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8-K - FORM 8-K - Westmoreland Resource Partners, LP | c24111e8vk.htm |
Exhibit 99.1
Partnership Contact:
Brian Meilton
(614) 643-0314
ir@OxfordResources.com
Brian Meilton
(614) 643-0314
ir@OxfordResources.com
Oxford Resource Partners, LP Reports Third Quarter and
Nine Months Ended September 30, 2011 Financial Results
Nine Months Ended September 30, 2011 Financial Results
COLUMBUS, Ohio, November 3, 2011 Oxford Resource Partners, LP (NYSE: OXF) (the Partnership or
Oxford) today announced financial results for the third quarter and nine months ended September
30, 2011.
Net income for the third quarter of 2011 was negligible, compared to a net loss for the third
quarter of 2010 of $3.4 million, or $0.20 per diluted limited partner unit. Total revenue was
$110.0 million, up 23.5% from $89.1 million for the third quarter of 2010. Adjusted
EBITDA1 was $16.6 million, up 11.2% from $15.0 million for the third quarter of 2010.
Distributable cash flow1 was $3.9 million, as compared to $3.3 million for the third
quarter of 2010.
Negatively impacting net
income for the third quarter of 2011 was higher amortization expense of
approximately $1.1 million, or $0.05 per diluted limited partner
unit, related to four closed mines. Also negatively impacting
net income for the quarter were losses on disposals of major mining equipment of approximately $0.5
million, or $0.03 per diluted limited partner unit. Excluding these one-time non-cash charges, net
income for the third quarter of 2011 would have been $1.6 million, or $0.08 per diluted limited
partner unit. Negatively impacting distributable cash flow for the third quarter of 2011 were cash
reclamation costs of $1.9 million primarily related to the four mines mentioned above. The
information in this paragraph is provided for purposes of adjusting third quarter 2011 actual
results for one-time items and is not intended to be used to compare to actual third quarter 2010
results.
Net loss for the nine months ended September 30, 2011 was $8.0 million, or $0.38 per diluted
limited partner unit, compared to a net loss of $5.8 million, or $0.40 per diluted limited partner
unit, for the nine months ended September 30, 2010. Total revenue was $304.1 million, up 13.8%
from $267.3 million for the nine months ended September 30, 2010.
1. | Definitions of adjusted EBITDA and distributable cash flow, which are non-GAAP
financial measures, and reconciliations to comparable GAAP financial measures, are included
in the non-GAAP financial measures table presented at the end of this press release.
Adjusted EBITDA has been redefined and recalculated with resulting adjustments to the
previously-reported amount for the third quarter of 2010, as shown in the non-GAAP
financial measures table. |
Adjusted EBITDA for the nine months ended September 30, 2011 was $41.8 million, up 12.3% from $37.2
million for the nine months ended September 30, 2010. Net cash provided by operating activities
was $34.2 million, up 21.6% from $28.1 million for the nine months ended September 30, 2010.
Distributable cash flow was $8.1 million, with no comparable amount for the nine months ended
September 30, 2010.1
President and Chief Executive Officer Charles C. Ungurean commented, We are pleased to have the
weather-related disruptions that we faced during the first half of the year behind us. In the
third quarter, we benefited from a return to normal operating conditions and higher average sales
prices. These contributed to a 49% increase in adjusted EBITDA, a 38% increase in EBITDA per ton
margin and distributable cash flow growth of approximately $5.1 million as compared to the second
quarter of 2011.
Ungurean continued, We are on track to fully replace all of the reserves that we mine in 2011. In
addition, we have obtained permits covering approximately five million tons this year despite the
increasingly challenging regulatory environment. As a leading producer of surface mined thermal
coal, these actions support Oxfords continued growth trajectory.
1. | There is no comparable distributable cash flow amount for the nine months ended
September 30, 2010 because the Partnership does not calculate distributable cash flow with
respect to periods prior to becoming a publicly traded partnership in and for the second
half of 2010. |
Production and Sales Information Summary
A summary of certain production and sales information providing year-over-year comparisons for the
three months and nine months ended September 30, 2011, respectively, compared to the three months
and nine months ended September 30, 2010, respectively, is presented in the table set forth below.
