Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - Westmoreland Resource Partners, LP | c20858e8vk.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 Second Quarter and
First Half 2011 Financial Results
First Half 2011 Financial Results
COLUMBUS, Ohio, August 4, 2011 — Oxford Resource Partners, LP (NYSE: OXF) (the “Partnership” or
“Oxford”) today announced financial results for the second quarter and first half of 2011.
Net loss for the second quarter of 2011 was $6.3 million, or $0.30 per diluted limited partner
unit, compared to a net loss for the second quarter of 2010 of $2.1 million, or $0.18 per diluted
limited partner unit. Total revenue was $98.0 million for the second quarter of 2011, up 8.7% from
$90.1 million for the second quarter of 2010. Adjusted EBITDA1 was $11.2 million for the
second quarter of 2011, compared to $11.3 million for the second quarter of 2010. Net cash
provided by operating activities was $12.3 million for the second quarter of 2011, up 110.7% from
$5.8 million for the second quarter of 2010. Distributable cash flow1 was a negative
$1.3 million for the second quarter of 2011 with no comparable amount for the second quarter of
2010. Negatively impacting the quarter was record rainfall which affected production, per ton
costs and sales to river customers, along with higher diesel fuel prices, a substantial portion of
which will be recovered in the second half of the year through embedded fuel cost adjusters.
Net loss for the first half of 2011 was $8.0 million, or $0.38 per diluted limited partner unit,
compared to a net loss for the first half of 2010 of $2.4 million, or $0.20 per diluted limited
partner unit. Total revenue was $194.1 million for the first half of 2011, up 8.9% from $178.2
million for the first half of 2010. Adjusted EBITDA1 was $25.1 million for the first
half of 2011, up 13.1% from $22.2 million for the first half of 2010. Net cash provided by
operating activities was $29.5 million for the first half of 2011, up 108.2% from $14.2 million for
the first half of 2010. Distributable cash flow1 was $4.2 million for the first half of
2011 with no comparable amount for the first half of 2010. As with the second quarter, the first
half of 2011 was negatively impacted by adverse weather conditions in Northern Appalachia and the
Illinois Basin, along with higher diesel fuel prices, a substantial portion of which will be
recovered in the second half of the year through embedded fuel cost adjusters.
| 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 second quarter of 2010,
as shown in the non-GAAP financial measures table. |
President and Chief Executive Officer Charles C. Ungurean commented, “We continued to face severe
weather-related delays and unprecedented flooding on the Ohio and Green Rivers, particularly in the
months of April and May, which significantly hampered production, sales and ultimately our
profitability. As a result of the adverse weather, production was impacted by approximately
190,000 tons for the first half of the year, including 140,000 tons related to the second quarter,
which thereby increased our per ton costs. In addition, we lost a total of 30 barge
loading days due to flooding in the first half of 2011, 14 of which occurred during the second
quarter. As a result of both lost production and adverse weather, we were unable to ship to our
river customers approximately 160,000 tons during the second quarter and approximately 330,000 tons
during the first half of the year. To help make up some of this shortfall, we are leasing up to
$8.0 million in equipment to increase production by up to 30,000 tons per month starting in August.
June was the first full month without weather-related disruptions, and contributed to over 50% of
our adjusted EBITDA for the second quarter. The momentum we gained during June, our continued
investment in the business, and the higher average sales price resulting from our fuel cost
adjusters position us to dramatically improve upon our financial results in the second half of the
year and close the gap we experienced in the first half of the year related to covering our
distributions. In 2012, we expect to fully cover our minimum quarterly distribution.”
Production and Sales Information Summary
A summary of certain production and sales information providing year-over-year comparisons for the
second quarter and first half of 2011 compared to the second quarter and first half of 2010,
respectively, is presented in the table set forth below.
