitholders. If we choose not to utilize this aggregate
method, we may use any other reasonable depreciation and
amortization method to preserve the uniformity of the intrinsic
tax characteristics of any units that would not have a material
adverse effect on the unitholders. The IRS may challenge any
method of depreciating the Section 743(b) adjustment
described in this paragraph. If this challenge were sustained,
the uniformity of units
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might be affected, and the gain from the sale of units might be
increased without the benefit of additional deductions. Please
read Disposition of Common Units
Recognition of Gain or Loss.
Tax-Exempt
Organizations and Other Investors
Ownership of units by employee benefit plans, other tax-exempt
organizations, non-resident aliens, foreign corporations and
other foreign persons raises issues unique to those investors
and, as described below to a limited extent, may have
substantially adverse tax consequences to them. If you are a
tax-exempt entity or a
non-U.S. person,
you should consult your tax advisor before investing in our
common units.
Employee benefit plans and most other organizations exempt from
federal income tax, including individual retirement accounts and
other retirement plans, are subject to federal income tax on
unrelated business taxable income. Virtually all of our income
allocated to a unitholder that is a tax-exempt organization will
be unrelated business taxable income and will be taxable to it
Non-resident aliens and foreign corporations, trusts or estates
that own units will be considered to be engaged in business in
the U.S. because of the ownership of units. As a
consequence, they will be required to file federal tax returns
to report their share of our income, gain, loss or deduction and
pay federal income tax at regular rates on their share of our
net income or gain. Moreover, under rules applicable to publicly
traded partnerships, we will withhold at the highest applicable
effective tax rate from cash distributions made quarterly to
foreign unitholders. Each foreign unitholder must obtain a
taxpayer identification number from the IRS and submit that
number to our transfer agent on a
Form W-8BEN
or applicable substitute form in order to obtain credit for
these withholding taxes. A change in applicable law may require
us to change these procedures.
In addition, because a foreign corporation that owns units will
be treated as engaged in a U.S. trade or business, that
corporation may be subject to the U.S. branch profits tax
at a rate of 30%, in addition to regular federal income tax, on
its share of our income and gain, as adjusted for changes in the
foreign corporations U.S. net equity,
which is effectively connected with the conduct of a
U.S. trade or business. That tax may be reduced or
eliminated by an income tax treaty between the U.S. and the
country in which the foreign corporate unitholder is a
qualified resident. In addition, this type of
unitholder is subject to special information reporting
requirements under Section 6038C of the Internal Revenue
Code.
A foreign unitholder who sells or otherwise disposes of a common
unit will be subject to U.S. federal income tax on gain
realized from the sale or disposition of that unit to the extent
the gain is effectively connected with a U.S. trade or
business of the foreign unitholder. Under a ruling published by
the IRS, interpreting the scope of effectively connected
income, a foreign unitholder would be considered to be
engaged in a trade or business in the U.S. by virtue of the
U.S. activities of the partnership, and part or all of that
unitholders gain would be effectively connected with that
unitholders indirect U.S. trade or business.
Moreover, under the Foreign Investment in Real Property Tax Act,
a foreign common unitholder generally will be subject to
U.S. federal income tax upon the sale or disposition of a
common unit if (i) he owned (directly or constructively
applying certain attribution rules) more than 5% of our common
units at any time during the five-year period ending on the date
of such disposition and (ii) 50% or more of the fair market
value of all of our assets consisted of U.S. real property
interests at any time during the shorter of the period during
which such unitholder held the common units or the
5-year
period ending on the date of disposition. Currently, more than
50% of our assets consist of U.S. real property interests
and we do not expect that to change in the foreseeable future.
Therefore, foreign unitholders may be subject to federal income
tax on gain from the sale or disposition of their units.
Administrative
Matters
Information Returns and Audit Procedures.
We
intend to furnish to each unitholder, within 90 days after
the close of each calendar year, specific tax information,
including a
Schedule K-1,
which describes his share of our income, gain, loss and
deduction for our preceding taxable year. In preparing this
information, which will not be reviewed by counsel, we will take
various accounting and reporting positions, some of which have
been mentioned earlier, to determine each unitholders
share of income, gain, loss and deduction. We cannot
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assure you that those positions will yield a result that
conforms to the requirements of the Internal Revenue Code,
Treasury Regulations or administrative interpretations of the
IRS. Neither we nor Latham & Watkins LLP can assure
prospective unitholders that the IRS will not successfully
contend in court that those positions are impermissible. Any
challenge by the IRS could negatively affect the value of the
units.
The IRS may audit our federal income tax information returns.
Adjustments resulting from an IRS audit may require each
unitholder to adjust a prior years tax liability, and
possibly may result in an audit of his return. Any audit of a
unitholders return could result in adjustments not related
to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for
purposes of federal tax audits, judicial review of
administrative adjustments by the IRS and tax settlement
proceedings. The tax treatment of partnership items of income,
gain, loss and deduction are determined in a partnership
proceeding rather than in separate proceedings with the
partners. The Internal Revenue Code requires that one partner be
designated as the Tax Matters Partner for these
purposes. Our partnership agreement names Oxford Resources GP,
LLC as our Tax Matters Partner.
The Tax Matters Partner has made and will make some elections on
our behalf and on behalf of unitholders. In addition, the Tax
Matters Partner can extend the statute of limitations for
assessment of tax deficiencies against unitholders for items in
our returns. The Tax Matters Partner may bind a unitholder with
less than a 1% profits interest in us to a settlement with the
IRS unless that unitholder elects, by filing a statement with
the IRS, not to give that authority to the Tax Matters Partner.
The Tax Matters Partner may seek judicial review, by which all
the unitholders are bound, of a final partnership administrative
adjustment and, if the Tax Matters Partner fails to seek
judicial review, judicial review may be sought by any unitholder
having at least a 1% interest in profits or by any group of
unitholders having in the aggregate at least a 5% interest in
profits. However, only one action for judicial review will go
forward, and each unitholder with an interest in the outcome may
participate.
A unitholder must file a statement with the IRS identifying the
treatment of any item on his federal income tax return that is
not consistent with the treatment of the item on our return.
Intentional or negligent disregard of this consistency
requirement may subject a unitholder to substantial penalties.
Nominee Reporting.
Persons who hold an
interest in us as a nominee for another person are required to
furnish to us:
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the name, address and taxpayer identification number of the
beneficial owner and the nominee;
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whether the beneficial owner is:
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a person that is not a U.S. person;
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a foreign government, an international organization or any
wholly owned agency or instrumentality of either of the
foregoing; or
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a tax-exempt entity;
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the amount and description of units held, acquired or
transferred for the beneficial owner; and
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specific information including the dates of acquisitions and
transfers, means of acquisitions and transfers, and acquisition
cost for purchases, as well as the amount of net proceeds from
sales.
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Brokers and financial institutions are required to furnish
additional information, including whether they are
U.S. persons and specific information on units they
acquire, hold or transfer for their own account. A penalty of
$50 per failure, up to a maximum of $100,000 per calendar year,
is imposed by the Internal Revenue Code for failure to report
that information to us. The nominee is required to supply the
beneficial owner of the units with the information furnished to
us.
Accuracy-Related Penalties.
An additional tax
equal to 20% of the amount of any portion of an underpayment of
tax that is attributable to one or more specified causes,
including negligence or disregard of rules or regulations,
substantial understatements of income tax and substantial
valuation misstatements, is
186
imposed by the Internal Revenue Code. No penalty will be
imposed, however, for any portion of an underpayment if it is
shown that there was a reasonable cause for that portion and
that the taxpayer acted in good faith regarding that portion.
For individuals, a substantial understatement of income tax in
any taxable year exists if the amount of the understatement
exceeds the greater of 10% of the tax required to be shown on
the return for the taxable year or $5,000 ($10,000 for most
corporations). The amount of any understatement subject to
penalty generally is reduced if any portion is attributable to a
position adopted on the return:
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for which there is, or was, substantial
authority; or
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as to which there is a reasonable basis and the pertinent facts
of that position are disclosed on the return.
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If any item of income, gain, loss or deduction included in the
distributive shares of unitholders might result in that kind of
an understatement of income for which no
substantial authority exists, we must disclose the
pertinent facts on our return. In addition, we will make a
reasonable effort to furnish sufficient information for
unitholders to make adequate disclosure on their returns and to
take other actions as may be appropriate to permit unitholders
to avoid liability for this penalty. More stringent rules apply
to tax shelters, which we do not believe includes
us, or any of our investments, plans or arrangements.
A substantial valuation misstatement exists if (a) the
value of any property, or the adjusted basis of any property,
claimed on a tax return is 150% or more of the amount determined
to be the correct amount of the valuation or adjusted basis,
(b) the price for any property or services (or for the use
of property) claimed on any such return with respect to any
transaction between persons described in Internal Revenue Code
Section 482 is 200% or more (or 50% or less) of the amount
determined under Section 482 to be the correct amount of
such price, or (c) the net Internal Revenue Code
Section 482 transfer price adjustment for the taxable year
exceeds the lesser of $5 million or 10% of the
taxpayers gross receipts.
No penalty is imposed unless the portion of the underpayment
attributable to a substantial valuation misstatement exceeds
$5,000 ($10,000 for most corporations). If the valuation claimed
on a return is 200% or more than the correct valuation, the
penalty imposed increases to 40%. We do not anticipate making
any valuation misstatements.
Reportable Transactions.
If we were to engage
in a reportable transaction, we (and possibly you
and others) would be required to make a detailed disclosure of
the transaction to the IRS. A transaction may be a reportable
transaction based upon any of several factors, including the
fact that it is a type of tax avoidance transaction publicly
identified by the IRS as a listed transaction or
that it produces certain kinds of losses for partnerships,
individuals, S corporations, and trusts in excess of
$2 million in any single year, or $4 million in any
combination of 6 successive tax years. Our participation in a
reportable transaction could increase the likelihood that our
federal income tax information return (and possibly your tax
return) would be audited by the IRS. Please read
Information Returns and Audit Procedures.
Moreover, if we were to participate in a reportable transaction
with a significant purpose to avoid or evade tax, or in any
listed transaction, you may be subject to the following
provisions of the American Jobs Creation Act of 2004:
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accuracy-related penalties with a broader scope, significantly
narrower exceptions, and potentially greater amounts than
described above at Accuracy-Related
Penalties;
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for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability; and
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in the case of a listed transaction, an extended statute of
limitations.
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We do not expect to engage in any reportable
transactions.
187
Recent
Legislative Developments
Current law may change so as to cause us to be treated as a
corporation for federal income tax purposes or otherwise subject
us to entity-level taxation. For example, members of Congress
have recently considered and are considering substantive changes
to the existing federal income tax laws that could affect
certain publicly traded partnerships. As previously and
currently proposed, we do not believe any such legislation would
affect our tax treatment as a partnership. However, the proposed
legislation could be modified in a way that could affect us. 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 units.
On February 1, 2010, the White House released President
Obamas budget proposal for the fiscal year 2011 (the
Budget Proposal). Among the changes contained in the
Budget Proposal is the elimination of certain key
U.S. federal income tax preferences currently available to
coal exploration and development. The Budget Proposal would
(i) eliminate current deductions and the
60-month
amortization for exploration and development costs relating to
coal and other hard mineral fossil fuels, (ii) repeal the
percentage depletion allowance with respect to coal properties,
(iii) repeal capital gains treatment of coal and lignite
royalties, and (iv) exclude from the definition of domestic
production gross receipts all gross receipts derived from the
sale, exchange, or other disposition of coal, other hard mineral
fossil fuels, or primary products thereof.
Legislation has been introduced in the Senate and includes many
of the proposals outlined in the Budget Proposal. It is unclear
whether any such changes will actually be enacted or, if
enacted, how soon any such changes could become effective. The
passage of any legislation as a result of the Budget Proposal or
any other similar change in U.S. federal income tax law
could affect certain tax deductions that are currently available
with respect to coal exploration and development and could
negatively impact the value of an investment in our units.
State,
Local, Foreign and Other Tax Considerations
In addition to federal income taxes, you likely will be subject
to other taxes, such as state, local and foreign income taxes,
unincorporated business taxes, and estate, inheritance or
intangible taxes that may be imposed by the various
jurisdictions in which we do business or own property or in
which you are a resident. Although an analysis of those various
taxes is not presented here, each prospective unitholder should
consider their potential impact on his investment in us. We will
initially own property or do business in Illinois, Indiana,
Kentucky, Ohio, Pennsylvania and West Virginia. Each of these
states imposes a personal income tax on individuals. Most of
these states also impose an income tax on corporations and other
entities. We may also own property or do business in other
jurisdictions in the future. Although you may not be required to
file a return and pay taxes in some jurisdictions because your
income from that jurisdiction falls below the filing and payment
requirement, you will be required to file income tax returns and
to pay income taxes in many of these jurisdictions in which we
do business or own property and may be subject to penalties for
failure to comply with those requirements. In some
jurisdictions, tax losses may not produce a tax benefit in the
year incurred and may not be available to offset income in
subsequent taxable years. Some of the jurisdictions may require
us, or we may elect, to withhold a percentage of income from
amounts to be distributed to a unitholder who is not a resident
of the jurisdiction. Withholding, the amount of which may be
greater or less than a particular unitholders income tax
liability to the jurisdiction, generally does not relieve a
nonresident unitholder from the obligation to file an income tax
return. Amounts withheld will be treated as if distributed to
unitholders for purposes of determining the amounts distributed
by us. Please read Tax Consequences of Unit
Ownership Entity-Level Collections. Based
on current law and our estimate of our future operations, our
general partner anticipates that any amounts required to be
withheld will not be material.
It is the responsibility of each unitholder to investigate
the legal and tax consequences, under the laws of pertinent
jurisdictions, of his investment in us. Accordingly, each
prospective unitholder is urged to consult, and depend upon, his
tax counsel or other advisor with regard to those matters.
Further, it is the responsibility of each unitholder to file all
state, local and foreign, as well as U.S. federal tax
returns, that may be required of him. Latham & Watkins
LLP has not rendered an opinion on the state, local or foreign
tax consequences of an investment in us.
188
INVESTMENT
IN OXFORD RESOURCE PARTNERS, LP BY EMPLOYEE BENEFIT
PLANS
An investment in us by an employee benefit plan is subject to
additional considerations because the investments of these plans
are subject to the fiduciary responsibility and prohibited
transaction provisions of ERISA and the restrictions imposed by
Section 4975 of the Internal Revenue Code and provisions
under any federal, state, local,
non-U.S. or
other laws or regulations that are similar to such provisions of
the Internal Revenue Code or ERISA (collectively, Similar
Laws). For these purposes the term employee benefit
plan includes, but is not limited to, qualified pension,
profit-sharing and stock bonus plans, Keogh plans, simplified
employee pension plans and tax deferred annuities or IRAs or
annuities established or maintained by an employer or employee
organization, and entities whose underlying assets are
considered to include plan assets of such plans,
accounts and arrangements. Among other things, consideration
should be given to:
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whether the investment is prudent under
Section 404(a)(1)(B) of ERISA and any other applicable
Similar Laws;
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whether in making the investment, the plan will satisfy the
diversification requirements of Section 404(a)(1)(C) of
ERISA and any other applicable Similar Laws;
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whether the investment will result in recognition of unrelated
business taxable income by the plan and, if so, the potential
after-tax investment return. Please read Material Federal
Income Tax Consequences Tax-Exempt Organizations and
Other Investors; and
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whether making such an investment will comply with the
delegation of control and prohibited transaction provisions of
ERISA, the Internal Revenue Code and any other applicable
Similar Laws.
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The person with investment discretion with respect to the assets
of an employee benefit plan, often called a fiduciary, should
determine whether an investment in us is authorized by the
appropriate governing instrument and is a proper investment for
the plan.
Section 406 of ERISA and Section 4975 of the Internal
Revenue Code prohibit employee benefit plans, and IRAs that are
not considered part of an employee benefit plan, from engaging
in specified transactions involving plan assets with
parties that, with respect to the plan, are parties in
interest under ERISA or disqualified persons
under the Internal Revenue Code unless an exemption is
available. A party in interest or disqualified person who
engages in a non-exempt prohibited transaction may be subject to
excise taxes and other penalties and liabilities under ERISA and
the Internal Revenue Code. In addition, the fiduciary of the
ERISA plan that engaged in such a non-exempt prohibited
transaction may be subject to penalties and liabilities under
ERISA and the Internal Revenue Code.
In addition to considering whether the purchase of common units
is a prohibited transaction, a fiduciary should consider whether
the plan will, by investing in us, be deemed to own an undivided
interest in our assets, with the result that our general partner
would also be a fiduciary of such plan and our operations would
be subject to the regulatory restrictions of ERISA, including
its prohibited transaction rules, as well as the prohibited
transaction rules of the Internal Revenue Code, ERISA and any
other applicable Similar Laws.
The Department of Labor regulations and Section 3(42) of
ERISA provide guidance with respect to whether, in certain
circumstances, the assets of an entity in which employee benefit
plans acquire equity interests would be deemed plan
assets. Under these rules, an entitys assets would
not be considered to be plan assets if, among other
things:
(a) the equity interests acquired by the employee benefit
plan are publicly offered securities i.e., the
equity interests are widely held by 100 or more investors
independent of the issuer and each other, are freely
transferable and are registered under certain provisions of the
federal securities laws;
(b) the entity is an operating
company, i.e., it is primarily engaged in the
production or sale of a product or service, other than the
investment of capital, either directly or through a
majority-owned subsidiary or subsidiaries; or
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(c) there is no significant investment by benefit plan
investors, which is defined to mean that less than 25% of the
value of each class of equity interest, disregarding any such
interests held by our general partner, its affiliates and some
other persons, is held generally by the employee benefit plans
referred to above that are subject to ERISA and IRAs and other
similar vehicles that are subject to Section 4975 of the
Internal Revenue Code.
Our assets should not be considered plan assets
under these regulations because it is expected that the
investment will satisfy the requirements in (a) and
(b) above.
In light of the serious penalties imposed on persons who engage
in prohibited transactions or other violations, plan fiduciaries
contemplating a purchase of common units should consult with
their own counsel regarding the consequences under ERISA, the
Internal Revenue Code and other Similar Laws.
190
UNDERWRITING
Barclays Capital Inc. and Citigroup Global Markets Inc. are
acting as representatives of the underwriters and as joint
book-running managers of this offering. Under the terms of an
underwriting agreement, which will be filed as an exhibit to the
registration statement relating to this prospectus, each of the
underwriters named below has severally agreed to purchase from
us the respective number of common units shown opposite its name
below:
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Number of
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Underwriters
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Common Units
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Barclays Capital Inc.
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Citigroup Global Markets Inc.
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Total
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The underwriting agreement provides that the underwriters
obligation to purchase the common units depends on the
satisfaction of the conditions contained in the underwriting
agreement including:
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the obligation to purchase all of the common units offered
hereby (other than those common units covered by their option to
purchase additional common units as described below), if any of
the common units are purchased;
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the representations and warranties made by us to the
underwriters are true;
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there is no material change in our business or the financial
markets; and
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we deliver customary closing documents to the underwriters.
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Commissions
and Expenses
The following table summarizes the underwriting discounts and
commissions we will pay to the underwriters. These amounts are
shown assuming both no exercise and full exercise of the
underwriters option to purchase additional common units.
The underwriting fee is the difference between the initial price
to the public and the amount the underwriters pay to us for the
common units.
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No Exercise
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Full Exercise
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Per Common Unit
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$
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$
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Total
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$
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$
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The representatives of the underwriters have advised us that the
underwriters propose to offer the common units directly to the
public at the public offering price on the cover of this
prospectus and to selected dealers, which may include the
underwriters, at such offering price less a selling concession
not in excess of $ per common
unit. After the offering, the representatives may change the
offering price and other selling terms.
The expenses of the offering that are payable by us are
estimated to be $ (excluding
underwriting discounts and commissions).
Option to
Purchase Additional Common Units
We have granted the underwriters an option exercisable for
30 days after the date of the underwriting agreement, to
purchase, from time to time, in whole or in part, up to an
aggregate
of additional
common units at the public offering price less underwriting
discounts and commissions. This option may be exercised if the
underwriters sell more
than common
units in connection with this offering. To the extent that this
option is exercised, each underwriter will be obligated, subject
to certain conditions, to purchase its pro rata portion of these
additional common units based on the underwriters
underwriting commitment in the offering as indicated in the
table at the beginning of this Underwriting section.
191
Lock-Up
Agreements
We, our subsidiaries, our general partner and its affiliates,
including C&T Coal and AIM Oxford and the directors and
executive officers of our general partner, have agreed that
without the prior written consent of Barclays Capital Inc., we
and they will not directly or indirectly, (1) offer for
sale, sell, pledge, or otherwise dispose of (or enter into any
transaction or device that is designed to, or could be expected
to, result in the disposition by any person at any time in the
future of) any our common units (including, without limitation,
common units that may be deemed to be beneficially owned by us
or them in accordance with the rules and regulations of the
Securities and Exchange Commission and common units that may be
issued upon exercise of any options or warrants) or securities
convertible into or exercisable or exchangeable for common
units, (2) enter into any swap or other derivatives
transaction that transfers to another, in whole or in part, any
of the economic consequences of ownership of the common units,
(3) make any demand for or exercise any right or file or
cause to be filed a registration statement, including any
amendments thereto, with respect to the registration of any
common units or securities convertible, exercisable or
exchangeable into common units or any of our other securities,
or (4) publicly disclose the intention to do any of the
foregoing for a period of 180 days after the date of this
prospectus.
The
180-day
restricted period described in the preceding paragraph will be
extended if:
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during the last 17 days of the
180-day
restricted period we issue an earnings release or material news
or a material event relating to us occurs; or
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prior to the expiration of the
180-day
restricted period, we announce that we will release earnings
results during the
16-day
period beginning on the last day of the
180-day
period, in which case the restrictions described in the
preceding paragraph will continue to apply until the expiration
of the
18-day
period beginning on the issuance of the earnings release or the
announcement of the material news or occurrence of material
event unless such extension is waived in writing by Barclays
Capital Inc.
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Barclays Capital Inc., in its sole discretion, may release the
common units and other securities subject to the
lock-up
agreements described above in whole or in part at any time with
or without notice. When determining whether or not to release
common units and other securities from
lock-up
agreements, Barclays Capital Inc. will consider, among other
factors, the holders reasons for requesting the release,
the number of common units and other securities for which the
release is being requested and market conditions at the time.
As described below under Directed Unit
Program, any participants in the Directed Unit Program
will be subject to a
180-day
lock
up with respect to any common units sold to them pursuant to
that program. This lock up will have similar restrictions and an
identical extension provision as the
lock-up
agreement described above. Any common units sold in the Directed
Unit Program to our general partners directors or officers
will be subject to the
lock-up
agreement described above.
Offering
Price Determination
Prior to this offering, there has been no public market for our
common units. The initial public offering price will be
negotiated between the representatives and us. In determining
the initial public offering price of our common units, the
representatives will consider:
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the history and prospects for the industry in which we compete;
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our financial information;
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the ability of our management and our business potential and
earning prospects;
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the prevailing securities markets at the time of this
offering; and
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the recent market prices of, and the demand for, publicly traded
common units of generally comparable companies.
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Indemnification
We have agreed to indemnify the underwriters against certain
liabilities, including liabilities under the Securities Act and
liabilities incurred in connection with the Directed Unit
Program referred to below, and to contribute to payments that
the underwriters may be required to make for these liabilities.
Directed
Unit Program
At our request, the underwriters have established a Directed
Unit Program under which they have reserved for sale at the
initial public offering price up
to
common units offered hereby for officers, directors, employees
and certain other persons associated with us. The number of
common units available for sale to the general public will be
reduced by the number of directed common units purchased by
participants in the program. Any directed common units not so
purchased will be offered by the underwriters to the general
public on the same basis as the other common units offered
hereby. Any participants in this program will be prohibited from
selling, pledging or assigning any common units sold to them
pursuant to this program for a period of 180 days after the
date of this prospectus. This
180-day
lock
up period will be extended with respect to our issuance of an
earnings release or if a material news or a material event
relating to us occurs, in the same manner as described above
under
Lock-Up
Agreements.
Stabilization,
Short Positions and Penalty Bids
The representatives may engage in stabilizing transactions,
short sales and purchases to cover positions created by short
sales, and penalty bids or purchases for the purpose of pegging,
fixing or maintaining the price of the common units, in
accordance with Regulation M under the Exchange Act:
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Stabilizing transactions permit bids to purchase the underlying
security so long as the stabilizing bids do not exceed a
specified maximum.
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A short position involves a sale by the underwriters of common
units in excess of the number of common units the underwriters
are obligated to purchase in the offering, which creates the
syndicate short position. This short position may be either a
covered short position or a naked short position. In a covered
short position, the number of common units involved in the sales
made by the underwriters in excess of the number of common units
they are obligated to purchase is not greater than the number of
common units that they may purchase by exercising their option
to purchase additional common units. In a naked short position,
the number of common units involved is greater than the number
of common units in their option to purchase additional common
units. The underwriters may close out any short position by
either exercising their option to purchase additional common
units
and/or
purchasing common units in the open market. In determining the
source of common units to close out the short position, the
underwriters will consider, among other things, the price of
common units available for purchase in the open market as
compared to the price at which they may purchase common units
through their option to purchase additional common units. A
naked short position is more likely to be created if the
underwriters are concerned that there could be downward pressure
on the price of the common units in the open market after
pricing that could adversely affect investors who purchase in
the offering.
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Syndicate covering transactions involve purchases of the common
units in the open market after the distribution has been
completed in order to cover syndicate short positions.
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Penalty bids permit the representatives to reclaim a selling
concession from a syndicate member when the common units
originally sold by the syndicate member are purchased in a
stabilizing or syndicate covering transaction to cover syndicate
short positions.
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These stabilizing transactions, syndicate covering transactions
and penalty bids may have the effect of raising or maintaining
the market price of our common units or preventing or retarding
a decline in the market price of the common units. As a result,
the price of the common units may be higher than the price that
might otherwise exist in the open market. These transactions may
be effected on The New York Stock Exchange or otherwise and, if
commenced, may be discontinued at any time.
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Neither we nor any of the underwriters make any representation
or prediction as to the direction or magnitude of any effect
that the transactions described above may have on the price of
the common units. In addition, neither we nor any of the
underwriters make any representation that the representatives
will engage in these stabilizing transactions or that any
transaction, once commenced, will not be discontinued without
notice.
Electronic
Distribution
A prospectus in electronic format may be made available on the
Internet sites or through other online services maintained by
one or more of the underwriters
and/or
selling group members participating in this offering, or by
their affiliates. In those cases, prospective investors may view
offering terms online and, depending upon the particular
underwriter or selling group member, prospective investors may
be allowed to place orders online. The underwriters may agree
with us to allocate a specific number of common units for sale
to online brokerage account holders. Any such allocation for
online distributions will be made by the representatives on the
same basis as other allocations.
Other than the prospectus in electronic format, the information
on any underwriters or selling group members web
site and any information contained in any other web site
maintained by an underwriter or selling group member is not part
of the prospectus or the registration statement of which this
prospectus forms a part, has not been approved
and/or
endorsed by us or any underwriter or selling group member in its
capacity as underwriter or selling group member and should not
be relied upon by investors.
New York
Stock Exchange
We intend to apply to list our common units on the New York
Stock Exchange under the symbol OXF. The
underwriters have undertaken to sell the minimum number of
common units to the minimum number of beneficial owners
necessary to meet the New York Stock Exchange distribution
requirements for trading.
Discretionary
Sales
The underwriters have informed us that they do not intend to
confirm sales to discretionary accounts that exceed 5% of the
total number of common units offered by them.
Stamp
Taxes
If you purchase common units offered by this prospectus, you may
be required to pay stamp taxes and other charges under the laws
and practices of the country of purchase, in addition to the
offering price listed on the cover page of this prospectus.
Relationships/FINRA
Conduct Rules
An affiliate of Citigroup Global Markets Inc. has performed
commercial banking services for us for which it has received
customary fees and expenses. The underwriters and their
affiliates may in the future perform investment banking,
commercial banking and advisory services for us from time to
time for which they may in the future receive customary fees and
expenses. An affiliate of Citigroup Global Markets Inc. is a
lender under our new credit facility and our existing credit
facility and will receive a portion of the net proceeds from
this offering pursuant to our repayment of the outstanding
balance under our existing credit facility.
