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Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-34815

 

 

Oxford Resource Partners, LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   77-0695453

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer

Identification No.)

41 South High Street, Suite 3450, Columbus, Ohio 43215

(Address of Principal Executive Offices, Including Zip Code)

(614) 643-0337

(Registrant’s Telephone Number, Including Area Code)

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     YES  x    NO  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” and “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   ¨    Accelerated filer   x
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES  ¨    NO  x

As of May 4, 2012, 10,423,919 common units and 10,280,380 subordinated units were outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “OXF.”

 

 

 


Table of Contents

TABLE OF CONTENTS

 

         Page  

PART I. FINANCIAL INFORMATION

  

ITEM 1.   CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)      1   
  Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011      1   
  Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011      2   
  Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011      3   
  Condensed Consolidated Statements of Partners’ Capital for the Three Months Ended March 31, 2012 and 2011      4   
  Notes to Condensed Consolidated Financial Statements      5   
ITEM 2.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS      19   
ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK      39   
ITEM 4.   CONTROLS AND PROCEDURES      39   

PART II. OTHER INFORMATION

  

ITEM 1.   LEGAL PROCEEDINGS      40   
ITEM 1A.   RISK FACTORS      40   
ITEM 4.   MINE SAFETY DISCLOSURES      40   
ITEM 6.   EXHIBITS      40   

 

i


Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands, except for unit data)

 

     March 31,     December 31,  
     2012     2011  

ASSETS

    

Cash and cash equivalents

   $ 1,513      $ 3,032   

Trade accounts receivable

     34,750        28,388   

Inventory

     12,846        12,000   

Advance royalties—current portion

     1,834        1,412   

Prepaid expenses and other current assets

     1,192        1,226   

Assets held for sale

     10,819        —     
  

 

 

   

 

 

 

Total current assets

     62,954        46,058   

Property, plant and equipment, net

     173,157        195,607   

Advance royalties less current portion

     7,323        7,945   

Other long-term assets

     13,634        11,655   
  

 

 

   

 

 

 

Total assets

   $ 257,068      $ 261,265   
  

 

 

   

 

 

 

LIABILITIES

    

Current portion of long-term debt

   $ 11,267      $ 11,234   

Accounts payable

     29,388        26,940   

Asset retirement obligations - current portion

     8,487        4,553   

Accrued taxes other than income taxes

     1,531        1,732   

Accrued payroll and related expenses

     2,125        2,535   

Other current liabilities

     4,711        3,822   
  

 

 

   

 

 

 

Total current liabilities

     57,509        50,816   

Long-term debt, less current portion

     148,021        132,521   

Asset retirement obligations less current portion

     15,720        17,236   

Other long-term liabilities

     1,504        1,575   
  

 

 

   

 

 

 

Total liabilities

   $ 222,754      $ 202,148   
  

 

 

   

 

 

 

Commitments and Contingencies (Note 10)

    

PARTNERS’ CAPITAL

    

Limited partners unitholders (20,704,299 and 20,680,124 units outstanding as of March 31, 2012 and December 31, 2011, respectively)

     32,763        57,160   

General Partner unitholder (422,233 and 422,044 units outstanding as of March 31, 2012 and December 31, 2011, respectively)

     (1,529     (1,032
  

 

 

   

 

 

 

Total Oxford Resource Partners, LP capital

     31,234        56,128   

Noncontrolling interest

     3,080        2,989   
  

 

 

   

 

 

 

Total partners’ capital

     34,314        59,117   
  

 

 

   

 

 

 

Total liabilities and partners’ capital

   $ 257,068      $ 261,265   
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

1


Table of Contents

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except for unit data)

 

     Three Months Ended  
     March 31,  
     2012     2011  

Revenue

    

Coal sales

   $ 82,878      $ 83,304   

Transportation revenue

     11,935        10,442   

Royalty and non-coal revenue

     3,054        2,320   
  

 

 

   

 

 

 

Total revenue

     97,867        96,066   

Costs and expenses

    

Cost of coal sales (excluding depreciation, depletion and amortization, shown separately)

     69,615        62,617   

Cost of purchased coal

     3,203        5,127   

Cost of transportation

     11,935        10,442   

Depreciation, depletion and amortization

     13,682        12,111   

Impairment and restructuring charges

     8,355        —     

Selling, general and administrative expenses

     4,045        3,966   
  

 

 

   

 

 

 

Total costs and expenses

     110,835        94,263   

(Loss) income from operations

     (12,968     1,803   

Interest income

     1        1   

Interest expense

     (2,718     (2,003
  

 

 

   

 

 

 

Net loss

     (15,685     (199

Less: net income attributable to noncontrolling interest

     (91     (1,571
  

 

 

   

 

 

 

Net loss attributable to Oxford Resource Partners, LP unitholders

   $ (15,776   $ (1,770
  

 

 

   

 

 

 

Net loss allocated to general partner

   $ (315   $ (35
  

 

 

   

 

 

 

Net loss allocated to limited partners

   $ (15,461   $ (1,735
  

 

 

   

 

 

 

Net loss per limited partner unit:

    

Basic

   $ (0.75   $ (0.08
  

 

 

   

 

 

 

Diluted

   $ (0.75   $ (0.08
  

 

 

   

 

 

 

Weighted average number of limited partner units outstanding:

    

Basic

     20,689,448        20,621,793   
  

 

 

   

 

 

 

Diluted

     20,689,448        20,621,793   
  

 

 

   

 

 

 

Distributions paid per limited partner unit

   $ 0.4375      $ 0.4375   
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

 

     Three Months Ended  
     March 31,  
     2012     2011  

CASH FLOWS FROM OPERATING ACTIVITIES:

    

Net loss attributable to unitholders

   $ (15,776   $ (1,770

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

    

Depreciation, depletion and amortization

     13,682        12,111   

Impairment charges

     7,229        —     

Interest rate swap and fuel contract adjustment to market

     (161     (1

Loan fee amortization

     452        319   

Non-cash equity-based compensation expense

     262        364   

Advanced royalty recoupment

     291        309   

Loss on disposal of property and equipment

     1,177        166   

Non-controlling interest in subsidiary earnings

     91        1,571   

Decrease in assets:

    

Accounts receivable

     (6,362     (2,222

Inventory

     (846     (2,146

Other assets

     (578     (189

Decrease in liabilities:

    

Accounts payable and other liabilities

     5,152        7,906   

Asset retirement obligations

     (1,171     1,045   

Provision for below-market contracts and deferred revenue

     (20     (244
  

 

 

   

 

 

 

Net cash provided by operating activities

     3,422        17,219   

CASH FLOWS FROM INVESTING ACTIVITIES:

    

Purchase of property and equipment

     (7,017     (10,387

Purchase of mineral rights and land

     (51     (1,035

Mine development costs

     (1,116     (1,196

Royalty advances

     (1,530     (134

Proceeds from sale of property and equipment

     1,478        —     

Change in restricted cash

     (1,983     (339
  

 

 

   

 

 

 

Net cash used in investing activities

     (10,219     (13,091

CASH FLOWS FROM FINANCING ACTIVITIES:

    

Payments on borrowings

     (2,489     (1,606

Advances on line of credit

     17,000        11,000   

Capital contributions from partners

     3        5   

Distributions to noncontrolling interest

     —          (1,470

Distributions to partners

     (9,236     (9,206
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     5,278        (1,277

Net (decrease) increase in cash

     (1,519     2,851   

CASH AND CASH EQUIVALENTS, beginning of period

     3,032        889   
  

 

 

   

 

 

 

CASH AND CASH EQUIVALENTS, end of period

   $ 1,513      $ 3,740   
  

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(UNAUDITED)

(in thousands, except for unit data)

 

    Limited Partner                 Non-     Total  
    Subordinated     Common     General Partner     controlling     Partners’  
    Units     Capital     Units     Capital     Units     Capital     Interest     Capital  

Balance at December 31, 2010 

    10,280,380      $ (40,394     10,330,603      $ 146,078        420,633      $ (63   $ 3,142      $ 108,763   

Net (loss) income

      (864       (871       (35     1,571        (199

Partners’ contributions

            220        5          5   

Partners’ distributions

      (4,495       (4,527       (184     (1,470     (10,676

Equity-based compensation

          364              364   

Issuance of units to LTIP participants

        21,916        (383           (383
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at March 31, 2011

    10,280,380      $ (45,753     10,352,519      $ 140,661        420,853      $ (277   $ 3,243      $ 97,874   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2011

    10,280,380      $ (64,751     10,399,744      $ 121,911        422,044      $ (1,032   $ 2,989      $ 59,117   

Net (loss) income

      (7,677       (7,784       (315     91        (15,685

Partners’ contributions

            189        3          3   

Partners’ distributions

      (4,494       (4,557       (185       (9,236

Equity-based compensation

          262              262   

Issuance of units to LTIP participants

        24,175        (147           (147
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at March 31, 2012

    10,280,380      $ (76,922     10,423,919      $ 109,685        422,233      $ (1,529   $ 3,080      $ 34,314   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See accompanying notes to condensed consolidated financial statements.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“US GAAP”) for interim financial information and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by US GAAP for complete financial statements. In our opinion, the condensed consolidated financial statements reflect all adjustments necessary for a fair presentation of the results of operations and financial position for such periods. All such adjustments reflected in the condensed consolidated financial statements are considered to be of a normal recurring nature. The results of operations for any interim period are not necessarily indicative of results for the full year. Accordingly, these condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “Annual Report”) and filed with the U.S. Securities and Exchange Commission (the “SEC”).

NOTE 1: ORGANIZATION AND PRESENTATION

Significant Relationships Referenced in Notes to Condensed Consolidated Financial Statements (Unaudited)

 

   

“We,” “us,” “our,” or the “Partnership” means the business and operations of Oxford Resource Partners, LP, the parent entity, as well as its consolidated subsidiaries.

 

   

“ORLP” means Oxford Resource Partners, LP, individually as the parent entity, and not on a consolidated basis.

 

   

Our “GP” means Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP.

 

   

“Oxford” means our predecessor, Oxford Mining Company.

Organization

We are a low cost producer of high value steam coal. We focus on acquiring steam coal reserves that we can efficiently mine with our modern, large scale equipment. Our reserves and operations are strategically located in Northern Appalachia and the Illinois Basin to serve our primary market area of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. These coal reserves are mined by our subsidiaries, Oxford Mining Company, LLC (“Oxford Mining”), Oxford Mining Company—Kentucky, LLC and Harrison Resources, LLC (“Harrison Resources”).

We are managed by our GP and all executives, officers and employees who provide services to us are employees of our GP. Charles Ungurean, the President and Chief Executive Officer of our GP and a member of our GP’s board of directors, and Thomas Ungurean, the Senior Vice President, Equipment, Procurement and Maintenance of our GP, are the co-owners of one of our limited partners, C&T Coal, Inc. (“C&T Coal”).

We were formed in August 2007 to acquire all of the ownership interests in Oxford from C&T Coal. Immediately following the acquisition, C&T Coal and AIM Oxford Holdings, LLC (“AIM Oxford”) held a 34.3% and 63.7% limited partner interest in ORLP, respectively, and our GP owned a 2% general partner interest. Also at that time, the members of our GP were AIM Oxford with a 65% ownership interest and C&T Coal with a 35% ownership interest. After taking into account their indirect ownership of ORLP through our GP, AIM Oxford held a 65% total interest in ORLP and C&T Coal held a 35% total interest in ORLP.

On July 19, 2010, we completed the closing of the initial public offering of our common units. Immediately prior to the offering, we executed a unit split whereby the unitholders at that time received approximately 1.82097973 units in exchange for each unit they held at that time. As a result of these transactions, AIM Oxford’s and C&T Coal’s ownership of the Partnership, as of December 31, 2010, was 36.82% and 18.74%, respectively, with our GP’s ownership being 2.00%. The remaining 42.44% was held by the general public and our LTIP participants. AIM Oxford and C&T Coal owned 65.98% and 33.58%, respectively, of our GP as of December 31, 2010, with the remaining 0.44% interest therein being owned by Jeffrey M. Gutman, our Senior Vice President, Chief Financial Officer and Treasurer.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 1: ORGANIZATION AND PRESENTATION (continued)

 

On February 28, 2011, each of AIM Oxford and C&T Coal sold a portion of our common units held by them under Rule 144 in private transactions. Further, in January, March, June, September and December 2011, as well as January and March 2012, there were issuances of our common units to participants in our LTIP. As a result of these transactions, AIM Oxford’s and C&T Coal’s ownership of the Partnership, as of March 31, 2012, was 35.61% and 18.12%, respectively, with our GP’s ownership being 2.00%. The remaining 44.27% was held by the general public and our LTIP participants. AIM Oxford and C&T Coal own 65.65% and 33.41%, respectively, of the ownership interests in our GP as of March 31, 2012, with the remaining ownership interests therein being a 0.47% ownership interest held by Jeffrey M. Gutman, our Senior Vice President, Chief Financial Officer and Treasurer, and a 0.47% ownership interest held by Daniel M. Maher, our Senior Vice President, Chief Legal Officer and Secretary.

