Form 10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-Q 1 d398625d10q.htm FORM 10-Q Form 10-Q

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 September 30, 2012

¨	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):

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 November 1, 2012, 10,454,338 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


		Page
	PART I. FINANCIAL INFORMATION

ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)		1

	Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011		1

	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2012 and 2011		2

	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011		3

	Condensed Consolidated Statements of Partners’ Capital for the Nine Months Ended September 30, 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		18

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		32

ITEM 4.	CONTROLS AND PROCEDURES		32

	PART II. OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS		32

ITEM 1A.	RISK FACTORS		32

ITEM 4.	MINE SAFETY DISCLOSURES		32

ITEM 6.	EXHIBITS		32

PART I. FINANCIAL INFORMATION

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands, except for unit data)


	September 30,			December 31,
	2012			2011
ASSETS
Cash and cash equivalents	$	6,251		$	3,032
Accounts receivable		30,634			28,388
Inventory		12,478			12,000
Advance royalties - current portion		1,934			1,412
Prepaid expenses and other current assets		3,078			1,226
Assets held for sale		6,665			—

Total current assets		61,040			46,058
Property, plant and equipment, net		157,233			195,607
Advance royalties less current portion		6,824			7,945
Other long-term assets		8,136			11,655

Total assets	$	233,233		$	261,265

LIABILITIES
Accounts payable	$	27,133		$	26,940
Current portion of long-term debt		114,974			11,234
Current portion of reclamation and mine closure costs		5,075			4,553
Accrued taxes other than income taxes		1,340			1,732
Accrued payroll and related expenses		2,220			2,535
Other current liabilities		2,220			3,822

Total current liabilities		152,962			50,816

Long-term debt, less current portion		43,057			132,521
Reclamation and mine closure costs, less current portion		16,525			17,236
Other long-term liabilities		1,644			1,575

Total liabilities		214,188			202,148

Commitments and contingencies

PARTNERS’ CAPITAL
Limited partner unitholders (20,734,718 and 20,680,124 units outstanding as of September 30, 2012 and December 31, 2011, respectively)		17,532			57,160
General partner unitholder (422,698 and 422,044 units outstanding as of September 30, 2012 and December 31, 2011, respectively)		(1,847	)		(1,032	)

Total Oxford Resource Partners, LP capital		15,685			56,128
Noncontrolling interest		3,360			2,989

Total partners’ capital		19,045			59,117

Total liabilities and partners’ capital	$	233,233		$	261,265

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except for unit and per unit data)


	Three Months Ended						Nine Months Ended
	September 30						September 30
	2012			2011			2012			2011
REVENUE
Coal sales	$	83,931		$	94,919		$	246,964		$	262,093
Transportation revenue		11,096			12,867			32,842			34,976
Other revenue		2,187			2,202			7,223			7,015

Total revenue		97,214			109,988			287,029			304,084
COSTS AND EXPENSES
Cost of coal sales:
Produced coal		62,025			73,193			188,895			201,593
Purchased coal		6,274			3,143			16,121			13,058

Total cost of coal sales (excluding depreciation, depletion and amortization)		68,299			76,336			205,016			214,651
Cost of transportation		11,096			12,867			32,842			34,976
Cost of other revenue		274			248			649			1,309
Depreciation, depletion and amortization		13,110			13,323			39,019			38,669
Selling, general and administrative expenses		3,901			3,114			11,475			10,458
Impairment and restructuring charges		206			—			13,843			—
(Gain) loss on disposal of assets		357			516			(4,156	)		1,239

Total costs and expenses		97,243			106,404			298,688			301,302

(LOSS) INCOME FROM OPERATIONS		(29	)		3,584			(11,659	)		2,782
Interest income		1			5			7			10
Interest expense		(3,012	)		(2,431	)		(8,522	)		(6,787	)

NET (LOSS) INCOME		(3,040	)		1,158			(20,174	)		(3,995	)
Net income attributable to noncontrolling interest		(274	)		(1,134	)		(371	)		(4,015	)

NET (LOSS) INCOME ATTRIBUTABLE TO OXFORD RESOURCE PARTNERS, LP UNITHOLDERS	$	(3,314	)	$	24		$	(20,545	)	$	(8,010	)

Net loss allocated to general partner	$	(66	)	$	—		$	(410	)	$	(160	)

Net (loss) income allocated to limited partners	$	(3,248	)	$	24		$	(20,135	)	$	(7,850	)

Net loss per limited partner unit:
Basic	$	(0.16	)	$	0.00		$	(0.97	)	$	(0.38	)

Diluted	$	(0.16	)	$	0.00		$	(0.97	)	$	(0.38	)

Weighted average number of limited partner units outstanding:
Basic		20,717,734			20,635,288			20,702,042			20,631,055

Diluted		20,717,734			20,706,794			20,702,042			20,631,055

Distributions paid per unit
Limited partner unitholders:
Common	$	0.4375		$	0.4375		$	1.3125		$	1.3125
Subordinated	$	0.1000		$	0.4375		$	0.6375		$	1.3125
General partner unitholders	$	0.2688		$	0.4375		$	0.9750		$	1.3125

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)


	Nine Months Ended
	September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss attributable to unitholders	$	(20,545	)	$	(8,010	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion and amortization		39,019			38,669
Impairment charges		11,645			—
Interest rate swap and fuel contract adjustment to market		(194	)		76
Loan fee amortization		1,527			1,173
Non-cash equity-based compensation expense		966			854
Advance royalty recoupment		1,064			1,050
Accretion of reclamation and mine closure costs		1,189			1,153
(Gain) loss on disposal of property and equipment		(4,156	)		1,239
Noncontrolling interest in subsidiary earnings		371			4,015
Changes in assets and liabilities:
Accounts receivable		(2,246	)		(5,356	)
Inventory		(478	)		251
Other assets		(2,212	)		(639	)
Accounts payable and other liabilities		1,284			4,331
Reclamation and mine closure costs		(6,399	)		(3,267	)
Provision for below-market contracts and deferred revenue		(543	)		(1,357	)

Net cash from operating activities		20,292			34,182
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment		(16,547	)		(27,237	)
Purchase of coal reserves and land		(51	)		(1,124	)
Mine development costs		(2,909	)		(3,182	)
Advance royalties		(2,061	)		(484	)
Proceeds from sale of property and equipment		8,543			—
Change in restricted cash		3,092			(2,121	)

Net cash from investing activities		(9,933	)		(34,148	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on borrowings		(9,417	)		(4,728	)
Advances on line of credit		41,000			51,000
Payments on line of credit		(17,000	)		(15,000	)
Credit facility issuance costs		(1,086	)		—
Capital contributions from partners		7			12
Distributions to partners		(20,644	)		(27,629	)
Distributions to noncontrolling interest		—			(3,920	)

Net cash from financing activities		(7,140	)		(265	)

Net increase (decrease) in cash		3,219			(231	)
CASH AND CASH EQUIVALENTS, beginning of period		3,032			889

CASH AND CASH EQUIVALENTS, end of period	$	6,251		$	658

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(UNAUDITED)

(in thousands, except for unit data)


	Limited Partner																				Non-			Total
	Common					Subordinated					Total					General Partner					controlling			Partners’
	Units		Capital			Units		Capital			Units		Capital			Units		Capital			Interest			Capital
Balance at December 31, 2010		10,330,603	$	146,078			10,280,380	$	(40,394	)		20,610,983	$	105,684			420,633	$	(63	)	$	3,142		$	108,763
Net (loss) income				(3,939	)				(3,911	)				(7,850	)				(160	)		4,015			(3,995	)
Partners’ contributions																	495		12						12
Partners’ distributions				(13,588	)				(13,489	)				(27,077	)				(552	)		(3,920	)		(31,549	)
Equity-based compensation				854										854											854
Issuance of units to LTIP participants		27,825		(405	)							27,825		(405	)										(405	)