Because the Financial Industry Regulatory Authority, Inc., or
FINRA, views the common units offered hereby as interests in a
direct participation program, there is no conflict of interest
between us and the underwriters under Rule 2720 of the
National Association of Securities Dealers, Inc., or NASD,
Conduct Rules and the offering is being made in compliance with
Rule 2310 of the FINRA Rules. Investor suitability with
respect to the common units should be judged similarly to the
suitability with respect to other securities that are listed for
trading on a national securities exchange.
194
Selling
Restrictions
Public
Offer Selling Restrictions Under the Prospectus
Directive
In relation to each member state of the European Economic Area
that has implemented the Prospectus Directive (each, a relevant
member state), with effect from and including the date on which
the Prospectus Directive is implemented in that relevant member
state (the relevant implementation date), an offer of securities
described in this prospectus may not be made to the public in
that relevant member state other than:
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to any legal entity that is authorized or regulated to operate
in the financial markets or, if not so authorized or regulated,
whose corporate purpose is solely to invest in securities;
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to any legal entity that has two or more of (1) an average
of at least 250 employees during the last financial year;
(2) a total balance sheet of more than 43,000,000 and
(3) an annual net turnover of more than 50,000,000,
as shown in its last annual or consolidated accounts;
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to fewer than 100 natural or legal persons (other than qualified
investors as defined in the Prospectus Directive) subject to
obtaining the prior consent of the representatives; or
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in any other circumstances that do not require the publication
of a prospectus pursuant to Article 3 of the Prospectus
Directive,
|
provided that no such offer of securities shall require us or
any underwriter to publish a prospectus pursuant to
Article 3 of the Prospectus Directive.
For purposes of this provision, the expression an offer of
securities to the public in any relevant member state
means the communication in any form and by any means of
sufficient information on the terms of the offer and the
securities to be offered so as to enable an investor to decide
to purchase or subscribe for the securities, as the expression
may be varied in that member state by any measure implementing
the Prospectus Directive in that member state, and the
expression Prospectus Directive means Directive
2003/71/EC and includes any relevant implementing measure in
each relevant member state.
We have not authorized and do not authorize the making of any
offer of securities through any financial intermediary on their
behalf, other than offers made by the underwriters with a view
to the final placement of the securities as contemplated in this
prospectus. Accordingly, no purchaser of the securities, other
than the underwriters, is authorized to make any further offer
of the securities on behalf of us or the underwriters.
Selling
Restrictions Addressing Additional United Kingdom Securities
Laws
This prospectus is only being distributed to, and is only
directed at, persons in the United Kingdom that are qualified
investors within the meaning of Article 2(1)(e) of the
Prospectus Directive (Qualified Investors) that are
also (i) investment professionals falling within
Article 19(5) of the Financial Services and Markets Act
2000 (Financial Promotion) Order 2005 (the Order) or
(ii) high net worth entities, and other persons to whom it
may lawfully be communicated, falling within
Article 49(2)(a) to (d) of the Order (all such persons
together being referred to as relevant persons).
This prospectus and its contents are confidential and should not
be distributed, published or reproduced (in whole or in part) or
disclosed by recipients to any other persons in the United
Kingdom. Any person in the United Kingdom that is not a relevant
person should not act or rely on this document or any of its
contents.
Notice
to Prospective Investors in Switzerland
This document, as well as any other material relating to the
common units that are the subject of the offering contemplated
by this prospectus, do not constitute an issue prospectus
pursuant to Article 652a
and/or
1156
of the Swiss Code of Obligations. The common units will not be
listed on the SIX Swiss Exchange and, therefore, the documents
relating to the common units, including, but not limited to,
this document, do not claim to comply with the disclosure
standards of the listing rules of SIX Swiss Exchange and
corresponding prospectus schemes annexed to the listing rules of
the SIX Swiss Exchange. The common units are being offered in
Switzerland by way of a private placement, i.e., to a small
number of selected investors only,
195
without any public offer and only to investors who do not
purchase the common units with the intention to distribute them
to the public. The investors will be individually approached by
the issuer from time to time. This document, as well as any
other material relating to the common units, is personal and
confidential and do not constitute an offer to any other person.
This document may only be used by those investors to whom it has
been handed out in connection with the offering described herein
and may neither directly nor indirectly be distributed or made
available to other persons without express consent of the
issuer. It may not be used in connection with any other offer
and shall in particular not be copied
and/or
distributed to the public in (or from) Switzerland.
196
VALIDITY
OF THE COMMON UNITS
The validity of the common units offered hereby will be passed
upon for us by Latham & Watkins LLP, Houston, Texas.
Certain legal matters in connection with the common units
offered hereby will be passed upon for the underwriters by
Andrews Kurth LLP, Houston, Texas.
EXPERTS
The consolidated financial statements of Oxford Resource
Partners, LP and subsidiaries for the years ended
December 31, 2009 and 2008, the period from August 24,
2007 to December 31, 2007 and of Oxford Mining Company and
subsidiaries (the predecessor) for the period from
January 1, 2007 to August 23, 2007 have been included
in this prospectus in reliance upon the report of Grant Thornton
LLP an independent registered public accounting firm, appearing
elsewhere herein and upon the authority of said firm as experts
in accounting and auditing in giving said reports.
The combined financial statements for the carved-out surface
mining operations of Phoenix Coal Inc. for the nine months ended
September 30, 2009 and the years ended December 31,
2008 and 2007 included in this prospectus have been audited by
Ernst & Young LLP an independent registered public
accounting firm, as set forth in their report thereon appearing
elsewhere herein, and are included in reliance upon such report
given on the authority of said firm as experts in accounting and
auditing.
The information included in this prospectus relating to the
estimates of our proven and probable reserves associated with
our surface mining operations in Ohio is derived from our
internal estimates, which estimates were audited by John T. Boyd
Company, an independent mining and geological consulting firm.
The information included in this prospectus relating to the
estimates of our proven and probable reserves associated with
our surface mining operations in the Illinois Basin and our
proven and probable underground coal reserves is derived from
reserve reports prepared by John T. Boyd Company. This
information is included in this prospectus upon the authority of
said firm as an expert.
WHERE YOU
CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on
Form S-1
regarding the common units. This prospectus does not contain all
of the information found in the registration statement. For
further information regarding us and the common units offered in
this prospectus, you may desire to review the full registration
statement, including the exhibits. The registration statement,
including the exhibits, may be inspected and copied at the
public reference facilities maintained by the SEC at
100 F Street, N.E., Room 1580,
Washington, D.C. 20549. Copies of this material can also be
obtained upon written request from the Public Reference Section
of the SEC at 100 F Street, N.E., Room 1580,
Washington, D.C. 20549 at prescribed rates or from the
SECs web site on the Internet at
http://www.sec.gov.
Please call the SEC at
1-800-SEC-0330
for further information on public reference rooms.
As a result of the offering, we will file with or furnish to the
SEC periodic reports and other information. These reports and
other information may be inspected and copied at the public
reference facilities maintained by the SEC or obtained from the
SECs website as provided above. Our website on the
Internet will be located at
http://www.oxfordresources.com,
and we expect to make our periodic reports and other information
filed with or furnished to the SEC available, free of charge,
through our website, as soon as reasonably practicable after
those reports and other information are electronically filed
with or furnished to the SEC. Information on our website or any
other website is not incorporated by reference into this
prospectus and does not constitute a part of this prospectus.
We intend to furnish or make available to our unitholders annual
reports containing our audited financial statements prepared in
accordance with GAAP. Our annual report will contain a detailed
statement of any transactions with our general partner or its
affiliates, and of fees, commissions, compensation and other
benefits paid, or accrued to our general partner or its
affiliates for the fiscal year completed, showing the amount
paid or accrued to each recipient and the services performed. We
also intend to furnish or make
197
available to our unitholders quarterly reports containing our
unaudited interim financial information, including the
information required by
Form 10-Q,
for the first three fiscal quarters of each fiscal year.
FORWARD-LOOKING
STATEMENTS
Some of the information in this prospectus may contain
forward-looking statements. These statements can be identified
by the use of forward-looking terminology including
will, may, believe,
expect, anticipate,
estimate, continue, or other similar
words. These statements discuss future expectations, contain
projections of financial condition or of results of operations,
or state other forward-looking information. These
forward-looking statements involve risks and uncertainties. When
considering these forward-looking statements, you should keep in
mind the risk factors and other cautionary statements in this
prospectus. The risk factors and other factors noted throughout
this prospectus could cause our actual results to differ
materially from those contained in any forward-looking statement.
198
INDEX TO
FINANCIAL STATEMENTS
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F-2
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F-4
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|
F-5
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|
F-6
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Report of Independent Registered Public Accounting Firm
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|
F-8
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Consolidated Balance Sheets as of December 31, 2009 and 2008
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|
F-9
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Consolidated Statements of Operations for the years ended
December 31, 2009 and 2008 and the period from
August 24, 2007 to December 31, 2007 and Predecessor
Statement of Operations for the period from January 1, 2007
to August 23, 2007
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|
F-10
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Consolidated Statements of Partners Capital for the years
ended December 31, 2009 and 2008 and the period from
August 24, 2007 to December 31, 2007 and Predecessor
Statement of Shareholders Equity for the period from
January 1, 2007 to August 23, 2007
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F-11
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Consolidated Statements of Cash Flows for the years ended
December 31, 2009 and 2008 and the period from
August 24, 2007 to December 31, 2007 and Predecessor
Statement of Cash Flows for the period from January 1, 2007
to August 23, 2007
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F-12
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Notes to Consolidated Financial Statements
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F-13
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Carved-Out Surface Mining Operations of Phoenix Coal Inc.
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Report of Independent Auditors
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F-37
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Combined Balance Sheets as of September 30, 2009 and
December 31, 2008
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|
F-38
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Combined Statements of Operations and Comprehensive Loss for the
periods ended September 30, 2009 and December 31, 2008
and 2007
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F-39
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Combined Statements of Group Equity for the periods ended
September 30, 2009 and December 31, 2008 and 2007
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F-40
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Combined Statements of Cash Flows for the periods ended
September 30, 2009 and December 31, 2008 and 2007
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F-41
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Notes to Combined Financial Statements
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F-42
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F-1
OXFORD
RESOURCE PARTNERS, LP
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
Introduction
Set forth below are the unaudited pro forma consolidated balance
sheet of Oxford Resource Partners, LP as of December 31,
2009 and the unaudited pro forma consolidated statement of
operations of Oxford Resource Partners, LP for the year ended
December 31, 2009. References to we,
us and our mean Oxford Resource
Partners, LP and its consolidated subsidiaries, unless the
context requires otherwise.
Our unaudited pro forma consolidated balance sheet, which
presents the pro forma effects of the transactions described
below under Pro Forma Consolidated Balance
Sheet (the Offering Transactions) as if such
transactions occurred on December 31, 2009, has been
derived from, and should be read in conjunction with, our
audited historical financial statements included elsewhere in
this prospectus. Our unaudited pro forma consolidated statement
of operations, which presents the pro forma effects of the
Offering Transactions and the Phoenix Coal acquisition described
below under Pro Forma Consolidated Statement
of Operations as if such transactions occurred on
January 1, 2009, has been derived from, and should be read
in conjunction with, our audited historical financial statements
included elsewhere in this prospectus and the audited combined
statements of operations and comprehensive loss for the
carved-out surface mining operations of Phoenix Coal Inc.
included elsewhere in this prospectus. We have not made pro
forma adjustments to our audited historical consolidated balance
sheet as of December 31, 2009 for the Phoenix Coal
acquisition because that acquisition occurred on
September 30, 2009, and, therefore, the effects of that
acquisition are already reflected in our audited historical
consolidated balance sheet as of December 31, 2009.
Our unaudited pro forma consolidated financial statements are
based on certain assumptions and do not purport to be indicative
of the results that actually would have been achieved if the
Offering Transactions and the Phoenix Coal acquisition, as
applicable, had been completed on the dates set forth above.
Moreover, they do not project our financial position or results
of operations as of any future date or for any future period.
Pro Forma
Consolidated Balance Sheet
Our unaudited pro forma consolidated balance sheet is derived
from our audited historical consolidated balance sheet as of
December 31, 2009. The Adjustments for Offering
Transactions column in our unaudited pro forma
consolidated balance sheet contains the adjustments that we
believe are appropriate to give effect to the Offering
Transactions that will occur in connection with our initial
public offering (the Offering) assuming a
December 31, 2009 offering date. Please read
Note 1. Pro Forma Consolidated Balance
Sheet Adjustments. The Offering Transactions include:
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our distribution of approximately
$ million of cash and
accounts receivable to Oxford Resources GP, LLC (our
General Partner), C&T Coal, Inc.
(C&T Coal), AIM Oxford Holdings, LLC (AIM
Oxford), and the participants in our Long-Term Incentive
Plan (our LTIP) pro rata;
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our entry into a new credit facility;
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the conversion of our General Partners 2.0% general
partner interest in us, represented
by
general partner units,
into
general partner units representing a 2.0% general partner
interest in us;
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the conversion of all of our Class B common units held by
C&T Coal, representing a %
limited partner interest in us, into:
(i) common
units, representing a % limited
partner interest in us and
(ii) subordinated
units, representing a % limited
partner interest in us;
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the conversion of all of our Class B common units held by
AIM Oxford, representing a %
limited partner interest in us, into:
(i) common
units, representing a % limited
partner interest in us and
(ii) subordinated
units, representing a % limited
partner interest in us;
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F-2
OXFORD
RESOURCE PARTNERS, LP
UNAUDITED
PRO FORMA CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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the receipt by the participants in our LTIP of a distribution
of common
units for each common unit they currently own, resulting in
their ownership
of common
units, representing an aggregate %
limited partner interest in us;
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|
the issuance by us to the public
of
common units, representing a %
limited partner interest in us;
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the use of the net proceeds from the Offering to:
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|
repay in full the outstanding balance under our existing credit
facility;
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|
distribute approximately
$ million to C&T Coal in
respect of its limited partner interest in us;
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|
distribute approximately
$ million to certain
participants in the LTIP in respect of their limited partner
interests in us; and
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|
pay offering expenses of approximately
$ million; and
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|
|
the use of the net proceeds from borrowings under our new credit
facility of approximately $ to
distribute approximately
$ million to AIM Oxford in
respect of its limited partner interest in us and to pay fees
and expenses associated with our new credit facility of
approximately $ million.
|
Pro Forma
Consolidated Statement of Operations
On September 30, 2009, we acquired 100% of the active
surface mining coal operations of Phoenix Coal. Our unaudited
pro forma consolidated statement of operations is derived from
our audited historical consolidated statement of operations for
the year ended December 31, 2009 and the audited combined
statements of operations and comprehensive loss for the
carved-out
surface mining operations of Phoenix Coal Inc. for the
nine-month period ended September 30, 2009.
The Pro Forma Adjustments column in our unaudited
pro forma consolidated statement of operations contains the
adjustments that we believe are appropriate to present the
Phoenix Coal acquisition on a pro forma basis assuming a
January 1, 2009 acquisition date. Please read
Note 2. Pro Forma Consolidated Statement
of Operations Adjustments. These adjustments include,
among other things, the following:
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increases in revenue as a result of the amortization of
below-market coal sales contracts during the period from
January 1, 2009 to September 30, 2009 (the Stub
Period);
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|
adjustments in depreciation, depletion and amortization expense,
or DD&A expense, over the Stub Period due to a new fair
value basis of assets as a result of change in control
accounting and our leasing of equipment from a third party that
was previously owned by Phoenix Coal; and
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various adjustments to apply our accounting policies to the
Phoenix Coal financial statements during the Stub Period.
|
The Adjustments for Offering Transactions column in
our unaudited pro forma consolidated statement of operations
contains the adjustments that we believe are appropriate to give
effect to the Offering Transactions that will occur in
connection with the Offering assuming a January 1, 2009
offering date. Please read Note 2. Pro
Forma Consolidated Statement of Operations Adjustments. We
have not made adjustments to give effect to the incremental
selling, general and administrative expenses of approximately
$3.0 million that we expect to incur as a result of being a
publicly traded partnership.
F-3
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Adjustments for
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|
|
Offering
|
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|
|
|
|
|
Oxford Resource
|
|
|
Transactions
|
|
|
Pro Forma
|
|
|
|
Partners, LP
|
|
|
(Note 1)
|
|
|
As Adjusted
|
|
|
|
(in thousands)
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
3,366
|
|
|
$
|
93,729
|
(a)
|
|
$
|
30,769
|
|
|
|
|
|
|
|
|
(3,000
|
)
(a)
|
|
|
|
|
|
|
|
|
|
|
|
(90,729
|
)
(a)
|
|
|
|
|
|
|
|
|
|
|
|
(3,366
|
)
(b)
|
|
|
|
|
|
|
|
|
|
|
|
150,000
|
(b)
|
|
|
|
|
|
|
|
|
|
|
|
(13,500
|
)
(b)
|
|
|
|
|
|
|
|
|
|
|
|
(105,731
|
)
(b)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade accounts receivable
|
|
|
24,403
|
|
|
|
(22,403
|
)
(b)
|
|
|
2,000
|
|
Inventory
|
|
|
8,801
|
|
|
|
|
|
|
|
8,801
|
|
Advance royalties
|
|
|
1,674
|
|
|
|
|
|
|
|
1,674
|
|
Prepaid expenses and other current assets
|
|
|
1,424
|
|
|
|
857
|
(a)
|
|
|
2,281
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
39,668
|
|
|
|
5,857
|
|
|
|
45,525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
149,461
|
|
|
|
|
|
|
|
149,461
|
|
Advance royalties
|
|
|
7,438
|
|
|
|
|
|
|
|
7,438
|
|
Other long-term assets
|
|
|
6,796
|
|
|
|
2,143
|
(a)
|
|
|
7,302
|
|
|
|
|
|
|
|
|
(1,637
|
)
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
203,363
|
|
|
$
|
6,363
|
|
|
$
|
209,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
|
4,113
|
|
|
|
(846
|
)
(a)
|
|
|
3,267
|
|
Accounts payable
|
|
|
21,655
|
|
|
|
|
|
|
|
21,655
|
|
Asset retirement obligation current portion
|
|
|
7,377
|
|
|
|
|
|
|
|
7,377
|
|
Deferred revenue current portion
|
|
|
2,090
|
|
|
|
|
|
|
|
2,090
|
|
Accrued taxes other than income taxes
|
|
|
1,464
|
|
|
|
|
|
|
|
1,464
|
|
Accrued payroll and related expenses
|
|
|
2,045
|
|
|
|
|
|
|
|
2,045
|
|
Other current liabilities
|
|
|
5,714
|
|
|
|
|
|
|
|
5,714
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
44,458
|
|
|
|
(846
|
)
|
|
|
43,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
91,598
|
|
|
|
(89,883
|
)
(a)
|
|
|
95,444
|
|
|
|
|
|
|
|
|
93,729
|
(a)
|
|
|
|
|
Asset retirement obligations
|
|
|
5,966
|
|
|
|
|
|
|
|
5,966
|
|
Other long-term liabilities
|
|
|
4,229
|
|
|
|
|
|
|
|
4,229
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
146,251
|
|
|
$
|
3,000
|
|
|
$
|
149,251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PARTNERS CAPITAL
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited Partners
|
|
|
|
|
|
|
|
|
|
|
|
|
Common unitholders
( units
outstanding as of December 31, 2009)
|
|
|
53,960
|
|
|
|
(26,840
|
)
(b)
|
|
|
125,761
|
|
|
|
|
|
|
|
|
(102,030
|
)
(b)
|
|
|
|
|
|
|
|
|
|
|
|
136,500
|
(b)
|
|
|
|
|
|
|
|
|
|
|
|
(1,604
|
)
(c)
|
|
|
|
|
|
|
|
|
|
|
|
65,775
|
(b)
|
|
|
|
|
Subordinated unitholders
( units
outstanding as of December 31, 2009)
|
|
|
|
|
|
|
(65,775
|
)
(b)
|
|
|
(65,775
|
)
|
General partner
( units
outstanding as of December 31, 2009)
|
|
|
1,085
|
|
|
|
(2,630
|
)
(b)
|
|
|
(1,578
|
)
|
|
|
|
|
|
|
|
(33
|
)
(c)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Oxford Resource Partners, LP partners capital
|
|
|
55,045
|
|
|
|
3,363
|
|
|
|
58,408
|
|
Noncontrolling interest
|
|
|
2,067
|
|
|
|
|
|
|
|
2,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
57,112
|
|
|
|
3,363
|
|
|
|
60,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
203,363
|
|
|
$
|
6,363
|
|
|
$
|
209,726
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited pro forma consolidated
financial statements.
F-4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjustments for
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro Forma
|
|
|
|
|
|
Offering
|
|
|
|
|
|
|
Oxford Resource
|
|
|
Phoenix
|
|
|
Adjustments
|
|
|
|
|
|
Transactions
|
|
|
Pro Forma as
|
|
|
|
Partners, LP
|
|
|
Coal
|
|
|
(Note 2)
|
|
|
Pro Forma
|
|
|
(Note 2)
|
|
|
Adjusted
|
|
|
|
(in thousands)
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$
|
254,171
|
|
|
$
|
58,494
|
|
|
$
|
4,556
|
(d)
|
|
$
|
312,490
|
|
|
$
|
|
|
|
$
|
312,490
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,731
|
)
(e)
|
|
|
|
|
|
|
|
|
|
|
|
|
Transportation revenue
|
|
|
32,490
|
|
|
|
|
|
|
|
4,731
|
(e)
|
|
|
37,221
|
|
|
|
|
|
|
|
37,221
|
|
Royalty and non-coal revenue
|
|
|
7,183
|
|
|
|
|
|
|
|
|
|
|
|
7,183
|
|
|
|
|
|
|
|
7,183
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
293,844
|
|
|
|
58,494
|
|
|
|
4,556
|
|
|
|
356,894
|
|
|
|
|
|
|
|
356,894
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales (excluding DD&A, shown separately)
|
|
|
170,698
|
|
|
|
54,531
|
|
|
|
1,464
|
(f)
|
|
|
213,446
|
|
|
|
|
|
|
|
213,446
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,216
|
)
(g)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15,031
|
)
(e)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,000
|
(h)
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of purchased coal
|
|
|
19,487
|
|
|
|
|
|
|
|
10,305
|
(e)
|
|
|
29,792
|
|
|
|
|
|
|
|
29,792
|
|
Cost of transportation
|
|
|
32,490
|
|
|
|
|
|
|
|
4,731
|
(e)
|
|
|
37,221
|
|
|
|
|
|
|
|
37,221
|
|
Depreciation, depletion and amortization
|
|
|
25,902
|
|
|
|
5,800
|
|
|
|
(278
|
)
(i)
|
|
|
31,424
|
|
|
|
|
|
|
|
31,424
|
|
Selling, general and administrative expenses
|
|
|
13,242
|
|
|
|
6,948
|
|
|
|
5,852
|
(e)
|
|
|
26,042
|
|
|
|
(307
|
)
(l)
|
|
|
25,735
|
|
Phoenix Coal selling expense
|
|
|
|
|
|
|
5,852
|
|
|
|
(5,852
|
)
(e)
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales contract termination cost
|
|
|
|
|
|
|
3,000
|
|
|
|
(3,000
|
)
(h)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
261,819
|
|
|
|
76,131
|
|
|
|
(25
|
)
|
|
|
337,925
|
|
|
|
(307
|
)
|
|
|
337,618
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
32,025
|
|
|
|
(17,637
|
)
|
|
|
4,581
|
|
|
|
18,969
|
|
|
|
307
|
|
|
|
19,276
|
|
Interest income
|
|
|
35
|
|
|
|
4
|
|
|
|
|
|
|
|
39
|
|
|
|
|
|
|
|
39
|
|
Interest expense
|
|
|
(6,484
|
)
|
|
|
(2,601
|
)
|
|
|
(156
|
)
(j)
|
|
|
(9,241
|
)
|
|
|
2,900
|
(m)
|
|
|
(6,341
|
)
|
Other income (expense)
|
|
|
|
|
|
|
(5
|
)
|
|
|
5
|
(e)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain from purchase of business
|
|
|
3,823
|
|
|
|
|
|
|
|
|
|
|
|
3,823
|
|
|
|
|
|
|
|
3,823
|
|
Taxes
|
|
|
|
|
|
|
(16
|
)
|
|
|
16
|
(k)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
29,399
|
|
|
|
(20,255
|
)
|
|
|
4,446
|
|
|
|
13,590
|
|
|
|
3,207
|
|
|
|
16,797
|
|
Less: net income attributable to noncontrolling interest
|
|
|
(5,895
|
)
|
|
|
|
|
|
|
|
|
|
|
(5,895
|
)
|
|
|
|
|
|
|
(5,895
|
)
|
Net income (loss) attributable to Oxford Resource Partners,
LP unitholders
|
|
$
|
23,504
|
|
|
$
|
(20,255
|
)
|
|
$
|
4,446
|
|
|
$
|
7,695
|
|
|
$
|
3,207
|
|
|
$
|
10,902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to unaudited pro forma consolidated
financial statements.
F-5
OXFORD
RESOURCE PARTNERS, LP
|
|
NOTE 1.
|
PRO FORMA
CONSOLIDATED BALANCE SHEET ADJUSTMENTS
|
(a) Reflects adjustments relating to the repayment of our
existing credit facility and the entry into our new credit
facility based on an assumed December 31, 2009 transaction
date for the Offering Transactions. These adjustments are based
on the following assumptions:
|
|
|
|
|
the repayment of a total of $90.7 million in debt
outstanding under our existing credit facility;
|
|
|
|
total borrowings of $93.7 million under our new credit
facility; and
|
|
|
|
total fees relating to our new credit facility of
$3.0 million, which amount will be capitalized.
|
(b) Reflects adjustments for the Offering Transactions not
discussed in Note (a) above, based on an assumed
December 31, 2009 transaction date for the Offering
Transactions. These adjustments are based on the following
assumptions:
|
|
|
|
|
the distribution of $3.4 million in cash and
$22.4 million in accounts receivable to our General
Partner, C&T Coal, AIM Oxford and the participants in our
LTIP, pro rata;
|
|
|
|
gross proceeds of $150 million from the issuance and sale
of
common units at an assumed initial offering price
of
per unit (the midpoint of the range set forth on the cover page
of this prospectus);
|
|
|
|
estimated underwriting fees and commissions and offering
expenses of $13.5 million;
|
|
|
|
a total cash distribution of $105.7 million to our General
Partner, C&T Coal, AIM Oxford and the participants in our
LTIP, pro rata; and
|
|
|
|
replenishment of working capital with remaining cash proceeds of
$30.8 million.
|
(c) Reflects adjustments to write off deferred financing
costs of $1.6 million that relate to our existing credit
facility.
|
|
NOTE 2.
|
PRO FORMA
CONSOLIDATED STATEMENT OF OPERATIONS ADJUSTMENTS
|
(d) Reflects the benefit of amortization during the Stub
Period of the below-market coal sales contracts that we acquired
in the Phoenix Coal acquisition. The amount was calculated based
on the amortization we recognized in the fourth quarter of 2009
and the amount of coal shipped on these contracts during the
Stub Period as compared to the fourth quarter of 2009.
(e) Reflects reclassifications to conform the statement of
operations of Phoenix Coal to our basis of presentation.
(f) Reflects additional lease expense we would have
incurred over the Stub Period as a result of our leasing, from a
third party, equipment that was previously owned by Phoenix Coal.
(g) Reflects the application of our accounting policy with
regard to the capitalization threshold for major repairs to
equipment. Phoenix Coal had expensed $1.2 million of
rebuilds of dozer undercarriages during the Stub Period. Our
policy is to capitalize major rebuilds that extend the life of
the asset and thus we have reduced cost of coal sales by
$1.2 million.
(h) Reflects the reclassification of sales contract
termination costs incurred by Phoenix Coal into cost of coal
sales.
