Westmoreland Resource Partners (WMLPQ) 10-Q 2010 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2010

OR

o 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	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

41 South High Street, Suite 3450, Columbus, Ohio 43215
(Address of Principal Executive Offices, Including Zip Code)

(614) 643-0314
(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. YESþ NOo

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). Yeso Noo

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

Large accelerated filero	Accelerated filero	Non-accelerated filerþ	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YESo NOþ

As of November 9, 2010, 10,285,543 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. INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)		1
Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		1
Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009		2
Condensed Consolidated Statements of Partners’ Capital for the Nine Months Ended September 30, 2010 and 2009		3
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009		4
Notes to Condensed Consolidated Financial Statements		5
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		17
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		39
ITEM 4. CONTROLS AND PROCEDURES		39
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS		40
ITEM 1A. RISK FACTORS		40
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		40
ITEM 3. DEFAULTS UPON SENIOR SECURITIES		40
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		41
ITEM 5. OTHER INFORMATION		41
ITEM 6. EXHIBITS		42
Exhibit 10.20
Exhibit 10.21
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

i

PART I. FINANCIAL INFORMATION

Item 1. Interim Condensed Consolidated Financial Statements (Unaudited)

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands, except for unit data)

	September 30,		December 31,
	2010		2009
ASSETS
Cash and cash equivalents	$	1,833	$	3,366
Trade accounts receivable		27,061		24,403
Inventory		12,011		8,801
Advance royalties		3,108		1,674
Prepaid expenses and other current assets		1,415		1,424
Total current assets		45,428		39,668
Property, plant and equipment, net		204,211		149,461
Advance royalties		5,752		7,438
Other long-term assets		13,251		6,796
Total assets	$	268,642	$	203,363
LIABILITIES
Current maturities of long-term debt	$	7,413	$	4,113
Accounts payable		29,111		21,655
Asset retirement obligations		6,598		7,377
Deferred revenue — current portion		—		2,090
Accrued taxes other than income taxes		1,482		1,464
Accrued payroll and related expenses		2,968		2,045
Other current liabilities		3,224		5,714
Total current liabilities		50,796		44,458
Long-term debt		90,322		91,598
Asset retirement obligations		6,125		5,966
Other long-term liabilities		2,534		4,229
Total liabilities		149,777		146,251
Commitments and Contingencies
PARTNERS’ CAPITAL
Limited Partner unitholders (20,563,451 and 11,964,547 units outstanding as of September 30, 2010 and December 31, 2009, respectively)		114,510		53,960
General Partner unitholder (419,607 and 242,023 units outstanding as of September 30, 2010 and December 31, 2009, respectively)		94		1,085
Total Oxford Resource Partners, LP Capital		114,604		55,045
Noncontrolling interest		4,261		2,067
Total partners’ capital		118,865		57,112
Total liabilities and partners’ capital	$	268,642	$	203,363

See accompanying notes to interim unaudited condensed consolidated financial statements.

1

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except for unit data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Revenue
Coal sales	$	78,127		$	56,446		$	233,454		$	176,705
Transportation revenue		9,605			7,589			28,976			23,261
Royalty and non-coal revenue		1,347			1,748			4,857			5,546
Total revenue		89,079			65,783			267,287			205,512
Costs and expenses
Cost of coal sales (excluding depreciation, depletion and amortization, shown separately)		57,138			38,793			171,635			115,770
Cost of purchased coal		3,790			2,477			18,617			12,313
Cost of transportation		9,605			7,589			28,976			23,261
Depreciation, depletion and amortization		12,255			5,899			30,587			17,257
Selling, general and administrative expenses		4,044			3,297			10,446			9,391
Contract termination and amendment expenses, net		652			—			652			—
Total costs and expenses		87,484			58,055			260,913			177,992
Income from operations		1,595			7,728			6,374			27,520
Interest income		3			9			11			31
Interest expense		(3,662	)		(2,127	)		(7,535	)		(4,642	)
Gain from purchase of business		—			3,823			—			3,823
Net income (loss)		(2,064	)		9,433			(1,150	)		26,732
Less: net income attributable to noncontrolling interest		(1,336	)		(1,636	)		(4,644	)		(4,104	)
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(3,400	)	$	7,797		$	(5,794	)	$	22,628
Net income (loss) allocated to general partner	$	(68	)	$	155		$	(116	)	$	450
Net income (loss) allocated to limited partners	$	(3,332	)	$	7,642		$	(5,678	)	$	22,178
Basic earnings (loss) per limited partner unit	$	(0.18	)	$	0.71		$	(0.40	)	$	2.07
Dilutive earnings (loss) per limited partner unit	$	(0.18	)	$	0.71		$	(0.40	)	$	2.06
Weighted average number of limited partner units outstanding basic		18,884,324			10,746,556			14,306,473			10,735,070
Weighted average number of limited partner units outstanding diluted		18,884,324			10,787,819			14,306,473			10,763,200
Distributions paid per limited partner unit*	$	—		$	0.46		$	0.23		$	0.92

* Excludes amounts distributed as part of the initial public offering.

See accompanying notes to interim unaudited condensed consolidated financial statements.

2

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

For the Nine Months Ended September 30, 2010 and 2009

(UNAUDITED)

(in thousands, except for unit data)

	Limited Partner																Non-			Total
	Common					Subordinated						General Partner					controlling			Partners’
	Units		Capital			Units			Capital			Units		Capital			Interest			Capital
Balance at December 31, 2008		—	$	—			10,724,625		$	32,371			217,867	$	653		$	2,297		$	35,321
Net income										22,178					450			4,104			26,732
Partners’ contributions							1,183,689			11,329			24,156		231						11,560
Partners’ distributions										(10,381	)				(210	)		(2,940	)		(13,531	)
Equity-based compensation										320											320
Issuance of units to Long-Term Incentive Plan participants upon vesting							9,065														—
Balance at September 30, 2009		—	$	—			11,917,379		$	55,817			242,023	$	1,124		$	3,461		$	60,402
Balance at December 31, 2009		—	$	—			11,964,547		$	53,960			242,023	$	1,085		$	2,067		$	57,112
Net income (loss)				(782	)					(4,896	)				(116	)		4,644			(1,150	)
Initial public offering		10,280,368		157,181			(1,705,368	)		(7,331	)		175,000		694						150,544
Offering costs				(6,097	)																(6,097	)
Partners’ contributions													2,584		25						25
Partners’ distributions										(78,117	)				(1,594	)		(2,450	)		(82,161	)
Equity-based compensation										686											686
Issuance of units to Long-Term Incentive Plan participants upon vesting		2,703					21,201			(94	)										(94	)
Balance at September 30, 2010		10,283,071	$	150,302			10,280,380		$	(35,792	)		419,607	$	94		$	4,261		$	118,865

See accompanying notes to interim unaudited condensed consolidated financial statements.

3

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	Nine Months Ended
	September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(5,794	)	$	22,628
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		30,587			17,257
Interest rate swap or rate cap adjustment to market		286			(1,681	)
Loan fee amortization		787			362
Write-off of deferred financing costs for repayment		1,302			1,252
Non-cash equity compensation expense		686			320
Advanced royalty recoupment		1,202			972
Loss on disposal of property and equipment		766			908
Gain on acquisition of business		—			(3,823	)
Noncontrolling interest in subsidiary earnings		4,644			4,104
(Increase) decrease in assets:
Accounts receivable		(2,658	)		2,515
Inventory		(2,957	)		(2,135	)
Other assets		135			(6,032	)
Increase (decrease) in liabilities:
Accounts payable and other liabilities		3,106			3,629
Asset retirement obligation		(620	)		(641	)
Provision for below-market contracts and deferred revenue		(3,373	)		(8,576	)
Net cash provided by operating activities		28,099			31,059
CASH FLOWS FROM INVESTING ACTIVITIES:
Phoenix Coal acquisition		—			(18,275	)
Purchase of property and equipment		(68,545	)		(17,949	)
Purchase of mineral rights and land		(3,105	)		(1,771	)
Mine development costs		(2,230	)		(2,128	)
Royalty advances		(966	)		(359	)
Proceeds from sale of property and equipment		1,259			81
Change in restricted cash		(3,352	)		(2,431	)
Net cash used in investing activities		(76,939	)		(42,832	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Initial public offering		150,544			—
Offering expenses		(6,097	)		—
Proceeds from borrowings		60,041			6,650
Payments on borrowings		(89,942	)		(2,018	)
Advances on line of credit		31,000			7,500
Payments on line of credit		(10,500	)		—
Credit facility issuance costs		(5,603	)		(1,800	)
Capital contributions from partners		25			11,560
Distributions to noncontrolling interest		(2,450	)		(2,940	)
Distributions to partners		(79,711	)		(10,591	)
Net cash provided by financing activities		47,307			8,361
Net decrease in cash		(1,533	)		(3,412	)
CASH AND CASH EQUIVALENTS, beginning of period		3,366			15,179
CASH AND CASH EQUIVALENTS, end of period	$	1,833		$	11,767

See accompanying notes to interim unaudited condensed consolidated financial statements.

4

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“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 GAAP for complete financial statements. In our opinion, the interim 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 interim 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 interim condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2009 and notes thereto included in our final prospectus dated July 15, 2010 (the “Prospectus”) and filed with the U.S. Securities and Exchange Commission (the “SEC”).

NOTE 1: ORGANIZATION AND PRESENTATION

Significant Relationships Referenced in Notes to the Interim 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.

Organization

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

We are managed by our GP and all executives, officers and employees who provide services to us are employees of our GP. Charles C. Ungurean, the President and Chief Executive Officer of our GP and a member of our GP’s board of directors, and Thomas T. Ungurean, the Senior Vice President, Equipment, Procurement and Maintenance of our GP, are the co-owners of C&T Coal, Inc. (“C&T Coal”). Prior to our acquisition of Oxford Mining Company (“Predecessor” or “Oxford”), C&T Coal owned 100% of the outstanding ownership interest in Oxford.

We were formed in August 2007 to acquire all of the ownership interests in Oxford. On August 24, 2007, a contribution agreement was executed which resulted in AIM Oxford Holdings, LLC (“AIM Oxford”) and C&T Coal holding a 63.7% and 34.3% limited partner interest in ORLP, respectively, and our GP owning a 2% general partner interest in ORLP. Also at that time, the members of our GP were AIM Oxford and C&T Coal with a 65% and 35% ownership interest in our GP, respectively. 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.

Subsequent to our formation, AIM Oxford and C&T Coal made several capital contributions for various purposes including purchasing property, plant and equipment and acquiring the surface mining operations of Phoenix Coal Corporation (“Phoenix Coal”). The capital contributions were not all in direct proportion to AIM Oxford’s and C&T Coal’s initial limited partner interests in us. As a result of the disproportionate capital contributions and the Initial Public Offering (seeInitial Public Offeringin this Note 1), AIM Oxford’s and C&T Coal’s ownership of the Partnership, as of September 30, 2010, was 36.90% and 18.78%, respectively, with 2.00% and 42.32% interests being owned by our GP and other common unitholders, respectively. AIM Oxford and C&T Coal, as of September 30, 2010, owned 65.98% and 33.58% interests, respectively, in our GP, with the remaining 0.44% interest being owned by Jeffrey M. Gutman, Senior Vice President, Chief Financial Officer and Treasurer of our GP.

5

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

We own a 51% interest in Harrison Resources and are therefore deemed to have control. 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 interim condensed consolidated balance sheets.