Balance at September 30, 2011		10,358,428	$	129,000			10,280,380	$	(57,794	)		20,638,808	$	71,206			421,128	$	(763	)	$	3,237		$	73,680

Balance at December 31, 2011		10,399,744	$	121,911			10,280,380	$	(64,751	)		20,680,124	$	57,160			422,044	$	(1,032	)	$	2,989		$	59,117
Net (loss) income				(10,140	)				(9,995	)				(20,135	)				(410	)		371			(20,174	)
Partners’ contributions																	654		7						7
Partners’ distributions				(11,937	)				(8,295	)				(20,232	)				(412	)					(20,644	)
Equity-based compensation				966										966											966
Issuance of units to LTIP participants		54,594		(227	)							54,594		(227	)										(227	)

Balance at September 30, 2012		10,454,338	$	100,573			10,280,380	$	(83,041	)		20,734,718	$	17,532			422,698	$	(1,847	)	$	3,360		$	19,045

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

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 modern, large scale equipment. Our reserves and operations are strategically located 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 C. Ungurean, the President and Chief Executive Officer of our GP and a member of our GP’s board of directors (“Mr. C. Ungurean”), and Thomas T. Ungurean, the former Senior Vice President, Equipment, Procurement and Maintenance of our GP (“Mr. T. Ungurean”), 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 Long-Term Incentive Plan (“ 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 through October 1, 2012.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(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 the normal course of business during both 2011 and 2012, there have been 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 September 30, 2012, was 35.55% and 18.09%, respectively, with our GP’s ownership being 2.00%. The remaining 44.36% 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 September 30, 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 through October 1, 2012, 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.

Reclassifications

Certain prior-year amounts have been reclassified in our condensed consolidated statements of operations to conform with current-year classifications. These reclassifications are:

•

Including the cost of purchased coal of $3.1 million and $13.1 million in “Cost of coal sales” rather than their being shown separately for the three and nine month periods ended September 30, 2011, respectively.

•

Reclassifying $0.2 million and $1.3 million to “Cost of other revenue” from “Cost of coal sales” for the three and nine month periods ended September 30, 2011, respectively.

•

Separately presenting $0.5 million and $1.2 million in “(Gain) loss on disposal of assets” rather than including them in “Cost of coal sales” for the three and nine months ended September 30, 2011, respectively.

Also, “Accretion of reclamation and mine closure costs” is now presented as a separate line item in our condensed consolidated statements of cash flows.

New Accounting Standards Adopted

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

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 2:

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

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 2012 did not have a material effect on our consolidated financial statements.

In June 2011, the FASB issued ASU 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 is effective for public companies during interim and annual periods beginning after December, 15, 2011. The adoption of this guidance in 2012 did not affect our consolidated financial statements.

NOTE 3:

IMPAIRMENT AND RESTRUCTURING CHARGES

In March 2012, we received a termination notice from a customer related to an 0.8 million ton per year coal supply contract fulfilled from our Illinois Basin operations. In response, we idled one Illinois Basin mine and the related wash plant, closed our Illinois Basin lab, reduced operations at two other mines, terminated a significant number of employees, and substituted purchased coal for mined and washed coal on certain sales contracts.

In the second quarter of 2012, we further adjusted our Illinois Basin operations, varying the mines that were idled to best manage strip ratio impacts and other costs. We also resumed operations at the wash plant on a limited basis in June.

In the third quarter of 2012, we idled one additional mine and resumed production at a second mine for a limited period of time that allowed us to meet our coal supply commitments. As of September 30, 2012, both of these mines were being prepared for market deferment. The wash plant continued limited production through mid-September and has again been idled. We anticipate that the restructuring related to our Illinois Basin operations will be completed by the end of the first quarter of 2013.

In addition to these actions, we continue to redeploy certain Illinois Basin equipment to our Northern Appalachia operations. We are also seeking to sell certain excess mining equipment from these idled operations.

For the three and nine months ended September 30, 2012, we recognized impairment and restructuring charges of $0.2 million and $13.8 million, respectively, related to the restructuring of our Illinois Basin operations. We expect to incur $0.7 million of additional costs throughout the remainder of 2012 and the first quarter of 2013 as we complete the restructuring.

Impairment Charges

As a result of the restructuring described above, we recorded asset impairment charges of $11.6 million during the nine months ended September 30, 2012, none of which were recorded in the third quarter. These non-cash charges related to coal reserves, mine development assets and certain mining equipment (the “Impaired Assets”).

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 that are currently ready for sale and are no longer in production, are presented separately as current assets held for sale in our condensed consolidated balance sheet as of September 30, 2012. These assets are no longer being depreciated or amortized. Impaired Assets that do not meet the criteria to be

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 3:

IMPAIRMENT AND RESTRUCTURING CHARGES (continued)

classified as held for sale remain in property, plant and equipment. These assets are recorded at carrying value, after taking into account the impairment.

Restructuring Charges

Restructuring charges represent expenses directly related to the restructuring that do not provide future economic benefit. Restructuring charges related to our Illinois Basin operations totaling $0.2 million and $2.2 million were recorded during the three and nine months ended September 30, 2012, respectively. These charges included employee termination costs for approximately 160 terminated employees, professional and legal fees, and transportation costs associated with moving idled equipment to our Northern Appalachian operations. The liabilities related to the restructuring are included in “Other current liabilities” on our condensed consolidated balance sheet as of September 30, 2012.

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


	Nine Months Ended September 30, 2012					September 30, 2012
	Expense		Payments			Liability
Severance and other termination costs	$	760	$	(681	)	$	79
Professional and legal fees		974		(880	)		94
Equipment relocation costs		464		(444	)		20

Total restructuring charges		2,198	$	(2,005	)	$	193

Asset impairment (non-cash)		11,645

Total impairment and restructuring charges	$	13,843

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


	Total Expected
	Expenses
Severance and other termination costs	$	799
Professional and legal fees		1,427
Equipment relocation costs		683
Asset impairment (non-cash)		11,645

Total impairment and restructuring charges	$	14,554

NOTE 4:

INVENTORY

Inventory consisted of the following:


	September 30,		December 31,
	2012		2011
Coal	$	5,312	$	4,346
Fuel		1,950		2,013
Supplies and spare parts		5,216		5,641

Total inventory	$	12,478	$	12,000

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 5:

PROPERTY, PLANT AND EQUIPMENT, NET

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


	September 30,			December 31,
	2012			2011
Property, plant and equipment, gross
Land	$	3,357		$	3,188
Coal reserves		51,665			55,124
Mine development costs		35,896			30,223

Total property		90,918			88,535
Buildings and tipple		2,133			2,133
Machinery and equipment		199,933			218,715
Vehicles		4,572			4,781
Furniture and fixtures		1,669			1,619
Railroad sidings		160			160

Total property, plant and equipment, gross		299,385			315,943
Less: accumulated depreciation, depletion and amortization		(142,152	)		(120,336	)

Total property, plant and equipment, net	$	157,233		$	195,607

Assets held for sale totaling $6.7 million have been reclassified to current assets on our September 30, 2012 consolidated balance sheet and are not included in the amounts above. 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				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Expense type:
Depreciation	$	8,450	$	9,198	$	26,727	$	27,667
Depletion		1,301		1,398		4,010		4,425
Amortization		3,319		2,659		8,100		6,373

In April 2012, we sold oil and gas mineral rights on 1,250 acres of land for $6.3 million, which is recorded in “Gain/loss on disposal of assets.” As part of that transaction, we retained royalty rights equivalent to a 20% net revenue interest once the wells are producing. As of September 30, 2012, none of the wells were drilled and producing.

NOTE 6:

RECLAMATION AND MINE CLOSURE COSTS

Our reclamation and mine closure costs 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.