(i) Reflects the net effect of the elimination of DD&A
expense attributable to the operations we purchased from Phoenix
Coal and the addition of DD&A expense we would have
incurred based on a
F-6
OXFORD
RESOURCE PARTNERS, LP
Notes to
Unaudited Pro Forma Consolidated Financial
Statements (Continued)
|
|
NOTE 2.
|
PRO FORMA
CONSOLIDATED STATEMENT OF OPERATIONS
ADJUSTMENTS (Continued)
|
January 1, 2009 assumed acquisition date. Our net
adjustment to DD&A expense is a decrease of
$0.3 million and is attributable to the following:
|
|
|
|
|
a decrease in our depletion expense due to lower fair market
values assigned to coal reserves as compared to Phoenix
Coals carrying value, partially offset by
|
|
|
|
an increase in our depreciation expense due to higher fair
market values assigned to equipment purchased as compared to
Phoenix Coals carrying value.
|
(j) As a result of the Phoenix Coal acquisition, interest
expense increased $0.2 million over the Stub Period. This
increase would have been attributable to increased debt levels
and higher interest rates applicable to our existing credit
facility that we amended in connection with the acquisition. Our
amortization of deferred financing expenses also increased over
the Stub Period due to amendment fees paid to lenders as a
result of the amendment to our existing credit facility. These
items increased our interest expense by $2.8 million, which
was partially offset by the elimination of the historical
interest expense of Phoenix Coal of $2.6 million.
(k) Reflects the elimination of Phoenix Coals income
taxes that we would not have incurred because of our status as a
partnership that does not pay federal income taxes.
(l) Reflects the elimination of advisory fees of
$0.3 million paid to affiliates of AIM Oxford that would
not have been paid if we were a publicly traded partnership.
(m) Reflects a decrease in interest expense of
$2.9 million to reflect a lower effective interest rate
associated with our new credit facility, partially offset by
higher amortization of deferred financing cost associated with
our new credit facility.
F-7
Report of
Independent Registered Public Accounting Firm
To the Board of Directors of Oxford Resources GP, LLC (which is
the General Partner of Oxford Resource Partners, LP) and the
General Partner and Limited Partners of Oxford Resource
Partners, LP:
We have audited the accompanying consolidated balance sheets of
Oxford Resource Partners, LP and subsidiaries (the
Partnership) as of December 31, 2009 and 2008,
and the related consolidated statements of operations,
partners capital and shareholders equity and cash
flows of Oxford Resource Partners, LP and subsidiaries for the
years ended December 31, 2009 and 2008 and the period from
August 24, 2007 (inception) to December 31, 2007 and
of Oxford Mining Company and subsidiaries (the
Predecessor) for the period from January 1,
2007 through August 23, 2007. These financial statements
are the responsibility of the Partnerships management. Our
responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. The Partnership is not required
to have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audit included
consideration of internal control over financial reporting as a
basis for designing audit procedures that are appropriate in the
circumstances, but not for the purpose of expressing an opinion
on the effectiveness of the Partnerships internal control
over financial reporting. Accordingly, we express no such
opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements, and assessing the accounting principles used and
significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Oxford Resource Partners, LP and subsidiaries as of
December 31, 2009 and 2008, and the results of operations
and cash flows of Oxford Resource Partners, LP and subsidiaries
for the years ended December 31, 2009 and 2008, the period
from August 24, 2007 (inception) to December 31, 2007
and of the Predecessor for the period from January 1, 2007
through August 23, 2007 in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 2, the Partnership changed its method
of accounting and reporting for noncontrolling interests in
subsidiaries in 2009 for all periods presented due to the
adoption of Statement of Financial Accounting Standards
No. 160,
Noncontrolling Interests in Consolidated
Financial Statements
, codified in FASB ASC 810
Consolidation.
/s/ GRANT THORNTON LLP
Cleveland, Ohio
March 24, 2010
F-8
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
(in
thousands, except for unit information)
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
ASSETS
|
Cash and cash equivalents
|
|
$
|
3,366
|
|
|
$
|
15,179
|
|
Trade accounts receivable
|
|
|
24,403
|
|
|
|
21,528
|
|
Inventory
|
|
|
8,801
|
|
|
|
5,134
|
|
Advance royalties
|
|
|
1,674
|
|
|
|
1,509
|
|
Prepaid expenses and other current assets
|
|
|
1,424
|
|
|
|
787
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
39,668
|
|
|
|
44,137
|
|
Property, plant and equipment, net
|
|
|
149,461
|
|
|
|
112,446
|
|
Advance royalties
|
|
|
7,438
|
|
|
|
8,126
|
|
Other long-term assets
|
|
|
6,796
|
|
|
|
6,588
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
203,363
|
|
|
$
|
171,297
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
|
Current portion of long-term debt
|
|
$
|
4,113
|
|
|
$
|
2,535
|
|
Accounts payable
|
|
|
21,655
|
|
|
|
22,654
|
|
Asset retirement obligation current portion
|
|
|
7,377
|
|
|
|
4,749
|
|
Deferred revenue current portion
|
|
|
2,090
|
|
|
|
13,250
|
|
Accrued taxes other than income taxes
|
|
|
1,464
|
|
|
|
1,117
|
|
Accrued payroll and related expenses
|
|
|
2,045
|
|
|
|
326
|
|
Other current liabilities
|
|
|
5,714
|
|
|
|
3,360
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
44,458
|
|
|
|
47,991
|
|
Long-term debt
|
|
|
91,598
|
|
|
|
81,442
|
|
Asset retirement obligations
|
|
|
5,966
|
|
|
|
4,543
|
|
Other long-term liabilities
|
|
|
4,229
|
|
|
|
2,000
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
146,251
|
|
|
$
|
135,976
|
|
|
|
|
|
|
|
|
|
|
Commitments and Contingencies (Note 17)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PARTNERS CAPITAL
|
|
|
|
|
|
|
|
|
Limited partners (6,570,369 and 5,889,484 units outstanding
as of December 31, 2009 and 2008, respectively)
|
|
|
53,960
|
|
|
|
32,371
|
|
General partner (132,909 and 119,643 units outstanding as
of December 31, 2009 and 2008, respectively)
|
|
|
1,085
|
|
|
|
653
|
|
|
|
|
|
|
|
|
|
|
Total Oxford Resource Partners, LP partners capital
|
|
|
55,045
|
|
|
|
33,024
|
|
Noncontrolling interest
|
|
|
2,067
|
|
|
|
2,297
|
|
|
|
|
|
|
|
|
|
|
Total partners capital
|
|
|
57,112
|
|
|
|
35,321
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and partners capital
|
|
$
|
203,363
|
|
|
$
|
171,297
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-9
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
(in
thousands, except for unit information)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oxford Mining
|
|
|
|
Oxford Resource Partners, LP
|
|
|
Company
|
|
|
|
(Successor)
|
|
|
(Predecessor)
|
|
|
|
Years Ended
|
|
|
Period from August 24
|
|
|
Period from January 1
|
|
|
|
December 31,
|
|
|
to December 31,
|
|
|
to August 23,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
|
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$
|
254,171
|
|
|
$
|
193,699
|
|
|
$
|
61,324
|
|
|
$
|
96,799
|
|
Transportation revenue
|
|
|
32,490
|
|
|
|
31,839
|
|
|
|
10,204
|
|
|
|
18,083
|
|
Royalty and non-coal revenue
|
|
|
7,183
|
|
|
|
4,951
|
|
|
|
1,407
|
|
|
|
3,267
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
|
293,844
|
|
|
|
230,489
|
|
|
|
72,935
|
|
|
|
118,149
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of coal sales (excluding depreciation, depletion, and
amortization, shown separately)
|
|
|
170,698
|
|
|
|
151,421
|
|
|
|
40,721
|
|
|
|
70,415
|
|
Cost of purchased coal
|
|
|
19,487
|
|
|
|
12,925
|
|
|
|
9,468
|
|
|
|
17,494
|
|
Cost of transportation
|
|
|
32,490
|
|
|
|
31,839
|
|
|
|
10,204
|
|
|
|
18,083
|
|
Depreciation, depletion, and amortization
|
|
|
25,902
|
|
|
|
16,660
|
|
|
|
4,926
|
|
|
|
9,025
|
|
Selling, general and administrative expenses
|
|
|
13,242
|
|
|
|
9,577
|
|
|
|
2,114
|
|
|
|
3,643
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total costs and expenses
|
|
|
261,819
|
|
|
|
222,422
|
|
|
|
67,433
|
|
|
|
118,660
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
32,025
|
|
|
|
8,067
|
|
|
|
5,502
|
|
|
|
(511
|
)
|
Interest income
|
|
|
35
|
|
|
|
62
|
|
|
|
55
|
|
|
|
26
|
|
Interest expense
|
|
|
(6,484
|
)
|
|
|
(7,720
|
)
|
|
|
(3,498
|
)
|
|
|
(2,386
|
)
|
Gain from purchase of business
|
|
|
3,823
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
29,399
|
|
|
|
409
|
|
|
|
2,059
|
|
|
|
(2,871
|
)
|
Less: net income attributable to noncontrolling interest
|
|
|
(5,895
|
)
|
|
|
(2,891
|
)
|
|
|
(537
|
)
|
|
|
(682
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Oxford Resource Partners,
LP unitholders
|
|
$
|
23,504
|
|
|
$
|
(2,482
|
)
|
|
$
|
1,522
|
|
|
$
|
(3,553
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocated to general partner
|
|
$
|
467
|
|
|
$
|
(50
|
)
|
|
$
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) allocated to limited partners
|
|
$
|
23,037
|
|
|
$
|
(2,432
|
)
|
|
$
|
1,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic earnings per limited partner unit
|
|
$
|
3.80
|
|
|
$
|
(0.44
|
)
|
|
$
|
0.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per limited partner unit
|
|
$
|
3.79
|
|
|
$
|
(0.44
|
)
|
|
$
|
0.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
basic
|
|
|
6,061,072
|
|
|
|
5,554,395
|
|
|
|
4,900,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of limited partner units outstanding
diluted
|
|
|
6,084,508
|
|
|
|
5,554,395
|
|
|
|
4,901,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions paid per limited partner unit
|
|
$
|
2.17
|
|
|
$
|
2.21
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-10
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF PARTNERS
CAPITAL AND SHAREHOLDERS EQUITY
Years ended December 31, 2009 and 2008 and the periods from
inception to December 31, 2007 and from January 1,
2007 to August 23, 2007
(in thousands, except for unit information)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital in
|
|
|
Retained
|
|
|
Common Stock
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
Common
|
|
|
Excess of
|
|
|
Earnings
|
|
|
In
|
|
|
Shareholders
|
|
|
Noncontrolling
|
|
|
Total
|
|
Predecessor
|
|
Stock
|
|
|
Par Value
|
|
|
(Deficit)
|
|
|
Treasury
|
|
|
Equity
|
|
|
Interest
|
|
|
Equity
|
|
|
Balance at December 31, 2006
|
|
$
|
2
|
|
|
$
|
44
|
|
|
$
|
10,252
|
|
|
$
|
(2,077
|
)
|
|
$
|
8,221
|
|
|
$
|
|
|
|
$
|
8,221
|
|
Proceeds from the sale of minority interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
980
|
|
|
|
980
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
(3,553
|
)
|
|
|
|
|
|
|
(3,553
|
)
|
|
|
682
|
|
|
|
(2,871
|
)
|
Shareholders distributions
|
|
|
|
|
|
|
|
|
|
|
(16,339
|
)
|
|
|
|
|
|
|
(16,339
|
)
|
|
|
(343
|
)
|
|
|
(16,682
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at August 23, 2007
|
|
$
|
2
|
|
|
$
|
44
|
|
|
$
|
(9,640
|
)
|
|
$
|
(2,077
|
)
|
|
$
|
(11,671
|
)
|
|
$
|
1,319
|
|
|
$
|
(10,352
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited
|
|
|
Limited
|
|
|
General
|
|
|
General
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Partner
|
|
|
Partners
|
|
|
Partner
|
|
|
Partners
|
|
|
Total
|
|
|
Noncontrolling
|
|
|
Partners
|
|
Successor
|
|
Units
|
|
|
Capital
|
|
|
Units
|
|
|
Capital
|
|
|
Units
|
|
|
interest
|
|
|
Capital
|
|
|
Balance at August 24, 2007
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
|
|
|
$
|
|
|
Partners contributions
|
|
|
4,900,000
|
|
|
|
54,880
|
|
|
|
100,000
|
|
|
|
1,120
|
|
|
|
5,000,000
|
|
|
|
1,319
|
|
|
|
57,319
|
|
Predecessor basis adjustment
|
|
|
|
|
|
|
(20,465
|
)
|
|
|
|
|
|
|
(417
|
)
|
|
|
|
|
|
|
|
|
|
|
(20,882
|
)
|
Net income
|
|
|
|
|
|
|
1,492
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
537
|
|
|
|
2,059
|
|
Unit-based compensation
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2007
|
|
|
4,900,000
|
|
|
$
|
35,932
|
|
|
|
100,000
|
|
|
$
|
733
|
|
|
|
5,000,000
|
|
|
$
|
1,856
|
|
|
$
|
38,521
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
|
|
|
|
|
(2,432
|
)
|
|
|
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
2,891
|
|
|
|
409
|
|
Partners contributions
|
|
|
962,500
|
|
|
|
10,780
|
|
|
|
19,643
|
|
|
|
220
|
|
|
|
982,143
|
|
|
|
|
|
|
|
11,000
|
|
Partners distributions
|
|
|
|
|
|
|
(12,253
|
)
|
|
|
|
|
|
|
(250
|
)
|
|
|
|
|
|
|
(2,450
|
)
|
|
|
(14,953
|
)
|
Unit-based compensation
|
|
|
|
|
|
|
468
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
468
|
|
Issuance of units to LTIP participants
|
|
|
26,984
|
|
|
|
(124
|
)
|
|
|
|
|
|
|
|
|
|
|
26,984
|
|
|
|
|
|
|
|
(124
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2008
|
|
|
5,889,484
|
|
|
$
|
32,371
|
|
|
|
119,643
|
|
|
$
|
653
|
|
|
|
6,009,127
|
|
|
$
|
2,297
|
|
|
$
|
35,321
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
|
|
|
|
23,037
|
|
|
|
|
|
|
|
467
|
|
|
|
|
|
|
|
5,895
|
|
|
|
29,399
|
|
Partners contributions
|
|
|
650,029
|
|
|
|
11,329
|
|
|
|
13,266
|
|
|
|
231
|
|
|
|
663,295
|
|
|
|
|
|
|
|
11,560
|
|
Partners distributions
|
|
|
|
|
|
|
(13,141
|
)
|
|
|
|
|
|
|
(266
|
)
|
|
|
|
|
|
|
(6,125
|
)
|
|
|
(19,532
|
)
|
Unit-based compensation
|
|
|
|
|
|
|
472
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
472
|
|
Issuance of units to LTIP participants
|
|
|
30,883
|
|
|
|
(108
|
)
|
|
|
|
|
|
|
|
|
|
|
30,883
|
|
|
|
|
|
|
|
(108
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
6,570,396
|
|
|
$
|
53,960
|
|
|
|
132,909
|
|
|
$
|
1,085
|
|
|
|
6,703,305
|
|
|
$
|
2,067
|
|
|
$
|
57,112
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to consolidated financial statements.
F-11
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(in
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oxford Mining
|
|
|
|
Oxford Resource Partners, LP
|
|
|
Company
|
|
|
|
(Successor)
|
|
|
(Predecessor)
|
|
|
|
|
|
|
Period from
|
|
|
Period from
|
|
|
|
Years Ended
|
|
|
August 24 to
|
|
|
January 1
|
|
|
|
December 31
|
|
|
December 31
|
|
|
to August 23
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
|
CASH FLOWS FROM OPERATING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Oxford Resource Partners, LP
unitholders
|
|
$
|
23,504
|
|
|
$
|
(2,482
|
)
|
|
$
|
1,522
|
|
|
$
|
(3,553
|
)
|
Adjustments to reconcile net income (loss) to net cash provided
by (used
in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion, and amortization
|
|
|
25,902
|
|
|
|
16,660
|
|
|
|
4,926
|
|
|
|
9,025
|
|
Interest rate swap adjustment to market
|
|
|
(1,681
|
)
|
|
|
574
|
|
|
|
1,107
|
|
|
|
|
|
Loan fee amortization
|
|
|
530
|
|
|
|
398
|
|
|
|
131
|
|
|
|
148
|
|
Loss on debt extinguishment
|
|
|
1,252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash compensation expense
|
|
|
472
|
|
|
|
468
|
|
|
|
25
|
|
|
|
|
|
Advanced royalty recoupment
|
|
|
1,390
|
|
|
|
1,020
|
|
|
|
261
|
|
|
|
695
|
|
Loss (gain) on disposal of property and equipment
|
|
|
1,177
|
|
|
|
(1,407
|
)
|
|
|
(9
|
)
|
|
|
(25
|
)
|
(Gain) on acquisition
|
|
|
(3,823
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncontrolling interest in subsidiary earnings
|
|
|
5,895
|
|
|
|
2,891
|
|
|
|
537
|
|
|
|
682
|
|
(Increase) decrease in assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(2,875
|
)
|
|
|
(3,906
|
)
|
|
|
834
|
|
|
|
(1,785
|
)
|
Inventory
|
|
|
(2,062
|
)
|
|
|
(479
|
)
|
|
|
358
|
|
|
|
(847
|
)
|
Other assets
|
|
|
(2,807
|
)
|
|
|
(494
|
)
|
|
|
(4,368
|
)
|
|
|
(167
|
)
|
Increase (decrease) in liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable and other liabilities
|
|
|
1,412
|
|
|
|
6,720
|
|
|
|
(11,347
|
)
|
|
|
10,386
|
|
Asset retirement obligation
|
|
|
1,094
|
|
|
|
1,509
|
|
|
|
(454
|
)
|
|
|
3,178
|
|
Provision for below-market contracts and deferred revenue
|
|
|
(13,840
|
)
|
|
|
12,479
|
|
|
|
(2,001
|
)
|
|
|
(103
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
35,540
|
|
|
|
33,951
|
|
|
|
(8,478
|
)
|
|
|
17,634
|
|
CASH FLOWS FROM INVESTING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Phoenix Coal acquisition
|
|
|
(18,275
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of mineral rights and land
|
|
|
(5,049
|
)
|
|
|
(284
|
)
|
|
|
(24,560
|
)
|
|
|
(1,919
|
)
|
Purchase of producing mines
|
|
|
(2,346
|
)
|
|
|
(1,476
|
)
|
|
|
(312
|
)
|
|
|
(2,285
|
)
|
Royalty advances
|
|
|
(679
|
)
|
|
|
(858
|
)
|
|
|
(88
|
)
|
|
|
(1,201
|
)
|
Purchase of property and equipment
|
|
|
(24,850
|
)
|
|
|
(25,188
|
)
|
|
|
(77,155
|
)
|
|
|
(11,305
|
)
|
Proceeds from sale of property and equipment
|
|
|
88
|
|
|
|
3,972
|
|
|
|
|
|
|
|
|
|
Change in restricted cash
|
|
|
(4
|
)
|
|
|
(67
|
)
|
|
|
(1,221
|
)
|
|
|
|
|
Payments received notes receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(51,115
|
)
|
|
|
(23,901
|
)
|
|
|
(103,336
|
)
|
|
|
(16,619
|
)
|
CASH FLOWS FROM FINANCING ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from borrowings
|
|
|
9,810
|
|
|
|
14,800
|
|
|
|
74,549
|
|
|
|
6,445
|
|
Payments on borrowings
|
|
|
(2,576
|
)
|
|
|
(5,853
|
)
|
|
|
(175
|
)
|
|
|
(6,964
|
)
|
Capital contributions from partners
|
|
|
11,560
|
|
|
|
11,000
|
|
|
|
36,400
|
|
|
|
|
|
Proceeds from sale of minority interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
980
|
|
Net advances (payments) on line of credit
|
|
|
4,500
|
|
|
|
(500
|
)
|
|
|
500
|
|
|
|
(13
|
)
|
Distributions to noncontrolling interest
|
|
|
(6,125
|
)
|
|
|
(2,450
|
)
|
|
|
|
|
|
|
(343
|
)
|
Distributions to partners
|
|
|
(13,407
|
)
|
|
|
(12,503
|
)
|
|
|
|
|
|
|
|
|
Payments to shareholders of predecessor
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(339
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
3,762
|
|
|
|
4,494
|
|
|
|
111,274
|
|
|
|
(234
|
)
|
Net increase/(decrease) in cash
|
|
|
(11,813
|
)
|
|
|
14,544
|
|
|
|
(540
|
)
|
|
|
781
|
|
CASH AND CASH EQUIVALENTS, beginning of period
|
|
|
15,179
|
|
|
|
635
|
|
|
|
1,175
|
|
|
|
394
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS, end of period
|
|
$
|
3,366
|
|
|
$
|
15,179
|
|
|
$
|
635
|
|
|
$
|
1,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes to
consolidated financial statements.
F-12
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
|
NOTE 1:
|
ORGANIZATION
AND PRESENTATION
|
Significant
Relationships Referenced in Notes to Consolidated Financial
Statements
|
|
|
|
|
We, us, our,
Successor or the Partnership means the
business and operations of Oxford Resource Partners, LP, the
parent entity, as well as its consolidated subsidiaries.
|
|
|
|
ORLP means Oxford Resource Partners, LP,
individually as the parent entity, and not on a consolidated
basis.
|
|
|
|
Our GP means Oxford Resources GP, LLC, the general
partner of Oxford Resource Partners, LP.
|
Organization
We are a low cost producer of high value steam coal. We focus on
acquiring steam coal reserves that we can efficiently mine with
our modern, large scale equipment. Our reserves and operations
are strategically located in Northern Appalachia and the
Illinois Basin to serve our primary market area of Illinois,
Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. These
coal reserves are mined by our subsidiaries, Oxford Mining
Company, LLC (Oxford Mining), Oxford Mining
Company-Kentucky, LLC and Harrison Resources, LLC
(Harrison Resources).
We are managed by our GP and all executives, officers and
employees who provide services to us are employees of our GP.
Charles Ungurean, the President and Chief Executive Officer of
our GP and a member of our GPs board of directors, and
Thomas Ungurean, the Senior Vice President, Equipment,
Procurement and Maintenance of our GP, are the co-owners of
C&T Coal, Inc. (C&T Coal). Prior to our
acquisition of Oxford, C&T Coal owned 100% of the
outstanding ownership interest in Oxford Mining Company
(Predecessor or Oxford).
We were formed in August 2007 to acquire all of the
ownership interests in Oxford. On August 24, 2007, AIM
Oxford Holdings, LLC (AIM Oxford) contributed total
consideration to us of $36.4 million in cash, and C&T
Coal contributed 100% of its ownership interest in Oxford to us
for a distribution of $20.4 million in cash and
$16.0 million of working capital which was distributed
prior to this transaction and therefore is not reflected in the
table below. Contemporaneously, we entered into a credit
facility and the initial borrowings were used to pay in full
Oxfords existing debt and to pay transaction cost and
replenish working capital. The transaction costs were
$9.0 million.
The purchase consideration was comprised of the following:
|
|
|
|
|
AIM Oxford capital contributions
|
|
$
|
36,400,000
|
|
Long-term bank borrowing
|
|
|
70,000,000
|
|
Revolver borrowing
|
|
|
2,990,000
|
|
Deemed value of C&T Coals retained interest
|
|
|
19,600,000
|
|
|
|
|
|
|
Subtotal
|
|
|
128,990,000
|
|
|
|
|
|
|
Less:
|
|
|
|
|
Cash on hand
|
|
|
1,034,000
|
|
Distribution to C&T Coal
|
|
|
20,400,000
|
|
|
|
|
|
|
Net purchase consideration
|
|
$
|
107,556,000
|
|
|
|
|
|
|
At that time, C&T Coal and AIM Oxford held a 34.3% and
63.7% limited partner interest in ORLP, respectively, and our GP
owned a 2% general partner interest. Also at that time, the
members of our GP were AIM Oxford with a 65% ownership interest
and C&T Coal with a 35% ownership interest. After taking
into
F-13
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 1:
|
ORGANIZATION
AND PRESENTATION (Continued)
|
account their indirect ownership of ORLP through our GP, AIM
Oxford held a 65% total interest in ORLP and C&T Coal held
a 35% total interest in ORLP.
The acquisition of Oxford was accounted for under the purchase
method of accounting as prescribed by Statement of Financial
Accounting Standards (SFAS) 141,
Business
Combinations,
and we have included all operating assets and
liabilities of Oxford except for bank debt that was paid in full
as part of the transaction. The purchase price was allocated to
the assets acquired and liabilities assumed based on their
estimated fair values at the transaction date. The estimated
fair values of long-lived tangible and intangible assets were
determined primarily through third-party appraisals. Due to
C&T Coals limited partner interest in the Partnership
and its ownership interest in our GP, the purchase accounting
fair value adjustments are limited to the newly acquired 65%
total interest purchased by AIM Oxford pursuant to Emerging
Issues Task Force Abstract (EITF)
88-16,
Basis in Leveraged Buyout Transactions
.
The following is a summary of the fair values of the assets
acquired and liabilities assumed as of the date of acquisition:
|
|
|
|
|
Net working capital
|
|
$
|
5,195,000
|
|
Property and equipment
|
|
|
77,617,000
|
|
Intangibles
|
|
|
4,976,000
|
|
Mineral rights
|
|
|
19,730,000
|
|
Coal sales contracts
|
|
|
(2,726,000
|
)
|
Other
|
|
|
2,764,000
|
|
|
|
|
|
|
Total
|
|
$
|
107,556,000
|
|
|
|
|
|
|
Subsequent to our formation, AIM Oxford and C&T Coal made
several capital contributions for various purposes including
purchasing property, plant and equipment and acquiring the
surface mining operations of Phoenix Coal Corporation
(Phoenix Coal). See Note 3. The capital
contributions were not all in direct proportion to AIM
Oxfords and C&T Coals initial limited partner
interests in us. As a result of the disproportionate capital
contributions, AIM Oxfords and C&T Coals
ownership of the Partnership, as of December 31, 2009, is
64.39% and 32.77%, respectively, with 1.98% and 0.86% interests
being owned by our GP and participants in the Partnerships
Long-Term Incentive Plan (LTIP), respectively. AIM
Oxford and C&T Coal own 66.27% and 33.73%, respectively, in
the GP.
Basis
of Presentation and Principles of Consolidation
The accompanying consolidated financial statements include the
accounts and operations of the Partnership and its consolidated
subsidiaries and are prepared in conformity with accounting
principles generally accepted in the United States of America
(US GAAP). We have included the accounts of our
Predecessor and its subsidiaries for the eight month period
ended August 23, 2007 in the consolidated statements of
operations, cash flows and shareholders equity.
We own a 51% interest in Harrison Resources and are therefore
deemed to have control. As a result, we consolidate all of
Harrison Resources accounts with all material intercompany
transactions and balances being eliminated in our consolidated
financial statements. The 49% portion of Harrison Resources that
we do not own is reflected as Noncontrolling
interest in the consolidated balance sheet. See
Note 16.
F-14
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 2:
|
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
|
Use of
Estimates
In order to prepare financial statements in conformity with US
GAAP, we are required to make estimates and assumptions that
affect the reported amounts of assets and liabilities and the
disclosures of contingent assets and liabilities (if any) at the
date of the financial statements and the reported amounts of
revenue and expenses during the reporting period. The most
significant areas requiring the use of management estimates and
assumptions relate to
units-of-production
amortization calculations, asset retirement obligations, useful
lives for depreciation of fixed assets and estimates of fair
values for asset impairment purposes. The estimates and
assumptions that we use are based upon our evaluation of the
relevant facts and circumstances as of the date of the financial
statements. Actual results could ultimately differ from those
estimates.
Cash
and Cash Equivalents
Cash and cash equivalents consist of all unrestricted cash
balances and highly liquid investments that have an original
maturity of three months or less. Financial instruments and
related items, which potentially subject us to concentrations of
credit risk, consist primarily of cash, cash equivalents and
trade receivables. We place our cash and temporary cash
investments with high credit quality institutions. At times,
such investments may be in excess of the FDIC insurance limit.
We have not experienced any losses in such accounts and believe
we are not exposed to any significant credit risk relating to
our cash and cash equivalents.
Restricted
Cash
We had restricted cash and cash equivalents related to Harrison
Resources of $1,877,000 and $1,873,000 at December 31, 2009
and 2008, respectively, which are included in the balance sheet
caption Other long-term assets due to their
anticipated release from restriction. Harrison Resources
cash, which is deemed to be restricted due to the limitations of
its use for Harrison Resources operations, primarily
relates to funds set aside for future reclamation obligations.
See Note 16.