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (tons in thousands) | ||||||||||||||||
Tons of coal produced (clean) |
2,001 | 1,838 | 3,952 | 3,643 | ||||||||||||
(Increase) in inventory |
(39 | ) | (5 | ) | (68 | ) | (32 | ) | ||||||||
Tons of coal purchased |
135 | 238 | 276 | 495 | ||||||||||||
Tons of coal sold |
2,097 | 2,071 | 4,160 | 4,106 | ||||||||||||
Tons sold under long-term contracts (1) |
96.8 | % | 97.6 | % | 94.9 | % | 98.2 | % | ||||||||
Average sales price (net of transportation costs) per ton |
$ | 40.00 | $ | 37.94 | $ | 40.19 | $ | 37.83 | ||||||||
Cost of purchased coal sales per ton |
$ | 35.47 | $ | 29.28 | $ | 35.92 | $ | 29.95 | ||||||||
Cost of coal sales per ton |
$ | 34.44 | $ | 32.36 | $ | 33.52 | $ | 31.71 | ||||||||
Number of operating days — NAPP operations |
70.0 | 69.5 | 140.0 | 139.0 | ||||||||||||
Number of operating days — ILB operations |
70.0 | 69.5 | 140.0 | 139.0 | ||||||||||||
| (1) | Represents the percentage of the tons of coal sold that were delivered under long-term coal sales contracts. |
Quarter Ended June 30, 2011 Compared to Quarter Ended June 30, 2010
Coal Production. Tons of coal produced increased 8.9% to 2.0 million tons for the second
quarter of 2011 from 1.8 million tons for the second quarter of 2010. This increase was due
primarily to a 57.3% increase in production from the Illinois Basin operations. The Illinois Basin
operations improved because two mines with high strip ratios were closed at the end of the second
quarter of 2010 and were replaced with two new more productive mines. This increase was partially
offset by a 2.8% reduction in production from the Northern Appalachia operations due to the adverse
weather conditions. If not for the adverse weather conditions, raw coal production for the second
quarter of 2011 would have increased approximately 20.0% year over year compared to the second
quarter of 2010 taking into account the approximately 140,000 tons which were negatively impacted.
Sales Volume. Sales volume was 2.1 million tons for both the second quarter of 2011 and the
second quarter of 2010. Interruptions in both production and shipments via road and river barge
resulting from the adverse weather conditions and flooding during the second quarter of 2011
negatively impacted sales volume by approximately 160,000 tons. If not for these interruptions in
production and shipments, sales volume would have increased by approximately 9.0 % for the second
quarter of 2011 compared to the second quarter of 2010.
Average Sales Price (Net of Transportation Costs) Per Ton. Average sales price (net of
transportation costs) per ton increased 5.4% to $40.00 for the second quarter of 2011 from $37.94
for the second quarter of 2010. This $2.06 per ton increase was primarily the result of higher
contracted sales prices realized from the Northern Appalachia contract portfolio and changes in
customer mix.
Coal Sales Revenue. For the second quarter of 2011, coal sales revenue increased by $5.3
million to $83.9 million from $78.6 million, or 6.7%, compared to the second quarter of 2010. This
increase was primarily attributable to the increase of $2.06 per ton in average sales price. If
not for the interruptions in production and shipments during the second quarter of 2011, coal sales
revenue for the second quarter of 2011 would have increased approximately 15.0% year over year
compared to the second quarter of 2010.
Royalty and Non-Coal Revenue. Royalty and non-coal revenue increased to $2.5 million for the
second quarter of 2011 from $1.7 million for the second quarter of 2010. This increase primarily
resulted from increases in revenue from both the sale of limestone and contract services of $0.6
million collectively.
Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased 13.9% to
$67.6 million for the second quarter of 2011 from $59.3 million for the second quarter of 2010.
Contributing to the increase was an increase in production volumes coupled with higher diesel fuel
costs. Cost of coal sales per ton increased by 6.4% to $34.44 per ton for the second
quarter of 2011 compared to $32.36 per ton for the second quarter of 2010. This $2.08 per ton
increase resulted from the impact of higher diesel fuel prices which increased operating costs by
approximately $4.7 million, or $2.37 per ton.
Cost of Purchased Coal. Cost of purchased coal decreased to $4.8 million for the second
quarter of 2011 from $7.0 million for the second quarter of 2010. This decrease was attributable
to a reduction in the volume of coal purchased by the Illinois Basin operations due to a
corresponding increase in production volumes.
Depreciation, Depletion and Amortization (DD&A). DD&A expense for the second quarter of 2011
was $13.2 million compared to $9.6 million for the second quarter of 2010, an increase of $3.6
million. This increase was primarily attributable to increased DD&A resulting from the purchase of
previously leased and additional major mining equipment using proceeds from the Partnership’s
initial public offering and borrowings under its $175 million credit facility.
Selling, General and Administrative Expenses (SG&A). SG&A expenses for the second quarter of
2011 were $3.4 million compared to $2.9 million for the second quarter of 2010, an increase of $0.5
million. This increase was attributable to an increase of $0.5 million in wages and benefits due
to an increase in the number of employees.