Basis of Presentation and Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with US GAAP.

We own a 51% interest in Harrison Resources and are therefore deemed to have control for purposes of US GAAP. As a result, we consolidate all of Harrison Resources’ accounts with all material intercompany transactions and balances being eliminated in our consolidated financial statements. The 49% portion of Harrison Resources that we do not own is reflected as “Noncontrolling interest” in our condensed consolidated balance sheets and statements of operations.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

There were no changes to our significant accounting policies from those disclosed in the audited consolidated financial statements and notes thereto contained in the Annual Report, except with respect to certain impairment and restructuring charges. Please read Note 3 – Impairment and Restructuring Charges for a discussion of impairment and restructuring charges recognized during the three months ended March 31, 2012.

New Accounting Standards Issued

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement – Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”). This guidance amends certain accounting and disclosure requirements related to fair value measurements to ensure that fair value has the same meaning in US GAAP and in IFRS and that their respective fair value measurement and disclosure requirements are the same. This guidance is effective for public entities during interim and annual periods beginning after December 15, 2011. The adoption of this guidance in 2011 did not have a material effect on our consolidated financial statements.

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income – Presentation of Comprehensive Income, which amends current comprehensive income guidance. This guidance eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, comprehensive income must be reported in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. This guidance will be effective for public companies during the interim and annual periods beginning after December, 15, 2011. The adoption of this guidance in 2011 did not have a material effect on our consolidated financial statements.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 3: IMPAIRMENT AND RESTRUCTURING CHARGES

In March of 2012, we implemented a restructuring plan with regard to our Illinois Basin operations. The restructuring was precipitated by the receipt of a contract termination notice from a customer of our Illinois Basin operations. This contract requires us to supply the customer with 800,000 tons of coal per year, and absent any termination thereof the term of the contract runs until December 31, 2015. We believe that this customer’s action was taken in bad faith, motivated by the combination of the price increase that recently went into effect under the customer’s sales contract and the current coal market conditions. We have retained legal counsel and are aggressively pursuing compensation for our damages through all appropriate legal measures.

To address this circumstance, we idled one mine, reduced mining operations at a second mine and terminated a significant number of employees for the Illinois Basin operations that supported the terminated contract. Prior thereto in February, we had idled another Illinois Basin mine and the Illinois Basin wash plant and lab and terminated some of our employees in connection with our decision to substitute purchased coal for mined and washed coal under certain customer sales contracts, and these actions alone did not have a material effect on us. With our commitment in March to the restructuring of our Illinois Basin operations, the earlier action has been included as a part of the overall restructuring. We are now proceeding to close these two idled mines and the wash plant and lab and sell or redeploy the mining equipment idled in this process. Equipment being transferred from these Illinois Basin mines to our Northern Appalachian operations is expected to enhance productivity and reduce future capital expenditures in our Northern Appalachian operations. We are selling excess Illinois Basin equipment idled because of the mine closures and reduced mine operations, and the proceeds of these sales will be used for working capital requirements.

In the first quarter of 2012, we recognized impairment charges of $7.2 million and incurred $1.2 million of restructuring charges related to the restructuring of our Illinois Basin operations. We expect to incur additional costs estimated at approximately $1.2 million throughout the remainder of 2012 in completing the execution of the restructuring plan.

Impairment Charges

As a result of the actions taken and our intent to close the two idled mines and wash plant referenced above, we recorded asset impairment charges of $7.2 million during the three months ended March 31, 2012. These charges included non-cash impairment charges related to coal reserves, mine development costs, and charges associated with certain fixed assets such as mining equipment and vehicles (the “Impaired Assets”) at our Illinois Basin operations.

In determining our impairment charges, we utilized market prices for similar assets and discounted projected future cash flows to determine the fair value of the Impaired Assets. Our discounted projected future cash flows are based on financial forecasts developed internally for planning purposes. These projections incorporate certain assumptions, including future costs and sales trends, estimated costs to sell and our expected net realizable values for those Impaired Assets. In accordance with applicable accounting guidance under US GAAP, those Impaired Assets that we plan to sell and are currently ready for sale are presented separately as current assets held for sale in our condensed consolidated balance sheet as of March 31, 2012 and are no longer being depreciated or amortized. Those Impaired Assets which do not meet the criteria for held for sale are presented in “Property, plant and equipment, net” in our condensed consolidated balance sheet as of March 31, 2012 at the revised carrying value after taking into account such impairment. Those Impaired Assets include machinery and equipment, vehicles, coal reserves and mine development assets that are still being used to wind down the mining process or for reclamation activities.

As additional information becomes available regarding the significant assumptions used in our analysis, we may conclude that it is necessary to update our impairment analysis in future periods, resulting in additional impairment charges.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 3: IMPAIRMENT AND RESTRUCTURING CHARGES (continued)

 

Restructuring Charges

Restructuring charges represent those expenses which are directly related to the restructuring plan and do not provide future economic benefit. We recorded total impairment and restructuring charges of $8.4 million related to our Illinois Basin operations during the three months ended March 31, 2012, as described in the table below. The charges included one-time employee termination costs for the approximately 160 terminated employees and professional and legal fees, as well as transportation costs associated with transferring some of the idled machinery and equipment to our Northern Appalachian operations. The legal fees are related to our pursuit of all available legal remedies to seek damages from the customer who terminated its sales contract which triggered the restructuring.

Restructuring accrual activity, combined with a reconciliation to the “Impairment and restructuring charges” set forth in our condensed consolidated statement of operations, is summarized below:

 

     January 1,
2012
     Three months ended
March 31, 2012
    March 31,
2012
 
     Liability      Expense      Payments     Liability  

Severance and other termination costs

   $ —         $ 728,000       $ (286,000   $ 442,000   

Professional fees and other costs

     —           369,000         (69,000     300,000   

Equipment relocation costs

     —           29,000         (9,000     20,000   
  

 

 

    

 

 

    

 

 

   

 

 

 

Total restructuring charges

   $ —         $ 1,126,000       $ (364,000   $ 762,000   
  

 

 

       

 

 

   

 

 

 

Asset impairment (non-cash)

        7,229,000        
     

 

 

      

Total impairment and restructuring charges

      $ 8,355,000        
     

 

 

      

The liabilities for restructuring in the table above are included in “Other current liabilities,” on our condensed consolidated balance sheet as of March 31, 2012. We expect to pay these obligations as well as additional expected expenses throughout 2012.

The following table summarizes the total expenses expected to be incurred for the impairment and restructuring charges over the course of the restructuring plan.

 

     Total Expected  
     Expenses  

Severance and other termination costs

   $ 801,000   

Professional fees and other costs

     996,000   

Equipment relocation costs

     571,000   

Asset impairment

     7,229,000   
  

 

 

 

Total impairment and restructuring charges

   $ 9,597,000   
  

 

 

 

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 4: INVENTORY

Inventory consisted of the following:

 

     March 31,      December 31,  
     2012      2011  

Coal

   $ 5,926,000       $ 4,346,000   

Fuel

     2,204,000         2,013,000   

Supplies and spare parts

     4,716,000         5,641,000   
  

 

 

    

 

 

 

Total

   $ 12,846,000       $ 12,000,000   
  

 

 

    

 

 

 

NOTE 5: PROPERTY, PLANT AND EQUIPMENT, NET

Property, plant and equipment, net of accumulated depreciation, depletion and amortization, consisted of the following:

 

     March 31,      December 31,  
     2012      2011  

Property, plant and equipment, gross

     

Land

   $ 3,188,000       $ 3,188,000   

Coal reserves

     53,663,000         55,124,000   

Mine development costs

     31,316,000         30,223,000   
  

 

 

    

 

 

 

Total property

     88,167,000         88,535,000   

Buildings and tipple

     2,133,000         2,133,000   

Machinery and equipment

     198,764,000         218,715,000   

Vehicles

     4,848,000         4,781,000   

Furniture and fixtures

     1,619,000         1,619,000   

Railroad sidings

     160,000         160,000   
  

 

 

    

 

 

 

Total property, plant and equipment, gross

     295,691,000         315,943,000   

Less: accumulated depreciation, depletion and amortization

     122,534,000         120,336,000   
  

 

 

    

 

 

 

Total property, plant and equipment, net

   $ 173,157,000       $ 195,607,000   
  

 

 

    

 

 

 

Assets held for sale of $10.8 million have been reclassified to current assets on our March 31, 2012 consolidated balance sheet and are not included in the amounts above. See further discussion in Note 3 – Impairment and Restructuring Charges and Note 7 – Fair Value of Financial Instruments and Derivatives Activity. Assets held for sale are no longer being depreciated or amortized.

The amounts of depreciation expense related to owned and leased fixed assets, depletion expense related to owned and leased coal reserves, and amortization expense related to mine development costs for the respective periods are set forth below:

 

     Three Months Ended  
     March 31,  
     2012      2011  

Expense type:

     

Depreciation

   $ 9,666,000       $ 9,099,000   

Depletion

     1,217,000         1,499,000   

Amortization

     2,738,000         1,445,000   

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 6: ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations (“ARO”) arise from the Surface Mining Control and Reclamation Act (“SMCRA”) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The required reclamation activities to be performed are outlined in our mining permits. These activities include reclaiming the pit and support acreage as well as stream mitigation at surface mines.

Effective June 30, 2011, we changed our method for estimating ARO for our mines from the current disturbance method to the end of mine life method. This represents a change in accounting estimate effected by a change in method to a method which is a preferable method under US GAAP. We believe the end of mine life method results in a more precise estimate and is more consistent with industry practice.

The end of mine life method focuses on estimating the liability based upon the productive life of the mine and more specifically the last pit(s) to be reclaimed once the mine is no longer producing coal as opposed to the current disturbance method which estimates the liability at the balance sheet date.

The balance sheet effects of the change in accounting method resulted in a reclassification of approximately $6.2 million from the current portion of ARO to the long-term portion of ARO in the quarter ended June 30, 2011. The impact of the change in method was negligible to our consolidated statement of operations for the periods ended June 30, 2011 and December 31, 2011. This change was accounted for, in accordance with ASC 250, on a prospective basis.

We review our ARO at least annually and make necessary adjustments for permit changes as granted by state authorities and for revisions of estimates of the amount and timing of costs. When the liability is initially recorded for the costs to open a new mine site, the offset is recorded to the mine development asset. Over time, the ARO liability is accreted to its present value and the capitalized cost for the related mine is depleted using the units-of-production method.

At March 31, 2012, we had recorded ARO liabilities of $24.2 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with absolute certainty, we estimate that, as of March 31, 2012, the aggregate undiscounted cost of final mine closure is approximately $27.5 million.

The following table presents the activity affecting the ARO for the respective periods:

 

     Three Months Ended     Twelve Months Ended  
     March 31, 2012     December 31, 2011  

Beginning balance

   $ 21,789,000      $ 12,987,000   

Accretion expense

     381,000        1,503,000   

Payments

     (1,552,000     (6,443,000

Revisions in estimated cash flows

     3,589,000        13,742,000   
  

 

 

   

 

 

 

Total asset retirement obligations

     24,207,000        21,789,000   

Less current portion

     8,487,000        4,553,000   
  

 

 

   

 

 

 

Noncurrent liability

   $ 15,720,000      $ 17,236,000   
  

 

 

   

 

 

 

For the quarter ended March 31, 2012, revisions in estimated cash flows increased the ARO liability $3.6 million and were primarily related to mine development at one new mine, which has now reached full operating capacity, and revisions of approximately $1.7 million to estimated closing costs and timing for the two mines and the wash plant which are being closed prematurely at the Muhlenberg Complex. The premature closures are a result of the restructuring plan implemented in first quarter 2012. Please read Note 3—Impairment and Restructuring Charges for further discussion. Adjustments to the ARO due to such revisions generally result in a corresponding adjustment to the related asset retirement cost in mine development.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 6: ASSET RETIREMENT OBLIGATIONS (continued)

 

In 2011, the revisions in estimated cash flows resulted in a net increase in the ARO of $13.7 million and were primarily related to mine development at eight new mines, as well as revisions to estimates of the expected costs for stream and wetland mitigation as regulatory requirements continue to evolve along with changes in estimated third-party unit costs. Adjustments to the ARO due to such revisions generally result in a corresponding adjustment to the related asset retirement cost in mine development. The portion of the revisions attributable to the change in method was negligible.