Three Months Ended | Nine Months Ended | |||||||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||||||
2011 | 2010 | % Change | 2011 | 2010 | % Change | |||||||||||||||||||
(tons in thousands) | ||||||||||||||||||||||||
Tons of coal produced (clean) |
2,083 | 1,925 | 8.2 | % | 6,035 | 5,568 | 8.4 | % | ||||||||||||||||
Increase (decrease) in inventory |
(104 | ) | 22 | n/a | (36 | ) | 54 | n/a | ||||||||||||||||
Tons of coal purchased |
88 | 122 | (27.9 | %) | 365 | 617 | (40.8 | %) | ||||||||||||||||
Tons of coal sold |
2,275 | 2,025 | 12.3 | % | 6,436 | 6,131 | 5.0 | % | ||||||||||||||||
Tons of coal sold under long-term contracts(1) |
93.2 | % | 95.2 | % | n/a | 93.5 | % | 95.2 | % | n/a | ||||||||||||||
Average sales price per ton |
$ | 47.38 | $ | 43.32 | 9.4 | % | $ | 46.16 | $ | 42.80 | 7.9 | % | ||||||||||||
Cost of transportation per ton |
$ | 5.66 | $ | 4.74 | 19.4 | % | $ | 5.43 | $ | 4.73 | 14.8 | % | ||||||||||||
Average sales price per ton (net of transportation costs) |
$ | 41.72 | $ | 38.58 | 8.1 | % | $ | 40.73 | $ | 38.07 | 7.0 | % | ||||||||||||
Cost of purchased coal sales per ton |
$ | 35.72 | $ | 31.07 | 15.0 | % | $ | 35.78 | $ | 30.12 | 18.8 | % | ||||||||||||
Cost of coal sales per ton |
$ | 33.82 | $ | 30.03 | 12.6 | % | $ | 33.63 | $ | 31.13 | 8.0 | % | ||||||||||||
Number of operating days |
70.0 | 69.5 | n/a | 210.0 | 208.5 | n/a |
1. | Represents the percentage of the tons of coal sold that were delivered under long-term coal
sales contracts. |
Quarter Ended September 30, 2011 Compared to Quarter Ended September 30, 2010
Coal Production. Tons of coal produced increased 8.2% to 2.1 million tons for the third
quarter of 2011 from 1.9 million tons for the third quarter of 2010. This increase was primarily
attributable to increased production from the Cadiz and Muhlenberg mine complexes.
Sales Volume. Sales volume increased 12.3% to 2.3 million tons for the third quarter of 2011
from 2.0 million tons for the third quarter of 2010. This increase was primarily attributable to
sales resulting from increased contracted sales commitments.
Average Sales Price Per Ton (Net of Transportation Costs). Average sales price per ton (net
of transportation costs) increased 8.1% to $41.72 for the third quarter of 2011 from $38.58 for the
third quarter of 2010. This $3.14 per ton increase was primarily attributable to the higher
contracted sales price realizations from fuel escalators and changes in customer mix.
Coal Sales Revenue. Coal sales revenue for the third quarter of 2011 increased by $16.8
million, or 21.5%, to $94.9 million from $78.1 million for the third quarter of 2010. This
increase was attributable to the increase of $3.14 per ton in the average sales price coupled with
an increased sales volume of 0.3 million tons.
Royalty and Non-Coal Revenue. Royalty and non-coal revenue increased to $2.2 million for the
third quarter of 2011 from $1.3 million for the third quarter of 2010. This increase resulted from
higher royalties from underground coal reserves of $0.5 million combined with higher revenue from
both the sale of limestone and contract services of $0.3 million and $0.1 million, respectively.
During the third quarter of 2010 the Partnership experienced a $0.6 million temporary royalty
reduction from its underground coal reserves that are subleased, as mining occurred during the
quarter on a small piece of property in the center of the Partnerships reserves that was not
subject to royalty payments.
Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased 29.4% to
$74.0 million for the third quarter of 2011 from $57.1 million for the third quarter of 2010. This
$16.9 million increase resulted from an increase in production volumes which contributed to higher
costs of $8.6 million, an increase in diesel fuel costs of $2.7 million due to higher fuel prices,
higher inventory costs of $2.8 million, higher royalties and production taxes of $0.7 million and
an increase in all other operating costs of $2.1 million. Cost of coal sales per ton increased
12.6% to $33.82 per ton for the third quarter of 2011 from $30.03 per ton for the third quarter of
2010. This $3.79 per ton increase resulted primarily from an increase in diesel fuel costs of
$1.25 per ton, higher inventory costs of $1.29 per ton, higher royalties and production taxes of
$0.30 per ton and an increase in all other operating costs of $0.95 per ton.
Cost of Purchased Coal. Cost of purchased coal decreased to $3.1 million for the third
quarter of 2011 from $3.8 million for the third quarter of 2010. This decrease was primarily
attributable to a reduction in the volume of coal available for purchase under a contract with a
third-party supplier.
