Delaware | 1221 | 77-10695453 | ||
(State or Other Jurisdiction
of
Incorporation or Organization) |
(Primary Standard Industrial
Classification Code Number) |
(I.R.S. Employer Identification Number) |
William N. Finnegan IV
Brett E. Braden Latham & Watkins LLP 717 Texas Avenue, Suite 1600 Houston, Texas 77002 (713) 546-5400 |
G. Michael OLeary
William J. Cooper Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 (713) 220-4200 |
Large accelerated
filer
o
|
Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
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.
|
| 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 must generate approximately $36.7 million of available cash from operating surplus to pay the minimum quarterly distribution for four quarters on all of our common units, subordinated units and general partner units that will be outstanding immediately after this offering. For the year ended December 31, 2009 and the twelve months ended March 31, 2010, we generated only $16.1 million and $10.8 million of available cash from operating surplus, respectively, and would not have been able to pay the full minimum quarterly distribution on our common units or any distributions on our subordinated units during those periods. In addition, we believe that we will not have generated cash available for distribution for the quarter ended June 30, 2010 sufficient to pay the full minimum quarterly distribution on all of our common units, subordinated units and general partner units that will be outstanding immediately after this offering. |
| Our general partner and its affiliates have conflicts of interest with us, and their limited fiduciary duties to our unitholders may permit them to favor their own interests to the detriment of our unitholders. |
| Decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators could adversely affect our business. |
| New 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. |
| Competition within the coal industry may materially and adversely affect our ability to sell coal at an acceptable price. |
| 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. |
| Our inability to acquire additional coal reserves that are economically recoverable may have a material adverse effect on our future profitability. |
| 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. |
| Our unitholders share of our income will be taxable to them for U.S. federal income tax purposes even if they do not receive any cash distributions from us. |
Per Common Unit | Total | |||||||
Public Offering Price
|
$ | $ | ||||||
Underwriting
Discount
(1)
|
$ | $ | ||||||
Proceeds to us (before expenses)
|
$ | $ |
(1) | Excludes a structuring fee equal to an aggregate of 0.5% of the gross proceeds from this offering payable to Barclays Capital Inc. and Citigroup Global Markets Inc. |
Barclays Capital | Citi |
Credit Suisse | Raymond James | Wells Fargo Securities | UBS Investment Bank |
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F-1
A-1
B-1
EX-1.1
EX-5.1
EX-8.1
EX-10.1
EX-10.17A
EX-10.17C
EX-10.17D
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As of December 31, 2009
Production for
Production for
Total
the Year Ended
the Quarter
Proven &
Average
Average
Primary
December 31,
Ended
Probable
Proven
Probable
Heat
Sulfur
Transportation
Mining Complexes
2009
March 31, 2010
Reserves
(1)
Reserves
(1)
Reserves
(1)
Value
Content
Methods
(in million tons)
(Btu/lb)
(%)
1.1
0.3
12.4
12.2
0.2
11,520
3.3
Barge, Rail
0.9
0.3
8.8
8.8
0.0
11,570
3.7
Truck
1.3
0.3
6.6
6.3
0.3
11,510
3.7
Barge
0.5
0.1
6.4
6.4
0.0
11,350
4.4
Truck
0.6
0.1
4.9
4.0
0.9
11,260
4.0
Rail
0.7
0.2
2.8
2.8
0.0
12,040
1.8
Barge, Rail, Truck
0.3
0.1
2.5
2.4
0.1
11,230
4.7
Barge, Truck
0.4
(3)
0.4
24.2
23.5
0.7
11,295
3.6
Barge, Truck
5.8
1.8
68.6
66.4
2.2
23.0
18.6
4.4
12,900
2.1
23.0
18.6
4.4
91.6
85.0
6.6
(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
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consolidated financial statements for the year ended
December 31, 2009 and the first quarter of 2010 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.
(3)
Acquired from Phoenix Coal on September 30, 2009. As a
result, production data for 2009 represents production from the
date of acquisition through 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. We received royalty payments on
0.6 million tons and 0.1 million tons of coal produced
from the Tusky mining complex during 2009 and the first quarter
of 2010, respectively.
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
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time. Please read Cash Distribution Policy and
Restrictions on Distributions General
Our Ability to Grow is Dependent on Our Ability to Access
External Expansion Capital for additional details on how
we intend to grow our reserve base and production capacity and
the limitations we face in implementing this strategy.
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 97.6%, 101.5%, 71.3% and
40.9%, respectively, of our 2010 estimated coal sales of
8.2 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
23.3 million tons of coal and acquired 52.6 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.
Our mining operations are flexible and
diverse.
During the first quarter of 2010, our
largest mine represented 12.6% of our coal production. We
currently have 17 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, the expertise of our general partners employees
and their 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%, respectively, through 2015. 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 general partners senior management team and key
operational employees have extensive industry
experience.
The members of our general
partners 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.
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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.
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.
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.
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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.
We must generate approximately $36.7 million of available
cash from operating surplus to pay the minimum quarterly
distribution for four quarters on all of our common units,
subordinated units and general partner units that will be
outstanding immediately after this offering. For the year ended
December 31, 2009 and the twelve months ended
March 31, 2010, we generated only $16.1 million and
$10.8 million of available cash from operating surplus,
respectively, and would not have been able to pay the full
minimum quarterly distribution on our common units or any
distributions on our subordinated units during those periods. In
addition, we believe that we will not have generated cash
available for distribution for the quarter ended June 30,
2010 sufficient to pay the full minimum quarterly distribution
on all of our common units, subordinated units and general
partner units that will be outstanding immediately after this
offering.
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.
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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.
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.
Competition within the coal industry may materially and
adversely affect our ability to sell coal at an acceptable price.
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.
New 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.
In the future, we may not receive cash distributions from
Harrison Resources, and Harrison Resources may not be able to
acquire additional reserves on economical terms from CONSOL
Energy.
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.
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.
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.
We may be unable to obtain, maintain or renew permits necessary
for our operations, which would materially reduce our
production, cash flows and profitability.
If the assumptions underlying our reclamation and mine closure
obligations are materially inaccurate, our costs could be
significantly greater than anticipated.
Debt we incur in the future may limit our flexibility to obtain
financing and to pursue other business opportunities.
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.
Our operations may impact the environment or cause environmental
contamination, which could result in material liabilities to us.
Our ability to operate our business effectively could be
impaired if we fail to attract and retain key management
personnel.
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.
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Our work force could become unionized in the future, which 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 ability to collect payments from our customers could be
impaired if their creditworthiness deteriorates.
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.
The amount of estimated reserve replacement 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 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.
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.
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.
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 with us, 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.
Our unitholders will experience immediate and substantial
dilution of $14.43 per common unit.
The control of our general partner may be transferred to a third
party without unitholder consent.
The incentive distribution rights of our general partner may be
transferred to a third party without unitholder consent.
Our general partner has a limited call right that may require
our unitholders to sell their common units at an undesirable
time or price.
We may issue additional units without unitholder approval, which
would dilute unitholder interests.
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.
Cost reimbursements due to our general partner and its
affiliates will reduce cash available for distribution to our
unitholders.
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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.
We will incur increased costs as a result of being a publicly
traded partnership.
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 receive distributions or
allocations of income or loss on their common units and their
common units will be subject to redemption.
Our unitholders may have liability to repay distributions.
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 share of our income will be taxable to
them for U.S. federal income tax purposes even if they do
not receive any cash distributions from us.
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.
Tax gain or loss on the disposition of our common units could be
more or less than expected.
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.
We will treat each purchaser of our 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 our common units.
We prorate our items of income, gain, loss and deduction for
U.S. federal income tax purposes 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.
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, such
unitholder 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.
We will adopt certain valuation methodologies and monthly
conventions for U.S. federal income tax purposes that may result
in a shift of income, gain, loss and deduction between our
general partner
9
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and our unitholders. The IRS may challenge this treatment, which
could adversely affect the value of our common units.
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.
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.
we will distribute pro rata, in accordance with their respective
interests in us, the right to receive cash collected from an
aggregate of $21.0 million of our 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, that hold our common units;
each general partner unit held by our general partner will
automatically split into 1.82 general partner units, resulting
in the ownership by our general partner of an aggregate of
244,607 general partner units, representing a 2.0% general
partner interest in us;
each common unit held by participants in our LTIP will
automatically split into 1.82 common units, resulting in their
ownership of an aggregate of 126,577 common units, representing
an aggregate 1.0% limited partner interest in us;
each outstanding phantom unit granted to participants in our
LTIP will automatically split into 1.82 phantom units, resulting
in their holding an aggregate of 181,262 phantom units;
each Class B common unit held by C&T Coal will
automatically split into 1.82 Class B common units,
resulting in C&T Coals ownership of an aggregate of
3,999,696 Class B common units, representing an aggregate
32.7% limited partner interest in us; and
each Class B common unit held by AIM Oxford will
automatically split into 1.82 Class B common units,
resulting in AIM Oxfords ownership of an aggregate of
7,859,487 Class B common units, representing an aggregate
64.3% limited partner interest in us.
all of our Class B common units held by C&T Coal will
automatically convert into: (i) 532,476 common units
and (ii) 3,467,220 subordinated units;
all of our Class B common units held by AIM Oxford will
automatically convert into: (i) 1,046,327 common units and (ii)
6,813,160 subordinated units;
we will issue 8,750,000 common units to the public in this
offering;
C&T Coal and AIM Oxford will contribute 59,022 common units
and 115,978 common units, respectively, to our general partner
as a capital contribution;
our general partner will contribute the common units contributed
to it by C&T Coal and AIM Oxford to us in exchange for
175,000 general partner units in order to maintain its 2.0%
general partner interest in us;
we will use the net proceeds from this offering for the purposes
set forth in Use of Proceeds;
we will enter into a new credit facility; and
we will use the net proceeds from borrowings under our new
credit facility for the purposes set forth in Use of
Proceeds.
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41.7
%
2.3
%
4.4
%
16.5
%
32.5
%
2.0
%
0.6
%
100
%
11
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12
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13
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Common units offered to the public
8,750,000 common units.
10,062,500 common units if the underwriters exercise their
option to purchase additional common units in full.
Units outstanding after this offering
10,280,380 common units representing a 49.0% limited partner
interest in us and 10,280,380 subordinated units representing a
49.0% limited partner interest in us.
Our general partner will own 419,607 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 $162.8 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 $22.3 million to
C&T Coal, (iii) distribute approximately
$0.7 million to the participants in our LTIP that hold our
common units, (iv) terminate our advisory services
agreement with affiliates of AIM for a payment of approximately
$2.5 million, (v) pay offering expenses of
approximately $3.2 million, (vi) purchase major mining
equipment for approximately $22.1 million and
(vii) replenish approximately $15.5 million of our
working capital.
We will use the proceeds from borrowings of approximately
$86.0 million under our new credit facility to
(i) distribute approximately $43.8 million to AIM
Oxford, (ii) pay fees and expenses relating to our new
credit facility of approximately $5.3 million,
(iii) distribute approximately $1.3 million to our
general partner in respect of its general partner interest,
(iv) replenish approximately $3.5 million of our
working capital that we distributed to our partners immediately
prior to the closing of this offering and (v) purchase
major mining equipment that we currently lease for approximately
$32.1 million.
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.
For more information about our use of the proceeds of this
offering, including a tabular summary, please read Use of
Proceeds.
Cash distributions
We intend to pay a minimum quarterly distribution of
$0.4375 per common unit (or $1.75 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
14
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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 do not expect to make distributions with respect to the
quarter ended June 30, 2010 or for the period that begins
on July 1, 2010 and ends on the day prior to the closing of
this offering other than the distributions to be made in
connection with the closing of this offering that are described
in Summary The Transactions and
Use of Proceeds. We will adjust the minimum
quarterly distribution for the period from the closing of this
offering through September 30, 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 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:
If cash distributions to our unitholders exceed $0.5031 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
Total Quarterly Distribution
in Distributions
Target Amount
Unitholders
General Partner
85%
15%
75%
25%
50%
50%
Please read How We Make Cash Distribution
General Partner Interest and Incentive Distribution
Rights.
15
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Our historical cash available for distribution generated during
the year ended December 31, 2009 and the twelve months
ended March 31, 2010 was $16.1 million and
$10.8 million, respectively. 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 $36.7 million (or an average of
$9.2 million per quarter). As a result, for the year ended
December 31, 2009 and the twelve months ended
March 31, 2010 we would have generated aggregate available
cash sufficient to pay only 87.8% and 58.8%, respectively, of
the aggregate minimum quarterly distribution on our common units
during those periods, and we would not have been able to pay any
distributions on our subordinated units in those periods. We
have not used
quarter-by-quarter
estimates for each quarter in the year ended December 31,
2009 and the twelve months ended March 31, 2010 to
determine if we would have generated available cash sufficient
to pay the minimum quarterly distribution for each quarter
during those periods. 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
$0.4375 on all of our common units and subordinated units and
the corresponding distribution on our general partners
2.0% general partner interest for the four quarters ending
June 30, 2011. 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 $44.1 million. Although we believe we
will have available cash sufficient to pay the minimum quarterly
distribution on all of our units for each quarter in the
forecast period, we do not provide a quarterly forecast for each
quarter in the forecast period due to the uncertainty
surrounding the precise timing of certain anticipated capital
expenditures during the latter part of the forecast period.
During the quarter ending September 30, 2010, we expect
that cash generated from operations will be approximately
$6.9 million, or approximately $2.3 million less than
the amount of cash needed to pay the entire minimum quarterly
distribution on all of our outstanding units. As a result,
during that period we expect to generate cash from operations
sufficient to pay the entire minimum quarterly distribution on
our common units, but only 52.9% of the minimum quarterly
distribution on our subordinated units. We expect to fund the
additional $2.3 million distribution on our subordinated
units with cash on-hand or working capital borrowings.
Our financial forecast does not include the quarter ended
June 30, 2010 and we do not have complete financial
information available
16
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with respect to that quarter. However, based on the preliminary
financial information we have available at this time, we believe
that we will not have generated cash available for distribution
for the quarter ended June 30, 2010 sufficient to pay the
full minimum quarterly distribution on all of our common units,
subordinated units and general partner units that will be
outstanding immediately after this offering. Please read
Cash Distribution Policy and Restrictions on
Distributions Anticipated Cash Available for
Distribution for the Quarter Ended June 30, 2010.
Although we do not anticipate any distributions out of capital
surplus, as opposed to operating surplus, any such distributions
would constitute a return of capital to our unitholders and
would result in a reduction in the minimum quarterly
distribution and target distribution levels. For a further
description of the 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) $1.75 (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 September 30, 2013 or (ii) $0.65625 per quarter
(150.0% of the minimum quarterly distribution, which is $2.625
on an annualized basis) on each outstanding common and
subordinated unit and the corresponding distributions on our
general partner units for any four quarter period ending on or
after September 30, 2011, 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
17
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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 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 57.1% 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 25% or less of the cash distributed with
respect to that period.
18
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For example, if you receive an annual distribution of $1.75 per
unit, we estimate that your average allocable federal taxable
income per year will be no more than approximately $0.44 per
unit. Please read Material Federal Income Tax
Consequences Tax Consequences of Unit
Ownership Ratio of Taxable Income to
Distributions for the basis of this estimate.
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 5% of the common units
offered by this prospectus for our officers, directors and
employees of our general partner and certain friends and family
of our sponsors, and the officers, directors and employees of
our general partner. The number of common units available for
sale to the 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 public on the same basis as the other common
units offered by this prospectus. Please read
Underwriting Directed Unit Program.
Material federal income tax consequences
For a discussion of the 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
Our common units have been approved for listing on the New York
Stock Exchange, subject to official notice of issuance, under
the symbol OXF.
19
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20
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Oxford
Mining
Pro Forma Oxford
Company
Oxford Resource Partners, LP
Resource Partners, LP
(Predecessor)
(Successor)
(Successor)
Period from
Period from
January 1,
August 24,
Quarter
2007 to
2007 to
Year Ended
Quarter Ended
Year Ended
Ended
August 23,
December 31,
December 31,
March 31,
December 31,
March 31,
2007
2007
2008
2009
2009
2010
2009
2010
(unaudited)
(In thousands, except per ton amounts)
(unaudited)
$
96,799
$
61,324
$
193,699
$
254,171
$
67,377
$
76,756
$
312,490
$
76,756
18,083
10,204
31,839
32,490
8,660
9,530
37,221
9,530
3,267
1,407
4,951
7,183
2,402
1,774
7,183
1,774
118,149
72,935
230,489
293,844
78,439
88,060
356,894
88,060
70,415
40,721
151,421
170,698
40,825
55,186
208,574
53,254
17,494
9,468
12,925
19,487
8,505
7,859
29,792
7,859
18,083
10,204
31,839
32,490
8,660
9,530
37,221
9,530
9,025
4,926
16,660
25,902
5,688
8,777
41,369
11,270
3,643
2,114
9,577
13,242
3,101
3,535
25,735
3,458
118,660
67,433
222,422
261,819
66,779
84,887
342,691
85,371
(511
)
5,502
8,067
32,025
11,660
3,173
14,203
2,689
26
55
62
35
11
1
39
1
(2,386
)
(3,498
)
(7,720
)
(6,484
)
(1,123
)
(1,833
)
(7,906
)
(1,978
)
3,823
3,823
(2,871
)
2,059
409
29,399
10,548
1,341
10,159
712
(682
)
(537
)
(2,891
)
(5,895
)
(1,165
)
(1,628
)
(5,895
)
(1,628
)
$
(3,553
)
$
1,522
$
(2,482
)
$
23,504
$
9,383
$
(287
)
$
4,264
$
(916
)
$
17,634
$
(8,519
)
$
33,992
$
37,183
$
10,502
$
8,341
(16,619
)
(98,745
)
(23,942
)
(49,528
)
(7,482
)
(10,280
)
(234
)
106,724
4,494
532
2,442
(137
)
$
7,832
$
7,961
$
21,533
$
50,799
$
16,292
$
10,001
$
43,888
$
12,010
1,297
163
2,526
3,057
61
528
3,057
528
11,305
7,420
25,321
25,657
6,715
4,995
25,657
4,995
12,503
13,407
2,523
2,818
n/a
n/a
$
1,175
$
635
$
15,179
$
3,366
$
20,641
$
1,290
$
23,316
18,396
17,547
21,528
24,403
23,196
29,838
8,838
4,824
4,655
5,134
8,801
6,584
10,390
10,390
54,510
106,408
112,446
149,461
117,031
147,949
202,118
90,893
146,774
171,297
203,363
184,982
212,917
269,812
43,165
75,529
83,977
95,711
91,799
98,432
90,915
2,693
1,634
5,089
5,846
1,396
1,806
7,221
1,806
641
305
434
530
192
258
885
258
3,333
1,938
5,528
6,311
1,559
2,036
8,051
2,036
$
29.04
$
31.64
$
35.04
$
40.27
$
43.23
$
37.71
$
38.81
$
37.71
$
26.15
$
24.92
$
29.75
$
29.20
$
29.25
$
30.56
$
28.89
$
29.49
$
27.29
$
31.08
$
29.81
$
36.79
$
44.32
$
30.51
$
33.67
$
30.51
(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 ended
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.
Table of Contents
(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. Our partnership
agreement divides maintenance capital expenditures into two
categories reserve replacement expenditures and
other maintenance capital expenditures. Examples of reserve
replacement expenditures include cash expenditures for the
purchase of fee interests in coal reserves and cash expenditures
for advance royalties with respect to the acquisition of
leasehold interests in coal reserves. Examples of other
maintenance capital expenditures include capital expenditures
associated with the repair, refurbishment and replacement of
equipment. 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 reserve replacement expenditures and which of
them would have been other 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.
22
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the level of our production and coal sales and the amount of
revenue we generate;
the level of our operating costs, including reimbursement of
expenses to our general partner;
changes in governmental regulation of the mining industry or the
electric power industry and the increased costs of complying
with those changes;
our ability to obtain, renew and maintain permits on a timely
basis;
prevailing economic and market conditions; and
difficulties in collecting our receivables because of credit or
financial problems of major customers.
the level of capital expenditures we make;
the restrictions contained in our credit agreement and our debt
service requirements;
the cost of acquisitions;
fluctuations in our working capital needs;
our ability to borrow funds and access capital markets; and
the amount of cash reserves established by our general partner.
23
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efficiencies we expect to gain in the form of lower operating
expenses resulting from our investment in major mining equipment
with a portion of the proceeds from the transactions
contemplated by this offering;
the positive cash flow impact of eliminating operating lease
payments by purchasing the major mining equipment that we
currently lease with the proceeds from the transactions
contemplated by this offering;
the expected favorable cash flow impact of a full year of
operations at our Muhlenberg County mining complex that we
acquired in the Phoenix Coal acquisition and the favorable cash
flow impact of the implementation of more efficient mining
practices at that complex; and
24
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the expected favorable cash flow impact from price increases
embedded in our long term coal sales contracts.
general economic conditions, particularly those affecting
industrial electric power demand, such as the recent downturn in
the U.S. economy and financial markets;
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;
environmental and other governmental regulations, including
those impacting coal-fired power plants; and
energy conservation efforts and related governmental policies.
25
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domestic and foreign supply and demand for coal;
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.
26
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27
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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 or
flooding;
the unavailability of qualified labor and contractors;
the unavailability or increased prices of equipment or other
critical supplies such as tires and explosives, fuel, lubricants
and other consumables;
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 permits or mineral and surface rights;
future health, safety and environmental regulations or changes
in the interpretation or enforcement of existing regulations;
mine accidents or other unforeseen casualty events, including
those involving injuries or fatalities;
increased or unexpected reclamation costs; and
the inability to monitor our operations due to failures of
information technology systems.
28
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a substantial and extended decline in the sales price for coal
produced from our underground coal reserves;
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
a material decline in the creditworthiness of our sublessee,
including as a result of the current economic downturn.
29
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30
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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;
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;
we may be more vulnerable to competitive pressures or a downturn
in our business or the economy generally; and
our flexibility in responding to changing business and economic
conditions may be limited.
incur additional debt;
make distributions on or redeem or repurchase units;
make certain investments and acquisitions;
incur certain liens or permit them to exist;
enter into certain types of transactions with affiliates;
merge or consolidate with another company; and
transfer or otherwise dispose of assets.
31
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32
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quality of the coal;
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;
the percentage of coal ultimately recoverable;
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;
assumptions concerning the timing for the development of
reserves; and
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.
33
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34
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35
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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;
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 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;
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 our
general partner honestly believed that the decision was in the
best interests of the partnership;
generally provides that affiliated transactions and resolutions
of conflicts of interest not approved by 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
provides that our general partner and its officers and directors
will not be liable for monetary damages to us or our limited
partners 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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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;
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;
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;
our general partner determines our estimated reserve replacement
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;
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;
our general partner determines which costs incurred by it and
its affiliates are reimbursable by us;
our partnership agreement does not restrict our general partner
from causing us to pay it or its affiliates for any services
rendered on terms that are fair and reasonable to us or entering
into additional contractual arrangements with any of these
entities on our behalf;
our general partner intends to limit its liability regarding our
contractual and other obligations;
our general partner may exercise its limited right to call and
purchase common units if it and its affiliates own more than
80.0% of the common units;
our general partner controls the enforcement of obligations owed
to us by it and its affiliates; and
our general partner decides whether to retain separate counsel,
accountants or others to perform services for us.
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our unitholders proportionate ownership interest in us
will decrease;
the amount of cash available for distribution on each unit may
decrease;
because a lower percentage of total outstanding units will be
subordinated units, the risk that a shortfall in the payment of
the minimum quarterly distribution will be borne by our common
unitholders will increase;
the relative voting strength of each previously outstanding unit
may be diminished; and
the market price of the common units may decline.
39
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our quarterly distributions;
our quarterly or annual earnings or those of other companies in
our industry;
loss of a large customer;
announcements by us or our competitors of significant contracts
or acquisitions;
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changes in accounting standards, policies, guidance,
interpretations or principles;
changes in interest rates;
general economic conditions;
the failure of securities analysts to cover our common units
after this offering or changes in financial estimates by
analysts; and
the other factors described in these Risk Factors.
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repay in full the outstanding balance under our existing credit
facility, which was approximately $96.5 million at
June 16, 2010;
distribute approximately $22.3 million to C&T Coal in
respect of its limited partner interest in us;
distribute approximately $0.7 million to the participants
in our LTIP that hold our common units in respect of their
limited partner interests in us;
terminate our advisory services agreement with affiliates of AIM
for a payment of approximately $2.5 million;
pay offering expenses of approximately $3.2 million; and
purchase major mining equipment for approximately
$22.1 million.
Application of
Net Proceeds of
Percentage of
this Offering
Net Proceeds
(in thousands)
$
96,517
59.3
%
22,271
13.7
705
0.4
2,500
1.5
3,125
1.9
22,100
13.6
15,532
9.6
$
162,750
100.0
%
distribute approximately $43.8 million to AIM Oxford in
respect of its limited partner interest in us;
pay fees and expenses relating to our new credit facility of
approximately $5.3 million;
distribute approximately $1.3 million to our general
partner in respect of its general partner interest in us;
replenish approximately $3.5 million of our working
capital; and
purchase major mining equipment that we currently lease for
approximately $32.1 million.
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our historical capitalization, as of March 31, 2010; and
our pro forma, as adjusted capitalization as of March 31,
2010, giving effect to:
our entry into our new credit facility and the repayment of all
outstanding indebtedness under our existing credit facility;
our receipt of net proceeds of $162.8 million from the
issuance and sale of 8,750,000 common units to the public
at an assumed initial offering price of $20.00 per unit (based
on the mid-point of the price range set forth on the cover page
of this prospectus);
the application of the net proceeds from this offering in the
manner described in Use of Proceeds; and
the other transactions described in Summary
The Transactions.
As of March 31, 2010
Pro Forma,
Actual
As Adjusted
(in thousands)
$
1,290
$
23,316
(1
)
93,517
86,000
4,915
4,915
$
98,432
$
90,915
157,482
962
(420
)
50,158
(4,766
)
(34,902
)
1,048
(814
)
52,168
116,580
3,695
3,695
55,863
120,275
$
154,295
$
211,190
(1)
This amount includes cash retained from the transactions
described in Use of Proceeds to replenish working
capital. As described in note (2) below, subsequent to
March 31, 2010 we have made an additional $3.0 million
of borrowings under our existing credit facility as of
June 16, 2010. Because we will repay all outstanding
borrowings under our existing credit facility with the proceeds
of this offering, this $3.0 million increase in borrowings
as of June 16, 2010 would result in a corresponding
decrease in cash and cash equivalents of the same amount as of
such date.
(2)
As of June 16, 2010, we had $96.5 million of
borrowings under our existing credit facility. This amount does
not include $8.2 million of letters of credit that were
outstanding under our existing credit facility as of
June 16, 2010.
(3)
This amount does not include $6.9 million in outstanding
letters of credit that will be issued under our new credit
facility.
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$
20.00
$
4.61
0.96
5.57
$
14.43
(1)
Determined by dividing the net tangible book value of our assets
and liabilities by the number of units (1,530,380 common
units, 10,280,380 subordinated units and the 2.0% general
partner interest represented by 419,607 general partner units)
held by our general partner and its affiliates and the
participants under our LTIP.
(2)
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 (10,280,380 common
units, 10,280,380 subordinated units and the 2.0% general
partner interest represented by 419,607 general partner
units) to be outstanding after this offering.
(3)
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 $1.00.
Units Acquired
Total Consideration
Number
Percent
Amount
Percent
($ in millions)
12.2
58.3
%
$
52.2
23.0
%
8.8
41.7
%
175.0
77.0
%
21.0
100.0
%
$
227.2
100.0
%
(1)
Upon the consummation of the transactions contemplated by this
prospectus, our general partner and its affiliates, and the
participants under our LTIP, will own 1,530,380 common
units, 10,280,380 subordinated units and a 2.0% general
partner interest represented by 419,607 general partner
units.
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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. In addition, our ability to pay
quarterly cash distributions will be restricted if an event of
default has occurred under our new credit facility. The
financial tests, covenants and events of default 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.
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.
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,
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approximately 6.7% of our outstanding common units and all of
our outstanding subordinated units. Please read The
Partnership Agreement Amendment of Our Partnership
Agreement.
Even if our cash distribution policy is not modified or revoked,
the amount of distributions we pay under our cash distribution
policy and the decision to make any distribution is determined
by our general partner, taking into consideration the terms of
our partnership agreement.
Under
Section 17-607
of the Delaware Act, we may not make a distribution if the
distribution would cause our liabilities to exceed the fair
value of our assets.
We may lack sufficient cash to pay distributions to our
unitholders due to reduced revenues or increases in our
operating costs, SG&A expenses, principal and interest
payments on our outstanding debt and working capital
requirements.
If we make distributions out of capital surplus, as opposed to
operating surplus, any such distributions would constitute a
return of capital and would 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.
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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Number of Units
One Quarter
Four Quarters
10,280,380
$
4,497,666
$
17,990,665
10,280,380
4,497,666
17,990,665
419,607
183,579
734,312
20,980,367
$
9,178,911
$
36,715,642
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Cash Available for Distribution
Historical
Forecasted
(1)
Year Ended
Twelve Months
Twelve Months
December 31,
Ended
Ending June 30,
2009
March 31, 2010
2011
(In thousands, except per unit and
per ton amounts)
5,846
6,256
7,890
530
595
670
6,376
6,851
8,560
6,311
6,788
8,654
65
63
(94
)
6,311
6,788
8,202
n/a
n/a
452
$
40.27
$
38.83
$
38.51
n/a
n/a
$
41.61
$
254,171
$
263,550
$
315,816
n/a
n/a
18,834
32,490
33,360
44,200
7,183
6,555
7,455
293,844
303,465
386,305
170,698
185,059
217,218
19,487
18,841
20,813
32,490
33,360
44,200
25,902
28,991
49,535
13,242
13,676
15,192
261,819
279,927
346,958
32,025
23,538
39,347
35
25
33
(6,484
)
(7,194
)
(7,435
)
3,823
3,823
29,399
20,192
31,945
(5,895
)
(6,358
)
(5,643
)
$
23,504
$
13,834
$
26,302
25,902
28,991
49,535
6,484
7,194
7,435
472
667
433
35
25
33
3,823
3,823
1,705
2,330
2,100
$
50,799
$
44,508
$
81,572
5,970
6,248
5,656
33,406
35,626
22,100
3,057
3,524
5,682
25,657
23,937
26,175
33,406
35,626
22,100
$
16,115
$
10,799
$
44,059
$
1.75
$
1.75
$
1.75
$
15,313
$
15,313
$
15,313
222
222
222
2,456
2,456
2,456
17,991
17,991
17,991
734
734
734
36,716
36,716
36,716
$
(20,601
)
$
(25,917
)
$
7,343
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(1)
The forecasted column is based on the assumptions set forth in
Significant Forecast Assumptions below.
(2)
Represents coal sold for 2009 and the twelve months ended
March 31, 2010 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 and other revenue.
(4)
Historical SG&A expenses for both the year ended
December 31, 2009 and the twelve months ended
March 31, 2010 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 ending June 30, 2011 do 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 both the year ended
December 31, 2009 and the twelve months ended
March 31, 2010.
(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:
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. Our
partnership agreement divides maintenance capital expenditures
into two categories reserve replacement expenditures
and other maintenance capital expenditures. For purposes of this
presentation, however, we have evaluated our capital
expenditures for both the year ended December 31, 2009 and
the twelve months ended March 31, 2010 to determine which
of them would have been classified as reserve replacement
expenditures and other maintenance capital expenditures,
respectively, in accordance with our partnership agreement at
the time they were made. Based on this evaluation, we estimate
that our reserve replacement expenditures and other maintenance
capital expenditures for the year ended December 31, 2009
would have been $3.1 million and $25.7 million,
respectively, and for the twelve months ended March 31,
2010 would have been $3.5 million and $23.9 million,
respectively. The amount of our actual reserve replacement
expenditures may differ substantially from period to period,
which could
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cause similar fluctuations in the amounts of operating surplus,
adjusted operating surplus and cash available for distribution
to our unitholders, if we subtracted actual reserve replacement
expenditures from operating surplus. To eliminate these
fluctuations, our partnership agreement will require that an
estimate of the reserve replacement expenditures necessary to
maintain our asset base be subtracted from operating surplus
each quarter as opposed to amounts actually spent on reserve
replacement expenditures. The $5.7 million of reserve
replacement expenditures for the forecasted twelve months ending
June 30, 2011 represents estimated reserve replacement
expenditures as defined in our partnership agreement. The amount
of estimated reserve replacement expenditures deducted from
operating surplus must be determined by the board of directors
of our general partner at least once a year, subject to approval
by the Conflicts Committee. We expect our actual reserve
replacement expenditures during the forecast period to be
consistent with our estimated reserve replacement expenditures
for that period. 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
reserve replacement expenditures.
(8)
We expect to fund the $22.1 million of expansion capital
expenditures incurred in the forecast period with the proceeds
from this offering.
(9)
Represents the amount that would be required to pay
distributions for four quarters at our minimum quarterly
distribution rate of $0.4375 per unit on all of the common and
subordinated units that will be outstanding immediately
following this offering and the corresponding distributions on
our general partners 2.0% general partner interest.
We estimate that we will produce approximately 7.9 million
tons of coal during the twelve months ending June 30, 2011,
as compared to approximately 5.8 million tons and
6.3 million tons we produced in the year ended
December 31, 2009 and the twelve months ended
March 31, 2010, respectively. 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 2.0 million tons of coal from
our Muhlenberg County mining complex in the forecast period,
compared to 0.4 million tons of coal during the first
quarter of 2010 (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 9% and 7%
compared to the year ended December 31, 2009 and the twelve
months ended March 31, 2010, respectively. These increases
are primarily attributable to increased production at our
Harrison County mining complex.
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We estimate that we will sell approximately 8.7 million
tons of coal during the twelve months ending June 30, 2011,
as compared to approximately 6.3 million tons and
6.8 million tons we sold in the year ended
December 31, 2009 and the twelve months ended
March 31, 2010, respectively. We have committed to sell
approximately 8.2 million tons, of which 8.0 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. Our
long-term coal sales contracts that provide for these options
typically require the customer to provide us with from one to
three months advance notice of an election to take option tons.
This also assumes that we will reach agreement on an amendment
to a long-term coal sales contract that we are currently
negotiating with AEP. In exchange for the removal of AEPs
right to purchase option tons during an extension period, this
amendment is expected to reduce the tons we are committed to
deliver to AEP by approximately 280,000 tons in the second
half of 2010 and by approximately 150,000 tons and
200,000 tons, respectively, in 2011 and 2012. This also
includes orders to deliver additional tons to AEP from mining
complexes that can ship coal through our Bellaire river terminal
that were placed in June 2010.
We estimate that the average sales price per ton for committed
tons will be $38.51 for the twelve months ending June 30,
2011, as compared to $40.27 and $38.83 for the year ended
December 31, 2009 and the twelve months ended
March 31, 2010, respectively. This estimate takes into
account prices in our long-term coal sales 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 non-recurring price increase for 2009, which
contributed $13.25 million to revenues and Adjusted EBITDA
in 2009, that related to an amendment of a long-term coal sales
contract with a major customer. This estimate also assumes that
we will be successful in negotiating a price increase over the
forecast period for a long-term coal sales contract with a
customer that uses coal we produce at our Muhlenberg County
mining complex. In exchange for this price increase, we are
negotiating a long-term coal sales contract with this customer
that covers deliveries from 2012 through 2015.
We estimate that the average sales price per ton for uncommitted
tons will be $41.61 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 and other sources of
revenue, will be $7.5 million for the twelve months ending
June 30, 2011, as compared to $7.2 million and
$6.6 million for the year ended December 31, 2009 and
the twelve months ended March 31, 2010, respectively. 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 for the year ended December 31, 2009
and the twelve months ended March 31, 2010.
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we will repay in full the outstanding borrowings of
$96.5 million under our existing credit facility with a
portion of the proceeds from the offering;
we will borrow approximately $86.0 million under our new
credit facility;
for calculating our interest expense, we have assumed a weighted
average interest rate over the forecast period of 7.6% under our
new credit facility, which is higher than the weighted average
interest rate of 6.9% for the year ended December 31, 2009
and 7.2% for the twelve months ended March 31, 2010 under
our existing credit facility; and
we will maintain a low cash balance.
Our estimated reserve replacement expenditures for the forecast
period are $5.7 million for the twelve months ending
June 30, 2011, compared to approximately $3.1 million
and $3.5 million of actual reserve replacement expenditures
for the year ended December 31, 2009 and the twelve months
ended March 31, 2010, respectively. Our estimated
maintenance capital expenditures (other than estimated reserve
replacement expenditures) for the forecast period are
$26.2 million for the twelve months ending June 30,
2011, compared to approximately $25.7 million and
$23.9 million of actual other maintenance capital
expenditures for the year ended December 31, 2009 and the
twelve months ended March 31, 2010, respectively. These
increases are 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.
Our expansion capital expenditures for the forecast period are
approximately $22.1 million as compared to approximately
$33.4 million and $35.6 million of actual capital
expenditures for the year ended December 31, 2009 and the
twelve months ended March 31, 2010, respectively, that we
would have classified as expansion capital expenditures if we
had distinguished between expansion capital expenditures and
other capital expenditures during those periods. Please read
How We Make Cash Distributions Operating
Surplus and Capital Surplus Capital
Expenditures for a further discussion of expansion capital
expenditures. Of the $33.4 million of expansion capital
expenditures for the year ended December 31, 2009,
approximately $28.7 million was attributable to the Phoenix
Coal acquisition and approximately $4.7 million was
attributable to the purchase of other additional coal reserves.
Of the $35.6 million of expansion capital expenditures for
the twelve months ended March 31, 2010, approximately
$28.7 million was attributable to the Phoenix Coal
acquisition and approximately $6.9 million was attributable
to the purchase of other additional coal reserves. The
forecasted expansion capital expenditures for the forecast
period consist of approximately $9.0 million for an
electric shovel and supporting fleet at our Muhlenberg County
complex, $6.1 million for a highwall miner at our Belmont
County complex and $7.0 million for large scale bulldozers
and will be funded with net proceeds from this offering. Please
read How We Make Cash Distributions Operating
Surplus and Capital Surplus Capital
Expenditures for a further discussion of expansion capital
expenditures.
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no material nonperformance or credit-related defaults by
suppliers, customers or vendors, or shortage of skilled labor;
all supplies and commodities necessary for production and
sufficient transportation will be readily available;
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;
no material unforeseen geologic conditions or equipment problems
at our mining locations;
no material accidents, weather-related incidents, unscheduled
downtime or similar unanticipated events;
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
no material changes in market, regulatory or overall economic
conditions.
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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:
provide for the proper conduct of our business (including
reserves for our future capital expenditures and anticipated
future credit needs subsequent to that quarter);
comply with applicable law, any of our debt instruments or other
agreements; and
provide funds for distributions to our unitholders and to our
general partner for any one or more of the next four quarters;
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 resulting from working capital borrowings
made subsequent to the end of such quarter.