Initial Public Offering

On July 6, 2010, we commenced the initial public offering of our common units pursuant to our Registration Statement on Form S-1, Commission File No. 333-165662 (the “Registration Statement”), which was declared effective by the SEC on July 12, 2010.

Upon closing of our initial public offering on July 19, 2010, we issued 8,750,000 of the common units that were registered at a price per unit of $18.50. The aggregate offering amount of the securities sold pursuant to the Registration Statement was $161.9 million. In our initial public offering, we granted the underwriters a 30 day option to purchase up to 1,312,500 additional common units. This option was not exercised.

After deducting underwriting discounts and commissions of approximately $10.5 million paid to the underwriters, our offering expenses of approximately $6.1 million and a structuring fee of approximately $0.8 million, the net proceeds from our initial public offering were approximately $144.5 million. We used all of the net proceeds from our initial public offering for the uses described in the Prospectus.

Unit Split

Immediately prior to the closing of our initial public offering on July 19, 2010, we executed a unit split whereby the unitholders at that time received approximately 1.82097973 units in exchange for each unit they held on that date. The units and per unit amounts referenced in the accompanying interim condensed consolidated financial statements and notes thereto have been retroactively restated to reflect this unit split.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

There were no changes to our significant accounting policies from those disclosed in the Prospectus.

New Accounting Standards Issued and Adopted

In August 2009, the Financial Accounting Standards Board (the “FASB”) issued ASU 2009-05, Measuring Liabilities at Fair Value. This ASU provides clarification that, in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the alternative valuation methods outlined in the guidance. It also clarifies that restrictions preventing the transfer of a liability should not be considered as a separate input or adjustment in the measurement of its fair value. This pronouncement was effective for reporting periods that begin after August 27, 2009. Our adoption of this guidance, on October 1, 2009, did not impact our consolidated financial statements.

In June 2009, the FASB amended guidance for the consolidation of a variable interest entity (“VIE”). This guidance updated the determination of whether an enterprise is the primary beneficiary of a VIE, and is, therefore, required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. This standard also requires continuous reassessments of whether an enterprise is the primary beneficiary of a VIE. Previously, reconsideration was required only when specific events had occurred. This guidance also requires enhanced disclosure about an enterprise’s involvement with a VIE. The provisions of these updates are effective for reporting periods that begin after November 15, 2009. Our adoption of this standard, on January 1, 2010, did not impact our consolidated financial statements.

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

In January 2010, the FASB issued guidance on improving disclosures about fair value measurements. This guidance requires reporting entities to make new disclosures about recurring or nonrecurring fair value measurements including significant transfers into and out of Level 1 and Level 2 fair value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair value measurements. We adopted this guidance effective January 1, 2010 except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption of this guidance and the adoption of the Level 3 reconciliation disclosures did not and is not expected to have a material effect on our consolidated financial statements.

NOTE 3: ACQUISITION

On September 30, 2009, we acquired 100% of the active western Kentucky surface mining coal operations of Phoenix Coal. This acquisition provided us an entry into the Illinois Basin and consisted of four active surface coal mines and coal reserves of approximately 20 million tons, as well as mineral rights, fixed assets working capital and various coal sales and purchase contracts.

In connection with the closing of our Phoenix Coal acquisition, we entered into an escrow agreement with Phoenix Coal. The purpose of the escrow agreement is to provide a source of funding for any indemnification claims we make against Phoenix Coal for breaches of warranties and/or covenants as the seller under the terms of the acquisition agreement. To date, there have been no indemnification claims against the escrow fund. The escrow was funded with $3,300,000. The escrow agreement provides for the release to Phoenix Coal of portions of the escrow fund including earnings thereon at periodic intervals, with one-third of the escrow fund amount being released to Phoenix Coal at each of March 31, 2010, September 30, 2010, and March 31, 2011. All amounts are offset for any indemnification claims. Pursuant to such release provisions, the escrow agent released one-third of the then owing escrow fund amount, or $1,100,000, to Phoenix Coal at each of the first two release dates as scheduled.

We also assumed a contract with a third party to pay a contingent fee if the third party was able to arrange to lease or purchase, on our behalf, a specified amount of coal reserves by July 31, 2010. The contingency was met in the second quarter of 2010 and we paid a fee of $500,000 by installments in May 2010 and in July 2010.

The following unaudited pro forma financial information reflects the consolidated results of operations as if the Phoenix Coal acquisition had occurred at the beginning of 2009. The pro forma information includes adjustments primarily for depreciation, depletion and amortization based upon fair values of property, plant and equipment and mineral rights, leased equipment, and interest expense for acquisition debt and additional capital contributions. The pro forma financial information is not necessarily indicative of results that actually would have occurred if we had assumed operation of these assets on the date indicated nor are they indicative of future results.

	Three		Nine
	Months Ended		Months Ended
	September 30,		September 30,
	2009		2009
Revenue	$	90,598	$	268,561
Net income attributable to Oxford Resource Partners, LP unitholders	$	2,568	$	5,603

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 4: INVENTORY

Inventory consisted of the following:

	September 30,		December 31,
	2010		2009
Coal	$	6,460,000	$	4,759,000
Fuel		1,645,000		1,264,000
Supplies and spare parts		3,906,000		2,778,000
Total	$	12,011,000	$	8,801,000

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,
	2010		2009
Property, plant and equipment, gross
Land	$	3,374,000	$	3,374,000
Coal reserves		54,373,000		39,905,000
Mine development costs		10,872,000		8,606,000
Total property		68,619,000		51,885,000
Buildings and tipple		2,066,000		2,025,000
Machinery and equipment		196,511,000		133,667,000
Vehicles		4,191,000		3,913,000
Furniture and fixtures		1,293,000		690,000
Railroad sidings		160,000		160,000
Total property, plant and equipment, gross		272,840,000		192,340,000
Less: accumulated depreciation, depletion and amortization		68,629,000		42,879,000
Total property, plant and equipment, net	$	204,211,000	$	149,461,000

The amounts of depreciation expense related to 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,
	2010		2009		2010		2009
Expense type:
Depreciation	$	9,609,000	$	4,558,000	$	23,590,000	$	12,560,000
Depletion		1,481,000		1,058,000		4,505,000		3,485,000
Amortization		1,165,000		283,000		2,492,000		1,212,000

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 6: LONG-TERM DEBT AND RELATED DERIVATIVE FINANCIAL INSTRUMENTS

Our $115 million credit facility evidenced by our credit agreement with a syndicate of lenders, for which FirstLight Funding I, Ltd. acted as Administrative Agent (our “$115 million credit facility”), provided for borrowings consisting of a term loan of $70 million, acquisition loans of up to $25 million and a revolving credit facility of $20 million.

In connection with our initial public offering, we paid off the amounts outstanding under our $115 million credit facility and entered into 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 (our “$175 million credit facility”). Our $175 million credit facility became effective on July 19, 2010, the closing date of our initial public offering, and provides for a $60 million term loan and a $115 million revolving credit facility. We are required to make quarterly principal payments of $1.5 million on the term loan commencing on September 30, 2010 and continuing until the maturity date in 2014 when the remaining balance is to be paid. The $115 revolving credit facility and $60 million term loan will mature in 2013 and 2014, respectively, and borrowings will bear interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (“LIBOR”) or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin are each defined in the credit agreement evidencing our $175 million credit facility).

Borrowings under our $175 million credit facility are secured by a first-priority lien on and security interest in substantially all of our assets. Our $175 million credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness, make certain investments, make distributions to our unitholders, make ordinary course dispositions of assets over predetermined levels or enter into equipment leases over predetermined levels as well as enter into a merger or sale of all or substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries. Our $175 million credit facility also requires compliance with certain financial covenant ratios, including limiting our leverage ratio (the ratio of consolidated indebtedness to adjusted EBITDA) to no greater than 2.75 : 1.0 and limiting our interest coverage ratio (the ratio of adjusted EBITDA to consolidated interest expense) to no less than 4.0 : 1.0. In addition, we are not permitted under our $175 million credit facility to fund capital expenditures in any fiscal year in excess of certain predetermined amounts.

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

As of September 30, 2010, we had $83.5 million of borrowings outstanding under our $175 million credit facility, consisting of term loan borrowings of $58.5 million and revolving credit facility borrowings of $25 million.

In August 2010, we entered into a $50 million amortizing interest rate swap agreement in order to manage our exposure to interest rate fluctuations under the variable rate borrowings under our $175 million credit facility. A swap involves the exchange of fixed and variable rate interest payments and does not represent an actual exchange of the underlying notional amounts between the two parties.

The purpose of the interest rate swap agreement was to convert the variable interest rate on a portion of our outstanding debt to a fixed interest rate. The interest rate swap agreement expires in 2013 and results in interest payments based on fixed rates of 1.39%. The variable interest rate on our debt under the $175 million credit facility, at September 30, 2010, was 5.25%, calculated as the 30 day LIBOR rate, subject to a floor of 1.0%, plus the applicable margin of 4.25%. At September 30, 2010, the 30 day LIBOR rate was less than 1%. The balance of the amortizing interest rate swap agreement was $48.5 million at September 30, 2010.

9

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

We did not elect hedge accounting treatment for the interest rate swap agreement. All gains and losses related to the interest rate swap agreement are recorded as adjustments in interest expense. At September 30, 2010, the fair value of the interest rate swap agreement was a net liability of $252,000 and was included in other liabilities on the interim condensed consolidated balance sheets. Our interest rate cap had a fair value of zero at September 30, 2010 and $34,000 at December 31, 2009. The mark-to-market adjustments for the interest rate swap and cap agreements increased interest expense by $252,000 and $286,000 for the three months and nine months ended September 30, 2010, respectively and decreased interest expense by $703,000 and $1,681,000 for the three and nine months ended September 30, 2009, respectively. See Note 7.

On June 22, 2010, our 51% owned subsidiary, Harrison Resources, entered into an agreement with an affiliate of CONSOL Energy (“CONSOL”) to purchase approximately 3.4 million tons of coal reserves located near the Harrison mining complex. This purchase closed on August 9, 2010. Under the terms of the agreement, a down payment of $850,000 was paid at closing, with the balance of the installment payment portion of the purchase price funded with a note payable that was issued at closing by Harrison Resources to CONSOL in the principal amount of $13.5 million. Payments under the promissory note do not begin until Harrison Resources is issued a permit to mine the reserves, which is currently expected to occur in late 2011 or early 2012, and are payable thereafter in three annual installments of $5.4 million, $5.4 million and $2.7 million. The note has no stated interest rate; therefore, the difference between the face amount of $13.5 million and the imputed amount of $11.9 million reflected on the balance sheet was recorded as a discount using an imputed interest rate of 5.5% and is being amortized into interest expense using the interest method. Additionally, a royalty stream is due on certain excess coal tonnage produced from the reserves above specified levels contained in the agreement.

NOTE 7: FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value measures are classified into a three-tiered fair value hierarchy, which prioritizes the inputs used in measuring fair values as follows:

• Level 1 — Observable inputs such as quoted prices in active markets.

• Level 2 — Inputs, other than quoted prices in active markets, that are observable either directly or indirectly.

• Level 3 — Unobservable inputs in which there is little or no market data, which require a reporting entity to develop its own assumptions.

Assets and liabilities measured at fair value are based on one or more of the following valuation techniques:

• Market approach (Level 1) — Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

• Cost approach (Level 2) — Amount that would be required to replace the service capacity of an asset (replacement cost).