As of September 30, 2012, we had liabilities totaling $21.6 million recorded for reclamation and mine closure costs, 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 September 30, 2012, the aggregate undiscounted cost of final mine closure was $25.0 million.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 6:

RECLAMATION AND MINE CLOSURE COSTS (continued)

The following table presents the activity affecting the liability for reclamation and mine closure costs for the respective periods:


	Nine Months Ended			Twelve Months Ended
	September 30, 2012			December 31, 2011
Beginning balance	$	21,789		$	12,987
Accretion expense		1,189			1,503
Payments		(6,399	)		(6,443	)
Revisions in estimated cash flows		5,021			13,742

Total reclamation and mine closure costs		21,600			21,789
Less current portion		5,075			4,553

Noncurrent liability	$	16,525		$	17,236

For the nine months ended September 30, 2012, revisions in discounted estimated cash flows increased the reclamation and mine closure costs liability by $5.0 million. Of this amount, $1.9 million was related to four newly-opened mines and $3.0 million was related to reclamation work in progress at recently closed mines. Adjustments to the liability for reclamation and mine closure costs due to such revisions generally result in a corresponding adjustment to the related mine development asset for new mines and to amortization expense for closed mines.

In 2011, revisions in discounted estimated cash flows resulted in a net increase in the reclamation and mine closure costs of $13.7 million and were primarily related to eight new mines, as well as revisions to estimates of the expected costs for stream and wetland mitigation as regulatory requirements continue to evolve. Adjustments to the liability for reclamation and mine closure costs due to such revisions generally result in a corresponding adjustment to the related mine development asset for new mines.

NOTE 7:

LONG-TERM DEBT

Credit Facility

In connection with our initial public offering in July 2010, we entered into an agreement (the “Credit Agreement”) for a $175 million credit facility with Citicorp USA, Inc., as Administrative Agent, Citibank, N.A., as Swing Line Bank, Barclays Bank PLC and The Huntington National Bank, as Co-Syndication Agents, Fifth Third Bank and Comerica Bank, as Co-Documentation Agents, and the lenders party thereto. The Credit Agreement became effective July 19, 2010 and provides for a $60 million term loan and a $115 million revolving credit line. We are required to make quarterly principal payments of $1.5 million on the term loan commencing on September 30, 2010 and continuing until maturity in July 2014, when the remaining balance is to be paid. The $115 million revolving credit line matures in July 2013. Accordingly, the $104 million outstanding on the revolver as of September 30, 2012 has been classified as a current liability. Borrowings under the Credit Agreement bear interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (“LIBOR”) or the Base Rate plus the Applicable Margin (Base Rate and Applicable Margin are defined in the Credit Agreement).

The Credit Agreement 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 and 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. The Credit Agreement also requires compliance with certain financial covenants, including limiting our leverage and interest coverage ratios, as well as capping capital expenditures in any fiscal year to certain predetermined amounts. Borrowings under the Credit Agreement are secured by a first-priority lien on and security interest in substantially all of our assets.

In June 2012, we executed an amendment to the Credit Agreement which is applicable for the remaining term of the Credit Agreement and which (i) modified the leverage ratio, (ii) authorized the sale of certain Kentucky assets, and (iii) allows quarterly distributions at minimum levels and additionally at certain higher levels as long as

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 7:

LONG-TERM DEBT (continued)

specified liquidity thresholds are maintained after giving effect to the distribution. In connection with the amendment, we paid the consenting lenders a non-refundable amendment fee equal to 0.50% of their then outstanding loan commitments under the Credit Agreement. The amendment fee was capitalized and is being amortized over the remaining term of the Credit Agreement.

As of September 30, 2012, we were in compliance with all covenants under the terms of the Credit Agreement.

NOTE 8:

FAIR VALUE MEASUREMENTS

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


	Fair Value Measurements as of September 30, 2012
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)
Interest rate swap agreement	$	—	$	(49	)	$	—
Fuel purchases accounted for as derivatives		—	$	87			—

	Fair Value Measurements as of December 31, 2011
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)
Interest rate swap agreement	$	—	$	(156	)	$	—

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, accounts receivable and accounts payable: The carrying amount reported in the balance sheets for cash and cash equivalents, 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.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 8:

FAIR VALUE MEASUREMENTS (continued)

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


	September 30, 2012				December 31, 2011
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Fixed rate debt	$	7,531	$	7,646	$	12,755	$	13,650
Variable rate debt		150,500		150,500		131,000		131,000

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 September 30, 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.


	Fair Value Measurements as of September 30, 2012
	Active Markets for Identical Liabilities		Significant Other Observable Inputs		Significant Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)
Assets held for sale⁽¹⁾	$	—	$	6,665	$	—

⁽¹⁾	Total assets held for sale as of September 30, 2012 are $6.7 million. Some of the assets held for sale were not impaired and therefore are not reflected in the table above. Assets which were not impaired are recorded at net book value rather than fair value.

Derivatives Activity

We are exposed to certain market risks, primarily fuel price 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 various financial instruments, some of which require derivative accounting under ASC 815. 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.

As a result of the reduced production levels associated with the Illinois Basin restructuring, we were unable to take physical delivery of some of the diesel fuel for which we were obligated under our previous fuel contracts. Therefore, we renegotiated fuel deliveries and restructured our fuel contracts into a single amended contract that decreased the fuel volume and net settled a portion of the previous contracts. As a result, the amended contract no longer qualifies for the normal purchase and sale exemption allowed by ASC 815 and is accounted for as a derivative. As of September 30, 2012, the amended contract is valued at $87 which is recorded in “Prepaid expenses and other current assets.”

NOTE 9:

LONG-TERM INCENTIVE PLAN

Under our LTIP, we recognize equity-based compensation expense over the vesting period of the granted 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, our grants of units included some units that vest based on performance criteria established at the time of and in connection with the grant. We are authorized to distribute up to 2,056,075 units under the LTIP. As of September 30, 2012, 1,458,956 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.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 9:

LONG-TERM INCENTIVE PLAN (continued)

For the three months ended September 30, 2012 and 2011, equity-based compensation expense was $490 and $245, respectively. For the nine months ended September 30, 2012 and 2011, our equity-based compensation expense was $966 and $854, respectively. These amounts are included in selling, general and administrative expenses. As of September 30, 2012 and December 31, 2011, $2,080 and $978, respectively, of cost remained unamortized which we expect to recognize using the straight-line method over a remaining weighted average period of 1.4 years.

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


				Weighted
				Average
				Grant Date
	Units			Fair Value
Unvested balance as of December 31, 2011		80,043		$	16.25
Granted		298,787			10.33
Issued		(54,594	)		10.97
Surrendered		(27,652	)		13.16

Unvested balance as of September 30, 2012		296,584			11.54

The values of LTIP units vested during the three months ended September 30, 2012 and 2011 were $284 and $54, respectively. The values of LTIP units vested during the nine months ended September 30, 2012 and 2011 were $841 and $507, respectively.