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$35.0 million (as described below); plus
an amount equal to the aggregate amount of cash distributed to
our general partner, C&T Coal, AIM Oxford and the
participants in our LTIP that hold our common units in respect
of the right (entitling them to receive cash collected from
accounts receivable outstanding prior to the closing of this
offering) distributed to them immediately prior to the closing
of this offering; plus
all of our cash receipts after the closing of this offering,
excluding cash from interim capital transactions (as defined
below); plus
working capital borrowings made after the end of a quarter but
on or before the date of determination of operating surplus for
that quarter; plus
cash distributions paid on equity issued (including incremental
distributions on incentive distribution rights), other than
equity issued on the closing date of this offering, to finance
all or a portion of expansion capital expenditures in respect of
the period from such financing until the earlier to occur of the
date the capital asset commences commercial service and the date
that it is abandoned or disposed of; plus
cash distributions paid on equity issued by us (including
incremental distributions on incentive distribution rights) to
pay the interest on debt incurred, or to pay distributions on
equity issued, to finance the expansion capital expenditures
referred to above, in each case in respect of the period from
such financing until the earlier to occur of the date the
capital asset commences commercial service and the date that it
is abandoned or disposed of; less
all of our operating expenditures (as defined below) after the
closing of this offering and the completion of the transactions
described in Summary The Transactions;
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; less
64
Table of Contents
all working capital borrowings not repaid within 12 months
after having been incurred, or repaid within such 12-month
period with the proceeds of additional working capital
borrowings; less
any cash loss realized on disposition of an investment capital
expenditure.
repayments of working capital borrowings where such borrowings
have previously been deemed to have been repaid (as described
above);
payments (including prepayments and prepayment penalties) of
principal of and premium on indebtedness other than working
capital borrowings;
expansion capital expenditures;
investment capital expenditures;
payment of transaction expenses (including taxes) relating to
interim capital transactions;
distributions to partners;
actual reserve replacement expenditures;
non-pro rata repurchases of partnership interests made with the
proceeds of an interim capital transaction; or
any other payments made in connection with this offering that
are described under Use of Proceeds.
65
Table of Contents
it will reduce the risk that reserve replacement expenditures in
any one quarter will be large enough to render operating surplus
less than the minimum quarterly distribution to be paid on all
the units for the quarter and subsequent quarters;
it will increase our ability to distribute as operating surplus
cash we receive from non-operating sources;
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
it will reduce the likelihood that a large reserve replacement
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.
66
Table of Contents
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;
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 on a fully diluted basis during those periods; and
there are no arrearages in payment of the minimum quarterly
distribution on the common units.
distributions of available cash from operating surplus on each
of the outstanding common units, subordinated units and general
partner units equaled or exceeded $2.625 (150.0% of the
annualized minimum quarterly distribution) for the immediately
preceding four-quarter period;
the adjusted operating surplus (as defined below) generated
during the immediately preceding four-quarter period equaled or
exceeded the sum of $2.625 (150.0% of the annualized 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
there are no arrearages in payment of the minimum quarterly
distributions on the common units.
67
Table of Contents
the subordination period will end and each subordinated unit
will immediately convert into one common unit;
any existing arrearages in payment of the minimum quarterly
distribution on the common units will be extinguished; and
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.
operating surplus (excluding the first bullet of the definition
and including the second bullet of the definition, but only to
the extent such accounts receivable are collected in cash)
generated with respect to that period; less
any net increase in working capital borrowings with respect to
such period; less
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
any net decrease in working capital borrowings with respect to
such period; plus
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
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.
first
, 98.0% 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;
second
, 98.0% 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;
third
, 98.0% 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
thereafter
, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
68
Table of Contents
first
, 98.0% 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
thereafter
, in the manner described in
General Partner Interest and Incentive
Distribution Rights below.
we have distributed available cash from operating surplus to the
unitholders in an amount equal to the minimum quarterly
distribution; and
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;
first
, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until each unitholder receives a total of
$0.5031 per unit for that quarter (the first target
distribution);
second
, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until each unitholder receives a total of
$0.5469 per unit for that quarter (the second target
distribution);
third
, 75.0% to all unitholders, pro rata, and 25.0% to
our general partner, until each unitholder receives a total of
$0.6563 per unit for that quarter (the third target
distribution); and
thereafter
, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
69
Table of Contents
Marginal Percentage Interest
Total Quarterly Distribution
in Distributions
Per Unit Target Amount
Unitholders
General Partner
$
0.4375
98
%
2
%
above $
0.4375
up to $0.5031
98
%
2
%
above $
0.5031
up to $0.5469
85
%
15
%
above $
0.5469
up to $0.6563
75
%
25
%
above $
0.6563
50
%
50
%
70
Table of Contents
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;
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;
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
thereafter
, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
Marginal Percentage
Interest in Distributions
2.0%
General
Incentive
Quarterly Distribution
Partner
Distribution
Quarterly Distribution Per Unit
Per Unit Prior to Reset
Unitholders
Interest
Rights
Following Hypothetical Reset
$0.4375
98
%
2.0
%
$ 0.70
above $0.4375
up to $0.5031
98
%
2.0
%
up to $0.805
(1)
above $0.5031
up to $0.5469
85
%
2.0
%
13.0
%
above $
0.805
(1
)
up to $0.875
(2)
above $0.5469
up to $0.6563
75
%
2.0
%
23.0
%
above $
0.875
(2
)
up to $ 1.05
(3)
above $0.6563
50
%
2.0
%
48.0
%
above $ 1.05
(3)
(1)
This amount is 115.0% of the hypothetical reset minimum
quarterly distribution.
(2)
This amount is 125.0% of the hypothetical reset minimum
quarterly distribution.
(3)
This amount is 150.0% of the hypothetical reset minimum
quarterly distribution.
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Table of Contents
Cash Distributions to General
Cash
Partner Prior to Reset
Distributions to
2.0%
Quarterly
Common
General
Incentive
Distribution Per
Unitholders
Common
Partner
Distribution
Total
Unit Prior to Reset
Prior to Reset
Units
Interest
Rights
Total
Distributions
$0.4375
$
8,995,332
$
$
183,579
$
$
183,579
$
9,178,911
above $0.4375
up to $0.5031
1,348,786
27,526
27,526
1,376,312
above $0.5031
up to $0.5469
900,561
18,379
137,313
155,692
1,056,253
above $0.5469
up to $0.6563
2,249,347
45,905
685,595
731,500
2,980,847
above $0.6563
898,505
18,337
846,316
864,653
1,763,158
$
14,392,531
$
$
293,726
$
1,669,224
$
1,962,950
$
16,355,481
Cash
Cash Distributions to General
Distributions
Partner After Reset
to
2.0%
Quarterly
Common
General
Incentive
Distribution Per
Unitholders
Common
Partner
Distribution
Total
Unit After Reset
After Reset
Units
Interest
Rights
Total
Distributions
$ 0.70
$
14,392,531
$
1,669,224
$
293,726
$
$
1,962,950
$
16,355,481
above $0.70
up to $0.805
above $0.805
up to $0.875
above $0.875
up to $ 1.05
above $ 1.05
$
14,392,531
$
1,669,224
$
293,726
$
$
1,962,950
$
16,355,481
first
, 98.0% 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
, 98.0% 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
, as if they were from operating surplus.
72
Table of Contents
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.
73
Table of Contents
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;
second
, 98.0% 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:
third
, 98.0% 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:
fourth
, 98.0% to all unitholders, pro rata, and 2.0% to
our general partner, until we allocate under this paragraph an
amount per unit equal to:
fifth
, 85.0% to all unitholders, pro rata, and 15.0% to
our general partner, until we allocate under this paragraph an
amount per unit equal to:
74
Table of Contents
sixth
, 75.0% to all unitholders, pro rata, and 25.0% to
our general partner, until we allocate under this paragraph an
amount per unit equal to:
thereafter
, 50.0% to all unitholders, pro rata, and 50.0%
to our general partner.
first
, 98.0% 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
, 98.0% 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
, 100.0% to our general partner.
75
Table of Contents
FINANCIAL AND OPERATING DATA
76
Table of Contents
Pro Forma Oxford
Oxford Mining Company
Oxford Resource Partners, LP
Resource Partners, LP
(Predecessor)
(Successor)
(Successor)
Period
Period
from
from
Year
Year
January 1,
August 24,
Year
Year
Year
Quarter
Ended
Ended
2007 to
2007 to
Ended
Ended
Ended
Ended
December 31,
December 31,
August 23,
December 31,
December 31,
December 31,
Quarter Ended March 31,
December 31,
March 31,
2005
2006
2007
2007
2008
2009
2009
2010
2009
2010
(unaudited)
(unaudited)
(in thousands, except per ton amounts)
$
141,440
$
96,799
$
61,324
$
193,699
$
254,171
$
67,377
$
76,756
$
312,490
$
76,756
27,771
18,083
10,204
31,839
32,490
8,660
9,530
37,221
9,530
6,643
3,267
1,407
4,951
7,183
2,402
1,774
7,183
1,774
175,854
118,149
72,935
230,489
293,844
78,439
88,060
356,894
88,060
106,657
70,415
40,721
151,421
170,698
40,825
55,186
208,574
53,254
22,159
17,494
9,468
12,925
19,487
8,505
7,859
29,792
7,859
27,771
18,083
10,204
31,839
32,490
8,660
9,530
37,221
9,530
12,396
9,025
4,926
16,660
25,902
5,688
8,777
41,369
11,270
2,097
3,643
2,114
9,577
13,242
3,101
3,535
25,735
3,458
171,080
118,660
67,433
222,422
261,819
66,779
84,887
342,691
85,371
4,774
(511
)
5,502
8,067
32,025
11,660
3,173
14,203
2,689
30
26
55
62
35
11
1
39
1
(3,672
)
(2,386
)
(3,498
)
(7,720
)
(6,484
)
(1,123
)
(1,833
)
(7,906
)
(1,978
)
3,823
3,823
1,132
(2,871
)
2,059
409
29,399
10,548
1,341
10,159
712
(682
)
(537
)
(2,891
)
(5,895
)
(1,165
)
(1,628
)
(5,895
)
(1,628
)
$
1,132
$
(3,553
)
$
1,522
$
(2,482
)
$
23,504
$
9,383
$
(287
)
$
4,264
$
(916
)
$
16,236
$
17,634
$
(8,519
)
$
33,992
$
37,183
$
10,502
$
8,341
(13,547
)
(16,619
)
(98,745
)
(23,942
)
(49,528
)
(7,482
)
(10,280
)
(2,548
)
(234
)
106,724
4,494
532
2,442
(137
)
$
17,170
$
7,832
$
7,961
$
21,533
$
50,799
$
16,292
$
10,001
$
43,888
$
12,010
3,881
1,297
163
2,526
3,057
61
528
3,057
528
9,665
11,305
7,420
25,321
25,657
6,715
4,995
25,657
4,995
n/a
n/a
12,503
13,407
2,523
2,818
n/a
n/a
$
252
$
392
$
1,175
$
635
$
15,179
$
3,366
$
20,641
$
1,290
$
23,316
21,979
16,826
18,396
17,547
21,528
24,403
23,196
29,838
8,838
3,884
3,977
4,824
4,655
5,134
8,801
6,584
10,390
10,390
47,428
48,001
54,510
106,408
112,446
149,461
117,031
147,949
202,118
85,099
80,533
90,893
146,774
171,297
203,363
184,982
212,917
269,812
46,091
43,697
43,165
75,529
83,977
95,711
91,799
98,432
90,915
3,913
2,693
1,634
5,089
5,846
1,396
1,806
7,221
1,806
962
641
305
434
530
192
258
885
258
4,872
3,333
1,938
5,528
6,311
1,559
2,036
8,051
2,036
$
29.03
$
29.04
$
31.64
$
35.04
$
40.27
$
43.23
$
37.71
$
38.81
$
37.71
$
27.26
$
26.15
$
24.92
$
29.75
$
29.20
$
29.25
$
30.56
$
28.89
$
29.49
$
23.03
$
27.29
$
31.08
$
29.81
$
36.79
$
44.32
$
30.51
$
33.67
$
30.51
Table of Contents
(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 ended December 31, 2009.
(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
Oxford Mining Company
Oxford Resource Partners, LP
Resource Partners, LP
(Predecessor)
(Successor)
(Successor)
Period
Period
from
from
January 1,
August 24,
Year Ended
2007 to
2007 to
Year Ended
Year Ended
Year Ended
Quarter Ended
December 31,
August 23,
December 31,
December 31,
December 31,
Quarter Ended March 31,
December 31,
March 31,
2006
2007
2007
2008
2009
2009
2010
2009
2010
(unaudited)
(unaudited)
(in thousands)
$
1,132
$
(3,553
)
$
1,522
$
(2,482
)
$
23,504
$
9,383
$
(287
)
$
4,264
$
(916
)
12,396
9,025
4,926
16,660
25,902
5,688
8,777
41,369
11,270
3,672
2,386
3,498
7,720
6,484
1,123
1,833
7,906
1,978
25
468
472
109
304
472
304
30
26
55
62
35
11
1
39
1
1,955
771
1,705
625
6,261
625
3,823
3,823
$
17,170
$
7,832
$
7,961
$
21,533
$
50,799
$
16,292
$
10,001
$
43,888
$
12,010
(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. Our partnership agreement divides maintenance
capital expenditures into two categories reserve
replacement expenditures and other maintenance capital
expenditures. Examples of reserve replacement expenditures
include cash expenditures for the purchase of fee interests in
coal reserves and cash expenditures for advance royalties with
respect to the acquisition of leasehold interests in coal
reserves. Examples of other maintenance capital expenditures
include capital expenditures associated with the repair,
refurbishment and replacement of equipment. 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 reserve replacement expenditures and which of them
would have been classified as other 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
78
Table of Contents
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 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.
79
Table of Contents
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
80
Table of Contents
our coal production, sales volume and average sales prices,
which drive our coal sales revenue;
our cost of coal sales;
our cost of purchased coal; and
our Adjusted EBITDA, a non-GAAP financial measure.
Oxford Mining
Company
Oxford Resource Partners, LP
(Predecessor)
(Successor)
Period
from
Period from
August 24,
Year
Year
Quarter
Quarter
January 1,
2007 to
Ended
Ended
Ended
Ended
2007 to August 23,
December 31,
December 31,
December 31,
March 31,
March 31,
2007
2007
2008
2009
2009
2010
(tons in thousands)
2,693
1,634
5,089
5,846
1,396
1,806
641
305
434
530
192
258
3,333
1,938
5,528
6,311
1,559
2,036
96.6
%
98.9
%
93.8
%
97.8
%
97.6
%
98.8
%
$
29.04
$
31.64
$
35.04
$
40.27
$
43.23
$
37.71
(1)
Represents the percentage of the tons of coal we sold that were
delivered under long-term coal sales contracts.
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Oxford Mining
Company
Oxford Resource Partners, LP
(Predecessor)
(Successor)
Period from
Period from
January 1,
August 24,
2007 to
2007 to
Year Ended
Year Ended
Quarter Ended
Quarter Ended
August 23,
December 31,
December 31,
December 31,
March 31,
March 31,
2007
2007
2008
2009
2009
2010
(tons in thousands)
$
29.04
$
31.64
$
35.04
$
40.27
$
43.23
$
37.71
$
26.15
$
24.92
$
29.75
$
29.20
$
29.25
$
30.56
2,693
1,634
5,089
5,846
1,396
1,806
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Oxford Mining
Company
Oxford Resource Partners, LP
(Predecessor)
(Successor)
Period from
Period from
January 1,
August 24,
2007 to
2007 to
Year Ended
Year Ended
Quarter Ended
Quarter Ended
August 23,
December 31,
December 31,
December 31,
March 31,
March 31,
2007
2007
2008
2009
2009
2010
(tons in thousands)
$
29.04
$
31.64
$
35.04
$
40.27
$
43.23
$
37.71
$
27.29
$
31.08
$
29.81
$
36.79
$
44.32
$
30.51
641
305
434
530
192
258
83
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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.
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.
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.
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.
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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Oxford Mining
Company
Oxford Resource Partners, LP
(Predecessor)
(Successor)
Period from
Period from
January 1,
August 24,
2007 to
2007 to
Year Ended
Year Ended
Quarter Ended
Quarter Ended
August 23,
December 31,
December 31,
December 31,
March 31,
March 31,
2007
2007
2008
2009
2009
2010
(in thousands)
$
96,799
$
61,324
$
193,699
$
254,171
$
67,377
$
76,756
18,083
10,204
31,839
32,490
8,660
9,530
3,267
1,407
4,951
7,183
2,402
1,774
118,149
72,935
230,489
293,844
78,439
88,060
70,415
40,721
151,421
170,698
40,825
55,186
17,494
9,468
12,925
19,487
8,505
7,859
18,083
10,204
31,839
32,490
8,660
9,530
9,025
4,926
16,660
25,902
5,688
8,777
3,643
2,114
9,577
13,242
3,101
3,535
118,660
67,433
222,422
261,819
66,779
84,887
(511
)
5,502
8,067
32,025
11,660
3,173
26
55
62
35
11
1
(2,386
)
(3,498
)
(7,720
)
(6,484
)
(1,123
)
(1,833
)
3,823
(2,871
)
2,059
409
29,399
10,548
1,341
(682
)
(537
)
(2,891
)
(5,895
)
(1,165
)
(1,628
)
$
(3,553
)
$
1,522
$
(2,482
)
$
23,504
$
9,383
$
(287
)
$
7,832
$
7,961
$
21,533
$
50,799
$
16,292
$
10,001
(1)
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
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liabilities we acquired. We recorded this difference as a gain
of $3.8 million for the year ended December 31, 2009.
(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:
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:
Oxford Mining
Company
Oxford Resource Partners, LP
(Predecessor)
(Successor)
Period from
Period from
January 1,
August 24,
2007 to
2007 to
Year Ended
Year Ended
Quarter Ended
Quarter Ended
August 23,
December 31,
December 31,
December 31,
March 31,
March 31,
2007
2007
2008
2009
2009
2010
(in thousands)
$
(3,553
)
$
1,522
$
(2,482
)
$
23,504
$
9,383
$
(287
)
9,025
4,926
16,660
25,902
5,688
8,777
2,386
3,498
7,720
6,484
1,123
1,833
25
468
472
109
304
26
55
62
35
11
1
1,955
771
1,705
625
3,823
$
7,832
$
7,961
$
21,533
$
50,799
$
16,292
$
10,001
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88
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89
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90
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91
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our working capital;
cash generated from operations;
borrowing capacity under our new credit facility;
issuances of additional partnership units; and
debt offerings.
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Oxford Mining
Company
Oxford Resource Partners, LP
(Predecessor)
(Successor)
January 1,
August 24,
2007 to
2007 to
August 23,
December 31,
Year Ended December 31,
Quarter Ended March 31,
2007
2007
(1)
2008
2009
2009
2010
(in thousands)
$
17,634
$
(8,519
)
$
33,992
$
37,183
$
10,502
$
8,341
$
(16,619
)
$
(98,745
)
$
(23,942
)
$
(49,528
)
$
(7,482
)
$
(10,280
)
$
(234
)
$
106,724
$
4,494
$
532
$
2,442
$
(137
)
(1)
Please read Note 1 to our historical consolidated financial
statements included elsewhere in this prospectus.
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Payments Due by Period
Less than
More than
Total
1 Year
1-3 Years
4-5 Years
5 Years
(in thousands)
$
105,507
$
5,591
$
99,916
$
$
5,435
3,642
1,783
10
18,425
6,289
12,013
123
8,389
8,389
83,627
14,103
29,796
19,864
19,864
$
221,383
$
38,014
$
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.
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25 39 years
7 12 years
5 7 years
3 7 years
7 years
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99
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100
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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.
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 4,800 megawatts in Ohio in the next three
years.
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.
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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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.
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.
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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(tons in millions)
Total
Total
Actual
Estimate
Estimate
Forecast
Growth
Forecast
Growth
2008
2009
2010
2015
2009-2015
2035
2009-2035
1,042
934
961
1,044
11.7
%
1,183
26.7
%
54
44
43
54
19.1
%
51
14.6
%
22
16
22
20
28.2
%
14
(10.3
)%
4
3
3
3
%
3
%
20
n/m
68
n/m
1,122
997
1,029
1,141
14.4
%
1,319
32.2
%
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Total
Electricity
Coal-Fired Electricity
Generation
Generation
GWh
GWh
% of total
135,949
113,824
83.7
%
116,668
108,591
93.1
%
218,377
104,927
48.0
%
193,214
90,949
47.1
%
90,988
84,380
92.7
%
70,774
68,136
96.3
%
825,970
570,807
69.1
%
3,125,137
1,193,679
38.2
%
3,951,107
1,764,486
44.7
%
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106
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107
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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.
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
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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.
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.
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 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.
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.
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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As of December 31, 2009
Production for
Production for
Total
the Year Ended
the Quarter Ended
Proven &
Average
Average
Primary
December 31,
March 31,
Probable
Proven
Probable
Heat
Sulfur
Transportation
Mining Complexes
2009
2010
Reserves
(1)
Reserves
(1)
Reserves
(1)
Value
Content
Methods
(in million tons)
(Btu/lb)
(%)
1.1
0.3
12.4
12.2
0.2
11,520
3.3
Barge, Rail
0.9
0.3
8.8
8.8
0.0
11,570
3.7
Truck
1.3
0.3
6.6
6.3
0.3
11,510
3.7
Barge
0.5
0.1
6.4
6.4
0.0
11,350
4.4
Truck
0.6
0.1
4.9
4.0
0.9
11,260
4.0
Rail
0.7
0.2
2.8
2.8
0.0
12,040
1.8
Barge, Rail, Truck
0.3
0.1
2.5
2.4
0.1
11,230
4.7
Barge, Truck
0.4
(3)
0.4
24.2
23.5
0.7
11,295
3.6
Barge, Truck
5.8
1.8
68.6
66.4
2.2
23.0
18.6
4.4
12,900
2.1
23.0
18.6
4.4
91.6
85.0
6.6
(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 Coal
Reserves.
(2)
The Harrison mining complex is owned by Harrison Resources, our
joint venture with CONSOL Energy. We own 51.0% of Harrison
Resources and CONSOL Energy owns the remaining 49.0% 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 and the
first quarter of 2010 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
100.0% of Harrison Resources. Please read
Mining Operations Northern
Appalachia Harrison Mining Complex.
(3)
Acquired from Phoenix Coal on September 30, 2009. As a
result, production data for 2009 represents production from the
date of acquisition through December 31, 2009.
(4)
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. We received royalty payments on 0.6 million tons
and 0.1 million tons of coal produced from the Tusky mining
complex during 2009 and the first quarter of 2010, respectively.
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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.
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
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currently use in Ohio at the mines that we recently acquired as
part of the Phoenix Coal acquisition. We currently have 17
active surface mines that are managed as eight mining complexes,
with our largest mine comprising 12.6% of our coal production
during the first quarter of 2010. 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.
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.
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. Please read Cash
Distribution Policy and Restrictions on
Distributions General Our Ability to
Grow is Dependent on Our Ability to Access External Expansion
Capital for additional details on how we intend to grow
our reserve base and production capacity and the limitations we
face in implementing this strategy.
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 97.6%, 101.5%, 71.3% and
40.9%, respectively, of our 2010 estimated coal sales of
8.2 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.
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
23.3 million tons of coal and acquired 52.6 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 first quarter of 2010 on an annualized
basis was 7.2 million tons, an increase of 24% over our
actual 2009 production.
Our mining operations are flexible and
diverse
. During the first quarter of 2010, our
largest mine represented 12.6% of our coal production. We
currently have 17 active surface mines that are managed
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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.
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 believe 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, the expertise of our general partners
employees and their 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.
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%, respectively, through 2015. 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.
Our general partners senior management team and key
operational employees have extensive industry
experience
. The members of our general
partners 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 general partners
key operational employees have extensive mining experience and
have been with us for an average of 23 years. We believe
our general partners 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.
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 Barb Tipple blending and coal crushing facility that is
adjacent to one of our customers power plants near
Coshocton, Ohio;
our Strasburg wash plant near Strasburg, Ohio;
our Bellaire river terminal on the Ohio River;
our Island river terminal on the Green River in western Kentucky;
our Stonecreek coal crushing facility located in Tuscarawas
County, Ohio; and
our Schoate wash plant located in Muhlenberg County, Kentucky.
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Tons Produced for the
Number
Year Ended
Transportation Facilities Utilized
Transportation
of Active
December 31,
Quarter Ended
River Terminal
Rail Loadout
Method
(1)
Mines
2007
2008
2009
March 31, 2010
(in millions)
Bellaire
Cadiz
Barge, Rail
2
1.1
1.4
1.1
0.3
Truck
4
1.1
1.0
0.9
0.3
Bellaire
Barge
3
0.8
0.9
1.3
0.3
Truck
1
0.3
0.5
0.5
0.1
New Lexington
Rail
1
0.6
0.7
0.6
0.1
Bellaire
Cadiz
Barge, Rail, Truck
1
0.2
0.4
0.7
0.2
Bellaire
Barge, Truck
2
0.2
0.2
0.3
0.1
14
4.3
5.1
5.4
1.4
(1)
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.
(2)
The Harrison mining complex is owned by Harrison Resources, our
joint venture with CONSOL Energy. We own 51.0% of Harrison
Resources and CONSOL Energy owns the remaining 49.0% 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 and the
first quarter of 2010 as required by GAAP, coal production
attributable to the Harrison mining complex is presented on a
gross basis assuming we owned 100.0% of Harrison Resources.
Please read Harrison Mining Complex.
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Transportation
Tons Produced for
Facilities Utilized
the Year Ended
Tons Produced for
River
Rail
Transportation
Number of
December 31,
the Quarter Ended
Terminal
Loadout
Method
(1)
Active Mines
2009
(2)
March 31, 2010
Island
Barge, Truck
3
0.4
0.4
(1)
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.
(2)
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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Proven (Measured) Reserves.
Reserves for
which (a) quantity is computed from dimensions revealed in
outcrops, trenches, workings or drill holes; and grade
and/or
quality are computed from the results of detailed sampling and
(b) the sites for inspection, sampling and measurement are
spaced so closely and the geologic character is so well defined
that size, shape, depth and mineral content of reserves are
well-established.
Probable (Indicated) Reserves.
Reserves for
which quantity and grade
and/or
quality are computed from information similar to that used for
proven (measured) reserves, but the sites for inspection,
sampling, and measurement are farther apart or are otherwise
less adequately spaced. The degree of assurance, although lower
than that for proven (measured) reserves, is high enough to
assume continuity between points of observation.
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Total Tons of Proven and
Probable Coal
Reserves
(1)
Total
Owned
Leased
(in million tons)
12.4
7.5
4.9
8.8
0.1
8.7
6.6
1.9
4.7
6.4
0.7
5.7
4.9
2.8
2.1
2.8
2.8
2.5
0.1
2.4
44.4
15.9
28.5
24.2
24.2
24.2
24.2
68.6
15.9
52.7
23.0
23.0
23.0
23.0
91.6
15.9
75.7
100
%
17.4
%
82.6
%
(1)
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.
(2)
The Harrison mining complex is owned by Harrison Resources. We
own 51.0% of Harrison Resources and CONSOL Energy owns the
remaining 49.0% 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 and the first quarter of 2010 as required
by GAAP, proven and probable coal reserves attributable to the
Harrison mining complex are presented on a gross basis assuming
we owned 100.0% of Harrison Resources. Please read
Mining Operations Northern
Appalachia Harrison Mining Complex.
(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. We received royalty payments on
0.6 million tons and 0.1 million tons of coal produced
from the Tusky mining complex during 2009 and the first quarter
of 2010, respectively.
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As received
Basis
(1)
# of
Proven and Probable Coal Reserves
SO2/mm
Sulfur
Content
(1)
% Ash
% Sulfur
Btu/lb.
Btu
Total
<2%
2-4%
>4%
(in million tons)
11.6
3.3
11,520
5.7
12.4
1.1
6.1
5.2
10.5
3.7
11,570
6.3
8.8
1.6
3.5
3.7
12.6
3.7
11,510
6.4
6.6
4.6
2.0
10.7
4.4
11,350
7.7
6.4
0.7
5.7
11.1
4.0
11,260
7.1
4.9
2.0
2.9
11.9
1.8
12,040
3.0
2.8
2.1
0.7
13.2
4.7
11,230
8.4
2.5
0.3
2.2
11.2
3.6
11,295
6.4
24.2
23.0
1.2
5.4
2.1
12,900
3.3
23.0
3.8
19.2
(1)
As received represents an analysis of a sample as received at a
laboratory operated by a third party.
(2)
The Harrison mining complex is owned by Harrison Resources. We
own 51.0% of Harrison Resources and CONSOL Energy Inc owns the
remaining 49.0% 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 and the first quarter of 2010 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 100.0%
of Harrison Resources. Please read Mining
Operations Northern Appalachia Harrison
Mining Complex.
(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. We received royalty payments on
0.6 million tons and 0.1 million tons of coal produced
from the Tusky mining complex during 2009 and the first quarter
of 2010, respectively.
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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;
service fees we earn for providing earth-moving services for
Tunnel Hill Partners, LP, an entity owned by our sponsors that
owns a landfill; and
service fees we earn for hauling and disposing of ash at a third
party landfill for two municipal utilities.
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Acid Rain.
Title IV of the Clean Air Act
was added through the CAAA and requires reductions of sulfur
dioxide emissions by electric utilities regulated under the Acid
Rain Program, or ARP. The ARP was designed to reduce the
electric power sector emissions of sulfur dioxide and nitrous
oxides. Sulfur dioxide emissions were controlled through the
development of a national market-based
cap-and-trade
system. Under the ARP, a cap is established and then EPA issues
allowances to regulated entities up to the cap using defined
formulas. A small percentage of the allowances are
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retained for auctions. Each power plant must have enough
allowances to cover all its annual SO2 emissions or pay
penalties. The electric power plant can choose to reduce
emissions and sell or bank the surplus allowances or purchase
allowances. Though the CAAA created flexibility by allowing
power plants to choose to emit or control emissions, emission
reductions are encouraged by requiring an allowance to be
retired every year for each ton of SO2 emitted. 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.
SO2.
On June 3, 2010, the EPA issued a
stricter NAAQS for SO2 emissions which establishes a new
1-hour
standard at a level of 75 parts per billion or ppb to protect
against short-term exposure and minimize health-based risks. EPA
indicated that it would abolish the previous annual standard for
SO2. Under the new rule, monitors must be set up by 2013 in the
areas of the highest concentrations of SO2. The rule also
provides for modeling to determine compliance. States with areas
that do not meet the standard will have to submit plans no later
than August 2017 showing how they will come into compliance. As
a result, coal-fired power plants, which are the largest end
users of our coal, may be required to install additional
emissions control equipment or take other steps to lower SO2
emissions.
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 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.
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.
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, including the six states in our
primary market area, 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.
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
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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.
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, EPA is under a court deadline to issue a final rule by
November 2011, and has stated 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. 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. In addition, on April 30, 2010, EPA proposed
new MACT for several classes of boilers and process heaters,
including large coal-fired boilers and process heaters, which
would require significant reductions in the emission of
particulate matter, carbon monoxide, hydrogen chloride, dioxins
and mercury. The Obama Administration has also indicated a
desire to negotiate 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.
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.
New Source Review, 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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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.
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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74
Chairman of the Board
60
Director, President and Chief Executive Officer
44
Senior Vice President, Chief Financial Officer and Treasurer
53
Senior Vice President, Operations
59
Senior Vice President, Equipment, Procurement and Maintenance
55
Secretary and General Counsel
35
Senior Director of Accounting
40
Director
44
Director
61
Director
48
Director
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Charles C. Ungurean, President and Chief Executive Officer;
Jeffrey M. Gutman, Senior Vice President, Chief Financial
Officer and Treasurer;
Thomas T. Ungurean, Senior Vice President, Equipment,
Procurement and Maintenance;
Gregory J. Honish, Senior Vice President, Operations; and
Michael B. Gardner, Secretary and General Counsel.
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to create unitholder value through sustainable earnings and cash
available for distribution;
to provide a significant percentage of total compensation that
is at-risk or variable;
to encourage significant equity holdings to align the interests
of executive officers and other key employees with those of
unitholders;
to provide competitive, performance-based compensation programs
that allow us to attract and retain superior talent; and
to develop a strong linkage between business performance,
safety, environmental stewardship, cooperation and executive
compensation.
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Characteristics
Purpose
Fixed annual cash compensation. Our 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.
Keep our annual compensation competitive with the defined market
for skills and experience necessary to execute our business
strategy.
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.
Align annual compensation with our financial performance and
reward our executive officers for individual performance during
the year and for contributing to our financial success. Amounts
provided as incentive bonuses are also designed to provide
competitive total direct compensation; potential for awards
above or below target amounts are intended to motivate our
executive officers to achieve greater levels of performance.
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Characteristics
Purpose
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.
Align interests of our executive officers with unitholders and
motivate and reward our executive officers to increase
unitholder value over the long term. Ratable vesting over a
four-year period is designed to facilitate retention of our
executive officers.
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 401(k) plan in which all eligible
employees can elect to contribute compensation for retirement up
to IRS imposed limits, either on a tax deferred or after-tax
basis. 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.
Provide our executive officers and other employees with the
opportunity to save for their future retirement.
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.
Provide benefits to meet the health and wellness needs of our
executive officers and other employees and their families.
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Base Salary
Base Salary at
Increase
2009 Base Salary
Start of 2009
in 2009
Following Increase
$
300,000
$
75,000
$
375,000
250,000
10,000
260,000
200,000
25,000
225,000
110,000
40,000
150,000
133,000
12,000
145,000
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a subjective performance evaluation based on company-wide
financial and individual qualitative performance, as determined
in the Boards discretion; and
the scope, level of expertise and experience required for the
executive officers position.
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2009
Bonus
(1)
$
225,000
112,500
175,000
63,750
61,625
(1)
Amounts shown in this column do not include vacation pay amounts
included in bonus amounts in the Summary Compensation Table for
2009 below.
financial performance for the prior fiscal year, including the
level of achievement of our budgeted cash distribution target
for the year as discussed above;
distribution performance for the prior fiscal year compared to
the peer group;
unitholder total return for the prior fiscal year compared to
the peer group; and
competitive compensation data for executive officers in the peer
group.
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Target Annual
Bonus
Annual
as a % of
Base Salary
Annual Salary
$
500,000
66.6
%
270,000
50.0
%
275,000
66.6
%
185,000
50.0
%
165,000
50.0
%
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All Other
Compensation
Salary
($)
(1)
Bonus
($)
(2)
($)
(3)
Total ($)
President and Chief Executive Officer
$
375,002
$
248,077
$
18,888
$
641,967
Senior Vice President, Chief Financial Officer and Treasurer
261,385
125,481
15,370
402,236
Senior Vice President, Equipment, Procurement and Maintenance
233,333
190,385
16,572
440,290
Senior Vice President, Operations
142,116
70,096
12,771
224,983
Secretary and General Counsel
152,083
75,567
13,560
241,210
(1)
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 $3,434 and $1,152, respectively.
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Unit Awards
Number of
Market Value of
Phantom Units
Phantom Units
That Have Not
That Have Not
Vested
(1)(2)
Vested
($)
(3)
Senior Vice President, Chief Financial Officer and Treasurer
14,848
$
258,801
Senior Vice President, Operations
5,128
$
89,381
Secretary and General Counsel
3,204
$
55,846
(1)
Represents the number of units that were awarded prior to the
unit split described under Summary The
Transactions.
(2)
On March 31, 2010, 7,425 of Mr. Gutmans units
vested and the remaining unvested units will vest 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.
(3)
Based on the fair market value of our common units of $17.43 on
December 31, 2009.
Number of
Value
Units Acquired
Realized on
on
Vesting (#)
(3)
Vesting ($)
Senior Vice President, Chief Financial Officer and
Treasurer
(1)
7,425
$
83,160
Senior Vice President,
Operations
(2)
2,564
$
44,691
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 $17.43 per unit, the fair market
value on such vesting date.
(3)
Represents the number of units that were awarded prior to the
unit split described under Summary The
Transactions.
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Death or
Termination
Resignation for
Disability
Without Cause
Good Reason
Payment Type
($)
($)
($)
Cash severance
$
1,000,000
$
1,000,000
Benefit continuation
$
10,769
10,769
Total
10,769
1,010,769
1,000,000
Cash severance
550,000
550,000
Benefit continuation
9,212
9,212
Total
9,212
559,212
550,000
Cash severance
270,000
270,000
Cash severance
185,000
185,000
Cash severance
165,000
165,000
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a $50,000 cash retainer;
a $50,000 annual unit grant; and
where applicable, a committee chair retainer of $10,000 for each
committee chaired.
$1,000 for Board meetings attended in person;
where applicable, $500 for Board committee meetings attended in
person; and
$500 for telephonic Board meetings and committee meetings
greater than one hour in length.
Fees Earned or
Paid in Cash ($)
Unit Awards
($)
(1)
Total ($)
$
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 market value of
$17.43 per unit on such date.
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each person who is known to us to beneficially own 5% or more of
such units to be outstanding;
our general partner;
each of the directors and named executive officers of our
general partner; and
all of the directors and executive officers of our general
partner as a group.
Percentage of
Percentage of
Total Common
Percentage of
Subordinated
Subordinated
and Subordinated
Common Units
Common Units
Units to be
Units to be
Units to be
to be Beneficially
to be Beneficially
Beneficially
Beneficially
Beneficially
Owned
Owned
Owned
Owned
Owned
930,349
9.0
%
6,813,160
66.3
%
37.7
%
473,454
4.6
%
3,467,220
33.7
%
19.2
%
930,349
9.0
%
6,813,160
66.3
%
37.7
%
%
%
%
930,349
9.0
%
6,813,160
66.3
%
37.7
%
2,090
*
%
%
*
%
2,500
*
%
%
*
%
473,454
4.6
%
3,467,220
33.7
%
19.2
%
473,454
4.6
%
3,467,220
33.7
%
19.2
%
31,769
*
%
%
*
%
9,338
*
%
%
*
%
5,510
*
%
%
*
%
6,290
*
%
%
*
%
1,461,300
14.2
%
10,280,380
100.0
%
57.1
%
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*
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 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 41 South High Street,
Suite 3450, Columbus, Ohio 43215.
(4)
Each of Messrs. McCown and Carbone disclaim beneficial
ownership of the units, except to the extent of any pecuniary
interest therein.
(5)
Represents an estimate of the number of common units that will
be granted to Peter B. Lilly on the date that is 30 days
after the closing of this offering if he is a member of the
Board on that date. The actual number of units to be granted to
Mr. Lilly assuming he is a member of the Board on that date
will equal 50,000 divided by the actual offering price of a
common unit in this offering.
(6)
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. Each of Messrs. Charles C. Ungurean and Thomas
T. Ungurean disclaim beneficial ownership of the units, except
to the extent of any pecuniary interest therein.
