Oxford Resource Partners, LP Reports Second Quarter and First Half 2011 Financial Results

COLUMBUS, Ohio, Aug. 4, 2011 /PRNewswire/ -- 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 EBITDA(1) 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 flow(1) 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 EBITDA(1) 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 flow(1) 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)








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)












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)













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.  

SOURCE Oxford Resource Partners, LP



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