NOTE 10:

EARNINGS PER UNIT

For purposes of our earnings per unit calculation, we have two classes: limited partner units 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, but will in the future 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.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 10:

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					Nine Months Ended
	September 30,					September 30,
	2012			2011		2012			2011
	(in thousands, except for unit and per unit amounts)
*Limited partner units*
Average units outstanding:
Basic		20,717,734			20,635,288		20,702,042			20,631,055
Effect of equity-based compensation		n/a			71,506		n/a			n/a

Diluted		20,717,734			20,706,794		20,702,042			20,631,055

Net (loss) income allocated to limited partners
Basic	$	(3,248	)	$	24	$	(20,135	)	$	(7,850	)
Diluted	$	(3,248	)	$	24	$	(20,135	)	$	(7,850	)

Net loss per limited partner unit
Basic	$	(0.16	)	$	—	$	(0.97	)	$	(0.38	)
Diluted	$	(0.16	)	$	—	$	(0.97	)	$	(0.38	)

*General partner units*
Average units outstanding:
Basic and diluted		422,677			421,120		422,461			420,983

Net loss allocated to general partner
Basic	$	(66	)	$	—	$	(410	)	$	(160	)
Diluted	$	(66	)	$	—	$	(410	)	$	(160	)

Net loss per general partner unit
Basic	$	(0.16	)	$	—	$	(0.97	)	$	(0.38	)
Diluted	$	(0.16	)	$	—	$	(0.97	)	$	(0.38	)

Anti-dilutive units ⁽¹⁾⁽²⁾		10,541			n/a		—			75,989

*Distributions paid per unit*
Limited partner unitholders:
Common	$	0.4375		$	0.4375	$	1.3125		$	1.3125
Subordinated	$	0.1000		$	0.4375	$	0.6375		$	1.3125
General partner unitholders	$	0.2688		$	0.4375	$	0.9750		$	1.3125

⁽¹⁾	Anti-dilutive units are not used in calculating dilutive average units.

⁽²⁾	Unvested LTIP units are not dilutive units for the nine months ended September 30, 2012.

NOTE 11:

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 contracts contain 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. As of September 30, 2012, the remaining terms of our long-term contracts range from less than one year to three and one-quarter years.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 11:

COMMITMENTS AND CONTINGENCIES (continued)

As previously disclosed in our public filings, we received a contract termination notice in March 2012 from a customer of our Illinois Basin operations. This contract required us to supply the customer with 0.8 million tons of coal per year. Absent any termination thereof, the term of the contract continued 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 had recently gone into effect under the customer’s sales contract and current coal market conditions. We are aggressively pursuing compensation for our damages through all appropriate legal measures.

Purchase Commitments

From time to time, we purchase coal from third parties in order to meet quality or delivery requirements under our customer contracts. As of September 30, 2012, we are committed to purchase 350,000 tons of coal in 2012 and 360,000 tons of coal in 2013.

We previously had a long-term coal purchase contract for 0.4 million tons per year with a separate supplier who now asserts that the contract is terminated by its terms. We have taken a contrary position and are actively pursuing resolution of this matter.

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 have a long-term rail transportation contract that has been amended and extended through March 31, 2014.

Coal Royalties

Periodically, limited amounts of coal associated with a reserve cannot be or are not mined due to various factors including mining conditions or economics. Despite those factors, certain lessors have alleged that they are due royalties associated with the unmined portion of those reserves. We are willing to entertain an amicable resolution and recorded $220 in additional royalty expense in the second quarter of 2012 related to this issue.

401(k) Plan

During September 2012, we paid our GP $2.1 million to fund the commitment to our 401(k) plan related to plan year 2011. As of September 30, 2012, we had an obligation to pay our GP $1.4 million related to plan year 2012. This amount is expected to be paid by September 2013.

Surety and Performance Bonds

As of September 30, 2012, we had $39.0 million in surety bonds outstanding to secure certain reclamation obligations. Additionally, as of September 30, 2012, we had letters of credit totaling $7.9 million outstanding in support of these bonds. Further, as of September 30, 2012, we had road bonds totaling $0.6 million and performance bonds totaling $2.7 million outstanding to secure our contractual performance. We believe these bonds and letters of credit will expire without any claims or payments thereon, and therefore will not have a material adverse effect on our financial position, liquidity or operations. Subsequent to September 30, 2012, we posted an additional $2.2 million of letters of credit as collateral related to our surety bonds.

Legal

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

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 11:

COMMITMENTS AND CONTINGENCIES (continued)

Guarantees

Our GP and the Partnership guarantee certain obligations of our subsidiaries. Also, Mr. C. Ungurean has guaranteed certain of our obligations relating to surety and performance bonds. We believe that these guarantees will expire without any liability to the guarantors, and therefore will not have a material adverse effect on our financial position, liquidity or operations.

NOTE 12:

RELATED PARTY TRANSACTIONS

The Partnership and Oxford Mining have 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, legal, 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. Reimbursable costs under the Services Agreement totaling $3.3 million and $2.7 million were included in accounts payable as of September 30, 2012 and December 31, 2011, respectively.

A services agreement with Tunnell Hill Reclamation, LLC (“Tunnell Hill”), a company that is indirectly owned by Mr. C. Ungurean, Mr. T. Ungurean, and affiliates of AIM Oxford, 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 $24 per month for rental of the equipment. Following the lease term, Tunnell Hill exercised its option to purchase all of the leased equipment. For this transaction, we received net proceeds of $877, which reflects the purchase price of $948 less a credit of 50% of the rental payments received during the lease period, and recognized a gain of $97.

Contract services provided to Tunnell Hill totaled $153 and $254 for the three months ended September 30, 2012 and 2011, respectively, and $187 and $1,453 for the nine months ended September 30, 2012 and 2011, respectively. Accounts receivable were $152 and $48 from Tunnell Hill as of September 30, 2012 and December 31, 2011, respectively. Separate from the terminated services agreement described above, we continue to sell clay and small quantities of coal to Tunnell Hill.

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. We incurred a de minimus amount of expense for charter services in the three months ended September 30, 2012 and $43 during the three months ended September 30, 2011. During the nine months ended September 30, 2012 and 2011, we paid Zanesville Aviation an aggregate of $126 and $116, respectively.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

(in thousands, except for unit and per unit data)

(CONTINUED)

NOTE 13:

SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information:


	Nine Months Ended
	September 30,
	2012		2011
Cash paid for:
Interest	$	8,482	$	5,106

Non-cash activities:
Purchase of coal reserves with debt		307		—
Reclamation and mine closure costs capitalized in mine development		6,411		9,158
Market value of common units vested in LTIP		764		1,057
Purchase of property and equipment included in accounts payable		1,569		4,633
Mine development expenditures included in accounts payable		269		186

NOTE 14:

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, municipalities and other coal-related entities, 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 extract coal utilizing surface mining techniques 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 15:

SUBSEQUENT EVENTS

On October 25, 2012, the GP’s Board of Directors declared a cash distribution by the Partnership of $0.20 per unit to its common unitholders, and $0.10 per unit to its holders of general partner units, with respect to the third quarter ended September 30, 2012. No distribution was declared related to the subordinated units for the period. This distribution, totaling $2.1 million (consisting of over $2.0 million to the common unitholders and $42.3 to the general partner unitholders), will be paid on November 14, 2012 to unitholders of record as of the close of business on November 8, 2012. Under the Partnership’s partnership agreement, arrearage amounts resulting from the reduction in the common units distribution accumulate, while those from the subordinated units do not. Accumulated arrearage amounts for the common unitholders will be paid as a priority over and before any future quarterly distributions are paid on the subordinated units. The total arrearage amount related to the November 2012 distribution is $2.5 million.