• Income approach (Level 3) — Techniques to convert future amounts to a single present value based on market expectations (including present value techniques, option pricing and excess earning models).

10

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

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

	Fair Value Measurement at September 30, 2010
	Quoted Prices in					Significant
	Active Markets for		Significant Other			Unobservable
	Identical Liabilities		Observable Inputs			Inputs
Description	(Level 1)		(Level 2)			(Level 3)
Interest rate swap agreement	$	—	$	(252,000	)	$	—

	Fair Value Measurement at December 31, 2009
	Quoted Prices in				Significant
	Active Markets for		Significant Other		Unobservable
	Identical Liabilities		Observable Inputs		Inputs
Description	(Level 1)		(Level 2)		(Level 3)
Interest rate cap agreement	$	—	$	34,000	$	—

We account for derivative financial instruments by recognizing the derivative instruments as either assets or liabilities in the balance sheet at fair value and recognizing the resulting gains or losses as adjustments to earnings as interest expense. We do not hold or issue derivative financial instruments for trading or speculative purposes.

We did not elect hedge accounting treatment for our interest rate swap and interest rate cap agreements. Any changes in the fair value of the interest rate swap and interest rate cap agreements are recorded in the condensed consolidated statement of operations under the caption “Interest expense.” We estimated the fair value of the interest rate swap and interest rate cap agreements using calculations based on market rates. We did not have any derivatives as of December 31, 2009. See Note 6.

The following methods and assumptions were used to estimate the fair values of financial instruments; however, the fair value option was not elected as the differences were immaterial:

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

Fixed rate debt: The fair values of long-term debt are estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows.

Variable rate debt: The fair values of variable rate debt are estimated using discounted cash flow analyses, based on our best estimates of market rates for instruments with similar cash flows.

11

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

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

	September 30, 2010				December 31, 2009
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Fixed rate debt	$	14,235,000	$	14,472,000	$	4,982,000	$	4,952,000
Variable rate debt		83,500,000		83,500,000		90,729,000		90,729,000

NOTE 8: LONG-TERM INCENTIVE PLAN

Under our long-term incentive plan (“LTIP”), we recognize equity compensation expense over the vesting period of the units, which is generally four years for each award. For the three-month periods ended September 30, 2010 and 2009, our equity compensation expense was approximately $230,000 and $106,000, respectively. For the nine-month periods ended September 30, 2010 and 2009, our equity compensation expense was approximately $686,000 and $320,000, respectively. These amounts are included in selling, general and administrative expenses in our consolidated statements of operations. As of September 30, 2010 and December 31, 2009, approximately $920,000 and $840,000, respectively, of cost remained unamortized which we expect to recognize using the straight-line method over a remaining weighted average period of one year.

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

				Weighted
				Average
				Grant Date
	Units			Fair Value
Unvested balance at December 31, 2009		143,933		$	6.48
Granted		74,312		$	10.36
Issued		(23,904	)	$	9.33
Surrendered		(10,428	)	$	7.62
Unvested balance at September, 30, 2010		183,913		$	7.61

The value of LTIP units vested during the three-month periods ended September 30, 2010 and 2009 was $50,000 and zero, respectively. The value of LTIP units vested during the nine-month periods ended September 30, 2010 and 2009 was $293,000 and $83,000, respectively.

NOTE 9: EARNINGS PER UNIT

For purposes of our earnings per unit calculation, we have applied the two-class method. The classes of units are our limited partner 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 are comprised of common units and subordinated units.

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 calculation of weighted average units outstanding to limited partners is adjusted to include LTIP units that have not yet vested and that will be issued as common units upon vesting. In years of a net loss attributable to limited partners, these unvested LTIP units are not included in the earnings per unit calculation.

12

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

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 our GP is adjusted for the dilutive impact of the unvested LTIP units. In years of a loss, these unvested LTIP units are not included in the earnings per unit calculation.

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,
	2010			2009		2010			2009
	(in thousands, except for unit and per unit amounts)
Limited partner units
Average units outstanding:
Basic		18,884,324			10,746,556		14,306,473			10,735,070
Effect of equity-based compensation		n/a			41,263		n/a			28,130
Diluted		18,884,324			10,787,819		14,306,473			10,763,200
Net income attributable to limited partners
Basic	$	(3,332	)	$	7,642	$	(5,678	)	$	22,178
Diluted	$	(3,332	)	$	7,642	$	(5,678	)	$	22,179
Earnings per limited partner unit
Basic	$	(0.18	)	$	0.71	$	(0.40	)	$	2.07
Diluted	$	(0.18	)	$	0.71	$	(0.40	)	$	2.06
General partner units
Average units outstanding:
Basic and diluted		385,368			218,130		291,277			217,956
Net income attributable to general partner
Basic	$	(68	)	$	155	$	(116	)	$	450
Diluted	$	(68	)	$	155	$	(116	)	$	449
Earnings per general partner unit
Basic	$	(0.18	)	$	0.71	$	(0.40	)	$	2.06
Diluted	$	(0.18	)	$	0.71	$	(0.40	)	$	2.06

The computation of earnings per unit above reflects the impact of the unit split on July 19, 2010 as discussed in Note 1, the additional units issued in our initial public offering on July 19, 2010, and the new units issued after our initial public offering through September 30, 2010.

NOTE 10: COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts

We are committed under long-term contracts to sell coal that meets certain quality requirements at specified prices. Most of these prices are subject to pass through or inflation adjusters that mitigate some risk from rising costs. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or us. The remaining life of our long-term contracts range up to nine years.

13

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

Purchase Commitments

We purchase coal from time to time from third parties in order to meet quality or delivery requirements under our customer contracts. We assumed one long-term purchase contract as a result of the Phoenix Coal acquisition. Under this contract, we are committed to purchase a certain volume of coal until the coal reserves covered by the contract are depleted. Based on the proven and probable coal reserves in place at September 30, 2010, we expect this contract to continue beyond five years. Additionally, we buy coal on the spot market, and the cost of that coal is dependent upon the market price and quality of the coal. Supply disruptions could impair our ability to fulfill customer orders or require us to purchase coal from other sources at a higher cost to us in order to satisfy requirements under our customer contracts.

Transportation

We depend upon barge, rail and truck transportation systems to deliver our coal to our customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments. We entered into a long-term transportation contract on April 1, 2006 for rail services, and that contract has been amended and extended through March 31, 2011.

Former Pension Plan and New 401(k) Plan

Our former defined contribution pension plan was terminated on December 31, 2009 and all funds have been transferred to our new 401(k) plan effective January 1, 2010. At September 30, 2010, we had an obligation to pay our GP $1,356,000 for the purpose of funding our GP’s commitment to our new 401(k) plan which is expected to be paid by September 2011.

Performance Bonds

As of September 30, 2010, we had outstanding $36.0 million in surety bonds and $14,000 in cash bonds to secure certain reclamation obligations. Additionally, as of September 30, 2010, we had outstanding letters of credit in support of these surety bonds of $7.4 million. Further, as of September 30, 2010, we had outstanding certain road bonds of $0.6 million and performance bonds of $7.5 million. Our management believes these bonds and letters of credit will expire without any claims or payments thereon and thus any subrogation or other rights with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.

Legal

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

Guarantees

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

14

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 11: RELATED PARTY TRANSACTIONS

In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (the “Services Agreement”) with our GP. 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. Pursuant to the Services Agreement, we reimbursed our GP for costs primarily related to payroll for all the periods after August 24, 2007, with the unpaid amounts thereof of $3,675,000 and $2,504,000 being included in our accounts payable at September 30, 2010 and December 31, 2009, respectively. These amounts include amounts payable for funding our former pension plan and our new 401(k) plan for plan years 2010 and 2009, respectively.

Also in connection with our formation in August 2007, Oxford Mining entered into an advisory services agreement (the “Advisory Agreement”) with certain affiliates of AIM Oxford. The Advisory Agreement had a term of ten years expiring in August 2017, subject to earlier termination at any time by the AIM Oxford affiliates. Under the terms of the Advisory Agreement, the AIM Oxford affiliates provided services as financial and management advisors to Oxford Mining, including providing services in obtaining equity, debt, lease and acquisition financing, as well as providing other financial, advisory and consulting services for the operation and growth of Oxford Mining. These services consisted of advisory services of a type customarily provided by sponsors of U.S. private equity firms to companies in which they have substantial investments. Such services were rendered at the reasonable request of Oxford Mining. The initial annual fee under the Advisory Agreement was $250,000 for 2008 and for 2009 and each year thereafter increased based on the percentage increase in our gross revenues. Further fees were payable for additional significant services requested. Pursuant to the Advisory Agreement, advisory fees were zero and $1,089,000 for the three-month periods ended September 30, 2010 and 2009, respectively, and $210,000 and $2,180,000 for the nine-month periods ended September 30, 2010 and 2009, respectively. The advisory fees paid for 2009 included a one-time transaction fee of $1,000,000 paid to the AIM Oxford affiliates for additional significant services in connection with the $115 million credit facility and the fee was included in deferred financing costs in 2009. The Advisory Agreement was terminated on July 19, 2010 with a termination payment of $2.5 million being made in connection with the closing of our initial public offering on the same date.

Contract services were provided to Tunnell Hill Reclamation, LLC, a company that is indirectly owned by Charles C. Ungurean, our President and Chief Executive Officer, Thomas T. Ungurean, our Senior Vice President, Equipment, Procurement and Maintenance, and affiliates of AIM Oxford, in the amount of $407,000 and $83,000 for the three-month periods ended September 30, 2010 and 2009, respectively, and $952,000 and $226,000 for the nine-month periods ended September 30, 2010 and 2009, respectively. Accounts receivable were $271,000 and $70,000 from Tunnell Hill at September 30, 2010 and December 31, 2009, respectively.

Accounts receivable from employees and owners at September 30, 2010 and December 31, 2009 were zero and $28,000, respectively.

15

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO INTERIM CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 12: SUPPLEMENTAL CASH FLOW INFORMATION

	Nine Months Ended
	September 30,
	2010		2009
Cash paid for:
Interest	$	5,606,000	$	5,051,000
Non-cash investing activities:
Purchases of property and equipment financed through accounts payable		4,099,000		2,733,000
Purchase of coal reserves by note payable		11,858,000		1,387,000
Mine development financed through accounts payable		866,000		—
Royalty advances financed through accounts payable		39,000		20,000
Non-cash financing activities:
Market value of common units vested in LTIP		336,000		83,000

NOTE 13: SEGMENT INFORMATION

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

NOTE 14: SUBSEQUENT EVENTS

Harrison Resources Distribution

Our majority-owned subsidiary Harrison Resources made a $3,000,000 distribution in October 2010, of which we and the unaffiliated noncontrolling interest holder received $1,530,000 and $1,470,000, respectively.

Partnership Distribution

On October 25, 2010, the GP’s Board of Directors declared a cash distribution by the Partnership of $0.3519 per unit with respect to the third quarter of 2010. This distribution is pro rated for the seventy-four days in which we were a public partnership in the third quarter of 2010. This distribution, totaling approximately $7,385,000, will be paid on November 12, 2010 to unitholders of record as of the close of business on November 1, 2010.

16

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 unaudited 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, 2009 included in our final prospectus dated July 15, 2009 (the “Prospectus”) and filed with the U.S. Securities and Exchange Commission (the “SEC”). This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under “Cautionary Statement Regarding Forward-Looking Statements.”