Transportation Revenue and Expenses. Transportation revenue and expenses for the second
quarter of 2011 increased 18.6% compared to the second quarter of 2010 due to growth in coal
shipments from the Partnership’s mines and rate increases related to higher fuel prices.
First Half Ended June 30, 2011 Compared to First Half Ended June 30, 2010
Coal Production. Tons of coal produced increased 8.5% to 4.0 million tons for the first half
of 2011 from 3.6 million tons for the first half of 2010. This increase was due primarily to a
46.5% increase in production from the Illinois Basin operations. The Illinois Basin operations
improved because two mines with high strip ratios were closed at the end of the second quarter of
2010 and were replaced with two new more productive mines. This increase was partially offset by a
1.5% reduction in production from the Northern Appalachia operations due to the adverse weather
conditions. If not for the adverse weather conditions, raw coal production for the first half of
2011 would have increased approximately 17.0% year over year compared to the first half of 2010
taking into account the approximately 190,000 tons which were negatively impacted.
Sales Volume. Sales volume increased 1.3% to 4.2 million tons for the first half of 2011 from
4.1 million tons for the first half of 2010. Interruptions in both production and shipments via
road and river barge resulting from the adverse weather conditions and flooding during the first
half of 2011 negatively impacted sales volume by approximately 330,000 tons. If not for
these interruptions in production and shipments, sales volume would have increased by
approximately 10.0% for the first half of 2011 compared to the first half of 2010.
Average Sales Price (Net of Transportation Costs) Per Ton. Average sales price (net of
transportation costs) per ton increased 6.2% to $40.19 for the first half of 2011 from $37.83 for
the first half of 2010. This $2.36 per ton increase was primarily the result of higher contracted
sales prices realized from the Partnership’s contract portfolio and changes in customer mix.
Coal Sales Revenue. For the first half of 2011, coal sales revenue increased by $11.8
million to $167.2 million from $155.3 million, or 7.6%, compared to the first half of 2010. This
increase was primarily attributable to the increase of $2.36 per ton in average sales price. If
not for the interruptions in production and shipments during the first half of 2011, coal sales
revenue for the first half of 2011 would have increased approximately 16.0% year over year compared
to the first half of 2010.
Royalty and Non-Coal Revenue. Royalty and non-coal revenue increased to $4.8 million for the
first half of 2011 from $3.5 million for the first half of 2010. This increase was due to
increases of $0.8 million in revenue from the sale of limestone and $0.6 million in revenue from
contract services for the first half of 2011 compared to the first half of 2010.
Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased 13.7% to
$130.2 million for the first half of 2011 from $114.5 million for the first half of 2010.
Contributing to the increase was an increase in production volumes coupled with higher diesel fuel
costs. Cost of coal sales per ton increased by 5.7% to $33.52 per ton for the first half of 2011
compared to $31.71 per ton for the first half of 2010. This $1.81 per ton increase resulted from
the impact of higher diesel fuel prices which increased operating costs by approximately $7.4
million, or $1.90 per ton.
Cost of Purchased Coal. Cost of purchased coal decreased to $9.9 million for the first half
of 2011 from $14.8 million for the first half of 2010. This decrease was attributable to a
reduction in the volume of coal purchased by the Illinois Basin operations due to a corresponding
increase in production volumes.
Depreciation, Depletion and Amortization (DD&A). DD&A expense for the first half of 2011 was
$25.3 million compared to $18.3 million for the first half of 2010, an increase of $7.0 million.
This increase was primarily attributable to increased DD&A resulting from the purchase of
previously leased and additional major mining equipment using proceeds from the Partnership’s
initial public offering and borrowings under its $175 million credit facility.
Selling, General and Administrative Expenses (SG&A). SG&A expenses for the first half of 2011
were $7.3 million compared to $6.4 million for the first half of 2010, an increase of $0.9
million. This increase was primarily attributable to an increase of $0.8 million in wages and
benefits due to an increase in the number of employees.
Transportation Revenue and Expenses. Transportation revenue and expenses for the first half
of 2011 increased 14.1% compared to the first half of 2010 due to growth in coal shipments from the
Partnership’s mines and rate increases related to higher fuel prices.