Depreciation, Depletion and Amortization (DD&A). DD&A expense for the third quarter of 2011
was $13.3 million compared to $12.3 million for the third quarter of 2010, an increase of $1.0
million. This increase was primarily attributable to higher amortization expense of approximately $1.1
million related to four closed mines.
Selling, General and Administrative Expenses (SG&A). SG&A expenses for the third quarter of
2011 were $3.1 million compared to $4.0 million for the third quarter of 2010, a decrease of $0.9
million. This decrease was primarily attributable to one-time transition costs incurred in
connection with becoming a publicly traded partnership in the third quarter of 2010.
Contract Termination and Amendment Expenses, Net. Contract termination and amendment expenses,
net for the third quarter of 2011 were zero compared to $0.7 million for the third quarter of 2010.
For 2010, there was a one-time charge of $2.5 million resulting from the termination of an
advisory agreement with certain affiliates in connection with the Partnerships initial public
offering, offset by a $1.8 million reduction in a specific reserve for a below-market coal supply
contract assumed in the purchase of the Illinois Basin assets that was amended to reset the price
to a market rate during the third quarter of 2010.
Transportation Revenue and Expenses. Transportation revenue and expenses for the third
quarter of 2011 increased 34.0% compared to the third quarter of 2010 due to growth in coal
shipments and rate increases related to higher diesel fuel prices.
Interest Expense (Net of Interest Income). Interest expense (net of interest income) for the
third quarter of 2011 was $2.4 million compared to $3.7 million for the third quarter of 2010, a
decrease of $1.3 million. Interest expense (net of interest income) for the third quarter of 2010
included loss on debt extinguishment of $1.3 million associated with the termination of the
Partnerships $115 million credit facility.
Net Income Attributable to Noncontrolling Interest. Net income attributable to noncontrolling
interest represents net income attributable to the 49% interest in Harrison Resources owned by
CONSOL Energy. For the third quarter of 2011 and 2010, the net income attributable to
noncontrolling interest was $1.1 million and $1.3 million, respectively.
Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010
Coal Production. Tons of coal produced increased 8.4% to 6.0 million tons for the first nine
months of 2011 from 5.6 million tons for the first nine months of 2010. This increase was
primarily attributable to increased production from the Cadiz and Muhlenberg mine complexes.
Sales Volume. Sales volume increased 5.0% to 6.4 million tons for the first nine months of
2011 from 6.1 million tons for the first nine months of 2010. This increase was primarily
attributable to sales resulting from increased contracted sales commitments.
Average Sales Price Per Ton (Net of Transportation Costs). Average sales price per ton (net
of transportation costs) increased 7.0% to $40.73 for the first nine months of 2011 from $38.07 for
the first nine months of 2010. This $2.66 per ton increase was primarily attributable to higher
contracted sales price realizations from fuel escalators and changes in customer mix.
Coal Sales Revenue. Coal sales revenue for the first nine months of 2011 increased by $28.6
million, or 12.3%, to $262.1 million from $233.5 million for the first nine months of 2010. This
increase was attributable to the increase of $2.66 per ton in the average sales price coupled with
an increased sales volume of 0.3 million tons.
Royalty and Non-Coal Revenue. Royalty and non-coal revenue increased to $7.0 million for the
first nine months of 2011 from $4.9 million for the first nine months of 2010. This increase
resulted from higher royalties from underground coal reserves of $0.4 million combined with higher
revenue from both the sale of limestone and contract services of $1.0 million and $0.7 million,
respectively. During the first nine months of 2010 the Partnership experienced a $1.7 million
temporary royalty reduction from its underground coal reserves that are subleased, as mining
occurred on a small piece of property in the center of the Partnerships reserves that was not
subject to royalty payments.
Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased 18.9% to
$204.1 million for the first nine months of 2011 from $171.6 million for the first nine months of
2010. This $32.5 million increase resulted from an increase in production volumes which
contributed to higher costs of $17.1 million, an increase in diesel fuel costs of $8.7 million due
to higher fuel prices, higher wages and benefits of $3.4 million due to increased headcount and
higher repair and maintenance costs of $2.5 million due to increases in parts and labor prices.
Additionally contributing to the higher costs were higher inventory costs of $2.0 million and an
increase in all other operating costs of $2.1 million. These increases were partially offset by
lower operating lease expense of $3.3 million due to the buy-out of previously leased major mining
equipment using proceeds from the Partnerships initial public offering and borrowings under the
Partnerships $175 million credit facility. Cost of coal sales per ton increased 8.0% to $33.63
per ton for the first nine months of 2011 from $31.13 per ton for the first nine months of 2010.