Cautionary Statement Regarding Forward-Looking Statements

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

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

• weakness in global economic conditions or in our customers’ industries;

• changes in governmental regulation of the mining industry or the electric power industry and the increased costs of complying with those changes;

• decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators;

• our dependence on a limited number of customers;

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

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

• our ability to acquire additional coal reserves;

• our ability to respond to increased competition within the coal industry;

• fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental regulations, including those related to carbon dioxide emissions, and other factors;

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

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

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

17

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

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

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

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

• risks associated with major mine-related accidents;

• results of litigation, including claims not yet asserted;

• our ability to attract and retain key management personnel;

• greater than expected shortage of skilled labor;

• our ability to maintain satisfactory relations with our employees; and

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

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

18

Overview

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

We operate in a single business segment and have three operating subsidiaries, Oxford Mining Company, LLC, Oxford Mining Company-Kentucky, LLC and Harrison Resources, LLC. 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.

We currently have 18 active surface mines that are managed as eight mining complexes. Our operations also include two river terminals, strategically located in eastern Ohio and western Kentucky. During the third quarter of 2010, we produced 1.9 million tons of coal and sold 2.0 million tons of coal, including 0.1 million tons of purchased coal. We purchase coal in the open market and under contracts to satisfy a portion of our sales commitments. During the three months and nine months ended September 30, 2010, we produced 0.4 million and 1.2 million tons of coal, respectively, from the reserves we acquired in western Kentucky from Phoenix Coal on September 30, 2009. As is customary in the coal industry, we have entered into long-term coal sales contracts with many of our customers. We define long-term coal sales contracts as coal sales contracts having terms of one year or more.

Initial Public Offering

On July 19, 2010, we closed our initial public offering of common units. After deducting underwriting discounts and commissions of approximately $10.5 million paid to the underwriters, our offering expenses of approximately $6.1 million and a structuring fee of approximately $0.8 million, the net proceeds from our initial public offering were approximately $144.5 million. We used all of the net proceeds from our initial public offering for the uses described in the Prospectus.

Credit Facility

In connection with our initial public offering, we paid off the amounts outstanding under our $115 million credit facility evidenced by our credit agreement with a syndicate of lenders, for which FirstLight Funding I, Ltd. acted as Administrative Agent (our “$115 million credit facility”), and entered into a $175 million credit facility evidenced by a credit agreement 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 (our “$175 million credit facility”). Our $175 million credit facility provides for a $115 million revolving credit facility and a $60 million term loan. As of September 30, 2010, we had $83.5 million of borrowings outstanding under our $175 million credit facility, consisting of term loan borrowings of $58.5 million and revolving credit facility borrowings of $25 million.

Evaluating Our Results of Operations

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

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

• our cost of coal sales;

• our cost of purchased coal;

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

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

19

Coal Production, Sales Volume and Sales Prices

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

Our long-term coal sales contracts typically provide for a fixed price, or a schedule of prices that are either fixed or contain market-based adjustments, over the contract term. In addition, most of our long-term coal sales contracts have full or partial cost pass through or inflation adjustment provisions. Cost pass through provisions coupled with annual inflation adjustments typically provide for increases in our sales prices in rising operating cost environments and for decreases in our sales prices in declining operating cost environments.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(tons in thousands)
Tons of coal produced (raw)		2,009			1,402			5,748			4,156
Tons of coal produced (clean)		1,925			1,364			5,568			4,039
Tons of coal purchased		122			74			617			306
Tons of coal sold		2,025			1,440			6,131			4,278
Tons sold under long-term contracts(1)		95.2	%		93.9	%		95.2	%		94.0	%
Average sales price per ton	$	38.61		$	39.21		$	38.09		$	41.31

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

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Cost of Coal Sales

We evaluate our cost of coal sales, which excludes the cost of purchased coal, on a cost per ton produced basis. Our cost of coal sales per ton produced represents our production costs divided by the clean tons of coal we produce. Our production costs include costs for labor, fuel, oil, explosives, operating lease expenses, repair and maintenance and all other costs that are directly related to our mining operations other than the cost of purchased coal, cost of transportation and depreciation, depletion and amortization, or DD&A. Our production costs also exclude any indirect costs, such as selling, general and administrative expenses, or SG&A expenses. Our production costs do not take into account the effects of any of the inflation adjustment or cost pass through provisions in our long-term coal sales contracts, as those provisions result in an adjustment to our coal sales price. The following table provides summary information for the periods indicated relating to our cost of coal sales per ton produced and tons of coal produced:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(tons in thousands)
Cost of coal sales per ton produced	$	29.69	$	28.42	$	30.82	$	28.66
Tons of coal produced		1,925		1,364		5,568		4,039

Cost of Purchased Coal

We purchase coal from third parties to fulfill a small portion of our obligations under our long-term coal sales contracts and, in certain cases, to meet customer specifications. In connection with the Phoenix Coal acquisition, we assumed a long-term coal purchase contract that had favorable pricing terms relative to our production costs. Under this contract we are obligated to purchase 0.5 million tons of coal in 2010 and 0.4 million tons of coal each year thereafter until the coal reserves covered by this contract are depleted. Based on an estimate of the proven and probable coal reserves in place at September 30, 2010, we expect this contract to continue beyond five years.

We evaluate our cost of purchased coal on a per ton basis. For the three months and nine months ended September 30, 2010, we sold 0.1 million tons and 0.6 million tons of purchased coal, respectively. The following table provides summary information for the periods indicated for our cost of purchased coal per ton and tons of purchased coal:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
	(tons in thousands)
Cost of purchased coal per ton	$	31.10	$	33.23	$	30.17	$	40.19
Tons of coal purchased		122		74		617		306

Adjusted EBITDA

Adjusted EBITDA represents net income (loss) attributable to our unitholders before interest, taxes, DD&A, gain from purchase of business, contract termination and amendment expenses, net, amortization of below-market coal sales contracts, non-cash equity compensation expense, non-cash gain or loss on asset disposals and the change in the fair value of our future asset retirement obligation (“ARO”). The change in our ARO represents the change over the applicable period in the fair value of our future ARO calculated on a present value basis. This amount is part of our reclamation expense in our financial statements. Although adjusted EBITDA is not a measure of performance calculated in accordance with Generally Accepted Accounting Principles (“GAAP”), our management believes that it is useful in evaluating our financial performance and our compliance with certain credit facility financial covenants. Because not all companies calculate adjusted EBITDA identically, our calculation may not be comparable to the similarly titled measure of other companies. Please read “— Summary” for reconciliations of net income (loss) attributable to our unitholders to adjusted EBITDA for each of the periods indicated.

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Distributable Cash Flow

Distributable cash flow represents adjusted EBITDA less cash interest paid (net of interest income), estimated reserve replacement expenditures and other maintenance capital expenditures. Estimated reserve replacement expenditures represent an estimate of the average quarterly reserve replacement expenditures that we will incur over the long term for the applicable period. We use estimated reserve replacement expenditures to calculate distributable cash flow instead of actual reserve replacement expenditures because our partnership agreement requires that we deduct estimated reserve replacement expenditures when calculating operating surplus. Distributable cash flow should not be considered as an alternative to net income (loss) attributable to our unitholders, income from operations, cash flows from operating activities or any other measure of performance presented in accordance with GAAP. Although distributable cash flow is not a measure of performance calculated in accordance with GAAP, our management believes distributable cash flow is a useful measure to investors because this measurement is used by many analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and to compare it with the performance of other publicly traded limited partnerships. We also compare distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Please read “— Summary” for a reconciliation of net income (loss) attributable to our unitholders to distributable cash flow for the period indicated.

Factors that Impact Our Business

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

For 2010, 2011, 2012 and 2013, we currently have long-term coal sales contracts that represent 100.0%, 102.1%, 81.7% and 55.5%, respectively, of our 2010 estimated coal sales of 8.1 million tons. During 2010, 2011, 2012 and 2013, we have committed to deliver 8.1 million tons, 8.3 million tons, 6.7 million tons and 4.5 million tons of coal, respectively, under long-term coal sales contracts. Two of our long-term coal sales contracts with the same customer contain provisions that provide for price re-openers. These price-reopeners provide for market-based adjustments to the initial contract price every three years. These contracts will terminate if we cannot agree upon a market-based price with the customer. For 2013, 1.0 million tons of coal that we have committed to deliver under our long-term coal sales contracts are subject to price re-opener provisions.

The current term of our long-term coal sales contract with American Electric Power Service Corporation, or AEP, runs through 2012 but it can be extended for two additional three-year terms if AEP gives us six months advance notice of its election to extend the contract. For each extension term, we will negotiate with AEP to agree upon a market-based price based on similar term contracts. In addition, the contract contains substantial cost pass through and inflation adjustment provisions. If AEP elects to extend this contract, we will be committed to deliver an additional 2.0 million tons in 2013, and our 2013 coal sales under long-term coal sales contracts, as a percentage of 2010 estimated coal sales, would increase to 80.1%. We are currently in negotiations with AEP to extend our contract with them. The mutual goal of the parties is to amend the contract to fix the term to run through 2018, establish future pricing that is acceptable to both parties and adjust the amounts of fixed and optional coal tonnage covered by the contract. While the outcome of these negotiations is not certain at this time, we believe that we will be able to achieve an extension with amended terms which are beneficial to us and that furthers our long-term coal sales contract strategy.

The terms of our coal sales contracts result from competitive bidding and negotiations with customers. As a result, the terms of these contracts vary by customer. However, most of our long-term coal sales contracts have full or partial cost pass through provisions or inflation adjustment provisions. For 2010, 2011, 2012 and 2013, 66.8%, 81.2%, 96.8% and 100% of the coal, respectively, that we have committed to deliver under our current long-term coal sales contracts are subject to full or partial cost pass through or inflation adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the cost of fuel, explosives and, in certain cases, labor. Inflation 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 inflation-related indices.

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A long-term coal sales contract may contain option provisions that give the customer the right to elect to purchase additional tons of coal each month during the contract term at a fixed price provided for in the contract. For example, upon 30 days advance notice, AEP may elect to purchase, at the contract price in effect at the time for all other tons, an additional 25,000 tons of coal each month under its long-term coal sales contract with us and, in addition, upon 90 days notice, it may elect to purchase, at the contract price in effect at the time for all other tons, an additional 200,000 tons of coal per half year. Our long-term coal sales contracts that provide for these option tons typically require the customer to provide us with from one to three months advance notice of an election to take these option tons. Because the price of these option tons is fixed at the contract price in effect at the time for all other tons under the terms of the contract, if our contract price is below market, we could be obligated to deliver additional coal to those customers at a price that is below the market price for coal on the date the option is exercised. For 2010, 2011, 2012 and 2013, we have outstanding option tons of 0.7 million, 0.7 million, 0.9 million and 0.9 million, respectively. If our customer does elect to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production at our mining complexes.

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

Results of Operations

Factors Affecting the Comparability of Our Results of Operations

The comparability of our results of operations is impacted by (i) the Phoenix Coal acquisition on September 30, 2009, (ii) an amendment to a long-term coal sales contract with a major customer in December 2008 and (iii) the transactions relating to the closing of our initial public offering and our $175 million credit facility in July 2010.

We acquired all of Phoenix Coal’s active surface mining operations on September 30, 2009. The financial results from this acquisition are included in our interim condensed consolidated financial statements for the three months and nine months ended September 30, 2010 but are not included in our interim condensed consolidated financial statements for the three months and nine months ended September 30, 2009.