Subsequent Events
On July 12, 2011, the Partnership declared a cash distribution of $0.4375 per unit for the quarter
ended June 30, 2011. The distribution will be paid on August 12, 2011 to all unitholders of record
as of the close of business on August 1, 2011.
Outlook
Ungurean commented, “Global thermal coal demand and pricing dynamics are strengthening, aided by
strong exports to meet rising demand. At the same time, the changing production profile in the U.S.
coal market favors our producing regions of Northern Appalachia and the Illinois Basin. We are
well positioned with a fully contracted sales portfolio for the rest of 2011 and are 85% contracted
in 2012 at increasing price levels. Additionally, looking to 2012, substantially all of our coal
sales are to base-load scrubbed power plants that we believe meet the new air pollution standards
that will be implemented then.”
Ungurean concluded, “We are confirming that we fully expect to continue paying our minimum
quarterly distributions even though we do not anticipate fully earning them in 2011. As I
previously stated, we do expect to begin fully earning our distribution in 2012. Given the impact
on the first half of the year, we have updated our previously provided guidance range.”
| 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 - 8,300 | 8,200 - 8,700 | ||
Tons of coal sold |
8,600 - 9,000 | 8,800 - 9,300 | ||
Average sales price
(net of transportation costs) per ton |
$40.00 - $41.00 | $40.00 - $41.00 | ||
DD&A |
$44,000 - $47,000 | $44,000 - $47,000 | ||
Maintenance capital expenditures
(including reserve replacement) |
$37,000 - $40,000 | $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 second quarter of 2011. To participate in the call, dial (866) 804-6924 or (857) 350-1670
for international callers and provide the passcode 37534845. The call will also be webcast live on
the Internet in the Investor Relations section of Oxford’s 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 August 4, 2011 and can be accessed at (888) 286-8010 or (617) 801-6888 for
international callers. The replay passcode is 45960802. The webcast will also be archived on the
Partnership’s 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 Oxford’s distributions to foreign investors attributable to income that
is effectively connected with a United States trade or business. Accordingly, Oxford’s
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 management’s
experience and perception of historical trends, current conditions, expected future developments
and other factors the Partnership’s 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 Partnership’s 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
Partnership’s dependence on a limited number of customers; the
Partnership’s inability to enter into new long-term coal sales contracts at attractive prices and
the renewal and other risks associated with the Partnership’s existing long-term coal sales
contracts, including risks related to adjustments to price, volume or other terms of those
contracts; difficulties in collecting the Partnership’s 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 Partnership’s ability to acquire additional coal
reserves; the Partnership’s 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
Partnership’s 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
Partnership’s coal reserves; the accuracy of the assumptions underlying the Partnership’s
reclamation and mine closure obligations; liquidity constraints; risks associated with major
mine-related accidents; results of litigation; the Partnership’s ability to attract and retain key
management personnel; greater than expected shortage of skilled labor; the Partnership’s 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
Partnership’s filings with the U.S. Securities and Exchange Commission, which are incorporated by
reference.
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(in thousands, except for unit data)
(UNAUDITED)
(in thousands, except for unit data)
| June 30, | December 31, | |||||||
| 2011 | 2010 | |||||||
ASSETS |
||||||||
Cash and cash equivalents |
$ | 1,215 | $ | 889 | ||||
Trade accounts receivable |
31,157 | 28,108 | ||||||