NOTE 7: FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVES ACTIVITY

We follow the provisions for fair value of financial assets and financial liabilities. We utilized fair value measurement guidance that, among other things, defines fair value, requires enhanced disclosures about assets and liabilities carried at fair value and establishes a hierarchical disclosure framework based upon the quality of inputs used to measure fair value. We have elected not to measure any additional financial assets or liabilities at fair value, other than those which were previously recorded at fair value prior to the adoption.

The financial instruments measured at fair value on a recurring basis are summarized below:

 

    Fair Value Measurement at March 31, 2012  
    Quoted Prices in
Active Markets for
Identical Liabilities
    Significant Other
Observable Inputs
    Significant
Unobservable
Inputs
 
Description   (Level 1)     (Level 2)     (Level 3)  

Interest rate swap agreement

  $ —        $ (124,000   $ —     

Fuel purchases accounted for as derivatives

    —          129,000        —     

 

    Fair Value Measurement at December 31, 2011  
    Quoted Prices in
Active Markets for
Identical Liabilities
    Significant Other
Observable Inputs
    Significant
Unobservable
Inputs
 
Description   (Level 1)     (Level 2)     (Level 3)  

Interest rate swap agreement

  $ —        $ (156,000   $ —     

The following methods and assumptions were used to estimate the fair values of financial instruments for which the fair value option was not elected:

Cash and cash equivalents, trade accounts receivable and accounts payable: The carrying amount reported in the balance sheets for cash and cash equivalents, trade accounts receivable and accounts payable approximates their fair values due to the short maturity of these instruments.

Derivatives: The fair value of derivatives is established using a discounted cash flow analysis using primarily inputs that can be observed within financial markets, such as LIBOR and ultra low-sulfur diesel rates.

Fixed rate debt: The fair value of fixed rate debt is estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows. As such, the fair value of fixed rate debt is considered Level 2.

Variable rate debt: The fair value of variable rate debt is estimated using discounted cash flow analyses, based on our best estimates of market rate for instruments with similar cash flows. As such, the fair value of variable rate debt is considered Level 2.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 7: FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVES ACTIVITY(continued)

 

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

 

     March 31, 2012      December 31, 2011  
     Carrying             Carrying         
     Amount      Fair Value      Amount      Fair Value  

Fixed rate debt

   $ 12,788,000       $ 14,040,000       $ 12,755,000       $ 13,650,000   

Variable rate debt

     146,500,000         146,500,000         131,000,000         131,000,000   

The following table sets forth by level within the fair value hierarchy our fair value measurements with respect to nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis as of March 31, 2012. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We have determined that certain of our nonfinancial assets and liabilities are Level 3 in the fair value hierarchy. We utilize discounted projected future cash flow techniques for our nonfinancial Level 3 fair value measurements. These techniques include unobservable data points such as future cost and sales trends and estimated costs to sell the impaired coal reserves and related mine development assets.

 

     Fair Value Measurements as of March 31, 2012        
     Active Markets
for Identical
Liabilities
     Significant
Other
Observable
Inputs
     Significant
Unobservable
Inputs
              
Description    (Level 1)      (Level 2)      (Level 3)      Total     Total Losses  

Assets held for sale

   $       $ 5,632,000       $       $ 5,632,000 (1)    ($ 1,722,000

Assets held and used

             1,237,000         1,792,000         3,029,000        ( 5,507,000
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $       $ 6,869,000       $ 1,792,000       $ 8,661,000      ($ 7,229,000
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

(1) 

Total held for sale assets on our March 31, 2012 balance sheet are $10,819,000. In addition, $5,187,000 of assets were not impaired and therefore are not reflected in the table above. Assets which were not impaired are recorded at their net book value rather than fair value.

During the first quarter 2012, assets held for sale with a carrying amount of $ 7.3 million were written down to their fair value of $5.6 million, resulting in an impairment charge of $1.7 million, which is included in impairment and restructuring charges in our condensed consolidated statements of operations. Please read Note 3—Impairment and Restructuring Charges for further discussion.

During the first quarter 2012, assets held and used with a carrying amount of $ 8.5 million were written down to their fair value of $3.0 million, resulting in an impairment charge of $5.5 million, which is included in impairment and restructuring charges in our condensed consolidated statements of operations. Please read Note 3—Impairment and Restructuring Charges for further discussion.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 7: FAIR VALUE OF FINANCIAL INSTRUMENTS AND DERIVATIVES ACTIVITY (continued)

 

Derivatives Activity

We are exposed to certain market risks, primarily fuel risk and interest rate risk. These risks represent risk of loss that may impact our business due to changes in underlying market rates or prices. We manage these risks through transactions that qualify for derivative accounting under ASC 815. We manage diesel fuel price risk by entering into fixed price forward contracts. Our risk management policy requires us to purchase up to 75% of our unhedged diesel fuel gallons under these fixed price forward contracts. Our strategy around our use of interest rate derivative instruments is to employ such instruments to fix a portion of our future interest cash outflows as discussed further in Note 10 of our Annual Report.

During the first quarter of 2012, as a result of the reduced production levels expected from restructuring the Illinois Basin operations, we will be unable to take physical delivery of all diesel fuel contracted for under our existing fuel contracts. Therefore, we renegotiated fuel deliveries and amended our fuel contracts into a single amended contract to decrease the fuel volume and net settle a portion of the previous contracts. This caused certain fuel contracts to no longer qualify for the normal purchase and sale exemption allowed by ASC 815, and the amended contract has been recognized as a derivative at March 31, 2012 with a value of a $129,000, recorded in “Prepaid expenses and other current assets,” resulting in a realized gain of $61,000 on the portion which was net settled. The amended contract is for 168,000 gallons to be delivered each month from April through September 2012 and 126,000 gallons to be delivered each month in the fourth quarter of 2012.

NOTE 8: LONG-TERM INCENTIVE PLAN

Under our LTIP, we recognize equity-based compensation expense over the vesting period of the units. Historically, these units have generally vested in equal annual increments over four years with accelerated vesting of the first increment in certain cases. Beginning in 2012, we also granted units that vest based on performance criteria established at the time of and in connection with the grant. The total number of units authorized for distribution under the LTIP was 2,056,075 at March 31, 2012 and 1,556,992 units remain available for issuance in the future assuming that all grants issued and currently outstanding are settled with common units, without reduction for tax withholding, and no future forfeitures occur.

For the three months ended March 31, 2012 and 2011, our equity-based compensation expense was approximately $262,000 and $364,000, respectively. These amounts are included in selling, general and administrative expenses (SG&A) in our condensed consolidated statements of operations. As of March 31, 2012 and December 31, 2011, approximately $2,634,000 and $978,000, respectively, of cost remained unamortized which we expect to recognize using the straight-line method over a remaining weighted average period of 1.6 years.

The following table summarizes additional information concerning our unvested LTIP units:

 

           Weighted  
           Average  
           Grant Date  
     Units     Fair Value  

Unvested balance at December 31, 2011

     80,043      $ 16.25   

Granted

     184,646        11.16   

Issued

     (24,175     13.78   

Surrendered

     (11,547     15.09   
  

 

 

   

Unvested balance at March 31, 2012

     228,967      $ 12.46   
  

 

 

   

The value of LTIP units vested during the three months ended March 31, 2012 and 2011 was $496,000 and $399,000, respectively.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 9: EARNINGS PER UNIT

For purposes of our earnings per unit calculation, we have applied the two class method. The classes of units are our limited partner and general partner units. All outstanding units share pro rata in income allocations and distributions and our general partner has sole voting rights.

Limited Partner Units: Basic earnings per unit are computed by dividing net income attributable to limited partners by the weighted average units outstanding during the reporting period. Diluted earnings per unit are computed similar to basic earnings per unit except that the weighted average units outstanding and net income attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to LTIP units upon vesting. In years of a loss, the phantom units are anti-dilutive and therefore not included in the earnings per unit calculation.

General Partner Units: Basic earnings per unit are computed by dividing net income attributable to our GP by the weighted average units outstanding during the reporting period. Diluted earnings per unit for our GP are computed similar to basic earnings per unit except that the net income attributable to the general partner units is adjusted for the dilutive impact of the phantom units. In years of a loss, the phantom units are anti-dilutive and therefore not included in the earnings per unit calculation.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 9: EARNINGS PER UNIT (continued)

 

The computation of basic and diluted earnings per unit under the two class method for limited partner units and general partner units is presented below:

 

     Three Months Ended  
     March 31,  
     2012     2011  
     (in thousands, except for unit and
per unit amounts)
 

Limited partner units

    

Average units outstanding:

    

Basic

     20,689,448        20,621,793   

Effect of equity-based compensation

     n/a        n/a   
  

 

 

   

 

 

 

Diluted

     20,689,448        20,621,793   
  

 

 

   

 

 

 

Net income (loss) allocated to limited partners

    

Basic

   $ (15,461   $ (1,735

Diluted

   $ (15,461   $ (1,735

Net income (loss) per limited partner unit

    

Basic

   $ (0.75   $ (0.08

Diluted

   $ (0.75   $ (0.08

General partner units

    

Average units outstanding:

    

Basic and diluted

     422,208        420,779   

Net income (loss) allocated to general partner

    

Basic

   $ (315   $ (35

Diluted

   $ (315   $ (35

Net income (loss) per general partner unit

    

Basic

   $ (0.75   $ (0.08

Diluted

   $ (0.75   $ (0.08

Anti-dilutive units (1)

     4,891        45,466   

Distributions paid per limited partner unit

   $ 0.4375      $ 0.4375   

 

(1)

Anti-dilutive units are not used in calculating dilutive average units.

NOTE 10: COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts

We are committed under long-term contracts to sell coal that meets certain quality requirements at specified prices. Most of these prices are subject to cost pass through or cost adjustment provisions that mitigate some risk from rising costs. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or us. The remaining terms of our long-term contracts now range from less than one year to almost four years.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 10: COMMITMENTS AND CONTINGENCIES (continued)

 

Purchase Commitments

We purchase coal from time to time from third parties in order to meet quality or delivery requirements under our customer contracts. We buy coal on the spot market, and the cost of that coal is dependent upon the market price and quality of the coal. Additionally, we assumed one long-term purchase contract with a third-party supplier in connection with an acquisition. Under this contract the third-party supplier is obligated to deliver and we are obligated to purchase 0.4 million tons of coal each year until the coal reserves covered by this contract are depleted. We have experienced supplier performance issues under this contract which continued through 2011 and still persist in 2012. The supplier has asserted that this contract is terminated by its terms, while we have taken a contrary position. We are now working with the supplier to resolve the matter.

On March 2, 2012, we entered into another long-term coal purchase contract with a separate supplier for our Illinois Basin operations for delivery of 350,000 tons of coal in 2012 and 360,000 tons of coal in 2013. A majority of the tons purchased in the first quarter of 2012 were under this new contract as compared to purchases under the previously-referenced lower priced contract which were in the first quarter of 2011.

Transportation

We depend upon barge, rail and truck transportation systems to deliver our coal to our customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments. We entered into a long-term rail transportation contract that has been amended and extended through March 31, 2014.

401(k) Plan

Effective January 1, 2010, our former defined contribution pension plan was replaced with our current 401(k) plan. At March 31, 2012, we had an obligation to pay our GP $2,761,000 for the purpose of funding our GP’s commitment to our 401(k) plan. Of this amount, $2,198,000 related to plan year 2011 and is expected to be paid by September 2012. The remainder of $563,000 is related to plan year 2012 and is expected to be paid by September 2013.

Performance Bonds

As of March 31, 2012, we had outstanding $38.5 million in surety bonds and $14,000 in cash bonds to secure certain reclamation obligations. Additionally, as of March 31, 2012, we had outstanding letters of credit in support of these surety bonds of $7.5 million. Further, as of March 31, 2012, we had outstanding certain road bonds of $0.9 million and performance bonds of $7.7 million. In April 2012, $5.0 million of these performance bonds, which secured our performance under a specific coal sales contract, were released with the approval of the counter-party, who determined that it no longer needed such performance security from us. Our management believes these bonds and letters of credit will expire without any claims or payments thereon, and thus any subrogation or other rights with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.