In December 2008, we agreed with one of our major customers to amend a long-term coal sales contract. As part of this amendment, we agreed to give this customer two additional three-year term extension options with market-based price adjustments for each extension. In exchange, we received a substantial non-recurring increase in the price per ton of coal for 2009 along with inflation adjusters and certain cost pass through provisions for the remaining term of the contract, which expires at the end of 2012 unless extended at the customer’s election. This price increase contributed $2.8 million and $10.3 million to revenue and adjusted EBITDA for the three months and nine months ended September 30, 2009, respectively.

In connection with the closing of our initial public offering and our $175 million credit facility, we effected the following transactions, each of which had an impact on our results of operations for the third quarter of 2010:

• we terminated our $115 million credit facility;

• we terminated our advisory services agreement with affiliates of AIM Oxford (see Note 1 to our interim condensed consolidated financial statements); and

• we purchased $54.2 million of major mining equipment that we were leasing and additional major mining equipment.

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Factors Impacting the Third Quarter of 2010

Third quarter net income, adjusted EBITDA and distributable cash flow decreased by $4.3 million as more fully described below.

• An unexpected delay in the receipt of the Rose France 404 permit adversely impacted production by approximately 36,000 tons and increased operating costs by approximately $0.5 million, or $0.24 per ton.

• Geologic and other mining challenges at certain of the Ohio mining complexes impacted operating costs by approximately $1.3 million, or $0.68 per ton.

• Higher repair and maintenance expenses increased operating costs by approximately $1.9 million, or $1.00 per ton.

• A temporary royalty reduction from our third party leased underground reserves reduced royalty and non-coal revenue by approximately $0.6 million.

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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						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(in thousands, unaudited)
Statement of Operations Data:
Revenue:
Coal sales	$	78,127		$	56,446		$	233,454		$	176,705
Transportation revenue		9,605			7,589			28,976			23,261
Royalty and non-coal revenue		1,347			1,748			4,857			5,546
Total revenue		89,079			65,783			267,287			205,512
Costs and expenses:
Cost of coal sales (excluding DD&A, shown separately)		57,138			38,793			171,635			115,770
Cost of purchased coal		3,790			2,477			18,617			12,313
Cost of transportation		9,605			7,589			28,976			23,261
Depreciation, depletion and amortization		12,255			5,899			30,587			17,257
Selling, general and administrative expenses		4,044			3,297			10,446			9,391
Contract termination and amendment expenses, net		652			—			652			—
Total costs and expenses		87,484			58,055			260,913			177,992
Income from operations		1,595			7,728			6,374			27,520
Interest income		3			9			11			31
Interest expense		(3,662	)		(2,127	)		(7,535	)		(4,642	)
Gain from purchase of business		—			3,823			—			3,823
Net income (loss)		(2,064	)		9,433			(1,150	)		26,732
Net loss attributable to noncontrolling interest		(1,336	)		(1,636	)		(4,644	)		(4,104	)
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(3,400	)	$	7,797		$	(5,794	)	$	22,628
Other Financial Data
Adjusted EBITDA(1) (3)	$	13,680		$	12,965		$	33,625		$	41,444
Distributable cash flow(2) (3)	$	4,219

(1)

Adjusted EBITDA represents net income (loss) attributable to our unitholders before interest, taxes, DD&A, gain from purchase of business, contract termination and amendment expenses, net, amortization of below-market coal sales contracts, non-cash equity compensation expense, non-cash gain or loss on asset disposals and the change in the fair value of our future ARO. The change in our ARO represents the change over the applicable period in the fair value of our future ARO calculated on a present value basis. This amount is part of our reclamation expense in our financial statements. Although adjusted EBITDA is not a measure of performance calculated in accordance with GAAP, our management believes that it is useful in evaluating our financial performance and our compliance with certain credit facility financial covenants. Because not all companies calculate adjusted EBITDA identically, our calculation may not be comparable to the similarly titled measure of other companies.

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

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

• our ability to generate cash sufficient to pay interest on our indebtedness and to make distributions to our unitholders and our general partner;

• our compliance with certain credit facility financial covenants; and

• our ability to fund capital expenditure projects from operating cash flow.

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(2)

Distributable cash flow represents adjusted EBITDA less cash interest paid (net of interest income), estimated reserve replacement expenditures and other maintenance capital expenditures. Estimated reserve replacement expenditures represent an estimate of the average quarterly reserve replacement expenditures that we will incur over the long term for the applicable period. We use estimated reserve replacement expenditures to calculate distributable cash flow instead of actual reserve replacement expenditures because our partnership agreement requires that we deduct estimated reserve replacement expenditures when calculating operating surplus. Distributable cash flow should not be considered as an alternative to net income (loss) attributable to our unitholders, income from operations, cash flows from operating activities or any other measure of performance presented in accordance with GAAP. Although distributable cash flow is not a measure of performance calculated in accordance with GAAP, our management believes distributable cash flow is a useful measure to investors because this measurement is used by many analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and to compare it with the performance of other publicly traded limited partnerships. We also compare distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions.

(3)

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

Reconciliation of net income (loss) attributable to Oxford Resource Partners, LP unitholders to adjusted EBITDA and distributable cash flow:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
Net Income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(3,400	)	$	7,797		$	(5,794	)	$	22,628
PLUS:
Interest expense, net of interest income		3,659			2,118			7,524			4,611
Depreciation, depletion and amortization		12,255			5,899			30,587			17,257
Contract termination and amendment expenses, net		652			—			652			—
Non-cash equity-based compensation expense		230			106			686			320
Non-cash loss on asset disposals		314			700			766			908
Change in fair value of future ARO		228			168			487			(457	)
LESS:
Gain on purchase of business		—			(3,823	)		—			(3,823	)
Amortization of below-market coal sales contracts		(258	)		—			(1,283	)		—
Adjusted EBITDA	$	13,680		$	12,965		$	33,625		$	41,444
LESS:
Cash interest expense, net of interest income		(1,316	)
Estimated reserve replacement expenditures		(1,401	)
Other maintenance capital expenditures		(6,744	)
Distributable cash flow	$	4,219

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Quarter Ended September 30, 2010 Compared to Quarter Ended September 30, 2009

Overview.We reported a net loss attributable to our unitholders of $3.4 million for the three months ended September 30, 2010 compared to net income attributable to our unitholders of $7.8 million for the three months ended September 30, 2009. Our adjusted EBITDA increased to $13.7 million in the third quarter of 2010 from $13.0 million in the third quarter of 2009.

The comparability of the third quarter 2010 financial results to the same period in the prior year was affected by a number of factors. As adjusted, we would have reported a net loss of $1.4 million for the third quarter of 2010, compared to net income of $2.4 million for the third quarter of 2009. Adjusted EBITDA for 2010 was not impacted by these items and remains $13.7 million. Without these factors, adjusted EBITDA for the third quarter of 2009 would have been $10.2 million, resulting in a year-over-year increase of 34%.

These factors for each year and their impact on the net income (loss) for the three months ended September 30, 2010 and 2009 are as follows:

Three months ended September 30, 2010

• $1.8 million increase in net income resulting from the reduction in a specific reserve for a below-market coal supply contract assumed in the Phoenix Coal acquisition that was amended to reset the price to market rates starting in 2010

• $1.3 million reduction in net income resulting from the write-off of deferred financing costs associated with the early termination of our prior $115 million credit facility that resulted from the closing on our new $175 million credit facility

• $2.5 million reduction in net income resulting from contract termination expense related to the buyout of an advisory services agreement in connection with our public offering

Three months ended September 30, 2009

• $2.8 million increase in net income resulting from a non-recurring price increase with a major customer that did not carry over into 2010

• $3.8 million increase in net income resulting from the gain on the purchase of a business as a result of the Phoenix Coal acquisition

• $1.3 million reduction in net income resulting from the write-off of deferred financing costs associated with our prior $115 million credit facility which was amended to accommodate the Phoenix Coal acquisition

Coal Production.Our tons of coal produced increased 41.0% to 1.9 million tons in the third quarter of 2010 from 1.4 million tons in the third quarter of 2009. This increase was primarily due to the inclusion of 0.4 million tons of coal we produced in the third quarter of 2010 from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009, as well as an 8.4% increase in production from our Ohio mining complexes. While overall coal production increased, production was adversely affected by delays in receiving the Rose France permit at our Muhlenberg County complex, adverse geological conditions at our Plainfield mine and overall higher strip ratios. The strip ratio relates to the amount of overburden that must be removed to extract one ton of coal.

Sales Volume.Our tons of coal sold increased 40.6% to 2.0 million tons in the third quarter of 2010 from 1.4 million tons in the third quarter of 2009. This increase was primarily attributable to the 0.5 million tons of coal we sold in the third quarter of 2010 from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009.

Average Sales Price Per Ton. Our average sales price per ton decreased 1.5% to $38.61 in the third quarter of 2010 from $39.21 in the third quarter of 2009. This $0.60 per ton decrease was primarily the result of the non-recurring price increase during 2009 previously discussed, which accounted for a $1.91 per ton decrease in our average sales price per ton for the third quarter of 2010 when compared to the same quarter of the prior year. The third quarter of 2009 also included $0.6 million of contract buyout fees from a customer which had a $0.44 per ton favorable impact on our average selling price for the period. The effects of the non-recurring price increase and contract buyout fees were partially offset by a higher average sales price realized from our Ohio sales contract portfolio as lower-priced legacy contracts were replaced with higher-priced long-term sales contracts as compared to the same quarter of the prior year. This increase was partially offset by the addition of lower priced contracts acquired from Phoenix Coal. Excluding the non-recurring price increase and contract buyout fees, our average sales price per ton would have increased by $1.75 per ton.

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Coal Sales Revenue.Our coal sales revenue for the third quarter of 2010 increased by $21.7 million, or 38.4%, compared to the third quarter of 2009. This increase was primarily attributable to coal sales volumes from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009 and higher coal sales to our major utility customers served by our Ohio operations. Partially offsetting the year-over-year increase was the inclusion in the third quarter of 2009 of $2.8 million of revenue relating to the non-recurring price increase previously discussed.

Royalty and Non-Coal Revenue. Our royalty and non-coal revenue includes our royalty revenue from subleasing our underground coal reserves to a third party, revenue from the sale of limestone that we recover in connection with our coal mining operations and various fees we receive for performing services for others. Our royalty and non-coal revenue decreased to $1.3 million in the third quarter of 2010 from $1.7 million in the third quarter of 2009. This decrease was primarily attributable to a $0.6 million temporary royalty reduction from our underground coal reserves that are subleased, as mining occurred during the quarter on a small piece of property in the center of our reserves that was not subject to our royalty. In late September 2010, mining activity resumed on the property subject to our royalties.

Cost of Coal Sales (Excluding DD&A).Cost of coal sales (excluding DD&A) increased 47.3% to $57.1 million in the third quarter of 2010 from $38.8 million in the third quarter of 2009. This increase was primarily attributable to the increase of 41.0% in our tons produced and higher operating costs per ton associated with our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009. Our average cost of coal sales per ton increased by 4.4% to $29.69 in the third quarter of 2010 compared to $28.42 in the third quarter of 2009. This increase resulted in part from higher operating costs as a result of the delay of the Rose France permit. This delay adversely impacted production by 36,000 tons and increased our operating costs by approximately $0.5 million, or $0.24 per ton. In addition, the Plainfield geologic conditions and higher strip ratios impacted our operating costs by approximately $1.3 million, or $0.68 per ton, and repair and maintenance expenses were approximately $1.9 million, or $1.00 per ton, higher than expected. These items increased our operating costs by $3.7 million for the three months ended September 30, 2010. Our cost of coal sales per ton, adjusted for these items, would have been $27.77 per ton, as compared to $29.69 per ton as reported, or a decrease of $1.92 per ton.