(7)
Does not include 33,981 common units that could be issuable upon
the vesting of phantom units, which phantom units will not vest
within 60 days of June 16, 2010.
(8)
Does not include 9,338 common units that could be issuable upon
the vesting of phantom units, which phantom units will not vest
within 60 days of June 16, 2010.
(9)
Does not include 5,834 common units that could be issuable upon
the vesting of phantom units, which phantom units will not vest
within 60 days of June 16, 2010.
(10)
Does not include 10,614 common units that could be issuable upon
the vesting of phantom units, which phantom units will not vest
within 60 days of June 16, 2010.
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Pre-IPO Stage
The consideration received by our general partner and its
affiliates prior to or in connection with this offering
Post-IPO Stage
Distributions of available cash to our general partner and its
affiliates
We will initially make cash distributions 98.0% to the
unitholders, including affiliates of our general partner, as the
holders of an aggregate of 1,403,803 common units and all of the
subordinated units and 2.0% to our general partner. 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 48.0% of
the distributions above the highest target distribution level.
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
$0.7 million on the 2.0% general partner interest and
approximately $20.5 million on their common units and
subordinated units.
Payments to our general partner and its affiliates
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
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.
Liquidation Stage
Liquidation
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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approved by the Conflicts Committee, although our general
partner is not obligated to seek such approval;
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;
on terms no less favorable to us than those generally being
provided to or available from unrelated third parties; or
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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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 honest belief that the decision was in our best
interest;
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
provides that our general partner and its executive officers and
directors will not be liable for monetary damages to us or our
limited partners resulting from any act or omission unless there
has been a final and non-appealable judgment entered by a court
of competent jurisdiction determining that our general partner
or its 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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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;
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;
the mortgage, pledge, encumbrance, hypothecation or exchange of
any or all of our assets;
the negotiation, execution and performance of any contracts,
conveyances or other instruments;
the distribution of our cash;
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;
the maintenance of insurance for our benefit and the benefit of
our partners;
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;
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;
the indemnification of any person against liabilities and
contingencies to the extent permitted by law;
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
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.
the amount and timing of asset purchases and sales;
cash expenditures and the amount of estimated reserve
replacement expenditures;
borrowings;
the issuance of additional units; and
the creation, reduction or increase of reserves in any quarter.
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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
hastening the expiration of the subordination period.
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State law fiduciary duty standards
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.
Partnership agreement modified standards
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:
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.
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 or our
limited partners 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.
Rights and remedies of unitholders
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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surety bond premiums to replace lost or stolen certificates, or
to cover taxes and other governmental charges in connection
therewith;
special charges for services requested by a holder of a common
unit; and
other similar fees or charges.
automatically agrees to be bound by the terms and conditions of,
and is deemed to have executed, our partnership agreement;
represents that such transferee has the capacity, power and
authority to enter into 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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with regard to certain actions taken prior to, or in connection
with, the closing of this offering, please read
Summary The Transactions;
with regard to distributions of available cash, please read
How We Make Cash Distributions;
with regard to the fiduciary duties of our general partner,
please read Conflicts of Interest and Fiduciary
Duties;
with regard to the transfer of common units, please read
Description of the Common Units Transfer of
Common Units; and
with regard to allocations of taxable income and taxable loss,
please read Material Federal Income Tax Consequences.
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
after the subordination period, the approval of a majority of
the outstanding common units.
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Issuance of additional units
No approval rights.
Amendment of our partnership agreement
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.
Merger of our partnership or the sale of all or substantially
all of our assets
Unit majority in certain circumstances. Please read
Merger, Sale or Other Disposition of
Assets.
Continuation of our partnership upon dissolution
Unit majority. Please read Termination and
Dissolution.
Withdrawal of our general partner
No approval rights. Please read Withdrawal or
Removal of Our General Partner.
Removal of our general partner
Not less than 80.0% 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.
Transfer of our general partner interest
After June 30, 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.
Transfer of incentive distribution rights
No approval rights. Please read Transfer of
Incentive Distribution Rights.
Transfer of ownership interests in our general partner
No approval required at any time. Please read
Transfer of Ownership Interests in Our General
Partner.
to remove or replace our general partner;
to approve some amendments to our partnership agreement; or
to take other action under our partnership agreement;
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the action would not result in the loss of limited liability of
any limited partner; and
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).
the subordination period will end and all outstanding
subordinated units will immediately convert into common units on
a
one-for-one
basis;
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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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
the current market price as of the date three days before the
date the notice is mailed.
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a current list of the name and last known address of each
partner;
a copy of our tax returns;
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;
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;
information regarding the status of our business and financial
condition; and
any other information regarding our affairs as is just and
reasonable.
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1% of the total number of the securities outstanding; or
the average weekly reported trading volume of the common units
for the four weeks prior to the sale.
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We will be classified as a partnership for federal income tax
purposes; and
Each of our operating subsidiaries will be disregarded as an
entity separate from us or will be treated as a partnership for
federal income tax purposes.
Neither we nor the operating subsidiaries has elected or will
elect to be treated as a corporation; and
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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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
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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interest on indebtedness properly allocable to property held for
investment;
our interest expense attributed to portfolio income; and
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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his relative contributions to us;
the interests of all the partners in profits and losses;
the interest of all the partners in cash flow; and
the rights of all the partners to distributions of capital upon
liquidation.
any of our income, gain, loss or deduction with respect to those
units would not be reportable by the unitholder;
any cash distributions received by the unitholder as to those
units would be fully taxable; and
all of these distributions would appear to be ordinary income.
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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);
for use in a trade or business within the meaning of
Section 1231 of the Internal Revenue Code; or
as a capital asset within the meaning of Section 1221 of
the Internal Revenue Code.
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a short sale;
an offsetting notional principal contract; or
a futures or forward contract with respect to the partnership
interest or substantially identical property.
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the name, address and taxpayer identification number of the
beneficial owner and the nominee;
whether the beneficial owner is:
a person that is not a U.S. person;
a foreign government, an international organization or any
wholly owned agency or instrumentality of either of the
foregoing; or
a tax-exempt entity;
the amount and description of units held, acquired or
transferred for the beneficial owner; and
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.
for which there is, or was, substantial authority; or
as to which there is a reasonable basis and the pertinent facts
of that position are disclosed on the return.
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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;
for those persons otherwise entitled to deduct interest on
federal tax deficiencies, nondeductibility of interest on any
resulting tax liability; and
in the case of a listed transaction, an extended statute of
limitations.
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whether the investment is prudent under
Section 404(a)(1)(B) of ERISA and any other applicable
Similar Laws;
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;
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
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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Number of
Common Units
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;
the representations and warranties made by us to the
underwriters are true;
there is no material change in our business or the financial
markets; and
we deliver customary closing documents to the underwriters.
No Exercise
Full Exercise
$
$
$
$
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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
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. and Citigroup Global Markets Inc.
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the history and prospects for the industry in which we compete;
our financial information;
the ability of our management and our business potential and
earning prospects;
the prevailing securities markets at the time of this offering;
and
the recent market prices of, and the demand for, publicly traded
common units of generally comparable companies.
Stabilizing transactions permit bids to purchase the underlying
security so long as the stabilizing bids do not exceed a
specified maximum.
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
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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.
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.
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.
214
Table of Contents
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;
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;
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
in any other circumstances that do not require the publication
of a prospectus pursuant to Article 3 of the Prospectus
Directive;
215
Table of Contents
216
Table of Contents
217
Table of Contents
218
Table of Contents
219
Table of Contents
F-2
F-5
F-6
F-7
F-8
F-11
F-12
F-13
F-14
F-15
F-26
F-27
F-28
F-29
F-30
F-31
F-56
F-57
F-58
F-59
F-60
F-61
F-1
Table of Contents
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
our distribution of the right to receive cash collected from an
aggregate of $21.0 million of our 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) that hold our common units
pro rata;
the split of the general partner units held by our general
partner with our general partner receiving 1.82 general partner
units for each general partner unit it currently owns, resulting
in its ownership of 244,607 general partner units representing a
2.0% general partner interest in us;
the split of the common units held by participants in our LTIP
with those participants receiving 1.82 common units for each
common unit they currently own, resulting in their ownership of
126,577 common units representing an aggregate 1.0% limited
partner interest in us;
F-2
Table of Contents
the split of the Class B common units held by C&T Coal
with C&T Coal receiving 1.82 Class B common units for
each Class B common unit it currently owns, resulting in
its ownership of 3,999,696 Class B common units
representing an aggregate 32.7% limited partner interest
in us;
the split of the Class B common units held by AIM Oxford
with AIM Oxford receiving 1.82 Class B common units for
each Class B common unit it currently owns, resulting in
its ownership of 7,859,487 Class B common units
representing an aggregate 64.3% limited partner interest
in us;
the conversion of all of our Class B common units held by
C&T Coal into: (i) 532,476 common units and
(ii) 3,467,220 subordinated units;
the conversion of all of our Class B common units held by
AIM Oxford into: (i) 1,046,327 common units and
(ii) 6,813,160 subordinated units;
the capital contribution of 59,022 common units and 115,978
common units by C&T Coal and AIM Oxford, respectively, to
our general partner;
the contribution to us by our general partner of the common
units contributed to it by C&T Coal and AIM Oxford in
exchange for 175,000 general partner units in order to maintain
its 2.0% general partner interest in us;
our entry into a new credit facility;
the issuance by us to the public of 8,750,000 common units;
the use of the net proceeds from the Offering to:
repay in full the outstanding balance under our existing credit
facility;
distribute approximately $22.3 million to C&T Coal in
respect of its limited partner interest in us;
distribute approximately $0.7 million to the participants
in the LTIP that hold our common units in respect of their
limited partner interests in us;
terminate our advisory services agreement with affiliates of AIM
for a payment of approximately $2.5 million;
pay offering expenses of approximately $3.2 million;
fund capital expenditures of approximately $22.1 million to
purchase equipment to be used in our mining operations; and
replenish approximately $18.5 million of our working
capital; and
the use of the net proceeds from borrowings under our new credit
facility of approximately $86.0 to distribute approximately
$43.8 million to AIM Oxford in respect of its limited
partner interest in us, pay fees and expenses associated with
our new credit facility of approximately $5.3 million,
distribute approximately $1.3 million to our general
partner in respect of its general partner interest, replenish
approximately $3.5 million of our working capital that we
distributed to our partners immediately prior to the closing of
this offering and buyout certain operating leases for
$32.1 million.
F-3
Table of Contents
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);
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
various adjustments to apply our accounting policies to the
Phoenix Coal financial statements during the Stub Period.
F-4
Table of Contents
Unaudited Pro Forma Consolidated Balance Sheet
March 31, 2010
Adjustments for
Offering
Oxford Resource
Transactions
Pro Forma
Partners, LP
(Note 1)
As Adjusted
(in thousands)
$
1,290
$
86,000
(a)
$
23,316
(5,313
)
(a)
(93,517
)
(a)
175,000
(b)
(15,375
)
(b)
(68,100
)
(b)
(32,069
)
(d)
(22,100
)
(e)
(2,500
)
(f)
29,838
(21,000
)
(b)
8,838
10,390
10,390
1,839
1,839
4,797
1,518
(a)
4,172
(2,143
)
(h)
48,154
401
48,555
147,949
32,069
(d)
202,118
22,100
(e)
6,832
6,832
9,982
3,795
(a)
12,307
(1,470
)
(g)
$
212,917
$
56,895
$
269,812
LIABILITIES
4,115
(846
)
(a)
7,019
3,750
(a)
33,216
33,216
6,623
6,623
1,526
1,526
1,617
1,617
4,391
4,391
51,488
2,904
54,392
94,317
(92,671
)
(a)
83,896
82,250
(a)
7,013
7,013
4,236
4,236
$
157,054
$
(7,517
)
$
149,537
PARTNERS CAPITAL
51,120
(1,440
)
(g)
152,296
(2,450
)
(f)
(20,580
)
(b)
(23,197
)
(c)
(5,258
)
(b)
(2,676
)
(b)
(705
)
(b)
175,000
(b)
(15,375
)
(b)
(2,143
)
(h)
23,197
(c)
(34,902
)
(38,504
)
(b)
(19,595
)
(b)
1,048
(30
)
(g)
(814
)
(50
)
(f)
(420
)
(b)
(1,362
)
(b)
52,168
64,412
116,580
3,695
3,695
55,863
64,412
120,275
$
212,917
$
56,895
$
269,812
F-5
Table of Contents
Unaudited Pro Forma Consolidated Statement of
Operations
Year Ended December 31, 2009
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)
$
254,171
$
58,494
$
4,556
(i)
$
312,490
$
$
312,490
(4,731
)
(j)
32,490
4,731
(j)
37,221
37,221
7,183
7,183
7,183
293,844
58,494
4,556
356,894
356,894
170,698
54,531
1,464
(k)
214,662
(6,088
)
(p)
208,574
(15,031
)
(j)
3,000
(l)
19,487
10,305
(j)
29,792
29,792
32,490
4,731
(j)
37,221
37,221
25,902
5,800
(278
)
(m)
31,424
9,945
(q)
41,369
13,242
6,948
5,852
(i)
26,042
(307
)
(r)
25,735
5,852
(5,852
)
(j)
3,000
(3,000
)
(l)
261,819
76,131
1,191
339,141
3,550
342,691
32,025
(17,637
)
3,365
17,753
(3,550
)
14,203
35
4
39
39
(6,484
)
(2,601
)
(156
)
(n)
(9,241
)
1,335
(s)
(7,906
)
(5
)
5
(j)
3,823
3,823
3,823
(16
)
16
(o)
29,399
(20,255
)
3,230
12,374
(2,215
)
10,159
(5,895
)
(5,895
)
(5,895
)
$
23,504
$
(20,255
)
$
3,230
$
6,479
$
(2,215
)
$
4,264
F-6
Table of Contents
Unaudited Pro Forma Consolidated Statement of
Operations
for the Three Months Ended March 31, 2010
Adjustments for
Oxford Resource
Pro Forma
Offering
Pro Forma as
Partners, LP
Adjustments
Pro Forma
Transactions
Adjusted
(in thousands)
$
76,756
$
76,756
$
76,756
9,530
9,530
9,530
1,774
1,774
1,774
88,060
88,060
88,060
55,186
55,186
(1,932
)
(t)
53,254
7,859
7,859
7,859
9,530
9,530
9,530
8,777
8,777
2,493
(u)
11,270
3,535
3,535
(77
)
(v)
3,458
84,887
84,887
484
85,371
3,173
3,173
(484
)
2,689
1
1
1
(1,833
)
(1,833
)
(145
)
(w)
(1,978
)
1,341
1,341
(629
)
712
(1,628
)
(1,628
)
(1,628
)
$
(287
)
$
$
(287
)
$
(629
)
$
(916
)
F-7
Table of Contents
NOTE 1.
PRO FORMA
CONSOLIDATED BALANCE SHEET ADJUSTMENTS
the repayment of a total of $93.5 million in debt
outstanding under our existing credit facility;
total borrowings of $86.0 million under our new credit
facility; and
total fees relating to our new credit facility of
$5.3 million, which amount will be capitalized.
the distribution of the right to receive cash collected from an
aggregate of $21.0 million of our accounts receivable to
our General Partner, C&T Coal, AIM Oxford and the
participants in our LTIP, pro rata;
gross proceeds of $175 million from the issuance and sale
of 8,750,000 common units at an assumed initial offering price
of $20.00 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 $15.4 million at time of closing.
a total cash distribution of $68.1 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
$22.0 million.
NOTE 2.
PRO FORMA
CONSOLIDATED STATEMENT OF OPERATIONS ADJUSTMENTS
F-8
Table of Contents
NOTE 2.
PRO FORMA
CONSOLIDATED STATEMENT OF OPERATIONS
ADJUSTMENTS (Continued)
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.
F-9
Table of Contents
NOTE 2.
PRO FORMA
CONSOLIDATED STATEMENT OF OPERATIONS
ADJUSTMENTS (Continued)
F-10
Table of Contents
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
March 31, 2010 and December 31, 2009
(in thousands, except for unit information)
F-11
Table of Contents
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
OPERATIONS
For the Three Months Ended March 31, 2010 and 2009
(in thousands, except for unit information)
Three Months Ended March 31,
2010
2009
$
76,756
$
67,377
9,530
8,660
1,774
2,402
88,060
78,439
55,186
40,825
7,859
8,505
9,530
8,660
8,777
5,688
3,535
3,101
84,887
66,779
3,173
11,660
1
11
(1,833
)
(1,123
)
1,341
10,548
(1,628
)
(1,165
)
$
(287
)
$
9,383
$
(6
)
$
187
$
(281
)
$
9,196
$
(0.04
)
$
1.56
$
(0.04
)
$
1.56
6,575,259
5,889,539
6,575,259
5,900,217
$
0.42
$
0.42
F-12
Table of Contents
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF
PARTNERS CAPITAL
For the Three Months Ended March 31, 2010 and 2009
(in thousands, except for unit information)
Limited
Limited
General
General
Partner
Partners
Partner
Partners
Noncontrolling
Total Partners
Units
Capital
Units
Capital
Interest
Capital
5,889,484
$
32,371
119,643
$
653
$
2,297
$
35,321
9,196
187
1,165
10,548
(2,473
)
(50
)
(1,470
)
(3,993
)
109
109
4,978
5,894,462
$
39,203
119,643
$
790
$
1,992
$
41,985
6,570,396
$
53,960
132,909
$
1,085
$
2,067
$
57,112
(281
)
(6
)
1,628
1,341
1,418
25
25
(2,762
)
(56
)
(2,818
)
304
304
11,643
(101
)
$
(101
)
6,582,039
$
51,120
134,327
$
1,048
$
3,695
$
55,863
F-13
Table of Contents
Three Months Ended March 31,
2010
2009
$
(287
)
$
9,383
8,777
5,688
33
(466
)
168
110
304
109
600
263
175
216
1,628
1,165
(5,435
)
(1,668
)
(1,589
)
(1,450
)
(3,068
)
(604
)
9,457
191
293
531
(2,715
)
(2,966
)
8,341
10,502
(2,116
)
(20
)
(775
)
(179
)
(144
)
(149
)
(4,995
)
(6,715
)
1,248
21
(3,498
)
(440
)
(10,280
)
(7,482
)
6,650
(344
)
(215
)
25
3,000
(1,470
)
(2,818
)
(2,523
)
(137
)
2,442
(2,076
)
5,462
3,366
15,179
$
1,290
$
20,641
F-14
Table of Contents
NOTE 1:
ORGANIZATION
AND PRESENTATION
We, us, our, 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.
F-15
Table of Contents
NOTE 1:
ORGANIZATION
AND PRESENTATION (Continued)
NOTE 2:
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
F-16
Table of Contents
NOTE 3:
ACQUISITION
For the Quarter Ended
March 31, 2009
(Unaudited)
$
97,910,000
1,991,000
F-17
Table of Contents
NOTE 4:
INVENTORY
March 31, 2010
December 31, 2009
$
5,874,000
$
4,759,000
1,513,000
1,264,000
3,003,000
2,778,000
$
10,390,000
$
8,801,000
NOTE 5:
PROPERTY,
PLANT AND EQUIPMENT, NET
March 31, 2010
December 31, 2009
$
3,374,000
$
3,374,000
41,959,000
39,905,000
9,381,000
8,606,000
54,714,000
51,885,000
2,042,000
2,025,000
136,745,000
133,667,000
4,018,000
3,913,000
869,000
690,000
160,000
160,000
198,548,000
192,340,000
50,599,000
42,879,000
$
147,949,000
$
149,461,000
Quarter Ended
Quarter Ended
March 31, 2010
March 31, 2009
$
6,950,000
$
3,597,000
1,329,000
1,571,000
413,000
420,000
NOTE 6:
OPERATING
LEASES
F-18
Table of Contents
NOTE 6:
OPERATING
LEASES (Continued)
$
6,270,000
7,866,000
6,283,000
3,405,000
1,206,000
121,000
NOTE 7:
ASSET
RETIREMENT OBLIGATION
March 31, 2010
December 31, 2009
$
13,343,000
$
9,292,000
233,000
650,000
(354,000
)
(3,358,000
)
414,000
3,802,000
2,957,000
$
13,636,000
$
13,343,000
6,623,000
7,377,000
$
7,013,000
$
5,966,000
NOTE 8:
FAIR
VALUE OF FINANCIAL INSTRUMENTS
Level 1 Observable inputs such as quoted prices
in active markets.
Level 2 Inputs, other than quoted prices in
active markets, that are observable either directly or
indirectly.
Level 3 Unobservable inputs in which there is
little or no market data, which require a reporting entity to
develop its own assumptions.
F-19
Table of Contents
NOTE 8:
FAIR
VALUE OF FINANCIAL
INSTRUMENTS (Continued)
Market approach (Level 1) Prices and other
relevant information generated by market transactions involving
identical or comparable assets or liabilities.
Cost approach (Level 2) Amount that would be
required to replace the service capacity of an asset
(replacement cost).
Income approach (Level 3) Techniques to convert
future amounts to a single present amount based on market
expectations (including present-value techniques, option-pricing
and excess earning models).
Fair Value Measurements at March 31, 2010
Quoted Prices in
Significant
Active Markets for
Significant Other
Unobservable
Identical Liabilities
Observable Inputs
Inputs
(Level 1)
(Level 2)
(Level 3)
$
$
1,000
$
Fair Value Measurements at December 31, 2009
Quoted Prices in
Significant
Active Markets for
Significant Other
Unobservable
Identical Liabilities
Observable Inputs
Inputs
(Level 1)
(Level 2)
(Level 3)
$
$
34,000
$
March 31, 2010
December 31, 2009
Carrying
Carrying
Amount
Fair Value
Amount
Fair Value
$
4,914,000
$
4,980,000
$
4,982,000
$
4,952,000
$
93,518,000
$
93,518,000
$
90,729,000
$
90,729,000
F-20
Table of Contents
NOTE 9:
LONG-TERM
INCENTIVE PLAN
Weighted
Average
Grant
Date Fair
Units
Value
79,050
$
11.79
37,221
17.43
(11,643
)
14.77
(5,087
)
14.21
99,541
13.43
NOTE 10:
EARNINGS
PER UNIT
F-21
Table of Contents
NOTE 10:
EARNINGS
PER UNIT (Continued)
Quarter Ended March 31,
2010
2009
(in thousands
except unit amounts)
6,575,259
5,889,539
n/a
10,678
6,575,259
5,900,217
$
(281
)
$
9,196
(281
)
9,197
$
(0.04
)
$
1.56
(0.04
)
1.56
133,053
119,643
$
(6
)
$
187
(6
)
186
$
(0.04
)
$
1.56
(0.04
)
1.56
NOTE 11:
COMMITMENTS
AND CONTINGENCIES
F-22
Table of Contents
NOTE 11:
COMMITMENTS
AND CONTINGENCIES (Continued)
NOTE 12:
CONCENTRATION
OF CREDIT RISK AND MAJOR CUSTOMERS
F-23
Table of Contents
NOTE 12:
CONCENTRATION
OF CREDIT RISK AND MAJOR
CUSTOMERS (Continued)
NOTE 13:
RELATED
PARTY TRANSACTIONS
F-24
Table of Contents
NOTE 14:
SUPPLEMENTAL
CASH FLOW INFORMATION
For the Quarters Ended
March 31,
2010
2009
$
1,711,000
$
1,443,000
1,296,000
225,000
3,074,000
3,637,000
1,387,000
288,000
83,000
NOTE 15:
SEGMENT
INFORMATION
NOTE 16:
SUBSEQUENT
EVENTS
F-25
Table of Contents
F-26
Table of Contents
F-27
Table of Contents
Oxford Mining
Oxford Resource Partners, LP
Company
(Successor)
(Predecessor)
Period from
Period from
Years Ended
August 24
January 1
December 31,
to December 31,
to August 23,
2009
2008
2007
2007
$
254,171
$
193,699
$
61,324
$
96,799
32,490
31,839
10,204
18,083
7,183
4,951
1,407
3,267
293,844
230,489
72,935
118,149
170,698
151,421
40,721
70,415
19,487
12,925
9,468
17,494
32,490
31,839
10,204
18,083
25,902
16,660
4,926
9,025
13,242
9,577
2,114
3,643
261,819
222,422
67,433
118,660
32,025
8,067
5,502
(511
)
35
62
55
26
(6,484
)
(7,720
)
(3,498
)
(2,386
)
3,823
29,399
409
2,059
(2,871
)
(5,895
)
(2,891
)
(537
)
(682
)
$
23,504
$
(2,482
)
$
1,522
$
(3,553
)
$
467
$
(50
)
$
30
$
23,037
$
(2,432
)
$
1,492
$
3.80
$
(0.44
)
$
0.30
$
3.79
$
(0.44
)
$
0.30
6,061,072
5,554,395
4,900,000
6,084,508
5,554,395
4,901,956
$
2.17
$
2.21
$
F-28
Table of Contents
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
Total
Common
Excess of
Earnings
Stock In
Shareholders
Noncontrolling
Total
Stock
Par Value
(Deficit)
Treasury
Equity
Interest
Equity
$
2
$
44
$
10,252
$
(2,077
)
$
8,221
$
$
8,221
980
980
(3,553
)
(3,553
)
682
(2,871
)
(16,339
)
(16,339
)
(343
)
(16,682
)
$
2
$
44
$
(9,640
)
$
(2,077
)
$
(11,671
)
$
1,319
$
(10,352
)
Limited
Limited
General
General
Total
Partner
Partners
Partner
Partners
Total
Noncontrolling
Partners
Units
Capital
Units
Capital
Units
interest
Capital
$
$
$
$
4,900,000
54,880
100,000
1,120
5,000,000
1,319
57,319
(20,465
)
(417
)
(20,882
)
1,492
30
537
2,059
25
25
4,900,000
$
35,932
100,000
$
733
5,000,000
$
1,856
$
38,521
(2,432
)
(50
)
2,891
409
962,500
10,780
19,643
220
982,143
11,000
(12,253
)
(250
)
(2,450
)
(14,953
)
468
468
26,984
(124
)
26,984
(124
)
5,889,484
$
32,371
119,643
$
653
6,009,127
$
2,297
$
35,321
23,037
467
5,895
29,399
650,029
11,329
13,266
231
663,295
11,560
(13,141
)
(266
)
(6,125
)
(19,532
)
472
472
30,883
(108
)
30,883
(108
)
6,570,396
$
53,960
132,909
$
1,085
6,703,305
$
2,067
$
57,112
F-29
Table of Contents
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
$
23,504
$
(2,482
)
$
1,522
$
(3,553
)
25,902
16,660
4,926
9,025
(1,681
)
574
1,107
530
398
131
148
1,252
472
468
25
1,390
1,020
261
695
1,177
(1,407
)
(9
)
(25
)
(3,823
)
5,895
2,891
537
682
(2,875
)
(3,906
)
834
(1,785
)
(2,062
)
(479
)
358
(847
)
(2,807
)
(494
)
(4,368
)
(167
)
3,055
6,761
(11,388
)
10,386
1,094
1,509
(454
)
3,178
(13,840
)
12,479
(2,001
)
(103
)
37,183
33,992
(8,519
)
17,634
(18,275
)
(2,705
)
(197
)
(20,010
)
(1,919
)
(2,346
)
(1,476
)
(312
)
(2,285
)
(629
)
(853
)
(88
)
(1,201
)
(25,657
)
(25,321
)
(77,114
)
(11,305
)
88
3,972
(4
)
(67
)
(1,221
)
91
(49,528
)
(23,942
)
(98,745
)
(16,619
)
6,650
14,800
69,999
6,445
(2,646
)
(5,853
)
(175
)
(6,964
)
11,560
11,000
36,400
980
7,500
16,850
3,490
(3,000
)
(17,350
)
(2,990
)
(13
)
(6,125
)
(2,450
)
(343
)
(13,407
)
(12,503
)
(339
)
532
4,494
106,724
(234
)
(11,813
)
14,544
(540
)
781
15,179
635
1,175
394
$
3,366
$
15,179
$
635
$
1,175
F-30
Table of Contents
NOTE 1:
ORGANIZATION
AND PRESENTATION
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.
$
36,400,000
70,000,000
2,990,000
19,600,000
128,990,000
1,034,000
20,400,000
$
107,556,000
F-31
Table of Contents
NOTE 1:
ORGANIZATION
AND PRESENTATION (Continued)
$
5,195,000
77,617,000
4,976,000
19,730,000
(2,726,000
)
2,764,000
$
107,556,000
F-32
Table of Contents
NOTE 2:
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES
F-33
Table of Contents
NOTE 2:
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
25-39 years
7-12 years
5-7 years
3-7 years
7 years
F-34
Table of Contents
NOTE 2:
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
F-35
Table of Contents
NOTE 2:
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
F-36
Table of Contents
NOTE 2:
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
F-37
Table of Contents
NOTE 2:
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
Oxford Resource Partners, LP
Period from
Years Ended December 31,
August 24 to
2009
2008
December 31, 2007
(in thousands except unit amounts)
6,061,072
5,554,395
4,900,000
23,436
n/a
1,956
6,084,508
5,554,395
4,901,956
$
23,037
$
(2,432
)
$
1,492
23,038
(2,432
)
1,492
$
3.80
$
(0.44
)
$
0.30
3.79
(0.44
)
0.30
123,023
113,241
100,000
$
467
$
(50
)
$
30
466
(50
)
30
$
3.80
$
(0.44
)
$
0.30
3.79
(0.44
)
0.30
F-38
Table of Contents
NOTE 2:
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
F-39
Table of Contents
NOTE 2:
SUMMARY
OF SIGNIFICANT ACCOUNTING
POLICIES (Continued)
NOTE 3:
ACQUISITION
$
1,594,000
10,264,000
20,519,000
404,000
(6,600,000
)
(4,083,000
)
$
22,098,000
F-40
Table of Contents
NOTE 3:
ACQUISITION (Continued)
Pro Forma Results
for the Year Ended
December 31,
2009
2008
(Unaudited)
$
356,894,000
$
313,118,000
6,479,000
(21,711,000
)
NOTE 4:
INVENTORY
2009
2008
$
4,759,000
$
2,462,000
1,264,000
1,053,000
2,778,000
1,619,000
$
8,801,000
$
5,134,000
NOTE 5:
PROPERTY,
PLANT AND EQUIPMENT, NET
2009
2008
$
3,374,000
$
2,475,000
39,905,000
25,597,000
43,279,000
28,072,000
2,025,000
1,375,000
133,667,000
93,908,000
3,913,000
3,005,000
690,000
594,000
160,000
160,000
8,606,000
4,712,000
192,340,000
131,826,000
42,879,000
19,380,000
$
149,461,000
$
112,446,000
F-41
Table of Contents
NOTE 5:
PROPERTY,
PLANT AND EQUIPMENT, NET (Continued)
Oxford Mining
Oxford Resource Partners, LP
Company
(Successor)
(Predecessor)
For the Years Ended
For the Period from
For the Period from
December 31,
Inception to
January 1, 2007
2009
2008
December 31, 2007
to August 23, 2007
$
19,632,000
$
11,455,000
$
3,404,000
$
7,827,000
4,672,000
3,226,000
1,030,000
216,000
1,200,000
1,533,000
318,000
982,000
NOTE 6:
OPERATING
LEASES
$
6,289,000
6,014,000
4,429,000
1,570,000
123,000
NOTE 7:
INTANGIBLE
ASSETS AND LIABILITIES
December 31, 2009
Estimated
Remaining
Accumulated
Net Carrying
Life (years)
Cost
Amortization
Value
18
$
3,315,000
$
1,019,000
$
2,296,000
3
1,811,000
174,000
1,637,000
$
5,126,000
$
1,193,000
$
3,933,000
3
$
6,600,000
$
1,705,000
$
4,895,000
F-42
Table of Contents
NOTE 7:
INTANGIBLE
ASSETS AND LIABILITIES (Continued)
December 31, 2008
Estimated
Remaining
Accumulated
Net Carrying
Life (years)
Cost
Amortization
Value
19
$
3,315,000
$
621,000
$
2,694,000
4
1,786,000
528,000
1,258,000
$
5,101,000
$
1,149,000
$
3,952,000
$
984,000
868,000
639,000
254,000
227,000
961,000
$
2,345,000
1,919,000
631,000
Table of Contents
NOTE 8:
OTHER
CURRENT LIABILITIES
2009
2008
$
2,345,000
$
860,000
2,262,000
1,125,000
1,384,000
1,098,000
$
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
Year Ended December 31,
2009
2008
$
9,292,000
$
7,644,000
650,000
459,000
(3,358,000
)
(2,594,000
)
3,802,000
3,783,000
2,957,000
$
13,343,000
$
9,292,000
(7,377,000
)
(4,749,000
)
$
5,966,000
$
4,543,000
F-44
Table of Contents
NOTE 10:
LONG-TERM
DEBT
2009
2008
$
64,925,000
$
65,625,000
21,304,000
14,800,000
4,500,000
90,729,000
80,425,000
228,000
436,000
1,843,000
1,570,000
3,089,000
1,317,000
24,000
27,000
95,711,000
83,977,000
(4,113,000
)
(2,535,000
)
$
91,598,000
$
81,442,000
F-45
Table of Contents
NOTE 10:
LONG-TERM
DEBT (Continued)
F-46
Table of Contents
NOTE 10:
LONG-TERM
DEBT (Continued)
F-47
Table of Contents
NOTE 10:
LONG-TERM
DEBT (Continued)
$
4,113,000
2,268,000
89,317,000
4,000
4,000
5,000
$
95,711,000
NOTE 11:
INTEREST
RATE CAP AND SWAP AGREEMENTS
NOTE 12:
FAIR
VALUE OF FINANCIAL INSTRUMENTS
Fair Value Measurements at December 31, 2009
Quoted Prices in
Significant
Active Markets for
Significant Other
Unobservable
Identical Liabilities
Observable Inputs
Inputs
(Level 1)
(Level 2)
(Level 3)
$
$
34,000
$
F-48
Table of Contents
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
(Level 1)
(Level 2)
(Level 3)
$
$
1,681,000
$
December 31, 2009
December 31, 2008
Carrying
Carrying
Amount
Fair Value
Amount
Fair Value
$
4,982,000
$
4,952,000
$
3,552,000
$
3,311,000
$
90,729,000
$
90,729,000
$
80,425,000
$
80,425,000
NOTE 13:
LONG-TERM
INCENTIVE PLAN
F-49
Table of Contents
NOTE 13:
LONG-TERM
INCENTIVE PLAN (Continued)
Weighted Average
Grant Date
Units
Fair Value
106,410
$
11.20
43,172
11.20
(26,984
)
11.20
(8,825
)
11.20
(6,410
)
11.20
107,363
$
11.20
11,148
17.43
(30,883
)
11.75
(8,578
)
11.88
79,050
$
11.79
NOTE 14:
WORKERS
COMPENSATION AND BLACK LUNG
NOTE 15:
RETIREMENT
PLAN
NOTE 16:
NONCONTROLLING
INTEREST
F-50
Table of Contents
NOTE 16:
NONCONTROLLING
INTEREST (Continued)
Year Ended December 31
2009
2008
$
2,297,000
$
1,856,000
5,895,000
2,891,000
(6,125,000
)
(2,450,000
)
$
2,067,000
$
2,297,000
NOTE 17:
COMMITMENTS
AND CONTINGENCIES
F-51
Table of Contents
NOTE 17:
COMMITMENTS
AND CONTINGENCIES (Continued)
NOTE 18:
CONCENTRATION
OF CREDIT RISK AND MAJOR CUSTOMERS
NOTE 19:
RELATED
PARTY TRANSACTIONS
F-52
Table of Contents
NOTE 19:
RELATED
PARTY TRANSACTIONS (Continued)
NOTE 20:
SUPPLEMENTAL
CASH FLOW INFORMATION
F-53
Table of Contents
NOTE 20:
SUPPLEMENTAL
CASH FLOW INFORMATION (Continued)
F-54
Table of Contents
NOTE 20:
SUPPLEMENTAL
CASH FLOW INFORMATION (Continued)
Oxford Resource
Oxford Mining
Partners, LP
Company
(Successor)
(Predecessor)
For the
For the
Period from
Period from
January 1,
For the Years Ended
Inception to
2007 to
December 31,
December 31,
August 23,
2009
2008
2007
2007
$
6,005,000
$
6,395,000
$
2,202,000
$
2,625,000
363,000
302,000
62,000
87,000
55,000
5,000
2,049,000
3,161,000
983,000
4,924,000
3,230,000
4,550,000
NOTE 21:
SEGMENT
INFORMATION
NOTE 22:
SUBSEQUENT
EVENTS
F-55
Table of Contents
F-56
Table of Contents
September 30,
December 31,
2009
2008
$
6,349,835
$
2,843,134
252,357
452,558
591,957
400,886
7,194,149
3,696,578
48,576,077
45,162,984
509,825
16,707,173
15,649,026
188,602
216,147
$
72,666,001
$
65,234,560
$
8,839,064
$
6,449,019
8,224,486
6,532,045
1,627,800
1,958,000
18,691,350
14,939,064
2,898,278
2,366,000
13,080,972
14,641,745
37,995,401
33,287,751
$
72,666,001
$
65,234,560
F-57
Table of Contents
Nine Months
Year
Year
Ended
Ended
Ended
September 30,
December 31,
December 31,
2009
2008
2007
$
58,493,767
$
76,645,989
$
66,973,145
54,531,148
71,877,168
61,939,870
5,851,821
8,188,945
7,746,824
6,947,484
11,090,565
5,822,082
5,799,952
6,646,543
4,064,979
3,000,000
2,873,055
76,130,405
97,803,221
82,446,810
(17,636,638
)
(21,157,232
)
(15,473,665
)
(2,600,873
)
(1,811,280
)
(86,316
)
3,900
6,302
8,292
(5,142
)
(1,014,424
)
739,493
(2,602,115
)
(2,819,402
)
661,469
(20,238,753
)
(23,976,634
)
(14,812,196
)
16,081
37,838
70,155
$
(20,254,834
)
$
(24,014,472
)
$
(14,882,351
)
F-58
Table of Contents
Combined Statements of Group Equity
For the Nine Months Ended September 30, 2009 and
the Years Ended December 31, 2008 and 2007
$
18,800,282
21,670,486
813,454
(14,882,351
)
26,401,871
26,511,411
4,388,941
(24,014,472
)
33,287,751
22,703,615
2,258,869
(20,254,834
)
$
37,995,401
F-59
Table of Contents
Nine Months
Year
Year
Ended
Ended
Ended
September 30,
December 31,
December 31,
2009
2008
2007
$
(20,254,834
)
$
(24,014,472
)
$
(14,882,351
)
5,799,952
6,646,543
4,064,979
792
1,012,779
(742,086
)
2,258,869
4,388,941
813,454
2,873,055
(644,217
)
(730,436
)
1,244,438
(3,506,701
)
1,452,404
(2,541,574
)
200,201
620,139
(816,314
)
(191,071
)
34,096
(235,371
)
2,390,045
(2,169,229
)
5,147,696
(13,946,964
)
(12,759,235
)
(5,074,074
)
509,825
(509,825
)
216,477
(1,631,921
)
(3,194,375
)
(6,879,142
)
210,000
683,912
1,582,346
(1,346,609
)
(3,187,274
)
(9,712,212
)
(2,258,705
)
(6,207,562
)
(14,792,531
)
22,703,615
26,511,411
21,670,486
(209,025
)
(1,058,336
)
(939,463
)
(6,288,921
)
(6,486,278
)
(1,007,250
)
16,205,669
18,966,797
19,723,773
(142,832
)
142,832
$
$
$
$
1,237,268
$
1,055,688
$
245,893
$
6,629,614
$
18,025,434
$
10,293,381
F-60
Table of Contents
1.