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

Statements in this Quarterly Report on Form 10-Q that are not historical facts are forward-looking statements within the “safe harbor” provision of the Private Securities Litigation Reform Act of 1995 and may involve a number of risks and uncertainties. We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to various risks, uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

•

market demand for coal and energy;

•

availability of qualified workers;

•

future economic or capital market conditions;

•

weather conditions or catastrophic weather-related damage;

•

our production capabilities;

•

consummation of financing, acquisition or disposition transactions and the effect thereof on our business;

•

our plans and objectives for future operations and expansion or consolidation;

•

our relationships with, and other conditions affecting, our customers;

•

availability and costs of key supplies or commodities such as diesel fuel, steel, explosives and tires;

•

availability and costs of capital equipment;

•

prices of fuels which compete with or impact coal usage, such as oil and natural gas;

•

timing of reductions or increases in customer coal inventories;

•

long-term coal supply arrangements;

•

reductions and/or deferrals of purchases by major customers;

•

risks in or related to coal mining operations, including risks relating to third-party suppliers and carriers operating at our mines or complexes;

•

unexpected maintenance and equipment failure;

•

environmental, safety and other laws and regulations, including those directly affecting our coal mining and production, and those affecting our customers’ coal usage;

•

ability to obtain and maintain all necessary governmental permits and authorizations;

•

competition among coal and other energy producers in the United States and internationally;

•

railroad, barge, trucking and other transportation availability, performance and costs;

•

employee benefits costs and labor relations issues;

•

replacement of our reserves;

•

our assumptions concerning economically recoverable coal reserve estimates;

•

availability and costs of credit, surety bonds and letters of credit;

•

title defects or loss of leasehold interests in our properties which could result in unanticipated costs or inability to mine these properties;

•

future legislation and changes in regulations or governmental policies or changes in interpretations or enforcement thereof, including with respect to safety enhancements and environmental initiatives relating to global warming and climate change;

•

our liquidity, including our ability to adhere to financial covenants related to our borrowing arrangements;

•

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;

•

adequacy and sufficiency of our internal controls;

•

legal and administrative proceedings, settlements, investigations and claims, including those related to citations and orders issued by regulatory authorities, and the availability of related insurance coverage;

•

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.

You should keep in mind that any forward-looking statements made by us in this Quarterly Report on Form 10-Q or elsewhere speak only as of the date on which the statements were made. New risks and uncertainties arise from time to time, and it is impossible for us to predict these events or how they may affect us or anticipated results. We have no duty to, and do not intend to, update or revise the forward-looking statements in this Quarterly Report on Form 10-Q after the date of this Quarterly Report on Form 10-Q, except as may be required by law. In light of these risks and uncertainties, you should keep in mind that any forward-looking statement made in this Quarterly Report on Form 10-Q might not occur. When considering these forward-looking statements, you should keep in mind the cautionary statements in this Quarterly Report on Form 10-Q and in our other SEC filings, including the more detailed discussion of these factors, as well as other factors that could affect our results, contained in the “Risks Relating to Our Business” section of Item 1A of our Annual Report.

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 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. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky. During the three months and nine months ended September 30, 2012, we produced 1.8 and 5.3 million tons of coal, respectively, and sold 1.9 and 5.7 million tons of coal, respectively, including 0.1 and 0.4 million tons of purchased coal, respectively.

As previously disclosed in our public filings, we received a termination notice in March 2012 from a customer related to an 0.8 million ton per year coal supply contract fulfilled from our Illinois Basin operations. In response, we idled one Illinois Basin mine and the related wash plant, closed our Illinois Basin lab, reduced operations at two other mines, terminated a significant number of employees and substituted purchased coal for mined and washed coal on certain sales contracts.

For the three and nine months ended September 30, 2012, we recognized impairment and restructuring charges of $0.2 million and $13.8 million, respectively, related to the restructuring of our Illinois Basin operations. We expect to incur $0.7 million of additional costs throughout the balance of 2012 and the first quarter of 2013 as we complete the restructuring.

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 including cost of purchased coal;

•

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

•

our Distributable Cash Flow, a non-GAAP financial measure.

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. 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 Coal Sales” 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 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 a coal sales revenue per ton basis, net of transportation costs. Our coal sales revenue per ton represents our coal sales revenue divided by total tons of coal sold. The following table provides operational data including data with respect to our coal production and purchases, coal sold and coal sales revenue per ton for the periods indicated:


													% Change
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months 2012 vs.			Nine Months 2012 vs.
	2012			2011			2012			2011			2011			2011
	(tons in thousands)
Produced tons		1,776			2,187			5,285			6,071			(18.8	%)		(12.9	%)
Purchased tons		146			88			366			365			65.9	%		0.3	%

Tons of coal sold		1,922			2,275			5,651			6,436			(15.5	%)		(12.2	%)

Tons sold under long-term contracts⁽¹⁾		94.0	%		93.2	%		93.0	%		93.5	%		n/a			n/a

Coal sales revenue per ton	$	43.67		$	41.72		$	43.70		$	40.73			4.7	%		7.3	%
Below-market sales contract amortization per ton		0.06			0.11			0.10			0.12			(45.5	%)		(16.7	%)

Cash coal sales revenue per ton		43.61			41.61			43.60			40.61			4.8	%		7.4	%
Cash cost of coal sales per ton		35.54			33.54			36.28			33.36			6.0	%		8.8	%

Cash margin per ton	$	8.07		$	8.07		$	7.32		$	7.25			0.0	%		1.0	%

Transportation revenue and cost per ton	$	5.77		$	5.66		$	5.81		$	5.43			1.9	%		7.0	%

Number of operating days		67			68			203			204			(1.5	%)		(0.5	%)

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

Cost of Coal Sales

We evaluate, on a cost per ton sold basis, our cost of coal sales, which excludes the cost of transportation, non-cash costs such as depreciation, depletion and amortization (“DD&A”), gain/loss on asset disposals, impairment and restructuring charges, and indirect costs such as selling, general and administrative expenses. Our cost of coal sales per ton represents our cost of coal sales divided by the tons of coal sold. Our cost of coal sales includes costs for labor, fuel, oil, explosives, royalties, equipment lease expense, repairs and maintenance, and other costs directly related to our mining operations. Our cost of coal sales does not take into account the effects 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.

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 coal quality specifications. These costs are included in the cost of purchased coal amount within cost of coal sales.

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 are actively pursuing resolution of this matter. We have not received any tons from this supplier during 2012.

In March 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 both the third quarter and the nine months ended September 30, 2012 were under this new contract as compared to the previously described lower priced contract in the third quarter and the nine months ended September 30, 2011.

The following table provides summary information for the periods indicated relating to our cost of coal sales per ton and tons of coal sold:


									% Change
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months 2012 vs.			Nine Months 2012 vs.
	2012		2011		2012		2011		2011			2011
	(tons in thousands)
Cost of coal sales per ton	$	35.54	$	33.54	$	36.28	$	33.36		6.0	%		8.8	%

Produced tons		1,776		2,187		5,285		6,071		(18.8	%)		(12.9	%)
Purchased tons		146		88		366		365		65.9	%		0.3	%

Tons of coal sold		1,922		2,275		5,651		6,436		(15.5	%)		(12.2	%)

Adjusted EBITDA

Adjusted EBITDA represents net income (loss) attributable to our unitholders before interest, income taxes, DD&A, non-cash equity-based compensation expense, gain or loss on the disposal of assets, amortization of below-market coal sales contracts, impairment and restructuring charges, certain non-recurring costs, non-cash change in future reclamation obligations, and noncontrolling interest. Although Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP, we believe it is useful in evaluating our financial performance and compliance with certain credit facility financial covenants. Because not all companies calculate Adjusted EBITDA in the same way, our calculation may not be comparable to similarly titled measure of other companies.

Adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements, such as investors and lenders, to assess:

•

our financial performance without regard to financing methods, capital structure or income taxes;

•

our ability to generate cash sufficient to pay interest on our indebtedness and to make cash distributions to our limited partners and general partners;

•

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 represents Adjusted EBITDA less cash interest expense (net of interest income), estimated reserve replacement expenditures, maintenance capital expenditures, cash reclamation expenditures, and noncontrolling interest. 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. Maintenance capital expenditures include, among other things, actual expenditures for plant, equipment, and mine development. Cash reclamation expenditures represent the reduction to our reclamation and mine closure costs resulting from cash payments. Earnings attributable to the noncontrolling interest are not available for distribution to our unitholders and accordingly are deducted.

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, we believe Distributable Cash Flow is useful 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, facilitating comparison with the performance of other publicly traded limited partnerships.

Sales Contracts

For the past three years, over 90% 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 define coal sales contracts as long-term if their initial term is one year or more. 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.

