Oxford Resource Partners, LP Reports Third Quarter and Nine Months Ended September 30, 2011 Financial Results

COLUMBUS, Ohio, Nov. 3, 2011 /PRNewswire/ -- 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 EBITDA(1) was $16.6 million, up 11.2% from $15.0 million for the third quarter of 2010.  Distributable cash flow(1) 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.

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 Oxford's continued growth trajectory."

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.

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 Partnership's 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 Partnership's 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 Partnership's $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 Partnership's 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 Partnership's initial public offering and borrowings under the Partnership's $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 Partnership's initial public offering and borrowings under the Partnership's $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 Partnership's 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 Partnership's $115 million credit facility during the first nine months of 2010, partially offset by increased fees in connection with the Partnership's $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.

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 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 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 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.

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.  

SOURCE Oxford Resource Partners, LP

WANT YOUR COMPANY'S NEWS FEATURED ON PRNEWSWIRE.COM?

440k+
Newsrooms &
Influencers

9k+
Digital Media
Outlets

270k+
Journalists
Opted In

GET STARTED