Allowance
for Doubtful Accounts
We establish an allowance for losses on trade receivables when
it is probable that all or part of the outstanding balance will
not be collected. Our management regularly reviews the
probability that a receivable will be collected and establishes
or adjusts the allowance as necessary. There was no allowance
for doubtful accounts at December 31, 2009 and 2008.
Inventory
Inventory consists of coal that has been completely uncovered or
that has been removed from the pit and stockpiled for crushing,
washing, or shipment to customers. Inventory also consists of
supplies, spare parts and fuel. Inventory is valued at the lower
of average cost or market. The cost of coal inventory includes
certain operating expenses and operating overhead.
Property,
Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures
that extend the useful lives of existing plant and equipment are
capitalized. Maintenance and repairs that do not extend the
useful life or increase productivity are charged to operating
expense as incurred. Exploration expenditures are charged to
operating expense as incurred, including costs related to
locating coal deposits and drilling and evaluation costs
incurred
F-15
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 2:
|
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
|
to assess the economic viability of such deposits. Plant and
equipment are depreciated principally on the straight-line
method over the estimated useful lives of the assets based on
the following schedule:
|
|
|
|
|
|
Buildings and tipple
|
|
|
25 - 39 years
|
|
|
Machinery and equipment
|
|
|
7 - 12 years
|
|
|
Vehicles
|
|
|
5 - 7 years
|
|
|
Furniture and fixtures
|
|
|
3 - 7 years
|
|
|
Railroad siding
|
|
|
7 years
|
|
|
We acquire our reserves through purchases or leases of coal
reserves. Coal reserves are recorded at fair value under
purchase accounting at our formation date of August 24,
2007 or as part of the Phoenix Coal acquisition. See
Note 3. We deplete our reserves using the
units-of-production
method, without residual value, on the basis of tonnage mined in
relation to estimated recoverable tonnage. At December 31,
2009 and 2008, all of our reserves were attributed to mine
complexes engaged in mining operations or leased to third
parties. We believe that the carrying value of these reserves
will be recovered. Residual surface values are classified as
land and not depleted.
Exploration expenditures are charged to operating expense as
incurred, including costs related to locating coal deposits and
drilling and evaluation costs incurred to assess the economic
viability of such deposits. Once the economic viability of such
deposits is established, future expenditures are classified as
mine development costs and are capitalized until production
commences. Amortization of these mine development costs is
initiated when the mine begins production using the
units-of-production
method based upon the estimated recoverable tonnage.
Financial
Instruments and Derivative Financial Instruments
Our financial instruments include cash and cash equivalents,
accounts receivable, accounts payable, fixed rate debt, variable
rate debt, an interest rate swap agreement and an interest rate
cap agreement. We do not hold or issue financial instruments or
derivative financial instruments for trading purposes.
We used an interest rate swap agreement to partially reduce
risks related to floating rate financing agreements that are
subject to changes in the market rate of interest. Terms of the
interest rate swap agreement required us to receive a variable
interest rate and pay a fixed interest rate. Our interest rate
swap agreement and its variable rate financings were based upon
the three-month London Interbank Offered Rate
(LIBOR). We currently have an interest rate cap
agreement that sets an upper limit on LIBOR that we would have
to pay under the terms of our existing credit facility. We did
not elect hedge accounting for either agreement and so changes
in market value on these derivatives are included in interest
expense on the consolidated statements of operations.
We measure our derivatives (interest rate swap agreement or
interest rate cap agreement) at fair value on a recurring basis
using significant observable inputs, which are Level 2
inputs as defined in the fair value hierarchy. See Note 12.
Our risk management policy is to purchase up to 75% of our
diesel fuel gallons on fixed price forward contracts. These
contracts meet the normal purchases and sales exclusion and
therefore are not accounted for as derivatives. We take physical
delivery of all the fuel under these forward contracts and such
contracts have a term of one year or less.
F-16
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 2:
|
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
|
Advance
Royalties
A substantial portion of our reserves are leased. Advance
royalties are advance payments made to lessors under terms of
mineral lease agreements that are recoupable through a reduction
in royalties payable on future production. Amortization of
leased coal interests is computed using the
units-of-production
method over estimated recoverable tonnage.
Long-Lived
Assets
We follow authoritative guidance that requires projected future
cash flows from use and disposition of assets to be compared
with the carrying amounts of those assets when impairment
indicators are present. When the sum of projected cash flows is
less than the carrying amount, impairment losses are indicated.
If the fair value of the assets is less than the carrying amount
of the assets, an impairment loss is recognized. In determining
such impairment losses, discounted cash flows or asset
appraisals are utilized to determine the fair value of the
assets being evaluated. Also, in certain situations, expected
mine lives are shortened because of changes to planned
operations. When that occurs and it is determined that the
mines underlying costs are not recoverable in the future,
reclamation and mine closure obligations are accelerated. To the
extent it is determined that an assets carrying value will
not be recoverable during a shorter mine life, the asset is
written down to its recoverable value. No impairment losses were
recognized during any of the years or periods presented.
Identifiable
Intangible Assets and Liabilities
Identifiable intangible assets are recorded in other assets in
the accompanying consolidated balance sheets. We capitalize
costs incurred in connection with borrowings or the
establishment of credit facilities. These costs are amortized as
an adjustment to interest expense over the life of the
borrowings or term of the credit facility using the interest
method.
We also have recorded intangible assets and liabilities at fair
value associated with certain customer relationships and
below-market coal sales contracts, respectively. These balances
arose from the use of purchase accounting for business
combinations and so the assets and liabilities were adjusted to
fair value. These intangible assets are being amortized over
their expected useful lives. See the Coal Sales
Contracts section of Note 2 and Note 7 for
further details.
Asset
Retirement Obligation
Our asset retirement obligations, or AROs, arise from the
Surface Mining Control and Reclamation Act of 1977 (SMCRA) and
similar state statutes, which require that mine property be
restored in accordance with specified standards and an approved
reclamation plan. Our AROs are recorded initially at fair value.
It has been our practice, and we anticipate that it will
continue to be our practice, to perform a substantial portion of
the reclamation work using internal resources. Hence the
estimated costs used in determining the carrying amount of our
AROs may exceed the amounts that are eventually paid for
reclamation costs if the reclamation work was performed using
internal resources.
To determine the fair value of our AROs, we calculate on a mine
by mine basis the present value of estimated reclamation cash
flows. This process requires us to estimate the current
disturbed acreage subject to reclamation, estimates of future
reclamation costs and assumptions regarding the mines
productivity. These cash flows are discounted at the
credit-adjusted, risk free interest rate based on
U.S. Treasury bonds with a maturity similar to the expected
lives of our mines.
F-17
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 2:
|
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
|
When the liability is initially recorded for the costs to open a
new mine site, the offset is recorded to the producing mine
asset. Over time, the ARO liability is accreted to its present
value, and the capitalized cost is depreciated over the
units-of-production
for the related mine. The liability is also increased as
additional land is disturbed during the mining process. The
timeline between digging the mining pit and extracting the coal
is relatively short; therefore, much of the liability created
for active mining is expensed within a month or so of
establishment because the related coal has been extracted. If
the assumptions used to estimate the ARO do not materialize as
expected or regulatory changes occur, reclamation costs or
obligations to perform reclamation and mine closure activities
could be materially different than currently estimated. We
review our entire reclamation liability at least annually and
make necessary adjustments for permit changes as granted by
state authorities, additional costs resulting from revisions to
cost estimates and the quantity of disturbed acreage during the
current year. At December 31, 2009, we had recorded ARO
liabilities of $13.3 million, including amounts reported as
current liabilities. On an aggregate undiscounted basis, we
estimate the cost of final mine closure to be approximately
$15.5 million.
Income
Taxes
Prior to being contributed to us in August 2007, Oxford elected
to be recognized as an S Corporation under the
provisions of the Internal Revenue Code, which provides that, in
lieu of federal and state income taxes, the shareholders were
taxed on their proportionate share of Oxfords income,
deductions, losses and credits. Therefore, no provision or
liability for federal or state income taxes was presented in
Oxfords financial statements.
As a partnership, we are not a taxable entity for federal or
state income tax purposes; the tax effect of our activities
passes through to our unitholders. Therefore, no provision or
liability for federal or state income taxes is included in our
financial statements. Net income for financial statement
purposes may differ significantly from taxable income reportable
to our unitholders as a result of timing or permanent
differences between financial reporting under US GAAP and the
regulations promulgated by the Internal Revenue Service.
Authoritative accounting guidance on accounting for uncertainty
in income taxes establishes the criterion that an individual tax
position is required to meet for some or all of the benefits of
that position to be recognized in our financial statements. On
initial application, the uncertain tax position guidance has
been applied to all tax positions for which the statute of
limitations remains open. Only tax positions that meet the
more-likely-than-not recognition threshold at the adoption date
are recognized or will continue to be recognized.
Revenue
Recognition
Revenue from coal sales is recognized and recorded when shipment
or delivery to the customer has occurred, prices are fixed or
determinable and the title or risk of loss has passed in
accordance with the terms of the sales contract. Under the
typical terms of these contracts, risk of loss transfers to the
customers at the mine or port, when the coal is loaded on the
rail, barge, or truck.
On September 29, 2008, we executed and received a
prepayment from one of our customers of $13,250,000 toward its
future coal deliveries in 2009. This amount was classified as
deferred revenue and recognized as revenue as we delivered the
coal in accordance with the terms of the arrangement. As of
December 31, 2009, $2,090,000 of the prepayment remains on
our balance sheet as deferred revenue. We expect this balance
will be fully recognized as revenue in 2010.
Freight and handling costs paid to third-party carriers and
invoiced to customers are recorded as cost of transportation and
transportation revenue, respectively.
F-18
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 2:
|
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
|
Royalty and non-coal revenue consists of coal royalty income,
service fees for providing landfill earth moving services,
commissions that we receive from a third party who sells
limestone that we recover during our coal mining process,
service fees for operating a coal unloading facility and fees
that we receive for trucking ash for two municipal utility
customers. Revenues are recognized when earned or when services
are performed. Royalty revenue relates to the overriding royalty
we receive on our underground coal reserves that we sublease to
a third party mining company. Prior to June 2008, we did not
receive any royalties because we had purchased the output of
this mine thus no royalty was due to us. Starting in June 2008,
our sublessee began selling the coal production for its own
account which entitled us to start receiving royalty revenue.
For the years ended 2009 and 2008, we received royalties of
$4,513,000 and $1,289,000, respectively.
Coal
Sales Contracts
Our below-market coal sales contracts were acquired through the
Phoenix Coal acquisition and in connection with our acquisition
of Oxford in 2007 for which the prevailing market price for coal
specified in the agreement was in excess of the agreement price.
The fair value was based on discounted cash flows resulting from
the difference between the below-market agreement price and the
prevailing market price at the date of acquisition. The
difference between the below-market agreements cash flows and
the cash flows at the prevailing market price is amortized into
coal sales on the basis of tons shipped over the term of the
respective contract.
Unit-Based
Compensation
We account for unit-based awards in accordance with applicable
guidance, which establishes standards of accounting for
transactions in which an entity exchanges its equity instruments
for goods or services. Unit-based compensation expense is
recorded based upon the fair value of the award at grant date.
Such costs are recognized as expense on a straight-line basis
over the corresponding vesting period. The fair value of our
LTIP units is determined based on the sale price of our limited
partner units in arms-length transactions. The unit price
fair value was increased in September 2009 in connection with
the Phoenix Coal acquisition where additional units were
purchased by C&T Coal and AIM Oxford disproportionately to
their respective ownership interests to help fund the
acquisition. This resulted in C&T Coals previous
ownership interest being diluted. We verified the reasonableness
of the new valuation of our units using traditional valuation
techniques for publicly traded partnerships. See Note 13.
Earnings
Per Unit
For purposes of our earnings per unit calculation, we have
applied the two class method. The classes of units are our
limited partner and general partner units. All outstanding units
share prorata in income allocations and distributions and our
general partner has sole voting rights. Limited partner units
have been separated into Class A and Class B to
prepare for a potential transaction such as an initial public
offering.
Limited Partner Units: Basic earnings per unit are
computed by dividing net income attributable to limited partners
by the weighted average units outstanding during the reporting
period. Diluted earnings per unit are computed similar to basic
earnings per unit except that the weighted average units
outstanding and net income attributable to limited partners are
increased to include phantom units that have not yet vested and
that will convert to LTIP units upon vesting. In years of a
loss, the phantom units are not included in the earnings per
unit calculation.
General Partner Units: Basic earnings per unit are
computed by dividing net income attributable to our GP by the
weighted average units outstanding during the reporting period.
Diluted earnings per unit for our GP are computed similar to
basic earnings per unit except that the net income attributable
to the general partner units is adjusted for the dilutive impact
of the phantom units.
F-19
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 2:
|
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
|
The computation of basic and diluted earnings per unit under the
two-class method for limited partner units and general partner
units is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oxford Resource Partners, LP
|
|
|
|
|
|
|
|
|
|
Period from
|
|
|
|
Years Ended December 31,
|
|
|
August 24 to
|
|
|
|
2009
|
|
|
2008
|
|
|
December 31, 2007
|
|
|
|
(in thousands except unit amounts)
|
|
|
Limited partner units
|
|
|
|
|
|
|
|
|
|
|
|
|
Average units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
6,061,072
|
|
|
|
5,554,395
|
|
|
|
4,900,000
|
|
Effect of unit-based awards
|
|
|
23,436
|
|
|
|
n/a
|
|
|
|
1,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
|
6,084,508
|
|
|
|
5,554,395
|
|
|
|
4,901,956
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to limited partners
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
23,037
|
|
|
$
|
(2,432
|
)
|
|
$
|
1,492
|
|
Diluted
|
|
|
23,038
|
|
|
|
(2,432
|
)
|
|
|
1,492
|
|
Earnings per limited partner unit
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
3.80
|
|
|
$
|
(0.44
|
)
|
|
$
|
0.30
|
|
Diluted
|
|
|
3.79
|
|
|
|
(0.44
|
)
|
|
|
0.30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General partner units
|
|
|
|
|
|
|
|
|
|
|
|
|
Average units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
123,023
|
|
|
|
113,241
|
|
|
|
100,000
|
|
Net income attributable to general partner
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
467
|
|
|
$
|
(50
|
)
|
|
$
|
30
|
|
Diluted
|
|
|
466
|
|
|
|
(50
|
)
|
|
|
30
|
|
Earnings per general partner unit
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
3.80
|
|
|
$
|
(0.44
|
)
|
|
$
|
0.30
|
|
Diluted
|
|
|
3.79
|
|
|
|
(0.44
|
)
|
|
|
0.30
|
|
New
Accounting Standards Issued and Adopted
In June 2009, the FASB issued a new standard establishing the
FASB Accounting Standards Codification
(Codification) as the sole source of authoritative
generally accepted accounting principles. The Codification
reorganized existing U.S. accounting and reporting
standards issued by the FASB and other related private sector
standard setters into a single source of authoritative
accounting principles arranged by topic. The Codification
supersedes all existing U.S. accounting standards; all
other accounting literature not included in the Codification
(other than Securities and Exchange Commission guidance for
publicly traded companies) is considered non-authoritative. This
standard is effective for interim and annual reporting periods
ending after September 15, 2009. The Codification does not
change existing US GAAP.
In September 2009, the FASB issued Accounting Standards Update
(ASU)
2009-06,
Implementation Guidance on Accounting for Uncertainty in Income
Taxes and Disclosure Amendments for Nonpublic Entities. This
update addresses the need for additional implementation guidance
on accounting for uncertainty in income taxes for all entities.
The update clarifies that an entitys tax status as a pass
through or tax-exempt
not-for-profit
entity is a tax position subject to recognition requirements of
the standard and therefore must use the recognition and
measurement guidance when assessing their tax positions. The ASU
2009-06
updates are effective for interim and annual periods ending
after September 15, 2009. The adoption of the guidance in
F-20
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 2:
|
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
|
ASU
2009-06
during the third quarter of 2009 did not have a material impact
on our consolidated financial statements.
In May 2009, the FASB issued new guidance for accounting for
subsequent events that established the accounting for and
disclosure of events that occur subsequent to the balance sheet
date but before financial statements are issued or are available
to be issued. The standard provides guidance on
managements assessment of subsequent events and
incorporates this guidance into accounting literature. The
standard is effective prospectively for interim and annual
periods ending after June 15, 2009. We adopted this
standard for the year ended December 31, 2009 and the
adoption did not impact our consolidated financial statements.
See Note 22.
In December 2007, the FASB issued revised guidance on business
combinations. This new guidance establishes principles and
requirements for the acquirer of a business to recognize and
measure in its financial statements. This amendment applies to
all business combinations and establishes guidance for
recognizing and measuring identifiable assets, liabilities,
noncontrolling interests in the acquiree and goodwill. Most of
these items are recognized at their full fair value on the
acquisition date, including acquisitions where the acquirer
obtains control but less than 100% ownership in the acquiree.
The amendment also requires expensing acquisition-related costs
as incurred and establish disclosure requirements to enable the
evaluation of the nature and financial effects of the business
combination. This guidance is effective for business
combinations with an acquisition date in fiscal years beginning
after December 15, 2008. We have recorded the acquisition
of the surface coal mining assets of Phoenix Coal dated
September 30, 2009 under this revised guidance. See
Note 3. The impact of adoption was to expense $379,000 of
previously capitalized acquisition costs as of January 1,
2009.
In December 2007, the FASB issued new guidance on the accounting
for noncontrolling ownership interests in a subsidiary and for
the deconsolidation of a subsidiary. The guidance requires that
noncontrolling ownership interests in consolidated subsidiaries
be presented in the consolidated balance sheet within
partners capital as a separate component from the
parents equity as opposed to mezzanine equity.
Consolidated net income will now be disclosed as the amount
attributable to both the parent and the noncontrolling
interests. The guidance also provides for changes in the
parents ownership interest in a subsidiary, including
transactions where control is retained and where control is
relinquished; it also requires expanded disclosures in the
consolidated financial statements that clearly identify and
distinguish between the interests of the parent owners and the
interests of the noncontrolling owners of a subsidiary. This
guidance requires retrospective application to all periods
presented, as included in our consolidated financial statements.
New
Accounting Standards Issued and Not Yet Adopted
In August 2009, the FASB issued ASU
2009-05,
Measuring Liabilities at Fair Value. The amendment provides
clarification that in circumstances in which a quoted price in
an active market for the identical liability is not available, a
reporting entity is required to measure fair value using one or
more of the alternative valuation methods outlined in the
guidance. It also clarifies that restrictions preventing the
transfer of a liability should not be considered as a separate
input or adjustment in the measurement of its fair value. This
amendment was effective as of the beginning of interim and
annual reporting periods that begin after August 27, 2009.
The adoption of this guidance did not impact our consolidated
financial statements.
In June 2009, the FASB amended guidance for the consolidation of
a variable interest entity (VIE). This guidance
updated the determination of whether an enterprise is the
primary beneficiary of a VIE, and is, therefore, required to
consolidate an entity, by requiring a qualitative analysis
rather than a quantitative analysis. This standard also requires
continuous reassessments of whether an enterprise is the primary
beneficiary of a VIE. Previously, reconsideration was required
only when specific events had occurred. This
F-21
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 2:
|
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
|
guidance also requires enhanced disclosure about an
enterprises involvement with a VIE. The provisions of
these updates are effective as of the beginning of interim and
annual reporting periods that begin after November 15,
2009. We do not believe that this standard will have a material
impact on our consolidated financial statements.
On September 30, 2009, we acquired 100% of the active
western Kentucky surface mining coal operations of Phoenix Coal.
This acquisition provided us an entry into the Illinois Basin
and consisted of four active surface coal mines and coal
reserves of 20 million tons, as well as mineral rights,
working capital and various coal sales and purchase contracts.
The application of purchase accounting requires that the total
purchase price be allocated to the fair value of assets acquired
and liabilities assumed based on the fair values of the assets
and the liabilities at the acquisition date. The following table
summarizes the fair values of the assets acquired and the
liabilities assumed at the date of acquisition:
|
|
|
|
|
Net working capital
|
|
$
|
1,594,000
|
|
Mineral rights and land
|
|
|
10,264,000
|
|
Property, plant and equipment, net
|
|
|
20,519,000
|
|
Other assets
|
|
|
404,000
|
|
Coal sales contracts
|
|
|
(6,600,000
|
)
|
Other liabilities
|
|
|
(4,083,000
|
)
|
|
|
|
|
|
Net assets acquired
|
|
$
|
22,098,000
|
|
|
|
|
|
|
The purchase price of $18,275,000 was less than the fair value
of the net assets acquired of $22,098,000, and as a result we
recorded a gain of $3,823,000 included in other operating income
in the consolidated statements of operations for the year ended
December 31, 2009. Phoenix Coals surface coal mining
operations had previously operated at a loss and its management
and board of directors elected to exit the surface mining
business to focus on maximizing the value of its underground
reserves.
As part of the acquisition agreement, we agreed to make
additional payments of up to $1,000,000 in two installments to
Phoenix Coal if Phoenix Coal secured specific surface and
mineral rights by certain dates, the last of which will expire
on June 30, 2010. During the fourth quarter of 2009, we
paid $500,000 to Phoenix Coal for obtaining the surface rights
pertaining to certain coal leases. The remaining $500,000
contingent payment was paid to Phoenix Coal in January 2010 for
obtaining the mineral rights and is discussed further in our
subsequent events Note 22. At the closing date, we
concluded that the fair value of the contingent liability was
$1,000,000 as the payment was deemed probable.
We also assumed a contract with a third party to pay a
contingent fee if the third party was able to arrange to lease
or purchase, on our behalf, a specified amount of coal reserves
by July 31, 2010. The contract called for a payment of
$1,000,000; however, we concluded that the fair value of the
contingent liability was $625,000 using a probability weighted
average of the likely outcomes. That amount was recorded as a
liability with a corresponding asset in the consolidated balance
sheet under the caption of Property, plant and equipment,
net.
For the fourth quarter of 2009, our surface coal mine operations
that we acquired from Phoenix Coal reported total revenue of
$22.5 million and a net loss from operations of
approximately $1.9 million. As a result of recording a gain
of $3.8 million relating to the acquisition, the net income
of these operations for the quarter was approximately
$1.9 million, excluding general and administrative overhead
expenses which are not allocated among subsidiaries.
F-22
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 3:
|
ACQUISITION (Continued)
|
The following unaudited pro forma financial information reflects
the consolidated results of operations as if the Phoenix Coal
acquisition had occurred at the beginning of each year presented
below. The pro forma information includes adjustments primarily
for depreciation, depletion and amortization based upon fair
values of property, plant and equipment and mineral rights, the
lease of $11.1 million of equipment, and interest expense
for acquisition debt and additional capital contributions. The
pro forma financial information is not necessarily indicative of
results that actually would have occurred if we had assumed
operation of these assets on the date indicated nor is it
indicative of future results.
|
|
|
|
|
|
|
|
|
|
|
Pro Forma Results
|
|
|
for the Year Ended
|
|
|
December 31,
|
|
|
2009
|
|
2008
|
|
|
(Unaudited)
|
|
Revenue
|
|
$
|
356,894,000
|
|
|
$
|
313,118,000
|
|
Net income (loss) attributable to Oxford Resource Partners, LP
unitholders
|
|
|
7,695,000
|
|
|
|
(20,555,000
|
)
|
Inventory consisted of the following at December 31:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Coal
|
|
$
|
4,759,000
|
|
|
$
|
2,462,000
|
|
Fuel
|
|
|
1,264,000
|
|
|
|
1,053,000
|
|
Supplies and spare parts
|
|
|
2,778,000
|
|
|
|
1,619,000
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8,801,000
|
|
|
$
|
5,134,000
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 5:
|
PROPERTY,
PLANT AND EQUIPMENT, NET
|
Property, plant and equipment, net of accumulated depreciation,
depletion and amortization consisted of the following at
December 31:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Property, plant and equipment gross
|
|
|
|
|
|
|
|
|
Land
|
|
$
|
3,374,000
|
|
|
$
|
2,475,000
|
|
Coal reserves
|
|
|
39,905,000
|
|
|
|
25,597,000
|
|
|
|
|
|
|
|
|
|
|
Land and mineral rights
|
|
|
43,279,000
|
|
|
|
28,072,000
|
|
|
|
|
|
|
|
|
|
|
Buildings and tipple
|
|
|
2,025,000
|
|
|
|
1,375,000
|
|
Machinery and equipment
|
|
|
133,667,000
|
|
|
|
93,908,000
|
|
Vehicles
|
|
|
3,913,000
|
|
|
|
3,005,000
|
|
Furniture and fixtures
|
|
|
690,000
|
|
|
|
594,000
|
|
Railroad sidings
|
|
|
160,000
|
|
|
|
160,000
|
|
Producing mines
|
|
|
8,606,000
|
|
|
|
4,712,000
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment, gross
|
|
|
192,340,000
|
|
|
|
131,826,000
|
|
Less: accumulated depreciation, depletion and amortization
|
|
|
42,879,000
|
|
|
|
19,380,000
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment, net
|
|
$
|
149,461,000
|
|
|
$
|
112,446,000
|
|
|
|
|
|
|
|
|
|
|
F-23
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 5:
|
PROPERTY,
PLANT AND EQUIPMENT, NET (Continued)
|
The amounts of depreciation expense related to owned and leased
fixed assets, depletion expense related to owned and leased coal
reserves, and amortization expense related to producing mines
for the respective years are set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oxford Mining
|
|
|
|
Oxford Resource Partners, LP
|
|
|
Company
|
|
|
|
(Successor)
|
|
|
(Predecessor)
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Period from
|
|
|
|
|
|
|
|
|
|
For the Period from
|
|
|
January 1,
|
|
|
|
|
|
|
|
|
|
Inception to
|
|
|
2007 to
|
|
|
|
For the Years Ended December 31,
|
|
|
December 31,
|
|
|
August 23,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
|
Expense Type:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
$
|
19,632,000
|
|
|
$
|
11,455,000
|
|
|
$
|
3,404,000
|
|
|
$
|
7,827,000
|
|
Depletion
|
|
|
4,672,000
|
|
|
|
3,226,000
|
|
|
|
1,030,000
|
|
|
|
216,000
|
|
Amortization
|
|
|
1,200,000
|
|
|
|
1,533,000
|
|
|
|
318,000
|
|
|
|
982,000
|
|
We lease certain equipment under non-cancelable lease agreements
that expire on various dates through 2014. Generally the lease
agreements are for a period of four years. As of
December 31, 2009, aggregate lease payments that are
required under operating leases that have initial or remaining
non-cancelable lease terms in excess of one year are set forth
below:
|
|
|
|
|
For the years ending December 31, 2010
|
|
$
|
6,289,000
|
|
2011
|
|
|
6,014,000
|
|
2012
|
|
|
4,429,000
|
|
2013
|
|
|
1,570,000
|
|
2014
|
|
|
123,000
|
|
For the years ended December 31, 2009 and 2008, the period
from inception to December 31, 2007 and the Predecessor
period from January 1, 2007 to August 23, 2007, we
incurred lease expenses of approximately $5,428,000, $2,267,000,
$260,000 and $1,775,000, respectively.
We also entered into various coal reserve lease agreements under
which future royalty payments are due based on production. Such
payments are capitalized as advance royalties at the time of
payment, and amortized into royalty expense based on the stated
recoupment rate.
|
|
NOTE 7:
|
INTANGIBLE
ASSETS AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
|
|
Estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
|
|
Accumulated
|
|
|
Net Carrying
|
|
|
|
Life (years)
|
|
|
Cost
|
|
|
Amortization
|
|
|
Value
|
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer relationships
|
|
|
18
|
|
|
$
|
3,315,000
|
|
|
$
|
1,019,000
|
|
|
$
|
2,296,000
|
|
Deferred financing costs
|
|
|
3
|
|
|
|
1,811,000
|
|
|
|
174,000
|
|
|
|
1,637,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total intangible assets
|
|
|
|
|
|
$
|
5,126,000
|
|
|
$
|
1,193,000
|
|
|
$
|
3,933,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Below-market coal sales contracts
|
|
|
3
|
|
|
$
|
6,600,000
|
|
|
$
|
1,705,000
|
|
|
$
|
4,895,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-24
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 7:
|
INTANGIBLE
ASSETS AND LIABILITIES (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2008
|
|
|
|
Estimated
|
|
|
|
|
|
|
|
|
|
|
|
|
Remaining
|
|
|
|
|
|
Accumulated
|
|
|
Net Carrying
|
|
|
|
Life (years)
|
|
|
Cost
|
|
|
Amortization
|
|
|
Value
|
|
|
Intangible assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer relationships
|
|
|
19
|
|
|
$
|
3,315,000
|
|
|
$
|
621,000
|
|
|
$
|
2,694,000
|
|
Deferred financing costs
|
|
|
4
|
|
|
|
1,786,000
|
|
|
|
528,000
|
|
|
|
1,258,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total intangible assets
|
|
|
|
|
|
$
|
5,101,000
|
|
|
$
|
1,149,000
|
|
|
$
|
3,952,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer relationships represent intangible assets that were
recorded at fair value when we acquired Oxford on
August 24, 2007. We amortized these assets over the
expected life of the respective customer relationships. The
amount included in depreciation, depletion and amortization
related to customer relationships was $398,000, $446,000 and
$174,000 for the years ended December 31, 2009 and 2008 and
the period from inception to December 31, 2007,
respectively. Oxford did not have this type of intangible asset
prior to inception.