Nature of
Operations and Significant Accounting Policies
F-61
Table of Contents
1.
Nature of
Operations and Significant Accounting
Policies (Continued)
F-62
Table of Contents
1.
Nature of
Operations and Significant Accounting
Policies (Continued)
F-63
Table of Contents
1.
Nature of
Operations and Significant Accounting
Policies (Continued)
F-64
Table of Contents
1.
Nature of
Operations and Significant Accounting
Policies (Continued)
F-65
Table of Contents
1.
Nature of
Operations and Significant Accounting
Policies (Continued)
2.
Preparation
of Carved-Out Financial Statements
F-66
Table of Contents
2.
Preparation
of Carved-Out Financial
Statements (Continued)
3.
Acquisitions
$
1,281,000
859,000
2,387,000
(2,476,000
)
$
2,051,000
F-67
Table of Contents
3.
Acquisitions (Continued)
$
334,000
429,000
1,770,000
(1,386,000
)
$
1,147,000
Total
Charolais
Charolais
Acquisition
Acquisition
Allocation
Allocation
Excluding RCF
$
557,000
$
557,000
13,483,000
7,939,000
8,705,000
7,405,000
(821,000
)
(821,000
)
$
21,924,000
$
15,080,000
F-68
Table of Contents
4.
Property,
Plant, and Equipment, Net
September 30,
December 31,
2009
2008
$
636,154
$
599,654
480,885
25,424
3,683,996
3,084,768
52,483,183
45,886,694
1,775,000
1,775,000
355,557
370,450
65,965
65,965
59,480,740
51,807,955
10,904,663
6,644,971
$
48,576,077
$
45,162,984
5.
Asset
Retirement Obligations
F-69
Table of Contents
5.
Asset
Retirement Obligations (Continued)
Nine Months
Ended
Year Ended
September 30,
December 31,
2009
2008
$
4,324,000
$
3,757,353
1,131,000
846,295
166,083
188,719
189,132
(832,936
)
(919,568
)
4,526,078
4,324,000
1,627,800
1,958,000
$
2,898,278
$
2,366,000
6.
Debt
September 30,
December 31,
2009
2008
$
47,643
$
105,109
21,257,815
21,068,681
21,305,458
21,173,790
8,224,486
6,532,045
$
13,080,972
$
14,641,745
$
2,013,455
8,147,660
7,366,999
3,604,101
173,243
$
21,305,458
F-70
Table of Contents
7.
Income
Taxes
Nine Months
Ended
Year Ended
Year Ended
September 30,
December 31,
December 31,
2009
2008
2007
$
16,081
$
37,838
$
70,155
8.
Major
Customers
Nine Months
Ended
Year Ended
Year Ended
September 30,
December 31,
December 31,
2009
2008
2007
4
3
3
98
%
86
%
83
%
$
6,349,485
$
2,410,395
$
2,285,240
9.
Commitments
and Contingent Liabilities
F-71
Table of Contents
9.
Commitments
and Contingent
Liabilities (Continued)
10.
Stock
Incentive Plans
F-72
Table of Contents
10.
Stock
Incentive Plans (Continued)
2009
2008
2007
Options
Options
Options
$
0.08 per share
$
0.64 per share
$
0.73 per share
2.75
%
3.98
%
4.37
%
0.00
0.00
0.00
0.40
0.40
0.40
10.00
10.00
10.00
11.
Sales
Contract Termination
F-73
Table of Contents
11.
Sales
Contract Termination (Continued)
12.
Defined
Contribution Plan
13.
Related-Party
Transactions
Nine Months
Ended
Year Ended
Year Ended
September 30,
December 31,
December 31,
2009
2008
2007
$
6,947,484
$
10,362,888
$
5,170,340
1,363,605
755,592
(159,577
)
14.
Subsequent
Events
F-74
Table of Contents
Table of Contents
A-1
Definitions
A-1
Construction
A-18
A-19
Formation
A-19
Name
A-19
Registered Office;
Registered Agent; Principal Office; Other Offices
A-19
Purpose and
Business
A-19
Powers
A-20
Term
A-20
Title to Partnership
Assets
A-20
A-20
Limitation of
Liability
A-20
Management of
Business
A-20
Outside Activities of
the Limited Partners
A-21
Rights of Limited
Partners
A-21
A-21
Certificates
A-21
Mutilated, Destroyed,
Lost or Stolen Certificates
A-22
Record
Holders
A-22
Transfer
Generally
A-23
Registration and
Transfer of Limited Partner Interests
A-23
Transfer of the
General Partners General Partner Interest
A-24
Transfer of Incentive
Distribution Rights
A-24
Restrictions on
Transfers
A-24
Citizenship
Certificates; Non-citizen Assignees
A-25
Redemption of
Partnership Interests of Non-citizen
A-26
A-27
Intentionally
Omitted
A-27
Contributions by the
General Partner and the Initial Limited Partners
A-27
Contributions by
Limited Partners
A-27
Interest and
Withdrawal of Capital Contributions
A-28
Capital
Accounts
A-28
Issuances of
Additional Partnership Securities
A-30
Conversion of
Subordinated Units
A-31
Limited Preemptive
Right
A-32
Splits and
Combinations
A-32
Fully Paid and
Non-Assessable Nature of Limited Partner Interests
A-32
Issuance of Common
Units in Connection with Reset of Incentive Distribution
Rights
A-32
A-34
Allocations for
Capital Account Purposes
A-34
Allocations for Tax
Purposes
A-40
Requirement and
Characterization of Distributions; Distributions to Record
Holders
A-42
A-i
Table of Contents
Distributions of IPO
Proceeds, Credit Facility Proceeds and Available Cash from
Operating Surplus
A-43
Distributions of
Available Cash from Capital Surplus
A-44
Adjustment of Minimum
Quarterly Distribution and Target Distribution Levels
A-45
Special Provisions
Relating to the Holders of Subordinated Units
A-45
Special Provisions
Relating to the Holders of Incentive Distribution
Rights
A-45
Entity-Level Taxation
A-46
A-46
Management
A-46
Certificate of Limited
Partnership
A-48
Restrictions on the
General Partners Authority
A-48
Reimbursement of the
General Partner
A-48
Outside
Activities
A-49
Loans from the General
Partner; Loans or Contributions from the Partnership or Group
Members
A-50
Indemnification
A-50
Liability of
Indemnitees
A-52
Resolution of
Conflicts of Interest; Standards of Conduct and Modification of
Duties
A-52
Other Matters
Concerning the General Partner
A-53
Purchase or Sale of
Partnership Securities
A-54
Registration Rights of
the General Partner and its Affiliates
A-54
Reliance by Third
Parties
A-57
A-57
Records and
Accounting
A-57
Fiscal Year
A-57
Reports
A-57
A-58
Tax Returns and
Information
A-58
Tax
Elections
A-58
Tax
Controversies
A-58
Withholding
A-58
A-59
Admission of Limited
Partners
A-59
Admission of Successor
or Additional General Partner
A-59
Amendment of Agreement
and Certificate of Limited Partnership
A-60
A-60
Withdrawal of the
General Partner
A-60
Removal of the General
Partner
A-61
Interest of Departing
General Partner and Successor General Partner
A-61
Termination of
Subordination Period, Conversion of Subordinated Units and
Extinguishment of Cumulative Common Unit Arrearages
A-63
Withdrawal of Limited
Partners
A-63
A-63
Dissolution
A-63
Continuation of the
Business of the Partnership After Dissolution
A-63
Table of Contents
Liquidator
A-64
Liquidation
A-64
Cancellation of
Certificate of Limited Partnership
A-65
Return of
Contributions
A-65
Waiver of
Partition
A-65
Capital Account
Restoration
A-65
A-65
Amendments to be
Adopted Solely by the General Partner
A-65
Amendment
Procedures
A-66
Amendment
Requirements
A-67
Special
Meetings
A-67
Notice of a
Meeting
A-68
Record Date
A-68
Adjournment
A-68
Waiver of Notice;
Approval of Meeting
A-68
Quorum and
Voting
A-68
Conduct of a
Meeting
A-69
Action Without a
Meeting
A-69
Right to Vote and
Related Matters
A-69
A-70
Authority
A-70
Procedure for Merger,
Consolidation or Conversion
A-70
Approval by Limited
Partners
A-71
Certificate of
Merger
A-72
Effect of Merger,
Consolidation or Conversion
A-72
A-73
Right to Acquire
Limited Partner Interests
A-73
A-74
Addresses and Notices;
Written Communications
A-74
Further
Action
A-75
Binding
Effect
A-75
Integration
A-75
Creditors
A-75
Waiver
A-75
Third-Party
Beneficiaries
A-75
Counterparts
A-75
Applicable Law; Forum,
Venue and Jurisdiction
A-75
Invalidity of
Provisions
A-76
Consent of
Partners
A-76
Facsimile
Signatures
A-76
Provisions Regarding
Effective Time
A-76
A-77
Non-Pro Rata
Redemption of Common Units
A-77
Table of Contents
PARTNERSHIP OF OXFORD RESOURCE PARTNERS, LP
A-1
Table of Contents
A-2
Table of Contents
A-3
Table of Contents
A-4
Table of Contents
A-5
Table of Contents
A-6
Table of Contents
A-7
Table of Contents
A-8
Table of Contents
A-9
Table of Contents
A-10
Table of Contents
A-11
Table of Contents
A-12
Table of Contents
A-13
Table of Contents
A-14
Table of Contents
A-15
Table of Contents
A-16
Table of Contents
A-17
Table of Contents
A-18
Table of Contents
A-19
Table of Contents
A-20
Table of Contents
A-21
Table of Contents
A-22
Table of Contents
A-23
Table of Contents
A-24
Table of Contents
A-25
Table of Contents
A-26
Table of Contents
A-27
Table of Contents
A-28
Table of Contents
A-29
Table of Contents
A-30
Table of Contents
A-31
Table of Contents
A-32
Table of Contents
A-33
Table of Contents
A-34
Table of Contents
A-35
Table of Contents
A-36
Table of Contents
A-37
Table of Contents
A-38
Table of Contents
A-39
Table of Contents
A-40
Table of Contents
A-41
Table of Contents
A-42
Table of Contents
A-43
Table of Contents
A-44
Table of Contents
A-45
Table of Contents
A-46
Table of Contents
A-47
Table of Contents
A-48
Table of Contents
A-49
Table of Contents
A-50
Table of Contents
A-51
Table of Contents
A-52
Table of Contents
A-53
Table of Contents
A-54
Table of Contents
A-55
Table of Contents
A-56
Table of Contents
A-57
Table of Contents
A-58
Table of Contents
A-59
Table of Contents
A-60
Table of Contents
A-61
Table of Contents
A-62
Table of Contents
A-63
Table of Contents
A-64
Table of Contents
A-65
Table of Contents
A-66
Table of Contents
A-67
Table of Contents
A-68
Table of Contents
A-69
Table of Contents
A-70
Table of Contents
A-71
Table of Contents
A-72
Table of Contents
A-73
Table of Contents
A-74
Table of Contents
A-75
Table of Contents
A-76
Table of Contents
A-77
Table of Contents
By:
Title:
President and Chief Executive Officer
A-78
Table of Contents
Agreement of Limited Partnership of
Oxford Resource Partners, LP
Representing Limited Partner Interests in
Oxford Resource Partners, LP
AA-1
Table of Contents
Dated:
Oxford Resource Partners, LP
Countersigned and Registered by:
its General Partner
as Transfer Agent and Registrar
Authorized Signature
AA-2
Table of Contents
as tenants in common
UNIF GIFT/TRANSFERS MIN ACT
as tenants by the entireties
Custodian
(Cust) (Minor)
as joint tenants with right of survivorship and not as tenants
in common
under Uniform Gifts/Transfers to CD Minors Act (State)
AA-3
Table of Contents
OXFORD RESOURCE PARTNERS, LP
NOTE: The signature to any endorsement hereon must correspond
with the name as written upon the face of this Certificate in
every particular, without alteration, enlargement or change.
AA-4
Table of Contents
B-1
Table of Contents
B-2
Table of Contents
B-3
Table of Contents
B-4
Table of Contents
Table of Contents
Table of Contents
Item 13.
Other
Expenses of Issuance and Distribution.
$
17,825
25,500
125,000
600,000
3,224,646
1,084,034
4,000
192,775
$
5,273,780
*
To be provided by amendment.
Item 14.
Indemnification
of Directors and Officers.
Item 15.
Recent
Sales of Unregistered Securities.
II-1
Table of Contents
Item 16.
Exhibits
and Financial Statement Schedules.
(a)
The following documents are filed as exhibits to this
registration statement:
Exhibit
1
.1
Form of Underwriting Agreement
3
.1*
Certificate of Limited Partnership of Oxford Resource Partners,
LP (as previously filed with the initial filing of this
Registration Statement on March 24, 2010)
3
.2
Form of Third Amended and Restated Agreement of Limited
Partnership of Oxford Resource Partners, LP (included as
Appendix A to the Prospectus)
3
.3*
Certificate of Formation of Oxford Resources GP, LLC (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
II-2
Table of Contents
Exhibit
3
.4*
Form of Second Amended and Restated Limited Liability Company
Agreement of Oxford Resources GP, LLC (as previously filed with
Amendment No. 3 to this Registration Statement on
June 9, 2010)
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 (as previously filed with
Amendment No. 3 to this Registration Statement on
June 9, 2010)
10
.3*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Michael B. Gardner (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.4*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Jeffrey M. Gutman (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.5*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Gregory J. Honish (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.6*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Charles C. Ungurean (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.7*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Thomas T. Ungurean (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.8*#
Employee Unitholder Agreement among Oxford Resource Partners,
LP, Oxford Resources GP, LLC and Michael B. Gardner (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
10
.9*#
Employee Unitholder Agreement among Oxford Resource Partners,
LP, Oxford Resources GP, LLC and Jeffrey M. Gutman (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
10
.10*#
Employee Unitholder Agreement among Oxford Resource Partners,
LP, Oxford Resources GP, LLC and Gregory J. Honish (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
10
.11*#
Employee Unitholder Agreement among Oxford Resource Partners,
LP, Oxford Resources GP, LLC and Denise M. Maksimoski (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
10
.12*#
Form of Oxford Resource Partners, LP Long-Term Incentive Plan,
as amended (as previously filed with Amendment No. 3 to
this Registration Statement on June 9, 2010)
10
.13A*#
Form of Long-Term Incentive Plan Grant Agreement (as previously
filed with Amendment No. 3 to this Registration Statement
on June 9, 2010)
10
.13B*#
Form of Long-Term Incentive Plan Grant Agreement between Oxford
Resources GP, LLC and Jeffrey M. Gutman (as previously
filed with Amendment No. 3 to this Registration Statement
on June 9, 2010)
10
.14*#
Form of Non-Employee Director Compensation Plan (as previously
filed with Amendment No. 3 to this Registration Statement
on June 9, 2010)
10
.15A*#
Form of Non-Employee Director Compensation Plan Grant Agreement
(as previously filed with Amendment No. 3 to this
Registration Statement on June 9, 2010)
10
.15B*#
Director Unitholder Agreement, dated December 1, 2009, by and
among Oxford Resource Partners, LP, Oxford Resources GP, LLC and
Gerald A. Tywoniuk (as previously filed with Amendment
No. 1 to this Registration Statement on April 21, 2010)
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 (as previously filed with
Amendment No. 1 to this Registration Statement on
April 21, 2010)
Table of Contents
Exhibit
10
.17A
Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21,
2004, by and between Oxford Mining Company, Inc. and American
Electric Power Service Corporation, agent for Columbus Southern
Power Company
10
.17B*
Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated
October 25, 2004 (as previously filed with Amendment No. 1
to this Registration Statement on April 21, 2010)
10
.17C
Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated
April 8, 2005
10
.17D
Amendment No. 2006-3 to Coal Purchase and Sale Agreement, dated
December 5, 2006
10
.17F
Amendment No. 2008-6 to Coal Purchase and Sale Agreement, dated
December 29, 2008
10
.17G
Amendment No. 2009-1 to Coal Purchase and Sale Agreement, dated
May 21, 2009
10
.17H
Amendment No. 2009-3 to Coal Purchase and Sale Agreement, dated
December 15, 2009
10
.17I
Amendment No. 2010-1 to Coal Purchase and Sale Agreement, dated
January 11, 2010
10
.17J*
Amendment No. 2010-2 to Coal Purchase and Sale Agreement, dated
February 4, 2010 (as previously filed with Amendment No. 1
to this Registration Statement on April 21, 2010)
10
.17K*
Amendment No. 2010-3 to Coal Purchase and Sale Agreement, dated
April 16, 2010 (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.18*
Non-Compete Agreement by and among Oxford Resource Partners, LP,
C&T Coal, Inc., Charles C. Ungurean, Thomas T. Ungurean and
Oxford Resources GP, LLC (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.19*
Administrative and Operational Services Agreement, dated August
24, 2007, by and among Oxford Resource Partners, LP, Oxford
Mining Company, LLC and Oxford Resources GP, LLC (as previously
filed with Amendment No. 1 to this Registration Statement
on April 21, 2010)
21
.1*
List of Subsidiaries of Oxford Resource Partners, LP (as
previously filed with the initial filing of this Registration
Statement on March 24, 2010)
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 to the
initial filing of this Registration Statement on March 24,
2010)
24
.2*
Power of Attorney for Peter B. Lilly (included on the signature
page to Amendment No. 3 to this Registration Statement
filed on June 9, 2010)
*
Previously filed.
#
Compensatory plan or arrangement.
Certain portions have been omitted pursuant to a confidential
treatment request. Omitted information has been filed separately
with the Securities and Exchange Commission.
Table of Contents
(b)
Financial Statements Schedules.
Item 17.
Undertakings.
II-5
Table of Contents
By:
By:
II-6
Table of Contents
Exhibit
1
.1
Form of Underwriting Agreement
3
.1*
Certificate of Limited Partnership of Oxford Resource Partners,
LP (as previously filed with the initial filing of this
Registration Statement on March 24, 2010)
3
.2
Form of Third Amended and Restated Agreement of Limited
Partnership of Oxford Resource Partners, LP (included as
Appendix A to the Prospectus)
3
.3*
Certificate of Formation of Oxford Resources GP, LLC (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
3
.4*
Form of Second Amended and Restated Limited Liability Company
Agreement of Oxford Resources GP, LLC (as previously filed with
Amendment No. 3 to this Registration Statement on
June 9, 2010)
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 (as previously filed with
Amendment No. 3 to this Registration Statement on
June 9, 2010)
10
.3*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Michael B. Gardner (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.4*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Jeffrey M. Gutman (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.5*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Gregory J. Honish (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.6*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Charles C. Ungurean (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.7*#
Form of Employment Agreement between Oxford Resources GP, LLC
and Thomas T. Ungurean (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.8*#
Employee Unitholder Agreement among Oxford Resource Partners,
LP, Oxford Resources GP, LLC and Michael B. Gardner (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
10
.9*#
Employee Unitholder Agreement among Oxford Resource Partners,
LP, Oxford Resources GP, LLC and Jeffrey M. Gutman (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
10
.10*#
Employee Unitholder Agreement among Oxford Resource Partners,
LP, Oxford Resources GP, LLC and Gregory J. Honish (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
10
.11*#
Employee Unitholder Agreement among Oxford Resource Partners,
LP, Oxford Resources GP, LLC and Denise M. Maksimoski (as
previously filed with Amendment No. 1 to this Registration
Statement on April 21, 2010)
10
.12*#
Form of Oxford Resource Partners, LP Long-Term Incentive Plan,
as amended (as previously filed with Amendment No. 3 to
this Registration Statement on June 9, 2010)
10
.13A*#
Form of Long-Term Incentive Plan Grant Agreement (as previously
filed with Amendment No. 3 to this Registration Statement
on June 9, 2010)
10
.13B*#
Form of Long-Term Incentive Plan Grant Agreement between Oxford
Resources GP, LLC and Jeffrey M. Gutman (as previously
filed with Amendment No. 3 to this Registration Statement
on June 9, 2010)
10
.14*#
Form of Non-Employee Director Compensation Plan (as previously
filed with Amendment No. 3 to this Registration Statement
on June 9, 2010)
10
.15A*#
Form of Non-Employee Director Compensation Plan Grant Agreement
(as previously filed with Amendment No. 3 to this
Registration Statement on June 9, 2010)
10
.15B*#
Director Unitholder Agreement, dated December 1, 2009, by and
among Oxford Resource Partners, LP, Oxford Resources GP, LLC and
Gerald A. Tywoniuk (as previously filed with Amendment
No. 1 to this Registration Statement on April 21,
2010)
II-7
Table of Contents
Exhibit
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 (as previously filed with
Amendment No. 1 to this Registration Statement on
April 21, 2010)
10
.17A
Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21,
2004, by and between Oxford Mining Company, Inc. and American
Electric Power Service Corporation, agent for Columbus Southern
Power Company
10
.17B*
Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated
October 25, 2004 (as previously filed with Amendment No. 1
to this Registration Statement on April 21, 2010)
10
.17C
Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated
April 8, 2005
10
.17D
Amendment No. 2006-3 to Coal Purchase and Sale Agreement, dated
December 5, 2006
10
.17F
Amendment No. 2008-6 to Coal Purchase and Sale Agreement, dated
December 29, 2008
10
.17G
Amendment No. 2009-1 to Coal Purchase and Sale Agreement, dated
May 21, 2009
10
.17H
Amendment No. 2009-3 to Coal Purchase and Sale Agreement, dated
December 15, 2009
10
.17I
Amendment No. 2010-1 to Coal Purchase and Sale Agreement, dated
January 11, 2010
10
.17J*
Amendment No. 2010-2 to Coal Purchase and Sale Agreement, dated
February 4, 2010 (as previously filed with Amendment No. 1
to this Registration Statement on April 21, 2010)
10
.17K*
Amendment No. 2010-3 to Coal Purchase and Sale Agreement, dated
April 16, 2010 (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.18*
Non-Compete Agreement by and among Oxford Resource Partners, LP,
C&T Coal, Inc., Charles C. Ungurean, Thomas T. Ungurean and
Oxford Resources GP, LLC (as previously filed with Amendment
No. 3 to this Registration Statement on June 9, 2010)
10
.19*
Administrative and Operational Services Agreement, dated August
24, 2007, by and among Oxford Resource Partners, LP, Oxford
Mining Company, LLC and Oxford Resources GP, LLC (as previously
filed with Amendment No. 1 to this Registration Statement
on April 21, 2010)
21
.1*
List of Subsidiaries of Oxford Resource Partners, LP (as
previously filed with the initial filing of this Registration
Statement on March 24, 2010)
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 to the
initial filing of this Registration Statement on March 24,
2010)
24
.2*
Power of Attorney for Peter B. Lilly (included on the signature
page to Amendment No. 3 to this Registration Statement
filed on June 9, 2010)
*
Previously filed.
#
Compensatory plan or arrangement.
Certain portions have been omitted pursuant to a confidential
treatment request. Omitted information has been filed separately
with the Securities and Exchange Commission.
II-8
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
Very truly yours, | ||||||||
|
||||||||
Oxford Resources GP, LLC | ||||||||
|
||||||||
By: | ||||||||
Name: | ||||||||
Title: | ||||||||
|
||||||||
|
||||||||
Oxford Resource Partners, LP | ||||||||
|
||||||||
By: | Oxford Resources GP, LLC, | |||||||
its general partner | ||||||||
|
||||||||
|
By: | |||||||
|
||||||||
|
Name: | |||||||
|
||||||||
|
Title: | |||||||
|
||||||||
|
||||||||
|
||||||||
Oxford Mining Company, LLC | ||||||||
|
||||||||
By: | ||||||||
Name: | ||||||||
Title: | ||||||||
Accepted: | ||||
|
||||
Barclays Capital Inc. | ||||
Citigroup Global Markets Inc. | ||||
|
||||
For themselves and as Representatives | ||||
of the several Underwriters named | ||||
in Schedule 1 hereto | ||||
|
||||
Barclays Capital Inc. | ||||
|
||||
By:
|
||||
|
||||
|
Authorized Representative | |||
|
||||
Citigroup Global Markets Inc. | ||||
|
||||
By:
|
||||
|
||||
|
Authorized Representative |
Number of Firm Units | ||||
Underwriters | to be Purchased | |||
Barclays Capital Inc.
|
||||
Citigroup Global Markets Inc.
|
||||
Credit Suisse Securities (USA) LLC
|
||||
Raymond James & Associates, Inc.
|
||||
Wells Fargo Securities, LLC
|
||||
|
||||
Total
|
||||
|
Schedule 1
Schedule 2
1. | Public offering price for the Units: $[___] | |
2. | Number of Units: [___] |
Schedule 3
1. | Letter dated May 3, 2010 for Equipment Lease Payoff/Termination and Equipment Purchase Transaction executed by Caterpillar Financial Services Corporation in favor of Oxford Resource Partners, LP, Oxford Resources GP, LLC, Oxford Mining Company, LLC and Oxford Mining Company Kentucky, LLC. | |
2. | Letter dated May 12, 2010 for Equipment Lease Payoff/Termination and Equipment Purchase Transaction executed by General Electric Capital Corporation in favor of Oxford Resource Partners, LP, Oxford Resources GP, LLC, Oxford Mining Company, LLC and Oxford Mining Company Kentucky, LLC. | |
3. | Letter dated May 10, 2010 for Equipment Lease Termination and Equipment Purchase Transaction executed by OMCO Leasing Corporation in favor of Oxford Resource Partners, LP, Oxford Resources GP, LLC, Oxford Mining Company, LLC and Oxford Mining Company Kentucky, LLC. | |
4. | Letter dated May 12, 2010 for Equipment Lease Payoff/Termination and Equipment Purchase Transaction executed by Komatsu Financial Limited Partnership in favor of Oxford Resource Partners, LP, Oxford Resources GP, LLC, Oxford Mining Company, LLC and Oxford Mining Company Kentucky, LLC. | |
5. | Letter dated May 12, 2010 for Payoff Calculation and Payoff Transaction executed by Sovereign Bank in favor of Oxford Resource Partners, LP and Oxford Mining Company, LLC. | |
6. | Letter agreement dated June 2, 2010 for Lease Payoff/Termination and Equipment Purchase Transaction between Marquette Equipment Finance, LLC, on the one hand, and Oxford Resource Partners, LP and Oxford Mining Company, LLC, on the other hand. |
Schedule 4
A-2
Very truly yours,
|
||||
By: | ||||
Name: | ||||
Title: | ||||
A-3
B-1-1
B-1-2
B-1-3
B-1-4
B-1-5
B-2-1
B-2-2
B-2-3
B-3-1
B-3-2
717 Texas Avenue, 16th floor | ||||||||
Houston, TX 77002 | ||||||||
Tel: +1.713.546.5400 Fax: +1.713.546.5401 | ||||||||
www.lw.com | ||||||||
|
||||||||
FIRM / AFFILIATE OFFICES | ||||||||
|
Abu Dhabi | Moscow | ||||||
|
Barcelona | Munich | ||||||
|
Beijing | New Jersey | ||||||
|
Brussels | New York | ||||||
|
Chicago | Orange County | ||||||
|
Doha | Paris | ||||||
|
Dubai | Riyadh | ||||||
June 22, 2010
|
Frankfurt | Rome | ||||||
|
Hamburg | San Diego | ||||||
|
Hong Kong | San Francisco | ||||||
|
Houston | Shanghai | ||||||
|
London | Silicon Valley | ||||||
Oxford Resource Partners, LP
|
Los Angeles | Singapore | ||||||
41 South High Street, Suite 3450
|
Madrid | Tokyo | ||||||
Columbus, Ohio 43215
|
Milan | Washington, D.C. |
1. | The Partnership has been duly formed and is validly existing as a limited partnership under the Delaware Act. | ||
2. | The Common Units, when issued and delivered on behalf of the Partnership against payment therefor as described in the Partnerships Registration Statement on Form S-1 (File No. 333-165662), as amended as of the effective date thereof, to which this opinion is an exhibit and relating to the Common Units (the Registration Statement ), will be duly authorized, validly issued, fully paid and non-assessable. |
Very truly yours,
|
||||
/s/ Latham & Watkins LLP | ||||
Latham & Watkins LLP | ||||
ARTICLE I DEFINITIONS AND ACCOUNTING TERMS | 1 | |||||
Section 1.01
|
Certain Defined Terms | 1 | ||||
Section 1.02
|
Computation of Time Periods; Other Definitional Provisions | 36 | ||||
Section 1.03
|
Accounting Terms | 36 | ||||
ARTICLE II AMOUNTS AND TERMS OF THE ADVANCES AND THE LETTERS OF CREDIT | 36 | |||||
Section 2.01
|
The Advances and the Letters of Credit | 36 | ||||
Section 2.02
|
Making the Advances | 38 | ||||
Section 2.03
|
Issuance of and Drawings and Reimbursement Under Letters of Credit | 41 | ||||
Section 2.04
|
Repayment of Advances | 43 | ||||
Section 2.05
|
Optional Termination or Reduction of the Commitments | 44 | ||||
Section 2.06
|
Prepayments | 45 | ||||
Section 2.07
|
Interest | 47 | ||||
Section 2.08
|
Fees | 48 | ||||
Section 2.09
|
Conversion of Borrowings | 50 | ||||
Section 2.10
|
Increased Costs, Etc. | 51 | ||||
Section 2.11
|
Payments and Computations | 52 | ||||
Section 2.12
|
Taxes | 54 | ||||
Section 2.13
|
Sharing of Payments, Etc. | 56 | ||||
Section 2.14
|
Use of Proceeds | 57 | ||||
Section 2.15
|
Defaulting Lenders | 57 | ||||
Section 2.16
|
Evidence of Debt | 59 | ||||
Section 2.17
|
Replacement of Certain Lenders | 60 | ||||
Section 2.18
|
Increase in the Aggregate Commitments | 61 | ||||
ARTICLE III CONDITIONS OF LENDING | 63 | |||||
Section 3.01
|
Conditions Precedent | 63 | ||||
Section 3.02
|
Conditions Precedent to Each Borrowing, Commitment Increase and Issuance and Renewal | 67 | ||||
Section 3.03
|
Determinations Under Section 3.01 | 68 | ||||
ARTICLE IV REPRESENTATIONS AND WARRANTIES | 68 | |||||
Section 4.01
|
Representations and Warranties of Borrower | 68 | ||||
ARTICLE V COVENANTS | 76 | |||||
Section 5.01
|
Affirmative Covenants | 76 | ||||
Section 5.02
|
Negative Covenants | 80 | ||||
Section 5.03
|
Reporting Requirements | 86 | ||||
Section 5.04
|
Financial Covenants | 89 | ||||
ARTICLE VI EVENTS OF DEFAULT | 91 | |||||
Section 6.01
|
Events of Default | 91 | ||||
Section 6.02
|
Actions in Respect of the Letters of Credit Upon Default | 93 | ||||
ARTICLE VII ADMINISTRATIVE AGENT | 94 | |||||
Section 7.01
|
Appointment and Authority | 94 | ||||
Section 7.02
|
Administrative Agent Individually | 94 | ||||
Section 7.03
|
Duties of Administrative Agent; Exculpatory Provisions | 96 | ||||
Section 7.04
|
Reliance by Administrative Agent | 96 | ||||
Section 7.05
|
Indemnification | 97 |
i
Section 7.06
|
Delegation of Duties | 98 | ||||
Section 7.07
|
Resignation of Administrative Agent, Issuing Bank or Swing Line Bank | 98 | ||||
Section 7.08
|
Non-Reliance on Administrative Agent and Other Lender Parties | 100 | ||||
Section 7.09
|
No Other Duties, Etc. | 101 | ||||
ARTICLE VIII MISCELLANEOUS | 102 | |||||
Section 8.01
|
Amendments, Etc. | 102 | ||||
Section 8.02
|
Notices | 103 | ||||
Section 8.03
|
Posting of Approved Electronic Communications | 104 | ||||
Section 8.04
|
No Waiver; Remedies | 105 | ||||
Section 8.05
|
Costs and Expenses | 105 | ||||
Section 8.06
|
Right of Set-off | 107 | ||||
Section 8.07
|
Binding Effect | 108 | ||||
Section 8.08
|
Assignments and Participations | 108 | ||||
Section 8.09
|
Execution in Counterparts | 111 | ||||
Section 8.10
|
No Liability of Issuing Bank | 111 | ||||
Section 8.11
|
Confidentiality | 112 | ||||
Section 8.12
|
Treatment of Information | 113 | ||||
Section 8.13
|
Jurisdiction, Etc. | 115 | ||||
Section 8.14
|
Governing Law | 115 | ||||
Section 8.15
|
MLP and Subsidiary Guarantors as Limited Parties; Non-Recourse to the General Partner and Associated Persons | 115 | ||||
Section 8.16
|
Patriot Act Notice | 115 | ||||
Section 8.17
|
Survival | 116 | ||||
Section 8.18
|
Entire Agreement | 116 | ||||
Section 8.19
|
WAIVER OF JURY TRIAL | 116 |
ii
Exhibits
|
||||||
|
||||||
A-1
|
Form of Revolving Note | |||||
A-2
|
Form of Term Note | |||||
B
|
Form of Notice of Borrowing | |||||
C
|
Form of Assignment and Acceptance | |||||
D-1
|
Form of MLP Guaranty | |||||
D-2
|
Form of Subsidiary Guaranty | |||||
E
|
Form of Solvency Certificate | |||||
F
|
Form of Compliance Certificate | |||||
|
||||||
Schedules
|
||||||
|
||||||
I
|
Lending Officer and Commitment Information | |||||
II
|
Subsidiary Guarantors | |||||
2.03(f)
|
Existing Letters of Credit | |||||
4.01(a)
|
Capital Stock of Oxford Mining Company, LLC | |||||
4.01(b)
|
Loan Party Subsidiaries | |||||
4.01(d)
|
Authorization, Approval, Action, Notice and Filing Requirements | |||||
4.01(f)
|
Litigation | |||||
4.01(n)
|
Plans and Multiemployer Plans | |||||
4.01(o)
|
Environmental Matters | |||||
4.01(p)
|
Open Year Tax Returns | |||||
4.01(s)
|
Real Property | |||||
4.01(t)
|
Loan Party Investments | |||||
5.01(p)
|
Post Closing Covenants | |||||
5.02(a)
|
Existing Liens | |||||
5.02(c)
|
Existing Debt |
iii
1
2
Leverage Ratio | Eurodollar Rate Advances | Base Rate Advances | ||
Level I
|
3.75% | 2.75% | ||
£
1.00x
|
||||
Level II
|
4.00% | 3.00% | ||
> 1.00x
£
1.50x
|
||||
Level III
|
4.25% | 3.25% | ||
> 1.50x
£
2.00x
|
||||
Level IV
|
4.50% | 3.50% | ||
>2.00x
|
3
Leverage Ratio | Applicable Percentage | |
Level I
|
0.500% | |
£
1.00x
|
||
Level II
|
0.625% | |
> 1.00x
£
1.50x
|
||
Level III
|
0.750% | |
> 1.50x
£
2.00x
|
||
Level IV
|
0.750% | |
>2.00x
|
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
1 | Expected to be approximately seven (7) days following anticipated closing of the IPO. |
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
2 | to be conformed to Sources and Uses in Registration Statement. |
84
85
86
87
88
89
Period of Fiscal | Capital Expenditure | |||
Year Ending | Amount | |||
December 31, 2010*
|
$ | 17,000,000 | ||
December 31, 2011
|
$ | 40,000,000 | ||
December 31, 2012
|
$ | 45,000,000 | ||
December 31, 2013
|
$ | 45,000,000 | ||
December 31, 2014
|
$ | 40,000,000 |
* | For the period of such Fiscal Year from the Effective Date on. |
90
91
92
93
94
95
96
97
98
99
100
101
102
(i) | if to the Borrower or any other Loan Party: | ||
Oxford Mining Company, LLC
41 South High Street, Suite 3450 Columbus, OH 43215 Attention of: Jeffrey M. Gutman Telecopier No.: (614) 754-7100 E-Mail Address: jgutman@oxfordmining.com |
|||
(ii) | if to the Administrative Agent: | ||
Citibank, N.A.
1615 Brett Rd OPS3 New Castle, DE 19720 Attention of: Suzanna Gallagher Telecopier No.: (212) 994-0961 E-Mail Address: Suzanna.Gallagher@citi.com |
|||
(iii) | if to the Issuing Bank: | ||
Fifth Third Bank
38 Fountain Square Plaza MD 10AT63 Cincinnati, OH 45263 Attention of: Patrick Lingrosso Telecopier No.: (513) 534-8400 E-Mail Address: Patrick.lingrosso@53.com |
|||
(iv) | if to the Swing Line Bank: | ||
Citibank, N.A.
1615 Brett Rd OPS3 New Castle, DE 19720 Attention of: Suzanna Gallagher Telecopier No.: (212) 994-0961 E-Mail Address: Suzanna.Gallagher@citi.com |
103
104
105
106
107
108
109
110
111
112
113
114
115
116
117
Lessor | Lease Date | Mine | Document Needed | Document Obtained | ||||
Terry Adkins
|
12-2-05 | Jessup | Notice of Assignment | |||||
|
||||||||
Hilltop Haven, Inc.
|
5-30-01 | Jessup | Notice of Assignment | |||||
|
||||||||
Anna Loraine Cundiff
|
6-7-06 | Winn | Consent to Assignment and Transfer | |||||
|
||||||||
Martha Rogers Haas, Trustee of the
Martha Rogers Haas 1996 Revocable
Trust, Talmage G. Rogers, Jr., Jean M.
Rogers, James L. Rogers III,
Testamentary Trustee Under the Will of
James L. Rogers, Jr., James L. Rogers,
III, Mary M. Rogers, and Sue Rogers
Johnson
|
9-30-09 | Rose France | Consent to Assignment, Mortgage, and Transfer of Control | |||||
|
||||||||
Tom Eubanks and Jeff Eubanks
|
5-31-07 | KO | Notice of Assignment | |||||
|
||||||||
Talmage G. Rogers, Jr., Jean M.
Rogers, James L. Rogers, III,
Testamentary Trustee Under the Will of
James L. Rogers, Jr., and Martha
Rogers Haas, Trustee of the Martha
Rogers Haas 1996 Revocable Trust
|
9-23-09 | Rose France | Consent to Assignment and Mortgage | |||||
|
||||||||
Martha Rogers Haas, Trustee of the
Martha Rogers Haas 1996 Revocable
Trust, Talmage G. Rogers, Jr., Jean M.