Legal

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material adverse effect on our financial position, liquidity or operations.

 

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 10: COMMITMENTS AND CONTINGENCIES (continued)

 

Guarantees

Our GP and the Partnership guarantee certain obligations of our subsidiaries. Our management believes that these guarantees will expire without any liability to the guarantors, and therefore any indemnification or subrogation commitments with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.

NOTE 11: RELATED PARTY TRANSACTIONS

In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (the “Services Agreement”) with our GP. The Services Agreement is terminable by either party upon thirty days written notice. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Our GP provides us with services such as general administrative and management, human resources, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geological, risk management and insurance services. Pursuant to the Services Agreement, the primary reimbursements to our GP were for costs related to payroll, and for such reimbursable costs the amounts of $3,569,000 and $2,682,000 were included in our accounts payable at March 31, 2012 and December 31, 2011, respectively.

Contract services were provided to Tunnell Hill Reclamation, LLC, a company that is indirectly owned by Charles Ungurean, our President and Chief Executive Officer (“Mr. C. Ungurean”), Thomas Ungurean, our Senior Vice President, Equipment, Procurement and Maintenance (“Mr. T. Ungurean”), and affiliates of AIM Oxford, in the amount of $34,000 and $555,000 for the three months ended March 31, 2012 and 2011, respectively. Accounts receivable were $1,000 and $48,000 from Tunnell Hill Reclamation, LLC (“Tunnell Hill”) at March 31, 2012 and December 31, 2011, respectively.

The services agreement with Tunnell Hill was scheduled to expire on December 31, 2011. During July 2011, we concluded negotiations with Tunnell Hill for an early termination of the services agreement effective August 1, 2011 (the “Termination Date”). In connection with the termination of the services agreement, we entered into a transaction agreement and related documents with Tunnell Hill, effective as of the Termination Date, under which Tunnell Hill temporarily leased from us for a period of six months certain of our equipment. Under the leasing arrangement, we received $23,700 per month for rental of the equipment, and Tunnell Hill had an option during the six-month leasing period to elect to purchase all of the equipment for a purchase price of $948,000 with 50% of the rental payments being credited against the purchase price should Tunnell Hill elect to exercise its purchase option. Following the lease term, Tunnell Hill exercised its option to purchase the leased equipment. For this transaction, we received net proceeds of approximately $877,000, which reflects the purchase price of $948,000 less a credit of 50% of the rental payments received during the lease period, and recognized a gain of approximately $97,000.

From time to time for business purposes we charter the use of an airplane from Zanesville Aviation located in Zanesville, Ohio. T&C Holdco LLC, a company that is owned by Mr. C. Ungurean and Mr. T. Ungurean, owns an airplane that it leases to Zanesville Aviation and that Zanesville Aviation uses in providing chartering services to its customers including us. Under its lease with Zanesville Aviation, T&C Holdco LLC receives compensation from Zanesville Aviation for the use of T&C Holdco LLC’s airplane. The airplane owned by T&C Holdco LLC was chartered to us on a number of occasions during the three months ended March 31, 2012 and 2011, and we paid Zanesville Aviation an aggregate of approximately $71,000 and $21,000, respectively, for those charters.

 

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(CONTINUED)

 

NOTE 12: SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information:

 

     Three Months Ended  
     March 31,  
     2012      2011  

Cash paid for:

     

Interest

   $ 2,333,000       $ 1,540,000   

Non-cash activities:

     

Purchase of coal reserves with debt

     1,022,000         —     

ARO capitalized in mine development

     3,589,000         2,135,000   

Market value of common units vested in LTIP

     419,000         949,000   

Accounts payable as of March 31 for:

     

Purchase of property and equipment

     1,996,000         2,571,000   

Mine development

     158,000         —     

NOTE 13: SEGMENT INFORMATION

We operate in a single business segment. We operate surface coal mines in Northern Appalachia and the Illinois Basin and sell high value steam coal to utilities, industrial customers and other coal-related organizations, primarily in the eastern United States. Our operating and executive management reviews and bases its decisions upon consolidated reports. All three of our operating subsidiaries participate primarily in the business of utilizing surface mining techniques to mine domestic coal and prepare it for sale to their customers. The operating companies share customers and a particular customer may receive coal from any one of the operating companies.

NOTE 14: SUBSEQUENT EVENTS

On April 26, 2012, the GP’s Board of Directors declared a cash distribution by the Partnership of $0.4375 per unit to its common unitholders, $0.10 per unit to its subordinated unitholders and $0.26875 per unit to its holders of general partner units with respect to the first quarter ended March 31, 2012. This distribution, totaling approximately $5,702,000, will be paid on May 15, 2012 to unitholders of record as of the close of business on May 8, 2012.

In April, Oxford sold oil and gas mineral rights on approximately 1,250 acres of land for $6.3 million. In the transaction, it retained royalty rights equivalent to a 20 percent net revenue interest once the wells are producing.

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q and the audited consolidated financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations for the year ended December 31, 2011 included in our Annual Report on Form 10-K (our “Annual Report”) and filed with the U.S. Securities and Exchange Commission (the “SEC”). This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under “Cautionary Statement Regarding Forward-Looking Statements.”

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains certain “forward-looking statements.” Statements included in this Quarterly Report on Form 10-Q that are not historical facts, and that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions or other such references, are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including but not limited to:

 

   

our production levels, margins earned and level of operating costs;

 

   

weakness in global economic conditions or in our 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;

 

   

our dependence on a limited number of customers;

 

   

our inability to enter into new long-term coal sales contracts at attractive prices and the renewal and other risks associated with our existing long-term coal sales contracts, including risks related to adjustments to price, volume or other terms of those contracts;

 

   

difficulties in collecting our receivables because of credit or financial problems of major customers, and customer bankruptcies, cancellations or breaches of existing contracts, or other failures to perform;

 

   

our ability to acquire additional coal reserves;

 

   

our 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 laws and regulations, including those pertaining to carbon dioxide emissions, and other factors;

 

   

significant costs imposed on our mining operations by extensive and frequently changing environmental laws and regulations, and greater than expected environmental regulation, costs and liabilities;

 

   

legislation, and regulatory and related judicial decisions and interpretations, including issues pertaining to climate change and miner health and safety;

 

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a variety of operational, geologic, permitting, labor and weather-related factors, including those related to both our mining operations and our underground coal reserves that we do not operate;

 

   

limitations in the cash distributions we receive from our majority-owned subsidiary, Harrison Resources, LLC (“Harrison Resources”), and the ability of Harrison Resources to acquire additional reserves on economical terms from CONSOL Energy in the future;

 

   

the potential for inaccuracies in our estimates of our coal reserves, which could result in lower than expected revenues or higher than expected costs;

 

   

the accuracy of the assumptions underlying our reclamation and mine closure obligations;

 

   

liquidity constraints, including those resulting from the cost or unavailability of financing due to capital markets conditions;

 

   

risks associated with major mine-related accidents;

 

   

results of litigation, including claims not yet asserted;

 

   

our ability to attract and retain key management personnel;

 

   

greater than expected shortage of skilled labor;

 

   

our ability to maintain satisfactory relations with our employees;

 

   

failure to obtain, maintain or renew our security arrangements, such as surety bonds or letters of credit, in a timely manner and on acceptable terms;

 

   

our ability to pay our quarterly distributions which substantially depends upon our future operating performance (which may be affected by prevailing economic conditions in the coal industry), debt covenants, and financial, business and other factors, some of which are beyond our control; and

 

   

the need to recognize impairment and/or restructuring charges associated with our operations, including impairment and restructuring charges associated with our Illinois Basin operations, as well as any changes to previously identified impairment or restructuring charge estimates.

When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this Quarterly Report on Form 10-Q and in our Annual Report filed with the SEC, as well as other written and oral statements made or incorporated by reference from time to time by us in other reports and filings with the SEC. All forward-looking statements included in this Quarterly Report on Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Overview

We are a low cost producer of high value steam coal, and we are the largest producer of surface mined coal in Ohio. We focus on acquiring steam coal reserves that we can efficiently mine with our modern, large scale equipment. Our reserves and operations are strategically located in Northern Appalachia and the Illinois Basin to serve our primary market area of Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia.

We operate in a single business segment and have three operating subsidiaries, Oxford Mining Company, LLC (“Oxford Mining”), Oxford Mining Company-Kentucky, LLC and Harrison Resources. All of our operating subsidiaries participate primarily in the business of utilizing surface mining techniques to mine domestic coal and prepare it for sale to our customers. All three subsidiaries share common customers, assets and employees.

We currently have 17 active surface mines and we manage these mines as eight mining complexes. In addition, we have two idled mines in the Illinois Basin which are scheduled to be closed in 2012 as discussed further below. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky. During the first quarter of 2012, we produced and sold approximately 1.9 million tons of coal. We purchase coal in

 

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the open market and under contracts to satisfy a portion of our sales commitments. As is customary in the coal industry, we have entered into long-term coal sales contracts with many of our customers. We define long-term coal sales contracts as coal sales contracts having initial terms of one year or more.

On March 21, 2012, we announced several actions with regard to our Illinois Basin operations. As noted in our Annual Report, we received a contract termination notice from a customer of our Illinois Basin operations. We believe that this customer’s action was taken in bad faith, motivated by the combination of the price increase that recently went into effect under the customer’s sales contract and the current coal market conditions. We have retained legal counsel and are aggressively pursuing compensation for our damages through all appropriate legal measures.

To address this circumstance, we idled one mine, reduced mining operations at a second mine and terminated a significant number of employees for the Illinois Basin operations that supported the terminated contract. Prior thereto in February, we had idled another Illinois Basin mine and the Illinois Basin wash plant and lab and terminated some of our employees in connection with our decision to substitute purchased coal for mined and washed coal under certain customer sales contracts, and these actions alone did not have a material effect on us. With our commitment in March to the restructuring of our Illinois Basin operations, the earlier action has been included as a part of the overall restructuring. We are now proceeding to close these two idled mines and the wash plant and lab and sell or redeploy the mining equipment idled in this process. We expect these steps to result in a reduction in production levels from our Illinois Basin operations and we expect to experience accelerated mine closure costs as more fully described in “Part I. – Financial Information – Item 1. – Condensed Consolidated Financial Statements (Unaudited) – Notes to Condensed Consolidated Financial Statements—Note 6 – Asset Retirement Obligations.”

We are transferring equipment from these Illinois Basin mines to our Northern Appalachian operations, a move that is expected to enhance productivity and reduce future capital expenditures by approximately $10 million in 2012. We are selling excess Illinois Basin equipment idled because of the mine closures and reduced mine operations, and the proceeds of these sales of $10 to $15 million will be used to strengthen our balance sheet. The restructuring plan is expected to reduce production for 2012 by approximately 1.1 million tons to meet market demand and reduce costs.

As a result of the actions taken and our intent to close the two idled mines, we recorded impairment and restructuring charges of $8.4 million related to our Illinois Basin operations during the three months ended March 31, 2012. The charges included non-cash impairment charges related to coal reserves, mine development costs, and certain fixed assets such as mining equipment and vehicles (the “Impaired Assets”). Those Impaired Assets that we plan to sell and that are currently ready for sale are presented separately as current assets held for sale in our condensed consolidated balance sheet at March 31, 2012 and are no longer being depreciated or amortized. Those Impaired Assets which do not meet the criteria for held for sale are presented in “Property, plant and equipment, net” in our condensed consolidated balance sheet at March 31, 2012 and recorded at their revised carrying value after taking into account the impairment.

For additional information regarding these impairment and restructuring charges, refer to “Part I. – Financial Information – Item 1. – Condensed Consolidated Financial Statements (Unaudited) – Notes to Condensed Consolidated Financial Statements—Note 3 – Impairment and Restructuring Charges.”

Evaluating Our Results of Operations

We evaluate our results of operations based on several key measures:

 

   

our coal production, sales volume and sales prices, which drive our coal sales revenue;

 

   

our cost of coal sales;

 

   

our cost of purchased coal;

 

   

our adjusted EBITDA, a non-GAAP financial measure; and

 

   

our distributable cash flow, a non-GAAP financial measure.