We capitalize costs incurred in connection with the
establishment of credit facilities. On September 30, 2009,
we amended and restated our credit agreement (the Restated
Credit Agreement). The Restated Credit Agreement was
determined to be substantially different from our prior credit
agreement, and therefore, we wrote off, to interest expense, the
remaining unamortized capitalized costs of $1,252,000 from our
prior credit agreement (the Original Credit
Agreement). We incurred costs of $1,811,000 associated
with the Restated Credit Agreement which we capitalized. These
costs are amortized to interest expense over the life of the
Restated Credit Agreement using the interest method.
Amortization of deferred financing costs included in interest
expense was $530,000, $398,000, $131,000 and $147,000 for the
years ended December 31, 2009 and 2008, the period from
inception to December 31, 2007 and the Predecessor period
from January 1, 2007 to August 23, 2007, respectively.
Expected amortization of identifiable intangible assets and
deferred loan costs for each of the next five years will be
approximately:
|
|
|
|
|
During the years ending December 31, 2010
|
|
$
|
984,000
|
|
2011
|
|
|
868,000
|
|
2012
|
|
|
639,000
|
|
2013
|
|
|
254,000
|
|
2014
|
|
|
227,000
|
|
thereafter
|
|
|
961,000
|
|
We evaluate our intangible assets for impairment when indicators
of impairment exist. For the years ended December 31, 2009
and 2008, the period from inception through December 31,
2007 and the Predecessor period from January 1, 2007 to
August 23, 2007, there were no impairments related to
intangibles.
Based on expected shipments related to the below-market
contracts, we expect to record annual amortization income of:
|
|
|
|
|
During the years ending December 31, 2010
|
|
$
|
2,345,000
|
|
2011
|
|
|
1,919,000
|
|
2012
|
|
|
631,000
|
|
F-25
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 8:
|
OTHER
CURRENT LIABILITIES
|
Other current liabilities consist of the following at December
31:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Below-market coal sales contracts(1)
|
|
$
|
2,345,000
|
|
|
$
|
|
|
Accrued interest and interest rate swap(2)
|
|
|
860,000
|
|
|
|
2,262,000
|
|
Contingent liabilities(1)
|
|
|
1,125,000
|
|
|
|
|
|
Other
|
|
|
1,384,000
|
|
|
|
1,098,000
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5,714,000
|
|
|
$
|
3,360,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
Below-market coal sales contracts and contingent liabilities
assumed with the Phoenix Coal acquisition. See Note 3.
|
|
(2)
|
|
The interest rate swap is discussed in Note 11.
|
|
|
NOTE 9:
|
ASSET
RETIREMENT OBLIGATION
|
Our asset retirement obligations arise from the SMCRA and
similar state statutes, which require that mine property be
restored in accordance with specified standards and an approved
reclamation plan. The required reclamation activities to be
performed are outlined in our mining permits. These activities
include reclaiming the pit and support acreage at surface mines.
We review our asset retirement obligations at least annually and
make necessary adjustments for permit changes as granted by
state authorities and for revisions of estimates of the amount
and timing of costs. When the liability is initially recorded
for the costs to open a new mine site, the offset is recorded to
the producing mine asset. Over time, the ARO liability is
accreted to its present value, and the capitalized cost is
depreciated over the
units-of-production
for the related mine. The liability is also increased as
additional land is disturbed during the mining process. The
timeline between digging the mining pit and extracting the coal
is relatively short; therefore, much of the liability created
for active mining is expensed within a month or so of
establishment because the related coal has been extracted.
At December 31, 2009, we had recorded asset retirement
obligation liabilities of $13.3 million, including amounts
reported as current liabilities. While the precise amount of
these future costs cannot be determined with absolute certainty
as of December 31, 2009, we estimate that the aggregate
undiscounted cost of final mine closure is approximately
$15.5 million.
The following table presents the activity affecting the asset
retirement obligation for the respective years:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Beginning balance
|
|
$
|
9,292,000
|
|
|
$
|
7,644,000
|
|
Accretion expense
|
|
|
650,000
|
|
|
|
459,000
|
|
Payments
|
|
|
(3,358,000
|
)
|
|
|
(2,594,000
|
)
|
Revisions in estimated cash flows
|
|
|
3,802,000
|
|
|
|
3,783,000
|
|
Additions due to acquisition
|
|
|
2,957,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total asset retirement obligation
|
|
$
|
13,343,000
|
|
|
$
|
9,292,000
|
|
Less current portion
|
|
|
(7,377,000
|
)
|
|
|
(4,749,000
|
)
|
|
|
|
|
|
|
|
|
|
Noncurrent liability
|
|
$
|
5,966,000
|
|
|
$
|
4,543,000
|
|
|
|
|
|
|
|
|
|
|
F-26
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
We had long-term debt as of December 31, 2009 and 2008
consisting of the following:
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
FirstLight Funding I, Ltd.:
|
|
|
|
|
|
|
|
|
Term loans
|
|
$
|
64,925,000
|
|
|
$
|
65,625,000
|
|
Acquisition loans
|
|
|
21,304,000
|
|
|
|
14,800,000
|
|
Revolving loans
|
|
|
4,500,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total FirstLight Funding I, Ltd. loans
|
|
|
90,729,000
|
|
|
|
80,425,000
|
|
|
|
|
|
|
|
|
|
|
Note payable Peabody #1
|
|
|
228,000
|
|
|
|
436,000
|
|
Note payable Peabody #2
|
|
|
1,843,000
|
|
|
|
|
|
Note payable CONSOL #1
|
|
|
1,570,000
|
|
|
|
3,089,000
|
|
Note payable CONSOL #2
|
|
|
1,317,000
|
|
|
|
|
|
Note payable Other
|
|
|
24,000
|
|
|
|
27,000
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
95,711,000
|
|
|
|
83,977,000
|
|
Less current portion
|
|
|
(4,113,000
|
)
|
|
|
(2,535,000
|
)
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
91,598,000
|
|
|
$
|
81,442,000
|
|
|
|
|
|
|
|
|
|
|
FirstLight
Funding I, Ltd. Debt
Our Restated Credit Agreement is with a syndicate of lenders
with FirstLight Funding I, Ltd. (FirstLight)
acting as the Agent. The Restated Credit Agreement provides for
borrowings of up to $115,000,000 in the form of $70,000,000 of
term loans, acquisition loans of up to $25,000,000 and a
revolving credit facility of $20,000,000. The Restated Credit
Agreement includes the option of a Base Rate (as defined below)
or LIBOR interest rate plus an applicable margin depending upon
the type of borrowing. Base Rate is defined by the Restated
Credit Agreement as the highest of (a) the rate publicly
quoted from time to time by The Wall Street Journal as the
base rate on corporate loans posted by at least
seventy-five percent (75%) of the nations 30 largest
banks, (b) the sum of the Federal Funds Rate plus
one-half of one percentage point (0.50%), and (c) effective
September 30, 2009, 1.50%. The Restated Credit Agreement is
secured by pledging all of our assets and equity interests in
wholly-owned subsidiaries. The Restated Credit Agreement
requires us to meet various financial covenants and contains
financial and other covenants that limit our ability to, among
other things, effect acquisitions or dispositions and borrow
additional funds.
At December 31, 2009 and 2008, we had $90,729,000 and
$80,425,000, respectively, of borrowings outstanding and
$8,245,000 and $5,404,000, respectively, of letters of credit
outstanding. At December 31, 2009 and 2008, we had
available unused capacity for borrowings under the Restated
Credit Agreement and our original credit agreement
(Original Credit Agreement) of $7,255,000 and
$9,900,000, respectively. As of December 31, 2009 and 2008,
the Base Rate was 3.25% and LIBOR was 0.25% and 1.83%,
respectively.
In February 2009, we were notified by FirstLight that we failed
to provide an updated list of after-acquired properties within
the timeframe outlined in our Original Credit Agreement. This
administrative issue was satisfactorily resolved by the Third
Amendment and Waiver to the Original Credit Agreement that was
executed on February 23, 2009. The Third Amendment and
Waiver waived any potential defaults or potential events of
default due to this administrative oversight. As consideration
for the Third Amendment and Waiver, we paid and expensed
amendment fees totaling $350,000 and the applicable margin for
Term Loan 1, Acquisition Loan 1 and the Revolving Loans (as
defined in the Original Credit Agreement) was increased from
2.5% to 3.0% per annum for LIBOR advances and from 1.25% to
2.75% per annum on Base Rate
F-27
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 10:
|
LONG-TERM
DEBT (Continued)
|
advances. The applicable margins for Term Loan 2 and Acquisition
Loan 2 (as defined in the Original Credit Agreement) were
increased from 5.5% to 6.5% per annum on LIBOR advances and from
4.25% to 6.25% per annum on Base Rate advances.
In order to facilitate the Phoenix Coal acquisition, it was
necessary to enter into negotiations with FirstLight that
resulted in another amendment to our Original Credit Agreement.
The parties agreed to incorporate this amendment and all prior
amendments directly into the Restated Credit Agreement. This
resulted in the Restated Credit Agreement, effective
September 30, 2009. This amendment allowed for the Phoenix
Coal acquisition, subject to certain financial limitations. As
consideration for the Restated Credit Agreement, we paid
amendment fees totaling $500,000 and the applicable margins for
all Term Loan 1, Acquisition Loan 1 and the Revolving Credit
Facility amounts outstanding or new borrowings was increased
from 3.0% to 4.5% per annum on LIBOR loans and from 2.75% to
4.25% per annum on Base Rate loans. The applicable margins for
all Term Loan 2 and Acquisition Loan 2 amounts outstanding
increased from 6.5% to 8.0% per annum on LIBOR advances and from
6.25% to 7.75% per annum on Base Rate advances. The amendment
also provided for a LIBOR interest rate floor of 1.0% per annum.
In addition, the Leverage Ratio covenant, defined as total debt
divided by the last twelve months EBITDA (as defined in
the Restated Credit Agreement), was reduced from 4.25 to 1.00 to
3.50 to 1.00 for the period September 30, 2009 through
December 31, 2010 and to 3.00 to 1.00 thereafter.
We were in compliance with all covenants under the terms of the
Restated Credit Agreement as of December 31, 2009.
Term
Loans
We had $64,925,000 of term loans outstanding as of
December 31, 2009 under the Restated Credit Agreement with
$43,625,000 representing Term Loan 1 borrowings and $21,300,000
representing Term Loan 2 borrowings. Term Loan 1 provided for
borrowings up to $48,000,000 and has a current stated interest
rate equal to Base Rate plus 4.25% per annum on advances or, at
the election of the borrower, LIBOR plus 4.5% per annum on
advances. We are obligated to make quarterly principal payments
of $175,000 on Term Loan 1 until maturity. During 2009, we made
principal repayments of $700,000. Term Loan 2 provided for
borrowings up to $22,000,000 and has a current stated interest
rate of Base Rate plus 7.75% per annum on advances or, at the
election of the borrower, LIBOR plus 8.0% per annum. No
principal repayments are required on Term Loan 2 until maturity.
Both obligations mature in August 2012 and any advances
requested by us were prorated between the two term loans.
Additional borrowings are not permitted under the terms of these
term loans.
Acquisition
Loans
We had $21,304,000 of acquisition loans outstanding as of
December 31, 2009 with $14,454,000 representing borrowings
under Acquisition Loan 1 and $6,850,000 representing Acquisition
Loan 2 borrowings. Acquisition Loan 1 provided for borrowings up
to $17,000,000 and, as of December 31, 2009, had stated
interest rates of Base Rate plus 4.25% per annum on advances or,
at the election of the borrower, LIBOR plus 4.50% per annum on
advances. Acquisition Loan 2 was for $8,000,000 and had a
current stated interest rate of Base Rate plus 7.75% per annum
on advances or, at the election of the borrower, LIBOR plus 8.0%
per annum on advances. Both obligations mature in August 2012
and any advances requested by us are prorated between the two
acquisition loans.
We had until March 30, 2009 to utilize these lines of
credit, after which time no additional borrowings were
permitted. Until March 30, 2009, we paid a commitment fee
of 0.50% per annum that was due quarterly on the unused portion
of these lines of credit. Beginning on March 30, 2009, we
were obligated to make
F-28
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 10:
|
LONG-TERM
DEBT (Continued)
|
quarterly principal payments of $36,500 on Acquisition Loan 1
until maturity. During 2009, we made principal payments of
$146,000. No principal repayments are required on Acquisition
Loan 2 until maturity.
Revolving
Credit Facility
We have a revolving credit facility for Revolving Loans in the
amount of $20,000,000. As of December 31, 2009 and 2008, we
had $4,500,000 and $0, respectively, outstanding under the
revolving credit facility and $8,245,000 and $5,404,000,
respectively, of outstanding letters of credit. The revolving
credit facility has an August 2012 maturity and a current stated
interest rate of Base Rate plus 4.25% per annum on advances, or,
at the election of the borrower, LIBOR plus 4.5% per annum on
advances. Under the facility, letters of credit can be issued in
an aggregate amount not to exceed $12,000,000, which results in
a dollar for dollar reduction in the available capacity. As of
December 31, 2009, we had $7,255,000 available on the
revolving credit facility. The facility matures on
August 24, 2012 and, until that time, only interest
payments are required. For our outstanding letters of credit
issued under the revolving credit facility, we pay issuing fees
of 0.25% per annum on the stated amount of the letters of credit
when we issue a letter of credit and an applicable margin of
2.50% per annum to FirstLight, as the Agent, on behalf of the
lenders. Additionally, we pay a commitment fee of 0.50% per
annum that is due quarterly for any unused capacity under this
revolving credit facility.
Other
Notes Payable
Peabody #1
In July 2007, we
acquired coal reserves from Peabody Energy Corporation through
one of its subsidiaries in exchange for a note payable that is
due in three annual payments of $250,000 at no stated interest
rate. The obligation was secured by real property and mineral
rights and matures in June 2010. The difference between the face
amount and the imputed amount was recorded as a discount using
an imputed interest rate of 9.25% and is being amortized into
interest expense using the interest method.
Peabody #2
In December 2009, we
acquired coal reserves from Peabody Energy Corporation through
one of its subsidiaries in exchange for a down payment of
$1,000,000 and a note payable that is due in two annual payments
of $1,000,000 at no stated interest rate. The obligation was
secured by real property and mineral rights and matures in
December 2011. The difference between the face amount and the
imputed amount was recorded as a discount using an imputed
interest rate of 5.5% and is being amortized into interest
expense using the interest method.
CONSOL #1
In August 2007,
Harrison Resources acquired coal reserves from CONSOL Energy,
through one of its subsidiaries, in exchange for a note payable
that matures in August 2010. The note is payable in three equal
installments of $1,773,000 at no stated interest rate. The
difference between the face amount and the imputed amount was
recorded as a discount using an imputed interest rate of 8.25%
and is being amortized into interest expense using the interest
method.
CONSOL #2
In March 2009, we
acquired coal reserve leases from CONSOL Energy, through one of
its subsidiaries, in exchange for a down payment of $1,500,000
and a note payable that matures in March 2012 in an original
face amount of $1,500,000. The note is payable in monthly
installments based on
units-of-production
with a minimum of $500,000 due annually at no stated interest
rate. The difference between the face amount and the imputed
amount was recorded as a discount using an imputed interest rate
of 4.6% and is being amortized using the interest method.
Other Note Payable
We acquired coal
reserves from an individual with payments due of $5,000 per year
for ten years at no stated interest rate. The obligation matures
in April 2015. The difference between the face amount and the
imputed amount was recorded as a discount using an imputed
interest rate of 6.75% and is being amortized into interest
expense using the interest method.
F-29
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 10:
|
LONG-TERM
DEBT (Continued)
|
Debt
Maturity Table
The total debt of the Partnership matures as follows:
|
|
|
|
|
During the years ending December 31, 2010
|
|
$
|
4,113,000
|
|
2011
|
|
|
2,268,000
|
|
2012
|
|
|
89,317,000
|
|
2013
|
|
|
4,000
|
|
2014
|
|
|
4,000
|
|
Thereafter
|
|
|
5,000
|
|
|
|
|
|
|
|
|
$
|
95,711,000
|
|
|
|
|
|
|
|
|
NOTE 11:
|
INTEREST
RATE CAP AND SWAP AGREEMENTS
|
On September 11, 2009, we entered into an interest rate cap
agreement to hedge our exposure to rising LIBOR interest rates
during 2010. This agreement, which has an effective date of
January 4, 2010 and a notional amount of $50,000,000,
provides for a LIBOR interest rate cap of 2% using three-month
LIBOR. LIBOR was 0.251% as of December 31, 2009. We paid a
fixed fee of $85,000 for this agreement which has quarterly
settlement dates and matures on December 31, 2010. At
December 31, 2009, the value of the interest rate cap was
$34,000 and was recorded in other assets and the
mark-to-market
decrease in value of $51,000 was recorded to interest expense in
the consolidated statement of operations for the year ended
December 31, 2009.
We entered into an interest rate swap agreement on
August 24, 2007 that had an original notional principal
amount of $67,500,000 and a maturity of August 2009. Under the
swap agreement, we paid interest at a fixed rate of 4.83% and
received interest at a variable rate equal to LIBOR (1.43% as of
December 31, 2008), based on the notional amount. The swap
agreement decreased interest expense by $1,681,000 for the year
ended December 31, 2009 and increased interest expense by
$574,000 and $1,107,000 for the year ended December 31,
2008 and the period from inception to December 31, 2007,
respectively. As of December 31, 2008, the fair value of
the swap agreement was a liability of approximately $1,681,000.
The swap agreement matured in August 2009.
|
|
NOTE 12:
|
FAIR
VALUE OF FINANCIAL INSTRUMENTS
|
Effective January 1, 2008, we adopted the provision for
fair value of financial assets and financial liabilities. We
utilized fair value measurement guidance that, among other
things, defines fair value, requires enhanced disclosures about
assets and liabilities carried at fair value and establishes a
hierarchal disclosure framework based upon the quality of inputs
used to measure fair value. We elected to defer the application
of the guidance to nonfinancial assets and liabilities until our
fiscal year 2009 and that application did not have a material
impact on our consolidated financial statements as of
December 31, 2009. As a result of the adoption, we have
elected not to measure any additional financial assets or
liabilities at fair value, other than those which were
previously recorded at fair value prior to the adoption.
The financial instruments measured at fair value on a recurring
basis are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009
|
|
|
Quoted Prices in
|
|
|
|
Significant
|
|
|
Active Markets for
|
|
Significant Other
|
|
Unobservable
|
|
|
Identical Liabilities
|
|
Observable Inputs
|
|
Inputs
|
Description
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Interest rate cap agreement
|
|
$
|
|
|
|
$
|
34,000
|
|
|
$
|
|
|
F-30
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 12:
|
FAIR
VALUE OF FINANCIAL
INSTRUMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2008
|
|
|
Quoted Prices in
|
|
|
|
Significant
|
|
|
Active Markets for
|
|
Significant Other
|
|
Unobservable
|
|
|
Identical Liabilities
|
|
Observable Inputs
|
|
Inputs
|
Description
|
|
(Level 1)
|
|
(Level 2)
|
|
(Level 3)
|
|
Interest rate swap agreement
|
|
$
|
|
|
|
$
|
1,681,000
|
|
|
$
|
|
|
The following methods and assumptions were used to estimate the
fair values of financial instruments for which the fair value
option was not elected:
Cash and cash equivalents, trade accounts receivable and
accounts payable:
The carrying amount reported in
the balance sheets for cash and cash equivalents, trade accounts
receivable and accounts payable approximates its fair value due
to the short maturity of these instruments.
Fixed rate debt:
The fair values of long-term
debt are estimated using discounted cash flow analyses, based on
current market rates for instruments with similar cash flows.
Variable rate debt:
The fair value of variable
rate debt is estimated using discounted cash flow analyses,
based on our best estimates of market rate for instruments with
similar cash flows.
The carrying amounts and fair values of financial instruments
for which the fair value option was not elected are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009
|
|
December 31, 2008
|
|
|
Carrying
|
|
|
|
Carrying
|
|
|
|
|
Amount
|
|
Fair Value
|
|
Amount
|
|
Fair Value
|
|
Fixed rate debt
|
|
$
|
4,982,000
|
|
|
$
|
4,952,000
|
|
|
$
|
3,552,000
|
|
|
$
|
3,311,000
|
|
Variable rate debt
|
|
$
|
90,729,000
|
|
|
$
|
90,729,000
|
|
|
$
|
80,425,000
|
|
|
$
|
80,425,000
|
|
|
|
NOTE 13:
|
LONG-TERM
INCENTIVE PLAN
|
In November 2007, we implemented a Long-Term Incentive Plan or
LTIP whereby equity awards may be granted to executives,
officers, employees, directors, or consultants, as determined by
the Board of Directors Compensation Committee
(Compensation Committee), in the form of partnership
units, and may include distribution equivalent rights. Under
this program, we have granted phantom units that have no rights
until they are converted upon vesting. At our option, we can
issue cash or LTIP units upon vesting, although we do not intend
to settle these awards in cash. To date, we have always issued
units and those units have the right to an allocation of income
and to distributions but are not obligated to participate in any
capital calls. See Unit-Based Compensation section of
Note 2 for a further description of how we value our LTIP
units.
These units are subject to such conditions and restrictions as
our Compensation Committee may determine, including continued
employment or service or achievement of pre-established
performance goals and objectives. Currently, there are no
outstanding performance awards. Although we have the option to
repurchase these units upon employee termination, we currently
do not have the intent to do so. Generally, these units vest in
equal annual increments over four years with accelerated vesting
of the first increment in certain cases. The total number of
units authorized to distribute under the plan was 181,348 at
December 31, 2009. Unless amended by our Compensation
Committee, the LTIP will expire in November 2017.
Surrendered units were used to satisfy the individual tax
obligations of those LTIP participants electing a net issuance
whereby we pay the employees tax liability and the
employee surrenders a sufficient number of units equal to the
amount of tax liability assumed by us. After consideration of
the grant vesting during 2009, 44,431 units remain
available for issuance in the future.
F-31
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 13:
|
LONG-TERM
INCENTIVE PLAN (Continued)
|
We recognize compensation expense over the vesting period of the
units, which is generally four years for each award. For the
years ended December 31, 2009 and 2008 and for the period
from inception to December 31, 2007, our gross LTIP expense
was approximately $472,000, $468,000 and $25,000, respectively,
which is included in selling, general and administrative
expenses (SG&A) in our consolidated statements of
operations. As of December 31, 2009 and 2008, approximately
$840,000 and $1,118,000, respectively, of cost remained
unamortized which we expect to recognize over a remaining
weighted average period of 2 years.
The following table summarizes additional information concerning
our unvested LTIP units:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
Average
|
|
|
|
|
Grant
|
|
|
|
|
Date Fair
|
|
|
Units
|
|
Value
|
|
Unvested balance at December 31, 2007
|
|
|
106,410
|
|
|
$
|
11.20
|
|
Granted
|
|
|
43,172
|
|
|
|
11.20
|
|
Issued
|
|
|
(26,984
|
)
|
|
|
11.20
|
|
Surrendered
|
|
|
(8,825
|
)
|
|
|
11.20
|
|
Forfeited
|
|
|
(6,410
|
)
|
|
|
11.20
|
|
|
|
|
|
|
|
|
|
|
Unvested balance at December 31, 2008
|
|
|
107,363
|
|
|
$
|
11.20
|
|
Granted
|
|
|
11,148
|
|
|
|
17.43
|
|
Issued
|
|
|
(30,883
|
)
|
|
|
11.75
|
|
Surrendered
|
|
|
(8,578
|
)
|
|
|
11.88
|
|
|
|
|
|
|
|
|
|
|
Unvested balance at December 31, 2009
|
|
|
79,050
|
|
|
$
|
11.79
|
|
|
|
|
|
|
|
|
|
|
The value of LTIP units vested during the years ended
December 31, 2009 and 2008 and the period from inception to
December 31, 2007 was $465,000, $401,000 and $0,
respectively.
|
|
NOTE 14:
|
WORKERS
COMPENSATION AND BLACK LUNG
|
We have no liabilities under state statutes and the Federal Coal
Mine Health and Safety Act of 1969, as amended, to pay black
lung benefits to eligible employees, former employees and their
dependents. With regard to workers compensation, we
provide benefits to our employees by being insured through state
sponsored programs or an insurance carrier where there is no
state sponsored program.
We had a money purchase pension plan in which substantially all
full-time employees with more than six months of service
participated. Contributions were made annually at 4% of
qualified wages and an additional 4% was contributed on wages
over the FICA limit up to the maximum allowed under the Internal
Revenue Code. We incurred expense of $1,522,000, $1,083,000,
$379,000 and $496,000 for the years ended December 31, 2009
and 2008, the period from inception to December 31, 2007
and the Predecessor period from January 1, 2007 to
August 23, 2007, respectively.
Effective January 1, 2010, the money purchase pension plan
was replaced with a 401(k) plan.
|
|
NOTE 16:
|
NONCONTROLLING
INTEREST
|
Harrison Resources, a limited liability company, was formed in
March 2006 by Oxford to acquire coal properties, develop mine
sites, and mine coal for sale to customers. Effective
January 30, 2007, 49% of
F-32
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 16:
|
NONCONTROLLING
INTEREST (Continued)
|
Harrison Resources was sold to CONSOL Energy and its ownership
interest is held by one of its subsidiaries. Harrison
Resources revenues which are included in the consolidated
statements of operations were $37,190,000, $20,605,000,
$4,791,000, and $4,250,000 for the years ended December 31,
2009 and 2008 and the periods from inception to
December 31, 2007 and from January 1, 2007 to
August 23, 2007, respectively. Oxford Mining has a contract
mining agreement with Harrison Resources to operate the mines
for an
agreed-upon
per ton price and markets all the coal under a broker agreement
with Harrison Resources.
Harrison Resources cash, which is deemed to be restricted
due to the limitations of its use for Harrison Resources
operations and primarily relates to funds set aside for future
reclamation obligations, was $1,877,000 and $1,873,000 at
December 31, 2009 and 2008, respectively, and is included
in the balance sheet caption Other long-term assets. Harrison
Resources total net assets as of December 31, 2009
and 2008 were $4,218,000 and $4,688,000, respectively
The noncontrolling interest represents the 49% of Harrison
Resources owned by CONSOL Energy, through one of its
subsidiaries, and consists of the following:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
2009
|
|
|
2008
|
|
|
Beginning balance
|
|
$
|
2,297,000
|
|
|
$
|
1,856,000
|
|
Net income
|
|
|
5,895,000
|
|
|
|
2,891,000
|
|
Distributions to owners
|
|
|
(6,125,000
|
)
|
|
|
(2,450,000
|
)
|
|
|
|
|
|
|
|
|
|
Ending balance
|
|
$
|
2,067,000
|
|
|
$
|
2,297,000
|
|
|
|
|
|
|
|
|
|
|
|
|
NOTE 17:
|
COMMITMENTS
AND CONTINGENCIES
|
Coal
Sales Contracts
We are committed under long-term contracts to sell coal that
meets certain quality requirements at specified prices. Most of
these prices are subject to pass through or inflation adjusters
that mitigate some risk from rising costs. Quantities sold under
some of these contracts may vary from year to year within
certain limits at the option of the customer or us. The
remaining life of our long-term contracts ranges from one to
nine years.