This $2.50 per ton increase resulted primarily from an increase in diesel fuel costs of $1.43 per
ton, higher wages and benefits of $0.56 per ton, higher repair and maintenance costs of $0.41 per
ton, higher inventory costs of $0.33 per ton, lower lease expense of $0.55 per ton and an increase
in all other operating costs of $0.32 per ton.
Cost of Purchased Coal. Cost of purchased coal decreased to $13.1 million for the first nine
months of 2011 from $18.6 million for the first nine months of 2010. This decrease was primarily
attributable to a reduction in the volume of coal available for purchase under a contract with a
third-party supplier.
Depreciation, Depletion and Amortization (DD&A). DD&A expense for the first nine months of
2011 was $38.7 million compared to $30.6 million for the first nine months of 2010, an increase of
$8.1 million. This increase was primarily attributable to the purchase of previously leased and
additional major mining equipment using proceeds from the Partnerships initial public offering and
borrowings under the Partnerships $175 million credit facility, which resulted in $4.1 million
higher depreciation. Additionally, revisions in estimated reclamation costs for stream and wetland
mitigation on closed mines and revised estimates related to the closure of previously active
mines increased amortization expense by approximately $2.9 million.
Selling, General and Administrative Expenses (SG&A). SG&A expenses for the first nine months
of 2011 were $10.5 million compared to $10.4 million for the first nine months of 2010, an increase
of $0.1 million.
Contract Termination and Amendment Expenses, Net. Contract termination and amendment expenses,
net for the first nine months of 2011 were zero compared to $0.7 million for the first nine months
of 2010. For 2010, there was a one-time charge of $2.5 million resulting from the termination of
an advisory agreement with certain affiliates in connection with the Partnerships initial public
offering, offset by a $1.8 million reduction in a specific reserve for a below-market coal supply
contract assumed in the purchase of the Illinois Basin assets that was amended to reset the price
to a market rate during the first nine months of 2011.
Transportation Revenue and Expenses. Transportation revenue and expenses for the first nine
months of 2011 increased 20.7% compared to the first nine months of 2010 due to growth in coal
shipments and rate increases related to higher diesel fuel prices.
Interest Expense (Net of Interest Income). Interest expense (net of interest income) for the
first nine months of 2011 was $6.8 million compared to $7.5 million for the first nine months of
2010, a decrease of $0.7 million. This decrease was primarily attributable to a loss on debt
extinguishment of $1.3 million associated with the termination of the Partnerships $115 million
credit facility during the first nine months of 2010, partially offset by increased fees in
connection with the Partnerships $175 million credit facility during the first nine months of
2011.
Net Income Attributable to Noncontrolling Interest. Net income attributable to noncontrolling
interest represents net income attributable to the 49% interest in Harrison Resources owned by
CONSOL Energy. For the first nine months of 2011 and 2010, the net income attributable to
noncontrolling interest was $4.0 million and $4.6 million, respectively.
Recent Events
On October 20, 2011, the Partnership declared a cash distribution of $0.4375 per unit for the
quarter ended September 30, 2011. The distribution will be paid on November 14, 2011 to all
unitholders of record as of the close of business on November 1, 2011.
On October 26, 2011, Oxford executed an amendment to the coal supply agreement with American
Electric Power Service Corporation (AEP). Prior to the amendment, the term of the supply
agreement ran through 2012, subject to extension by AEP for up to two further three-year terms.
With the amendment, Oxford and AEP have agreed to extend the term of the supply agreement through
2015, with an AEP option to elect by June 2013 a further three-year extension through 2018. The
amended supply agreement provides for Oxford to supply 1.7 million tons of coal annually during the
delivery period from 2012 through 2015, and also during the delivery period from 2016 through 2018
if the extension is elected by AEP. The amendment also provides for an additional annual option of
up to 0.4 million tons of coal if elected by AEP.
Outlook
Ungurean concluded, We believe our strategy of being a low cost thermal coal producer in Northern
Appalachia and the Illinois Basin uniquely positions us to generate value for our unitholders. The
supply and demand fundamentals in our market remain positive with thermal coal sold domestically
benefiting from elevated exports and strong met coal demand. Coal inventories at utilities have
declined significantly year-to-date and pricing remains favorable for our coal. In addition, we
believe that the new Cross-State Air Pollution Rule which takes effect in 2012 will not
significantly impact our contracted sales commitments. Ultimately our
customers base-load
scrubbed power plants may actually secure additional electricity market share in this stricter
regulatory environment.
Based on actual results for the first three quarters of the year and the latest estimate for the
fourth quarter of 2011, Oxford is updating guidance as shown below.