Cost of Purchased Coal. Cost of purchased coal increased to $3.8 million in the third quarter of 2010 from $2.5 million in the third quarter of 2009. This increase was primarily attributable to a higher volume of purchases made under a long-term coal supply contract assumed in the Phoenix Coal acquisition. Our average cost of purchased coal per ton decreased by 6.4% to $31.10 in the third quarter of 2010 due to a significant portion of our purchases in that quarter being supplied under the long-term supply contract compared to a higher percentage of higher-priced spot market purchases in the third quarter of 2009.

Depreciation, Depletion and Amortization (DD&A).DD&A expense in the third quarter of 2010 was $12.3 million compared to $5.9 million in the third quarter of 2009, an increase of $6.4 million. Approximately $3.0 million of this increase related to higher DD&A expense associated with the assets we acquired in the Phoenix Coal acquisition and the remaining increase of $3.4 million related primarily to higher depreciation on equipment placed in service in late 2009 and the purchase of major mining equipment we were leasing and the purchase of additional mining equipment that was acquired with proceeds from our initial public offering and borrowings under our $175 million credit facility.

Selling, General and Administrative Expenses (SG&A).SG&A expenses for the third quarter of 2010 were $4.0 million compared to $3.3 million for the third quarter of 2009, an increase of $0.7 million. This increase was primarily due to an increase of $0.5 million in public company expenses and $0.2 million of additional administrative expenses for supporting our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009.

Contract Termination and Amendment Expenses, Net.Contract termination and amendment expenses, net for the third quarter of 2010 were $0.7 million compared to zero for the third quarter of 2009. These expenses result from the $2.5 million expense related to the termination of an advisory services agreement with certain affiliates of AIM Oxford in connection with our initial public offering, offset by a $1.8 million reduction in a specific reserve for a below-market coal supply contract assumed in the Phoenix Coal acquisition that was amended to reset the price to a market rate starting in 2010.

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Transportation Revenue and Expenses. Our transportation expenses represent the cost to transport our coal by truck or rail from our mines to our river terminals, our rail loading facilities and our customers. Our long-term coal sales contracts have these transportation costs built into the price of our coal. Our transportation revenue reflects the portion of our total revenues that is attributable to reimbursements for transportation expenses. Our transportation revenue fluctuates based on a number of factors, including the volume of coal we transport by truck or rail under those contracts and the related transportation costs. Our transportation revenue and expenses for the third quarter of 2010 increased 26.6% compared to the third quarter of 2009 due to 38.4% higher coal sales revenue.

Interest Expense. Interest expense for the third quarter of 2010 was $3.7 million compared to $2.1 million for the third quarter of 2009, an increase of $1.6 million. This increase was primarily attributable to the $1.0 million increase in the non-cash mark-to-market adjustment for the interest rate swap agreement for the third quarter of 2010 compared to the same quarter in 2009. Additionally, we experienced higher interest expense of $0.5 million under our $115 million credit facility due to higher interest rates because we elected base rate borrowings due to the anticipated termination of this credit facility rather than LIBOR borrowings and higher effective interest rates due to an amendment to accommodate the Phoenix Coal acquisition.

Net Income Attributable to Noncontrolling Interest. In 2007, we entered into a joint venture, Harrison Resources, with CONSOL Energy to mine surface coal reserves purchased from CONSOL Energy. We own 51.0% of Harrison Resources and CONSOL Energy owns the remaining 49.0% indirectly through one of its subsidiaries. We manage all of the operations of, and perform all of the contract mining and marketing services for, Harrison Resources. Net income attributable to noncontrolling interest relates to the 49.0% of Harrison Resources that we do not own. For the third quarter of 2010, the net income attributable to noncontrolling interest was $1.3 million compared to $1.6 million for the third quarter of 2009. Net income attributable to noncontrolling interest for the third quarter of 2009 includes $0.3 million which represents the noncontrolling interest’s share of payments received from a customer to terminate a long-term coal sales contract.

Distributable Cash Flow. Our distributable cash flow for the third quarter of 2010 was $4.2 million, or $3.2 million less than our pro rated minimum quarterly distribution of $7.4 million. Our distributable cash flow for the third quarter of 2010 was negatively impacted by a number of factors totaling $4.3 million. We experienced higher operating costs of $3.7 million due to a permit delay, adverse geological conditions and increased repair and maintenance costs as discussed in Cost of Coal Sales. Also royalty revenue decreased $0.6 million related to our sublease as described in Royalty and Non-Coal Revenue.

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Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009

Overview.We reported a net loss attributable to our unitholders of $5.8 million for the first nine months of 2010 compared to net income attributable to our unitholders of $22.6 million for the first nine months of 2009. Our adjusted EBITDA decreased to $33.6 million in the first nine months of 2010 from $41.4 million in the first nine months of 2009. Our performance in the first nine months of 2010 reflected the contribution from the assets that we acquired in western Kentucky from Phoenix Coal on September 30, 2009 as well as the impact of the purchase of leased equipment and additional equipment with the proceeds from our initial public offering and borrowings under our $175 million credit facility. Additionally, for the first nine months of 2010 our results related to our Ohio operations did not include a non-recurring price increase which positively impacted our net income and adjusted EBITDA for the first nine months of 2009 by $10.3 million. Excluding the non-recurring price increase, results for the first nine months of 2009 would have resulted in net income attributable to our unitholders of $12.3 million and adjusted EBITDA of $31.1 million.

Coal Production.Our tons of coal produced increased 37.8% to 5.6 million tons in the first nine months of 2010 from 4.0 million tons in the first nine months of 2009. This increase was primarily due to the inclusion of 1.2 million tons of coal we produced in the first nine months of 2010 from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009. Our tons of coal produced also benefited from an 8.1% increase in production from our Ohio mining complexes.

Sales Volume.Our tons of coal sold increased 43.3% to 6.1 million tons in the first nine months of 2010 from 4.3 million tons in the first nine months of 2009. This increase was primarily attributable to the 1.2 million tons of coal we sold in the first nine months of 2010 from our Muhlenberg County complex that we acquired and 0.5 million tons of coal purchased under a supply contract assumed from Phoenix Coal on September 30, 2009.

Average Sales Price Per Ton.Our average sales price per ton decreased 7.8% to $38.09 in the first nine months of 2010 from $41.31 in the first nine months of 2009. This $3.22 per ton decrease was primarily the result of the non-recurring price increase during 2009 described above, which accounted for a $2.41 per ton decrease in our average sales price per ton for the first nine months of 2010 when compared to the first nine months of the prior year. The effects of this non-recurring price increase and contract buyout fees were partially offset by the favorable impact of higher average sales prices realized from our Ohio sales contract portfolio as lower priced legacy contracts were replaced with higher priced long-term sales contracts as compared to the same period of the prior year. The third quarter of 2009 also included $1.4 million of contract buyout fees from a customer which had a $0.34 per ton favorable impact on our average selling price for the period. Excluding the non-recurring price increase and contract buyout fees, our average sales price per ton would have decreased by $0.47, due to the effect of the lower-priced legacy coal sales contracts that we assumed in the Phoenix Coal acquisition.

Coal Sales Revenue. Our coal sales revenue for the first nine months of 2010 increased by $56.7 million, or 32.1%, compared to the first nine months of 2009. This increase was primarily attributable to coal sales from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009. However, this increase was partially offset by the inclusion in the first nine months of 2009 of $10.3 million of revenue relating to the non-recurring price increase and $1.4 million of contract buyout fees from a customer previously discussed.

Royalty and Non-Coal Revenue. Our royalty and non-coal revenue decreased to $4.9 million in the first nine months of 2010 from $5.5 million in the first nine months of 2009. This decline was primarily attributable to a decrease of $1.7 million in royalty revenue in the first nine months of 2010 associated with our underground coal reserves that are leased to a third party, partially offset by an increase in fees for providing earth moving services of $0.7 million and one-time fees of $0.2 million relating to a barge handling contract.

Cost of Coal Sales (Excluding DD&A).Cost of coal sales (excluding DD&A) increased 48.3% to $171.6 million in the first nine months of 2010 from $115.8 million in the first nine months of 2009. This increase was primarily attributable to the increase of 37.8% in our tons produced and higher operating costs per ton associated with our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009. Our average cost of coal sales per ton increased by 7.6% to $30.82 in the first nine months of 2010 compared to $28.66 in the first nine months of 2009. With respect to our newly-acquired Muhlenberg County complex, we closed two mines that were fully depleted and opened a new mine that began producing in May 2010. The closure of the two mines and associated reclamation costs, together with opening a new mine and weather-related issues that disrupted production, negatively impacted our per ton operating costs. Excluding our Muhlenberg County complex, our cost of coal sales per ton would have increased by approximately 2.2% during the first nine months of 2010 as compared to the same period in the prior year. This increase resulted primarily from the Rose France permit delay, unanticipated geological conditions, higher strip ratios and higher repair and maintenance expenses at certain of our Ohio mining complexes.

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Cost of Purchased Coal. Cost of purchased coal increased to $18.6 million in the first nine months of 2010 from $12.3 million in the first nine months of 2009. This increase was primarily attributable to higher purchases made under a long-term supply contract assumed in the Phoenix Coal acquisition. Our average cost of purchased coal per ton decreased by 24.9% to $30.17 in the first nine months of 2010 due to a significant portion of our purchases in that period being acquired under the lower-priced supply contract compared to a higher percentage of higher-priced spot market purchases in the first nine months of 2009.

Depreciation, Depletion and Amortization (DD&A).DD&A expense in the first nine months of 2010 was $30.6 million compared to $17.3 million in the first nine months of 2009, an increase of $13.3 million. Approximately $7.0 million of this increase relates to higher DD&A expense associated with assets we acquired in the Phoenix Coal acquisition and the remaining increase of $6.3 million relates primarily to depreciation on equipment placed in service in late 2009 and the first nine months of 2010. A substantial portion of this equipment was acquired with proceeds from our initial public offering and draws under our $175 million credit facility.

Selling, General and Administrative Expenses (SG&A).SG&A expenses for the first nine months of 2010 were $10.4 million compared to $9.4 million for the first nine months of 2009, an increase of $1.0 million. This increase was primarily due to $0.7 million of additional administrative expenses for supporting our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009 combined with an increase of $0.6 million in public company expenses offset by a reduction of $0.3 million in professional fees.

Contract Termination and Amendment Expenses, Net.Contract termination and amendment expenses, net for the first nine months of 2010 were $0.7 million compared to zero for the first nine months of 2009. These expenses resulted from the $2.5 million expense related to the termination of an advisory services agreement with certain affiliates of AIM Oxford in connection with our initial public offering, offset by a $1.8 million reduction in a specific reserve for a below-market coal supply contract assumed in the Phoenix Coal acquisition that was amended to reset the price to a market rate starting in 2010.

Transportation Revenue and Expenses.Our transportation revenue and expenses for the first nine months of 2010 increased 24.6% compared to the first nine months of 2009 due to higher coal sales.

