2014

Oxford Resource Partners, LP Reports Fourth Quarter and Full Year 2011 Financial Results

COLUMBUS, Ohio, Feb. 29, 2012 /PRNewswire/ -- Oxford Resource Partners, LP (NYSE: OXF) (the "Partnership" or "Oxford") today announced 2011 financial results for the fourth quarter and full year.

Fourth Quarter 2011 Results

Net loss for the fourth quarter of 2011 was $5.1 million, or $0.24 per diluted limited partner unit, compared to a net loss for the fourth quarter of 2010 of $1.6 million, or $0.05 per diluted limited partner unit.  Contributing to the increased net loss was lower adjusted EBITDA(1) of $12.2 million, down $2.2 million from $14.4 million for the same quarter in 2010.  Other contributing factors were higher depreciation, depletion and amortization ("DD&A") of $1.5 million and higher interest expense of $1.1 million due to higher borrowings outstanding and a bank amendment fee of $0.5 million.  Distributable cash flow(1) was $0.2 million, as compared to $5.2 million for the prior year period, due primarily to the lower adjusted EBITDA coupled with higher maintenance capital expenditures of $2.1 million because the majority of the maintenance capital during 2010 was pre-funded out of IPO proceeds and borrowings under the Partnership's credit facility.

For the fourth quarter of 2011, total revenue increased $7.0 million or 7.8 percent over the prior year quarter with coal sales revenue increasing 4.5 percent or $1.71 per ton.  Cost of coal sales increased $10.4 million or 18.1 percent while cost of coal sales on a per ton basis increased $3.64 or 12.0 percent year-over-year.  The decrease in coal sales margin was primarily attributable to higher diesel fuel prices, increased wages and benefits and higher operating lease expense which collectively accounted for over 75 percent of the adjusted EBITDA decrease.  Production and sales volume increases were limited to 2.6 percent and 0.1 percent, respectively, over the same quarter in 2010 due primarily to key permit issuance delays at the Partnership's newly-opened Ellis and Shuman mines and supplier performance issues related to a long-term coal purchase contract.

Full Year 2011 Results

Net loss for the year ended December 31, 2011 was $13.1 million, or $0.62 per diluted limited partner unit, compared to a net loss for the year ended December 31, 2010 of $7.4 million, or $0.45 per diluted limited partner unit.  Factors contributing to the increased net loss were higher DD&A and interest expense of $9.6 million and $0.4 million, respectively.  Adjusted EBITDA(1) was $54.0 million, up 4.7 percent from $51.6 million for the prior year.  Distributable cash flow(1) was $8.3 million, with no comparable amount for the prior year period.(2)

For 2011, total revenue increased $43.8 million or 12.3 percent over the prior year with coal sales revenue increasing 10.3 percent or $2.42 per ton.  Cost of coal sales increased $43.0 million or 18.7 percent while cost of coal sales on a per ton basis increased $2.78 or 9.0 percent year-over-year.  Contributing to this per ton increase were higher diesel fuel prices, increased wages and benefits and higher repairs and maintenance, which accounted for nearly 90 percent of the increase.  Despite the negative impacts experienced throughout the year, clean production and sales volumes for 2011 were up 6.9 percent and 3.8 percent, respectively, over 2010 which contributed to the increase in adjusted EBITDA year-over-year.

(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.

(2)  There is no comparable distributable cash flow amount for the year ended December 31, 2010 because the Partnership does not calculate distributable cash flow with respect to periods prior to becoming a publicly traded partnership in and for the second half of 2010.

Production and Sales Information Summary



Three Months Ended


Twelve Months Ended



December 31,


December 31,



2011


2010

% Change


2011


2010

% Change



(tons in thousands)












Tons of coal produced (clean)


1,952


1,903

2.6%


7,987


7,470

6.9%

Increase (decrease) in inventory


55


1

n/a


91


(53)

n/a

Tons of coal purchased


16


117

(27.9%)


380


734

(48.2%)

Tons of coal sold


2,023


2,021

0.1%


8,458


8,151

3.8%












Tons of coal sold











under long-term contracts(1)


96.7%


95.2%

n/a


96.6%


95.9%

n/a












Average sales price per ton


$ 46.46


$ 43.36

7.1%


$ 46.23


$ 42.94

7.7%

Cost of transportation per ton


$   6.10


$   4.71

29.5%


$   5.59


$   4.72

18.4%

Average sales price per ton











(net of transportation expenses)


$ 40.36


$ 38.65

4.4%


$ 40.64


$ 38.22

6.3%












Cost of purchased coal sales per ton


$ 26.92


$ 29.15

(7.7%)


$ 35.47


$ 30.00

18.2%

Cost of coal sales per ton


$ 34.02


$ 30.38

12.0%


$ 33.72


$ 30.94

9.0%












Number of operating days


68.5


66.5

n/a


278.5


275.5

n/a



(1)

Represents the percentage of the tons of coal sold that were delivered under long-term coal sales contracts.