Current Guidance | Previous Guidance | |||||
Full Year 2011 | Full Year 2011 | |||||
(Range) | (Range) | |||||
(in thousands, except per ton amounts) | ||||||
Tons of coal produced (clean) |
8,000 8,200 | 8,000 8,300 | ||||
Tons of coal sold |
8,600 8,800 | 8,600 9,000 | ||||
Average sales price per ton |
||||||
(including transportation costs) |
$45.75 $46.50 | n/a | ||||
(net of transportation costs) |
$40.25 $41.00 | $40.00 $41.00 | ||||
Depreciation, depletion and amortization |
$49,000 $52,000 | $44,000 $47,000 | ||||
Maintenance capital expenditures |
||||||
(including reserve replacement) |
$37,000 $39,000 | $37,000 $40,000 |
Conference Call
Oxford will host a conference call at 10:00 a.m. Eastern Time today to review its financial results
for the third quarter of 2011. To participate in the call, dial (800) 920-8624 or (617) 597-5430
for international callers and provide the passcode 75950453. The call will also be webcast live on
the Internet in the Investor Relations section of Oxfords website at
www.OxfordResources.com.
An audio replay of the conference call will be available for seven days beginning at 1:00 p.m.
Eastern Time on November 3, 2011 and can be accessed at (888) 286-8010 or (617) 801-6888 for
international callers. The replay passcode is 36663955. The webcast will also be archived on the
Partnerships website at www.OxfordResources.com for 30 days following the call.
About Oxford Resource Partners, LP
Oxford Resource Partners, LP is a low cost producer of high value steam coal in Northern Appalachia
and the Illinois Basin. The Partnership markets its coal primarily to large electric utilities
with coal-fired, base-load scrubbed power plants under long-term coal sales contracts. As of
December 31, 2010, the Partnership controlled 93.5 million tons of proven and probable coal
reserves, and it currently operates 22 active surface mines that are managed as eight mining
complexes. The Partnership is headquartered in Columbus, Ohio.
For more information about Oxford Resource Partners, LP (NYSE: OXF), please visit
www.OxfordResources.com. Financial and other information about us is routinely posted on
and accessible at www.OxfordResources.com.
This announcement is intended to be a qualified notice under Treasury Regulation Section
1.1446-4(b), with 100% of Oxfords distributions to foreign investors attributable to income that
is effectively connected with a United States trade or business. Accordingly, Oxfords
distributions to foreign investors are subject to federal income tax withholding at the highest
applicable tax rate.
FORWARD-LOOKING STATEMENTS: Except for historical information, statements made in this press
release are forward-looking statements. All statements, other than statements of historical
facts, included in this press release that address activities, events or developments that the
Partnership expects, believes or anticipates will or may occur in the future are forward-looking
statements, including the statements and information included under the heading Outlook. These
statements are based on certain assumptions made by the Partnership based on its managements
experience and perception of historical trends, current conditions, expected future developments
and other factors the Partnerships management believes are appropriate in the circumstances. Such
statements are subject to a number of assumptions, risks and uncertainties, many of which are
beyond the Partnerships control, which may cause actual results to differ materially from those
implied or expressed by the forward-looking statements. These risks, uncertainties and
contingencies include, but are not limited to, the following: productivity levels, margins earned
and the level of operating costs; weakness in global economic conditions or in customers
industries; changes in governmental regulation of the mining industry or the electric power
industry and the increased costs of complying with those changes; decreases in demand for
electricity and changes in coal consumption patterns of U.S. electric power generators; the
Partnerships dependence on a limited number of customers; the Partnerships inability to enter
into new long-term coal sales contracts at attractive prices and the renewal and other risks
associated with the Partnerships existing long-term coal sales contracts, including risks related
to adjustments to price, volume or other terms of those contracts; difficulties in collecting the
Partnerships receivables because of credit or financial problems of major customers, and customer
bankruptcies, cancellations or breaches to existing contracts, or other failures to perform; the
Partnerships ability to acquire additional coal reserves; the Partnerships ability to respond to
increased competition within the coal industry; fluctuations in coal demand, prices and
availability due to labor and transportation costs and disruptions, equipment availability or
governmental regulations; significant costs imposed on the Partnerships mining operations by
extensive environmental laws and regulations, and greater than expected environmental regulations,
costs and liabilities; legislation and regulatory and related court decisions and interpretations
including issues related to climate change and miner health and safety; a variety of operational,
geologic, permitting, labor and weather-related factors; limitations in the cash distributions the
Partnership receives from Harrison Resources, LLC, and the ability of Harrison Resources, LLC to
acquire additional reserves on economical terms from Consolidation Coal Company in the future; the
potential for inaccuracies in estimates of the Partnerships coal reserves; the accuracy of the
assumptions underlying the Partnerships reclamation and mine closure obligations; liquidity
constraints; risks associated with major mine-related accidents; results of litigation; the
Partnerships ability to attract and retain key management personnel; greater than expected
shortage of skilled labor; the Partnerships ability to maintain satisfactory relations with
employees; and failure to obtain, maintain or renew security arrangements. The Partnership
undertakes no obligation to publicly update or revise any forward-looking statements. Further
information on risks and uncertainties is available in the Partnerships filings with the U.S.