Purchase
Commitments
We use independent contractors to mine some of our coal at a few
of our mines. We also purchase coal from third parties in order
to meet quality or delivery requirements under our customer
agreements. We assumed one long-term purchase agreement as a
result of the Phoenix Coal acquisition. Under this agreement, we
are committed to purchase a certain volume of coal until the
coal reserves covered by the contract are depleted. Based on the
proven and probable coal reserves in place at December 31,
2009, we expect this contract to continue beyond five years.
Additionally, we bought coal on the spot market, and the cost of
that coal is dependent upon the market price and quality of the
coal. Supply disruptions could impair our ability to fill
customer orders or require us to purchase coal from other
sources at a higher cost to us in order to satisfy these orders.
Transportation
We depend upon barge, rail, and truck transportation systems to
deliver our coal to our customers. Disruption of these
transportation services due to weather-related problems,
mechanical difficulties, strikes, lockouts, bottlenecks, and
other events could temporarily impair our ability to supply coal
to our customers,
F-33
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 17:
|
COMMITMENTS
AND CONTINGENCIES (Continued)
|
resulting in decreased shipments. We entered into a long-term
transportation contract on April 1, 2006 for rail services,
and that agreement has been amended and extended through
March 31, 2011.
Defined
Contribution Pension Plan
At December 31, 2009, we had an obligation to pay our GP
for the purpose of funding our GPs commitments to the
money purchase pension plan in the amount of $1,522,000. This
amount is expected to be paid by September 2010.
Security
for Reclamation and Other Obligations
As of December 31, 2009, we had $31,300,000 in surety bonds
and $14,000 in cash bonds outstanding to secure certain
reclamation obligations. Additionally, as of December 31,
2009, we had letters of credit outstanding in support of these
surety bonds of $6,900,000 and also a letter of credit of
$1,345,000 guaranteeing an operating lease. Further, as of
December 31, 2009, we had certain road bonds of $645,000
outstanding and performance bonds outstanding of $12,300,000.
Our management believes these bonds and letters of credit will
expire without any claims or payments thereon and thus any
subrogation or other rights with respect thereto will not have a
material adverse effect on our financial position, liquidity or
operations.
Legal
We are involved, from time to time, in various legal proceedings
arising in the ordinary course of business. While the ultimate
results of these proceedings cannot be predicted with certainty,
our management believes these claims will not have a material
adverse effect on our financial position, liquidity or
operations.
Guarantees
Our GP and the Partnership guarantee certain obligations of our
subsidiaries. Our management believes that these guarantees will
expire without any liability to the guarantors, and therefore
any indemnification or subrogation commitments with respect
thereto will not have a material adverse effect on our financial
position, liquidity or operations.
|
|
NOTE 18:
|
CONCENTRATION
OF CREDIT RISK AND MAJOR CUSTOMERS
|
We have a credit policy that establishes procedures to determine
creditworthiness and credit limits for trade customers.
Generally, credit is extended based on an evaluation of the
customers financial condition. Collateral is not generally
required, unless credit cannot be established.
We market our coal principally to electric utilities,
municipalities and electric cooperatives and industrial
customers in Illinois, Indiana, Kentucky, Ohio, Pennsylvania and
West Virginia. As of December 31, 2009 and 2008, accounts
receivable from electric utilities totaled $18.2 million
and $16.3 million or 75% and 76% of total trade
receivables, respectively. A small portion of these sales are
executed through coal brokers. Three customers individually
accounted for greater than 10% of coal sales for the year ended
December 31, 2009 which, in the aggregate, represented
approximately 64.1% of coal sales for the year. Two customers
individually accounted for greater than 10% of coal sales which,
in the aggregate, represented approximately 55.5%, 64.0% and
64.2% of coal sales for the year ended December 31, 2008,
the period from inception to December 31, 2007 and the
Predecessor period from January 1, 2007 to August 23,
2007, respectively. These same customers, in the aggregate,
represented approximately 58.5% and 51.5% of the outstanding
accounts receivable at December 31, 2009 and 2008,
respectively.
F-34
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 19:
|
RELATED
PARTY TRANSACTIONS
|
In connection with our formation in August 2007, the Partnership
and Oxford Mining entered into an administrative and operational
services agreement (Services Agreement) with our GP.
The Services Agreement is terminable by either party upon thirty
days written notice. Under the terms of the Services
Agreement, our GP provides services through its employees to us
and is reimbursed for all related costs incurred on our behalf.
Our GP provides us with services such as general administrative
and management services, human resources, information
technology, finance and accounting, corporate development, real
property, marketing, engineering, operations (including mining
operations), geological, risk management and insurance services.
Pursuant to the Services Agreement, we reimbursed our GP for
costs primarily related to payroll for all the periods after
August 24, 2007, of which $2,504,000 and $2,502,000 were
included in our accounts payable at December 31, 2009 and
2008, respectively.
Also in connection with our formation in August 2007, Oxford
Mining entered into an advisory services agreement
(Advisory Agreement) with certain affiliates of AIM
Oxford. The Advisory Agreement runs for a term of ten years
until August 2017, subject to earlier termination at any time by
the AIM Oxford affiliates. Under the terms of the Advisory
Agreement, the AIM Oxford affiliates have duties as financial
and management advisors to Oxford Mining, including providing
services in obtaining equity, debt, lease and acquisition
financing, as well as providing other financial, advisory and
consulting services for the operation and growth of Oxford
Mining. These services consist of advisory services of a type
customarily provided by sponsors of U.S. private equity
firms to companies in which they have substantial investments.
Such services are rendered at the reasonable request of Oxford
Mining. The basic annual fees under the Advisory Agreement were
$250,000 for 2008, and for 2009 and each year thereafter
increase based on the percentage increase in gross revenues.
Further fees are payable for additional significant services
requested. Pursuant to the Advisory Agreement, advisory fees
were paid to AIM Oxford affiliates of $1,307,000 and $225,000
for the years ended December 31, 2009 and 2008,
respectively. No advisory fees were paid for the period from
inception to December 31, 2007. The advisory fees paid for
2009 included a transaction fee of $1,000,000 paid to the AIM
Oxford affiliates for additional significant services in
connection with the Restated Credit Agreement and the fee is
included in deferred financing costs. See FirstLight Funding I,
Ltd. Debt section of Note 10.
We have debt with CONSOL Energy, the minority owner of Harrison
Resources, as described in Note 10. Also, coal was
purchased for resale from CONSOL Energy in the amount of
$1,089,000 and $4,780,000 during the period from inception to
December 31, 2007 and the Predecessor period from
January 1, 2007 to August 23, 2007, respectively. We
did not purchase coal from CONSOL Energy for resale during the
years ended December 31, 2009 and 2008.
Contract services were provided to Tunnell Hill Reclamation,
LLC, a company with common owners, in the amount of $695,000,
$1,050,000, $186,000 and $1,104,000 for the years ended
December 31, 2009 and 2008, the period from inception to
December 31, 2007 and the Predecessor period from
January 1, 2007 to August 23, 2007, respectively.
Accounts receivable were $70,000 and $0 from Tunnel Hill at
December 31, 2009 and 2008, respectively. We have concluded
that Tunnell Hill Reclamation, LLC does not represent a variable
interest entity.
We had accounts receivable from employees and owners in the
amount of $28,000 and $6,000 at December 31, 2009 and 2008,
respectively, which have been collected in full subsequent to
year end.
F-35
OXFORD
RESOURCE PARTNERS, LP AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
NOTE 20:
|
SUPPLEMENTAL
CASH FLOW INFORMATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oxford Mining
|
|
|
Oxford Resource Partners, LP
|
|
Company
|
|
|
(Successor)
|
|
(Predecessor)
|
|
|
|
|
|
|
For the Period from
|
|
|
|
|
|
|
|
|
Inception to
|
|
For the Period from
|
|
|
For the Years Ended December 31,
|
|
December 31,
|
|
January 1, 2007 to
|
|
|
2009
|
|
2008
|
|
2007
|
|
August 23, 2007
|
|
Cash paid for:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
$
|
6,005,000
|
|
|
$
|
6,395,000
|
|
|
$
|
2,202,000
|
|
|
$
|
2,625,000
|
|
Non-cash activity
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market value of common units vested in LTIP
|
|
|
363,000
|
|
|
|
302,000
|
|
|
|
|
|
|
|
|
|
Increase ( decrease) in:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts payable for purchase of property and equipment
|
|
|
755,000
|
|
|
|
2,270,000
|
|
|
|
(3,941,000
|
)
|
|
|
4,924,000
|
|
|
|
NOTE 21:
|
SEGMENT
INFORMATION
|
We operate in one business segment. We operate surface coal
mines in Northern Appalachia and the Illinois Basin and sell
high value steam coal to utilities, industrial customers or
other coal-related organizations primarily in the eastern United
States. Our operating and executive management reviews and bases
its decisions upon consolidated reports. All three of our
operating subsidiaries participate primarily in the business of
utilizing surface mining techniques to mine domestic coal and
prepare it for sale to their customers. The operating companies
share customers and a particular customer may receive coal from
any one of the operating companies.
|
|
NOTE 22:
|
SUBSEQUENT
EVENTS
|
The following represents material events that have occurred
subsequent to December 31, 2009 through March 24,
2010, the date these financial statements were issued.
We paid Phoenix Coal $500,000 in January 2010 for achieving
specified objectives as to arrangements for additional coal
leases in western Kentucky.
We made a quarterly distribution to our unitholders of
$2,815,000 in February 2010.
We granted LTIP awards in January and February 2010 in the
amount of $649,000. Of those units, the first 25% vested in
January and March respectively with a remaining unvested value
of $487,000. The remaining grant vests ratably over the next
three years.
F-36
Report of
Independent Auditors
The Board of Directors of Phoenix Coal Inc.
We have audited the accompanying combined balance sheets of the
Carved-Out Surface Mining Operations of Phoenix Coal Inc. (the
Company) as described in Note 1, as of September 30,
2009 and December 31, 2008, and the related combined
statements of operations and comprehensive loss, group equity,
and cash flows for the nine months ended September 30, 2009
and for the years ended December 31, 2008 and 2007. These
financial statements are the responsibility of Phoenix Coal
Inc.s management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States. Those standards require
that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement. We were not engaged to perform an audit
of the Companys internal control over financial reporting.
Our audits included consideration of internal control over
financial reporting as a basis for designing audit procedures
that are appropriate in the circumstances, but not for the
purpose of expressing an opinion on the effectiveness of the
Companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
In our opinion, the financial statements referred to above
present fairly, in all material respects, the combined financial
position of the Company as described in Note 1, at
September 30, 2009 and December 31, 2008, and the
combined results of their operations and their cash flows for
the nine months ended September 30, 2009 and for the years
ended December 31, 2008 and 2007 in conformity with
U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Louisville, Kentucky
December 18, 2009
F-37
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Combined Balance
Sheets
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Assets
|
Current assets:
|
|
|
|
|
|
|
|
|
Trade accounts receivable
|
|
$
|
6,349,835
|
|
|
$
|
2,843,134
|
|
Coal inventories
|
|
|
252,357
|
|
|
|
452,558
|
|
Prepaid expenses and other current assets
|
|
|
591,957
|
|
|
|
400,886
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
7,194,149
|
|
|
|
3,696,578
|
|
Property, plant, and equipment, net
|
|
|
48,576,077
|
|
|
|
45,162,984
|
|
Restricted certificates of deposit
|
|
|
|
|
|
|
509,825
|
|
Mining rights, mine development costs and mineral reserves net
of accumulated amortization of $3,796,187 in 2009 and $3,888,082
in 2008
|
|
|
16,707,173
|
|
|
|
15,649,026
|
|
Prepaid royalties
|
|
|
188,602
|
|
|
|
216,147
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
72,666,001
|
|
|
$
|
65,234,560
|
|
|
|
|
|
|
|
|
|
|
Liabilities and shareholders equity
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Trade accounts payable and accrued liabilities
|
|
$
|
8,839,064
|
|
|
$
|
6,449,019
|
|
Current portion of long-term debt
|
|
|
8,224,486
|
|
|
|
6,532,045
|
|
Current portion of asset retirement obligations
|
|
|
1,627,800
|
|
|
|
1,958,000
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
18,691,350
|
|
|
|
14,939,064
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations, less current portion
|
|
|
2,898,278
|
|
|
|
2,366,000
|
|
Long-term debt, less current portion
|
|
|
13,080,972
|
|
|
|
14,641,745
|
|
Group equity
|
|
|
37,995,401
|
|
|
|
33,287,751
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
72,666,001
|
|
|
$
|
65,234,560
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
F-38
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Combined Statements of Operations and Comprehensive
Loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Revenue
|
|
$
|
58,493,767
|
|
|
$
|
76,645,989
|
|
|
$
|
66,973,145
|
|
Cost and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales, exclusive of depreciation and amortization shown
separately
|
|
|
54,531,148
|
|
|
|
71,877,168
|
|
|
|
61,939,870
|
|
Selling expenses
|
|
|
5,851,821
|
|
|
|
8,188,945
|
|
|
|
7,746,824
|
|
General and administrative expenses
|
|
|
6,947,484
|
|
|
|
11,090,565
|
|
|
|
5,822,082
|
|
Depreciation and amortization
|
|
|
5,799,952
|
|
|
|
6,646,543
|
|
|
|
4,064,979
|
|
Sales contract termination cost
|
|
|
3,000,000
|
|
|
|
|
|
|
|
|
|
Asset impairment
|
|
|
|
|
|
|
|
|
|
|
2,873,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
76,130,405
|
|
|
|
97,803,221
|
|
|
|
82,446,810
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from operations
|
|
|
(17,636,638
|
)
|
|
|
(21,157,232
|
)
|
|
|
(15,473,665
|
)
|
Other income (expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
(2,600,873
|
)
|
|
|
(1,811,280
|
)
|
|
|
(86,316
|
)
|
Interest income
|
|
|
3,900
|
|
|
|
6,302
|
|
|
|
8,292
|
|
Other, principally sale of assets
|
|
|
(5,142
|
)
|
|
|
(1,014,424
|
)
|
|
|
739,493
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,602,115
|
)
|
|
|
(2,819,402
|
)
|
|
|
661,469
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes
|
|
|
(20,238,753
|
)
|
|
|
(23,976,634
|
)
|
|
|
(14,812,196
|
)
|
Income taxes
|
|
|
16,081
|
|
|
|
37,838
|
|
|
|
70,155
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss and comprehensive loss
|
|
$
|
(20,254,834
|
)
|
|
$
|
(24,014,472
|
)
|
|
$
|
(14,882,351
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
F-39
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Combined
Statements of Group Equity
For the
Nine Months Ended September 30, 2009 and
the Years Ended December 31, 2008 and 2007
|
|
|
|
|
Group equity at December 31, 2006
|
|
$
|
18,800,282
|
|
Contribution from parent
|
|
|
21,670,486
|
|
Share-based compensation allocated from parent
|
|
|
813,454
|
|
Net loss
|
|
|
(14,882,351
|
)
|
|
|
|
|
|
Group equity at December 31, 2007
|
|
|
26,401,871
|
|
Contribution from parent
|
|
|
26,511,411
|
|
Share-based compensation allocated from parent
|
|
|
4,388,941
|
|
Net loss
|
|
|
(24,014,472
|
)
|
|
|
|
|
|
Group equity at December 31, 2008
|
|
|
33,287,751
|
|
Contribution from parent
|
|
|
22,703,615
|
|
Share-based compensation allocated from parent
|
|
|
2,258,869
|
|
Net loss
|
|
|
(20,254,834
|
)
|
|
|
|
|
|
Group equity at September 30, 2009
|
|
$
|
37,995,401
|
|
|
|
|
|
|
See accompanying notes.
F-40
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Combined
Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
Year
|
|
|
Year
|
|
|
|
Ended
|
|
|
Ended
|
|
|
Ended
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss
|
|
$
|
(20,254,834
|
)
|
|
$
|
(24,014,472
|
)
|
|
$
|
(14,882,351
|
)
|
Adjustments to reconcile net loss to net cash used in operating
activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
5,799,952
|
|
|
|
6,646,543
|
|
|
|
4,064,979
|
|
Loss (gain) on sale of property and equipment
|
|
|
792
|
|
|
|
1,012,779
|
|
|
|
(742,086
|
)
|
Share-based compensation
|
|
|
2,258,869
|
|
|
|
4,388,941
|
|
|
|
813,454
|
|
Asset impairment write down
|
|
|
|
|
|
|
|
|
|
|
2,873,055
|
|
Asset retirement obligations
|
|
|
(644,217
|
)
|
|
|
(730,436
|
)
|
|
|
1,244,438
|
|
Changes in noncash operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
(3,506,701
|
)
|
|
|
1,452,404
|
|
|
|
(2,541,574
|
)
|
Inventories
|
|
|
200,201
|
|
|
|
620,139
|
|
|
|
(816,314
|
)
|
Prepaid expenses and other current assets
|
|
|
(191,071
|
)
|
|
|
34,096
|
|
|
|
(235,371
|
)
|
Trade accounts payable and other accrued liabilities
|
|
|
2,390,045
|
|
|
|
(2,169,229
|
)
|
|
|
5,147,696
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in operating activities
|
|
|
(13,946,964
|
)
|
|
|
(12,759,235
|
)
|
|
|
(5,074,074
|
)
|
Investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted certificates of deposit
|
|
|
509,825
|
|
|
|
(509,825
|
)
|
|
|
|
|
Proceeds from sale of investments
|
|
|
|
|
|
|
|
|
|
|
216,477
|
|
Payments for other assets, principally mine development and
mining rights
|
|
|
(1,631,921
|
)
|
|
|
(3,194,375
|
)
|
|
|
(6,879,142
|
)
|
Proceeds from sale of property and equipment
|
|
|
210,000
|
|
|
|
683,912
|
|
|
|
1,582,346
|
|
Payments for property and equipment
|
|
|
(1,346,609
|
)
|
|
|
(3,187,274
|
)
|
|
|
(9,712,212
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities
|
|
|
(2,258,705
|
)
|
|
|
(6,207,562
|
)
|
|
|
(14,792,531
|
)
|
Financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Contributions from parent
|
|
|
22,703,615
|
|
|
|
26,511,411
|
|
|
|
21,670,486
|
|
Principal payments on debt
|
|
|
(209,025
|
)
|
|
|
(1,058,336
|
)
|
|
|
(939,463
|
)
|
Payments on equipment financing
|
|
|
(6,288,921
|
)
|
|
|
(6,486,278
|
)
|
|
|
(1,007,250
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by financing activities
|
|
|
16,205,669
|
|
|
|
18,966,797
|
|
|
|
19,723,773
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net decrease in cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
(142,832
|
)
|
Cash and cash equivalents, beginning of period
|
|
|
|
|
|
|
|
|
|
|
142,832
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest paid
|
|
$
|
1,237,268
|
|
|
$
|
1,055,688
|
|
|
$
|
245,893
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncash investing and financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Vendor financing for equipment purchases
|
|
$
|
6,629,614
|
|
|
$
|
18,025,434
|
|
|
$
|
10,293,381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See accompanying notes.
F-41
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to Combined Financial Statements
September 30,
2009 and December 31, 2008
|
|
1.
|
Nature of
Operations and Significant Accounting Policies
|
Nature
of Operations and Basis of Presentation
Phoenix Coal Inc. (PCI) and Phoenix Coal Corporation, a wholly
owned subsidiary of PCI, (collectively, the Parent) are engaged
in the development, production, and sale of steam coal to
utilities and industrial fuel consumers. The Parent is also
engaged in the development of underground coal reserves. Mining
activities are currently limited to one reportable business
segment, which is the Illinois Basin. PCI is a publicly traded
entity listed on the Toronto Stock Exchange and is headquartered
in Madisonville, Kentucky, with corporate offices in Louisville,
Kentucky.
On September 30, 2009, the Parent sold substantially all of
its operating assets and operations associated with its surface
coal mining operations in western Kentucky to Oxford Mining
Company, LLC (Oxford). The assets acquired by Oxford were
utilized in the operation of multiple surface coal mining
locations and related support facilities (maintenance shop,
barge loading facility, and coal preparation plant)
(collectively, the Company). The assets transferred included
coal and supplies inventories, coal reserves and related prepaid
royalties, mining property, plant, and equipment, mining rights,
coal purchase contracts, and coal sales contracts.
These combined financial statements represent the carved-out
financial position, results of operations, changes in group
equity, and cash flows of the Company, combined from different
legal entities, all of which are wholly owned subsidiaries of
the Parent. The carved-out financial statements have been
prepared in accordance with SEC Financial Reporting Manual
section 2065
Acquisition of Selected Parts of an Entity
May Result in Less Than Full Financial Statements
and Staff
Accounting Bulletin (SAB) Topic 1.B.
Allocation of Expenses
and Related Disclosure in Financial Statements of Subsidiaries,
Divisions or Lesser Business Components of Another Entity
.
The carved-out financial statements include allocations of
certain Parent corporate expenses and intercompany interest
charges (see Note 2). Management believes that the
assumptions and estimates used in preparation of the carved-out
financial statements are reasonable. However, the carved-out
financial statements may not necessarily reflect the
Companys financial position, results of operations, or
cash flows in the future, or what its financial position,
results of operations, or cash flows would have been if the
Company had been a stand-alone entity during the periods
presented. Because of the nature of these carved-out financial
statements, the Parents net investment in the Company,
including amounts due to/from the Parent, is shown as
group equity.
The carved-out financial statements have been prepared in
accordance with accounting principles generally accepted in the
United States (GAAP). All monetary references expressed in these
notes are references to United States dollars. All intercompany
transactions between the Companys locations have been
eliminated.
Use of
Estimates
The preparation of the carved-out financial statements in
conformity with GAAP requires management to make estimates and
assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities
at the date of the carved-out financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from these estimates. The
assets and liabilities which require management to make
significant estimates and assumptions in determining carrying
values include, but are not limited to, coal inventories,
property, plant, and equipment, mining rights, mine development,
mineral reserves, prepaid royalties, provision for income taxes,
and asset retirement obligations.
F-42
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
1.
|
Nature of
Operations and Significant Accounting
Policies (continued)
|
Parent
Sale of Surface Mining Operations
The Parent currently reports its consolidated financial results
in accordance with Canadian generally accepted accounting
principles. As these carved-out financial statements represent a
subset of the Parents financial activity and are prepared
under United States GAAP, the accounting treatment and related
materiality levels of certain transactions may differ from the
Parents separately reported consolidated financial
results. As previously noted, on September 30, 2009, the
Parent sold substantially all of its operating assets and
operations associated with its surface coal mining operations in
western Kentucky to Oxford. The consideration received under the
terms of the acquisition agreement included cash, payment by
Oxford of all debt associated with the equipment being sold and
the assumption of certain asset retirement obligations.
As of June 30, 2009, pursuant to the Canadian Institute of
Chartered Accountants Handbook Section 3475,
Disposal of Long-lived Assets and Discontinued Operations,
(a Canadian accounting standard that is consistent with
Financial Accounting Standards Board (FASB) Accounting Standards
Codification (ASC) 360,
Property, Plant, and Equipment
),
the Parent classified these surface mining operations as held
for sale and wrote down the related assets to the amount
expected to be realized on sale, resulting in a charge of
$38,920,000 to the Parents consolidated statement of
operations for the six months ended June 30, 2009.
Concurrent with the closing on September 30, 2009, the
Parent decreased this estimated loss by $2,680,000 and reported
a loss on the sale of these surface mining operations of
approximately $36,240,000 for the nine months ended
September 30, 2009. For purposes of these financial
statements, an impairment charge was not recorded in the
carved-out statement of operations as the surface mining assets
are, from the Companys perspective, classified as assets
held for use and therefore tested for impairment based on
estimated future undiscounted cash flows to be realized from the
use of the assets. Based on the Companys impairment
analysis, as of September 30, 2009 the estimated future
cash flows from the surface mining operations exceeded their
carrying value.
Cash
and Cash Equivalents, Including Restricted Cash
The Parent provides cash as needed to support the Companys
surface mining operations, including restricted cash used to
collateralize reclamation bonds. Any excess cash collected by
the Company at the end of each business day is transferred to
the Parents bank account. Consequently, the accompanying
balance sheets do not include any cash balances. Transfers of
cash between the Company and the Parent are classified as a
financing activity in the statement of cash flows. At
December 31, 2008, pending the transfer of mining permits
related to business acquisitions completed in July 2008,
restricted certificates of deposit totaling $509,825 were owned
by the Company and are included in the balance sheet at that
date.
Trade
Accounts Receivable
Trade accounts receivables are recorded at the invoiced amount
and do not bear interest. Customers are primarily investment
grade companies and quasi-governmental agencies. While the
Company is subject to credit risk from its trade accounts
receivable, the Company manages its risk by providing credit
terms on a case by case basis. As a result, the Company has not
experienced any instances of nonpayment and does not currently
require an allowance for doubtful accounts. Management monitors
customers closely and will record an allowance if trade account
balances become potentially uncollectible. Subsequent to
September 30, 2009 and December 31, 2008, the Company
has collected all of its trade accounts receivable at the
applicable reporting dates.
F-43
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
1.
|
Nature of
Operations and Significant Accounting
Policies (continued)
|
Inventory
The Company accounts for coal inventories on a
first-in,
first-out basis and values these inventories at the lower of
cost and net realizable value with cost determined using average
cost per ton. Coal inventory values were $25.95 per ton at
September 30, 2009 and $22.62 per ton at December 31,
2008. At September 30, 2009 and December 31, 2008, the
coal inventory was valued at net realizable value.
The Company accounts for parts inventory using the original cost
on a
first-in,
first-out basis. Parts inventory is included in other current
assets and totaled $119,484 and $103,555 as of
September 30, 2009 and December 31, 2008, respectively.
Property,
Plant, and Equipment
Property, plant, and equipment are stated at cost. Depreciation
is calculated on the straight-line basis with useful lives that
range from 5 to 40 years. Depreciation expense for the nine
months ended September 30, 2009 and the years ended
December 31, 2008 and 2007 was $4,352,339, $4,362,179, and
$2,222,516, respectively.
The cost of assets sold, retired, or otherwise disposed of and
the related accumulated depreciation are eliminated from the
accounts and any resulting gain or loss is included in
operations. Expenditures for maintenance and repairs are charged
to expense as incurred.
Consistent with FASB ASC 360,
Property Plant, and Equipment,
the Company evaluates long-lived assets for impairment when
events or changes in circumstances indicate that their carrying
amount may not be recoverable. This impairment testing is based
on estimated future undiscounted cash flows to be realized from
the use of the long-lived asset. These future cash flows are
developed using assumptions that reflect the long-term operating
plans given managements best estimate of future economic
conditions, such as revenues, production costs, and reserve
estimates. A change in these factors could result in a
modification of the impairment calculation.
Mine
Development Costs
Mine development costs represent the costs incurred to prepare
future mine sites for mining and are amortized on the
units-of-production
method. The net book value of mine development costs was
$2,650,129 and $529,112 at September 30, 2009 and
December 31, 2008, respectively. Accumulated amortization
of mine development costs was $471,125 and $505,902 at
September 30, 2009 and December 31, 2008,
respectively. Development costs amortized totaled $384,743,
$665,243, and $455,508 for the nine months ended
September 30, 2009 and the years ended December 31,
2008 and 2007, respectively.
Mining
Rights
Mining rights, which are rights to mine coal properties acquired
through coal leases, are recorded at cost. Mining rights are
amortized on the
units-of-production
method. The net book value of mining rights totaled $13,867,610
and $14,930,480 at September 30, 2009 and December 31,
2008, respectively. Accumulated amortization of mining rights
was $3,325,062 and $3,382,180 at September 30, 2009 and
December 31, 2008, respectively. Mining rights amortization
totaled $1,062,870, $1,619,121, and $1,386,955 for the nine
months ended September 30, 2009 and the years ended
December 31, 2008 and 2007, respectively.
In June 2007, the Crittenden County Coal mining operation was
closed due to uneconomical mining conditions. As a result of the
closing, the Company recorded an asset impairment write down
related to its mining rights of $2,873,055.
F-44
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
1.
|
Nature of
Operations and Significant Accounting
Policies (continued)
|
Mineral
Reserves
Mineral reserves, which are coal properties for which the
Company owns the coal in place, are recorded at cost. At
September 30, 2009 and December 31, 2008, the net book
value of mineral reserves totaled $189,434 and was attributable
to properties where the Company was not currently engaged in
mining operations and, therefore, the assets were not currently
being depleted.