 

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Coal Production, Sales Volume and Sales Prices

We evaluate our operations based on the volume of coal we produce, the volume of coal we sell and the prices we receive for our coal. These coal volumes are measured in clean tons, net of refuse. Because we sell substantially all of our coal under long-term coal sales contracts, our coal production, sales volume and sales prices are largely dependent upon the terms of those contracts. The volume of coal we sell is also a function of the productive capacity of our mining complexes, the amount of coal we purchase and changes in inventory levels. Please read “— Cost of Purchased Coal” for more information regarding our purchased coal.

Our long-term coal sales contracts typically provide for a fixed price, or a schedule of prices that are either fixed or contain market-based adjustments, over the contract term. In addition, many of our long-term coal sales contracts have full or partial cost pass through or cost adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the costs for items such as fuel and inflation. Cost adjustment provisions adjust the initial contract price over the term of the contract either by a specific percentage or a percentage determined by reference to various cost-related indices, including cost-related indices for fuel and cost-of-living generally.

Our transportation revenue reflects the portion of our total coal revenues that is attributable to the actual transportation costs incurred to transport our coal from our mines to our river terminals, our rail loading facilities and our customers. Our transportation revenue fluctuates based on a number of factors, including the volume of coal we transport, the method by which we transport our coal and the rates charged by the third-party transportation companies. Our transportation expenses are equal to and offset our transportation revenues.

We evaluate the price we receive for our coal on an average sales price per ton basis, net of transportation costs. Our average sales price per ton represents our coal sales revenue divided by total tons of coal sold. The following table provides operational data with respect to our coal production and purchases, coal sales volume and average sales price per ton for the periods indicated:

 

     Three Months Ended
March 31,
 
     2012     2011     % Change  
     (tons in thousands)  

Tons of coal produced (clean)

     1,891        1,951        (3.1 %) 

(Increase) in inventory

     (32     (29     n/a   

Tons of coal purchased

     71        141        (49.6 %) 

Tons of coal sold

     1,930        2,063        (6.4 %) 

Tons of coal sold under long-term contracts(1)

     92.5     92.9     n/a   

Average sales price per ton

   $ 49.13      $ 45.44        8.1

Cost of transportation per ton

   $ 6.18      $ 5.07        21.9

Average sales price per ton (net of transportation costs)

   $ 42.95      $ 40.37        6.4

Number of operating days

     72.0        70.0        2.9

 

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

Cost of Coal Sales

We evaluate our cost of coal sales, which excludes the costs of purchased coal and transportation; all non-cash costs such as depreciation, depletion and amortization (“DD&A”); impairment and restructuring charges; and any indirect costs such as selling, general and administrative expenses (“SG&A”), on a cost per ton sold basis. Our cost of coal sales per ton sold represents our cost of coal sales divided by the tons of coal we produced and sold. Our cost of coal sales includes costs for labor, fuel, oil, explosives, royalties, operating leases, repairs and maintenance and all other costs that are directly related to our mining operations.

 

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Our cost of coal sales does not take into account the effects of any of the cost pass through or cost adjustment provisions in our long-term coal sales contracts, as those provisions result in an adjustment to our coal sales price. The following table provides summary information for the periods indicated relating to our cost of coal sales per ton and tons of coal sold, excluding purchase coal:

 

     Three Months Ended March 31,  
     2012      2011      % Change  
     (tons in thousands)  

Cost of coal sales per ton

   $ 37.45       $ 32.57         15.0

Tons of coal sold, excluding purchase coal

     1,859         1,922         (3.3 %) 

Cost of Purchased Coal

We purchase coal from third parties to fulfill a portion of our obligations under our long-term coal sales contracts and, in certain cases, to meet customer specifications. In connection with our Illinois Basin operations, we had a long-term coal purchase contract with a third-party supplier that had favorable pricing terms relative to our production costs. Under this contract the third-party supplier was obligated to deliver and we were obligated to purchase 0.4 million tons of coal each year until the coal reserves covered by this contract were depleted. We have experienced supplier performance issues under this contract which have continued into 2012. The supplier has asserted that this contract is terminated by its terms, while we have taken a contrary position. We continue to work with the supplier to resolve the matter. We did not receive any tons from this supplier during the first quarter of 2012.

On March 2, 2012, we entered into another long-term coal purchase contract with a separate supplier for our Illinois Basin operations for delivery of 350,000 tons of coal in 2012 and 360,000 tons of coal in 2013. A majority of the tons purchased in the first quarter of 2012 were under this new contract as compared to purchases under the above-described lower priced contract in the first quarter of 2011. This arrangement allowed us to idle one of our mines and shutdown our wash plant and lab in the Illinois Basin.

We evaluate our cost of purchased coal on a per ton basis. The following table provides summary information for the periods indicated for our cost of purchased coal per ton and tons of coal purchased:

 

     Three Months Ended March 31,  
     2012      2011      % Change  
     (tons in thousands)  

Cost of purchased coal per ton

   $ 45.16       $ 36.44         23.9

Tons of coal purchased

     71         141         (49.6 %) 

Adjusted EBITDA

Adjusted EBITDA for the period represents net income (loss) attributable to our unitholders for that period before interest, taxes, DD&A, impairment and restructuring charges, amortization of below-market coal sales contracts, non-cash equity-based compensation expense, loss on asset disposals, certain non-recurring costs and the non-cash change in future asset retirement obligations (“ARO”). The non-cash change in future ARO is included in cost of coal sales 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. Please read “— Reconciliation to GAAP Measures” below for a reconciliation of net income (loss) attributable to our unitholders to adjusted EBITDA for each of the periods indicated.

 

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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 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 and then 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. Due to the restructuring of our Illinois Basin operations, starting in the first quarter of 2012, we are not currently estimating reserve replacement expenditures with respect to our Illinois Basin operations. Other maintenance capital expenditures include, among other things, actual cash expenditures for plant, equipment, mine development and cash 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 compute the coverage ratio of distributable cash flow to planned cash distributions. Please read “— Reconciliation to GAAP Measures” below for a reconciliation of net income (loss) attributable to our unitholders to distributable cash flow for each of the periods indicated.

Sales Contracts

For the past three years over 90.0% of our annual coal sales were made under long-term coal sales contracts and we intend to continue to enter into long-term coal sales contracts for substantially all of our annual coal production. We believe our long-term coal sales contracts reduce our exposure to fluctuations in the spot price for coal and provide us with a reliable and stable revenue base. Our long-term coal sales contracts also allow us to partially mitigate our exposure to rising costs to the extent those contracts have full or partial cost pass through and/or cost adjustment provisions.

For 2012, 2013, 2014 and 2015, we currently have long-term coal sales contracts for coal sales of 7.0 million tons, 6.7 million tons, 5.5 million tons and 4.0 million tons, respectively. These tonnages assume the successful renegotiation of some of our long-term coal sales contracts which contain provisions that provide for price reopeners. Two of our long-term coal sales contracts with the same customer provide for market-based adjustments to the initial contract price every three years. These two long-term coal sales contracts will terminate effective December 31, 2012 if we cannot agree upon a market-based price with the customer by September 30, 2012. In addition, we have one long-term coal sales contract with another customer that will terminate effective December 31, 2013 if we cannot agree upon a market-based price with the customer by June 30, 2013. The coal

 

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tonnage which is involved for these three contracts is 1.0 million tons for 2013, 1.4 million tons for 2014 and 0.9 million tons for 2015. Our long-term coal sales contracts exclude tons related to an unplanned contract termination in the Illinois Basin during the first quarter of 2012.

The terms of our coal sales contracts result from competitive bidding and negotiation with customers. As a result, the terms of these contracts vary by customer. However, many of our long-term coal sales contracts have full or partial cost pass through and/or cost adjustment provisions. For 2012, 2013, 2014 and 2015, 71%, 72%, 61% and 48% of the coal, respectively, that we have committed to deliver under our current long-term coal sales contracts are subject to full or partial cost pass through and/or cost adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the costs for such items as fuel, explosives and/or labor. Cost adjustment provisions adjust the initial contract price over the term of the contract either by a specific percentage or a percentage determined by reference to various cost-related indices. While 71% of our coal sales contracts have full or partial cost pass through and/or cost adjustment provisions in 2012, when factoring in the partial nature of some of our pass through provisions, approximately 52% of the change in diesel fuel pricing associated with our estimated diesel fuel usage is fully covered by cost pass through provisions.

Some long-term coal sales contracts contain option provisions that give the customer the right to elect to purchase additional tons of coal during the contract term at the same price as the fixed tons provided for in the contract. We have outstanding option tons of 0.4 million for each of 2012 through 2014 and 0.7 million for 2015. If there are customer elections to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production at our mining complexes. As of May 4, 2012, no option tons have been elected and only 0.1 million option tons remain available for 2012 customer elections.

Factors That Impact Our Business

We are currently experiencing a general softening of the coal markets and reduced demand for coal. As a result, it has been necessary to take steps to accommodate the changing supply profile of some customers. In the first quarter of 2012, we completed an amendment with a significant customer of our Northern Appalachian operations to reduce the 2012 contract tonnage for that customer in exchange for a compensating increase in sales price thereby preserving our economics under the contract.

We are also focused on reviewing and modifying our operations to manage controllable costs and eliminate discretionary capital expenditures. As previously mentioned, during the first quarter of 2012 we reached an agreement for 2012 and 2013 to purchase coal on more favorable terms rather than supplying our own washed coal on certain Illinois Basin customer contracts, enabling us to idle one of our mines and shut down a wash plant and lab from our Illinois Basin operations. These steps are expected to result in cost savings in 2012.

In March of 2012, we received an unplanned contract termination notice from an Illinois Basin customer terminating our long-term coal sales contract with this customer based on allegations that our coal deliveries failed to conform to the quality specifications in the coal sales contract. The coal sales contract called for us to supply 800,000 tons of coal per year through 2015. We believe that this customer’s action was taken in bad faith, motivated by the price increase that went into effect in 2012 under the customer’s coal sales contract as compared to the lower market pricing prevailing under the current coal market conditions. We have retained legal counsel and are aggressively pursuing compensation for our damages through all appropriate legal measures.

We believe the other key factors that influence our business are: (i) demand for coal, (ii) demand for electricity, (iii) economic conditions, (iv) the quantity and quality of coal available from competitors, (v) competition for production of electricity from non-coal sources, (vi) domestic air emission standards and the ability of coal-fired power plants to meet these standards, (vii) legislative, regulatory and judicial developments, including delays, challenges to, and difficulties in acquiring, maintaining or renewing necessary permits or mineral or surface rights, (viii) market price fluctuations for sulfur dioxide emission allowances and (ix) our ability to meet governmental financial security requirements associated with mining and reclamation activities.

 

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Results of Operations

Factors Affecting the Comparability of Our Results of Operations

The comparability of our results of operations was impacted by impairment and restructuring charges resulting from the actions taken with respect to our Illinois Basin operations as described above under “Overview.” For additional information regarding these impairment and restructuring charges, refer to “Part I. – Financial Information – Item 1. – Condensed Consolidated Financial Statements (Unaudited) – Notes to Condensed Consolidated Financial Statements—Note 3 – Impairment and Restructuring Charges.”

Additionally, the comparability of our results of operations was impacted by a contract amendment with a significant customer of our Northern Appalachian operations that reduced the 2012 contract tonnage for that customer in exchange for a compensating increase in sales price which preserved our economics under the contract.