Securities and Exchange Commission, which are incorporated by reference.
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(in thousands, except for unit data)
(UNAUDITED)
(in thousands, except for unit data)
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenue |
||||||||||||||||
Coal sales |
$ | 94,919 | $ | 78,127 | $ | 262,093 | $ | 233,454 | ||||||||
Transportation revenue |
12,867 | 9,605 | 34,976 | 28,976 | ||||||||||||
Royalty and non-coal revenue |
2,202 | 1,347 | 7,015 | 4,857 | ||||||||||||
Total revenue |
109,988 | 89,079 | 304,084 | 267,287 | ||||||||||||
Costs and expenses |
||||||||||||||||
Cost of coal sales (excluding depreciation,
depletion and amortization, shown separately) |
73,957 | 57,138 | 204,141 | 171,635 | ||||||||||||
Cost of purchased coal |
3,143 | 3,790 | 13,058 | 18,617 | ||||||||||||
Cost of transportation |
12,867 | 9,605 | 34,976 | 28,976 | ||||||||||||
Depreciation, depletion and amortization |
13,323 | 12,255 | 38,669 | 30,587 | ||||||||||||
Selling, general and administrative expenses |
3,114 | 4,044 | 10,458 | 10,446 | ||||||||||||
Contract termination and amendment expenses, net |
| 652 | | 652 | ||||||||||||
Total costs and expenses |
106,404 | 87,484 | 301,302 | 260,913 | ||||||||||||
Income from operations |
3,584 | 1,595 | 2,782 | 6,374 | ||||||||||||
Interest income |
5 | 3 | 10 | 11 | ||||||||||||
Interest expense |
(2,431 | ) | (3,662 | ) | (6,787 | ) | (7,535 | ) | ||||||||
Net income (loss) |
1,158 | (2,064 | ) | (3,995 | ) | (1,150 | ) | |||||||||
Less: net income attributable to noncontrolling interest |
(1,134 | ) | (1,336 | ) | (4,015 | ) | (4,644 | ) | ||||||||
Net income (loss) attributable to Oxford Resource
Partners, LP unitholders |
$ | 24 | $ | (3,400 | ) | $ | (8,010 | ) | $ | (5,794 | ) | |||||
Net loss allocated to general partner |
$ | | $ | (68 | ) | $ | (160 | ) | $ | (116 | ) | |||||
Net loss allocated to limited partners |
$ | 24 | $ | (3,332 | ) | $ | (7,850 | ) | $ | (5,678 | ) | |||||
Net loss per limited partner unit: |
||||||||||||||||
Basic |
$ | | $ | (0.20 | )(1) | $ | (0.38 | ) | $ | (0.40 | ) | |||||
Dilutive |
$ | | $ | (0.20 | )(1) | $ | (0.38 | ) | $ | (0.40 | ) | |||||
Weighted average number of
limited partner units outstanding: |
||||||||||||||||
Basic |
20,635,288 | 18,884,324 | 20,631,055 | 14,306,473 | ||||||||||||
Dilutive |
20,706,794 | 18,884,324 | 20,631,055 | 14,306,473 | ||||||||||||
Distributions paid per limited partner unit(2) |
$ | 0.4375 | $ | | $ | 1.3125 | $ | 0.2300 | ||||||||
(1) | Amounts revised to correct for rounding differences. |
|
(2) | Excludes amounts distributed as part of the initial public offering. |
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(in thousands, except for unit data)
(UNAUDITED)
(in thousands, except for unit data)
September 30, | December 31, | |||||||
2011 | 2010 | |||||||
ASSETS |
||||||||
Cash and cash equivalents |
$ | 658 | $ | 889 | ||||
Trade accounts receivable |
33,464 | 28,108 | ||||||
Inventory |
13,588 | 12,640 | ||||||
Advance royalties |
1,412 | 924 | ||||||
Prepaid expenses and other current assets |
2,161 | 1,023 | ||||||
Total current assets |
51,283 | 43,584 | ||||||
Property, plant and equipment, net |
199,784 | 198,694 | ||||||
Advance royalties |
6,139 | 7,693 | ||||||
Other long-term assets |
12,221 | 11,100 | ||||||
Total assets |
$ | 269,427 | $ | 261,071 | ||||
LIABILITIES |
||||||||
Current maturities of long-term debt |
$ | 11,237 | $ | 7,249 | ||||
Accounts payable |
30,782 | 26,074 | ||||||
Asset retirement obligations current portion |
3,937 | 6,450 | ||||||
Deferred revenue current portion |
164 | 780 | ||||||
Accrued taxes other than income taxes |
1,870 | 1,643 | ||||||
Accrued payroll and related expenses |
3,557 | 2,625 | ||||||
Other current liabilities |
3,337 | 2,952 | ||||||
Total current liabilities |
54,884 | 47,773 | ||||||
Long-term debt |
123,021 | 95,737 | ||||||
Asset retirement obligations |
16,094 | 6,537 | ||||||
Other long-term liabilities |
1,748 | 2,261 | ||||||
Total liabilities |
195,747 | 152,308 | ||||||