Rogers, and James L. Rogers, III,
Testamentary Trustee Under the Will of
James L. Rogers, Jr.
|
7-17-06 | Vaught | Consent to Assignment, Mortgage, and Transfer of Control | |||||
|
||||||||
John K. Vaught and Lisa Michelle Vaught
|
11-4-08 | Vaught | Consent to Assignment, Mortgage, and Transfer of Control | |||||
|
||||||||
Holmes Limestone Company
|
2-1-03 | Various | Consent to Assignment | |||||
|
||||||||
Holmes Limestone Company
|
6-22-05 | Tusky | Consent to Assignment | |||||
|
||||||||
Oxford Mining Company LLC
|
4-1-09 | Tusky | Consent to Assignment | |||||
|
||||||||
Florence Krulock, David G. Krulock,
and Daniel J. Krulock, Trustees of the
Krulock General Power of Appointment
Trust
|
6-7-02 | Consent to Assignment |
Annex A Page 1
Lessor | Lease Date | Mine | Document Needed | Document Obtained? | ||||
Krulock Coal Company
|
6-7-02 | Consent to Assignment | ||||||
|
||||||||
Capstone Holding Company
|
12-20-02 | Consent to Assignment | ||||||
|
||||||||
Joseph J. Fister and Theresa Fister
|
6-11-07 | Consent to Assignment | ||||||
|
||||||||
Lewis G. Stratton and Wanda F. Stratton
|
1-22-02 | Consent to Assignment | ||||||
|
||||||||
John P. Dagrava and Margaret A.
Williams, Trustees for the Dagrava
Family Revocable Living Trust
|
3-10-08 | Consent to Assignment | ||||||
|
||||||||
Robert D. Wilson
|
8-12-08 | Consent to Assignment |
2
Commitment Information
Revolving Credit
Term Loan
Letter of Credit
Swing Line
Domestic Lending
Name of Initial Lender
Commitment
Commitment
Commitment
Commitment
Office
Eurodollar Lending Office
$
10,500,000.00
$
10,500,000.00
$
1,826,086.96
$
684,782.61
399 Park Avenue
New York, NY 10043
399 Park Avenue
New York, NY 10043
$
19,500,000.00
$
1,500,000.00
$
3,391,304.35
$
1,271,739.13
745 7th Avenue
New York, NY 10019
745 7th Avenue
New York, NY 10019
$
13,800,000.00
$
7,200,000.00
$
2,400,000.00
$
900,000.00
41 South High Street
Columbus, OH 43215
41 South High Street
Columbus, OH 43215
$
13,800,000.00
$
7,200,000.00
$
2,400,000.00
$
900,000.00
38 Fountain Square
Plaza
MD 10AT63
Cincinnati, OH 45263
38 Fountain Square Plaza
MD 10AT63
Cincinnati, OH 45263
$
13,800,000.00
$
7,200,000.00
$
2,400,000.00
$
900,000.00
2 Embarcadero Ctr #300
San Francisco, CA 94111
2 Embarcadero Ctr #300
San Francisco, CA 94111
Corporation
$
9,428,571.43
$
8,571,428.57
$
1,639,751.55
$
614,906.83
2120 West End Avenue
Nashville, TN 37203
2120 West End Avenue
Nashville, TN 37203
$
8,542,857.14
$
4,457,142.86
$
1,485,714.29
$
557,142.86
1221 Avenue of the
Americas
New York, NY 10020
1221 Avenue of the Americas
New York, NY 10020
Branch
$
8,542,857.14
$
4,457,142.86
$
1,485,714.29
$
557,142.86
Eleven Madison Avenue New York, NY 10010
Eleven Madison Avenue
New York, NY 10010
$
8,542,857.14
$
4,457,142.86
$
1,485,714.29
$
557,142.86
201 S. Jefferson St. Roanoke, VA 24011
201 S. Jefferson St.
Roanoke, VA 24011
$
8,542,857.14
$
4,457,142.86
$
1,485,714.29
$
557,142.86
710 Carillon Parkway
St. Petersburg, FL
33716
710 Carillon Parkway
St. Petersburg, FL 33716
$
115,000,000
$
60,000,000
$
20,000,000
$
7,500,000
1.
Oxford Mining Company Kentucky,
LLC
2.
Daron Coal Company, LLC
Issuing Bank
Beneficiary
Amount
Effective Date
Letter of Credit
RLI Insurance
$
75,000
8/25/2008
Argonaut Insurance Co.
2,500,000
9/30/2009
S409447
Travelers Casualty
3,750,000
11/3/2009
S409532
and Surety Company
of America
Republic Bank, Inc.*
1,320,000
11/3/2009
S409506
Argonaut Insurance Co.
600,000
3/12/2010
S500148
Total
$
8,245,000
*
With equipment leases being bought-out at closing, this letter of credit will not need to be
renewed.
Company, LLC
Number of Units
Percentage of
Owner
Owned
Outstanding Units
100
100%
100
100%
Number of
Number of
Percentage of
Authorized
Outstanding
Units/Shares Owned
Loan Party Subsidiary
Units/Shares
Units/Shares
by Loan Party
100
100
100%
Number of
Number of
Percentage of
Authorized
Outstanding
Units/Shares Owned
Loan Party Subsidiary
Units/Shares
Units/Shares
by Loan Party
100
100
100%
100
100
100%
*
*
51%
*
A members interest in Harrison Resources, LLC is not represented by units or
shares; and instead is represented simply by the members percentage membership
interest as reflected in the Harrison Resources, LLC Operating
Agreement.
Notice and Filing Requirements
1.
Oxford Retirement Plan
2.
Oxford Resource Partners, LP Long-Term Incentive Plan
3.
Oxford Mining Employee Group Benefit Plan (providing medical, dental,
vision, life and short-term disability benefits for employees and their
eligible dependents)
4.
Oxford Mining Company, LLC Premium Only Plan (Cafeteria Plan)
Off Road
On Road
Gas Tank
Location
Capacity
Tank No.
Tank No.
No.
8000
0144
2000
3201
250
3202
10000
7333
2000
Tr. 9788
20000
BT-4105
20000
BT-4106
3000
4102
400
4103
10000
7382
400
7920
1000
J Brown
2000
0083
9000
7301
500
7304
250
7303
3000
Tk. 9815
10000
4101
10000
BD-8001
150
8003
10000
262
10000
363
15000
376
3000
7458
500
8201
2000
Tk. 9796
10000
7395
12000
3401
1000
Tk. 9812
1000
3403
500
3404
300
6001
Off Road
On Road
Gas Tank
Location
Capacity
Tank No.
Tank No.
No.
10000
2356
10000
7331
2000
303
1500
Tr. 9759
10000
16
22000
25
22000
26
22000
27
22000
28
22000
29
1000
24
10000
17
10000
7395
3000
Tr. 9722
8000
7502
10000
297
2000
Tr. 9772
10000
400
2000
Tr. 9840
10000
7302
1000
8901 (Scottie)
8000
3402
10000
375
10000
7364
2000
Tr. 9766
50000
1007
20000
1005
20000
1006
3000
Tr. 9709
2000
Tr. 9758
500
1001
500
1002
10000
0031
20000
7332
3000
Tr. 9827
1000
7334
500
7335
2000
Tr. 9710
20000
8702
30000
9724
3000
Tr. 9825
3000
Tr. 9843
Location
Capacity
Off Road Tank No.
On Road Tank No.
Gas Tank No.
10000
00227
300
00230
2000
0233
2000
00258
10000
00259
2000
Tr. 9798
Drum
Drum
2000
0271
20000
284
12000
285
20000
286
20000
287
20000
288
20000
289
2000
Tr. 9822
2000
2502
275
2503
8600
524
10000
4201
2000
4202
1000
4203
10000
5202
1000
7101
2000
6101
2000
7701
10000
7702
15000
7383
2000
Tr. 9797
500
7703
2.
Fuel Storage Tanks (Kentucky)
Location
Capacity
Tank No.
5000
T-101
8020
T-102
6000
T-103
6909
T-104
10000
T-105
7500
T-106
4400
T-201
10000
T-107
10000
T-108
Location
Capacity
Tank No.
10000
T-110
8130
T-203
12126
T-111
12855
T-119
4400
T-204
11650
T-112
3000
T-113
1128
T-115
8685
T-116
7150
T-202
3.
Oil Storage Tanks (Ohio)
Location
Capacity
Contents
2000
15/40
2000
10 wt
1000
C-4 TO4-30
550
C-4 TO4-60
8000
Waste Oil
275
Engine Oil
275
Hydraulic Oil
275
Transmission Oil
275
Antifreeze
275
90 wt
1000
Waste Oil
10000
Dust Bond (#7365)
1500
C-4 TO4-10
1000
C-4 TO4-30
1000
15/40
500
60 wt
500
Antifreeze
550
Waste Oil
2000
15/40
8000
10 wt
2000
C-4 TO4-30
2000
60 wt
8000
Antifreeze
10000
Waste Oil
2000
15/40
2000
10 wt
1000
30 wt
550
60 wt
550
Antifreeze
Location
Capacity
Contents
2000
10 wt
2000
15/40
1000
30 wt
550
60 wt
550
Antifreeze
2 Totes
Waste Oil
2000
10 wt
2000
15/40
4000
30 & 60 wt (3 way split)
5 Totes
Antifreeze
3000
Waste Oil
1500
30 & 60 wt, 15/40 (3 way split)
500
60 wt
500
Antifreeze
4 Totes
Waste Oil
4 Totes
(250 Gallon)
2 Totes
Waste Oil
1000
15/40
1000
10 wt
550
60 wt
550
30 wt
300
Antifreeze
10000
10 & 30 wt, 15/40, empty (2500) (4 way split)
2 Totes
50 wt
2 Totes
80/9 wt
1 Tote
68 wt
3 Totes
Antifreeze
1000
15/40
1000
10 wt
1000
30 wt
500
60 wt
500
Antifreeze
1000
Waste Oil
1000
15/40
2 x1000
10 wt
1000
#46 Hydraulic Oil
550
60 wt
550
30 wt
550
Antifreeze
1500
Waste Oil
4000
15/40
4000
10 wt
1000
30 wt
1000
60 wt
1000
Waste Oil
Location
Capacity
Contents
1000
10 wt
1000
15/40
1000
30 wt
550
Antifreeze
550
60 wt
2 x 300
Waste Oil
3 x 280
Oil
280
Waste Oil
278 (Steel)
Used Fuel Oil
1000
15/40
1000
30 wt
1000
60 wt
2000
10 wt
500
Antifreeze
2000
Waste Oil
*
Highlighted entries owned by Randy Moore, not Oxford Mining Company, LLC
4.
Oil Storage Tanks (Kentucky)
Location
Capacity
Contents
300
Fleet 15W-40
2 x 300
Megaflow AW46
300
UGL 85W-140
300
Fleet Charge Antifreeze
4000
PowerDrive 30
2 x 275
UGL 80W-90
3000
Megaflow AW46
2 x 1000
Fleet 15W-40
4000
Fleet 10W
1000
PowerDrive 50
1100
Ecoterra HVI 46
1100
Fleet Charge Antifreeze
275
MegaPlex XD5 grease bin
1400
Fleet 10W
1400
Fleet 15W-40
900
PowerDrive 30
900
PowerDrive 50
900
Fleet 10W
550
Fleet Charge Antifreeze
275
MegaPlex XD5 grease bin
1100
Fleet 10W
Location
Capacity
Contents
1100
Fleet 15W-40
550
PowerDrive 30
550
PowerDrive 50
550
Fleet Charge Antifreeze
550
Megaflow AW46
1100
Waste Oil
1100
Fleet 10W
1100
Fleet 15W-40
550
PowerDrive 30
550
PowerDrive 50
550
Fleet Charge Antifreeze
550
Megaflow AW46
*
Highlighted entries owned by Home Oil rather than Oxford Mining Company Kentucky, LLC
Loan Party/Subsidiary/
Tax Affiliate
Tax Year
2006
1/1-8/23 2007
8/24-12/31 2007
2008
2009
2007
2008
2009
2007
2008
2009
*
Predecessor of Oxford Mining Company, LLC
Tax Parcel Number(s)
Type of
Exhibit
(not certified see
County
State
Name
Acquisition
Document Date
Recording Data
Attachment
document & tax records)
OH
Fluharty
Lease
05/04/2006
OR 426 272
A-1
D01-00100222-00
D01-00100238-00
OH
Stevens
Lease
05/04/2006
OR 417 2498
A-2
D01-00100230-00
OH
Stevens-Hook
Lease
05/04/2006
OR 426 264
A-3
D01-00100219-00
D01-00100220-00
D01-00100221-00
D01-00100239-00
D01-99900007-00
D01-99900008-00
D01-99900009-00
D01-99900025-00
D01-99900026-00
D01-99900027-00
OH
Cameron
Lease
07/14/2008
OR 429 217
A-4
D01-00100203-00
D01-00100202-00
OH
Brake
Lease
07/09/200
OR 429 221
A-5
D01-00100226-00
D01-00100224-00
OH
Russell
Lease
07/10/2008
OR 429 211
A-6
D01-00100237-00
D01-00100236-00
D01-00100217-00
OH
Lucas and Williams
Lease
Assignment
11/19/2008
05/08/2009
OR 430 1901
OR 441 1997
A-7
D01-00100204-00
OH
K&S Shugert
Deed
12/10/2009
OR 211 819
B-1
39-01481.000
39-01482.000
OH
Robt. Shugert
Deed
12/10/2009
OR 211 815
B-2
39-01483.000
39-01484.000
OH
North American Coal
Deed
04/06/2006
OR 57 151
B-3
41-01039.000
Royalty
41-01040.000
Tax Parcel Number(s)
Type of
Exhibit
(not certified see
County
State
Name
Acquisition
Document Date
Recording Data
Attachment
document & tax records)
OH
Jan Kenan et al
Deed
06/30/2003
DV 797 779
B-4
39-00680.000
(Timmons)
Aff Surveyor
D.V. 797 789
39-00679.000
OH
CSX Transporation
Deed
05/22/2003
DV 788 792
B-5
39-90010.002
OH
Consolidation Coal
Deed
(15.02 ac)
07/30/2002
OR 779 862
B-6
05-00477.000
OH
Consolidation Coal
Deed
03/17/2003
OR 786 448
B-7
None
(see document)
OH
Consolidation Coal
Deed
07/30/2002
DV 779 868
B-8
41-00444.000
Aff Surveyor
DV 785 823
41-00445.000
41-00446.000
41-00436.000
41-00431.000
41-00430.000
41-00883.000
41-00881.000
05-00714.000
OH
Ohio River
Deed
03/06/2002
DV 776 55
B-9
39-00543.000
Collieries
39-00544.000
39-00545.000
39-00546.000
39-00547.000
39-00548.000
39-00549.000
39-00829.000
39-00830.000
Tax Parcel Number(s)
Type of
Exhibit
(not certified see
County
State
Name
Acquisition
Document Date
Recording Data
Attachment
document & tax records)
OH
Consolidation Coal
Deed
12/17/2002
OR 785 829
B-10
41-00881.004
OH
Cravat Coal
Deed
04/16/2007
OR 105 616
B-11
50-00546.000
(Whlg Valley)
50-00546.003
50-00584.000
50-00549.002
OH
Harrison Leasing
Deed
04/16/2007
OR 105 630
B-12
(see document)
OH
R&F Coal
Deed
12/23/1998
DV 744 258
B-13
Multiple
(see document)
OH
Fleishman
Deed
07/30/2008
OR 158 289
B-14
09-00338.000
39-00382.000
OH
Consolidation Coal
County Road 29
Deed
03/31/2009
OR 191 936
B-15
05-00611.000
OH
Taylor
Deed
09/28/2000
DV 761 462
B-16
41-00837.001
OH
Jeffco Resources
Deed
12/21/2000
DV 763 572
B-17
41-00563.000
41-00460.000
41-00465.001
OH
Seaway Coal
Deed
03/03/2003
DV 786 373
B-18
(see document)
OH
Capstone
Deed
03/07/2003
DV 285 840
B-19
(see document)
OH
Capstone
Lease
06/19/2001
LV 111 264
B-20
(see document)
LV 111 477
Tax Parcel Number(s)
Type of
Exhibit
(not certified see
County
State
Name
Acquisition
Document Date
Recording Data
Attachment
document & tax records)
OH
Capstone
Sublease
06/19/2001
LV 111 254
B-21
(see document)
LV 111 482
OH
Capstone
Lease
06/20/2000
LV 110 863
B-22
(see document)
OH
Krulock et al
Lease
06/07/2002
LV 112 570
B-23
50-00541.000
Cravat
Assignment
OR 105 391
50-00634.000
OH
Mularcik
Lease
10/07/2005
OR 39 797
B-24
50-00549.000
Cravat
Assignment
OR 105 391
50-00549.001
OH
Antolak
Lease
04/29/2005
LV 112 413
B-25
32-01377.000
Cravat
Assignment
OR 105 391
OH
Mel-Tina Ltd
Lease
05/05/2004
LV 112 428
B-26
50-00521.000
Cravat
Assignment
OR 105 391
OH
Porterfield
Lease
08/28/2002
LV 112 79
B-27
32-001600.000
Cravat
Assignment
OR 105 391
32-01408.000
OH
Zaccagnini et al
Lease
08/28/2002
LV 112 13
B-28
32-01716.000
Cravat
Assignment
OR 105 391
32-01719.000
32-01774.000
32-01775.000
OH
Shugert
Lease
09/12/2002
LV 112 24
B-29
(pt) 39-00710.000
Cravat
Assignment
OR 105 391
12-00208.000
12-00201.002
OH
Fleischman
Lease
04/28/2004
LV 112 418
B-30
09-00338.000
Cravat
Assignment
OR 105 391
39-00382.000
OH
Fulkerson
Lease
12/03/2001
LV 111 586
B-31
(see document)
Cravat
Assignment
OR 105 391
Addendum
OR 183 212
Tax Parcel Number(s)
Type of
Exhibit
(not certified see
County
State
Name
Acquisition
Document Date
Recording Data
Attachment
document & tax records)
OH
Adkins
Lease
12/03/2001
LV 111 590
B-32
(see document)
Cravat
Assignment
OR 105 391
Addendum
OR 183 210
OH
Stratton
Lease
01/22/2002
LV 111 422
B-33
(see document)
Addendum
OV 112 399
Part Release
OR 112 440
Addendum
OR 191 282
OH
Shutway
Lease
02/26/2005
LV 113 219
B-34
(see document)
OH
Ohio River
Collieries
Lease
03/05/2002
LV 111 465
B-35
39-00545.000
OH
Valley Mining
Lease
12/01/2000
LV 111 37
B-36
(see document)
OH
Alice Reilly
Lease
01/31/2001
LV 111 125
B-37
(see document)
OH
Buckeye Management
Lease
06/16/2007
OR 105 395
B-38
09-01400.000
(Speidel)
09-01401.000
09-01399.000
OH
Consolidation Coal
Lease
11/14/1952
LV 73 306
B-39
(see document)
Assignment
12/17/2000
LV 112 87
Tax Parcel Number(s)
Type of
Exhibit
(not certified see
County
State
Name
Acquisition
Document Date
Recording Data
Attachment
document & tax records)
OH
Welch
Lease
08/31/2004
LV 112 543
B-40
39-00383.003
Cravat
Assignment
OR 105 391
09-00312.000
OH
Smail
Lease
07/06/2005
OR 12 854
B-41
39-00493.000
39-01405.000
OH
Capstone
Lease
01/17/2002
LV 111 448
B-42
09-00626.000
Cravat
Addendum
OR 87 371
09-00634.000
(Badgertown)
Assignment
OR 105 391
09-00635.000
OH
Matusek
Lease
03/29/2007
LV 101 963
B-43
50-00545.000
Cravat
Assignment
OR 105 391
50-00550.001
Addendum
OR 183 207
OH
Thompson
Lease
11/07/1978
LV 93 333
B-44
(see document)
Seaway
Assignment
LV 110 189
OH
Jefferson Beagle
Lease
10/01/2002
LV 112 30
B-45
32-01244.000
Club
Assignment
OR 105 391
32-01718.000
Cravat
32-01716.000
32-01719.000
32-01717.000
32-01243.000
OH
Miller
Lease
07/30/2007
OR 117 598
B-46
39-00549.001
39-00572.000
OH
Henderson
Lease
09/23/05
OR 39 786
B-47
50-01178.000
Cravat
Assignment
OR 105 391
Tax Parcel Number(s)
Type of
Exhibit
(not certified see
County
State
Name
Acquisition
Document Date
Recording Data
Attachment
document & tax records)
OH
Krulock Coal
Lease
06/07/02
LV 111 703
B-48
50-00633.000
Cravat
Assignment
OR 105 391
41-00256.004
50-00622.000
50-00624.000
50-00623.000
50-00643.000
50-00644.000
50-00645.000
OH
Bedway Land and
Lease
01/25/03
LV 112 258
B-49
32-01242.000
Minerals
32-10914.000
OH
Capstone
Master Lease &
12/02/02
LV 113 252
B-50
(see document)
Sublease
LV 113 195
OH
Seaway
Lease
05/01/1971
LV 86 477
B-51
(see document)
Consol
Assignment
LV 112 114
OH
Capstone
Lease
01/01/05
LV 113 283
B-52
(see document)
OH
Ohio River
Lease
03/24/06
OR 49 922
B-53
32-01481.000
Collieries
39-00522.000
51-00192.000
OH
Fitch
Lease
11/05/2007
OR 130 282
B-54
41-00243.000
OH
Dagrava
Lease
03/10/2008
OR 144 314
B-55
32-01761.000
OH
Pollock
Lease
05/12/2008
OR 151 881
B-56
39-00599.000
OH
Robt Shugert
Lease
01/19/2009
OR 176 400
B-57
39-00710.000
Tax Parcel Number(s)
Type of
Exhibit
(not certified see
County
State
Name
Acquisition
Document Date
Recording Data
Attachment
document & tax records)
OH
Mauersberger
Lease
11/26/2008
OR 174 477
B-58
39-00466.000
39-00668.000
39-00641.000
39-00161.000
39-00640.000
39-00640.002
39-00642.000
OH
Consolidation Coal
Lease
03/31/2009
L/V 90 416
B-59
05-00611.000
County Road 29
Lease
LV 106 218
Addendum
OR 187 863
Assignment
OR 191 830
OH
Robt. Shugert
Lease
04/27/2009
OR 191 287
B-60
39-00710.000
39-00709.000
39-00708.000
OH
K&S Shugert
Lease
03/04/2009
OR 183 214
B-61
39-00414.000
39-00633.000
39-00384.000
39-00384.001
39-00384.002
39-00416.000
39-00636.000
OH
Jeffco Resources
Lease
09/29/2000
OR 192 231
B-62
41-00498.000
(Barnesville
41-01613.000
Hospital)
Tax Parcel Number(s)
Type of
Exhibit
(not certified see
County
State
Name
Acquisition
Document Date
Recording Data
Attachment
document & tax records)
OH
Capstone
Lease
12/23/2009
OR 215 154
B-63
41-00762.000
(Schooley Hollow)
41-00761.000
41-00780.000
41-00782.000
41-00783.000
41-00791.000
41-00788.000
41-00792.000
41-00785.000
41-00786.000
41-00789.000
41-00787.000
OH
Ohio Power
Lease
01/06/2010
OR 224 895
B-64
29-90037.000
(Bellaire Dock)
OH
Brier Ridge
Lease
10/04/2004
LV 112 559
B-65
09-00488.000
(Cravat)
Assignment
04/16/2007
OR 103 562
41-01468.000
Assignment
05/12/2008
OR 154 607
OH
Green-Crawf
Lease
09/22/2004
LV 112 549
B-66
09-00353.000
(Cravat)
Assignment
04/16/2007
OR 103 562
09-01235.000
Assignment
05/12/2008
OR 154 607
09-01311.000
09-00356.000
OH
Robt Shepherd
Lease
09/23/2004
LV 112 565
B-67
09-00387.000
(Cravat)
Assignment
04/16/2007
OR 103 562
09-00653.000
Assignment
05/12/2008
OR 154 607
09-00654.000
OH
Buckeye Management
Deed
05/08/2008
OR 152 323
B-68
09-01400.000
(Speidel)
09-01401.000
09-01399.000
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Capstone
Lease
03/31/2009
OR 229 519
B-69
05-00591.000
(Gasline)
05-00593.000
05-00592.000
05-00591.000
51-00185.000
51-00184.000
51-00183.000
51-00182.000
OH
Capstone
Lease
05/21/2010
OR 230 175
B-70
41-01468.000
(Speidel)
09-00488.000
09-00643.000
OH
Capstone
Lease
01/01/2010
OR 229 488
B-71
29-03499.000
(Bellaire Dock)
29-03500.000
29-03634.000
29-03635.000
29-03661.000
29-03662.000
29-03863.000
29-03922.000
OH
Capstone
Lease
01/01/2010
LV 106 290
B-72
(see document)
(Swierkos)
Sublease
OR 229 516
OH
The Conservation
Lease
10/06/2004
OR 12 119
C-1
(see document)
Fund
Assignment
04/16/2007
OR 38 1266
OH
Wm. Wright
Lease
05/25/2001
LV 84 874
C-2
33-01252.000
Assignment
12/10/2005
OR 37 2032
Assignment
04/16/2007
OR 38 1269
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Dobrijevic
Lease
12/16/2001
LV 84 872
C-3
17-00005.000
Assignment
12/10/2005
OR 37 2032
Assignment
04/16/2007
OR 38 1269
OH
Dan Wright
Lease
12/13/2001
LV 84 870
C-4
33-01248.000
Assignment
12/10/2005
OR 37 2032
33-01247.000
Assignment
04/16/2007
OR 38 1269
OH
The Conservation
Lease
03/03/2005
OR 17 1714
C-5
33-01252.000
Fund (Cravat)
Assignment
04/16/2007
OR 38 260
33-01248.000
Assignment
05/12/2008
OR 46 2036
33-01247.000
17-00124.000
17-00125.000
17-00129.000
17-00130.000
OH
Yockel
Lease
02/21/2005
OR 17 1704
C-6
17-00279.001
(Cravat)
Assignment
04/16/2007
OR 38 260
17-00279.002
Assignment
05/12/2008
OR 46 2036
17-00279.000
17-00279.007
OH
Holmes Woodland
Lease
03/02/2005
OR 17 1710
C-7
17-00579.000
(Cravat)
Assignment
04/16/2007
OR 38 260
Assignment
05/12/2008
OR 46 2036
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Ferris Coal
Deed
OR 1477 197
D-1
(see document)
(Sheriff)
OH
County Auditor
Deed
11/30/2006
OR 1518 567
D-2
67-00030.000
(Ferris Coal)
OH
County Auditor
Deed
11/30/2006
OR 1518 573
D-3
40-00796.000
(Ferris Coal)
OH
County Auditor
Deed
11/30/2006
OR 1518 571
D-4
40-00799.000
(Ferris Coal)
OH
Baker
Deed
11/18/2004
OR 1329 149
D-5
12-01654.000
OH
Frantz/Perrino
Deed
01/11/2008
OR 1606 443
D-6
12-01653.001
OH
Lois Rawson
Deed
06/15/2007
OR 1596 262
D-7
40-00612.000
13-00190.000
OH
Petersburg
Deed
01/27/2006
OR 1464 614
D-8
13-00151.000
40-00331.000
40-00378.001
40-00377.001
OH
CDDB Holdings
Deed
03/23/2010
OR 1727 528
D-9
12-00214.001
12-00214.002
OH
Robt Hunt et al
Deed
OR 7130 296
D-10
12-00760.000
OH
Lewis
Lease
09/19/2006
OR 1499 428
D-11
(see document)
OH
Stuba
Lease
11/17/2005
OR 1425 943
D-12
12-01831.000
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Scyoc
Lease
08/01/2004
OR 1330 21
D-13
(see document)
Assignment
OR 1436 792
OH
Williams
Lease
11/23/2004
OR 1333 168
D-14
(see document)
OH
Derenberger
Lease
04/30/2008
OR 1625 911
D-15
12-01469.000
12-01653.000
OH
Wells
Lease
09/08/2004
OR 1330 15
D-16
(see document)
Assignment
OR 1436 794
OH
Ferris
Lease
05/28/1992
OR 328 153
D-17
12-00163.000
Rawson
Amendment
05/14/2000
OR 795 511
12-01653.000
Assignment
03/25/2004
OR 1275 645
12-00153.000
Ferris Bankruptcy
Trustee
Addendum
02/25/2010
OR 1722 882
12-01512.000
12-00210.000
12-00214.000
12-00757.000
12-00215.000
12-00017.000
OH
Westover
Lease
02/21/2002
OR 1258 727
D-18
(see document)
Assignment
03/25/2004
OR 1275 645
OH
Rager
Deed
08/20/1997
OR 124 1075
E-1
043-00002630-00
OH
Rager
Deed
08/20/1997
OR 124 1077
E-2
043-00003755-00
043-00003756-00
OH
R&F Coal
Deed
12/23/1998
OR 151 701
E-3
038-00000324-00
039-00000067-01
OH
Myers
Deed
01/15/2001
OR 205 993
E-4
043-00003755-00
043-00003756-00
OH
Capstone
Master Lease &
12/02/2002
OR 373 24
E-5
Multiple
Sublease
(see document)
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Holmes Limestone
Lease
02/01/2003
OR 372 493
E-6
(see document)
OH
Fairview Land
Lease
12/03/1997
OR 133 368
E-7
(see document)
Holmes Limestone
Assignment
06/09/2003
OR 324 653
OH
T&C Holdco
Lease
07/05/2007
OR 457 141
E-8
(see document)
OH
Columbus Southern
Lease
03/17/2007
OR 457 148
E-9
(see document)
Power
OH
Capstone
Master Lease &
12/02/2002
OR 425 810
F-1
(see document)
Sublease
OR 425 831
OH
Holmes Limestone
Lease
02/01/2003
OR 425 381
F-2
(see document)
OH
Fairview Land
Lease
12/03/1997
OR 173 785
F-3
(see document)
Holmes Limestone
Assignment
06/09/2003
OR 369 502
OH
Wilson
Lease
08/12/2008
OR 458 3023
F-4
23-0000117.000
OH
Capstone
Lease
12/23/2009
OR 469 29
F-5
28-0000235.000
(Schooley Hollow)
OH
Combs/Conway
Lease
05/22/2005
OR 436 8
F-6
23-0000006.000
Addendum
11/26/2007
OR 453 1855
Sublease
04/25/2006
OR 447 2381
Assignment
04/16/2007
OR 448 117
Assignment
05/12/2008
OR 457 113
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Miller & Gingerich
Lease
11/09/2005
OR 436 2
F-7
23-0000417.000
(Conway)
Addendum
04/21/2008
OR 456 423
Sublease
04/25/2006
OR 447 2381
Assignment
04/16/2007
OR 448 117
Assignment
05/12/2008
OR 457 113
OH
Dan Doudna
Lease
04/15/2006
OR 439 223
F-8
23-0000218.000
(Conway)
Addendum
05/26/2008
OR 457 802
Sublease
04/25/2006
OR 447 2381
Assignment
04/16/2007
OR 448 117
Assignment
05/12/2008
OR 457 113
OH
Steve Doudna
Lease
12/29/2005
OR 436 19
F-9
23-0000418.000
(Conway)
Addendum
05/21/2008
OR 456 3523
23-0000419.000
Sublease
04/25/2006
OR 447 2381
Assignment
04/16/2007
OR 448 117
Assignment
05/12/2008
OR 457 113
OH
L. Hall
Lease
12/29/2005
OR 436 5
F-10
23-0000123.000
(Conway)
Addendum
11/20/2007
OR 453 1307
Sublease
04/25/2006
OR 447 2381
Assignment
04/16/2007
OR 448 117
Assignment
05/12/2008
OR 457 113
OH
V. Hall
Lease
12/29/2005
OR 436 12
F-11
23-0000382.001
(Conway)
Addendum
11/28/2007
OR 453 1849
23-0000382.002
Sublease
04/25/2006
OR 447 2381
23-0000382.000
Assignment
04/16/2007
OR 448 117
23-0000140.001
Assignment
05/12/2008
OR 457 113
OH
Donald & Joe Lucas
Lease
05/13/2010
OR 471 738
F-12
17-0000319
17-0000233
17-0000271
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Carol & Donald Lucas
Lease
05/13/2010
OR 471 734
F-13
17-0000100
OH
Cravat Coal
Deed
04/16/2007
OR 171 135
G-1
26-0000285.000
(Whlg Valley)
26-0000014.000
26-1000001.333
25-0000119.000
OH
R&F Coal
Deed
12/27/2999
OR 75 813
G-2
02-0000281.000
OH
Consolidation Coal
Deed
05/30/2002
OR 127 39
G-3
04-0000022.000
OH
Consolidation Coal
Deed
12/28/1999
OR 75 816
G-4
Multiple
(see document)
OH
Consolidation Coal
Deed
12/20/2002
OR 134 157
G-5
02-0000098.000
OH
Nelson Mast
Deed
05/29/2003
OR 139 228
G-6
04-0000004.000
OH
Budzik
Deed
11/01/2001
OR 107-730
G-7
04-0000010.000
OH
Consolidation Coal
Deed
07/30/2002
OR 121 426
G-8
04-0000406.000
04-0000412.000
04-0000407.000
04-0000168.000
04-0000170.000
04-0000172.000
04-0000167.000
04-0000171.000
04-0000166.000
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Cravat Coal
Deed
08/01/2008
OR 177 344
G-9
04-0000553.000
(Cadiz Office)
Corrective Deed
08/189/2008
OR 177 1332
04-0000387.000
OH
Consolidation Coal
Deed
03/31/2009
OR 180 317
G-10
02-0000366.001
(County Road 29)
OH
Bruner Land
Deed
11/21/2003
OR 149 438
G-11
02-0000181.004
02-0000181.005
OH
Buckeye Management
Deed
05/08/2008
OR 176 399
G-12
01-0000350.000
01-0000431.000
01-0000432.000
01-0000433.000
OH
Capstone
Master Lease & Sublease
12/20/2002
OR 159 2121
G-13
(see document)
OH
Capstone
Lease
05/07/1993
LV 77 386
G-14
(see document)
(Bedway)
Addendum
08/16/1993
LV 77 553
SubLease
06/19/2001
OR 104 673
OH
Capstone
Lease
06/19/2001
OR 104 662
G-15
(see document)
Addendum
03/15/2004
OR 176 1986
OH
Liggett Enterprises
Lease
01/31/2001
OR 98 327
G-16
04-0000231.000
04-0000229.000
OH
The Conservation Fund
Lease
06/27/2002
OR 128 788
G-17
(see document)
Corrective
OR 157 1104
Part. Assign
04/16/2007
OR 158 604
Assignment
OR 171 393
OH
Slater
Lease
02/09/2004
OR 152 890
G-18
(see document)
OH
Love
Lease
08/13/2003
OR 146 881
G-19
02-0000268.000
04-0000234.000
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Dodds
Lease
05/31/2005
OR 161 1041
G-20
04-00630.000
OH
Beer
Lease
05/13/2004
OR 155 1555
G-21
04-0000577.002
OH
Cobb
Lease
12/28/2004
OR160 593
G-22
04-00261.001
OH
Capstone
Lease
04/03/2003
OR 135 119
G-23
Unknown
(Polen)
OH
Lopez
Lease
11/22/2004
OR 158 1036
G-24
04-00261.001
OH
Capstone
Lease
11/16/2001
OR 111 37
G-25
04-0000010.000
(Budzik-Barricklow)
OH
Bowers
Lease
02/17/2005
OR 159 2384
G-26
26-0000010.000
Assignment
04/16/2007
OR 171 393
OH
Bowers
Lease
02/17/2005
OR 159 2389
G-27
26-0000009.000
Assignment
04/16/2007
OR 171 393
OH
Barricklow
Lease
01/31/2001
OR 98 331
G-28
04-0000010.000
(Budzik-Barricklow)
OH
Consolidation Coal
Lease
LV 34 115
G-29
(see document)
(Ruckstuhl) Part. Release
LV 35 162
Part. Release
OR 158-1031
Lease
OR 160 599
(Haverfield)
LV 34 171
Lease
07/30/2002
LV 35 191
(MacDowell)
LV 33-561
Assignment
LV 35 203
OR 121 131
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
R&F Coal
Lease
11/16/1998
OR 61 443
G-30
Multiple
Daron
Addendum
OR 84 18
(see documents)
Addendum
OR 110 105
OH
Twin Minerals
Lease
01/01/1999
OR 84 26
G-31
Multiple
Daron
Addendum
OR 84 38
(see document)
Addendum
OR 172 2240
OH
LPT Management
Lease
05/27/2003
OR 173 2523
G-32
04-00012.001
OH
Chambers Development
Lease
09/21/2001
OR 176 1970
G-33
(see document)
OH
Consolidation Coal
Lease
03/31/2009
LV 58 237
G-34
02-0000261.000
(County Road 29)
Assignment
OR 180 278
OH
The Conservation
Lease
04/03/2009
OR 179 2596
G-35
22-0000219.000
Fund (Lewis)
OH
Holmes Limestone
Lease
06/22/2005
OR 1611284
G-36
Multiple
PPG & KLM
Sublease
06/22/2005
OR 161 1291
(see document)
Amendment
08/12/2008
OR 177 2343
Amendment
08/12/2008
OR 177 2372
Amendment
04/01/2009
OR 179 2091
OH
Wm. Henderson
Lease
03/19/2010
OR 182 2925
G-37
04-0000557.000
04-0000197.000
OH
The Conservation
Lease
03/03/2005
OR 160 1321
G-38
(see document)
Fund (Cravat)
Assignment
04/16/2007
OR 170 2806
Assignment
05/12/2008
OR 176 650
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Ionno & Miller
Lease
11/13/2001
OR 160 2144
G-39
(see document)
(Stallion Farms)
Assignment
04/16/2007
OR 170 2806
(Cravat)
Assignment
05/12/2008
OR 176 650
Addendum
11/04/2008
OR 178 1319
Addendum
02/16/2010
OR 182 1948
OH
The Conservation
Lease
03/25/2004
OR 165 276
G-40
(see document)
Fund (Cravat)
Assignment
04/16/2007
OR 170 2806
Assignment
05/12/2008
OR 176 650
OH
Brian Lewis
Lease
07/06/2002
OR 166 2843
G-41
17-0000109.016
(Cravat)
Assignment
04/16/2007
OR 170 2806
22-0000038.000
Assignment
05/12/2008
OR 176 650
OH
Hochstetler
Lease
03/17/2006
OR 166 2824
G-42
Multiple
(Cravat)
Assignment
04/16/2007
OR 170 2806
(see document)
Assignment
05/12/2008
OR 176 650
OH
Diebel
Lease
06/12/2006
OR 166 2847
G-43
30-0000803.000
(Cravat)
Assignment
04/16/2007
OR 170 2806
Assignment
05/12/2008
OR 176 650
OH
Weppler
Lease
06/05/2006
OR 166 2821
G-44
30-0000294.000
(Cravat)
Assignment
04/16/2007
OR 170 2806
30-0000295.000
Assignment
05/12/2008
OR 176 650
30-0000293.000
OH
Puskarich
Lease
04/03/2007
OR 170 2135
G-45
17-0000075.000
(Cravat)
Assignment
04/16/2007
OR 170 2806
17-0000090.000
Assignment
05/12/2008
OR 176 650
17-0000067.000
17-0000091.000
OH
Capstone
Lease
03/31/2009
OR 183 1961
G-46
02-0000242.000
(Gasline)
02-0000231.000
Tax Parcel
Number(s) (not
certified see
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
document & tax records)
OH
Capstone
Lease
03/01/2010
OR 183 1638
G-47
04-0000160.000
(Limestone)
OH
Capstone
Lease
03/01/2010
OR 183 1643
G-48
04-0000160.000
(Coal Stockpile)
OH
Liggett
Lease
04/26/2001
OR 97 865
G-49
(see document)
OH
Consolidation
Powerline
Right of
12/01/2008
OR 178 1400
G-50
(see document)
Coal/Harrison
Way
Resources
OH
Boich & Sovell
Deed
03/06/2006
OR 746 947
H-1
50-00053.000
OH
Moore
Deed
03/5,6,7,10/2006
OR 769 431
H-2
50-00599.000
08/19/2006
OH
Hutchison
Lease
12/28/2004
OR 681 875
H-3
15-02383.000
Ragsdale
Addendum
11/25/2009
OR 898 904
OH
Boich
Lease
11/07/2005
LV 59 876
H-4
50-01431.000
(McCain)
Sublease
OR 731 789
50-01431.001
50-01432.000
50-00613.000
50-01384.000
50-01443.000
OH
Joseph Ellis
Lese
03/02/2007
OR 796 642
H-5
50-00264.000
OH
Fern Ellis
Lease
12/20/2002
OR 535 897
H-6
50-00262.000
Addendum
03/06/2007
OR 796 950
50-00263.000
OH
Boich
Lease
11/07/2005
OR 731 791
H-7
(see document)
OH
Harkins
Lease
01/13/2006
OR 735 309
H-8
50-01506.000
Tax Parcel
Number(s) (not
certified see
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
document & tax records)
OH
Starvaggi
Lease
03/24/2006
OR 746 757
H-9
(see document)
(McCain)
OH
Starvaggi
Lease
02/18/2003
OR 545 727
H-10
(see document)
(Ellis)
OH
Zimnox Coal
Lease
10/11/2005
OR 666 896
H-11
50-01042.000
OH
Piergallini
Lease
03/02/2007
OR 796 646
H-12
(see document)
OH
Rush Run
Lease
12/19/2006
OR 785 747
H-13
50-01489.000
50-01489.001
OH
Eastham
Lease
01/08/2007
OR 788 210
H-14
50-01170.000
OH
Moore
Lease
11/16/2004
OR 676 282
H-15
50-00592.000
OH
Starvaggi
Lease
05/01/2007
OR 802 290
H-16
(see document)
OH
Starvaggi
Lease
05/01/2007
OR 802 286
H-17
(see document)
OH
Pasco
Lease
04/26/2007
OR 804 195
H-18
50-01209.000
50-00360.000
50-01471.000
50-01472.000
OH
Verhovec
Lease
05/24/2007
OR 805 60
H-19
(see document)
Tax Parcel
Number(s) (not
certified see
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
document & tax records)
OH
Jeffco Resources
Lease
04/25/2008
OR 844 225
H-20
50-00694.000
50-00168.000
50-00693.000
50-00163.000
OH
Bedway Land
and
Lease
11/26/2008
OR 868 707
H-21
50-00797.000
Minerals
OH
Lapanja
Lease
04/01/2009
OR 880 570
H-22
50-00507.000
OH
Jennings
Lease
05/16/2009
OR 882 960
H-23
50-01178.000
OH
Bedway
Lease
09/12/2001
OR 886 542
H-24
20-01756.011
(Dairy Jean)
OH
Starvaggi (Jeffco,
Lease
10/22/2009
OR 898-895
H-25
05-00694.000
Jennings, Lapanja)
05-00168.000
05-00693.000
05-00163.000
50-01178.000
50-00507.000
OH
Southhall
Lease
05/13/2009
OR 202 1901
I-1
050-008-570-0
050-008-580-0
050-008-590-0
050-008-560-0
050-008-540-0
050-008-530-0
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Kasler
Lease
03/23/2009
OR 202 1892
I-2
050-004-320-0
050-004-290-0
050-004-300-0
050-004-250-0
050-004-310-0
050-004-860-0
050-004-870-0
050-004-840-0
050-004-850-0
OH
R&F Coal
Deed
12/23/1998
Vol 1151 587
J-1
38-60-02-18-000
OH
American National
Can
Deed
05/04/1999
Vol 1155 4
J-2
73-73-03-07-03-000
OH
Peabody Development
Deed
01/29/1996
Vol 1118 641
J-3
38-39-70-01-19-200
38-38-90-01-06-200
OH
Peabody Coal
Deed
10/26/1992
Vol 1071 383
J-4
Multiple
(see document)
OH
Barrick Gold
Deed
05/24/1999
Not recorded
J-5
(see document)
OH
McNeish
Lease
12/05/2002
OR 1716 898
J-6
70-70-06-41-33-000
70-70-06-41-35-000
OH
Holmes Limestone
Lease
02/01/2003
OR 1934 933
J-7
Multiple
(see document)
OH
Hendershot
Lease
03/31/2010
Vol 2273 85
J-8
70-04-03-16-000
Huston
70-04-03-09-000