Prepaid
Royalties
Rights to leased coal lands are often acquired through royalty
payments. Where royalty payments represent prepayments
recoupable against production, they are recorded as a prepaid
asset. As mining occurs on these leases, the prepayment is
charged to cost of sales. Prepaid royalties were $188,602 and
$216,147 at September 30, 2009 and December 31, 2008,
respectively.
Asset
Retirement Obligations
FASB ASC
410-20,
Asset Retirement Obligations
, addresses financial
accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated
asset retirement costs. The Companys asset retirement
obligation (ARO) liabilities primarily consist of spending
estimates related to reclaiming surface land and support
facilities in accordance with federal and state reclamation laws
as defined by each mining permit.
Revenue
Recognition
Revenue is recognized when all of the following criteria are
met: (1) persuasive evidence of an arrangement exists,
(2) delivery has occurred or services have been rendered,
(3) the sellers price to the buyer is fixed or
determinable, and (4) collectability is reasonably assured.
In the case of coal that is mined and sold, a specific sales
contract is negotiated with each customer, which includes a
fixed-price per ton, a delivery schedule, and terms of payment.
Royalty
Expense
The majority of the coal that the Company mines is owned by
other entities. The Company acquires the right to mine and sell
the coal through various leases. These leases require the
Company to pay a royalty to the owners of the land and the
minerals being mined. Royalty expense for the nine months ended
September 30, 2009 and for the years ended
December 31, 2008 and 2007 was $2,688,647, $3,778,642, and
$3,386,015, respectively, and is included in selling expenses in
the statements of operations and comprehensive loss.
Income
Taxes
The Company files consolidated federal and state income tax
returns with the Parent. Income tax expense for purposes of
these combined financial statements is calculated on a separate
return basis. Deferred income taxes are recorded by applying
statutory tax rates in effect at the date of the balance sheet
to differences between the book and tax basis of assets and
liabilities. Due to the significantly large tax losses generated
by the Company, management has recorded a valuation allowance
against its total net deferred tax assets as they do not believe
it is more-likely-than-not that these assets will be realized.
The Companys income tax expense for the nine months ended
September 30, 2009, and the years ended December 31,
2008 and 2007, consisted of state taxes.
F-45
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
1.
|
Nature of
Operations and Significant Accounting
Policies (continued)
|
Share-Based
Compensation
The Parent uses the fair value method for options, warrants, and
restricted stock granted. The fair value of stock options and
warrants is determined by the Black-Scholes option pricing model
with assumptions for risk-free interest rates, dividend yields,
volatility factors of the expected market price of the
Parents common shares and an expected life of the options
and warrants. The fair value of the instruments granted is
amortized over their vesting period. The share-based
compensation expense recorded in these carved-out financial
statements has been allocated to the Company based on the
employees who have provided services to the Company during the
applicable reporting periods and recorded as an expense in the
statement of operations. The Parents cost of providing
these benefits is recorded as a contribution to the
Companys equity.
Fair
Value and Financial Instruments
FASB ASC 820 defines fair value as the price that would be
received to sell an asset or paid to transfer a liability in an
orderly transaction between market participants at the
measurement date. At September 30, 2009 and
December 31, 2008, the fair values of restricted
certificates of deposit, trade accounts receivable, trade
accounts payable, and accrued liabilities approximated their
carrying values because of the short-term nature of these
financial instruments. At September 30, 2009, the fair
value of the Companys long-term debt, calculated using the
present value of the scheduled debt payments, and using a credit
adjusted risk free rate of 8.25%, was $20,843,900, compared to
its carrying value at that date of $21,305,458. At
December 31, 2008, the fair value of the Companys
long-term debt, calculated using the present value of the
scheduled debt payments, and using a credit adjusted risk free
rate of 6.75%, was $21,052,500, compared to its carrying value
at that date of $21,173,790.
New
Accounting Standards Issued and Adopted
In September 2009, the FASB issued Accounting Standards Update
(ASU)
2009-06,
Implementation Guidance on Accounting for Uncertainty in
Income Taxes and Disclosure Amendments for Nonpublic
Entities
. ASU
2009-06
amended guidance on certain aspects of FASB ASC 740,
Income
Taxes
, including application to nonpublic entities, as well
as application guidance on the accounting for income tax
uncertainties for all entities. The amendments are applicable to
all entities that apply FASB ASC 740 as well as those that
historically had not, such as pass-through and tax-exempt
not-for-profit
entities. The amendments clarify that an entitys tax
status as a pass-through or tax-exempt
not-for-profit
entity is a tax position subject to the recognition requirements
of FASB ASC 740 and therefore these entities must use the
recognition and measurement guidance in FASB ASC 740 when
assessing their tax positions. The ASU
2009-06
amendments are effective for interim and annual periods ending
after September 15, 2009. The adoption of the ASU
2009-06
amendments for the nine months ended September 30, 2009 did
not have a material impact on the Companys financial
statements.
For the financial statements for the September 30, 2009
reporting period, the Company adopted amendments to FASB ASC
805,
Business Combinations
(SFAS No. 141R,
Business Combinations
), issued by the FASB in December
2007. The FASB ASC 805 amendments apply to all business
combinations and establish guidance for recognizing and
measuring identifiable assets acquired, liabilities assumed,
noncontrolling interests in the acquiree and goodwill. Most of
these items are recognized at their full fair value on the
acquisition date, including acquisitions where the acquirer
obtains control but less than 100% ownership in the acquiree.
The FASB ASC 805 amendments also require expensing restructuring
and acquisition-related costs as incurred and establish
disclosure requirements to enable the evaluation of the nature
and financial effects of the business combination. Per FASB ASC
805-10-65-1,
these amendments to FASB ASC 805 are effective for business
combinations with an acquisition date in fiscal years beginning
after
F-46
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
1.
|
Nature of
Operations and Significant Accounting
Policies (continued)
|
December 15, 2008. The Company did not complete any
business acquisitions during the nine months ended
September 30, 2009.
For the financial statements for the September 30, 2009
reporting period, the Company adopted amendments to FASB ASC
855,
Subsequent Events
(SFAS No. 165,
Subsequent Events
), issued by the FASB in May 2009. The
amendments to FASB ASC 855 establish the accounting for and
disclosure of events that occur after the balance sheet date but
before financial statements are issued or are available to be
issued. The amendments to FASB ASC 855 also require disclosure
of the date through which an entity has evaluated subsequent
events and the basis for that date, that is, whether that date
represents the date the financial statements were issued or were
available to be issued. The Company evaluated subsequent events
after the balance sheet date of September 30, 2009 through
December 18, 2009.
New
Accounting Standards Issued and Not Yet Adopted
In August 2009, the FASB issued ASU
2009-05,
Measuring Liabilities at Fair Value
. The ASU
2009-05
amendments provide additional guidance on measuring the fair
value of liabilities, as well as outline alternative valuation
methods and a hierarchy for their use. The amendments also
clarify that restrictions preventing the transfer of a liability
should not be considered as a separate input or adjustment in
the measurement of its fair value. The ASU
2006-05
amendments are effective as of the beginning of interim and
annual reporting periods that begin after August 26, 2009.
The Company does not anticipate these requirements will have a
material impact on its financial statements.
|
|
2.
|
Preparation
of Carved-Out Financial Statements
|
The following allocation policies have been used in the
preparation of these carved-out financial statements. Unless
otherwise noted, these policies have been consistently applied
in the financial statements. In the opinion of management, the
methods for allocating these costs are reasonable. It is not
practicable to estimate the costs that would have been incurred
by the Company if it had been operated on a stand-alone basis.
Specifically
Identified Expenses
Costs related specifically to the Company have been identified
and included in the statements of operations and comprehensive
loss. These expenses include labor and benefits, mining
supplies, equipment maintenance and reclamation costs. In
addition, any costs incurred by the Parent which were
specifically identifiable to a surface mining operation have
been charged to the Company.
Shared
Operating Expenses
Historically, the Company has not allocated corporate general
and administrative services to each operating division. These
shared services included executive management, accounting,
information services, engineering, and human resources. For the
purposes of these carved-out financial statements, these costs
have been allocated to the Company based primarily on a
percentage of revenue.
Debt
and Related Interest Expense
The Parent has funded the acquisition and operating activities
of the Company, as well as its other operations, through equity
offerings (including private placement, preferred stock
offerings, and public stock offerings) and bank and finance
company debt. Funds used by the Parent for acquisition of the
Company have been recorded by the Parent as an investment in the
Company. Funds subsequently provided to, or received
F-47
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
2.
|
Preparation
of Carved-Out Financial Statements (continued)
|
from, the Company after the initial acquisition of its assets
have been recorded by the Parent in an intercompany
account balance.
Historically, the Parent has not charged or credited the Company
for interest on funds provided to, or received from the Company.
For the purpose of these carved-out financial statements,
interest expense has been computed on the average intercompany
account balance at the Parents consolidated average
borrowing rate and included in the Companys statements of
operations and comprehensive loss. The intercompany balance has
been contributed by the Parent to the Company at the end of each
year and therefore has been included in the statement of group
equity. Average borrowing rates utilized in this calculation
were 6.9%, 8.4%, and 11.7% for the nine months ended
September 30, 2009 and the years ended December 31,
2008 and 2007, respectively.
Beginning in September 2007, the Company began executing debt
agreements directly with equipment finance companies. Interest
expense related to equipment financed debt has also been
included in the carved-out statements.
C&R
Coal Inc.
In July 2008, the Parent, through one of its surface mining
subsidiaries, purchased all of the outstanding common shares of
C&R Coal Inc. (C&R) for cash consideration of
$2,051,000. In addition, under the terms of the agreement, the
Company will pay the former owners a royalty of $0.60 per ton
for each ton of coal sold from the C&R mines. At the
acquisition date, the current mining area, Beech Creek and Beech
Creek South, contained approximately 450,000 reserve tons. The
Company also acquired other leases in the transaction from
C&R and R&G Leasing, LLC, a company that is
affiliated with C&R through common ownership. At the
acquisition date, the Company estimated the leases contained
approximately 1,500,000 tons of coal.
The cost of the C&R acquisition was allocated to the
following identifiable net assets:
|
|
|
|
|
Current assets and restricted certificates of deposit
|
|
$
|
1,281,000
|
|
Mining equipment
|
|
|
859,000
|
|
Mining rights and mine development costs
|
|
|
2,387,000
|
|
Assumed liabilities
|
|
|
(2,476,000
|
)
|
|
|
|
|
|
|
|
$
|
2,051,000
|
|
|
|
|
|
|
Prior to July 2008, the Parent operated and managed
C&Rs mines under a management and administrative
services agreement. Since the Parent did not own nor control
C&R, it did not consolidate its operating results prior to
July 2008, and recorded funds invested and services provided in
other assets and accounts receivable on its balance sheet.
Renfro
Equipment, Inc.
In July 2008, the Parent, on behalf of the Company, purchased
all of the outstanding common shares of Renfro Equipment, Inc.
(Renfro) for total cash consideration of $1,129,000.
Additionally, the Parent incurred $18,000 of closing costs. The
purchase included all assets and liabilities of Renfro, except
certain equipment and associated debt specifically excluded from
the purchase. Based on exploration completed by the Parent,
management estimated that Renfro controlled approximately
1.5 million tons of coal via lease at acquisition date.
Additionally, if by July 2010, the Company acquires at least
1.5 million reserve tons as defined by Canadian Securities
Administrators National Instrument
43-101
due
to the direct efforts of the sellers (the Additional Reserves),
the Company will pay the sellers $1,000,000 for the first
1.5 million tons of reserves,
F-48
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
3.
|
Acquisitions (continued)
|
plus $0.50 per ton for each reserve ton in excess of
1.5 million. The purchase agreement defines a specific
territory from which the Additional Reserves can be acquired.
The acquisition of the Additional Reserves is on terms and
conditions acceptable to the Company in its sole, reasonable
discretion.
The cost of the Renfro acquisition was allocated to the
following identifiable net assets:
|
|
|
|
|
Current assets and restricted certificates of deposit
|
|
$
|
334,000
|
|
Mining equipment
|
|
|
429,000
|
|
Mining rights and mine development costs
|
|
|
1,770,000
|
|
Assumed liabilities
|
|
|
(1,386,000
|
)
|
|
|
|
|
|
|
|
$
|
1,147,000
|
|
|
|
|
|
|
Charolais
Corporation
In January 2007, the Parent acquired assets and shares of the
Charolais Corporation and related entities. The purchase price
paid to the seller was $21,735,000. In addition, the Parent
incurred $189,000 of transaction costs related to the purchase
for total consideration of $21,924,000. Included in the
Charolais acquisition was the purchase of the Rock Crusher Fines
(RCF) operation, which was not purchased on behalf of the
Company. The RCF operation is not included in these carved-out
financial statements as it was a fine coal recovery operation
and all assets utilized at RCF were sold in 2007 and not
included in the Companys operations. The portion of the
Charolais purchase price attributed to the RCF operation was
$6,844,000.
The purchase price was allocated as follows:
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
Charolais
|
|
|
|
Charolais
|
|
|
Acquisition
|
|
|
|
Acquisition
|
|
|
Allocation
|
|
|
|
Allocation
|
|
|
Excluding RCF
|
|
|
Real property
|
|
$
|
557,000
|
|
|
$
|
557,000
|
|
Plant and equipment
|
|
|
13,483,000
|
|
|
|
7,939,000
|
|
Mining rights and mineral reserves
|
|
|
8,705,000
|
|
|
|
7,405,000
|
|
Asset retirement obligations
|
|
|
(821,000
|
)
|
|
|
(821,000
|
)
|
|
|
|
|
|
|
|
|
|
|
|
$
|
21,924,000
|
|
|
$
|
15,080,000
|
|
|
|
|
|
|
|
|
|
|
F-49
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
4.
|
Property,
Plant, and Equipment, Net
|
Property, plant, and equipment consists of the following at
September 30, 2009 and December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Land
|
|
$
|
636,154
|
|
|
$
|
599,654
|
|
Building and improvements
|
|
|
480,885
|
|
|
|
25,424
|
|
Preparation plant
|
|
|
3,683,996
|
|
|
|
3,084,768
|
|
Mining equipment
|
|
|
52,483,183
|
|
|
|
45,886,694
|
|
Loading and marine transport equipment
|
|
|
1,775,000
|
|
|
|
1,775,000
|
|
Office equipment
|
|
|
355,557
|
|
|
|
370,450
|
|
Vehicles
|
|
|
65,965
|
|
|
|
65,965
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59,480,740
|
|
|
|
51,807,955
|
|
Less accumulated depreciation and amortization
|
|
|
10,904,663
|
|
|
|
6,644,971
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
48,576,077
|
|
|
$
|
45,162,984
|
|
|
|
|
|
|
|
|
|
|
In 2008 and 2007, the Company sold several pieces of noncore
property and equipment, generating gross proceeds of $683,912
and $1,582,346, respectively. The Company recorded a loss of
$1,012,779 related to these sales in 2008, and a gain of
$742,086 in 2007. There were no significant sales of property
and equipment for the nine months ended September 30, 2009.
|
|
5.
|
Asset
Retirement Obligations
|
The Company estimates its ARO liabilities for final reclamation
and mine closure based upon detailed engineering calculations of
the amount and timing of the future cash spending for a third
party to perform the required work. Spending estimates are
escalated for inflation and then discounted at the
credit-adjusted risk-free rate, which ranged from 6.12% to 7.64%
at September 30, 2009 and December 31, 2008. Total
estimated undiscounted future cash spending related to the ARO
liabilities totaled $4,900,000 at September 30, 2009 with
spending estimated to occur from 2009 to 2016. Total estimated
undiscounted future cash spending related to the ARO liabilities
totaled $5,142,000 at December 31, 2008. The Company
records an ARO asset associated with the discounted liability
for final reclamation and mine closure as a mine development
cost. The obligation and corresponding asset are recognized in
the period in which the liability is incurred. The ARO asset is
amortized on the
units-of-production
method over its expected life and the ARO liability is accreted
to the projected spending date. As changes in estimates occur
(such as mine plan revisions, changes in estimated costs or
changes in timing of the performance of reclamation activities),
the revisions to the obligation and asset are recognized at the
appropriate credit-adjusted risk-free rate. The Company also
recognizes an obligation for contemporaneous reclamation
liabilities incurred as a result of surface mining.
Contemporaneous reclamation consists primarily of grading,
topsoil replacement, and revegetation of backfilled pit areas.
F-50
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
5.
|
Asset
Retirement Obligations (continued)
|
A progression of the reclamation liability recorded on the
balance sheet is as follows:
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
|
|
Ended
|
|
|
Year Ended
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Balance at beginning of period
|
|
$
|
4,324,000
|
|
|
$
|
3,757,353
|
|
Liabilities acquired
|
|
|
|
|
|
|
1,131,000
|
|
Liabilities incurred
|
|
|
846,295
|
|
|
|
166,083
|
|
Accretion
|
|
|
188,719
|
|
|
|
189,132
|
|
Liabilities settled
|
|
|
(832,936
|
)
|
|
|
(919,568
|
)
|
|
|
|
|
|
|
|
|
|
Total asset retirement obligation
|
|
|
4,526,078
|
|
|
|
4,324,000
|
|
Less current portion
|
|
|
1,627,800
|
|
|
|
1,958,000
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
2,898,278
|
|
|
$
|
2,366,000
|
|
|
|
|
|
|
|
|
|
|
Long-term debt consists of the following at September 30,
2009 and December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
Bank notes payable, interest at 5.50% to 8.90%. Payments are
made in monthly installments. The loans are collateralized by
various pieces of equipment and mature April 2010
|
|
$
|
47,643
|
|
|
$
|
105,109
|
|
Equipment notes payable, interest at 5.25% to 8.75%. Payments
are made in monthly installments. The loans are collateralized
by related assets with a net book value of $31,184,000 as of
September 30, 2009 and have maturity dates from August 2010
to March 2013
|
|
|
21,257,815
|
|
|
|
21,068,681
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt
|
|
|
21,305,458
|
|
|
|
21,173,790
|
|
Less current portion
|
|
|
8,224,486
|
|
|
|
6,532,045
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
13,080,972
|
|
|
$
|
14,641,745
|
|
|
|
|
|
|
|
|
|
|
Expected maturities of notes payable based on years ending
December 31 are as follows:
|
|
|
|
|
2009 (remaining three months)
|
|
$
|
2,013,455
|
|
2010
|
|
|
8,147,660
|
|
2011
|
|
|
7,366,999
|
|
2012
|
|
|
3,604,101
|
|
2013
|
|
|
173,243
|
|
|
|
|
|
|
|
|
$
|
21,305,458
|
|
|
|
|
|
|
As previously discussed in Note 1, on September 30,
2009, the Parent sold substantially all of its operating assets
and operations associated with its surface coal mining
operations in western Kentucky to Oxford. In conjunction with
the transactions, Oxford paid off all the outstanding debt as of
September 30, 2009.
F-51
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
The components of income tax expense for the nine months ended
September 30, 2009 and the years ended December 31,
2008 and 2007 are:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
|
|
Ended
|
|
Year Ended
|
|
Year Ended
|
|
|
September 30,
|
|
December 31,
|
|
December 31,
|
|
|
2009
|
|
2008
|
|
2007
|
|
Current
|
|
$
|
16,081
|
|
|
$
|
37,838
|
|
|
$
|
70,155
|
|
The expense for income taxes includes federal and state income
taxes currently payable or receivable and those deferred or
prepaid because of temporary differences between the financial
statement and the tax basis of assets and liabilities. The
Company records income taxes under the liability method. Under
this method, deferred income taxes are recognized for the
estimated deferred tax effects of differences between the tax
basis of assets and liabilities and their financial reporting
amounts based on enacted laws.
At September 30, 2009 and December 31, 2008, the
Company had deferred tax assets of approximately $28,862,000 and
$20,263,000 and deferred tax liabilities of $12,471,000 and
$10,761,000, respectively. The Companys deferred tax
assets consist principally of net operating loss carryforwards,
while deferred tax liabilities relate primarily to temporary
timing differences for amortization of mining rights and
depreciation. As a result of losses from operations, management
has recorded a valuation allowance against the total net
deferred tax asset as they do not believe it is
more-likely-than-not these assets will be realized.
For the nine months ended September 30, 2009 and the years
ended December 31, 2008 and 2007 the Companys
concentration of major customers was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
|
|
Ended
|
|
Year Ended
|
|
Year Ended
|
|
|
September 30,
|
|
December 31,
|
|
December 31,
|
|
|
2009
|
|
2008
|
|
2007
|
|
Number of customers whose sales each exceeded 10% of total
revenue
|
|
|
4
|
|
|
|
3
|
|
|
|
3
|
|
Percentage of total revenue
|
|
|
98
|
%
|
|
|
86
|
%
|
|
|
83
|
%
|
Accounts receivable due at period end
|
|
$
|
6,349,485
|
|
|
$
|
2,410,395
|
|
|
$
|
2,285,240
|
|
The Company has never experienced nonpayment from any of these
customers. All amounts due from these customers at
September 30, 2009 have subsequently been collected.
|
|
9.
|
Commitments
and Contingent Liabilities
|
In the normal course of business, the Company makes various
commitments and incurs certain contingent liabilities, including
liabilities related to asset retirement obligations and
financial obligations in connection with mining permits that are
not reflected in the balance sheet. The Company does not
anticipate any material losses as a result of these
transactions. In accordance with Kentucky state law, the Company
is required to post reclamation bonds to assure that reclamation
work is completed. Outstanding reclamation bonds totaled
approximately $12 million at September 30, 2009 and
approximately $11 million at December 31, 2008. These
bonds are secured by letters of credit or certificates of
deposit issued by a bank equal to the amount of the outstanding
reclamation bonds, and are typically provided by the Parent.
However, at December 31, 2008, pending the transfer of
certain mining permits related to the C&R and Renfro
acquisitions, restricted certificates of deposit totaling
$509,825 were held by the Company and included in the balance
sheet. Subsequent to December 31, 2008 these restricted
certificates of deposit were replaced by letters of credit
provided by the Parent.
F-52
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
9.
|
Commitments
and Contingent Liabilities (continued)
|
A significant amount of the Companys coal reserves are
controlled through leasing arrangements and noncancellable
royalty lease agreements under which future minimum lease
payments are due.
In the ordinary course of business, the Company enters into
contracts to purchase diesel fuel from local suppliers for
physical delivery at specified prices. Pursuant to these
contracts, the Company does not own a futures or options
position in the purchased fuel. As of September 30, 2009,
the Company had executed purchase contracts for a total of
1,890,000 gallons to be delivered in 2009 and 2010 at a total
cost of $4,206,048, or an average weighted price of $2.23 per
gallon.
In 2007, the Company entered into a master coal purchase and
sale agreement (the Master Agreement) to purchase coal fines
recovered and processed by Covol Fuels No. 2, LLC (Covol)
from two coal slurry reserve areas in Muhlenberg County,
Kentucky. On July 6, 2009, the Company executed an
amendment to the Master Agreement (the Amended Master Agreement)
revising the annual purchase and sale tonnage commitments. The
term of the Amended Master Agreement runs through the exhaustion
of the reserves (the Term). During the Term of the Amended
Master Agreement, by July 1 of each year, the Company and
Covol will agree to the annual tonnage commitment (the
Commitment) that Covol will produce and that the Company will
purchase for the next calendar year. For the calendar year 2010
the Commitment cannot be less than 360,000 tons and for
subsequent years the Commitment cannot be less than 400,000
tons. Additionally, the Company has the first right of refusal
to purchase any tons produced by Covol in excess of the
Commitment, but up to 720,000 tons annually.
In June 2009, the Company entered into a coal supply agreement
with an Illinois Basin producer to purchase 20,000 tons of coal
per month from July 2009 through December 2009. Upon mutual
agreement of the parties to the coal supply agreement, the term
of the agreement may be extended to December 31, 2010.
Subsequent to September 30, 2009, this agreement was
extended to June 30, 2010.
As part of the Renfro Equipment Inc. acquisition in July 2008,
the Company agreed that if, by July 31, 2010, it acquires
at least 1.5 million reserve tons as defined by Canadian
Securities Administrators National Instrument
43-101
(NI
43-101)
due
to the direct efforts of the sellers (Additional Reserves), the
Company will pay the sellers $1,000,000 for the first
1.5 million tons of reserves, plus $0.50 per ton for each
reserve ton in excess of 1.5 million. The acquisition
closing documents define a specific territory from which the
Additional Reserves can be acquired. The acquisition of the
Additional Reserves must be on terms and conditions acceptable
to the Company in its sole, reasonable discretion. As of
September 30, 2009, the sellers had provided several
mineral leases to the Company. However, the analysis and
drilling that is required to qualify these properties as reserve
tons under the definition of NI
43-101
is in
its early stages. Therefore, it is not yet probable that the
sellers will deliver 1.5 million reserve tons to the
Company, so no liability has been currently accrued on the
balance sheet to the sellers.
|
|
10.
|
Stock
Incentive Plans
|
PCI adopted a shareholder-approved stock option plan (the 2008
Plan) on May 20, 2008, which became effective in June 2008.
PCC had a stock incentive plan authorized by its Board of
Directors in 2004 (the 2004 Plan) to grant options to its
employees (including officers), directors, and consultants. In
June 2008, each stock option issued under the 2004 Plan was
cancelled and extinguished and the holder received a replacement
option to purchase that number of common shares of PCI equal to
the number of PCC common shares that the holder could purchase
under the 2004 Plan.
The 2008 Plan is designed to advance the interests of the
Company by encouraging employees, officers, directors, and
consultants to have equity participation in the Parent through
the acquisition of common shares. The 2008 Plan has been used to
grant options to the Companys employees, officers,
directors, and
F-53
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
10.
|
Stock
Incentive Plans (continued)
|
consultants. Options granted under the 2008 Plan may be
incentive stock options or nonqualified stock
options.
For options granted under the 2008 Plan, the exercise price per
common share is not to be less than the market price of the
common shares at the time of the grant. The exercise period for
each stock option is not to be more than ten years (five years
in the case of an incentive stock option granted to a person who
owns more than 10% of the issued and outstanding common shares
of the Parent). Options may be granted subject to vesting
requirements. Stock options granted under the 2004 Plan were
generally subject to vesting provisions of 25% at the end of
year one from the date of grant and then evenly over the
following 48 months. The options were granted at a price
equal to 100% of the fair value of the Companys common
shares on the date of grant and have a ten-year term.
Unless terminated earlier by the Parents Board of
Directors, the 2008 Plan will remain in effect until all options
granted under the 2008 Plan have been exercised or forfeited, or
have expired. However, no new options may be granted under the
2008 Plan more than ten years from the date the Plan was
originally adopted.
Compensation cost of stock option grants is recognized
straight-line over the options vesting periods.
Compensation expense related to stock options for the nine
months ended September 30, 2009 and the years ended
December 31, 2008 and 2007 was $2,258,869, $4,388,941, and
$813,454, respectively. Under the terms of the 2008 Plan, and as
approved by the Board of Directors of the Parent, the sale of
the surface mining assets to Oxford caused all options
outstanding under the 2008 Plan to become fully vested and all
remaining unrecognized compensation expense totaling
approximately $547,000 was charged to the statement of
operations and comprehensive loss in the third quarter 2009.
The options fair value was determined using the
Black-Scholes option-pricing model. Expected volatilities are
based on comparable company historical share price movement and
other factors. The cost relating to the stock-based compensation
plans is included in general and administrative expenses in the
accompanying combined statements of operations and comprehensive
loss.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
Options
|
|
|
Options
|
|
|
Options
|
|
|
Weighted-average fair value per share of options granted
|
|
$
|
0.08 per share
|
|
|
$
|
0.64 per share
|
|
|
$
|
0.73 per share
|
|
Assumptions (weighted-average):
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk free interest rate
|
|
|
2.75
|
%
|
|
|
3.98
|
%
|
|
|
4.37
|
%
|
Expected dividend yield
|
|
|
0.00
|
|
|
|
0.00
|
|
|
|
0.00
|
|
Expected volatility
|
|
|
0.40
|
|
|
|
0.40
|
|
|
|
0.40
|
|
Expected option life (in years)
|
|
|
10.00
|
|
|
|
10.00
|
|
|
|
10.00
|
|
|
|
11.
|
Sales
Contract Termination
|
On March 3, 2009, the Company entered into a mutual release
and settlement agreement with one of its customers to terminate
a coal supply agreement for delivery of coal in 2009 and 2010
(the 2009/2010 Supply Agreement). In consideration for
terminating the 2009/2010 Supply Agreement, the Company paid the
customer $3,000,000 in cash. The payment relieved the Company of
the obligation to deliver approximately 970,000 tons of coal,
470,000 in 2009 and 500,000 in 2010. In addition, the Company
agreed to make up in 2009 approximately 170,000 tons of
shipments that were not delivered in 2008 under a separate coal
supply agreement dated January 1, 2008 (the 2008 Supply
Agreement). In return for fulfilling the 2008 Supply
F-54
Carved-Out
Surface Mining Operations of Phoenix Coal Inc.