PARTNERS CAPITAL |
||||||||
Limited Partner unitholders (20,638,808 and 20,610,983 units
outstanding as of September 30, 2011 and December 31, 2010,
respectively) |
71,206 | 105,684 | ||||||
General Partner unitholder (421,128 and 420,633 units outstanding
as of September 30, 2011 and December 31, 2010, respectively) |
(763 | ) | (63 | ) | ||||
Total Oxford Resource Partners, LP Capital |
70,443 | 105,621 | ||||||
Noncontrolling interest |
3,237 | 3,142 | ||||||
Total partners capital |
73,680 | 108,763 | ||||||
Total liabilities and partners capital |
$ | 269,427 | $ | 261,071 | ||||
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
(UNAUDITED)
(in thousands)
Nine Months Ended | ||||||||
September 30, | ||||||||
2011 | 2010 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net loss attributable to Oxford Resource Partners, LP unitholders |
$ | (8,010 | ) | $ | (5,794 | ) | ||
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities: |
||||||||
Depreciation, depletion and amortization |
38,669 | 30,587 | ||||||
Interest rate swap or rate cap adjustment to market |
76 | 286 | ||||||
Loan fee amortization |
1,173 | 787 | ||||||
Loss on debt extinguishment |
| 1,302 | ||||||
Non-cash equity compensation expense |
854 | 686 | ||||||
Advanced royalty recoupment |
1,050 | 1,202 | ||||||
Loss on disposal of property and equipment |
1,239 | 766 | ||||||
Noncontrolling interest in subsidiary earnings |
4,015 | 4,644 | ||||||
(Increase) decrease in assets: |
||||||||
Accounts receivable |
(5,356 | ) | (2,658 | ) | ||||
Inventory |
251 | (2,957 | ) | |||||
Other assets |
(639 | ) | 135 | |||||
Increase (decrease) in liabilities: |
||||||||
Accounts payable and other liabilities |
4,331 | 3,106 | ||||||
Asset retirement obligations |
(2,114 | ) | (620 | ) | ||||
Provision for below-market contracts and deferred revenue |
(1,357 | ) | (3,373 | ) | ||||
Net cash provided by operating activities |
34,182 | 28,099 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Purchase of property and equipment |
(27,237 | ) | (68,545 | ) | ||||
Purchase of mineral rights and land |
(1,124 | ) | (3,105 | ) | ||||
Mine development costs |
(3,182 | ) | (2,230 | ) | ||||
Royalty advances |
(484 | ) | (966 | ) | ||||
Insurance proceeds |
| 1,223 | ||||||
Proceeds from sale of property and equipment |
| 36 | ||||||
Change in restricted cash |
(2,121 | ) | (3,352 | ) | ||||
Net cash used in investing activities |
(34,148 | ) | (76,939 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Initial public offering |
| 150,544 | ||||||
Offering expenses |
| (6,097 | ) | |||||
Proceeds from borrowings |
| 60,041 | ||||||
Payments on borrowings |
(4,728 | ) | (89,942 | ) | ||||
Advances on line of credit |
51,000 | 31,000 | ||||||
Payments on line of credit |
(15,000 | ) | (10,500 | ) | ||||
Credit facility issuance costs |
| (5,603 | ) | |||||
Capital contributions from partners |
12 | 25 | ||||||
Distributions to partners |
(27,629 | ) | (79,711 | ) | ||||
Distributions to noncontrolling interest |
(3,920 | ) | (2,450 | ) | ||||
Net cash provided by (used in) financing activities |
(265 | ) | 47,307 | |||||
Net increase (decrease) in cash |
(231 | ) | (1,533 | ) | ||||
CASH AND CASH EQUIVALENTS, beginning of period |
889 | 3,366 | ||||||
CASH AND CASH EQUIVALENTS, end of period |
$ | 658 | $ | 1,833 | ||||
NON-GAAP FINANCIAL MEASURES TABLE
Reconciliation of net loss attributable to Oxford Resource Partners, LP unitholders to adjusted
EBITDA and distributable cash flow:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2011 | 2010 | 2011 | 2010 | |||||||||||||
(in thousands, unaudited) | ||||||||||||||||
Net income (loss) attributable to Oxford
Partners, LP unitholders |
$ | 24 | $ | (3,400 | ) | $ | (8,010 | ) | $ | (5,794 | ) | |||||
PLUS: |
||||||||||||||||
Interest expense, net of interest income |
2,426 | 3,659 | 6,777 | 7,524 | ||||||||||||
Depreciation, depletion and amortization |
13,323 | 12,255 | 38,669 | 30,587 | ||||||||||||
Contract termination and amendment expenses, net |
| 652 | | 652 | ||||||||||||