OH
Timmons
Deeds
02/10/2003
OR 97 588
K-1
01-21043.000
and
OR 97 592
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Wadella
Deed
01/15/2004
OR 108 160
K-2
01-21078.000
OH
Mary Reed
Lease
06/16/2003
OR 113 454
K-3
01-50065.000
OH
Ann Jones
Lease
06/21/2002
OR 87 821
K-4
01-21448.000
01-21449.000
01-30101.000
OH
Darrell Long
Lease
03/26/2003
OR 97 544
K-5
01-50074.000
OH
David Reed
Lease
01/23/2004
OR 108 841
K-6
01-21079.001
OH
Capstone
Master Lease
12/02/2002
OR 122 194
K-7
(see document)
& Sublease
OH
Capstone
Master Lease
120/02/2002
OR 122 173
K-8
(see document)
& Sublease
OH
David Reed
Lease
07/11/2008
OR 157 670
K-9
01-50008.000
01-21039.000
OH
Gadd/Slevin
Lease
02/06/2009
OR 162 910
K-10
01-21042.000
OH
Capstone
Lease
01/25/2010 and
OR 174 267
K-11
(see document)
(Haul Road
02/16/2010
Agreement)
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Leighton
Deed
05/29/2007
OR 344 426
L-4
003-000458-0200
003-000303-0000
003-000284-000
OH
Owen
Deed
09/07/2005
OR 325 1721
L-5
003-000365-0500
OH
Perry County
Deed
09/07/2005
OR 325 1719
L-6
(see document)
Industrial
Development
OH
Ponsart
Deed
09/01/2006
OR 336 2620
L-7
003-000296-0500
003-000303-0204
OH
Wooten
Deed
08/24/2005
OR 325 552
L-8
003-000296-0600
003-000303-0100
OH
Masterson
Deed
07/02/2004
OR 311 2523
L-9
003-000229-0000
OH
Bieber
Deed
06/04/1998
OR 209 800
L-10
024-000-383-0000
OH
Jorgenson
Deed
09/30/2993
OR 280 28
L-11
003-000216-0000
Deed
03-29/2002
OH
Branham
Deed
09/30/1993
OR 279 2522
L-12
003-000360-0400
Deed
03/29/2002
OH
Harris/Leroy
Deed
04/14/2005
OR 320 2062
L-13
008-000003-0000
OH
Peabody
Deed
03/26/1998
OR 204 575
L-14
008-000003-0000
OH
Halsey
Deed
09/30/1993
OR 323 858
L-15
003-000382-0000
Deed
12/10/2006
003-000386-0000
OH
Essington
Deed
09/30/1993
OR 265 1596
L-16
007-000160-0000
Deed
01/19/2001
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Reed
Deed
09/30/1993
OR 216 244
L-17
008-000009-000
Deed
08/28/1998
007-000623-0000
OH
Hoops/Woltz
Deed
08/27/1998
OR 222 343
L-18
003-000468-000
09/10/1998
09/16/1998
10/02/1998
10/28/1998
11/20/1998
OH
Fisher
Deed
08/22/2005
OR 325 692
L-19
003-000303-0105
Deed
06/29/2006
OR 345 297
OH
Rose Jr
Deed
09/30/1993
OR 283 725
L-20
007-000600-0101
Deed
06/25/2002
OH
Rose Sr
Deed
09/30/1993
OR 295 1279
L-21
007-000600-0100
Deed
05/06/2003
OH
John Rose
Deed
09/30/19993
OR 311 546
L-22
003-000123.0000
Deed
06/14/2004
OH
Humphrey
Deed
05/29/1999
OR 236 782
L-23
003-000411-0000
OH
Kiester
Deed
09/30/1993
OR 258 251
L-24
003-000194-0000
Deed
03/22/2000
OH
Black
Deed
06/29/2007
OR 345 297
L-25
003-000303-0102
Deed
05/05/2009
OR 361 583
OH
Cowgill
Deed
09/11/2009
OR 363 2485
L-26
003-000284-0104
003-000303-0108
OH
Sipe
Deed
05/28/2010
OR 369 665
L-27
003-000289-0000
OH
Peabody Development
Deed
06/24/1996
OR 166 428
L-28
(see document)
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Fisher
Deed
02/01/2010
OR 367 52
L-29
003-000303-0101
OH
Woltz
Deed
01/06/1998
OR 197 441
L-30
003-000468-0000
OH
Johnson
Deed
03/09/2006
OR 331 931
L-31
(see document)
OH
Foraker Heirs, LLC
Deed
10/12/2004
OR 315 84
L-32
007-000186-000
007-000184-0000
007-000185-000
OH
Jude
Deed
OR 366 2230
01/21/2010
L-33
003-000233-0000
OH
Jude
Deed
OR 366 2233
01/21/2010
L-34
003-000303-0200
OH
Steen
Deed
OR 367 48
02/02/2010
L-35
003-000235.0000
OH
Marion
Deed
OH 367 1039
02/25/2010
L-36
030-000303-0107
OH
McCauley
Deed
OR 367 38
02/01/2010
L-37
003-000284.0200
003-000284-0300
OH
Fister
Lease
06/11/2007
OR 344 2046
L-38
003-000296-0000
003-000296-0000
OH
Arnold
Lease
02/16/2008
OR 352 2637
L-39
003-000284-0101
OH
Johnson/Rambo
Lease
02/19/2007
OR 341 2102
L-40
007-000573-0000
007-000573-0100
007-000575-0000
OH
McCauley
Lease
03/17/2000
OR 257 2634
L-41
(see document)
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Z-Mak Enterprises
Lease
07/05/1994
OR 123 393
L-42
(see document)
OH
Cowgill
Lease
09/11/2009
OR 363 2489
L-43
(pt) 003-000284-0102
(pt) 003-000303-0103
OH
McCauley
Agreement
05/15/2010
OR 369 170
L-44
(see document)
OH
Holmes Limestone
Lease
02/01/2003
200503180016636
M-1
Multiple
(see document)
OH
Holmes Limestone
Deed
04/01/2005
OR 1184 1331
N-1
16-00756.000
OH
Tusco Land
Lease
02/24/2004
OR 1144 589
N-2
(see document)
OH
Mizer
Lease
03/03/2004
OR 1144 590
N-3
(see document)
OH
Beach
Lease
06/03/2004
OR 1157 1652
N-4
(see document)
OH
Keffer
Lease
06/03/2004
OR 1157 1651
N-5
(see document)
OH
Holmes Limestone
Lease
07/14/2005
OR 1194 2066
N-6
(see document)
Sublease
06/22/2005
OR 1194 2072
Amendment
08/12/2008
OR 1293 607
Amnd Sublease
08/12/2008
OR 1293 636
Amnd Sublease
04/01/2009
OR 1306 238
OH
Tusco Land
Lease
08/07/2006
OR 1269 2011
N-7
(see document)
OH
Ankrom
Lease
11/08/2005
OR 1269 2014
N-8
(see document)
OH
Ault
Lease
09/01/2005
OR 1269 2010
N-9
(see document)
Tax Parcel
Number(s) (not
certified see
document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Glauser
Lease
08/27/2007
OR 1269 2009
N-10
(see document)
OH
Horn
Lease
10/20/2006
OR 1269 2012
N-11
(see document)
OH
Mizer
Lease
06/24/2005
OR 1269 2015
N-12
(see document)
OH
Mutti
Lease
07/24/2007
OR 1269 2013
N-13
(see document)
OH
Shinaberry
Lease
07/24/2007
OR 1269 2008
N-14
(see document)
OH
Cantrell
Lease
09/30/2006
OR 1270 1582
N-15
(see document)
OH
Bau
Lease
11/03/2006
OR 1270 1584
N-16
(see document)
OH
Welch Brothers
Lease
05/05/2008
OR 1283 847
N-17
51-00359.000
OH
Crossman
Lease
01/11/2008
OR 1275 202
N-18
51-00568.000
OH
Kyle Limited
Lease
12/23/2008
OR 1298 415
N-19
07-00529.000
Partnership
07-00530.000
07-00531.000
07-00528.000
OH
Van Fossen
Lease
12/30/2008
OR 1298 414
N-20
48-00531.000
Re-recorded
OR 1301 1668
48-00532.000
48-00533.000
48-00534.000
OH
Creighton
Deed
02/25/2008
OR 1278 1695
N-21
71-00162.000
71-00160.000
71-00161.000
Tax Parcel Number(s)
(not certified
see document & tax
County
State
Name
Type of Acquisition
Document Date
Recording Data
Exhibit Attachment
records)
OH
Kopka
Lease
05/21/2010
OR 1331 1246
N-23
71-00366.000
OH
Frink
Lease
05/21/2010
OR 1331 1241
N-24
71-00958.000
71-00960.001
OH
Holmes Limestone
Lease
03/19/2010
OR 1327 593
N-25
(see document)
OH
Penn-Ohio
Lease
02/15/2006
OR 1270 1022
N-26
(see document)
Sublease
04/23/2010
OR 1329 605
OH
Berlin Mineral
Deed
07/17/2006
OR 1238 2127
N-27
07-00502.000
OH
Robt Linard
Deed
07/02/2009
OR 1310 580
N-28
16-00514.000
(water rights)
WV
Goodman
Lease
03/26/2004
Bk 307 255
O-1
(see document)
WV
Starvaggi
Lease
02/19/2003
Bk 306 129
O-2
(see document)
PA
Phoenix
Lease
08/07/2007
200727420
P-1
380-008-00-00-0016-00
Greenlawn
PA
Starvaggi
Lease
11/05/2007
200731037
P-2
380-008-00-00-0016-00
(Phoenix Greenlawn)
PA
Starvaggi
Lease
02/19/2003
200810189
P-3
380-014-00-00-0004-00
(PA & WV)
Addendum
02/27/2008
380-014-00-00-005-00
380-014-00-00-006-00
1.
Mortgagor is the fee owner of all real estate except real estate noted as Lease, Lease
and Addendum, Assignment of Leases, Sublease or Assignment of Sublease in the column
captioned Type of Acquisition.
2.
Identified Exhibits for legal descriptions of properties located in County and State of
recording are attached to the counterpart of this Supplement being recorded in such County
and State of recording.
3.
Identified Exhibits for legal descriptions of properties located in County or State other
than County and State of recording are intentionally omitted from the counterpart of this
Supplement being recorded in such County and State of recording
1.
0.780 acre (in one or more parcels) conveyed by Oxford Mining Company to Jean A. Powers
and Harding C. Powers by deed dated January 20, 2000 and recorded in
Belmont County Deed
Volume 754, Page 775
.
2.
17 +/- acres (in one or more parcels) conveyed by Oxford Mining Company to Capstone
Holding Company by deed dated December 16, 1999 and recorded in
Belmont County Deed
Volume 759, Page 460
.
3.
22 +/- acres (in one or more parcels) conveyed by Oxford Mining Company to Richard M.
Taylor and Jennifer D. Taylor by deed dated September 27, 2000 and recorded in
Belmont
County Deed Volume 761, Page 464
.
4.
10+/- acres (in one or more parcels) conveyed by Oxford Mining Company to Jeffco
Resources, Inc. by deed dated December 5, 2000 and recorded in
Belmont County Deed
Volume 763, Page 562
.
5.
3+/- acres (in one or more parcels) conveyed by Oxford Mining Company to Jeffco
Resources, Inc. by deed dated December 5, 2000 and recorded in
Belmont County Deed
Volume 763, Page 564
.
6.
7+/- acres (in one or more parcels) conveyed by Oxford Mining Company to Jeffco
Resources, Inc. by deed dated December 5, 2000 and recorded in
Belmont County Deed
Volume 763, Page 566
.
7.
26+/- acres (in one or more parcels) conveyed by Oxford Mining Company to Jeffco
Resources, Inc. by deed dated December 5, 2000 and recorded in
Belmont County Deed
Volume 763, Page 569
.
8.
87+/- acres (in one or more parcels) conveyed by Oxford Mining Company to Capstone
Holding Company by deed dated December 11, 2001 and recorded in
Belmont County Deed
Volume 773, Page 359
.
9.
36+/- acres (in one or more parcels) conveyed by Oxford Mining Company to Lewis G.
Stratton and Wanda F. Stratton by deed dated May 29, 2004 and recorded in
Belmont County
Deed Volume 799, Page 195
.
10.
24+/- acres (in one or more parcels) conveyed by Oxford Mining Company to Richard A.
Nowak by deed dated April 5, 2004 and recorded in
Belmont County Deed Volume 800, Page
690
.
11.
24.753 acres (in one or more parcels) conveyed by Oxford Mining Company LLC to Wharton
Sportsmens Club by deed dated April 2, 2008 and recorded in
Belmont County Official
Record Volume 151, Page 688
.
12.
34.33 acres (in one or more parcels) conveyed by Oxford Mining Company LLC to Robert A.
Shugert by deed dated December 4, 2009 and recorded in
Belmont County Official Record
Volume 211, Page 886
.
13.
200 acres (in one or more parcels) conveyed by Oxford Mining Company LLC to Belmont
County Port Authority by deed dated September 11, 2009 and recorded in
Belmont County
Official Record Volume 201, Page 45
.
14.
1.277 acres (in one or more parcels) conveyed by Oxford Mining Company, Inc. to Ungurean
Farm Partnership by deed dated January 19, 2000 and recorded in Coshocton County Official
Record Volume 177, Page 193.
15.
7.18 acres (in one or more parcels) conveyed by Oxford Mining Company, Inc. to Lester R.
Sharrock, et al by deed dated November 22, 1999 and recorded in Coshocton County Official
Record Volume 172, Page 958.
16.
251.4065 acres (in one or more parcels) conveyed by Oxford Mining Company, Inc. to T & C
Holdco LLC by deed dated July 5, 2007 and recorded in Coshocton County Official Record
Volume 448, Page 427.
17.
17.482 acres (in one or more parcels) conveyed by Oxford Mining Company, Inc. to Lester
R. Sharrock, et al by deed dated November 11, 1999 and recorded in Coshocton County Official
Record Volume 172, Page 169.
18.
13.772 acres (in one or more parcels) conveyed by Oxford Mining Company to Consolidation
Coal Company by deed dated December 20, 2002 and recorded in
Harrison County Official
Record Volume 134, Page 157
.
19.
Several surface parcels conveyed by Oxford Mining Company, Inc. to Tunnell Hill
Reclamation, LLC by Limited Warranty Deed dated April 11, 2005 and recorded in
Perry
County Official Record Volume 324, Page 298
.
20.
Several surface parcels conveyed by Oxford Mining Company, Inc. to Tunnell Hill
Reclamation, LLC by Limited Warranty Deed dated December 10, 2006 and recorded in
Perry
County Official Record Volume 340, Page 2021
.
21.
Several mineral parcels (except #5 and #6 coal and mining rights) conveyed by Oxford
Mining Company, Inc. to Tunnell Hill Reclamation, LLC by Limited Warranty Deed dated August
2, 2007 and recorded in
Perry County Official Record Volume 346, Page 2336
.
22.
1.23 acres (in one or more parcels) conveyed by Oxford Mining Company, Inc., to Charles
E. Rose by Quit Claim Deed dated May 6, 2003 and recorded in
Perry County Official
Record Volume 295, Page 1281
.
23.
51.52 acres and 180.73 acres (in one or more parcels) conveyed by Oxford Mining Company,
Inc. to Charles W. Owen Jr. and Kathy E. Owen by Quit Claim Deed dated January 21, 2005 and
recorded in
Perry County Official Record Volume 318, Page 2411
.
24.
34.88 acres (in one or more parcels) conveyed by Oxford Mining Company, Inc. to Thomas H.
Johnson, Jr. by Warranty Deed dated March 28, 2005 and recorded in
Perry County Official
Record Volume 320, Page 1446
.
25.
2.00 acres (in one or more parcels) conveyed by Oxford Mining. Corp. to Barbara L. Hill
by Warranty Deed dated September 18, 2003 and recorded in
Perry County Official Record
Volume 301, Page 2348
.
26.
0.36 acre conveyed by Oxford Mining Company to Albert Ervin Butcher and Debra K. Butcher
by Warranty Deed dated July 31, 1997 and recorded in
Perry County Official Record Volume
188, Page 220
.
27.
0.36 acre (in one or more parcels) conveyed by Oxford Mining Co. to Richard A. Goodin by
Warranty Deed dated August 13, 1997 and recorded in
Perry County Official Record Volume
189, Page 788.
28.
5.46 acres (in one or more parcels) conveyed by Oxford Mining Co. to Philip D. Munyan and
Lillian M. Munyan by Warranty Deed dated November 22, 1999 and recorded in
Perry County
Official Record Volume 252, Page 75
.
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Anna Loraine Cundiff, an individual (amended by Memorandum of Lease to add George Rudy Cundiff as a Lessor)
Lease
2/28/2008
Memorandum of Lease recorded in Deed Book 543, page 396
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-1
N/A
KY
Anna Loraine Cundiff, an individual
Lease
6/7/2006
Lease recorded in Deed Book 521, page 74, re-recorded in Deed Book 521, page 237
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-2
N/A
KY
Anna Loraine Cundiff, an individual
Lease
6/7/2006
Lease recorded in Deed Book 521, page 68, re-recorded in Deed Book 521, page 227
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-3
N/A
KY
Kirkpatrick-Beech Creek Mining
Lease
9/10/2001
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-4
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
C&R Coal Company, Inc.
Sublease
10/20/2006
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-5
N/A
KY
Tom McDonald Heirs etal.
Lease
See notes
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-6
N/A
KY
Bobby Dukes & Jonnie Dukes, h&w (see notes for original Lessor information)
Sublease
10/23/2003
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-7
N/A
KY
John Wesley Horn, single
Lease
5/24/2006
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-8
N/A
KY
Marjorie Dukes, unmarried
Lease
10/23/2003
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-9
N/A
KY
Glendell Horn and Martha Horn, h&w
Lease
12/8/2003
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-10
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Kenneth R. Dukes, unmarried
Lease
1/13/2004
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-11
N/A
KY
Bobby Dukes and Jonnie Dukes, his wife
Lease
10/23/2003
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-12
N/A
KY
William Thomas Dockins, individually, and as Sole Trustee f/b/o Karen Estelle Dockins; and Brenda Dockins, his wife
Lease
6/29/2009
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-13
N/A
KY
Florence Jane McPherson, and Virgil McPherson, her husband
Lease
6/29/2009
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-14
N/A
KY
Edwin & Exie Bandy
Lease
12/22/2003
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-15
N/A
KY
Billy & Patsy Kirtley
Lease
7/31/2004
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-16
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Rudy Cundiff
Coal Lease Option Agreement
9/27/2006
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-17
N/A
KY
R&G Leasing, LLC and Jonathan L. Rogers
Assignment and Assumption Agreement
7/31/2008
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-18
N/A
KY
Tom Eubanks 2378 S.R. 189 South Greenville, KY 42345
Lease
5/31/2007 *(see notes)
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-19
N/A
KY
Jeffrey L. Eubanks 196 Luzerne-Depoy Rd. Greenville, KY 42345
Lease
5/31/2007 *(see notes)
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-20
N/A
KY
Donald R. Lear & Judy Lear, his wife et al
Lease
9/12/2005
Surface Coal Mining and Option Lease recorded in Deed Book 522,
page 181 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-21
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Claude W. Lee & Alicetine Lee, his wife
Lease
8/7/2009
Memorandum of Coal Mining Lease recorded in Deed Book 543, page 956 [Assignment and Assumption of Leases Recorded at Deed Book 547, page 325]
Exhibit Q-22
N/A
KY
Ella J. Winn & Donald Winn, her husband
Lease
9/12/2005
Surface Coal Mining and Option Lease recorded in Deed Book 522, page 181 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-23
N/A
KY
Martha L. Blass (11650 State Route 175 South; Greenville, KY 42345)
Lease
9/12/2005
Surface Coal Mining and Option Lease recorded in Deed Book 522, page 181 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-24
N/A
KY
Flowel (William R. King)
Lease
9/12/2005
Surface Coal Mining and Option Lease recorded in Deed Book 522, page 181 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-25
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Ruby Smith
Lease
9/12/2005
Surface Coal Mining and Option Lease recorded in Deed Book 522, page 181 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-26
N/A
KY
William L. Lear & Sadie L. Lear
Lease
9/12/2005
Surface Coal Mining and Option Lease recorded in Deed Book 522, page 181 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-27
N/A
KY
Herbert W. Lear & Ilene L. Lear, his wife 11903 State Route 175 South Greenville, KY 42345 (1/8th interest)
Lease
8/20/2005
Memorandum of Lease recorded in Deed Book 522, page 165
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-28
N/A
KY
Jon Simms & Crystal Simms 565 Kennedy Rd. Greenville, KY 42345
Lease
10/9/2006
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-29
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Loren R. Lee & Kay Lee, his wife 193 Stoneybrook Dr. Greenwood, IN 46142
Lease
3/6/2006
Memorandum of Lease recorded in Deed Book 522, page 170
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-30
N/A
KY
Donald Lee & Ellen Lee, his wife 929 S. 250 W. Hebron, IN 46341
Lease
8/30/2005
Memorandum of Lease recorded in Deed Book 522, page 175
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 831]
Exhibit Q-31
N/A
KY
Talmage G. Rogers et al. (aka Rogers Bros)
Lease
12/4/1947
Deed Book 164, page 525
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-32
N/A
KY
J.L. Rogers Jr. etal. (aka Rogers Bros)
Supplemental Lease
1/8/1957
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-33
N/A
KY
Talmage G. Rogers Jr. et al. (aka Rogers Bros)
Extension of Lease
12/6/1962
N/A
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-34
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Martha F. Rogers, etal (aka Rogers Bros)
Third Supplemental Lease
1/1/1966
Deed Book 304, page 439 (Not certain this is a Deed Book)
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-35
N/A
KY
Sentry Royalty Company
Lease
10/20/1967
Deed Book 261, Page 228 (Recording info for Short Form Lease)
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-36
N/A
KY
Peabody Coal Company
Lease
10/6/1969
Lease Book 59, page 434
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-37
N/A
KY
Rogers Bros.
Partial Release of Coal Mining Lease
9/23/1986
Deed Book 376, page 610 (Not certain this is a Deed Book)
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-38
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
AMAX, Inc. (Assignor)
Assignment & Assumption Agreement
8/27/1987
Deed Book 403, page 584
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-39
N/A
KY
Meadowlark, Inc.
Lease
11/16/1999
Book 481, page 32 (may be Deed Book for a Memo of Surface & Mineral Lease Agreement)
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-40
N/A
KY
Lynx, Inc. (Assignor)
Assignment & Sublease Agreement
1/22/2001
Evidenced by Memorandum of Assignment & Sublease recorded in Book D481, page 039
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-41
N/A
KY
Meadowlark, Inc.
Corrected Lease
4/5/2001
Evidenced by Corrected Memorandum of Surface & Mineral Lease in Book D482, page 213 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-42
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Lynx, Inc.
Corrected Assignment & Sublease Agreement
4/11/2001
Eveidence by Corrected Memorandum of Assignment & Sublease recorded in Book D482, page 220
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-43
N/A
KY
Lynx, Inc.
Corrected Memorandum of Assignment & Sublease Agreement
4/12/2001
Book D482, page 220
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-44
N/A
KY
Lynx, Inc.
Amendment to Assignment and Sublease Agreement
10/10/2001
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-45
N/A
KY
Rogers Bros.
Settlement & Access Agreement
9/1/2001
N/A
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-46
KY
Meadowlark, Inc.
Amendment No. 1 to Surface and Mineral Lease Agreement
1/1/2003
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-47
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Crescent Coal Company; Justin Potter & Valera Blair Potter, his wife
Royalty Agreement
7/30/1955
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-48
N/A
KY
Potter Grandchildren, L.L.C. (successor to Cresent and Potter)
Modification of Agreement
4/4/2001
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-49
N/A
KY
Lexington Coal Company
Surface and MIneral Lease and Sublease
6/30/2009
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-50
N/A
KY
Peabody Development
Assignment & Assumption of Leasehold
9/30/2005
Deed Book 525, page 21 , and Deed Book 514, page 531 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-51
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Peabody Development
Assignment & Assumption of Leasehold
9/30/2005
Deed Book 514, page 506 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-52
N/A
KY
Peabody Development
Grant of Surface Mining Rights
11/21/2005
Deed Book 525, page 39, and Deed Book 516, page 14 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-53
N/A
KY
Douglas Wood and Sandra B. Wood
Lease
7/1/1996
Deed Book 137, page 662 and Deed Book 172, page 334 [Assignment and Assumption of Leases Recorded at Deed Book 181, page 285]
Exhibit Q-54
N/A
KY
Richard Reno and Jeanette Reno
Lease
2/2/1996
Deed Book 135, page 4
Exhibit Q-55
N/A
KY
Howard H. Revlett, et al
Lease
7/1/1996
Deed Book 137, page 638 and Deed Book 172, page 334 [Assignment and Assumption of Leases Recorded at Deed Book 181, page 285]
Exhibit Q-56
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Peabody Development, LLC
Lease
11/21/2005
Deed Book 525, page 39 and Deed Book 516, page 14 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-57
N/A
KY
Peabody Development, LLC
Partial Assignment of Mining Rights
9/30/2005
Deed Book 514, page 501
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-58
N/A
KY
Peabody Development, LLC/Tertelling
Partial Assignment and Assumption of Leasehold Estate
9/30/2005
Deed Book 525, page 21 , and Deed Book 514, page 531 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-59
N/A
KY
Peabody Development Company, LLC/Tertelling
Partial Assignment and Assumption of Leasehold Estate
9/30/2005
Deed Book 514, page 506
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-60
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Peabody Development Company, LLC and Peabody Coal Company, LLC
Lease
11/21/2005
Deed Book 525, page 39, and Deed Book 516, page 14 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-61
N/A
KY
Peabody Development Company, LLC & Peabody Coal Company, LLC
Grant of Surface Mining Rights
11/21/2005
Deed Book 525, page 39 and Deed Book 516, page 14 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-62
N/A
KY
Peabody Development Company, LLC & Peabody Coal Company, LLC
Easement Agreement
11/21/2005
Deed Book 516, page 25 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-63
N/A
KY
Peabody Development Company, LLC
Partial Assignment & Assumption of Leasehold Estate
11/21/2005
Deed Book 516, page 45 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-64
N/A
KY
John K. Vaught, a/k/a Kenny Vaught & Lisa Michelle Vaught, his wife 1704 S.R. 1379 Central City, KY 42330
Lease
11/4/2008
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-65
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Martha Rogers Haas, et al
Lease
7/17/2006
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-66
N/A
KY
Geibel Lumber Co., Lydia Geibel by Jon Geibel, POA and Jon Geibel, Agent for the Geibel Family P.O. Box 200 Greenville, KY 42345
Lease
8/24/2005
Lease /Sublease recorded in Deed Book 517, page 35 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-67
N/A
Ky
Geibel Lumber Co.,James Tardio, Executor of the Estate of Lydia Geibel, and John Geibel, Agent for the Geibel Family
Amendment to Lease/Sublease Agreement
11/11/2008
See Lease / Sublease recorded in Deed Book 517, page 35 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-68
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Gerald A. Liles & Judith Ann Liles, his wife 69 Shady Acres Ln. Greenville, KY 42345
Lease
9/13/2006
Lease recorded in Deed Book 529, page 413 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-69
N/A
KY
James H. Edwards 1266 S.R. 831 Greenville, KY 42345
Lease
9/7/2006
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-70
N/A
KY
Gerald A. Liles & Judith Ann Liles, his wife 69 Shady Acres Ln. Greenville, KY 42345
Lease
8/3/2006
Lease /Sublease recorded in Deed Book 529, page 421 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-71
N/A
KY
Elroy Lester Shelor, et al
Lease
6/23/2009
Memorandum of Lease recorded in Deed Book 543, page 668 [Assignment and Assumption of Leases Recorded at Deed Book 547, page 325]
Exhibit Q-72
N/A
KY
Terry Adkins 737 Blaine Street, Sand Coulee, MT
Lease
12/2/2005
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-73
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Hilltop Haven, Inc. P.O. Box 726 Burkesville, KY
Lease
5/30/2001
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-74
N/A
KY
Shirley A. Adler
Surface Lease Option
3/26/2008
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-75
N/A
KY
Roger A France & Ellen L. France; Ellen France Signed but not listed as Lessor at front of Lease
Surface Lease Option
1/11/2008
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 821]
Exhibit Q-76
N/A
KY
Howard Covington, Mary Covington, Morris Bandy, and Carolyn Bandy
Lease
6/23/2009
Memorandum of Coal Mining Lease recorded in Deed Book 544, page 584 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-77
N/A
KY
Richard T. Williams & Tonya L. Williams, his wife 631 Pallet Mill Rd. Greenville, KY 42345
Lease
6/25/2007
Not Recorded [Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-78
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Joseph P. Liles 3111 4th St., Apt. 320 Santa Monica, CA 90405
Lease
8/3/2006
Lease /Sublease recorded in Deed Book 529, page 421 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-79
N/A
KY
Joseph P. Liles 3111 4th St., Apt. 320 Santa Monica, CA 90405
Lease
9/13/2006
Lease recorded in Deed Book 529, page 413 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-80
N/A
KY
Louis G. (Gayle) Baggett & Brenda J. Baggett (2877 Hwy. 62 W., Greenville, KY 42345)
Lease
4/30/2009
Memorandum of Coal Mining Lease recorded in Deed Book 544, page 527 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-81
N/A
KY
Lisa Fairchild & John Fairchild III (297 Baggett Ln, Greenville, KY 42345)
Lease
3/5/2009
Memorandum of Coal Mining Lease recorded in Deed Book 544, page 245 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-82
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
H.C. Epley & Betty Epley, h&w, James K. Putman & Ilene A. Putman, Trustees of the Putman Family Trust, Linnie Putman (Widow)
Lease
11/7/2005
N/A
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-83
N/A
KY
James K. Putman & Ilene A. Putman, Trustees of the Putman Family Trust, Linnie Putman, Sondra Epley; Kevin Epley & Melissa Epley, his wife
Amendment/Term Extension & Renewal Agreement (#1)
1/18/2008
N/A
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-84
N/A
KY
James K. Putman & Ilene A. Putman, Trustees of the Putman Family Trust, Linnie Putman, Sondra Epley;
Amendment to Lease (#2)
7/1/2009
N/A
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-85
N/A
KY
Midsouth Energy, Inc.
Assignment of Coal Lease
7/20/2009
Deed Book 544, page 663 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-86
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Captain & Dana, Inc. (515 Gishton Rd, Central City, KY 42330)
Sublease Agreement to Surface Mine Coal
8/21/2007
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-87
N/A
KY
Captain & Dana, Inc. (515 Gishton Rd, Central City, KY 42330)
Lease
8/21/2007
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 837]
Exhibit Q-88
N/A
KY
Rogers Brothers
Coal Mining Lease Amendment
10/26/2002
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-89
N/A
KY
Peabody Development Company, LLC
Partial Assignment & Assumption of Leasehold Estate
11/21/2005
Deed Book 516, page 34 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-90
N/A
KY
Martha Rogers, et al
Coal Mining Lease Amendment
11/30/1965
Deed Book 252, page 343 [Assignment and Assumption of Leases Recorded at Deed Book 544, page 807]
Exhibit Q-91
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Catherine Fowler, et al
Shop Lease
7/1/2007
Not Recorded
[Assignment and Assumption of Leases Recorded at Deed Book 181, page 330]
Exhibit Q-92
N/A
KY
Phoenix Coal Corp.
Deed
9/30/2009
Deed Book 544, page 804
Exhibit Q-93
N/A
KY
Phoenix Coal Corp.
Deed
9/30/2009
Deed Book 181, page 313
Exhibit Q-94
N/A
KY
R&L Winn, inc.
Deed
3/22/2010
Deed Book 547, page 275
Exhibit Q-95
N/A
KY
Rogers, et al
Lease
11/12/2009
Deed Book 545, page 1
Exhibit Q-96
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Rogers, et al
Lease
11/30/2009
Not Recorded
Exhibit Q-97
N/A
KY
Cyprus Creek Land Resources, LLC
Partial Assignment of Lease
12/31/2009
Deed Book 546, page 97
Exhibit Q-98
N/A
KY
Evergreen Mineral Co.
Assignment of Leases
4/12/2010
Deed Book 547, page 325
Exhibit Q-99
N/A
KY
Department of Miliary Affairs
Assignment of Leases
4/12/2010
Deed Book 547, page 325
Exhibit Q-100
N/A
KY
John K. Vaught
Lease
6/16/2010
To Be Recorded
Exhibit Q-101
N/A
KY
Cyprus Creek Land Resources, LLC
Deed
12/31/2009
Deed Book 546, page 79
Exhibit Q-102
N/A
Tax Parcel
Number(s) (not
certified see
Type of
Document
Exhibit
documents & tax
County
State
Name
Acquisition
Date
Recording Data
Attachment
records)
KY
Development Design & Construction, LLC
Lease
4/2/2010
To Be Recorded
Exhibit Q-103
N/A
KY
Phoenix Coal Processing
Assignment of Fleeting Rights
9/30/2009
Deed Book 181, page 331
Exhibit Q-104
N/A
KY
Phoenix Coal Processing
Assignment of Powerline Easement
9/30/2009
Deed Book 181, page 335
Exhibit Q-105
N/A
KY
Cyprus Creek Land Resources, LLC
Option Agreement
12/31/2009
Deed Book 546, page 121
Exhibit Q-106
N/A
KY
Cyprus Creek Land Resources, LLC
Haulroad Easement
12/31/2009
Deed Book 546, page 160
Exhibit Q-107
N/A
Financial
Name of Credit
Institution
Party on Account
Account Number(s)
Account Type
Oxford Mining
Company, LLC
069-134228
Money Market
Financial
Name of Credit
Institution
Party on Account
Account Number(s)
Account Type
Hartford, CT
Oxford Mining
Company, LLC
619-44679
Reserved Money Market
UCC/Financing
Filing
Statement Number
Jurisdiction
Debtor
Secured Party
S/N(s)
Ohio Secretary of
State
Oxford Resource Partners, LP
Marquette Equipment Finance, LLC
Republic Bank, Inc.