Interest Expense. Interest expense for the first nine months of 2010 was $7.5 million compared to $4.6 million for the first nine months of 2009, an increase of $2.9 million. This increase was primarily attributable to higher effective interest rates in the first nine months of 2010 as a result of an amendment to our $115 million credit facility in September 2009 together with higher borrowings outstanding during the first nine months of 2010 both due to the debt that we incurred to acquire the Phoenix Coal assets. In addition, the non-cash mark-to-market adjustment for the interest rate swap agreement increased interest expense by $2.0 million for the first nine months of 2010 compared to the same period in 2009.

Net Income Attributable to Noncontrolling Interest.For the first nine months of 2010, the net income attributable to noncontrolling interest was $4.6 million compared to $4.1 million for the first nine months of 2009. This increase of $0.5 million was primarily attributable to an increase in tons of coal sold by Harrison Resources in the first nine months of 2010 compared to the first nine months of 2009. Net income attributable to noncontrolling interest for the first nine months of 2009 included $0.6 million which represents the noncontrolling interest’s share of payments received from a customer to terminate a long-term coal sales contract.

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Liquidity and Capital Resources

Our business is capital intensive and requires substantial capital expenditures for purchasing, upgrading and maintaining equipment used in mining our reserves and for acquiring reserves, as well as complying with applicable environmental laws and regulations.

The principal indicators of our liquidity at September 30, 2010 were our cash on hand and availability under our $175 million credit facility. On July 19, 2010 and concurrent with the closing of our initial public offering, we closed on our $175 million credit facility, which is comprised of a $60 million term loan and a $115 million revolving credit facility. As of September 30, 2010, we had unused capacity under our $175 million credit facility of $82.6 million with $43.1 available for borrowing. Therefore, our available liquidity as of September 30, 2010 was $44.9 million, which consisted of $1.8 million in cash on hand and the $43.1 million of borrowing availability under our $175 million credit facility.

Going forward, we expect our sources of liquidity to include:

• our working capital;

• cash generated from operations;

• borrowings available under our $175 million credit facility;

• issuance of additional partnership units; and

• debt offerings.

We believe that cash generated from these sources will be sufficient to meet our liquidity needs over the next twelve months, including operating expenditures, debt service obligations, contingencies and anticipated capital expenditures, and to fund our quarterly distributions to unitholders.

Cash Flows

The following table reflects cash flows for the applicable periods:

	Nine Months Ended
	September 30,
	2010			2009
Net cash provided by (used in)
Operating activities	$	28,099		$	31,059
Investing activities		(76,939	)		(42,832	)
Financing activities		47,307			8,361

Net cash provided by operating activities was $28.1 million for the first nine months of 2010, a decrease of $3.0 million from net cash provided by operating activities of $31.1 million for the first nine months of 2009. This decrease is primarily due to lower net income attributable to unitholders partially offset by higher non-cash adjustments, primarily DD&A, and favorable working capital changes for the first nine months of 2010. Additionally, our net income attributable to our unitholders for the first nine months of 2009 included approximately $10.3 million of revenue related to a non-recurring price increase.

Net cash used in investing activities was $76.9 million for the first nine months of 2010 compared to $42.8 million for the first nine months of 2009. This $34.1 million increase was primarily attributable to the purchases of major mining equipment and the buy-out of equipment operating leases in the first nine months of 2010 compared to the first nine months of 2009. We utilized the net proceeds of our initial public offering and borrowings under our $175 million credit facility to fund these transactions. Cash used in investing activities for the first nine months of 2009 included the acquisition of the Phoenix Coal assets.

Net cash provided by financing activities was $47.3 million for the first nine months of 2010 compared to net cash provided by financing activities of $8.4 million for the first nine months of 2009. This change of $38.9 million was primarily attributable to the net proceeds from our initial public offering and borrowings under our new $175 million credit facility during the third quarter of 2010.

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Credit Facility

In connection with our initial public offering, we paid off the amounts outstanding under our $115 million credit facility and we entered into our $175 million credit facility. Our $175 million credit facility provides for a $60 million term loan and a $115 million revolving credit facility. As of September 30, 2010, we had borrowings of $83.5 million outstanding under our $175 million credit facility, consisting of a $58.5 million term loan and borrowings of $25 million on the revolving credit facility.

We also use our $175 million credit facility to collateralize letters of credit related to surety bonds securing our reclamation obligations. As of September 30, 2010, we had letters of credit outstanding in support of these surety bonds of $7.4 million.

We used a portion of the borrowings under our $175 million credit facility and a portion of our initial public offering proceeds to purchase all of the equipment we had under operating leases, which reduced operating lease expenses beginning in the third quarter of 2010.

Capital Expenditures

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

Off-Balance Sheet Arrangements

Federal and state laws require us to secure certain long-term obligations such as mine closure and reclamation costs and other obligations. We typically secure these obligations by using surety bonds, an off-balance sheet instrument, and we typically use bank letters of credit to secure our surety bonding obligations. As of September 30, 2010, we had outstanding $36.0 million in surety bonds and $14,000 in cash bonds to secure certain reclamation obligations. Additionally, as of September 30, 2010, we had outstanding letters of credit in support of these surety bonds of $7.4 million. Further, as of September 30, 2010, we had outstanding certain road bonds of $0.6 million and performance bonds of $7.5 million that required no letters of credit as security. Our management believes these bonds and letters of credit will expire without any claims or payments thereon and thus any subrogation or other rights with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.

Seasonality

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

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Critical Accounting Policies

“Management’s Discussion and Analysis of Financial Condition and Results of Operations” discusses our interim condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these interim condensed consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the interim condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. A summary of our significant accounting policies is included in the Notes to Condensed Consolidated Financial Statements (Unaudited) included in the Prospectus.

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

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

Use of Estimates

In order to prepare financial statements in conformity with GAAP, we are required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities (if any) at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. The most significant areas requiring the use of management estimates and assumptions relate to units-of-production amortization calculations, asset retirement obligations, useful lives for depreciation of fixed assets, fair value of derivative financial instruments and estimates of fair values for asset impairment purposes. The estimates and assumptions that we use are based upon our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.

Allowance for Doubtful Accounts

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

Inventory

Inventory consists of coal that has been completely uncovered or that has been removed from the pit and stockpiled for crushing, washing, or shipment to customers. Inventory also consists of supplies, spare parts and fuel. Inventory is valued at the lower of average cost or market. The cost of coal inventory includes certain operating expenses and operating overhead. The stripping costs incurred in the production phase of a mine are variable production costs included in the costs of the inventory produced during the period that the stripping costs were incurred.

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Property, Plant and Equipment

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

Buildings and tipple	25-39 years
Machinery and equipment	7-15 years
Vehicles	5-7 years
Furniture and fixtures	3-7 years
Railroad siding	7 years

We acquire our reserves through purchases in fee or leases of coal reserves. Coal reserves were recorded at fair value under purchase accounting at our formation date of August 24, 2007 and again as part of the Phoenix Coal acquisition, to the extent of the reserves acquired from Phoenix Coal. We deplete our reserves using the units-of-production method, without residual value, on the basis of tonnage mined in relation to estimated recoverable tonnage. We believe that the carrying value of these reserves will be recovered. Residual surface values are classified as land and not depleted.

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

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

Financial Instruments and Derivative Financial Instruments

Our financial instruments include cash and cash equivalents including restricted cash, accounts receivable, accounts payable, fixed and variable rate debt, an interest rate swap agreement and previously an interest rate cap agreement. We account for derivative financial instruments which includes our interest rate swap agreement and an interest rate cap agreement by recognizing derivative instruments as either assets or liabilities in the balance sheet at fair value and recognizing the resulting gains or losses as adjustments to earnings as interest expense. We do not hold or issue derivative financial instruments for trading or speculative purposes.

We manage interest costs using a mixture of fixed rate and variable rate debt. Additionally, we have entered into an interest rate swap agreement whereby we have agreed to exchange with a counterparty, at specified intervals, the difference between fixed and variable interest amounts calculated by reference to an agreed upon notional principal amount. The agreement specifies a minimum interest rate of 1%. We also use an interest rate cap agreement to partially reduce risks related to floating rate financing agreements that are subject to changes in the market rate of interest. Terms of the interest rate cap agreement required the counter party to pay the variable interest rate only when the London Interbank Offered Rate (“LIBOR”) exceeded the stated rate.

We did not elect hedge accounting treatment for our interest rate swap or interest rate cap agreements. Changes in the fair value of these derivatives are recorded in earnings as interest expense. We measure our derivatives (interest rate swap agreement or interest rate cap agreement) at fair value on a recurring basis using significant observable inputs, which are Level 2 inputs as defined in the fair value hierarchy. (See Note 6 and Note 7 to our interim condensed consolidated financial statements.)

Our risk management policy is to purchase up to 75% of our unhedged diesel fuel gallons on fixed price forward contracts. These contracts meet the normal purchases and sales exclusion and therefore are not accounted for as derivatives. We take physical delivery of all the fuel under these forward contracts and such contracts have a term of one year or less.

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Advance Royalties

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

Long-Lived Assets

We follow authoritative guidance that requires projected future cash flows from use and disposition of assets to be compared with the carrying amounts of those assets when impairment indicators are present. When the sum of projected cash flows is less than the carrying amount, impairment losses are indicated. If the fair value of the assets is less than the carrying amount of the assets, an impairment loss is recognized. In determining such impairment losses, discounted cash flows or asset appraisals are utilized to determine the fair value of the assets being evaluated. Also, in certain situations, expected mine lives are shortened because of changes to planned operations. When that occurs and it is determined that the mine’s underlying costs are not recoverable in the future, reclamation and mine closure obligations are accelerated. To the extent it is determined that an asset’s carrying value will not be recoverable during a shorter mine life, the asset is written down to its recoverable value. No impairment losses were recognized during any of the years or periods presented.

Identifiable Intangible Assets and Liabilities

Identifiable intangible assets are recorded in other assets in the accompanying condensed consolidated balance sheets. We capitalize costs incurred in connection with borrowings or the establishment of credit facilities. These costs are amortized as an adjustment to interest expense over the life of the borrowings or term of the credit facility using the interest method.

We also have recorded intangible assets and liabilities at fair value associated with certain customer relationships and below-market coal sales contracts, respectively. These balances arose from the use of purchase accounting for business combinations and so the assets and liabilities were adjusted to fair value. These intangible assets are being amortized over their expected useful lives.

Asset Retirement Obligations

Our asset retirement obligations, or AROs, arise from the Surface Mining Control and Reclamation Act of 1977 (SMCRA) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Our AROs are recorded initially at fair value. It has been our practice, and we anticipate that it will continue to be our practice, to perform a substantial portion of the reclamation work using internal resources. Hence, the estimated costs used in determining the carrying amount of our AROs may exceed the amounts that are eventually expended for reclamation activities if the reclamation work is performed using internal resources.

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

Accounting for AROs requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. AROs primarily relate to the closure of mines and the reclamation of land upon exhaustion of coal reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the mine closing and reclamation liabilities. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted, risk-free interest rate.

Accounting for AROs also requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, and the accretion to be recognized in reclamation expense will escalate over the life of the producing assets, typically as production declines.

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When the liability is initially recorded for the costs to open a new mine site, the offset is recorded to the producing mine asset. Over time, the ARO liability is accreted to its present value, and the capitalized cost is depreciated over the units-of-production for the related mine. The liability is also increased as additional land is disturbed during the mining process. The timeline between digging the mining pit and extracting the coal is relatively short; therefore, much of the liability created for active mining is expensed within a month or so of establishment because the related coal has been extracted. If the assumptions used to estimate the ARO do not materialize as expected or regulatory changes occur, reclamation costs or obligations to perform reclamation and mine closure activities could be materially different than currently estimated. We review our entire reclamation liability at least annually and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from revisions to cost estimates and the quantity of disturbed acreage during the current year.