Non-cash equity-based compensation expense |
245 | 230 | 854 | 686 | ||||||||||||
Non-cash loss on asset disposals |
516 | 314 | 1,239 | 766 | ||||||||||||
Non-cash portion of asset retirement obligations |
356 | 1,521 | 3,004 | 4,065 | ||||||||||||
LESS: |
||||||||||||||||
Amortization of below-market coal
sales contracts |
244 | 258 | 741 | 1,283 | ||||||||||||
Adjusted EBITDA |
$ | 16,646 | $ | 14,973 | $ | 41,792 | $ | 37,203 | ||||||||
LESS: |
||||||||||||||||
Cash interest expense, net of interest income |
2,009 | 1,863 | 5,528 | |||||||||||||
Estimated reserve replacement expenditures |
1,529 | 1,322 | 4,357 | |||||||||||||
Other maintenance capital expenditures |
9,243 | 8,449 | 23,823 | |||||||||||||
Distributable cash flow(1) |
$ | 3,865 | $ | 3,339 | $ | 8,084 | ||||||||||
(1) | Oxford does not calculate distributable cash flow with respect to the periods prior
to becoming a publicly traded limited partnership in and for the second half of 2010. |
Adjusted EBITDA
Adjusted EBITDA for a period represents net income (loss) attributable to our unitholders for
that period before interest, taxes, depreciation, depletion and amortization, gain on purchase of
business, contract termination and amendment expenses, net, amortization of below-market coal sales
contracts, non-cash equity-based compensation expense, non-cash gain or loss on asset disposals and
the non-cash change in future asset retirement obligations (ARO). The non-cash change in future
ARO is the portion of our non-cash change in our future ARO that is included in reclamation expense
in our financial statements. Although adjusted EBITDA is not a measure of performance calculated
in accordance with GAAP, our management believes that it is useful in evaluating our financial
performance and our compliance with certain credit facility financial covenants. Because not all
companies calculate adjusted EBITDA identically, our calculation may not be comparable to the
similarly titled measure of other companies.
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 credit facility financial covenants; and |
| our ability to fund capital expenditure projects from operating cash flow. |
Distributable Cash Flow
Distributable cash flow for a period represents adjusted EBITDA for that period, less cash
interest expense (net of interest income), estimated reserve replacement expenditures and other
maintenance capital expenditures. Cash interest expense represents the portion of our interest
expense accrued and paid in cash during the reporting periods presented or that we will pay in cash
in future periods as the obligations become due. Estimated reserve replacement expenditures
represent an estimate of the average periodic (quarterly or annual, as applicable) reserve
replacement expenditures that we will incur over the long term as applied to the applicable period.
We use estimated reserve replacement expenditures to calculate distributable cash flow instead of
actual reserve replacement expenditures, consistent with our partnership agreement which requires
that we deduct estimated reserve replacement expenditures when calculating operating surplus.
Other maintenance capital expenditures include, among other things, actual expenditures for plant,
equipment, mine development and expenditures relating to our ARO. Distributable cash flow should
not be considered as 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. Although distributable cash flow is not a measure of performance
calculated in accordance with GAAP, our management believes distributable cash flow is a useful
measure to investors because this measurement is used by many analysts and others in the industry
as a performance measurement tool to evaluate our operating and financial performance and to
compare it with the performance of other publicly traded limited partnerships. We also compare
distributable cash flow to the cash distributions we expect to pay our unitholders. Using this
measure, management can quickly compute the coverage ratio of distributable cash flow to planned
cash distributions.