Summary

The following table presents certain of our historical consolidated financial data for the periods indicated and contains both GAAP and non-GAAP measures:

 

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     Three Months Ended
March 31,
 
     2012     2011  
     (in thousands, unaudited)  

Statement of Operations Data

    

Revenue:

    

Coal sales

   $ 82,878      $ 83,304   

Transportation revenue

     11,935        10,442   

Royalty and non-coal revenue

     3,054        2,320   
  

 

 

   

 

 

 

Total revenue

     97,867        96,066   

Costs and expenses

    

Cost of coal sales (excluding depreciation,depletion and amortization, shown separately)

     69,615        62,617   

Cost of purchased coal

     3,203        5,127   

Cost of transportation

     11,935        10,442   

Depreciation, depletion and amortization

     13,682        12,111   

Selling, general and administrative expenses

     4,045        3,966   

Impairment and restructuring charges

     8,355        —     
  

 

 

   

 

 

 

Total costs and expenses

     110,835        94,263   

(Loss) income from operations

     (12,968     1,803   

Interest income

     1        1   

Interest expense

     (2,718     (2,003
  

 

 

   

 

 

 

Net loss

     (15,685     (199

Net income attributable to noncontrolling interest

     (91     (1,571
  

 

 

   

 

 

 

Net loss attributable to Oxford Resource Partners, LP unitholders

   $ (15,776   $ (1,770
  

 

 

   

 

 

 

Other Financial Data

    

Adjusted EBITDA

   $ 11,033      $ 13,987   
  

 

 

   

 

 

 

Distributable cash flow

   $ 129      $ 5,479   
  

 

 

   

 

 

 

 

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Reconciliation to GAAP Measures

The following table presents a reconciliation of net loss attributable to our unitholders to adjusted EBITDA and distributable cash flow for each of the periods indicated:

Reconciliation of net loss attributable to Oxford Resource Partners, LP

to adjusted EBITDA and distributable cash flow:

 

     Three Months Ended
March 31,
 
     2012     2011  
     (in thousands, unaudited)  

Net loss attributable to Oxford Resource Partners, LP unitholders

   $ (15,776   $ (1,770

PLUS:

    

Interest expense, net of interest income

     2,716        2,002   

Depreciation, depletion and amortization

     13,682        12,111   

Non-cash equity-based compensation expense

     262        364   

Non-cash loss on asset disposals

     1,177        166   

Change in fair value of future asset retirement obligations

     381        1,358   

Impairment and restructuring charges

     8,355        —     

Non-recurring costs

     453        —     

LESS:

    

Amortization of below-market coal sales contracts

     217        244   
  

 

 

   

 

 

 

Adjusted EBITDA

   $ 11,033      $ 13,987   

LESS:

    

Cash interest expense, net of interest income

     2,296        1,539   

Estimated reserve replacement expenditures

     842        1,331   

Other maintenance capital expenditures

     7,766        5,638   
  

 

 

   

 

 

 

Distributable cash flow

   $ 129      $ 5,479   
  

 

 

   

 

 

 

 

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Quarter Ended March 31, 2012 Compared to Quarter Ended March 31, 2011

Overview. Net loss for the first quarter of 2012 was $15.8 million, or $0.75 per diluted limited partner unit, compared to a net loss for the first quarter of 2011 of $1.8 million, or $0.08 per diluted limited partner unit. Negatively impacting net income for the first quarter of 2012 were impairment and restructuring charges and nonrecurring costs related to the restructuring of our Illinois Basin operations of $8.8 million, or $0.43 per diluted limited partner unit. Excluding the impairment and restructuring charges and non-recurring costs, net loss for the first quarter of 2012 would have been $7.0 million, or $0.32 per diluted limited partner unit. Total revenue was $97.9 million for the first quarter of 2012, up 1.9% from $96.1 million for the first quarter of 2011. Adjusted EBITDA was $11.0 million for the first quarter of 2012, down 21.1% from $14.0 million for the first quarter of 2011. Negatively impacting adjusted EBITDA for the first quarter of 2012 were lost profits from an unplanned coal sales contract termination during the quarter and increased diesel fuel costs. Distributable cash flow was $0.1 million for the first quarter of 2012, down $5.4 million from the first quarter of 2011. Distributable cash flow was negatively impacted by the lower adjusted EBITDA and higher cash interest expense of $0.8 million due primarily to higher debt levels.

Coal Production. Our tons of coal produced decreased 3.1% to 1.9 million tons for the first quarter of 2012 from 2.0 million tons for the first quarter of 2011. This decrease was attributable to reduced production from our Illinois Basin operations due to the idling of two mines and reduced production at a third mine due primarily to the unplanned termination of a coal sales contract during the first quarter of 2012.

Sales Volume. Our sales volume decreased 6.4% to 1.9 million tons for the first quarter of 2012 from 2.1 million tons for the first quarter of 2011. This decrease was primarily attributable to lost sales during the first quarter of 2012 resulting from the unplanned termination of a coal sales contract and an amendment with a significant customer of our Northern Appalachian operations that reduced the 2012 contract tonnage for that customer in exchange for a compensating increase in sales price.

Average Sales Price Per Ton (Net of Transportation Costs). Our average sales price per ton (net of transportation costs) increased 6.4% to $42.95 for the first quarter of 2012 from $40.37 for the first quarter of 2011. This $2.58 per ton increase was primarily the result of higher contracted sales prices realized during the first quarter of 2012 as compared to the first quarter of 2011, partially offset by higher transportation costs of $1.11 per ton. Of the $2.58 per ton increase in our average sales price per ton (net of transportation costs), $1.11 per ton was attributable to the compensating increase in sales price for a significant Northern Appalachian customer that elected to reduce its 2012 contract tonnage.

Coal Sales Revenue. Coal sales revenue for the first quarter of 2012 decreased $0.4 million, or 0.5%, to $82.9 million from $83.3 million for the first quarter of 2011. This decrease was due to lower sales volumes partially offset by a higher average sales price per ton for the first quarter of 2012.

Royalty and Non-Coal Revenue. Our royalty and non-coal revenue increased to $3.1 million for the first quarter of 2012 from $2.3 million for the first quarter of 2011. This increase resulted from higher revenue from the sale of limestone of $1.4 million offset by reduced contract services and other revenue of $0.6 million.

Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased 11.2% to $69.6 million for the first quarter of 2012 from $62.6 million for the first quarter of 2011. This $7.0 million increase resulted from higher diesel fuel prices of $3.8 million, higher operating lease expense of $1.1 million, higher explosives costs of $0.9 million and higher other mining costs of $1.2 million. Cost of coal sales per ton increased 15.0% to $37.45 per ton for the first quarter of 2012 from $32.57 per ton for the first quarter of 2011. This $4.88 per ton increase resulted from an increase in diesel fuel prices of $2.07 per ton, higher lease expense of $0.57 per ton, higher explosives costs of $0.46 per ton and higher other mining costs per ton of $1.78.

Cost of Purchased Coal. Cost of purchased coal decreased to $3.2 million for the first quarter of 2012 from $5.1 million for the first quarter of 2011. Of this $1.9 million decrease, $3.2 million was related to lower volumes in the first quarter of 2012 as compared to the first quarter of 2011, partially offset by $1.2 million due to a higher per ton cost for purchased coal of $8.72. This decrease in volume was attributable to a supplier’s non-performance under a coal purchase contract. See “Cost of Purchased Coal” section above for further details. Separately, we

 

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entered into a new coal purchase contract on March 2, 2012 which provides for delivery of 350,000 tons of coal in 2012 and 360,000 tons of coal in 2013. While this contract was the primary reason for the higher per ton purchase costs of $8.72 year over year, this arrangement has allowed us to shut down our wash plant and lab in the Illinois Basin and idle one mine that is being closed in 2012.

Depreciation, Depletion and Amortization (DD&A). DD&A expense for the first quarter of 2012 was $13.7 million compared to $12.1 million for the first quarter of 2011, an increase of $1.6 million. This increase was primarily attributable to higher amortization from an increase in ARO cost estimates associated with closed mines and higher depreciation associated with the purchase of additional major mining equipment.

Selling, General and Administrative Expenses (SG&A). SG&A expenses were $4.0 million for both the first quarter of 2012 and the first quarter of 2011.

Impairment and Restructuring Charges. Impairment and restructuring charges for the first quarter of 2012 were $8.4 million compared to zero for the first quarter of 2011. These impairment and restructuring charges resulted from the restructuring of our Illinois Basin operations following the unplanned termination of a coal sales contract with one of our Illinois Basin customers. In committing to the restructuring, Oxford idled one mine, reduced mining operations at a second mine and terminated a significant number of employees that supported the terminated contract. Prior thereto, we had idled another Illinois Basin mine and the Illinois Basin wash plant and lab and terminated some of our employees in connection with our decision to substitute purchased coal instead of mined and washed coal under certain customer sales contracts, and these actions alone did not have a material effect on us. With our subsequent commitment to the restructuring of our Illinois Basin operations, the earlier action has been included as a part of the overall restructuring. These impairment and restructuring charges consist of non-cash asset impairment charges related to coal reserves, mine development costs and certain fixed assets, such as mining equipment and vehicles, one-time employee termination costs, equipment relocation costs, and professional fees and other costs. For additional information regarding these impairment and restructuring charges, refer to “Part I. – Financial Information – Item 1. – Condensed Consolidated Financial Statements (Unaudited) – Notes to Condensed Consolidated Financial Statements—Note 3 – Impairment and Restructuring Charges.”

Transportation Revenue and Expenses. Transportation revenue and expenses for the first quarter of 2012 increased 14.3% compared to the first quarter of 2011 due primarily to a shift in customer mix and changes in hauling routes in response to the mines currently open compared to mines operating in the first quarter of 2011. Transportation expenses per ton sold increased 21.9% to $6.18 per ton for the first quarter of 2012 from $5.07 per ton for the first quarter of 2011. Transportation expenses increased $0.54 per ton due to shifts in volumes between customers, $0.40 per ton due to the mix of source mines and $0.18 per ton due to increased fuel prices.

Interest Expense (Net of Interest Income). Interest expense (net of interest income) for the first quarter of 2012 was $2.7 million compared to $2.0 million for the first quarter of 2011, an increase of $0.7 million. This increase was due primarily to increased borrowings under our 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 a subsidiary of CONSOL Energy. For the first quarter of 2012 and 2011, the net income attributable to noncontrolling interest was $0.1 million and $1.6 million, respectively. This decrease in net income attributable to noncontrolling interest was due to increased mining costs for Harrison Resources resulting from a higher strip ratio at the Harrison mine.

Liquidity and Capital Resources

Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in mining our reserves, as well as complying with applicable environmental laws and regulations. Our principal liquidity requirements are to finance current operations, fund capital expenditures, including acquisitions from time to time, service our debt and pay cash distributions to our unitholders. Our primary sources of liquidity to meet these needs are cash generated by our operations and borrowings under our credit facility. Accordingly, the principal indicators of our liquidity are our cash on hand and availability under our $175 million credit facility, which is described under “— Credit Facility” below.

 

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In December of 2011, we amended the credit agreement for our $175 million credit facility. Under the amendment, our leverage ratio was increased from 2.75 to 1 to 3.25 to 1 for the period from January 1, 2012 through June 30, 2012 and to 3.00 to 1 for all periods thereafter. The resulting effect of this amendment was to increase our borrowing availability under the $175 million credit facility effective January 1, 2012.

As of March 31, 2012, we had borrowing availability under our $175 million credit facility of $9.0 million. Our available liquidity as of March 31, 2011 was $10.5 million, which consisted of $1.5 million in cash on hand and the $9.0 million of borrowing availability under our $175 million credit facility.

In April, Oxford sold oil and gas mineral rights on approximately 1,250 acres of land for $6.3 million. In the transaction, it retained royalty rights equivalent to a 20 percent net revenue interest once the wells are producing.

In total, Oxford expects to enhance its liquidity by $30 to $35 million in 2012. This additional liquidity is expected to come from the above-described mineral rights sale, coupled with the $10 to $15 million in estimated proceeds from future asset sales, the $10 million in expected capital expenditure savings and the $3.5 million in savings from the reduced first quarter subordinated distribution.

Our ability to satisfy our working capital requirements and debt service obligations, fund planned capital expenditures and pay our quarterly distributions for the common unitholders substantially depends upon our future operating performance (which may be affected by prevailing economic conditions in the coal industry), debt covenants, and financial, business and other factors, some of which are beyond our control. To the extent our operating cash flow or access to financing sources and the costs thereof are materially different than expected, our future liquidity may be adversely affected.

For the first three months of 2012, we had $0.1 million in distributable cash flow to cover our distributions. We declared a cash distribution of $0.4375 per common unit for the first quarter ended March 31, 2012, consistent with our previously announced expectation regarding continued payment of the minimum quarterly distribution to common unitholders. We also declared a reduced cash distribution of $0.10 per subordinated unit for the first quarter ended March 31, 2012 as compared with $0.4375 per subordinated unit for previous quarters.

Please read “— Capital Expenditures” below for a further discussion on the impact of capital expenditures on liquidity.

Cash Flows

The following table reflects cash flows for the applicable periods:

 

     Three Months Ended
March 31,
 
     2012     2011  
     (in thousands, unaudited)  

Net cash provided by (used in)

    

Operating activities

   $ 3,422      $ 17,219   

Investing activities

     (10,219     (13,091

Financing activities

     5,278        (1,277

Net cash provided by operating activities was $3.4 million for the first three months of 2012, a decrease of $13.8 million from net cash provided by operating activities of $17.2 million for the first three months of 2011. This decrease was primarily attributable to a higher net loss which included $8.4 million in impairment and restructuring charges and unfavorable working capital adjustments.