President and Chief Executive Officer Charles C. Ungurean commented, "Significant weather disruptions, key permitting delays and supplier performance issues negatively impacted our production and sales volumes throughout the year.  Due to decreased productivity and higher costs, our adjusted EBITDA and distributable cash flow were much lower than anticipated.  We are disappointed with these results which were well below our expectations."

Ungurean concluded, "Going into 2012, with our fully contracted sales book at higher prices we expect improvement in our 2012 financial results as compared to 2011.  We do, however, find ourselves facing a general softening of the coal markets.  As a result, we have had to accommodate the changing supply profile of some customers and have done so to date without adversely impacting profitability.  We also remain focused on reviewing and modifying our operations to manage controllable costs and eliminate discretionary capital expenditures during this period of market weakness.  For instance, in addressing certain aspects of our Illinois Basin operations, we have reached an agreement for 2012 and 2013 to purchase coal on more favorable terms rather than supplying our own washed coal on certain customer contracts, enabling us to idle one of our mines and shut down a washplant, and allowing us to supply all of our Illinois Basin coal to customers on a raw basis, resulting in cost savings in 2012.  We will continue to evaluate additional such opportunities over the course of the year."

Liquidity and Distributions

For the year ended December 31, 2011, the Partnership's distributable cash flow did not cover its distributions to its unitholders. The Partnership's ability to pay its quarterly distributions substantially depends upon its future operating performance (which may be impacted by conditions affecting the coal industry as was the case in 2011), borrowing availability and other factors, some of which are beyond the Partnership's control.  Regarding its borrowing availability, the Partnership and its lenders amended the Partnership's credit agreement at the end of 2011 which enabled the Partnership to increase its borrowing availability from $5.1 million to $27.5 million going into 2012, but there is no assurance that the Partnership will be able to sustain any assured level or further increase its level of borrowing availability.  To the extent the Partnership's future operating cash flow and access to financing sources are insufficient, its future liquidity could be adversely affected with the result that its future operations and ability to make a portion or all of its distributions to unitholders could also be adversely affected.  The Partnership does not provide guidance as to its quarterly distributions, and the board of directors of the Partnership's general partner makes its determination regarding each quarterly distribution based on the circumstances existing at the time of the determination.

2012 Outlook

Based on the Partnership's industry outlook, it provides the below guidance for 2012 and sets forth alongside such guidance the actual results for 2011.


2012


2011


(in thousands, except per ton amounts)

Tons of coal produced (clean)

7,500

-

8,000


7,987

Tons of coal sold

7,900

-

8,400


8,458







Average sales price per ton






(including transportation costs)

$50.00

-

$52.00


$46.23

(net of transportation costs)

$43.00

-

$45.00


$40.64







Depreciation, depletion and amortization

$52,000

-

$57,000


$51,905

Maintenance capital expenditures






(including reserve replacement)

$32,000

-

$36,000


$37,107









Recent Event

On January 27, 2012, the Partnership declared a cash distribution of $0.4375 per unit for the quarter ended December 31, 2011.  The distribution was paid on February 14, 2012 to all unitholders of record as of the close of business on February 7, 2012.

Conference Call

Oxford will host a conference call at 10:00 a.m. Eastern Time today (February 29, 2012) to review its financial results for the fourth quarter and full year 2011.  To participate in the call, dial (888) 396-2356 or (617) 847-8709 for international callers and provide passcode 13193967.  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 12:00 p.m. Eastern Time on February 29, 2012 and can be accessed at (888) 286-8010 or (617) 801-6888 for international callers.  The replay passcode is 77153090.  The webcast will also be archived on Oxford'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, 2011, the Partnership controlled 88.0 million tons of proven and probable coal reserves, and it currently operates 19 active 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 Oxford 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 "2012 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 under 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, governmental regulations, including those pertaining to carbon dioxide emissions, and other factors; significant costs imposed on the Partnership's mining operations by extensive and frequently changing environmental laws and regulations, and greater than expected environmental regulations, costs and liabilities; legislation and regulatory and related judicial decisions and interpretations including issues pertaining to climate change and miner health and safety; a variety of operational, geologic, permitting, labor and weather-related factors, including those pertaining to both our mining operations and our underground coal reserves that we do not operate; limitations in the cash distributions the Partnership receives from its majority-owned subsidiary, Harrison Resources, LLC, and the ability of Harrison Resources, LLC to acquire additional reserves on economical terms from CONSOL Energy Inc. in the future; the potential for inaccuracies in estimates of the Partnership's coal reserves, which could result in lower than expected revenues or higher than expected costs; the accuracy of the assumptions underlying the Partnership's reclamation and mine closure obligations; liquidity constraints, including those resulting from the cost or unavailability of financing due to current capital markets conditions; risks associated with major mine-related accidents; results of litigation, including claims not yet asserted; 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, such as surety bonds or letters of credit, in a timely manner and on acceptable terms.