We measure our AROs at fair value on a recurring basis using significant unobservable inputs, which are Level 3 inputs as defined in the fair value hierarchy.

Revenue Recognition

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

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

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

Coal Sales Contracts

Our below-market coal sales contracts represent those contracts where the prevailing market price for coal specified in the contract was in excess of the contract price. The fair value was based on discounted cash flows resulting from the difference between the below-market contract price and the prevailing market price at the date of acquisition. The difference between the below-market contract cash flows and the cash flows at the prevailing market price is amortized into coal sales on the basis of tons shipped over the term of the contract.

Equity-Based Compensation

We account for equity-based awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Equity-based compensation expense is recorded based upon the fair value of the award at grant date. Such costs are recognized as expense on a straight-line basis over the corresponding vesting period. The fair value of our long-term incentive plan units is determined based on the market value of our common units which are traded on the New York Stock Exchange.

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Earnings Per Unit

For purposes of our earnings per unit calculation, we have applied the two class method. The classes of units are our limited partner 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 have been separated into common and subordinated units.

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 to limited partners is adjusted to include LTIP units that have not yet vested and that will be issued as common units upon vesting. In years of a net loss attributable to limited partners, these unvested LTIP units are not included in the earnings per unit calculation.

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risks

We sell most of the coal we produce under long-term coal sales contracts. Historically, we have principally managed the commodity price risks from our coal sales by entering into long-term coal sales contracts of varying terms and durations, rather than through the use of derivative instruments.

We believe that the price risks associated with our diesel fuel purchases is significant. Taking into account full or partial diesel fuel cost pass through provisions in our long-term coal sales contracts and our fixed price forward contracts for delivery of diesel fuel, we estimate that a hypothetical increase of $0.10 per gallon for diesel fuel would have reduced net income attributable to our unitholders by $0.1 million for the third quarter of 2010.

Interest Rate Risks

We are exposed to interest rate risks as borrowings under our $175 million credit facility are at variable rates. At September 30, 2010, the value of the interest rate cap was approximately zero. On August 2, 2010, we entered into an interest rate swap agreement that had an original notional principal amount of $50 million and a maturity of January 31, 2013. The notional principal amount declines over the term of the interest rate swap agreement at a rate of $1.5 million each quarter which corresponds to our required principal payments. Under the interest rate swap agreement, we pay interest monthly at a fixed rate of 1.39% per annum and receive interest monthly at a variable rate equal to LIBOR (with a 1% floor) based on the notional principal amount. The interest rate swap agreement was effective August 9, 2010. The derivative liability is recorded in other liabilities and increased by $0.3 million in the third quarter of 2010.

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 U.S. Securities and Exchange Commission (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, 2010. This evaluation was performed by our management, with the participation of our Chief Executive Officer and Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective to ensure that the Partnership is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods, and during the quarterly period ended September 30, 2010 there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

Item 2. Unregistered Sales Of Equity Securities And Use Of Proceeds

On July 19, 2010, in connection with the closing of our initial public offering, our general partner contributed 175,000 of our common units to us in exchange for 175,000 general partner units in order to maintain its 2.0% general partnership interest in us. This transaction was exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended.

Use of Proceeds

On July 6, 2010, we commenced the initial public offering of our common units pursuant to our Registration Statement on Form S-1, Commission File No. 333-165662 (the “Registration Statement”), which was declared effective by the SEC on July 12, 2010. Barclay’s Capital Inc. and Citigroup Markets Inc. acted as representatives of the underwriters and as joint book-running managers of the offering.

Upon closing of our initial public offering on July 19, 2010, we issued 8,750,000 of the common units that were registered at a price per unit of $18.50 (with an additional 1,312,500 common units that were registered being reserved for issuance upon the exercise of the underwriters’ over-allotment option). The Registration Statement registered securities with an aggregate offering price of $250 million. The aggregate offering amount of the securities sold pursuant to the Registration Statement was $161.9 million. In our initial public offering, we granted the underwriters a 30 day option to purchase up to 1,312,500 additional units. This option was not exercised.

After deducting underwriting discounts and commissions of approximately $10.5 million paid to the underwriters, actual offering expenses of approximately $6.1 million and a structuring fee of approximately $0.8 million, the net proceeds from our initial public offering were approximately $144.5 million. We used all of the net offering proceeds from our initial public offering for the uses described in the final prospectus filed with the SEC pursuant to Rule 424(b) on July 15, 2010. These uses included the following:

• to repay in full the outstanding balance under our $115 million credit facility;

• to distribute approximately $18.3 million to C&T Coal in respect of its limited partner interest in us;

• to distribute approximately $0.6 million to the participants in our long-term incentive plan that hold our common units in respect of their limited partner interests in us;

• to terminate our advisory services agreement with affiliates of AIM Oxford for a payment of approximately $2.5 million; and

• to purchase leased and additional major mining equipment for approximately $22.1 million.

We did not pay, directly or indirectly, any offering expenses to any of our directors or officers or persons owning ten percent or more of any class of our equity securities or to any other affiliates.

Item 3. Defaults Upon Senior Securities

None.

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Item 4. [Removed And Reserved]

Item 5. Other Information

Mine Safety

Coal mining operations are subject to stringent health and safety standards, including pursuant to the Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977, or the Mine Act. In addition to federal regulatory programs, all of the states in which we operate have programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is among the most comprehensive systems for protection of employee health and safety affecting any segment of U.S. industry. The Mine Act requires mandatory inspections of surface and underground coal mines and requires the issuance of citations or orders for the violation of a mandatory health and safety standard. A civil penalty must be assessed for each citation or order issued. Serious violations of mandatory health and safety standards may result in the issuance of an order requiring the immediate withdrawal of miners from the mine or shutting down a mine or any section of a mine or any piece of mine equipment. The Mine Act also imposes criminal liability for corporate operators who knowingly or willfully violate a mandatory health and safety standard or order and provides that civil and criminal penalties may be assessed against individual agents, officers and directors who knowingly or willfully violate a mandatory health and safety standard or order. In addition, criminal liability may be imposed against any person for knowingly falsifying records required to be kept under the Mine Act and standards.

In 2010, in response to underground mine accidents, Congress expanded mine safety disclosure requirements pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Act. In our third quarter, we received at least four citations from the Mine Safety and Health Administration, or MSHA, for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under Section 104 of the Mine Act from the following coal mines and MSHA ID numbers, respectively, as follows: one at Hall’s Creek Mine, #15-18134; one at K.O. Mine, #15-19303; one at Rice #1 Mine, #33-00965; and one at Rice #2 Mine, #33-03770. The total dollar value of the proposed assessments from MSHA under the Mine Act for these citations is $1,622.

In our third quarter, we did not receive any citations, orders or immediate danger orders pursuant to Section 104(b), Section 104(d) or Section 107(a) of the Mine Act, and there have not been any flagrant violations under Section 110(b)(2) of the Mine Act or mining-related fatalities. In addition, we did not receive any written notice from MSHA of a pattern of violations, or the potential to have such a pattern, of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under Section 104(e) of the Mine Act. The legal actions listed below are pending before the Federal Mine Safety and Health Review Commission, or the Commission.

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Docket No./	Civil
Mine/MSHA ID#	Penalty		Status
LAKE 2008-383 Oxford Mining #3 33-04336	$	1,400	Petition for civil penalty assessment for a miner not wearing a hard hat outside of the operating cab of his equipment. The Petition was served on June 6, 2008 and timely answered on July 3, 2008.
LAKE 2009-381-M Oxford Mining #2 33-04213	$	920	Petition for civil penalty assessment for two citations regarding brake lights on mobile equipment. The proposed civil penalty assessment became a final order on January 16, 2009, but the notice of contest was mailed to an incorrect address. A Motion to Reopen the Penalty Assessment was filed on March 19, 2009 and unopposed by the Secretary of Labor. The Commission has approved the Motion, and the matter has been assigned to Administrative Law Judge Barbour pending issuance of a Petition for Penalty Assessment.
LAKE 2010 576 Snyder Mine 33-04414	$	946	Petition for civil penalty assessment for a rock truck operator failing to maintain control of the vehicle and crashing into the highwall; the driver sustained a broken leg. The Petition was served on May 5, 2010 and timely answered on June 7, 2010. The case has been assigned to an Administrative Law Judge. The parties have been ordered to contact each other’s representative to engage in settlement discussions and, if the parties are unable to settle the case, to schedule a conference call with the Commission and all parties prior to November 29, 2010.
LAKE 2010 577 Snyder Mine 33-04414	$	207	Petition for civil penalty assessment for a dump truck that did not give an audible sound when reverse was engaged when tested. The Petition was served on May 6, 2010 and timely answered on June 7, 2010. The case has been assigned to an Administrative Law Judge. The parties have been ordered to contact each other’s representative to engage in settlement discussions and, if the parties are unable to settle the case, to schedule a conference call with the Commission and all parties prior to November 29, 2010.

Item 6. Exhibits

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

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SIGNATURES

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

Date: November 9, 2010

OXFORD RESOURCE PARTNERS, LP
By:	OXFORD RESOURCES GP, LLC, its general partner
By:	/s/ CHARLES C. UNGUREAN
	Charles C. Ungurean
	President and Chief Executive Officer (Principal Executive Officer)
By:	/s/ JEFFREY M. GUTMAN
	Jeffrey M. Gutman
	Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

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EXHIBIT INDEX

Exhibit
Number			Exhibit Description
	3.1		Certificate of Limited Partnership of Oxford Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
	3.2		Third Amended and Restated Agreement of Limited Partnership of Oxford Resource Partners, LP dated July 19, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
	3.3		Certificate of Formation of Oxford Resources GP, LLC (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	3.4		Second Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC dated July 19, 2010 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
	10.1	A	Credit Agreement dated as of July 6, 2010 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
	10.1	B	First Amendment to Credit Agreement and Limited Waiver dated as of July 15, 2010 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
	10.3	#	Employment Agreement between Oxford Resources GP, LLC and Michael B. Gardner (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010)
	10.4	#	Employment Agreement between Oxford Resources GP, LLC and Jeffrey M. Gutman (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010)
	10.5	#	Employment Agreement between Oxford Resources GP, LLC and Gregory J. Honish (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010)
	10.6	#	Employment Agreement between Oxford Resources GP, LLC and Charles C. Ungurean (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010)
	10.7	#	Employment Agreement between Oxford Resources GP, LLC and Thomas T. Ungurean (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) for the quarter ended June 30, 2010)
	10.12	#	Oxford Resource Partners, LP Amended and Restated Long-Term Incentive Plan dated July 19, 2010 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)

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Exhibit
Number			Exhibit Description
	10.20	*#	Engagement letter agreement dated August 1, 2010 between Oxford Resources GP, LLC and Squire, Sanders & Dempsey L.L.P. relating to representation services provided principally by and under the direction of Daniel M. Maher
	10.21	*#	Employment Agreement between Oxford Resources GP, LLC and Daniel M. Maher dated August 1, 2010
	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, 2010 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31.2	*	Certification of Jeffrey M. Gutman, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the September 30, 2010 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, 2010 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2	*	Certification of Jeffrey M. Gutman, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the September 30, 2010 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*	Filed herewith (or furnished, in the case of Exhibits 32.1 and 32.2).
#	Compensatory plan or arrangement.

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