GAE2170, GAE2173,
GAE2175, 20008, 20010
Ohio Secretary of
State
Oxford Mining Company, LLC
HCR Holdings, LLC
N/A
Ohio Secretary of
State
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Ohio Secretary of
State
Oxford Mining Company, LLC
Sovereign Bank
110, 111, 112, 113
Ohio Secretary of
State
Oxford Mining Company, LLC
OMCO Leasing Corporation
7HR00203
Ohio Secretary of
State
Oxford Mining Company, LLC
Sovereign Bank
VELS 4000R7, S5R001189
Ohio Secretary of
State
Oxford Mining Company, LLC
General Electric Capital
Corporation
T$BH, 8624,
1CYDCV5807T048139,
GEB00242, GEB00243,
30014
Ohio Secretary of
State
Oxford Mining Company, LLC
General Electric Capital
Corporation
30076
Ohio Secretary of
State
Oxford Mining Company, LLC
General Electric Capital
Corporation
7PZ0752, 8RP00543,
7CP00785
Ohio Secretary of
State
Oxford Mining Company, LLC
OMCO Leasing Corporation
93U00809
Ohio Secretary of
State
Oxford Mining Company, LLC
OMCO Leasing Corporation
93U01483
Ohio Secretary of
State
Oxford Mining Company, LLC
OMCO Leasing Corporation
9TZ00449
Ohio Secretary of
State
Oxford Mining Company, LLC
OMCO Leasing Corporation
7HR00059
Ohio Secretary of
State
Oxford Mining Company, LLC
Marquette Equipment Finance, LLC
Republic Bank, Inc.
GAE2170, GAE2173,
GAE2175, 20008, 20010
Ohio Secretary of
State
Oxford Mining Company, LLC
OMCO Leasing Corporation
AGS02099
Ohio Secretary of
State
Oxford Mining Company, LLC
Consolidated Coal Company
N/A
Ohio Secretary of
State
Oxford Mining Company, LLC
Bill Miller Equipment Sales, Inc.
2YR430, 2YR438, 2YR149
Ohio Secretary of
State
Oxford Mining Company, LLC
Columbus Equipment Company
10718
Ohio Secretary of
State
Oxford Mining Company, LLC
Bill Miller Equipment Sales, Inc.
9XOLD280847
Ohio Secretary of
State
Oxford Mining Company, LLC
Caterpillar Financial Services
Corporation
GEB00480
Ohio Secretary of
State
Oxford Mining Company, LLC
Komatsu Financial Limited
Partnership
30121, 30129
Ohio Secretary of
State
Oxford Mining Company, LLC
Komatsu Financial Limited
Partnership
20176
UCC/Financing
Filing
Statement Number
Jurisdiction
Debtor
Secured Party
S/N(s)
Ohio Secretary of
State
Oxford Mining Company, LLC
Komatsu Financial Limited
Partnership
30121
Ohio Secretary of
State
Oxford Mining Company, LLC
Komatsu Financial Limited
Partnership
30129
Ohio Secretary of
State
Oxford Mining Company, LLC
Komatsu Financial Limited
Partnership
20176
Ohio Secretary of
State
Oxford Mining Company, LLC
Dell Financial Services L.L.C.
N/A
Ohio Secretary of
State
Daron Coal Company, LLC
Firstlight Funding I, Ltd.
N/A
Kentucky Secretary
of State
Oxford Mining Company
Kentucky, LLC
Firstlight Funding I, Ltd.
N/A
Kentucky Secretary
of State
Oxford Mining Company
Kentucky, LLC
Cyprus Creek Land Resources, LLC
N/A
Kentucky Secretary
of State
Oxford Mining Company
Kentucky, LLC
Caterpillar Financial Services
Corporation
ABJ00602, 7PZ01450,
7PZ75010, JRP01612,
JRP01613, JRP01866,
H4C00345, JRP01234,
7PZ75009, JRP01305,
7PZ01449, JRP01367,
JRP01506, JRP01504
Henderson County,
KY Recorder
Oxford Mining Company
Kentucky, LLC
Firstlight Funding I, Ltd.
N/A
Henderson County,
KY Recorder
Oxford Mining Company
Kentucky, LLC
Firstlight Funding I, Ltd.
N/A
McLean County, KY
Recorder
Oxford Mining Company
Kentucky, LLC
Firstlight Funding I, Ltd.
N/A
McLean County, KY
Recorder
Oxford Mining Company
Kentucky, LLC
Firstlight Funding I, Ltd.
N/A
Carroll County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Washington County,
PA Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Athens County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
UCC/Financing
Filing
Statement Number
Jurisdiction
Debtor
Secured Party
S/N(s)
Delaware Secretary
of State
Oxford Resource Partners, LP
Firstlight Funding I, Ltd.
N/A
Delaware Secretary
of State
Oxford Resource Partners,
LP and Oxford Mining
Company, LLC
Marquette Equipment Finance, LLC
Republic Bank, Inc.
(by assignment)
GAE2170, GAE2173,
GAE2175, 20008, 20010
Delaware Secretary
of State
Oxford Resources GP, LLC
Firstlight Funding I, Ltd.
N/A
Tuscarawas County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Tuscarawas County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Tuscarawas County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Jefferson County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Jefferson County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Jefferson County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Jefferson County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Coshocton County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Coshocton County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Muskingum County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Morgan County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Morgan County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Guernsey County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Guernsey County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
UCC/Financing
Filing
Statement Number
Jurisdiction
Debtor
Secured Party
S/N(s)
Columbiana County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Columbiana County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Columbiana County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Columbiana County,
OH Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Noble County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Noble County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
200800000026
Perry County, OH
Recorder
Oxford Mining Company, LLC
Peabody Development Company, LLC
HCR Holdings, LLC
N/A
Perry County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Perry County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Perry County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Perry County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Belmont County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Belmont County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Belmont County, OH
Recorder
Oxford Mining Company, LLC
Firstlight Funding I, Ltd.
N/A
Muhlenberg County,
KY Recorder
Oxford Mining Company -
Kentucky, LLC
Firstlight Funding I, Ltd.
N/A
Muhlenberg County,
KY Recorder
Oxford Mining Company -
Kentucky, LLC
Firstlight Funding I, Ltd.
N/A
UCC/Financing
Filing
Statement Number
Jurisdiction
Debtor
Secured Party
S/N(s)
Muhlenberg County,
KY Recorder
Oxford Mining Company -
Kentucky, LLC
Cyprus Creek Land Resources, LLC.
N/A
Henderson County,
KY Recorder
Phoenix Newco, LLC
Firstlight Funding I, Ltd.
N/A
Henderson County,
KY Recorder
Phoenix Newco, LLC
Firstlight Funding I, Ltd.
N/A
Debt of the Loan Parties under the Existing Facility Agreement.
Debt of the Loan Parties to Peabody Energy Corporation for the deferred
purchase price for coal reserves having an outstanding principal balance of $2,000,000.
Debt of Harrison Resources to CONSOL Energy for the deferred purchase price
for coal reserves having an outstanding balance of $1,773,000.
Debt of the Loan Parties to CONSOL Energy for the deferred purchase price for
coal reserves having an outstanding principal balance of not more than $1,500,000.
Debt of Harrison Resources to CONSOL Energy for the deferred purchase price
for coal reserves having an outstanding balance of $13,458,333 (there additionally will be
royalties estimated at $2,691,667, increasing the deferred purchase price by the amount of
the royalties).
Covenant
Date of Completion
Borrower shall deliver to the
applicable insurance company an assignment
in form and substance reasonably acceptable
to the Administrative Agent, executed by
the Borrower and pursuant to which the
Borrower collaterally assigns to the
Administrative Agent, for the benefit of
the Lenders, its interest in any Key-Man
Life Insurance Policies.
Within three (3) Business Days
of the Effective Date
Borrower shall either (i) deliver
Deposit Account Control Agreements or
Securities Account Control Agreements, as
applicable, executed by the applicable
depository bank or securities intermediary
in a form reasonably satisfactory to
Administrative Agent for all deposit
accounts and securities accounts listed on
Schedule 3 and 4 to the Security Agreement,
to the extent such accounts remain open as
of July 30, 2010 or (ii) move such accounts
to Citibank, N.A. or Citibank Global
Markets, Inc., as applicable.
July 30, 2010
Borrower shall use commercially
reasonable efforts to make the notices and
to obtain and have executed all the
consents listed on
Annex A
attached hereto,
in a form reasonably satisfactory to the
Administrative Agent.
August 31, 2010
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5/3/04 | 2 |
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5/3/04 | 4 |
Specification A | Specification B | |||
Contract Year | Contract Quantity | Contract Quantity | ||
2005
|
[*] | [*] | ||
2006
|
[*] | [*] | ||
2007
|
[*] | [*] | ||
2008
|
[*] | [*] | ||
2009 (First Extended Term, if elected)
|
[*] | [*] | ||
2010 (Second Extended Term, if elected)
|
[*] | [*] |
5/3/04 | 5 |
Contract Year | Specification A | Specification B | Specification C | |||||||||||||
2006 |
Specification A deliveries would
run through March 31, 2007, and
Specification C deliveries begin
April 1, 2007.
|
[*] | [*] | [*] | ||||||||||||
2007 |
|
[*] | [*] | [*] | ||||||||||||
|
[*] | |||||||||||||||
2008 |
|
[*] | [*] | |||||||||||||
2009 |
|
[*] | ||||||||||||||
2010 |
Specification C deliveries would
continue through March 31, 2012.
|
[*] | ||||||||||||||
2011 |
|
[*] | ||||||||||||||
2012 |
|
[*] |
5/3/04 | 6 |
5/3/04 | 7 |
5/3/04 | 8 |
5/3/04 | 9 |
FOB Plant | ||||||||
Contract Year | Specification A | Specification B | ||||||
2005
|
[*] per ton | [*] per ton | ||||||
2006
|
[*] per ton | [*] per ton | ||||||
2007
|
[*] per ton | [*] per ton | ||||||
2008
|
[*] per ton | [*] per ton | ||||||
2009 (First Extended Term, if elected)
|
[*] per ton | [*] per ton | ||||||
2010 (Second Extended Term, if elected)
|
[*] per ton | [*] per ton |
FOB Plant Rehobeth | ||||||||
Contract Year | Specification A | Specification B | ||||||
2005
|
[*] per ton | [*] per ton | ||||||
2006
|
[*] per ton | [*] per ton | ||||||
2007
|
[*] per ton | [*] per ton | ||||||
2008
|
[*] per ton | [*] per ton | ||||||
2009 (First Extended Term, if elected)
|
[*] per ton | [*] per ton | ||||||
2010 (Second Extended Term, if elected)
|
[*] per ton | [*] per ton |
FOB Rail Cadiz | ||||||||
Contract Year | Specification A | Specification B | ||||||
2005
|
[*] per ton | [*] per ton | ||||||
2006
|
[*] per ton | [*] per ton | ||||||
2007
|
[*] per ton | [*] per ton | ||||||
2008
|
[*] per ton | [*] per ton | ||||||
2009 (First Extended Term, if elected)
|
[*] per ton | [*] per ton | ||||||
2010 (Second Extended Term, if elected)
|
[*] per ton | [*] per ton |
5/3/04 | 10 |
5/3/04 | 11 |
5/3/04 | 12 |
(i) | it is duly organized, validly existing and in good standing under the laws of jurisdiction of its formation; |
5/3/04 | 13 |
(ii) | it has all regulatory authorizations necessary for it to legally perform its obligations under this Agreement; | ||
(iii) | the execution, delivery and performance of this Agreement are within its powers, have been duly authorized by all necessary action and do not violate any of the terms and conditions in its governing documents, any contracts to which it is a party or any law, rule, regulation, order or the like applicable to it; | ||
(iv) | this Agreement and each other document executed and delivered in accordance with this Agreement constitutes its legally valid and binding obligation enforceable against it in accordance with its terms, subject to any equitable defenses; | ||
(v) | Buyer is acting as an agent for disclosed Parties, and Seller is acting for its own account; each Party has made its own independent decision to enter into this Agreement and as to whether this Agreement is appropriate or proper for it based upon its own judgment, is not relying upon the advice or recommendations of the other Party in so doing, and is capable of assessing the merits of and understanding, and understands and accepts, the terms, conditions and risks of this Agreement; | ||
(vi) | it is not bankrupt and there are no Bankruptcy Proceedings pending or being contemplated by it or, to its knowledge, threatened against it which would result in it being or becoming bankrupt; | ||
(vii) | there is not pending or, to its knowledge, threatened against it or any of its Affiliates any legal proceedings that could materially adversely affect its ability to perform its obligations under this Agreement; | ||
(viii) | no Event of Default with respect to it has occurred and is continuing and no such event or circumstance would occur as a result of its entering into or performing its obligations under this Agreement; | ||
(ix) | it is a forward contract merchant and this Agreement is a forward contract within the meaning of the United States Bankruptcy Code; | ||
(x) | it has entered into this Agreement in connection with the conduct of its business and it has the capacity or ability to make or take delivery of all Coal referred to in this Agreement; | ||
(xi) | with respect to this Agreement, it is an eligible contract participant as defined in Section 1a(12) of the Commodity Exchange Act, as amended [7USC § 1a(12)]; | ||
(xii) | all applicable information that is furnished in writing by it or on behalf of it to the other Party pursuant to this Agreement (as described on Schedule 10, attached hereto and hereby made a part of this Agreement) is as of the date provided true, accurate and complete in every material respect. For purposes of this representation, financial information provided via posting on the Internet shall be deemed to be written information provided to the other Party; | ||
(xiii) | no event or circumstance exists at any Approved Production Source (as provided under Schedule 3.1-B), that would constitute an event of Force Majeure under this Agreement. |
5/3/04 | 14 |
5/3/04 | 15 |
a) | Title to and risk of loss of the Coal will pass to Buyer as the trucks are unloaded at the Designated Delivery Point. | ||
b) | Title to and risk of loss (except as provided in Schedule 2.4-B) of the Coal will pass to Buyer as the loaded railcars are pulled from the Designated Delivery Point. | ||
c) | Title shall revert back to Seller immediately upon any rejection by Buyer as provided elsewhere in this Agreement. |
5/3/04 | 16 |
5/3/04 | 17 |
a) | the Settlement Amount that would be owed to the Non-Defaulting Party; plus | ||
b) | if the Non-Defaulting Party is Seller, the amount equal to aggregate of the amounts Seller is entitled to receive under this Agreement for Coal scheduled during the 60 day period preceding the Material Adverse Change (the amount of said Performance Assurance to be adjusted at the beginning of each subsequent quarter to reflect amounts then owing). |
5/3/04 | 18 |
5/3/04 | 19 |
5/3/04 | 20 |
5/3/04 | 21 |
5/3/04 | 22 |
5/3/04 | 23 |
5/3/04 | 24 |
5/3/04 | 25 |
5/3/04 | 26 |
5/3/04 | 27 |
5/3/04 | 28 |
Weighted Average As-Received Basis | ||||||||
Contracted | Half Month (A)* | Applicable Lot (B)* | ||||||
Half-Month | Suspension Limit | Suspension Limit (D)* | ||||||
SPECIFICATION A:
|
||||||||
Calorific Value (Btu/lb.)
|
[*] | [*] | [*] | |||||
Moisture (%)
|
[*] | [*] | [*] | |||||
Ash (%)
|
[*] | [*] | [*] | |||||
Volatile Matter (%)
|
[*] | [*] | [*] | |||||
Hardgrove Grindability
|
[*] | [*] | [*] | |||||
Sulfur Dioxide (lbs. S0
2
/MMBtu) (C)*
|
[*] | [*] | [*] | |||||
Ash Fusion Temp. (H=1/2w) °F Red. Atm
|
[*] | [*] | [*] | |||||
|
||||||||
SPECIFICATION B:
|
||||||||
Calorific Value (Btu/lb.)
|
[*] | [*] | [*] | |||||
Moisture (%)
|
[*] | [*] | [*] | |||||
Ash (%)
|
[*] | [*] | [*] | |||||
Volatile Matter (%)
|
[*] | [*] | [*] | |||||
Hardgrove Grindability
|
[*] | [*] | [*] | |||||
Sulfur Dioxide (lbs. S0
2
/MMBtu) (C)*
|
[*] | [*] | [*] | |||||
Ash Fusion Temp. (H=1/2w) °F Red. Atm
|
[*] | [*] | [*] | |||||
|
||||||||
SPECIFICATION C:
|
||||||||
Calorific Value (Btu/lb.)
|
[*] | [*] | [*] | |||||
Moisture (%)
|
[*] | [*] | [*] | |||||
Ash (%)
|
[*] | [*] | [*] | |||||
Volatile Matter (%)
|
[*] | [*] | [*] | |||||
Hardgrove Grindability
|
[*] | [*] | [*] | |||||
Sulfur Dioxide (lbs. S0
2
/MMBtu) (C)*
|
[*] | [*] | [*] | |||||
Ash Fusion Temp. (H=1/2w) °F Red. Atm
|
[*] | [*] | [*] | |||||
# Ash/MMBtu:
|
[*] | [*] | [*] |
Definitions: | ||
N/A: Not Applicable | ||
(A) = | the Half-Month weighted average analysis result (as determined under Article VIII of this Agreement). | |
(B) = | the analysis result of the sample (or composite of samples, if more than one) representing each days unloading of Coal, or, at Buyers election, a composite of two or more such days unloadings (a days unloading shall mean all Coal unloaded on a given day between the hours of 12:01 a.m. to 12:00 a.m.). | |
(C) = | For the purpose of determining the pounds of sulfur dioxide per million Btu and pounds Ash per million Btu, the figures shall be rounded to the nearest one hundredth. For example, [*] pounds SO 2 per million Btu shall mean [*] pounds SO 2 per million Btu, while [*] pounds SO 2 per million Btu shall mean [*] pounds SO2 per million Btu and shall be deemed, for example, not to have met a [*] pounds SO 2 per million Btu specification. | |
(D) = | Buyer shall also have the right to reject any Coal that: 1) has a maximum topsize exceeding [*] when delivered to the Plant or exceeds [*] capable of passing a [*] square wire cloth sieve; 2) has a maximum topsize exceeding [*] if delivered to CCPP; 3) is not free flowing and free of extraneous material upon unloading; or 4) has intermediate sizes (including fines) added or removed. | |
(E) = | the suspension specification for grindability shall be no less than X, where X = Contracted Btu times [*], divided by the actual weighted average as-received calorific value of the coal for such lot. |
5/3/04 | 29 |
Coal | Ohio | |||||||||||
Mine | Reserves | Seam | County | |||||||||
Boswell
|
[*] | 8,9 | Belmont | |||||||||
Egypt Valley East
|
[*] | 9 | Belmont | |||||||||
Martin
|
[*] | 8 | Belmont/Harrison | |||||||||
Sexton
|
[*] | 8,8A,9 | Harrison | |||||||||
Daron
|
[*] | 8,8A,9 | Harrison | |||||||||
New Lexington
|
[*] | 5,6 | Perry | |||||||||
|
||||||||||||
Subtotal Strip 1
|
[*] | |||||||||||
|
||||||||||||
Plainfield II
|
[*] | 5,6 | Guernsey/Coshocton | |||||||||
Little Africa
|
[*] | 5,6 | Coshocton | |||||||||
Plainfield III
|
[*] | 5,6 | Guernsey/Coshocton | |||||||||
Otsego
|
[*] | 6 | Guernsey/Muskingum | |||||||||
Other Plainfield
|
[*] | 5,6 | Guernsey | |||||||||
Stonecreek
|
[*] | 5,6,7 | Tuscarawas | |||||||||
Stillwater
|
[*] | 7 | Tuscarawas | |||||||||
Miley
|
[*] | 6 | Coshocton | |||||||||
|
||||||||||||
Subtotal Strip 2
|
[*] |
Coal | Ohio | |||||||||||
Mine | Reserves | Seam | County | |||||||||
Seam | County | |||||||||||
Tusky #6
|
[*] | 6 | Tuscarawas/Harrison | |||||||||
Rush Twp #6
|
[*] | 6 | Tuscarawas | |||||||||
|
||||||||||||
Subtotal Underground
|
[*] | |||||||||||
|
||||||||||||
Grand Totals
|
[*] | 6 Seams | 7 Counties |
FOB Plant or | ||||||
FOB Railcar | ||||||
|
Cadiz Loadout | OPSL No. CUOH-10045 | ||||
|
Rehobeth Loadout | OPSL No. OSRR-1009 |
5/3/04 | 30 |
5/3/04 | 31 |
5/3/04 | 32 |
5/3/04 | 33 |
5/3/04 | 34 |
5/3/04 | 35 |
5/3/04 | 36 |
TABLE OF CONTENTS | Page No. | |||||
|
Preamble | 1 | ||||
|
Definitions | 1-5 | ||||
ARTICLE I
|
Term and Delivery Period | 5 | ||||
ARTICLE II
|
Obligations and Deliveries | 5 | ||||
Section 2.1
|
Contract Quantity
|
5 | ||||
Section 2.2
|
Reconsignment and/or Resale Rights
|
6 | ||||
Section 2.3
|
Scheduling
|
7 | ||||
Section 2.4
|
Delivery
|
7 | ||||
Section 2.5
|
Option(s) Exercise
|
7 | ||||
Section 2.6
|
Rejection and Suspension
|
7 | ||||
ARTICLE III
|
Quality Specifications | 8 | ||||
ARTICLE IV
|
Billing and Payment; Financial Reports | 9 | ||||
ARTICLE V
|
Contract Price | 10 | ||||
ARTICLE VI
|
Taxes and Other Liabilities | 10 | ||||
ARTICLE VII
|
Adjustments to the Contract Price (for Quality) | 12 | ||||
ARTICLE VIII
|
Weighing, Sampling, and Analysis | 12 | ||||
ARTICLE IX
|
Other Governmental Legislation, Regulations, and Orders | 12 | ||||
ARTICLE X
|
Representations | 13 | ||||
ARTICLE XI
|
Audit | 15 | ||||
ARTICLE XII
|
Force Majeure | 15 | ||||
ARTICLE XIII
|
Warranties | 16 | ||||
ARTICLE XIV
|
Title, Risk of Loss, and Indemnity | 16 | ||||
ARTICLE XV
|
Netting and Set Off | 17 | ||||
ARTICLE XVI
|
Calculation of Damages | 17 | ||||
ARTICLE XVII
|
Events of Default, Remedies and Limitation of Liabilities | 18 | ||||
ARTICLE XVIII
|
Grant of Security Interest | 19 | ||||
ARTICLE XIX
|
Holding and Using of Performance Assurance | 19 | ||||
ARTICLE XX
|
Early Termination Payment and Remedies | 20 | ||||
ARTICLE XXI
|
Successors, Assigns, and Assignment | 20 | ||||
ARTICLE XXII
|
Government Contractor Compliance Certificate | 21 | ||||
ARTICLE XXIII
|
Counterparts, Survival and Severability | 22 | ||||
ARTICLE XXIV
|
Expenses | 22 | ||||
ARTICLE XXV
|
Non-Waiver and Duty to Mitigate | 22 | ||||
ARTICLE XXVI
|
Addresses for Notices | 22 | ||||
ARTICLE XXVII
|
Confidentiality | 23 | ||||
ARTICLE XXVIII
|
Entire Agreement, Amendments, and Interpretation | 23 | ||||
ARTICLE XXIX
|
Governing Law; Waiver of Jury Trial | 24 | ||||
ARTICLE XXX
|
Venue | 24 | ||||
ARTICLE XXXI
|
Imaged Agreement | 24 | ||||
ARTICLE XXXII
|
Major Technological Improvements | 24 | ||||
Schedule 2.4
|
Transportation Specifications | 26-28 | ||||
Schedule 3.1-A
|
Quality Specifications | 29 | ||||
Schedule 3.1-B
|
Approved Prod Sources/Reserves/Des. Del. Point | 30 | ||||
Schedule 7.2
|
Quality Adjustments | 31-32 | ||||
Schedule 8.1
|
Weighing, Sampling, and Analysis | 33 | ||||
Schedule 10
|
List of Documents Provided | 35 |
5/3/04 | 37 |
Re: |
Coal Supply Agreement No. 10-62-04-900
dated as of May 21, 2004, between American Electric Power Service Corporation as agent for Columbus Southern Power Company (Buyer), and Oxford Mining Company, Inc. (Seller) |
|
Amendment No. 2005-1 |
1) | Article I paragraph two shall be deleted and restated as such: Provided this Agreement is still in effect, Buyer shall have the optional right, but not the obligation, to extend the term of this Agreement for three one-year extensions, the first of which shall be referred to as the First Extended Term and shall begin January 1, 2009 and end December 31, 2009. Should Buyer elect the First Extended Term, then a second one-year term extension shall become available and shall be referred to as the Second Extended Term and shall begin on January 1, 2010 and end on December 31, 2010. Should Buyer elect the Second Extended Term, then a third one-year term extension shall become available and shall be referred to as the Third Extended Term and shall begin on January 1, 2011 and end December 31, 2011. Each such election shall be referred to as an Option for Coal produced from reserves of Coal dedicated to this Agreement in Schedule 3.1-B hereof. | ||
2) | That Article II Section 2.1 paragraph one shall be amended by the addition of the following to the table set forth therein: |
Specification A | Specification B | |||||||
Contract | Contract | |||||||
Contract Year | Quantity | Quantity | ||||||
2011 (Third Extended Term, if elected)
|
[*] | [*] |
3) | That Article II Section 2.1 paragraph four shall be deleted and restated as such: At such time, if any, that Buyer elects to purchase Specification C Coal, Buyer shall also have the option to elect to reduce purchases of Specification B Coal to [ * ] tons per year. The purchase of any revised quantities of Specification B Coal are to commence concurrently with the purchase of Specification C Coal and continue throughout the remaining Term, as set forth in Article I, of this Agreement, but not thereafter ( no later than December 31, 2011 ). If Buyers election shall become effective during a Contract Year, then the quantities of Specifications A, B, and C Coal to be purchased and sold during such Year shall be determined on a pro rata basis. | ||
4) | That Article II Section 2.1 paragraphs six and seven shall be deleted and restated as such: During each Contract Year except for the Third Extended Term , if elected , Buyer shall have the right to increase the Contract Quantity for Specification A and/or Specification B Coal by 200,000 tons per half-year (January through June or July through December) (hereinafter the Half-Year Quantity Option) by notifying Seller of its election to take such Half-Year Quantity Option at least ninety (90) days prior to the beginning of the applicable half-year period. | ||
5) | That the Agreement shall be amended by inserting the following language between paragraphs three and four of Article IV: During the period March 1, 2005 through December 15, 2008, Buyer shall deduct [ * ] from each Half-Month payment. For the billing period December 16, 2008 through December 31, 2008, Buyer shall deduct [ * ]. | ||
6) | That the Contract Price as set forth in Article V shall be amended as such: |
Contract Price | ||||
FOB Plant | ||||
Specification A | Specification B | |||
January 1,
2005 - February 28, 2005
|
[ * ] per ton | [ * ] per ton | ||
March 1,
2005 - December 31, 2005
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2006 - December 31, 2006
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2007 - December 31, 2007
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2008 - December 31, 2008
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2009 - December 31, 2009
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2010 - December 31, 2010
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2011 - December 31, 2011
|
[ * ] | [ * ] |
FOB Rail Rehobeth | ||||
Specification A | Specification B | |||
January 1,
2005 - February 28, 2005
|
[ * ] per ton | [ * ] per ton | ||
March 1,
2005 - December 31, 2005
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2006 - December 31, 2006
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2007 - December 31, 2007
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2008 - December 31, 2008
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2009 - December 31, 2009
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2010 - December 31, 2010
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2011 - December 31, 2011
|
[ * ] per ton | [ * ] per ton |
FOB Rail Cadiz | ||||
Specification A | Specification B | |||
January 1,
2005 - February 28, 2005
|
[ * ] per ton | [ * ] per ton | ||
March 1,
2005 - December 31, 2005
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2006 - December 31, 2006
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2007 - December 31, 2007
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2008 - December 31, 2008
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2009 - December 31, 2009
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2010 - December 31, 2010
|
[ * ] per ton | [ * ] per ton | ||
January 1,
2011 - December 31, 2011
|
[ * ] per ton | [ * ] per ton |
* | Market shall mean a mutually agreed upon price established using local market indicators (including, but not limited to offers from 3rd party coal companies, brokers, relevant indexes, etc.) |
7) | That Article V paragraph three (3) shall be deleted and restated as such: Any Monthly Quantity Option tons or Half-Year Quantity Option tons, for Specification A and/or Specification B, elected as provided for under Article II, Section 2.1, shall be discounted by [ * ] per ton from the Contract Price in effect for the applicable specification(s) during calendar years 2006 through 2008 and [ * ] per ton from the Contract Price in effect for the applicable specification(s) during the calendar years 2009 and 2010, should the term be extended. | ||
8) | That in Schedule 7.2 Section (b)(i) and (c)(i) the definition of E shall be deleted and restated as such: E = the SO2 Monthly Price (or if not published, the average of the SO2 Daily Prices for the applicable calendar month of delivery) of allowances expressed in dollars per ton of SO2 in the table entitled AIR Daily Emission Allowance Indices published in AIR Daily, or its successor publication, for such calendar month of delivery as first published following such month multiplied by [ * ]. |
Oxford Mining Company, Inc. | ||||
|
||||
By:
|
/s/ Charles C. Ungurean | |||
|
|
|||
|
||||
Title:
|
President | |||
|
|
Re: |
Coal Supply Agreement No. 10-62-04-900, dated as of May 21, 2004,
as amended, between American Electric Power Service Corporation, as agent for Columbus Southern Power Company (Buyer), and Oxford Mining Company, Inc. (Seller) |
|
Amendment No. 2006-3 |
1) | The following definitions shall be added to Definitions: | |
Accrued Value means the total of: | ||
(a) for the period July 1, 2006 through December 31, 2006 and for each six calendar month period thereafter through December 31, 2010, (i) the difference between the Contract Price as of July 1, 2006, (the July 1, 2006 Contract Price) and the adjusted Contract Price as set forth under Article V, if accepted by Seller (the Adjusted Contract Price) for Specification A Coal (the Specification A Differential), multiplied the number of tons of Specification A Coal delivered, plus (ii) the difference between the July 1, 2006 Contract Price and the Adjusted Contract Price for Specification B Coal, if accepted by Seller (the Specification B Differential), for such period, multiplied by the number of tons of Specification B Coal delivered for such period if Seller elects to accept the Adjusted Contract Price. If Seller does not elect to accept the Adjusted Contract Price for any Half-Year, no Accrued Value shall apply. |
Contract Years | Contract Quantity | Specification A Tons | Specification B Tons | |||
2006 - 2008
|
[*] per year | [*] | (see below) | |||
2009 - 2010
|
[*] per year | [*] | (see below) | |||
2011
|
[*] per year | [*] | (see below) | |||
2012 - 2014
|
[*] per year | (see below) | (see below) |
* | Buyer shall have the right (the Contract Option Right) to elect to increase the Contract Quantity from [*] Tons per year to [*] Tons per year for the period from January 1, 2011, through December 31, 2014, by providing written notice of such election to Seller no later than March 5, 2010. |
Such tonnage shall be delivered ratably during each month of each Contract Year. | ||
Buyer and Seller agree that the projected tonnage shortfall through December 2006 will be approximately [*] Tons of Coal. Buyer and Seller further agree that Buyer shall have the right but not the obligation to have such shortfall shipped at the rate of 25,000 Tons per month during any months through the Term of this Agreement by providing Seller thirty (30) days prior notice of such election. The Contract Price to be paid for such Coal shall be the Contract Price in effect when the shipment is made. | ||
For the Delivery Period from January 1, 2006, through December 31, 2011, Seller shall deliver, and Buyer shall accept, no less than [*] Tons per Contract Year of Specification A Coal. |
The remaining coal to be delivered to Buyer shall consist of Specification B Coal. At any time upon thirty (30) days prior written notice to Seller during such Delivery Period, Buyer may elect to receive more than [*] Tons of Specification A Coal during any Contract Year, provided that the total Tons of Specification A and Specification B Coal shall equal the Contract Quantity, which Quantity may be increased at Buyers option, as provided below. | ||
For the Delivery Periods on or after January 1, 2012, Buyer shall have the option to elect any percentage of the Contract Quantity to be delivered as Specification A or Specification B Coal with at least thirty (30) days prior notice to Seller, provided that the total Tons of Specification A and Specification B Coal shall equal the Contract Quantity, which Quantity may be increased at Buyers option, as provided below. | ||
Prior to Seller selling any washed Coal to a third party from a preparation plant that commences operation after January 1, 2006, Buyer shall have the right of first refusal on the first [*] tons of washed Coal processed during any Contract Year from such preparation plant at the price Seller would otherwise sell to a third party. Should Buyer elect to purchase the washed Coal, Sellers tonnage obligation under this Agreement shall be reduced by the amount of washed Coal that Seller delivers to Buyer. Such washed Coal shall meet the Specification C quality specifications as set forth on Schedule 3.1-A. | ||
During each Contract Year through Contract Year 2010, Buyer shall have the right to increase the Contract Quantity by 200,000 Tons per half-year, and during Contract Years 2011 through 2014, Buyer shall have the right to increase the Contract Quantity by 100,000 Tons (200,000 Tons, if Buyer exercises its Contract Option Right) per half-year (January through June or July through December) (hereinafter the Half-Year Quantity Option) by notifying Seller of its election to take such Half-Year Quantity Option at least ninety (90) days prior to the beginning of the applicable Half-Year period. | ||
Additionally, Buyer shall have the right at any time, and from time to time, to increase its monthly quantity obligation for Specification A and/or Specification B Coal by up to 25,000 Tons (hereinafter the Monthly Quantity Option), and thus the Contract Quantity, at any time up to thirty (30) days prior to the beginning of the applicable delivery month. Such election shall remain in effect until such time as Buyer again gives at least thirty (30) days prior notice of a subsequent election to reduce the monthly quantity obligation to the minimum monthly quantity obligation. | ||
Each such election shall be referred to as an Option for Coal produced from reserves of Coal dedicated to this Agreement in Schedule 3.1-B hereof. | ||
4) | The Article V, Contract Price, shall be deleted in its entirety and replaced with the following: | |
(a) The Contract Price shall be as follows: |
For the first [*] tons per year | For tons in excess of [*] tons per year | |||||||
Contract Price | Contract Price | |||||||
FOB Plant | FOB Plant | |||||||
Specification A | Specification B | Specification A | Specification B | |||||
January 1, 2006 December 31, 2006
|
[*] per ton | [*] per ton | [*] per ton | [*] per ton | ||||
January 1, 2007 December 31, 2007
|
2006 Contract Price plus | [*] per ton | 2006 Contract Price plus | [*] per ton | ||||
January 1, 2008 December 31, 2008
|
2007 Contract Price plus | [*] per ton | 2007 Contract Price plus | [*] per ton | ||||
January 1, 2009 December 31, 2009
|
2008 Contract Price plus | [*] per ton | 2008 Contract Price plus | [*] per ton | ||||
January 1, 2010 December 31, 2010
|
2009 Contract Price plus | [*] per ton | 2009 Contract Price plus | [*] per ton | ||||
January 1, 2011 December 31, 2011
|
[*] /Ton | [*] /Ton | [*] /Ton | [*] /Ton |
Contract Price | Contract Price | |||||||
FOB Rail Rehobeth | FOB Rail Rehobeth | |||||||
Specification A | Specification B | Specification A | Specification B | |||||
January 1,
2006 December 31, 2006
|
[*] per ton | [*] per ton | [*] per ton | [*] per ton | ||||
January 1,
2007 December 31, 2007
|
2006 Contract Price plus | [*] per ton | 2006 Contract Price plus | [*] per ton | ||||
January 1,
2008 December 31, 2008
|
2007 Contract Price plus | [*] per ton | 2007 Contract Price plus | [*] per ton | ||||
January 1,
2009 December 31, 2009
|
2008 Contract Price plus | [*] per ton | 2008 Contract Price plus | [*] per ton | ||||
January 1,
2010 December 31, 2010
|
2009 Contract Price plus | [*] per ton | 2009 Contract Price plus | [*] per ton | ||||
January 1,
2011 December 31, 2011
|
[*] per ton | [*] per ton | [*] per ton | [*] per ton |
Contract Price | Contract Price | |||||||
FOB Rail Cadiz | FOB Rail Cadiz | |||||||
Specification A | Specification B | Specification A | Specification B | |||||
January 1,
2006 December 31, 2006
|
[*] per ton | [*] per ton | [*] per ton | [*] per ton | ||||
January 1,
2007 December 31, 2007
|
2006 Contract Price plus | [*] per ton | 2006 Contract Price plus | [*] per ton | ||||
January 1,
2008 December 31, 2008
|
2007 Contract Price plus | [*] per ton | 2007 Contract Price plus | [*] per ton | ||||
January 1,
2009 December 31, 2009
|
2008 Contract Price plus | [*] per ton | 2008 Contract Price plus | [*] per ton | ||||
January 1,
2010 December 31, 2010
|
2009 Contract Price plus | [*] per ton | 2009 Contract Price plus | [*] per ton | ||||
January 1,
2011 December 31, 2011
|
[*] per ton | [*] per ton | [*] per ton | [*] per ton |
(b) The Labor and Supplies Components (Labor shall be deemed to be inclusive of all benefits and related taxes) shall be adjusted effective July 1 and January 1 of each year commencing July 1, 2006. At such dates the average of the values of each of the respective indices correlative thereto (as set forth below) for the third, fourth, and fifth preceding months of such dates (i.e., August, September, and October for the January calculation) shall be compared to the average of the values of each of such respective indices for the ninth, tenth, and eleventh preceding months of such dates, and [*] of the respective percentage change (carried out four decimal places, e.g., 6.124% shall be 0.0612) in each of such average index values shall be multiplied by the last previously effective Component or Subcomponent amount of the Contract Price correlative thereto. The amounts per Ton of increase or decrease so obtained shall be added to or subtracted from, as the case may be, the last previously effective amount of such respective Component or Subcomponent, and the resulting amounts per Ton shall become the then effective amounts per Ton for such Components and Subcomponents. The resulting total of such Components and Subcomponents, on a per ton basis and after adjustments pursuant to this Article V, paragraph (b) shall be the Adjusted Contract Price. Seller shall have the right but not the obligation to elect to accept the Adjusted Contract Prices for each Contract Half-Year, in lieu of accepting the Contract Price. Should Seller elect to accept the Adjusted Contract Prices such Adjusted Contract Price shall be applicable to any Coal taken into account on and after the effective date of any such adjustment and shall remain in effect until the Contract Prices are again adjusted and/or elected pursuant to this Article. |
(i) | The indices utilized in calculations made pursuant to this Article shall be the indices as they are first published. In the event that the current base or any index referred to in this Article is converted to a new base, then conversion tables published by the U.S. Department of Labor, Bureau of Labor Statistics, or the U.S. Department of Commerce, as the case may be, shall be used in recomputing the level of any such index. Should publication of any index be discontinued, an index, which is as nearly as practicably equivalent, shall be substituted by mutual agreement of the parties hereto. |