Net cash used in investing activities was $10.2 million for the first three months of 2012, a decrease of $2.9 million from net cash used in investing activities of $13.1 million for the first three months of 2011. This decrease was primarily attributable to lower purchases of property and equipment.

 

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Net cash provided by financing activities was $5.3 million for the first three months of 2012 compared to net cash used in financing activities of $1.3 million for the first three months of 2011. The increase of $6.6 million was primarily attributable to higher advances on our line of credit and lower distributions to the Harrison Resources noncontrolling interest.

Credit Facility

Our $175 million credit facility provides for a $60 million term loan and a $115 million revolving credit facility. As of March 31, 2012, we had borrowings of $146.5 million outstanding under our $175 million credit facility, consisting of $49.5 million on our term loan and borrowings of $97.0 million on the revolving credit facility. We also use our $175 million credit facility to collateralize letters of credit related to surety bonds securing our reclamation obligations. As of March 31, 2012, we had letters of credit outstanding in support of these surety bonds of $7.5 million.

The term loan and revolving credit facility mature in 2014 and 2013, respectively, and borrowings bear interest at a variable rate per annum equal to, at our option, LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin are each defined in the credit agreement that evidences our $175 million credit facility). Borrowings under our $175 million credit facility are secured by a first-priority lien on and security interest in substantially all of our assets. Our $175 million credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness, make certain investments, make distributions to our unitholders, make ordinary course dispositions of assets over predetermined levels or enter into equipment leases, as well as enter into a merger or sale of all or substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries. Our $175 million credit facility also requires compliance with certain financial covenant ratios, including limiting our leverage ratio (the ratio of consolidated indebtedness to adjusted EBITDA) as described below, and limiting our interest coverage ratio (the ratio of adjusted EBITDA to consolidated interest expense) to no less than 4.0 : 1.0. In addition, we are not permitted under our $175 million credit facility to fund capital expenditures in any fiscal year in excess of certain predetermined amounts expressed as the permitted capital expenditures. In December of 2011, we amended the credit agreement for our $175 million credit facility to modify certain financial covenants set forth in the credit agreement. These modifications included increasing the existing leverage ratio of 2.75 to 1 to 3.25 to 1 for the period from January 1, 2012 through June 30, 2012 and to 3.00 to 1 for all periods thereafter. The definitions of and methods used to determine the leverage ratio and permitted capital expenditures remain unchanged and are set forth in such credit agreement.

The events that constitute an event of default under our $175 million credit facility include, among other things, failure to pay principal and interest when due, breach of representations and warranties, failure to comply with covenants, voluntary bankruptcy or liquidation and a change of control.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to comply with environmental and mining laws and regulations. Our capital requirements primarily consist of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures are those capital expenditures required to maintain or replace, including over the long term, our operating capacity, asset base or operating income. Expansion capital expenditures are those capital expenditures made to increase our long-term operating capacity, asset base or operating income. Our partnership agreement divides maintenance capital expenditures into two categories — accrued reserve replacement expenditures and other maintenance capital expenditures. Examples of accrued reserve replacement expenditures include estimated cash expenditures for the purchase of fee interests in coal reserves and estimated cash expenditures for advance royalties with respect to the acquisition of leasehold interests in coal reserves. Examples of other maintenance capital expenditures include capital expenditures associated with the repair, refurbishment and replacement of equipment, the development of new mines and reclamation upon mine closures. Examples of expansion capital expenditures include the acquisition (by lease or otherwise) of reserves, equipment or a new mine or the expansion of an existing mine, to the extent such expenditures are incurred to increase our long-term operating capacity, asset base or operating income.

 

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For 2012, we expect to incur between $27.0 million and $30.0 million in maintenance capital expenditures consisting of accrued reserve replacement expenditures and other maintenance capital expenditures. Due to the restructuring of our Illinois Basin operations, we are not currently accruing reserve replacement expenditures for production associated with those operations.

The following table reflects our maintenance capital expenditures by type for the three months ended March 31, 2012 and 2011:

 

Reserve replacement expenditures

   $ 842       $ 1,331   

Other maintenance capital expenditures

     

Major mining equipment

     547         172   

Components and tires

     5,021         4,011   

Mine development

     826         588   

Asset retirement obligations

     1,372         867   
  

 

 

    

 

 

 

Total other maintenance capital expenditures

     7,766         5,638   

Total maintenance capital expenditures

   $ 8,608       $ 6,969   
  

 

 

    

 

 

 

We have funded and expect to continue funding maintenance capital expenditures primarily from cash generated by our operations, borrowings under our $175 million credit facility, asset sales proceeds and operating leases.

For the first three months of 2012, we had expansion capital expenditures of $0.4 million comprised primarily of major mining equipment. We have funded and expect to continue funding these expenditures with the proceeds of borrowings under our $175 million credit facility, issuance of debt and equity securities and/or other external sources of financing.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit, surety bonds, performance bonds and road bonds. No liabilities related to these arrangements are reflected in our consolidated balance sheet, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

Federal and state laws require us to secure certain long-term obligations such as mine closure and reclamation costs and other obligations. We typically secure these obligations by using surety bonds, an off-balance sheet instrument, since the use of surety bonds is less expensive for us than the alternative of posting a 100% cash bond. We typically use bank letters of credit to secure our surety bond obligations. To the extent that surety bonds become unavailable, we would seek to secure our reclamation obligations with bank letters of credit, cash deposits or other suitable forms of collateral. We also post performance bonds to secure our performance of various contractual obligations and road bonds to secure our obligations to repair local roads.

As of March 31, 2012, we had outstanding $38.5 million in surety bonds and $14,000 in cash bonds to secure certain reclamation obligations. Additionally, as of March 31, 2012, we had outstanding letters of credit in support of these surety bonds of $7.5 million. Further, as of March 31, 2012, we had outstanding road bonds of $0.9 million and performance bonds of $7.7 million (which has been reduced to $2.7 million subsequent to March 31, 2012) that required no letters of credit as security. Our management believes these bonds and letters of credit will expire without any claims or payments thereon and thus any subrogation or other rights with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.

Seasonality

Our business has historically experienced only limited variability in its results due to the effect of seasons. Demand for coal-fired power can increase due to unusually hot or cold weather as power consumers use more air conditioning or heating. Conversely, mild weather can result in softer demand for our coal. Adverse weather conditions, such as heavy and/or extended periods of rain, snow or floods, can impact our ability to mine and ship our coal, and our customers’ ability to take delivery of coal.

 

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Critical Accounting Policies

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” discusses our condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these condensed consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Our management regularly reviews our accounting policies to make certain they are current and also to provide readers of our condensed consolidated financial statements with useful and reliable information about our operating results and financial condition. These include, but are not limited to, matters related to accounts receivable, inventories, pension benefits and income taxes. Implementation of these accounting policies includes estimates and judgments by management based on historical experience and other factors believed to be reasonable. This may include judgments about the carrying value of assets and liabilities based on considerations that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

Our management believes the following critical accounting policies are most important to the portrayal of our financial condition and results of operations and require more significant judgments and estimates in the preparation of our condensed consolidated financial statements.

Use of Estimates

In order to prepare financial statements in conformity with GAAP, we are required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities (if any) at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant areas requiring the use of management estimates and assumptions relate to amortization calculations using the units-of-production method, asset retirement obligations, useful lives for depreciation of fixed assets and estimates of fair values or impairment of assets and liabilities. The estimates and assumptions that we use are based upon our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. See discussion of the change in estimate below in the “Asset Retirement Obligations” section.

Allowance for Doubtful Accounts

We establish an allowance for losses on trade receivables when it is probable that all or part of the outstanding balance will not be collected. Our management regularly reviews the probability that a receivable will be collected and establishes or adjusts the allowance as necessary.

Inventory

Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing or shipment to customers. Inventory also consists of supplies, spare parts and fuel. Inventory is valued at the lower of average cost or market. The cost of coal inventory includes certain operating expenses including overhead and stripping costs incurred prior to the production phase, which commences when saleable coal beyond a de minimus amount is produced.

 

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Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs that do not extend the useful life or increase productivity are charged to operating expense as incurred. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets based on the following schedule:

 

Buildings and tipple

     25-39 years   

Machinery and equipment

     7-12 years   

Vehicles

     5-7 years   

Furniture and fixtures

     3-7 years   

Railroad siding

     7 years   

We acquire our coal reserves through purchases or leases. We deplete our coal reserves using the units-of-production method on the basis of tonnage mined in relation to total estimated recoverable tonnage with residual surface values classified as land and not depleted. At March 31, 2012 and December 31, 2011, all of our reserves were attributed to mine complexes engaged in mining operations or leased to third parties. We believe that the carrying value of these reserves will be recovered.

Exploration expenditures are charged to operating expense as incurred and include costs related to locating coal deposits and the drilling and evaluation costs incurred to assess the economic viability of such deposits. Costs incurred in areas outside the boundary of known coal deposits and areas with insufficient drilling spacing to qualify as proven and probable reserves are also expensed as exploration costs.

Once management determines there is sufficient evidence that the expenditure will result in a future economic benefit to us, the costs are capitalized as mine development costs. Capitalization of mine development costs continues until more than a de minimus amount of saleable coal is extracted from the mine. Amortization of these mine development costs is then initiated using the units-of-production method based upon the total estimated recoverable tonnage.

Advance Royalties

A substantial portion of our reserves are leased. Advance royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable through an offset or credit against royalties payable on future production. Amortization of leased coal interests is computed using the units-of-production method over the estimated recoverable tonnage.

Financial Instruments and Derivative Financial Instruments

Our financial instruments include cash and cash equivalents, accounts receivable, accounts payable, fixed rate debt, variable rate debt, interest rate swap agreements, an interest rate cap agreement and certain fuel purchase arrangements that qualify for derivative accounting. We do not hold or purchase financial instruments or derivative financial instruments for trading purposes.

We used interest rate swap agreements to partially reduce risks related to floating rate financing agreements that are subject to changes in the market rate of interest. Terms of the interest rate swap agreements required us to receive a variable interest rate and pay a fixed interest rate. Our interest rate swap agreements and their variable rate financings were based upon LIBOR. We had an interest rate cap agreement that set an upper limit on LIBOR that we would have to pay under the terms of our existing credit facility. This agreement expired on December 31, 2010. We did not elect hedge accounting for any of these agreements and, therefore, changes in market value on these derivatives are included in interest expense on the condensed consolidated statements of operations.

We measure our derivatives (interest rate swap agreement or fuel purchase derivatives) at fair value on a recurring basis using significant observable inputs, which are Level 2 inputs as defined in the fair value hierarchy. See Note 7 to our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q under the heading “Fair Value of Financial Instruments and Derivatives Activity.”

Our other financial instruments include fixed price forward contracts for diesel fuel. These contracts meet the definition of a derivative contract under ASC 815 and are accounted for as such except when the contracts qualify for, and are elected as, the normal purchases and sales exclusion under ASC 815 and therefore are not accounted for as derivatives. With the exception of the fuel contracts amended due to the Illinois Basin restructuring, we take physical delivery of all the fuel under these forward contracts and such contracts usually have a term of one year or less. See “Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risks.”

 

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Long-Lived Assets

We review the carrying value of our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset or asset group may not be recoverable. Impairment testing involves a comparison of the sum of undiscounted future cash flows of the asset to its respective carrying amount. If this comparison indicates the value of the asset will not be recovered, then the carrying value of the asset is reduced to its estimated fair value and an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs, reclamation and mine closure obligations are accelerated by accelerating the depletion rate. To the extent it is determined that an asset’s carrying value will not be recoverable during a shorter mine life, the asset is written down to its recoverable value. During the first three months of 2012, we recognized $7.2 million in impairment charges related to our Illinois Basin operations following receipt of a contract termination notice from a customer. For additional information regarding these impairment losses, refer to “Part I. – Financial Information – Item 1. – Condensed Consolidated Financial Statements (Unaudited) – Notes to Condensed Consolidated Financial Statements—Note 3 – Impairment and Restructuring Charges” and “— Factors That Impact Our Business” above. There were no indicators of impairment present during the year ended December 31, 2011 and, accordingly, no impairment losses were recognized in the prior year.

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are recorded in other assets in the accompanying condensed consolidated balance sheets. We capitalize costs incurred in connection with the establishment of credit facilities and amortize such costs to interest expense over the term of the credit facility using the effective interest method.