Notes to
Combined Financial
Statements (Continued)
|
|
11.
|
Sales
Contract Termination (continued)
|
Agreement, the customer agreed to change the guaranteed monthly
average BTU specification from 11,500 to 11,200. The $3,000,000
payment has been charged to the statement of operations and
comprehensive loss.
|
|
12.
|
Defined
Contribution Plan
|
The Company has a retirement savings trust plan in effect for
substantially all full-time employees. The Plan also contains a
deferred salary arrangement under IRC Section 401(k). Under
the deferred salary arrangement, employees can contribute up to
100% of their earnings and the Company may match a portion of
the employee contributions. The Company paid and charged to
operations Plan contributions of approximately $497,000,
$621,000, and $508,000 for the nine months ended
September 30, 2009 and the years ended December 31,
2008 and 2007, respectively.
|
|
13.
|
Related-Party
Transactions
|
The Company is wholly owned by the Parent and its subsidiaries.
The Parent has allocated certain overhead costs associated with
general and administrative services, including executive
management, accounting, information services, engineering, and
human resources support to the Company. These overhead costs
were allocated based primarily on a percentage of revenue, which
management believes is reasonable.
Historically, interest costs related to intercompany debt have
not been charged or credited to the Parent or the Company. For
the purpose of these carved-out financial statements, interest
expense has been computed on the average intercompany account
balance at the Parents consolidated average borrowing rate
and included in the carved-out statements.
Allocated overhead costs and interest expense on intercompany
debt included in the statement of operations are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months
|
|
|
|
|
|
|
Ended
|
|
Year Ended
|
|
Year Ended
|
|
|
September 30,
|
|
December 31,
|
|
December 31,
|
|
|
2009
|
|
2008
|
|
2007
|
|
Overhead costs
|
|
$
|
6,947,484
|
|
|
$
|
10,362,888
|
|
|
$
|
5,170,340
|
|
Interest expense
|
|
|
1,363,605
|
|
|
|
755,592
|
|
|
|
(159,577
|
)
|
On November 4, 2009, the Company received a state mining
permit from the Kentucky Department of Natural Resources for its
Highway 431 reserve. With this permit, the Company has secured
all of the necessary permits required to begin mining on the
Highway 431 property in Muhlenberg County, Kentucky.
F-55
APPENDIX B
Glossary of Terms
adjusted operating surplus:
Adjusted operating
surplus, with respect to any period, consists of:
(i) operating surplus generated with respect to that
period; less (ii) any net decrease in cash reserves for
operating expenditures with respect to that period not relating
to an operating expenditure made with respect to that period;
plus (iii) any net decrease made in subsequent periods in
cash reserves for operating expenditures initially established
with respect to that period to the extent such decrease results
in a reduction in adjusted operating surplus in subsequent
periods; plus (iv) any net increase in cash reserves for
operating expenditures with respect to that period required by
any debt instrument for the repayment of principal, interest or
premium.
available cash:
Available cash generally
means, for any quarter, the sum of (i) all cash and cash
equivalents on hand at the end of the quarter; plus,
(ii) if our general partner so determines, all or any
portion of the cash on hand on the date of determination of
available cash for the quarter; less the amount of cash reserves
established by our general partner at the date of determination
of available cash for the quarter to (x) provide for the
proper conduct of our business (including reserves for our
future capital expenditures and anticipated future credit needs)
subsequent to that quarter; (y) comply with applicable law,
any of our debt instruments or other agreements; or
(z) provide funds for distributions to our unitholders and
to our general partner for any one or more of the next four
quarters.
base-load power plants:
The electrical
generation facilities used to meet some or all of a given
regions continuous energy demand and produce energy at a
constant rate.
Btu:
British thermal unit, or Btu, is the
amount of heat required to raise the temperature of one pound of
water one degree Fahrenheit.
capital account:
The capital account
maintained for a partner under the partnership agreement. The
capital account in respect of a general partner unit, a common
unit, a subordinated unit, an incentive distribution right or
any other partnership interest will be the amount which that
capital account would be if that general partner unit, common
unit, subordinated unit, incentive distribution right or other
partnership interest were the only interest in Oxford Resource
Partners, LP held by a partner.
capital surplus:
All amounts of available cash
distributed by Oxford Resource Partners, LP on any date from any
source will be deemed to be operating surplus until the sum of
all amounts of available cash previously distributed to the
partners equals operating surplus from the closing date of this
offering through the close of the immediately preceding quarter.
Any remaining amounts of available cash distributed on such date
will be deemed capital surplus.
closing price:
For common units, the last sale
price on a day, regular way, or in case no sale takes place on
that day, the average of the closing bid and asked prices on
that day, regular way, as reported in the principal consolidated
transaction reporting system for securities listed on the
principal national securities exchange on which the common units
are listed. If the common units are not listed on any national
securities exchange, the last quoted price on that day. If no
quoted price exists, the average of the high bid and low asked
prices on that day in the
over-the-counter
market, as reported by the New York Stock Exchange or any other
system then in use. If on any day the common units are not
quoted by any organization of that type, the average of the
closing bid and asked prices on that day as furnished by a
professional market maker making a market in the common units
selected by our general partner. If on that day no market maker
is making a market in the common units, the fair value of the
common units on that day as determined by our general partner.
common unit arrearage:
The amount by which the
minimum quarterly distribution for a quarter during the
subordination period exceeds the distribution of available cash
from operating surplus actually made for that quarter on a
common unit, cumulative for that quarter and all prior quarters
during the subordination period.
compliance coal:
A coal or a blend of coals
that meets sulfur dioxide emission standards for air quality
without the need for flue gas desulfurization.
B-1
current market price:
For any class of units
as of any date, the average of the daily closing prices for the
20 consecutive trading days immediately prior to that date.
dozer:
A large, powerful tractor having a
vertical blade at the front end for moving earth, rocks, etc.
GAAP:
Generally accepted accounting principles
in the United States.
highwall:
The unexcavated face of exposed
overburden and coal in a surface mine or in a face or bank on
the uphill side of a contour mine excavation.
incentive distribution right:
A non-voting
limited partner interest initially issued to the general
partner. An incentive distribution right will confer upon its
holder only the rights and obligations specifically provided in
the partnership agreement for incentive distribution rights.
incentive distributions:
The distributions of
available cash from operating surplus made to holders of the
incentive distribution rights.
industrial boilers:
Closed vessels that use a
fuel source to heat water or generate steam for industrial
heating and humidification applications.
interim capital transactions:
The following
transactions: (i) borrowings, (ii) sales of equity and
debt securities, (iii) sales or other dispositions of
assets outside the ordinary course of business,
(iv) capital contributions received, (v) corporate
reorganizations or restructurings and (vi) the termination
of interest rate hedge contracts or commodity hedge contracts
prior to the termination date specified therein (provided that
cash receipts from any such termination will be included in
operating surplus in equal quarterly installments over the
remaining scheduled life of such contract).
limestone:
A rock predominantly composed of
the mineral calcite (calcium carbonate (CaCO2)).
metallurgical coal:
The various grades of coal
suitable for carbonization to make coke for steel manufacture.
Its quality depends on four important criteria: volatility,
which affects coke yield; the level of impurities including
sulfur and ash, which affects coke quality; composition, which
affects coke strength; and basic characteristics, which affect
coke oven safety. Metallurgical coal typically has a
particularly high Btu but low ash and sulfur content.
operating expenditures:
All of our cash
expenditures (or our proportionate share of expenditures in the
case of subsidiaries that are not wholly owned), including, but
not limited to, taxes, reimbursements of expenses to our general
partner, interest payments, payments made in the ordinary course
of business under interest rate hedge contracts and commodity
hedge contracts, estimated maintenance capital expenditures and
non-pro rata repurchases of units (other than those made with
the proceeds of an interim capital transaction), provided that
operating expenditures will not include: payments (including
prepayments and prepayment penalties) of principal of and
premium on indebtedness; expansion capital expenditures; actual
maintenance capital expenditures; payment of transaction
expenses (including taxes) relating to interim capital
transactions; or distributions to partners.
operating surplus:
The total of
$ million; plus all of our
cash receipts after the closing of this offering, excluding cash
from interim capital transactions; less all of our operating
expenditures after the closing of this offering; less the amount
of cash reserves established by our general partner prior to the
date of determination of available cash to provide funds for
future operating expenditures. Operating surplus does not
reflect actual cash on hand that is available for distribution
to our unitholders.
probable (indicated) reserves:
Reserves for
which quantity and grade
and/or
quality are computed from information similar to that used for
proven (measured) reserves, but the sites for inspection,
sampling, and measurement are farther apart or are otherwise
less adequately spaced. The degree of assurance, although lower
than that for proven (measured) reserves, is high enough to
assume continuity between points of observation.
proven (measured) reserves:
Reserves for which
(i) quantity is computed from dimensions revealed in
outcrops, trenches, workings or drill holes; (ii) grade
and/or
quality are computed from the results of detailed sampling; and
(iii) the sites for inspection, sampling and measurement
are spaced so closely and the geologic character is so well
defined that size, shape, depth and mineral content of reserves
are well-established.
B-2
reclamation:
The restoration of mined land to
original contour, use or condition.
reserve:
That part of a mineral deposit that
could be economically and legally extracted or produced at the
time of the reserve determination.
scrubbed power plant:
A power plant that uses
scrubbers to clean the gases that pass through its smokestacks.
scrubbers:
Air pollution control devices that
can be used to remove some particulates and chemical compounds
from industrial exhaust streams.
selective catalytic reduction, or SCR,
device:
A means of converting nitrogen oxides,
also referred to as NOx, with the aid of a catalyst into
diatomic nitrogen, N2, and water, H2O.
spoil-piles:
Earth and rock removed from a
coal deposit and temporarily stored during excavation.
steam coal:
Coal used by power plants and
industrial steam boilers to produce electricity, steam or both.
subordination period:
The subordination period
will begin upon the date of this offering and will extend until
the first business day of any quarter beginning after a date
determined by the conflicts committee of the board of directors
of our general partner, that each of the following tests are
met: (i) distributions of available cash from operating
surplus on each of the outstanding common units, subordinated
units and general partner units equaled or exceeded the minimum
quarterly distribution for each of the three consecutive,
non-overlapping four-quarter periods immediately preceding that
date; (ii) the adjusted operating surplus
generated during each of the three consecutive, non-overlapping
four-quarter periods immediately preceding that date equaled or
exceeded the sum of the minimum quarterly distributions on all
of the outstanding common units, subordinated units and general
partner units during those periods on a fully diluted basis; and
(iii) there are no arrearages in payment of the minimum
quarterly distribution on the common units. Notwithstanding the
foregoing, the subordination period shall terminate and all of
the subordinated units will convert into common units on a
one-for-one
basis if each of the following occurs: (i) distributions of
available cash from operating surplus on each of the outstanding
common units, subordinated units and general partner units
equaled or exceeded 150% of the minimum quarterly distribution
for each calendar quarter in the immediately preceding
four-quarter period; (ii) the adjusted operating
surplus generated during each calendar quarter in the
immediately preceding four-quarter period equaled or exceeded
150% of the minimum quarterly distribution on each of the
outstanding common units, subordinated units and general partner
units during that period on a fully diluted basis; and
(iii) there are no arrearages in payment of the minimum
quarterly distributions on the common units.
tipple:
A structure where coal is cleaned and
loaded in railroad cars or trucks.
total maximum daily load:
A calculation of the
maximum amount of a pollutant that a body of water can receive
per day and still safely meet water quality standards.
units:
Refers to both common units and
subordinated units.
B-3
Oxford
Resource Partners, LP
Common
Units
Representing
Limited Partner Interests
Prospectus
,
2010
Barclays
Capital
Citi
Until ,
2010 (25 days after the date of this prospectus), all dealers
that buy, sell or trade our common units, whether or not
participating in this offering, may be required to deliver a
prospectus. This is in addition to the dealers obligation
to deliver a prospectus when acting as underwriters and with
respect to their unsold allotments or subscriptions.
PART II
INFORMATION
NOT REQUIRED IN THE PROSPECTUS
|
|
Item 13.
|
Other
Expenses of Issuance and Distribution.
|
Set forth below are the expenses (other than the underwriting
discount) expected to be incurred in connection with the
issuance and distribution of the securities registered hereby.
With the exception of the SEC registration fee, the FINRA filing
fee and the NYSE listing fee, the amounts set forth below are
estimates.
|
|
|
|
|
SEC registration fee
|
|
$
|
17,825
|
|
FINRA filing fee
|
|
|
25,500
|
|
NYSE listing fee
|
|
|
*
|
|
Printing and engraving expenses
|
|
|
*
|
|
Fees and expenses of legal counsel
|
|
|
*
|
|
Accounting fees and expenses
|
|
|
*
|
|
Transfer agent fees
|
|
|
*
|
|
Miscellaneous
|
|
|
*
|
|
|
|
|
|
|
Total
|
|
$
|
*
|
|
|
|
|
|
|
|
|
|
*
|
|
To be provided by amendment.
|
|
|
Item 14.
|
Indemnification
of Directors and Officers.
|
The section of the prospectus entitled The Partnership
Agreement Indemnification discloses that we
will generally indemnify officers, directors and affiliates of
our general partner to the fullest extent permitted by the law
against all losses, claims, damages or similar events and is
incorporated herein by this reference. Reference is also made to
the underwriting agreement to be filed as an exhibit to this
registration statement, which provides for the indemnification
of Oxford Resource Partners, LP and our general partner,
their officers and directors, and any person who controls Oxford
Resource Partners, LP and our general partner, including
indemnification for liabilities under the Securities Act.
Subject to any terms, conditions or restrictions set forth in
the partnership agreement,
Section 17-108
of the Delaware Revised Uniform Limited Partnership Act empowers
a Delaware limited partnership to indemnify and hold harmless
any partner or other person from and against all claims and
demands whatsoever. As of the consummation of this offering, the
general partner of the registrant will maintain directors and
officers liability insurance for the benefit of its directors
and officers.
|
|
Item 15.
|
Recent
Sales of Unregistered Securities.
|
On August 27, 2007, in connection with the formation of the
partnership, we received (1) a contribution of
approximately $35.7 million in cash from AIM Oxford in
exchange for the issuance of 3,185,000 Class B common units
to AIM Oxford, (2) a contribution of approximately
$19.2 million in equity in Oxford Mining Company from
C&T Coal in exchange for cash and the issuance of 1,715,000
Class B common units to C&T Coal and (3) a
contribution of approximately $1.1 million in cash from
Oxford Resources GP, LLC in exchange for the issuance to Oxford
Resources GP, LLC of 100,000 general partner units and the
incentive distribution rights, which rights will become
effective upon an initial public offering. These transactions
were exempt from registration under Section 4(2) of the
Securities Act of 1933. The number of units set forth above
reflect a 5,000 to 1 units split that was authorized by our
general partner on October 23, 2007.
On March 27, 2008, we entered into a contribution agreement
with Oxford Resources GP, LLC and AIM Oxford. Pursuant to this
contribution agreement, we received a contribution of
approximately $8.8 million from AIM Oxford as consideration
for the issuance to AIM Oxford of 787,500 Class B common
units. We also received a contribution of approximately $180,000
from Oxford Resources GP, LLC as consideration for
II-1
the issuance to Oxford Resources GP, LLC of approximately 16,071
general partner units. These transactions were exempt from
registration under Section 4(2) of the Securities Act of
1933.
On September 26, 2008, we entered into a contribution
agreement with Oxford Resources GP, LLC, C&T Coal and AIM
Oxford. Pursuant to this contribution agreement, we received a
contribution of approximately $686,000 from C&T Coal and a
contribution of $1.3 million from AIM Oxford as
consideration for the issuance to C&T Coal and AIM Oxford
of 61,250 Class B common units and 113,750 Class B
common units, respectively. We also received a contribution of
approximately $40,000 from Oxford Resources GP, LLC as
consideration for the issuance to Oxford Resources GP, LLC of
approximately 3,571 general partner units. These transactions
were exempt from registration under Section 4(2) of the
Securities Act of 1933.
On August 28, 2009, we entered into a contribution
agreement with C&T Coal and AIM Oxford. Pursuant to this
contribution agreement, we received a contribution of
approximately $1.1 million from C&T Coal and a
contribution of approximately $2.0 million from AIM Oxford
as consideration for the issuance to C&T Coal and AIM
Oxford of 35 deferred participation units and 65 deferred
participation units, respectively. These transactions were
exempt from registration under Section 4(2) of the
Securities Act of 1933.
On September 28, 2009, we entered into a contribution and
conversion agreement with Oxford Resources GP, LLC, C&T
Coal and AIM Oxford. Pursuant to this contribution and
conversion agreement, we received a contribution of
approximately $1.5 million from C&T Coal and a
contribution of approximately $6.9 million from AIM Oxford
as consideration for the issuance to C&T Coal and AIM
Oxford of 84,337 Class B common units and 393,575
Class B common units, respectively. We also received a
contribution of approximately $231,224 from Oxford Resources GP,
LLC as consideration for the issuance to Oxford Resources GP,
LLC of approximately 13,266 general partner units. In connection
with the execution of this contribution and conversion
agreement, C&T Coal and AIM Oxford elected to convert their
deferred participation units into approximately 60,241
Class B common units and approximately 111,876 Class B
common units, respectively. These transactions were exempt from
registration under Section 4(2) of the Securities Act of
1933.
|
|
Item 16.
|
Exhibits
and Financial Statement Schedules.
|
(a) The following documents are filed as exhibits to this
registration statement:
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1**
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1*
|
|
|
|
Certificate of Limited Partnership of Oxford Resource Partners,
LP
|
|
3
|
.2**
|
|
|
|
Form of Third Amended and Restated Agreement of Limited
Partnership of Oxford Resource Partners, LP (included as
Appendix A
to the Prospectus)
|
|
5
|
.1**
|
|
|
|
Opinion of Latham & Watkins LLP as to the legality of the
securities being registered
|
|
8
|
.1**
|
|
|
|
Opinion of Latham & Watkins LLP relating to tax matters
|
|
10
|
.1**
|
|
|
|
Form of Credit Agreement
|
|
10
|
.2**
|
|
|
|
Investors Rights Agreement, dated August 24, 2007, by
and among Oxford Resource Partners, LP, Oxford Resources GP,
LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C.
Ungurean and Thomas T. Ungurean
|
|
10
|
.3**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and
Michael B. Gardner
|
|
10
|
.4**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and
Jeffrey M. Gutman
|
|
10
|
.5**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and
Gregory J. Honish
|
|
10
|
.6**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and
Charles C. Ungurean
|
|
10
|
.7**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and Thomas
T. Ungurean
|
|
10
|
.8**
|
|
|
|
Employee Unitholder Agreement between Oxford Resources GP, LLC
and Michael B. Gardner
|
|
10
|
.9**
|
|
|
|
Employee Unitholder Agreement between Oxford Resources GP, LLC
and Jeffrey M. Gutman
|
|
10
|
.10**
|
|
|
|
Employee Unitholder Agreement between Oxford Resources GP, LLC
and Gregory J. Honish
|
|
10
|
.11**
|
|
|
|
Employee Unitholder Agreement between Oxford Resources GP, LLC
and Denise M. Maksimoski
|
|
10
|
.12**
|
|
|
|
Oxford Resource Partners, LP Long-Term Incentive Plan, as amended
|
|
10
|
.13**
|
|
|
|
Form of Long-Term Incentive Plan Grant Agreement
|
|
10
|
.14**
|
|
|
|
Form of Non-Employee Director Compensation Plan
|
II-2
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
10
|
.15**
|
|
|
|
Form of Non-Employee Director Compensation Plan Grant Agreement
|
|
10
|
.16**
|
|
|
|
Acquisition Agreement, dated August 14, 2009, by and among
Oxford Mining Company, LLC, Phoenix Coal Inc., Phoenix Coal
Corporation and Phoenix Newco, LLC
|
|
21
|
.1*
|
|
|
|
List of Subsidiaries of Oxford Resource Partners, LP
|
|
23
|
.1*
|
|
|
|
Consent of Grant Thornton LLP
|
|
23
|
.2*
|
|
|
|
Consent of Ernst & Young LLP
|
|
23
|
.3*
|
|
|
|
Consent of John T. Boyd Company
|
|
23
|
.4**
|
|
|
|
Consent of Latham & Watkins LLP (contained in Exhibit 5.1)
|
|
23
|
.5**
|
|
|
|
Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
|
|
24
|
.1*
|
|
|
|
Powers of Attorney (included on the signature page)
|
|
|
|
*
|
|
Filed herewith.
|
|
**
|
|
To be filed by amendment.
|
(b) Financial Statements Schedules.
The undersigned registrant hereby undertakes to provide to the
underwriters at the closing specified in the underwriting
agreement certificates in such denominations and registered in
such names as required by the underwriters to permit prompt
delivery to each purchaser.
Insofar as indemnification for liabilities arising under the
Securities Act of 1933 may be permitted to directors,
officers and persons controlling the registrant pursuant to the
foregoing provisions, the registrant has been informed that in
the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the Act
and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment
by the registrant of expenses incurred or paid by a director,
officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is
asserted by such director, officer or controlling person in
connection with the securities being registered, the registrant
will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of
appropriate jurisdiction the question of whether or not such
indemnification by it is against public policy as expressed in
the Securities Act of 1933 and will be governed by the final
adjudication of such issue.
The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under the
Securities Act of 1933, the information omitted from the form of
prospectus filed as part of this registration statement in
reliance upon Rule 430A and contained in a form of
prospectus filed by the registrant pursuant to
Rule 424(b)(1) or (4) or 497(h) under the Securities
Act of 1933 shall be deemed to be part of this registration
statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the
Securities Act of 1933, each post-effective amendment that
contains a form of prospectus shall be deemed to be a new
registration statement relating to the securities offered
therein, and the offering of such securities at that time shall
be deemed to be the initial bona fide offering thereof.
II-3
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the
registrant has duly caused this Registration Statement to be
signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Houston, State of Texas, on
March 24, 2010.
OXFORD RESOURCE PARTNERS, LP,
|
|
|
|
By:
|
Oxford Resources GP, LLC
its General Partner
|
|
|
|
|
By:
|
/s/ Jeffrey
M. Gutman
|
Jeffrey M. Gutman
Senior Vice President, Chief Financial Officer and Treasurer
Each person whose signature appears below appoints Michael B.
Gardner and Jeffrey M. Gutman, and each of them, either of whom
may act without the joinder of the other, as his true and lawful
attorneys-in-fact and agents, with full power of substitution
and resubstitution, for him and in his name, place and stead, in
any and all capacities, to sign any and all amendments
(including post-effective amendments) to this Registration
Statement and any Registration Statement (including any
amendment thereto) for this offering that is to be effective
upon filing pursuant to Rule 462(b) under the Securities
Act of 1933 and to file the same, with all exhibits thereto, and
all other documents in connection therewith, with the Securities
and Exchange Commission, granting unto said attorneys-in-fact
and agents full power and authority to do and perform each and
every act and thing requisite and necessary to be done, as fully
to all intents and purposes as he might or would do in person,
hereby ratifying and confirming all that said attorneys-in-fact
and agents or either of them or their or his substitute and
substitutes, may lawfully do or cause to be done by virtue
hereof.
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following
persons in their indicated capacities, which are with the
general partner of the registrant, on March 24, 2010.
|
|
|
|
|
Signature
|
|
Title
|
|
|
|
|
/s/ George
E. McCown
George
E. McCown
|
|
Chairman of the Board
|
|
|
|
/s/ Charles
C. Ungurean
Charles
C. Ungurean
|
|
Director, President and Chief Executive Officer
(principal executive officer)
|
|
|
|
/s/ Jeffrey
M. Gutman
Jeffrey
M. Gutman
|
|
Senior Vice President and Chief Financial Officer
(principal financial officer)
|
|
|
|
/s/ Denise
M. Maksimoski
Denise
M. Maksimoski
|
|
Senior Director of Accounting
(principal accounting officer)
|
|
|
|
/s/ Brian
D. Barlow
Brian
D. Barlow
|
|
Director
|
|
|
|
/s/ Matthew
P. Carbone
Matthew
P. Carbone
|
|
Director
|
|
|
|
/s/ Gerald
A. Tywoniuk
Gerald
A. Tywoniuk
|
|
Director
|
II-4
EXHIBIT INDEX
|
|
|
|
|
|
|
Exhibit
|
|
|
|
|
Number
|
|
|
|
Description
|
|
|
1
|
.1**
|
|
|
|
Form of Underwriting Agreement
|
|
3
|
.1*
|
|
|
|
Certificate of Limited Partnership of Oxford Resource Partners,
LP
|
|
3
|
.2**
|
|
|
|
Form of Third Amended and Restated Agreement of Limited
Partnership of Oxford Resource Partners, LP (included as
Appendix A
to the Prospectus)
|
|
5
|
.1**
|
|
|
|
Opinion of Latham & Watkins LLP as to the legality of the
securities being registered
|
|
8
|
.1**
|
|
|
|
Opinion of Latham & Watkins LLP relating to tax matters
|
|
10
|
.1**
|
|
|
|
Form of Credit Agreement
|
|
10
|
.2**
|
|
|
|
Investors Rights Agreement, dated August 24, 2007, by
and among Oxford Resource Partners, LP, Oxford Resources GP,
LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C.
Ungurean and Thomas T. Ungurean
|
|
10
|
.3**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and
Michael B. Gardner
|
|
10
|
.4**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and
Jeffrey M. Gutman
|
|
10
|
.5**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and
Gregory J. Honish
|
|
10
|
.6**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and
Charles C. Ungurean
|
|
10
|
.7**
|
|
|
|
Employment Agreement between Oxford Resources GP, LLC and Thomas
T. Ungurean
|
|
10
|
.8**
|
|
|
|
Employee Unitholder Agreement between Oxford Resources GP, LLC
and Michael B. Gardner
|
|
10
|
.9**
|
|
|
|
Employee Unitholder Agreement between Oxford Resources GP, LLC
and Jeffrey M. Gutman
|
|
10
|
.10**
|
|
|
|
Employee Unitholder Agreement between Oxford Resources GP, LLC
and Gregory J. Honish
|
|
10
|
.11**
|
|
|
|
Employee Unitholder Agreement between Oxford Resources GP, LLC
and Denise M. Maksimoski
|
|
10
|
.12**
|
|
|
|
Oxford Resource Partners, LP Long-Term Incentive Plan, as amended
|
|
10
|
.13**
|
|
|
|
Form of Long-Term Incentive Plan Grant Agreement
|
|
10
|
.14**
|
|
|
|
Form of Non-Employee Director Compensation Plan
|
|
10
|
.15**
|
|
|
|
Form of Non-Employee Director Compensation Plan Grant Agreement
|
|
10
|
.16**
|
|
|
|
Acquisition Agreement, dated August 14, 2009, by and among
Oxford Mining Company, LLC, Phoenix Coal Inc., Phoenix Coal
Corporation and Phoenix Newco, LLC
|
|
21
|
.1*
|
|
|
|
List of Subsidiaries of Oxford Resource Partners, LP
|
|
23
|
.1*
|
|
|
|
Consent of Grant Thornton LLP
|
|
23
|
.2*
|
|
|
|
Consent of Ernst & Young LLP
|
|
23
|
.3*
|
|
|
|
Consent of John T. Boyd Company
|
|
23
|
.4**
|
|
|
|
Consent of Latham & Watkins LLP (contained in Exhibit 5.1)
|
|
23
|
.5**
|
|
|
|
Consent of Latham & Watkins LLP (contained in Exhibit 8.1)
|
|
24
|
.1*
|
|
|
|
Powers of Attorney (included on the signature page)
|
|
|
|
*
|
|
Filed herewith.
|
|
**
|
|
To be filed by amendment.
|
II-5