Inventory |
16,061 | 12,640 | ||||||
Advance royalties |
880 | 924 | ||||||
Prepaid expenses and other current assets |
906 | 1,023 | ||||||
Total current assets |
50,219 | 43,584 | ||||||
Property, plant and equipment, net |
201,380 | 198,694 | ||||||
Advance royalties |
6,959 | 7,693 | ||||||
Other long-term assets |
9,351 | 11,100 | ||||||
Total assets |
$ | 267,909 | $ | 261,071 | ||||
LIABILITIES |
||||||||
Current maturities of long-term debt |
$ | 11,239 | $ | 7,249 | ||||
Accounts payable |
36,465 | 26,074 | ||||||
Asset retirement obligations — current portion |
4,282 | 6,450 | ||||||
Deferred revenue — current portion |
544 | 780 | ||||||
Accrued taxes other than income taxes |
1,791 | 1,643 | ||||||
Accrued payroll and related expenses |
3,279 | 2,625 | ||||||
Other current liabilities |
3,324 | 2,952 | ||||||
Total current liabilities |
60,924 | 47,773 | ||||||
Long-term debt |
107,520 | 95,737 | ||||||
Asset retirement obligations |
16,061 | 6,537 | ||||||
Other long-term liabilities |
1,894 | 2,261 | ||||||
Total liabilities |
186,399 | 152,308 | ||||||
PARTNERS’ CAPITAL |
||||||||
Limited Partner unitholders (20,635,249 and 20,610,983 units
outstanding as of June 30, 2011 and December 31, 2010,
respectively) |
79,987 | 105,684 | ||||||
General Partner unitholder (421,080 and 420,633 units
outstanding
as of June 30, 2011 and December 31, 2010, respectively) |
(580 | ) | (63 | ) | ||||
Total Oxford Resource Partners, LP Capital |
79,407 | 105,621 | ||||||
Noncontrolling interest |
2,103 | 3,142 | ||||||
Total partners’ capital |
81,510 | 108,763 | ||||||
Total liabilities and partners’ capital |
$ | 267,909 | $ | 261,071 | ||||
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 | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
Revenue |
||||||||||||||||
Coal sales |
$ | 83,870 | $ | 78,571 | $ | 167,174 | $ | 155,327 | ||||||||
Transportation revenue |
11,667 | 9,841 | 22,109 | 19,371 | ||||||||||||
Royalty and non-coal revenue |
2,493 | 1,736 | 4,813 | 3,510 | ||||||||||||
Total revenue |
98,030 | 90,148 | 194,096 | 178,208 | ||||||||||||
Costs and expenses |
||||||||||||||||
Cost of coal sales (excluding depreciation,
depletion and amortization, shown
separately) |
67,567 | 59,311 | 130,184 | 114,497 | ||||||||||||
Cost of purchased coal |
4,788 | 6,968 | 9,915 | 14,827 | ||||||||||||
Cost of transportation |
11,667 | 9,841 | 22,109 | 19,371 | ||||||||||||
Depreciation, depletion and amortization |
13,235 | 9,555 | 25,346 | 18,332 | ||||||||||||
Selling, general and administrative expenses |
3,378 | 2,867 | 7,344 | 6,402 | ||||||||||||
Total costs and expenses |
100,635 | 88,542 | 194,898 | 173,429 | ||||||||||||
Income (loss) from operations |
(2,605 | ) | 1,606 | (802 | ) | 4,779 | ||||||||||
Interest income |
4 | 7 | 5 | 8 | ||||||||||||
Interest expense |
(2,353 | ) | (2,040 | ) | (4,356 | ) | (3,873 | ) | ||||||||
Net income (loss) |
(4,954 | ) | (427 | ) | (5,153 | ) | 914 | |||||||||
Less: net income attributable to noncontrolling interest |
(1,310 | ) | (1,680 | ) | (2,881 | ) | (3,308 | ) | ||||||||
Net loss attributable to Oxford Resource
Partners, LP unitholders |
$ | (6,264 | ) | $ | (2,107 | ) | $ | (8,034 | ) | $ | (2,394 | ) | ||||
Net loss allocated to general partner |
$ | (125 | ) | $ | (42 | ) | $ | (160 | ) | $ | (48 | ) | ||||
Net loss allocated to limited partners |
$ | (6,139 | ) | $ | (2,065 | ) | $ | (7,874 | ) | $ | (2,346 | ) | ||||
Net loss per limited partner unit: |
||||||||||||||||
Basic |
$ | (0.30 | ) | $ | (0.18 | ) | $ | (0.38 | ) | $ | (0.20 | ) | ||||
Dilutive |
$ | (0.30 | ) | $ | (0.18 | ) | $ | (0.38 | ) | $ | (0.20 | ) | ||||
Weighted average number of
limited partner units outstanding: |
||||||||||||||||
Basic |
20,632,925 | 11,985,748 | 20,627,390 | 11,979,621 | ||||||||||||
Dilutive |
20,632,925 | 11,985,748 | 20,627,390 | 11,979,621 | ||||||||||||
Distributions paid per limited partner unit |
$ | 0.4375 | $ | — | $ | 0.8750 | $ | 0.2300 | ||||||||
OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
(UNAUDITED)
(in thousands)
| Six Months Ended | ||||||||
| June 30, | ||||||||
| 2011 | 2010 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||
Net loss attributable to Oxford Resource Partners, LP unitholders |