The Partnership undertakes no obligation to publicly update or revise any forward-looking statements. Readers should not place undue reliance on forward-looking statements, which reflect management's views only as of the date hereof.  Further information on risks and uncertainties is available in the Partnership's periodic reports filed with the U.S. Securities and Exchange Commission or otherwise publicly disseminated by the Partnership.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES










CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except for unit data)












Three Months Ended


Twelve Months Ended



December 31,


December 31,



2011


2010


2011


2010

Revenue









Coal sales


$      81,648


$      78,113


$    343,741


$    311,567

Transportation revenue


12,329


9,514


47,305


38,490

Royalty and non-coal revenue


2,316


1,664


9,331


6,521

Total revenue


96,293


89,291


400,377


356,578










Costs and expenses









Cost of coal sales (excluding depreciation,









depletion and amortization, shown separately)


68,279


57,833


272,420


229,468

Cost of purchased coal


422


3,407


13,480


22,024

Cost of transportation


12,329


9,514


47,305


38,490

Depreciation, depletion and amortization


13,236


11,742


51,905


42,329

Selling, general and administrative expenses


3,281


4,311


13,739


14,757

Contract termination and amendment expenses, net


-


-


-


652

Total costs and expenses


97,547


86,807


398,849


347,720










Income from operations


(1,254)


2,484


1,528


8,858

Interest income


3


1


13


12

Interest expense


(3,083)


(1,976)


(9,870)


(9,511)

Net income (loss)


(4,334)


509


(8,329)


(641)










Less:  net income attributable to noncontrolling interest


(733)


(2,066)


(4,748)


(6,710)










Net income (loss) attributable to Oxford Resource









 Partners, LP unitholders


$      (5,067)


$      (1,557)


$    (13,077)


$      (7,351)










Net loss allocated to general partner


$         (101)


$           (31)


$         (261)


$         (147)










Net loss allocated to limited partners


$      (4,966)


$      (1,526)


$    (12,816)


$      (7,204)










Net loss per limited partner unit:









Basic


$        (0.24)


$        (0.05)


$        (0.62)


$        (0.45)










Dilutive


$        (0.24)


$        (0.05)


$        (0.62)


$        (0.45)










Weighted average number of









limited partner units outstanding:









Basic


20,651,471


20,580,918


20,641,127


15,887,977










Dilutive


20,651,471


20,580,918


20,641,127


15,887,977










Distributions paid per limited partner unit (1)


$      0.4375


$      0.3500


$      1.7500


$      0.5800





















(1)  Excludes amounts distributed as part of the initial public offering during 2010.



OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES






CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands, except for unit data)








December 31,


December 31,



2011


2010

ASSETS





Cash and cash equivalents


$            3,032


$               889

Trade accounts receivable


28,388


28,108

Inventory


12,000


12,640

Advance royalties


1,412


924

Prepaid expenses and other current assets


1,226


1,023

Total current assets


46,058


43,584






Property, plant and equipment, net


195,607


198,694

Advance royalties


7,945


7,693

Other long-term assets


11,655


11,100

Total assets


$        261,265


$        261,071






LIABILITIES





Current maturities of long-term debt


$          11,234


$            7,249

Accounts payable


26,940


26,074

Asset retirement obligations - current portion


4,553


6,450

Deferred revenue - current portion


-


780

Accrued taxes other than income taxes


1,732


1,643

Accrued payroll and related expenses


2,535


2,625

Other current liabilities  


3,822


2,952

Total current liabilities


50,816


47,773






Long-term debt, less current maturities


132,521


95,737

Asset retirement obligations


17,236


6,537

Other long-term liabilities


1,575


2,261

Total liabilities


202,148


152,308






PARTNERS' CAPITAL





Limited partner unitholders (20,680,124 and 20,610,983 units
       outstanding as of December 31, 2011 and December 31, 2010,
       respectively)