We also have recorded intangible assets and liabilities at fair value associated with certain customer relationships and below-market coal sales contracts, respectively. These balances arose from the purchase accounting for our two acquisitions. These intangible assets are being amortized over their expected useful lives.

Asset Retirement Obligations

Our asset retirement obligations (“ARO”) arise from the Surface Mining Control and Reclamation Act (“SMCRA”) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Our ARO are recorded initially at fair value. It has been our practice, and we anticipate that it will continue to be our practice, to perform a substantial portion of the reclamation work using internal resources at a lower cost to us. Hence, the estimated costs used in determining the carrying amount of our ARO may exceed the amounts that are eventually paid for reclamation costs if the reclamation work is performed using internal resources.

Effective June 30, 2011, we changed our method for estimating the ARO for our mines from the current disturbance method to the end of mine life method. This represents a change in accounting estimate effected by a change in method to a method which is a preferable method under GAAP. We believe the end of mine life method results in a more precise estimate and is more consistent with industry practice.

The end of mine life method focuses on estimating the liability based upon the productive life of the mine and more specifically the last pit(s) to be reclaimed once the mine is no longer producing coal as opposed to the individual pits created throughout the mine’s life under the current disturbance method.

The balance sheet effects of the change in accounting method resulted in a reclassification of approximately $6.2 million from the current portion of ARO to the long-term portion of ARO. The impact of the change in method was negligible to our consolidated statement of operations for the period ended June 30, 2011. This change was accounted for in the quarter ended June 30, 2011 and also in the current quarter, and will be accounted for in all future quarters, in accordance with ASC 250.

To determine the fair value of our ARO, we calculate on a mine-by-mine basis the present value of estimated reclamation cash flows. This process requires us to estimate the acreage subject to reclamation, estimate future reclamation costs and make assumptions regarding the mine’s productivity and related mining plan. These cash flows are discounted at a credit-adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected lives of our mines.

 

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When the liability is initially established, the offset is capitalized to the producing mine asset. Over time, the ARO liability is accreted to its present value, and the capitalized cost is depleted using the units-of-production method for the related mine. If the assumptions used to estimate the ARO liability do not materialize as expected or regulatory changes occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than currently estimated. We review our entire reclamation liability at least annually and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from revisions to cost estimates and any changes to our mining plans and the timing of the expected reclamation expenditures.

For the quarter ended March 31, 2012, the revisions in estimated cash flows increased the ARO liability $3.6 million and were primarily related to mine development at one new mine which has now reached full operating capacity and revisions of approximately $1.7 million to estimated closing costs and timing for the two mines which are being closed prematurely at the Muhlenberg Complex. The premature closures are a result of the restructuring plan implemented in the first quarter of 2012. Please read Note 3—Impairment and Restructuring Charges for further discussion. Adjustments to the ARO due to such revisions generally result in a corresponding adjustment to the related asset retirement cost in mine development.

In 2011, the revisions in estimated cash flows resulted in a net increase in the ARO of $13.7 million and were primarily related to mine development at eight new mines, as well as revisions to estimates of the expected costs for stream and wetland mitigation as regulatory requirements continue to evolve along with changes in estimated third-party unit costs. Adjustments to the ARO due to such revisions generally result in a corresponding adjustment to the related asset retirement cost in mine development. The portion of the revisions attributable to the change in method was negligible.

Income Taxes

As a partnership, we are not a taxable entity for federal or state income tax purposes; the tax effect of our activities passes through to our unitholders. Although publicly-traded partnerships as a general rule are taxed as corporations, we qualify for an exemption because at least 90% of our income consists of qualifying income, as defined in Section 7704(c) of the Internal Revenue Code. Therefore, no provision or liability for federal or state income taxes is included in our financial statements. Net income for financial statement purposes may differ significantly from taxable income reportable to our unitholders as a result of timing or permanent differences between financial reporting under GAAP and the regulations promulgated by the Internal Revenue Service.

Authoritative accounting guidance on accounting for uncertainty in income taxes establishes the criterion that an individual tax position is required to meet for some or all of the benefits of that position to be recognized in our financial statements. On initial application, the uncertain tax position guidance has been applied to all tax positions for which the statute of limitations remains open and no liability was recognized. Only tax positions that meet the more-likely-than-not recognition threshold at the adoption date are recognized or will continue to be recognized.

Revenue Recognition

Revenue from coal sales is recognized and recorded when shipment or delivery to the customer has occurred, prices are fixed or determinable and the title or risk of loss has passed in accordance with the terms of the sales contract. Under the typical terms of these contracts, risk of loss transfers to the customers at the mine or dock, when the coal is loaded on the rail, barge, or truck.

Freight and handling costs paid to third-party carriers and invoiced to customers are recorded as cost of transportation and transportation revenue, respectively.

Royalty and non-coal revenue consists of coal royalty income, service fees for providing landfill earth moving and transportation services, commissions that we receive from a third party who sells limestone that we recover during our coal mining process, service fees for operating a coal unloading facility and fees that we receive for trucking ash for municipal utility customers. Revenues are recognized when earned or when services are performed. Royalty revenue relates to the overriding royalty we receive on our underground coal reserves that we sublease to a third-party mining company.

 

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Below-Market Coal Sales Contracts

Our below-market coal sales contracts were acquired through our acquisition of Illinois Basin assets in the third quarter of 2009 and were coal sales contracts for which the prevailing market price for coal specified in the contract was in excess of the contract price. The fair value was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The difference between the below-market contracts cash flows and the cash flows at the prevailing market price are amortized into coal sales on the basis of tons shipped over the terms of the respective contracts.

Equity-Based Compensation

We account for equity-based compensation awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Equity-based compensation expense is recorded based upon the fair value of the award at grant date. Such costs are recognized as expense on a straight-line basis over the corresponding vesting period. Prior to our initial public offering, the fair value of our LTIP units was determined based on the sale price of our limited partner units in arm’s-length transactions. Subsequent to our initial public offering, the unit price fair value is determined based on the closing sales price of our units on the New York Stock Exchange on the grant date. See Note 8 to our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q under the heading “Long-Term Incentive Plan.”

Earnings Per Unit

For purposes of our earnings per unit calculation, we have applied the two class method. The classes of units are our limited partner and general partner units. All outstanding units share pro rata in income allocations and distributions and our general partner has sole voting rights.

Limited Partner Units: Basic earnings per unit are computed by dividing net income attributable to limited partners by the weighted average units outstanding during the reporting period. Diluted earnings per unit are computed similar to basic earnings per unit except that the weighted average units outstanding and net income attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to LTIP units upon vesting. In years of a loss, the phantom units are anti-dilutive and therefore not included in the earnings per unit calculation.

General Partner Units: Basic earnings per unit are computed by dividing net income attributable to our general partner by the weighted average units outstanding during the reporting period. Diluted earnings per unit for our general partner are computed similar to basic earnings per unit except that the net income attributable to the general partner units is adjusted for the dilutive impact of the phantom units. In years of a loss, the phantom units are anti-dilutive and therefore not included in the earnings per unit calculation.

New Accounting Standards Issued

In May 2011, the FASB issued ASU 2011-04, Fair Value Measurement – Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”). This guidance amends certain accounting and disclosure requirements related to fair value measurements to ensure that fair value has the same meaning in US GAAP and in IFRS and that their respective fair value measurement and disclosure requirements are the same. This guidance is effective for public entities during interim and annual periods beginning after December 15, 2011. The adoption of this guidance in 2011 did not have a material effect on our consolidated financial statements.

In June 2011, the FASB issued ASU No. 2011-05, Comprehensive Income – Presentation of Comprehensive Income, which amends current comprehensive income guidance. This guidance eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, comprehensive income must be reported in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. This guidance will be effective for public companies during the interim and annual periods beginning after December, 15, 2011. The adoption of this guidance in 2011 did not have a material effect on our consolidated financial statements.

 

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Market risk includes risks that arise from changes in interest rates, foreign currency exchange rates, commodity prices, equity prices and other market changes that affect market-sensitive instruments. We believe our principal market risks are commodity price risks and interest rate risks.

Commodity Price Risks

We sell most of the coal we produce under long-term coal sales contracts. Historically, we have principally managed the commodity price risks from our coal sales by entering into long-term coal sales contracts with fuel cost pass through or cost adjustment provisions and varying terms and durations. Additionally, we enter into fixed price fuel purchase contracts to hedge our commodity price risk where we do not have fuel cost pass through or cost adjustment provisions in our long-term sales contracts. There is a risk with these fuel purchase contracts that the counterparty will be unable to or otherwise fails to perform.

We believe that the price risks associated with our diesel fuel expense is significant. Taking into account our fixed price fuel purchase contracts, we estimate that a hypothetical increase of $0.30 per gallon of diesel fuel would have increased our fuel and hauling costs and reduced net income attributable to our unitholders by $1.0 million for the first quarter of 2012. If this hypothetical increase had occurred, we estimate that fuel cost pass through or cost adjustment provisions in our long-term coal sales contracts would have provided a corresponding increase in revenue and net income attributable to our unitholders in an amount equal to 52% of the amount referred to above for the first quarter of 2012.

Interest Rate Risks

We are exposed to interest rate risks as borrowings under our $175 million credit facility are at variable rates. On August 2, 2010, we entered into an interest rate swap agreement that had an original notional principal amount of $50 million and a maturity of January 31, 2013. The notional principal amount declines over the term of the interest rate swap agreement at a rate of $1.5 million each quarter which corresponds to our required principal payments. Under the interest rate swap agreement, we pay interest monthly at a fixed rate of 1.39% per annum and receive interest monthly at a variable rate equal to LIBOR (with a 1% floor) based on the notional principal amount. The interest rate swap agreement was effective August 9, 2010. The derivative liability is recorded in other liabilities and decreased by approximately $32,000 in the first quarter of 2012 to $124,000.

Item 4. Controls and Procedures

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”)) was performed as of March 31, 2012. This evaluation was performed by our management, with the participation of our Chief Executive Officer and Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective to ensure that the Partnership is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods, and during the quarterly period ended March 31, 2012 there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this Quarterly Report on Form 10-Q as Exhibits 31.1 and 31.2. The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. 1350 are furnished with this Quarterly Report on Form 10-Q as Exhibits 32.1 and 32.2.

 

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes these claims will not have a material adverse effect on our financial position, liquidity or operations.

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report on Form 10-Q, careful consideration should be given to the risk factors discussed in the “Risk Factors” section of our Annual Report filed with the SEC. There have been no material changes to the risk factors previously disclosed in our Annual Report.

Item 4. Mine Safety Disclosures

Our mining operations are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Quarterly Report on Form 10-Q.

Item 6. Exhibits

The exhibits listed in the Exhibit Index are incorporated herein by reference.

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: May 9, 2012

 

OXFORD RESOURCE PARTNERS, LP

By:   OXFORD RESOURCES GP, LLC, its general partner

          By:   /s/ CHARLES C. UNGUREAN
 

 

  Charles C. Ungurean
  President and Chief Executive Officer
  (Principal Executive Officer)
          By:   /s/ JEFFREY M. GUTMAN
 

 

  Jeffrey M. Gutman
  Senior Vice President, Chief Financial Officer and Treasurer
  (Principal Financial Officer)

 

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EXHIBIT INDEX

 

Exhibit

Number

 

Exhibit Description

3.1   Certificate of Limited Partnership of Oxford Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
3.2   Third Amended and Restated Agreement of Limited Partnership of Oxford Resource Partners, LP dated July 19, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
3.3   Certificate of Formation of Oxford Resources GP, LLC (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
3.4   Third Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC dated January 1, 2011 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on January 4, 2011)
10.16L*†   Amendment No. 2012-1 to Coal Purchase and Sale Agreement, dated March 21, 2012.
31.1*   Certification of Charles C. Ungurean, President and Chief Executive Officer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the March 31, 2012 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*   Certification of Jeffrey M. Gutman, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the March 31, 2012 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*   Certification of Charles C. Ungurean, President and Chief Executive Officer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the March 31, 2012 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*   Certification of Jeffrey M. Gutman, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the March 31, 2012 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
95*   Mine Safety Disclosures
101*   Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011; (ii) our Condensed Consolidated Statements of Operations for the three month periods ended March 31, 2012 and 2011; (iii) our Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011; (iv) our Condensed Consolidated Statements of Partners’ Capital for the three months ended March 31, 2012 and 2011; and (v) the notes to our Condensed Consolidated Financial Statements. This information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934.

 

* Filed herewith (or furnished, in the case of Exhibits 32.1 and 32.2).
Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the Securities and Exchange Commission.

 

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