(ii) | In the event that supervening events or circumstances shall render inapplicable any of the methods set forth in this Article for computing price adjustments hereunder, the parties hereto shall meet promptly to consider and agree upon new and revised methods appropriate to the circumstances then prevailing. | ||
(iii) | Seller and Buyer shall keep accurate up-to-date records and books of account showing all costs, payments, price revisions, credits, debits, weights, analyses, and all other data required of each of them for the purpose of administering this Agreement. | ||
Each time the price is revised in accordance with this Article, Seller shall furnish to Buyer a detailed statement (a claim) showing Sellers calculations of the price which should then be in effect under the provisions of this Agreement and whether Seller is electing the Adjusted Contract Prices as set forth in (b) above. | |||
Buyer shall make a preliminary review of the claim within a reasonable amount of time. Upon completion of Buyers preliminary review, Buyer may submit to Seller a letter explaining the differences, if any, in the price as shown on the claim and the price as determined by Buyers preliminary review. Buyer shall then submit a letter agreement to Seller for its countersignature to establish a tentative price adjustment The price adjustment as agreed to in the fully executed letter agreement, either a debit or credit, shall be processed using Buyers normal payment procedures and, if necessary, a tentative retroactive adjustment shall be made by payment to the party to whom such tentative adjustment is due. | |||
From time to time, representatives of Buyer shall audit Sellers claim(s) and recommend final price adjustments associated with such claim(s). Thereafter, Buyer shall submit a letter agreement to Seller for its countersignature to establish a final price adjustment. The price adjustment as agreed to in the fully executed letter agreement, either a debit or credit, shall be processed using Buyers normal payment procedures and, if necessary, a final retroactive adjustment shall be made by payment to the party to whom such final adjustment is due. | |||
(iiii) | Buyer and its designated representatives and/or agents including but not limited to its auditors, engineers, and geologists, shall at reasonable times, have access to the mine(s) producing coal under this Agreement, to all support facilities, and to all records pertaining to the coal reserves covered by this Agreement; to the production and cost of production records of coal produced at the production sources specified on Schedule 3.1-B; to all records related to the operation, maintenance, calibration, and testing (including bias testing) of the scales and/or samplers; and to all records pertaining to the costs of transportation hereunder (such access to such cost records shall be only as required for purposes of administering this Agreement). |
The amount of the respective Contract Prices effective as of July 1, 2006 allocated to each Component and Subcomponent thereof, and the index or method to be used for the adjustment of each such Component and Subcomponent, beginning July 1, 2006 are as follows: |
Initial Amount | ||||||||||
Per Ton of | ||||||||||
Component | Subcomponent | Contract Price | Index-Method | |||||||
1. Labor | (a) | [*] | CEU1021210006 Average Hourly Earnings Coal Mining published by the Bureau of Labor Statistics | |||||||
|
||||||||||
|
(b) | [*] | CWUROOOOSAM CPI-W Medical Care Index | |||||||
|
||||||||||
2. Supplies | (a) | [*] | Petroleum Products, Refined Code WPU057 | |||||||
|
(b) | [*] | Explosives WPU067902 | |||||||
|
(c) | [*] | PPI-Industrial Commodities WPUO3THRU15 | |||||||
|
(d) | [*] | Construction Machinery & Equipment WPU112 | |||||||
|
||||||||||
3. Per Ton Assessments | Shall be adjusted if change in law affecting Fee or Tax | |||||||||
|
||||||||||
(a) Federal Reclamation Fee | 0.350 | |||||||||
(b) Federal Black Lung Excise Tax | 0.550 | |||||||||
(c) Ohio Severance Tax | 0.090 | |||||||||
|
||||||||||
JULY 1, 2006 CONTRACT PRICE | [*] | |||||||||
|
Initial Amount | ||||||||||
Per Ton of | ||||||||||
Component | Subcomponent | Contract Price | Index-Method | |||||||
1. Labor | (a) | [*] | CEU1021210006 Average Hourly Earnings Coal Mining published by the Bureau of Labor Statistics | |||||||
|
(b) | [*] | CWUROOOOSAM CPI-W Medical Care Index | |||||||
|
||||||||||
2. Supplies | (a) | [*] | Petroleum Products, Refined Code WPU057 | |||||||
|
(b) | [*] | Explosives WPU067902 | |||||||
|
(c) | [*] | PPI-Industrial Commodities WPUO3THRU15 | |||||||
|
(d) | [*] | Construction Machinery & Equipment WPU112 | |||||||
|
||||||||||
3. Per Ton Assessments | Shall be adjusted if change in law affecting Fee or Tax | |||||||||
|
||||||||||
(a) Federal Reclamation Fee | 0.350 | |||||||||
(b) Federal Black Lung Excise Tax | 0.550 | |||||||||
(c) Ohio Severance Tax | 0.090 | |||||||||
|
||||||||||
JULY 1, 2006 CONTRACT PRICE | [*] | |||||||||
|
Initial Amount | ||||||||||
Per Ton of | ||||||||||
Component | Subcomponent | Contract Price | Index-Method | |||||||
1. Labor | (a) | [*] | CEU1021210006 Average Hourly Earnings Coal Mining published by the Bureau of Labor Statistics | |||||||
|
(b) | [*] | CWUROOOOSAM CPI-W Medical Care Index | |||||||
|
||||||||||
2. Supplies | (a) | [*] | Petroleum Products, Refined Code WPU057 | |||||||
|
(b) | [*] | Explosives WPU067902 | |||||||
|
(c) | [*] | PPI-Industrial Commodities WPUO3THRU15 | |||||||
|
(d) | [*] | Construction Machinery & Equipment WPU112 | |||||||
|
||||||||||
3. Per Ton Assessments | Shall be adjusted if change in law affecting Fee or Tax | |||||||||
|
||||||||||
(a) Federal Reclamation Fee | 0.350 | |||||||||
(b) Federal Black Lung Excise Tax | 0.550 | |||||||||
(c) Ohio Severance Tax | 0.090 | |||||||||
|
||||||||||
JULY 1, 2006 CONTRACT PRICE | [*] | |||||||||
|
Initial Amount | ||||||||||
Per Ton of | ||||||||||
Component | Subcomponent | Contract Price | Index-Method | |||||||
1. Labor | (a) | [*] | CEU1021210006 Average Hourly Earnings Coal Mining published by the Bureau of Labor Statistics | |||||||
|
(b) | [*] | CWUROOOOSAM CPI-W Medical Care Index | |||||||
|
||||||||||
2. Supplies | (a) | [*] | Petroleum Products, Refined Code WPU057 | |||||||
|
(b) | [*] | Explosives WPU067902 | |||||||
|
(c) | [*] | PPI-Industrial Commodities WPUO3THRU15 | |||||||
|
(d) | [*] | Construction Machinery & Equipment WPU112 | |||||||
|
||||||||||
3. Per Ton Assessments | Shall be adjusted if change in law affecting Fee or Tax | |||||||||
|
||||||||||
(a) Federal Reclamation Fee | 0.350 | |||||||||
(b) Federal Black Lung Excise Tax | 0.550 | |||||||||
(c) Ohio Severance Tax | 0.090 | |||||||||
|
||||||||||
JULY 1, 2006 CONTRACT PRICE | [*] | |||||||||
|
Initial Amount | ||||||||||
Per Ton of | ||||||||||
Component | Subcomponent | Contract Price | Index-Method | |||||||
1. Labor | (a) | [*] | CEU1021210006 Average Hourly Earnings Coal Mining published by the Bureau of Labor Statistics | |||||||
|
(b) | [*] | CWUROOOOSAM CPI-W Medical Care Index | |||||||
|
||||||||||
2. Supplies | (a) | [*] | Petroleum Products, Refined Code WPU057 | |||||||
|
(b) | [*] | Explosives WPU067902 | |||||||
|
(c) | [*] | PPI-Industrial Commodities WPUO3THRU15 | |||||||
|
(d) | [*] | Construction Machinery & Equipment WPU112 | |||||||
|
||||||||||
3. Per Ton Assessments | Shall be adjusted if change in law affecting Fee or Tax | |||||||||
|
||||||||||
(a) Federal Reclamation Fee | 0.350 | |||||||||
(b) Federal Black Lung Excise Tax | 0.550 | |||||||||
(c) Ohio Severance Tax | 0.090 | |||||||||
|
||||||||||
JULY 1, 2006 CONTRACT PRICE | [*] | |||||||||
|
Initial Amount | ||||||||||
Per Ton of | ||||||||||
Component | Subcomponent | Contract Price | Index-Method | |||||||
1. Labor | (a) | [*] | CEU1021210006 Average Hourly Earnings Coal Mining published by the Bureau of Labor Statistics | |||||||
|
(b) | [*] | CWUROOOOSAM CPI-W Medical Care Index | |||||||
|
||||||||||
2. Supplies | (a) | [*] | Petroleum Products, Refined Code WPU057 | |||||||
|
(b) | [*] | Explosives WPU067902 | |||||||
|
(c) | [*] | PPI-Industrial Commodities WPUO3THRU15 | |||||||
|
(d) | [*] | Construction Machinery & Equipment WPU112 | |||||||
|
||||||||||
3. Per Ton Assessments | Shall be adjusted if change in law affecting Fee or Tax | |||||||||
(a) Federal Reclamation Fee | 0.350 | |||||||||
(b) Federal Black Lung Excise Tax | 0.550 | |||||||||
(c) Ohio Severance Tax | 0.090 | |||||||||
|
||||||||||
JULY 1, 2006 CONTRACT PRICE | [*] | |||||||||
|
The Parties shall negotiate, in good faith, commencing no later than January 1, 2010, on the Negotiated Prices for [*] tons per year and [*] tons per year as set forth in Article II, Section 2.1 to be applicable to the Specification A and Specification B Coal to be delivered under this Agreement during the period from January 1, 2011, through December 31, 2014. If the Parties agree on such Negotiated Prices, then such |
Negotiated Prices, as adjusted pursuant to this Amendment, shall be in effect during such period. If, prior to March 5, 2010, the Parties are unable to reach agreement on the Negotiated Prices to be effective during such period, then not later than the first day of each month during the period from January 1, 2011 through December 31, 2014, Seller shall pay to Buyer [*] of the sum of Accrued Value Plus Interest. Except for such payment obligation, provided that Buyer and Seller have complied with this Agreement, then this Agreement shall terminate as of December 31, 2010, without any further obligation of either Party. |
5) | Item (b)(i) and (c)(i) on Schedule 7.2, Quality Adjustments, shall be deleted in their entirety and replaced with the following in lieu thereof once FGD technology has been installed on Conesville Unit 4: | |
(b)(i) For Specifications A and C only, if the weighted average Half-Month SO2 content tested is greater than the SO2 Contracted Half-Month Weighted Average Specification, the Contract Price for Coal will be reduced by an amount determined in accordance with the following formula: | ||
((Actual lbs. SO2/mmbtu Contracted lbs. SO2/mmbtu)* Actual Btu/lb. * E * ([*] FGD Scrubber Efficiency Design Basis)) |
((Actual lbs. SO2/mmbtu Contracted lbs. SO2/mmbtu)* Contract Price * [*] * FGD Scrubber Efficiency Design Basis) | |||
(c)(i) For Specifications A and C only, if the weighted average Half-Month SO2 content tested is less than the SO2 Contracted Half-Month Weighted Average Specification, the Contract Price for Coal will be increased by an amount determined in accordance with the following formula: | |||
[((Contracted lbs. SO2/mmbtu Actual lbs. SO2/mmbtu)* Actual Btu/lb. * E * ([*] FGD Scrubber Efficiency Design Basis)) |
((Contracted lbs. SO2/mmbtu Actual lbs. SO2/mmbtu)* Contract Price * [*] * FGD Scrubber Efficiency Design Basis)]* [*] |
6) | The Ash specification for Specification B reflected in Schedule 3.1-A, Quality Specifications shall be amended to state as follows: |
Contracted | Half-Month (A)* | Applicable Lot (B)* | ||||||
Specification B | Half-Month | Suspension Limit | Suspension Limit (D)* | |||||
Ash (%)
|
[*] | [*] maximum | [*] maximum |
Acceptance Date: | 12/20/2006 | ||||||||
|
|||||||||
/s/ Charles E Zebula | |||||||||
Charles E Zebula | Oxford Mining Company, Inc. | ||||||||
AMERICAN ELECTRIC POWER
|
|||||||||
SERVICE CORPORATION, as Agent for
|
By: | /s/ Charles C. Ungurean | |||||||
Columbus Southern Power Company
|
Title: | President | |||||||
|
|||||||||
xc: W. E. Spiker Eagle Fuels, Inc.
|
. |
Re:
|
Coal Supply Agreement No. 10-62-04-900, dated as of May 21, 2004, as
amended, between American Electric Power Service Corporation, as agent for Columbus Southern Power Company (Buyer), and Oxford Mining Company, LLC (formerly Oxford Mining Company, Inc.) (Seller) (the Agreement) |
|
|
||
|
Amendment No. 2008-6 |
1) | Article I, Term and Delivery Period, shall be deleted in its entirety and replaced with the following in lieu thereof: | |
Article 1, Section 1 . The term of this Agreement (the Term also referenced herein as the Delivery Period) shall commence on the Effective Date, and shall remain in effect until December 31, 2012, unless said Term is accelerated or extended as provided elsewhere in the Agreement. | ||
Article I, Section 2 . Provided this Agreement is still in effect, Buyer shall have the optional right, but not the obligation, to extend the Term of this Agreement for two three (3) year option periods, with the first option period beginning January 1, 2013, and extending through December 31, 2015, and the second beginning January 1, 2016, and extending through December 31, 2018. Buyer shall provide Seller with Buyers notice of its exercising its election to extend the Term of the Agreement for the next option period at least 180 days prior to the commencement of the next option period. Should Buyer not elect to extend the Term of the Agreement for the first three (3) year option period, then the second three (3) year option period shall no longer be available. | ||
2) | Article II, Section 2.1, Contract Quantity, shall be deleted in its entirety and replaced with the following in lieu thereof: | |
Section 2.1 Contract Quantity . During the Delivery Period, Seller agrees to sell and deliver to Buyer and Buyer agrees to purchase and accept from Seller, FOB truck or railcar (as applicable) at the Designated Delivery Point, the quantity of Coal set forth herein. |
Contract Years | Contract Quantity | Specification A Tons | Specification B Tons | |||
2009 - 2011
|
[*] per year | [*] | (see below) | |||
2012 - 2014
|
[*] per year | (see below) | (see below) | |||
2015
|
[*] per year | (see below) | (see below) | |||
2016 - 2018
|
[*] per year | (see below) | (see below) |
For the Delivery Period from January 1, 2009, through December 31, 2011, Seller shall deliver, and Buyer shall accept, no less than [*] Tons per Contract Year of Specification A Coal. Not less than one hundred eighty (180) days prior to each Contract Year commencing with Contract Year 2012 Buyer will notify Seller whether the Conesville Coal Preparation Plant will continue operating during the next Contract Year. For each Contract Year commencing with Contract Year 2012 in which the Conesville Coal Preparation Plant continues operating, Buyer shall nominate a minimum of [*] Tons of Specification A Coal. The remaining Coal to be delivered to Buyer shall consist of Specification B Coal. Provided that the total Tons of Specification A and Specification B Coal shall equal the Contract Quantity, which Quantity may be increased at Buyers option, as provided herein, upon thirty (30) days prior written notice to Seller, Buyer may elect to receive (i) more than [*] Tons of Specification A Coal during any Contract Year in which the Conesville Coal Preparation Plant is operating, or (ii) any number of Specification A and Specification B Tons of Coal during any Contract Year in which the Conesville Coal Preparation Plant is not operating. | ||
Such tonnage shall be delivered ratably during each month of each Contract Year unless otherwise agreed to by Buyer and Seller. | ||
Through November 2008, there was a tonnage shortfall of [*] Tons (inclusive of [*] force majeure Tons claimed by Seller during Contract Year 2008). Buyer shall have the right to increase deliveries in any month(s) by up to 25,000 Tons per month with thirty (30) days prior written notice until such time as the [*] Tons have been delivered. The Contract Price to be paid for such Coal shall be the Contract Price in effect when delivered. | ||
Prior to Seller selling any washed Coal to a third party from a preparation plant that commences operation after January 1, 2009, Buyer shall have the right of first refusal to purchase the first [*] Tons of washed Coal processed during any Contract Year from such preparation plant at the price Seller would otherwise sell to a third party (the First Refusal Price), provided that if Buyer elects to purchase such washed Coal, the Contract Price for such Coal shall be the First Refusal Price prior to January 1, 2013, and thereafter the First Refusal Price less [*] per Ton. Should Buyer elect to purchase the washed Coal, Sellers tonnage obligation under this Agreement shall be reduced by the amount of washed Coal that Seller delivers to Buyer. Such washed Coal shall meet the Specification C quality specifications as set forth on Schedule 3.1-A. | ||
During each Contract Year (including any option period[s] elected), Buyer shall have the right to increase the Contract Quantity by 200,000 Tons per half-year (January through June or July through December being a Contract Half-Year) (hereinafter the Half-Year Quantity Option) by notifying Seller of its election to take such Half-Year Quantity Option at least ninety (90) days prior to the beginning of the applicable Contract Half-Year. | ||
Additionally, for any month(s) through December 2014, Buyer shall have the right at any time, and from time to time, to increase its monthly quantity obligation (i.e. the Contract Quantity for the applicable Contract Year divided by 12) for Specification A and/or Specification B Coal by up to 25,000 Tons (hereinafter the Monthly Quantity Option), and thus increase the Contract Quantity by up to 25,000 Tons per month, at any time prior to thirty (30) days prior to the beginning of the applicable delivery month. Such election shall remain in effect until such time as Buyer again gives at least thirty (30) days prior notice of a subsequent election to reduce the monthly quantity obligation by the amount of such increase. |
3) | The fourth paragraph of Article IV shall be deleted in its entirety and replaced with the following in lieu thereof: | |
For the first [*] Tons delivered beginning January 1, 2009 (and continuing until such time such amount is delivered), Seller shall deduct [*] per Ton to reimburse Buyer for Buyers prepayment to Seller in 2008 for Coal to be delivered in Contract Year 2009. | ||
4) | Article V, Contract Price, shall be deleted in its entirety and replaced with the following in lieu thereof: |
(a)The Contract Price shall be as follows and adjusted in accordance with Section (b) below: |
Contract Price FOB Plant (Per Ton) * | |||||||||
Specification A | Specification B | ||||||||
January 1,
2009
|
[*] | [*] |
Contract Price FOB Rail Rehobeth (Per Ton) * | |||||||||
Specification A | Specification B | ||||||||
January 1,
2009
|
[*] | [*] |
Contract Price FOB Rail Cadiz (Per Ton) * | |||||||||
Specification A | Specification B | ||||||||
January 1,
2009
|
[*] | [*] |
* | For the first [*] Tons to be delivered pursuant to this Agreement in Contract Year 2009, an amount of [*] per Ton shall be added to the Contract Price. |
(b) The Labor (Labor shall be deemed to be inclusive of all benefits and related taxes), Health Benefits, Petroleum Products Refined, Explosives, Construction Machinery & Equipment, Other, and Truck Transportation Cost Components shall be adjusted effective July 1 and January 1 of each Contract Year commencing July 1, 2009. At such dates the average of the values of each of the respective indices correlative thereto (as set forth below) for the third, fourth, and fifth preceding months of such dates (i.e., August, September, and October for the January calculation) shall be compared to the average of the values of each of such respective indices for the ninth, tenth, and eleventh preceding months of such dates, and [*] of the respective percentage change (carried out four decimal places, e.g., 6.124% shall be 0.0612) in each of such average index values shall be multiplied by the last previously effective Component amount of the Contract Price correlative thereto. The amounts per Ton of increase or decrease so obtained shall be added to or subtracted from, as the case may be, the last previously effective amount of such respective Component, and the resulting amounts per Ton shall become the then effective amounts per Ton for such Components of the Contract Price. | ||
The amount of the respective Base Prices effective as of January 1, 2009 allocated to each Component thereof, and the index or method to be used for the adjustment of each such Component, beginning July 1, 2009: |
Initial Amount Per Ton | ||||||||
Component | FOB Plant | FOB Rehobeth | FOB Cadiz | Index-Method | ||||
1. Labor
|
[*] | [*] | [*] | CEU1021210008 Average Hourly Earnings- Coal Mining | ||||
2. Health Benefits
|
[*] | [*] | [*] | CWUR0000SAM Medical Care | ||||
3. Petroleum Products Refined
|
[*] | [*] | [*] | WPU057 Petroleum Products Refined | ||||
4. Explosives
|
[*] | [*] | [*] | WPU067902 Explosives | ||||
5. Construction Machinery
|
[*] | [*] | [*] | WPU112 Construction Machinery & Equip. | ||||
6. Other
|
[*] | [*] | [*] | CUUR0000SA0 All Urban Consumers Adjusted in accordance with Article V, (c) | ||||
7. Per Ton Assessments
|
||||||||
Federal Reclamation Fee
|
0.315 | 0.315 | 0.315 | |||||
FBLET
|
0.550 | 0.550 | 0.550 | |||||
Ohio Severance Tax
|
0.252 | 0.252 | 0.252 | |||||
8. Changes in Law
|
0.000 | 0.000 | 0.000 | Adjusted in accordance with Article VI | ||||
|
||||||||
FOB Delivered Price
|
[*] | [*] | [*] | |||||
Truck Transportation Cost
|
[*] | [*] | [*] | PCU484 484 Truck Transportation | ||||
|
||||||||
January 1, 2009 Contract Price
|
[*] | [*] | [*] |
Initial Amount Per Ton | ||||||||
Component | FOB Plant | FOB Rehobeth | FOB Cadiz | Index-Method | ||||
1. Labor
|
[*] | [*] | [*] | CEU1021210008 Average Hourly Earnings- Coal Mining | ||||
2. Health Benefits
|
[*] | [*] | [*] | CWUR0000SAM Medical Care | ||||
3. Petroleum Products Refined
|
[*] | [*] | [*] | WPU057 Petroleum Products Refined | ||||
4. Explosives
|
[*] | [*] | [*] | WPU067902 Explosives | ||||
5. Construction Machinery
|
[*] | [*] | [*] | WPU112 Construction Machinery & Equip. | ||||
6. Other
|
[*] | [*] | [*] | CUUR0000SA0 All Urban Consumers Adjusted in accordance with Article V, (c) | ||||
7. Per Ton Assessments
|
||||||||
Federal Reclamation Fee
|
0.315 | 0.315 | 0.315 | |||||
FBLET
|
0.550 | 0.550 | 0.550 | |||||
Ohio Severance Tax
|
0.252 | 0.252 | 0.252 | |||||
8. Changes in Law
|
0.000 | 0.000 | 0.000 | Adjusted in accordance with Article VI | ||||
|
||||||||
FOB Delivered Price
|
[*] | [*] | [*] | |||||
Truck Transportation Cost
|
[*] | [*] | [*] | PCU484 484 Truck Transportation | ||||
|
||||||||
January 1, 2009 Contract Price
|
[*] | [*] | [*] |
(i) The indices utilized in calculations made pursuant to this Article shall be the indices as they are first published. In the event that the current base or any index referred to in this Article is converted to a new base, then conversion tables published by the U.S. Department of Labor, Bureau of Labor Statistics, shall be used in recomputing the level of any such index. Should publication of any index be discontinued, an index, which is as nearly as practicably equivalent, shall be substituted by mutual agreement of the Parties hereto. | ||
(ii) Seller and Buyer shall keep accurate up-to-date records and books of account showing all costs, payments, price revisions, credits, debits, weights, analyses, and all other data required of each of them for the purpose of administering this Agreement. |
Each time the price is revised in accordance with this Article, Seller shall furnish to Buyer a detailed statement (a claim) showing Sellers calculations of the price which should then be in effect under the provisions of this Agreement. | ||
Buyer shall make a preliminary review of the claim within a reasonable amount of time. Upon completion of Buyers preliminary review, Buyer may submit to Seller a letter explaining the differences, if any, in the price as shown on the claim and the price as determined by Buyers preliminary review. Buyer shall then submit a letter agreement to Seller for its countersignature to establish a tentative price adjustment. The price adjustment as agreed to in the fully executed letter agreement, either a debit or credit, shall be processed using Buyers normal payment procedures and, if necessary, a tentative retroactive adjustment shall be made by payment to the Party to whom such tentative adjustment is due. | ||
From time to time, representatives of Buyer shall audit Sellers claim(s) and recommend final price adjustments associated with such claim(s). Thereafter, Buyer shall submit a letter agreement to Seller for its countersignature to establish a final price adjustment. The price adjustment as agreed to in the fully executed letter agreement, either a debit or credit, shall be processed using Buyers normal payment procedures and, if necessary, a final retroactive adjustment shall be made by payment to the Party to whom such final adjustment is due. | ||
(iii) For each option period elected, Buyer and Seller shall negotiate the market prices FOB Plant for Specification A and Specification B Coal. In the event that Buyer and Seller are unable to agree upon such market prices within thirty (30) days after Buyers notification to Seller of its election to exercise an option, Buyer and Seller shall agree to be bound through arbitration. The arbitration shall be held in Columbus, Ohio, before a single arbitrator in accordance with the procedures of the American Arbitration Association (AAA) rules. To be qualified, the arbitrator must have at least ten (10) years extensive experience in the buying or selling of Eastern Coal. There shall be no ex parte communication with the arbitrator. Each Party shall submit to the arbitrator their calculation of the market prices FOB Plant for Specification A and Specification B Coal (as further defined in Schedule 3.1-A) for the option period, along with any supporting documentation. The arbitrator shall be required to select either the Buyers or the Sellers calculation of the market prices for the applicable option period. Once such market prices have been determined, either by agreement or through arbitration, the Contract Prices during the applicable option period shall be such market prices less [*] per Ton. The Parties shall then within thirty (30) days after such determination, determine the Contract Prices FOB Rail Rehobeth and FOB Rail Cadiz based upon the determined market prices for Specification A and Specification B Coal FOB Plant. | ||
(iv)Buyer and its designated representatives and/or agents including but not limited to its auditors, engineers, and geologists, shall at reasonable times, have access to the mine(s) producing Coal under this Agreement, to all support facilities, and to all records pertaining to this Agreement (including but not limited to records pertaining to the Coal reserves); to the production and cost of production records of Coal produced at the production sources specified on Schedule 3.1-B; to all records related to the operation, maintenance, calibration, and testing (including bias testing) of the scales and/or samplers; and to all records pertaining to the costs of transportation hereunder (such access to such cost records shall be only as required for purposes of administering this Agreement). | ||
(c) Assessments The Contract Price shall be adjusted for changes in the assessment rate to Seller for Federal Reclamation Fee, Federal Black Lung Excise Tax and Ohio Severance Tax. Any adjustment to the Contract Prices for changes in assessments shall be effective on the first day of the calendar month following the effective date of any change occurring after January 1, 2009 (except when such change is effective on the first day of a month in which case such adjustment shall be effective as of such date). Such amounts shall be adjusted for any related tax credits allowed Seller. For the purpose of calculating price adjustments under this section (c), all adjustments shall be deemed to be based on those assessments applicable to surface mining. |
Buyer and Seller acknowledge that Seller currently takes a deduction for moisture content in excess of inherent moisture when making Federal Reclamation Fee and Federal Black Lung Excise Tax payments for Coal. | ||
5) The second paragraph of Article VI, Section 6.2, Changes in Law, shall be deleted and the following substituted in lieu thereof: | ||
In the event of the enactment, modification, or revision of any Federal, State or local legislation, regulations, rules or mandates issued pursuant thereto, including but not limited to the Federal Mine Safety & Health Act of 1977 and the Surface Mining Control and Reclamation Act of 1977, after January 1, 2009, which affect the bituminous coal industry with respect to the coal reclamation, conservation, environmental protection, mine safety, mine working conditions and practices, ventilation, health, employee retirement programs occupational hazards, research and reclamation and conservation of mined areas, and which increases or decreases Sellers cost of producing Coal under this Agreement, an appropriate adjustment will be made to the current Contract Price to recognize such changed cost; provided, however, there shall be no changes made in the Contract Price for changed costs associated with labor related benefits or taxes, real or personal property taxes, corporate net income or franchise taxes; and further provided that Buyer shall have the right to terminate this Agreement should any such adjustments cause the Contract Price to be increased by more than [*] of its then current amount or should the total of all such adjustments under this Section 6.2 cause the Contract Price to be increased by more than [*] of its initial amount as of January 1, 2009. | ||
6) Commencing January 1, 2009, Buyer and Seller agree that should Sellers cumulative shortfall in deliveries be at least [*] Tons as of the end of any Contract Half Year, the first Tons shipped thereafter shall be deemed to be such shortfall Tons and the Contract Price for such Tons shall be reduced by [*] per Ton. This reduction is in addition to any other rights that Buyer may have under the Agreement or at law or in equity relative to any tonnage shortfall. |
|
Acceptance Date: 12/29/08 | |||
|
/s/ Timothy K. Light | ||||||
Timothy K. Light | Oxford Mining Company, Inc. | |||||
Vice President
|
||||||
Columbus Southern Power Company
|
By: | /s/ Jeffrey M. Gutman | ||||
|
||||||
|
Title: | SVP & CEO | ||||
|
Fuel Supply agreement between American Electric Power Service Corporation, as agent for Columbus Southern Power Company and Oxford Mining Company, LLC, fka Oxford Mining Company originally executed May 21, 2004 as amended, contract #10-62-04-900 | |||
The undersigned Charles C. Ungurean, President and Chief Executive Officer of OXFORD MINING COMPANY, LLC (Oxford) hereby delegates to Jeff Gutman, Senior Vice President and Chief Financial Officer of Oxford the authority to execute an amendment to the above referred contract on or before December 31, 2008. | |||
This delegation authorizes Mr. Gutman to act in my name and stead to agree and comit to the terms and conditions of the amendment on behalf of Oxford. |
Attest: | /s/ Linda Whitis |
Linda Whitis, Assistant Secretary
Oxford Mining Company, LLC |
Re:
|
Coal Supply Agreement No. 10-62-04-900, dated as of May 21, 2004, as | |
|
amended, between American Electric Power Service Corporation, as agent | |
|
for Columbus Southern Power Company (Buyer), and Oxford Mining | |
|
Company, LLC (formerly Oxford Mining Company, Inc.) (Seller) | |
|
(the Agreement) | |
|
||
|
Amendment No. 2009-1 |
1) | Section 2.1, Contract Quantity, of Article II, Obligations and Deliveries, shall be deleted in its entirety and replaced with the following in lieu thereof: |
Contract Years | Contract Quantity | Specification A Tons | Specification B Tons | |||||||||
2009 | [*] per year | [*] | (see below) | |||||||||
2010 - 2011 | [*] per year | [*] | (see below) | |||||||||
2012 - 2014 | [*] per year | (see below) | (see below) | |||||||||
2015 | [*] per year | (see below) | (see below) | |||||||||
2016 - 2018 | [*] per year | (see below) | (see below) |
2) | For the period May 1, 2009 through December 31, 2009, the following quality specifications for Specification A reflected in Schedule 3.1-A, Quality Specifications shall be amended as follows: |
Weighted Average As-Received Basis | ||||||||||||
Contracted | Half-Month (A) * | Applicable Lot (B) * | ||||||||||
SPECIFICATION A: | Half-Month | Suspension Limit | Suspension Limit (D)* | |||||||||
Calorific Value (Btu/lb.)
|
[*] | [*] minimum | [*] minimum | |||||||||
Ash (%)
|
[*] | [*] maximum | [*] maximum | |||||||||
Sulfur Dioxide (lbs.
SO2/MMBtu) (C)*
|
[*] | [*] maximum | [*] maximum |
Very truly yours,
|
||
/s/
James D.
Henry
|
||
James D. Henry
|
Acceptance Date: June 11, 2009 | |
Vice President Fuel Procurement East
|
||
AMERICAN ELECTRIC POWER
|
Oxford Mining Company, LLC | |
SERVICE CORPORATION, as agent for
|
||
Columbus Southern Power Company
|
||
|
By: /s/ Charles C.
Ungurean
|
|
|
||
|
Its: President &
CEO
|
|
|
||
xc: W. E. Spiker Eagle Fuels, Inc.
|
Re:
|
Coal Purchase and Sale Agreement No. 10-62-04-900, dated as of | |
|
May 21, 2004, as amended, between American Electric Power | |
|
Service Corporation, as agent for Columbus Southern Power | |
|
Company (Buyer), and Oxford Mining Company, Inc. (Seller) | |
|
||
|
Amendment No. 2009-3 |
1) | The fourth paragraph in Section 2.1, Contract Quantity, of Article II, Obligations and Deliveries, shall be deleted and replaced with the following in lieu thereof: | |
Through November 2008, there was a tonnage shortfall of [*] Tons (inclusive of [*] force majeure Tons claimed by Seller during Contract Year 2008). The shortfall has subsequently been reduced by [*] tons delivered by Seller in the months of January, February, and October 2009. The parties have agreed to an additional shortfall tonnage reduction in 2009, for a remaining shortfall total of [*] Tons. Buyer shall have the right to increase deliveries in any month(s) by up to 25,000 Tons per month with thirty (30) days prior written notice until such time as the [*] Tons have been delivered. The Contract Price to be paid for such Coal shall be the Contract Price in effect when delivered. | ||
2) | Delete the first paragraph in Article V, subsection (b) in its entirety and replace it with the following in lieu thereof: | |
(b) The Labor (Labor shall be deemed to be inclusive of all benefits and related taxes), Health Benefits, Construction Machinery & Equipment, Other, and Truck Transportation Cost Components shall be adjusted effective July 1 and January 1 of each Contract Year commencing July 1, 2009. At such dates the average of the values of each of the respective indices correlative thereto (as set forth below) for the third, fourth, and fifth preceding months of such dates (i.e., August, September, and October for the January calculation) shall be compared to the average of the values of each of such respective indices for the ninth, tenth, and eleventh preceding months of such dates. The Petroleum Products Refined Cost Component shall be adjusted effective |
January 1, April 1, July 1 and October 1 of each Contract Year beginning in April 2010. At such dates the Petroleum Products Refined Cost Component, for the third, fourth, and fifth preceding months of such dates (i.e., August, September, and October for the January calculation) shall be compared to the average values of the sixth, seventh and eighth preceding months of such dates. | ||
[*] of the respective percentage change (carried out four decimal places, e.g., 6.124% shall be 0.0612) in each of such average index values shall be multiplied by the last previously effective Component amount of the Contract Price correlative thereto. The amounts per Ton of increase or decrease, either by quarterly or semi-annual adjustment, so obtained shall be added to or subtracted from, as the case may be, the last previously effective amount of such respective Component, and the resulting amounts per Ton shall become the then effective amounts per Ton for such Components of the Contract Price. | ||
3) | For the period January 1, 2010 through December 31, 2010, the following quality specifications for Specification A reflected in Schedule 3.1-A, Quality Specifications shall be amended as follows: |
Weighted Average As-Received Basis | ||||||||||||
Contracted | Half-Month (A)* | Applicable Lot (B)* | ||||||||||
SPECIFICATION A: | Half-Month | Suspension Limit | Suspension Limit (D)* | |||||||||
Caloric Value (Btu/lb.)
|
[*] | [*] minimum | [*] minimum | |||||||||
Ash (%)
|
[*] | [*] maximum | [*] maximum | |||||||||
Sulfur Dioxide (lbs.
SO2/MMBtu( (C)*
|
[*] | [*] maximum | [*] maximum |
Acceptance Date:
|
||
|
||
Oxford Mining Company, LLC
|
||
|
||
/s/
Thomas T. Ungurean
|
||
Signature
|
||
|
||
Thomas T. Ungurean
|
||
Name (Print)
|
||
|
||
Vice
President
|
||
Title
|
||
|
||
xc: W. E. Spiker Eagle Fuels, Inc.
|
Re:
|
Coal Purchase and Sale Agreement No. 10-62-04-900, dated | |
|
as of May 21, 2004, as amended, between American Electric | |
|
Power Service Corporation, as agent for Columbus Southern | |
|
Power Company (Buyer), and Oxford Mining Company, Inc. (Seller) | |
|
||
|
Amendment No. 2010-1 |
1) | The fourth paragraph in Section 2.1, Contract Quantity, of Article II, Obligations and Deliveries, shall be deleted and replaced with the following in lieu thereof: | |
Through November 2008, there was a tonnage shortfall of [ * ] Tons (inclusive of [ * ] force majeure Tons claimed by Seller during Contract Year 2008). The shortfall has subsequently been reduced by [ * ] tons delivered by Seller in the months of January, February, and October 2009. The parties have agreed to an additional shortfall tonnage reduction in 2009, for a remaining shortfall total of [ * ] Tons. Buyer shall have the right to increase deliveries in any month(s) by up to 25,000 Tons per month with thirty (30) days prior written notice until such time as the [ * ] Tons have been delivered. The Contract Price to be paid for such Coal shall be the Contract Price in effect when delivered. | ||
2) | In accordance with Article XXVI, NOTICES , Sellers address shall be amended as follows: | |
For Notices:
If to Seller : Attn: Ms. Angela Ashcraft, Supervisor, Commercial Analysis Oxford Mining, LLC 544 Chestnut Street P. O. Box 427 Coshocton, OH 43812 Phone: 740-622-6302 Fax: 740-623-0365 |
By USPS mail a copy to:
|
By UPS or FEDX overnight mail a copy to: | |
William E. Spiker
|
William E. Spiker | |
Eagle Fuels, Inc.
|
Eagle Fuels, Inc. | |
P. O. Box 291
|
Suite 220 | |
Cadiz, OH 43907
|
153 East Main St. | |
Phone: 740-942-8181 Fax: 740-942-4227
|
Columbus, OH 43215 |
Acceptance
Date: 1/19/10
|
||
|
||
Oxford Mining Company, LLC
|
||
|
||
/s/
Chuck
Ungurean
|
||
Signature
|
||
|
||
|
||
Chuck
Ungurean
|
||
Name (Print)
|
||
|
||
President
& CEO
|
||
Title
|
||
|
||
xc: W. E. Spiker Eagle Fuels, Inc.
|
John T. Boyd Company
|
||||
By: | /s/ Ronald L. Lewis | |||
Ronald L. Lewis | ||||
Managing Director and Chief Operating Officer | ||||
Dated: June 24, 2010 |
||||