57,160


105,684

General partner unitholder (422,044 and 420,633 units outstanding
        as of December 31, 2011 and December 31, 2010, respectively)


(1,032)


(63)

Total Oxford Resource Partners, LP Capital


56,128


105,621

Noncontrolling interest


2,989


3,142

Total partners' capital


59,117


108,763

Total liabilities and partners' capital


$        261,265


$        261,071



OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES






CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)













Twelve Months Ended



December 31,



2011


2010

CASH FLOWS FROM OPERATING ACTIVITIES:





Net loss attributable to Oxford Resource Partners, LP unitholders


$ (13,077)


$ (7,351)

Adjustments to reconcile net loss to net cash provided by operating activities





Depreciation, depletion and amortization


51,905


42,329

Interest rate swap or rate cap adjustment to market


48


142

Loan fee amortization


1,600


1,239

Loss on debt extinguishment


-


1,302

Non-cash equity compensation expense


1,077


942

Advanced royalty recoupment


1,408


1,609

Loss on disposal of property and equipment


1,352


3,499

Noncontrolling interest in subsidiary earnings


4,748


6,710

(Increase) decrease in assets:





Accounts receivable


(280)


(3,705)

Inventory


1,731


(3,542)

Other assets


(452)


455

Increase (decrease) in liabilities:





Accounts payable and other liabilities


(331)


956

Asset retirement obligations


(3,476)


(1,583)

Provision for below-market contracts and deferred revenue


(1,719)


(2,734)

Net cash provided by operating activities


44,534


40,268






CASH FLOWS FROM INVESTING ACTIVITIES:





Purchase of property and equipment


(34,120)


(78,199)

Purchase of mineral rights and land


(1,088)


(3,120)

Mine development costs


(4,780)


(3,029)

Royalty advances


(1,222)


(1,169)

Insurance proceeds


1,096


2,271

Proceeds from sale of property and equipment


849


36

Change in restricted cash


(2,179)


(1,684)

Net cash used in investing activities


(41,444)


(84,894)






CASH FLOWS FROM FINANCING ACTIVITIES:





Initial public offering


-


150,544

Offering expenses


-


(6,097)

Proceeds from borrowings


-


60,040

Payments on borrowings


(6,231)


(92,552)

Advances on line of credit


62,000


39,000

Payments on line of credit


(15,000)


(10,500)

Credit facility issuance costs


-


(5,603)

Capital contributions from partners


28


47

Distributions to partners


(36,843)


(87,095)

Distributions to noncontrolling interest


(4,901)


(5,635)

Net cash  (used in)  provided by financing activities


(947)


42,149






Net increase (decrease) in cash


2,143


(2,477)






CASH AND CASH EQUIVALENTS, beginning of period


889


3,366

CASH AND CASH EQUIVALENTS, end of period


$    3,032


$      889



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


Twelve Months Ended



December 31,


December 31,



2011


2010


2011


2010



(in thousands, unaudited)

Net income (loss) attributable to Oxford Resource









Partners, LP unitholders


$ (5,067)


$ (1,557)


$ (13,077)


$ (7,351)










PLUS:









Interest expense, net of interest income


3,080


1,975


9,857


9,499

Depreciation, depletion and amortization


13,236


11,742


51,905


42,329

Contract termination and amendment expenses, net


-


-


-


652

Non-cash equity-based compensation expense


223


256


1,077


942

Non-cash loss on asset disposals


113


462


1,352


1,228

Non-cash portion of asset retirement obligations


351


1,677


3,355


5,742

Acquisition costs


507


-


507


-










LESS:









Amortization of below-market coal









sales contracts


198


141


939


1,424










Adjusted EBITDA


$ 12,245


$ 14,414


$  54,037


$ 51,617










LESS:









Cash interest expense, net of interest income excluding amendment fees

2,256


1,668


7,784



Estimated reserve replacement expenditures


1,440


1,313


5,797



Other maintenance capital expenditures


8,336


6,246


32,159












Distributable cash flow (1)


$      213


$   5,187


$    8,297





(1)

Oxford does not calculate distributable cash flow with respect to the periods prior to becoming a publicly traded limited partnership in and for the second half of 2010



Adjusted EBITDA

Adjusted EBITDA for a period represents net income (loss) attributable to our unitholders for that period before interest, taxes, DD&A and such items as gain on purchase of business, acquisition costs which are required by GAAP to be expensed, contract termination and amendment expenses, net, amortization of below-market coal sales contracts, non-cash equity-based compensation expense, 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.  Adjusted EBITDA 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.  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) and excluding amendment fees, 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 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



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