As of September 30, 2012, all of our projected sales for the balance of 2012 are committed and priced. For 2013, 2014 and 2015, we have committed and priced long-term contracts for sales of 6.3 million tons, 4.8 million tons and 1.9 million tons, respectively. In addition, we have contracts which are committed and unpriced for 0.4 million tons for 2014, 2.5 million tons for 2015 and 4.2 million tons for 2016.

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 fiscal 2012, 2013, 2014 and 2015, 63%, 70%, 68% and 61%, respectively, of the tons of coal 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 the coal sales price for all or a specified percentage of changes in the costs for items such 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.

Some long-term coal sales contracts contain option provisions that give the customer the right to purchase certain tons of coal during the contract term at the same price as the fixed tons provided for in the contract. As of September 30, 2012, customers hold options to purchase 0.4 million tons per year for the period from 2013 through 2015.

Factors That Impact Our Business

Factors that influence our business include, but are not limited to: (i) demand for electricity, (ii) economic conditions, (iii) the quantity and quality of coal available from competitors, (iv) competition for production of electricity from non-coal sources such as natural gas, (v) domestic air emission standards and the ability of coal-fired power plants to meet these standards, (vi) legislative, regulatory and judicial developments, including delays,

challenges to, and difficulties in acquiring, maintaining or renewing necessary permits or mineral or surface rights, (vii) market price fluctuations for sulfur dioxide emission allowances and (viii) our ability to meet governmental financial security requirements associated with mining and reclamation activities.

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.”

Summary

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands, unaudited)
Statement of Operations Data:
Revenue:
Coal sales	$	83,931		$	94,919		$	246,964		$	262,093
Transportation revenue		11,096			12,867			32,842			34,976
Other revenue		2,187			2,202			7,223			7,015

Total revenue		97,214			109,988			287,029			304,084

Costs and expenses:
Cost of coal sales:
Produced coal		62,025			73,193			188,895			201,593
Purchased coal		6,274			3,143			16,121			13,058

Total cost of coal sales (excluding depreciation, depletion and amortization)		68,299			76,336			205,016			214,651
Cost of transporation		11,096			12,867			32,842			34,976
Cost of other revenue		274			248			649			1,309
Depreciation, depletion and amortization		13,110			13,323			39,019			38,669
Selling, general and administrative expenses		3,901			3,114			11,475			10,458
Impairment and restructuring expenses		206			—			13,843			—
(Gain) loss on disposal of assets		357			516			(4,156	)		1,239

Total costs and expenses		97,243			106,404			298,688			301,302


(Loss) income from operations		(29	)		3,584			(11,659	)		2,782

Interest income		1			5			7			10
Interest expense		(3,012	)		(2,431	)		(8,522	)		(6,787	)

Net (loss) income		(3,040	)		1,158			(20,174	)		(3,995	)
Net income attributable to noncontrolling interest		(274	)		(1,134	)		(371	)		(4,015	)

Net (loss) income attributable to Oxford Resource Partners, LP unitholders	$	(3,314	)	$	24		$	(20,545	)	$	(8,010	)

Other Financial Data:
Adjusted EBITDA	$	14,170		$	17,795		$	39,897		$	46,314

Distributable Cash Flow	$	3,076		$	3,880		$	6,347		$	8,591

Reconciliation to GAAP Measures

The following table presents a reconciliation of net (loss) income attributable to our unitholders to Adjusted EBITDA and Distributable Cash Flow for each of the periods indicated:

Reconciliation of net (loss) income attributable to Oxford Resource Partners, LP unitholders

to Adjusted EBITDA and Distributable Cash Flow:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in thousands, unaudited)
Net (loss) income attributable to Oxford Resource Partners, LP unitholders	$	(3,314	)	$	24		$	(20,545	)	$	(8,010	)

Adjustments:
Interest expense, net of interest income		3,011			2,426			8,515			6,777
Depreciation, depletion and amortization		13,110			13,323			39,019			38,669
Impairment and restructuring expenses		206			—			13,843			—
(Gain) loss on disposal of assets		357			516			(4,156	)		1,239
Below-market coal sales contract amortization		(121	)		(244	)		(543	)		(741	)
Non-cash equity-based compensation expense		490			245			966			854
Non-cash change in future reclamation obligations		384			356			1,189			3,004
Non-recurring costs		(227	)		15			1,238			507
Noncontrolling interest		274			1,134			371			4,015

Adjusted EBITDA		14,170			17,795			39,897			46,314

Adjustments:
Cash interest expense, net of interest income		(2,399	)		(2,009	)		(7,095	)		(5,528	)
Estimated reserve replacement expenditures		(1,264	)		(1,529	)		(2,988	)		(4,357	)
Maintenance capital expenditures		(4,874	)		(7,323	)		(17,252	)		(20,097	)
Cash reclamation expenditures		(2,283	)		(1,920	)		(5,844	)		(3,726	)
Noncontrolling interest		(274	)		(1,134	)		(371	)		(4,015	)

Distributable Cash Flow	$	3,076		$	3,880		$	6,347		$	8,591

Three Months Ended September 30, 2012 Compared to Three Months Ended September 30, 2011

Overview. Net loss for the three months ended September 30, 2012 was $3.3 million, or $0.16 per diluted limited partner unit, compared to essentially a breakeven performance for the three months ended September 30, 2011. Total revenue was $97.2 million for the three months ended September 30, 2012, a decrease of $12.8 million, or 11.6%, from $110.0 million for the three months ended September 30, 2011. Adjusted EBITDA was $14.2 million for the three months ended September 30, 2012, a decrease of $3.6 million from $17.8 million for the three months ended September 30, 2011. Cash margin per ton remained constant at $8.07 for the three months ended September 30, 2012 and 2011. Distributable Cash Flow was $3.1 million for the three months ended September 30, 2012, a decrease of $0.8 million from $3.9 million for the three months ended September 30, 2011.

Coal Sales Revenue. Coal sales revenue was $83.9 million for the three months ended September 30, 2012, a decrease of $11.0 million, or 11.6%, from $94.9 million for the three months ended September 30, 2011. The decrease was primarily attributable to a 15.5% reduction in sales tons with a value of $14.7 million that resulted from the unplanned Illinois Basin coal sales contract termination. The decrease was partially offset by a $2.00 increase in cash coal sales revenue per ton (excluding transportation cost) that increased coal sales revenue by $3.7 million.

Transportation Revenue and Expenses. Transportation revenue and expenses were $11.1 million, respectively, for the three months ended September 30, 2012, a decrease of $1.8 million from $12.9 million, respectively, for the three months ended September 30, 2011. The reduction in tons shipped accounted for $2.0 million of the decrease which was partially offset by a slight increase in transportation costs.

Other Revenue. Royalty income and other revenue, primarily limestone sales, was consistent at $2.2 million for the three months ended September 30, 2012 and 2011. Limestone sales were $1.3 million for the three months ended September 30, 2012, an increase of $0.5 million, compared to $0.8 million for the three months ended September 30, 2011. This increase was offset by a decrease in royalty income and service contract income of $0.3 million and $0.2 million, respectively.

Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) was $68.3 million for the three months ended September 30, 2012, a decrease of $8.0 million, or 10.5%, from $76.3 million for the three months ended September 30, 2011. The decrease was primarily attributable to a reduction of 0.4 million in tons sold, which corresponds to an $11.8 million decrease in cost of coal sales. The reduction in tons sold was attributable to the ongoing impact of the unplanned Illinois Basin coal sales contract termination that occurred in the first quarter of 2012. Cost of coal sales per ton was $35.54 for the three months ended September 30, 2012, an increase of $2.00, or 6.0%, per ton from $33.54 per ton for the three months ended September 30, 2011. The $2.00 per ton increase corresponds to a $3.8 million increase in cost of coal sales, primarily attributable to a rise in cost of $3.6 million, $1.7 million and $1.3 million for purchased coal, diesel fuel and lease expense, respectively, and was partially offset by decreases in repairs and other costs of $1.0 million and $1.8 million, respectively. The diesel fuel increase was due to higher spot prices. For the three months ended September 30, 2012, 146,000 tons of coal were purchased at an average price of $42.98 per ton, which represents increases of 57,800 tons and $7.26 per ton, respectively, for the three months ended September 30, 2011.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense was $13.1 million for the three months ended September 30, 2012, a decrease of $0.2 million, or 1.6%, from $13.3 million for the three months ended September 30, 2011. In 2012, certain equipment associated with our Illinois Basin operations was reclassified to assets held for sale and is no longer being depreciated. The decrease in depreciation was partially offset by a $0.7 increase in amortization of reclamation and mine closure costs for closed mines where such costs exceeded the original estimate.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were $3.9 million for the three months ended September 30, 2012, an increase of $0.8 million, or 25.3%, from $3.1 million for the three months ended September 30, 2011. The increase was primarily attributable to higher compensation and insurance expenses.

Impairment and Restructuring Charges. Impairment and restructuring charges were $0.2 million for the three months ended September 30, 2012. No such charges were incurred for the three months ended September 30, 2011. These charges for the three months ended September 30, 2012 consisted of professional fees and equipment transportation costs associated with our continuing restructuring of our Illinois Basin operations.

(Gain) Loss on Disposal of Assets. The loss on disposal of assets of $0.4 million for the three months ended September 30, 2012 represented a decrease of $0.1 million from a loss of $0.5 million for the three months ended September 30, 2011. The loss, substantially unchanged quarter over quarter, was the result of the sale/disposal of primarily equipment in the normal course of business.

Net Income Attributable to Noncontrolling Interest. Net income attributable to noncontrolling interest represents the net income attributable to the 49% interest in Harrison Resources owned by a subsidiary of CONSOL Energy. Net income attributable to noncontrolling interest was $0.3 million for the three months ended September 30, 2012, a decrease of $0.8 million from $1.1 million for the three months ended September 30, 2011. This decrease in net income attributable to noncontrolling interest was primarily due to increased mining costs resulting from a higher strip ratio incurred at the Harrison mine.

Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

Overview. Net loss for the nine months ended September 30, 2012 was $20.5 million, a difference of $12.5 million compared to a net loss of $8.0 million for the nine months ended September 30, 2011. The increase in the loss was primarily attributable to the impairment and restructuring charges of $13.8 million, partially offset by a net gain of $4.2 million related to the disposal of assets. Adjusted EBITDA was $39.9 million for the nine months ended September 30, 2012, down $6.4 million, or 13.9%, from $46.3 million for the nine months ended September 30, 2011. Cash margin per ton was $7.32 for the nine months ended September 30, 2012, an increase of $0.07 per ton, or 1.0%, from $7.25 per ton for the nine months ended September 30, 2011. Distributable Cash Flow was $6.3 million for the nine months ended September 30, 2012, a decrease of $2.3 million, or 26.1%, from $8.6 million for the nine months ended September 30, 2011.

Coal Sales Revenue. Coal sales revenue was $247.0 million for the nine months ended September 30, 2012, a decrease of $15.1 million, or 5.8%, from $262.1 million for the nine months ended September 30, 2011. The decrease was primarily attributable to a reduction in tons sold that accounted for $31.9 million, offset by a $2.97 per ton increase in pricing that accounted for $16.8 million. This volume decrease was primarily due to the Illinois Basin coal sales contract termination that occurred in the first quarter of 2012 that continues to adversely impact our sales.

Transportation Revenue and Expenses. Transportation revenue and expenses were $32.8 million, respectively, for the nine months ended September 30, 2012, a decrease of $2.2 million, or 6.1%, from $35.0 million, respectively, for the nine months ended September 30, 2011. The reduction in tons shipped accounted for $4.3 million of the decrease which was partially offset by a $2.1 million increase in transportation costs.

Other Revenue. Royalty income and other revenue, primarily limestone sales, was $7.2 million for the nine months ended September 30, 2012, an increase of $0.2 million from $7.0 million for the nine months ended September 30, 2012. The increase was driven by a $2.4 million increase in limestone sales, partially offset by a decrease in royalty income and service contract income of $1.0 million and $1.2 million, respectively.

Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) was $205.0 million for the nine months ended September 30, 2012, a decrease of $9.7 million, or 4.5%, from $214.7 million for the nine months ended September 30, 2011. The decrease was primarily attributable to an 0.8 million reduction in tons sold relating to the Illinois Basin coal sales contract termination that accounted for $26.2 million of cost. Cost of coal sales per ton was $36.28 for the nine months ended September 30, 2012, an increase of $2.92 per ton, or 8.8%, from $33.36 per ton for the nine months ended September 30, 2011. The $16.5 million in increased costs was primarily attributable to $9.5 million, $3.5 million and $4.7 million of cost increases in diesel fuel, equipment lease expense and purchased coal cost, respectively, and was partially offset by decreases in other costs. The diesel fuel cost increase was due to higher spot prices. The purchased coal increase of $4.7 million was due to an average cost of $43.99 per ton paid for the nine months ended September 30, 2012, an increase of $8.21 per ton from $35.78 per ton paid for the nine months ended September 30, 2011.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense was $39.0 million for the nine months ended September 30, 2012, an increase of $0.3 million from $38.7 million for the nine months ended September 30, 2011. The increase was primarily attributable to amortization of reclamation and mine closure costs associated with closed mines, partially offset by lower depreciation expense associated with assets held for sale that are no longer being depreciated.

Selling, General and Administrative Expenses. Selling, general and administrative expenses were $11.5 million for the nine months ended September 30, 2012, an increase of $1.0 million, or 9.7%, from $10.5 million for the nine months ended September 30, 2011. The increase was primarily attributable to professional fees.

Impairment and Restructuring Charges. Impairment and restructuring charges were $13.8 million for the nine months ended September 30, 2012, with no similar amounts in the prior year. These charges resulted from the restructuring of our Illinois Basin operations and included non-cash asset impairment charges related to coal reserves, mine development assets and equipment. Restructuring charges included employee termination costs, professional fees, and transportation costs associated with moving idled equipment to our Northern Appalachian operations.

(Gain) Loss on Disposal of Assets. The net gain on disposal of assets totaled $4.2 million for the nine months ended September 30, 2012. We sold oil and gas rights on 1,250 acres of land for $6.3 million that was partially offset by a $2.1 million loss on the sale of equipment.

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. Net income attributable to noncontrolling interest was $0.4 million for the nine months ended September 30, 2012, a decrease of $3.6 million from $4.0 million for the nine months ended September 30, 2011. This decrease in net income attributable to noncontrolling interest was primarily due to increased mining costs associated with a higher strip ratio at the Harrison mine.

Liquidity and Capital Resources

Our business is capital intensive and requires substantial capital expenditures for, among other things, purchasing, maintaining and upgrading equipment used in developing and mining our coal, and acquiring reserves. Our principal liquidity needs 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 the Credit Agreement. Also, if we are able to effect any asset sales associated with our Illinois Basin restructuring at acceptable values, our liquidity will be enhanced by those amounts.

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

In June 2012, we amended the Credit Agreement to maintain the leverage ratio required as of June 30, 2012 through maturity of the facility.

In April 2012, we sold oil and gas mineral rights on 1,250 acres of land for $6.3 million. In the transaction, we retained royalty rights equivalent to a 20% net revenue interest once the wells produce. At September 30, 2012, none of the wells were drilled and producing.

As of September 30, 2012, our available liquidity was $9.2 million, which consisted of $6.3 million in cash on hand and $2.9 million of borrowing capacity under the Credit Agreement. Our available liquidity as of September 30, 2011 was $19.1 million, which consisted of $0.7 million in cash on hand and $18.4 million of borrowing capacity under the Credit Agreement.