$ | (8,034 | ) | $ | (2,394 | ) | ||
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities: |
||||||||
Depreciation, depletion and amortization |
25,346 | 18,332 | ||||||
Interest rate swap or rate cap adjustment to market |
85 | 34 | ||||||
Loan fee amortization |
746 | 335 | ||||||
Non-cash equity compensation expense |
609 | 456 | ||||||
Advanced royalty recoupment |
654 | 965 | ||||||
Loss on disposal of property and equipment |
723 | 452 | ||||||
Noncontrolling interest in subsidiary earnings |
2,881 | 3,308 | ||||||
(Increase) decrease in assets: |
||||||||
Accounts receivable |
(3,049 | ) | (1,167 | ) | ||||
Inventory |
(2,654 | ) | (2,543 | ) | ||||
Other assets |
30 | (6,135 | ) | |||||
Increase (decrease) in liabilities: |
||||||||
Accounts payable and other liabilities |
11,856 | 5,387 | ||||||
Asset retirement obligations |
1,046 | 258 | ||||||
Provision for below-market contracts and deferred revenue |
(733 | ) | (3,115 | ) | ||||
Net cash provided by operating activities |
29,506 | 14,173 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||
Purchase of property and equipment |
(19,669 | ) | (10,333 | ) | ||||
Purchase of mineral rights and land |
(1,110 | ) | (2,228 | ) | ||||
Mine development costs |
(2,426 | ) | (969 | ) | ||||
Royalty advances |
(376 | ) | (409 | ) | ||||
Insurance proceeds |
— | 1,223 | ||||||
Proceeds from sale of property and equipment |
— | 36 | ||||||
Change in restricted cash |
954 | (2,765 | ) | |||||
Net cash used in investing activities |
(22,627 | ) | (15,445 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||
Payments on borrowings |
(3,227 | ) | (2,345 | ) | ||||
Advances on line of credit |
25,000 | 6,000 | ||||||
Payments on line of credit |
(6,000 | ) | — | |||||
Capital contributions from partners |
11 | 25 | ||||||
Distributions to noncontrolling interest |
(3,920 | ) | (1,470 | ) | ||||
Distributions to partners |
(18,417 | ) | (2,818 | ) | ||||
Net cash used in financing activities |
(6,553 | ) | (608 | ) | ||||
Net increase (decrease) in cash |
326 | (1,880 | ) | |||||
CASH AND CASH EQUIVALENTS, beginning of period |
889 | 3,366 | ||||||
CASH AND CASH EQUIVALENTS, end of period |
$ | 1,215 | $ | 1,486 | ||||
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 | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2011 | 2010 | 2011 | 2010 | |||||||||||||
| (in thousands, unaudited) | ||||||||||||||||
Net loss attributable to Oxford Resource
Partners, LP unitholders |
$ | (6,264 | ) | $ | (2,107 | ) | $ | (8,034 | ) | $ | (2,394 | ) | ||||
PLUS: |
||||||||||||||||
Interest expense, net of interest income |
2,349 | 2,033 | 4,351 | 3,865 | ||||||||||||
Depreciation, depletion and amortization |
13,235 | 9,555 | 25,346 | 18,332 | ||||||||||||
Non-cash equity-based compensation expense |
245 | 152 | 609 | 456 | ||||||||||||
Non-cash loss on asset disposals |
557 | 277 | 723 | 452 | ||||||||||||
Change in fair value of future asset
retirement obligations |
1,290 | 1,832 | 2,648 | 2,544 | ||||||||||||
LESS: |
||||||||||||||||
Amortization of below-market coal
sales contracts |
253 | 400 | 497 | 1,025 | ||||||||||||
Adjusted EBITDA |
$ | 11,159 | $ | 11,342 | $ | 25,146 | $ | 22,230 | ||||||||
LESS: |
||||||||||||||||
Cash interest expense, net of interest income |
1,980 | 3,519 | ||||||||||||||
Estimated reserve replacement expenditures |
1,497 | 2,828 | ||||||||||||||
Other maintenance capital expenditures |
8,942 | 14,580 | ||||||||||||||
Distributable cash flow (1) |
$ | (1,260 | ) | $ | 4,219 | |||||||||||
| (1) | The Partnership does not calculate distributable cash flow with respect to 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, DD&A, 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, and that portion represents the change over the applicable period in the value of our
ARO. 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 for the period that was paid in cash during the period or that we will pay in cash
in future periods. 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 and mine
development and our estimate of the periodic expenditures that we will incur over the long term
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.