Distributions

For the nine months ended September 30, 2012, we generated $6.3 million in Distributable Cash Flow toward our total distributions of $13.5 million. The remaining $7.2 million in distributions were funded from the $6.3 million sale of oil and gas rights and advances under the Credit Agreement. We declared a cash distribution of $0.4375 per common unit for each of the first and second quarters of 2012, which was reduced to $0.20 per common unit for the third quarter of 2012, as compared with $0.4375 per common unit for all quarters in previous years. We also declared a reduced cash distribution of $0.10 per subordinated unit for each of the first and second quarters of 2012, which was further reduced to zero in the third quarter of 2012 with suspension of any subordinated units distribution, as compared with $0.4375 per subordinated unit for all quarters in previous years. Under our partnership agreement, arrearage amounts resulting from the reduction in the common units distribution accumulate, while those from the subordinated units do not. Accumulated arrearage amounts for the common unitholders will be paid as a priority over and before any future quarterly distributions are paid on the subordinated units. The arrearage amount related to this distribution for the third quarter of 2012 is $2.5 million.

Cash Flows

The following table reflects cash flows for the applicable periods:


	Nine Months Ended September 30,
	2012			2011
	(in thousands, unaudited)
Net cash from:
Operating activities	$	20,292		$	34,182
Investing activities		(9,933	)		(34,148	)
Financing activities		(7,140	)		(265	)

	$	3,219		$	(231	)

Net cash provided by operating activities was $20.3 million for the nine months ended September 30, 2012, down from $34.2 million for the nine months ended September 30, 2011. This decrease of $13.9 million was primarily the result of a larger net loss and a net unfavorable change in working capital.

Net cash used in investing activities was $9.9 million for the nine months ended September 30, 2012, down from $34.1 million for the nine months ended September 30, 2011. This decrease of $24.2 million was primarily attributable to leasing as opposed to purchasing major mining equipment and proceeds from the sale of assets.

Net cash used in financing activities was $7.1 million for the nine months ended September 30, 2012, up from $0.3 million for the nine months ended September 30, 2011. The increase of $6.8 million was primarily attributable to an increase in payments on borrowings, offset in part by lower advances on the line of credit under the Credit Agreement and lower distributions to partners for the nine months ended September 30, 2012 compared to the nine months ended September 30, 2011.

Credit Facility

The credit agreement related to our $175 million credit facility (the “Credit Agreement”) provides for a credit facility consisting of a $60 million term loan and a $115 million revolving line of credit. As of September 30, 2012, we had borrowings of $150.5 million outstanding consisting of $46.5 million on our term loan and $104.0 million on our revolving line of credit. We also had $7.9 million of letters of credit outstanding in support of surety bonds, which bonds are primarily issued for reclamation obligations.

The Credit Agreement became effective July 19, 2010. We are required to make quarterly principal payments of $1.5 million on the $60 million term loan commencing on September 30, 2010 and continuing until the maturity in July 2014, when the remaining balance is to be paid. The $115 million revolving credit line matures in

July 2013. Borrowings under the Credit Agreement bear interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (“LIBOR”) or the Base Rate plus the Applicable Margin (Base Rate and Applicable Margin are defined in the Credit Agreement). The Credit Agreement 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, and 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. The Credit Agreement also requires compliance with certain financial covenants; including limiting our leverage and interest coverage ratios as well as capping capital expenditures in any fiscal year to certain predetermined amounts. Borrowings under the Credit Agreement are secured by a first-priority lien on and security interest in substantially all of our assets.

In June 2012, an amendment to the Credit Agreement was executed that modified certain provisions. The amendment, applicable for the remaining term of the Credit Agreement, (i) modified the leverage ratio, (ii) authorized the sale of certain Kentucky assets, and (iii) allows quarterly distributions at minimum levels and additionally at certain higher levels as long as specified liquidity thresholds are maintained after giving effect to the distribution.

The Credit Agreement matures in July 2013. We intend to achieve the extension and/or replacement of our credit facility prior to the maturity date.

Capital Expenditures

Our mining operations require investments to expand, upgrade and enhance existing operations and to comply with environmental and mining laws and regulations. For 2012, we expect to incur between $22.0 million and $27.0 million in maintenance and expansion capital expenditures, excluding mine reclamation and closing costs.

The following table reflects our maintenance and expansion capital expenditures by type for the nine months ended September 30, 2012 and 2011:


	Nine Months Ended September 30,
	2012		2011
	(in thousands)
Coal reserves and land expenditures	$	51	$	1,075
Major mining equipment		2,637		10,156
Components and tires		12,739		16,735
Mine development		2,723		3,243

Total capital expenditures	$	18,150	$	31,209

We have funded and expect to continue funding maintenance and expansion capital expenditures primarily from cash generated by our operations, borrowings under the Credit Agreement, and proceeds from asset sales.

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 letters of credit and surety, performance, and road bonds. No liabilities related to these arrangements are reflected in our condensed 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 arrangements.

Federal and state laws require us to secure certain long-term obligations, such as reclamation and mine closure costs, and contractual performance. Typically, we secure these obligations with surety bonds supported by letters of credit. If surety bonds became unavailable, we would seek to secure our reclamation obligations with letters of credit, cash deposits or other suitable forms of collateral.

As of September 30, 2012, we had $39.0 million of surety bonds outstanding and de minimus cash bonds to secure certain reclamation obligations. Additionally, as of September 30, 2012, we had $7.9 million of letters of credit outstanding in support of these bonds. Further, as of September 30, 2012, we had $0.6 million of road bonds and $2.7 million of performance bonds outstanding that required no security. We believe these bonds and letters of credit will expire without any claims or payments thereon and accordingly we do not expect any material adverse effect on our financial position, liquidity or operations therefrom.

New Accounting Standards Adopted

See Note 2 – Summary of Significant Accounting Policies to the condensed consolidated financial statements included in Part I. – Financial Information – Item 1. – Condensed Consolidated Financial Statements (Unaudited) – Notes to Condensed Consolidated Financial Statements contained in this Quarterly Report on Form 10-Q related to recently issued accounting pronouncements, which information is incorporated herein by reference.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts. These estimates and assumptions are based on information available as of the date of the financial statements. Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end. The results of operations for the nine months ended September 30, 2012 are not necessarily indicative of results that can be expected for the full year. Please refer to the section entitled “Critical Accounting Policies and Estimates” of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in our Annual Report for a discussion of our critical accounting policies and estimates.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market price risk in the normal course of mining and selling coal. We manage this risk through the use of long-term coal supply agreements, rather than through the use of derivative instruments. Committed, but unpriced, sales are subject to future market price volatility. As of September 30, 2012, 100% of our projected sales for the balance of 2012 are committed and priced.

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 September 30, 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. During the quarterly period ended September 30, 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.

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. 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.

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: November 7, 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/ BRADLEY W. HARRIS
		Bradley W. Harris
		Senior Vice President, Chief Financial Officer and Treasurer
		(Principal Financial Officer)

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)

10.4C*#		Amendment to Employment Agreement between Oxford Resources GP, LLC and Gregory J. Honish, which Amendment was effective on August 15, 2012

10.16M*†		Amendment No. 2012-2 to Coal Purchase and Sale Agreement, dated July 30, 2012

10.19#		Employment Agreement between Oxford Resources GP, LLC and Bradley W. Harris, which Employment Agreement was effective on August 15, 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 September 30, 2012 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*		Certification of Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the September 30, 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 September 30, 2012 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2*		Certification of Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the September 30, 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 September 30, 2012 and December 31, 2011; (ii) our Condensed Consolidated Statements of Operations for the three and nine month periods ended September 30, 2012 and 2011; (iii) our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011; (iv) our Condensed Consolidated Statements of Partners’ Capital for the nine months ended September 30, 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.

#	Compensatory plan or amendment.