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

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

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

(614) 643-0314
(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. YES þ NO o

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

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

Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o
				(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). YES o NO þ

As of May 4, 2011, 10,352,519 common units and 10,280,380 subordinated units were outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “OXF.”

 

 

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)			1
Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010			1
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2011 and 2010			2
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2010			3
Condensed Consolidated Statements of Partners’ Capital for the Three Months Ended March 31, 2011 and 2010			4
Notes to Condensed Consolidated Financial Statements			5
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			16
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			34
ITEM 4. CONTROLS AND PROCEDURES			34
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS			35
ITEM 1A. RISK FACTORS			35
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			35
ITEM 3. DEFAULTS UPON SENIOR SECURITIES			35
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS			35
ITEM 5. OTHER INFORMATION			37
ITEM 6. EXHIBITS			37
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1.		Condensed Consolidated Financial Statements (Unaudited)

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

		March 31,				December 31,
		2011				2010
ASSETS
Cash and cash equivalents		$	3,740			$	889
Trade accounts receivable			30,330				28,108
Inventory			15,432				12,640
Advance royalties			939				924
Prepaid expenses and other current assets			931				1,023
Total current assets			51,372				43,584
Property, plant and equipment, net			200,012				198,694
Advance royalties			7,503				7,693
Other long-term assets			11,333				11,100
Total assets		$	270,220			$	261,071
LIABILITIES
Current maturities of long-term debt		$	11,355			$	7,249
Accounts payable			34,001				26,074
Asset retirement obligations — current portion			8,476				6,450
Deferred revenue — current portion			780				780
Accrued taxes other than income taxes			1,744				1,643
Accrued payroll and related expenses			2,057				2,625
Other current liabilities			3,134				2,952
Total current liabilities			61,547				47,773
Long-term debt			101,025				95,737
Asset retirement obligations			7,691				6,537
Other long-term liabilities			2,083				2,261
Total liabilities			172,346				152,308
Commitments and Contingencies (Note 10)
PARTNERS’ CAPITAL
Limited Partner unitholders (20,632,899 and 20,610,983 units outstanding as of March 31, 2011 and December 31, 2010, respectively)			94,908				105,684
General Partner unitholder (420,853 and 420,633 units outstanding as of March 31, 2011 and December 31, 2010, respectively)			(277	)			(63	)
Total Oxford Resource Partners, LP Capital			94,631				105,621
Noncontrolling interest			3,243				3,142
Total partners’ capital			97,874				108,763
Total liabilities and partners’ capital		$	270,220			$	261,071

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

		Three Months Ended
		March 31,
		2011				2010
Revenue
Coal sales		$	83,304			$	76,756
Transportation revenue			10,442				9,530
Royalty and non-coal revenue			2,320				1,774
Total revenue			96,066				88,060
Costs and expenses
Cost of coal sales (excluding depreciation, depletion and amortization, shown separately)			62,617				55,186
Cost of purchased coal			5,127				7,859
Cost of transportation			10,442				9,530
Depreciation, depletion and amortization			12,111				8,777
Selling, general and administrative expenses			3,966				3,535
Total costs and expenses			94,263				84,887
Income from operations			1,803				3,173
Interest income			1				1
Interest expense			(2,003	)			(1,833	)
Net income (loss)			(199	)			1,341
Less: net income attributable to noncontrolling interest			(1,571	)			(1,628	)
Net loss attributable to Oxford Resource Partners, LP unitholders		$	(1,770	)		$	(287	)
Net loss allocated to general partner		$	(35	)		$	(6	)
Net loss allocated to limited partners		$	(1,735	)		$	(281	)
Net loss per limited partner unit:
Basic		$	(0.08	)		$	(0.02	)
Dilutive		$	(0.08	)		$	(0.02	)
Weighted average number of limited partner units outstanding:
Basic			20,621,793				11,973,402
Dilutive			20,621,793				11,973,402
Distributions paid per limited partner unit		$	0.4375			$	0.2300

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

		Three Months Ended
		March 31,
		2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss attributable to Oxford Resource Partners, LP unitholders		$	(1,770	)		$	(287	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			12,111				8,777
Interest rate swap or rate cap adjustment to market			(1	)			33
Loan fee amortization			319				168
Non-cash equity compensation expense			364				304
Advanced royalty recoupment			309				600
Loss on disposal of property and equipment			166				175
Noncontrolling interest in subsidiary earnings			1,571				1,628
Increase in assets:
Accounts receivable			(2,222	)			(5,435	)
Inventory			(2,146	)			(1,589	)
Other assets			(189	)			(3,068	)
Increase (decrease) in liabilities:
Accounts payable and other liabilities			7,906				9,457
Asset retirement obligations			1,045				293
Provision for below-market contracts and deferred revenue			(244	)			(2,715	)
Net cash provided by operating activities			17,219				8,341
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment			(10,387	)			(4,995	)
Purchase of mineral rights and land			(1,035	)			(2,116	)
Mine development costs			(1,196	)			(775	)
Royalty advances			(134	)			(144	)
Insurance proceeds			—				1,223
Proceeds from sale of property and equipment			—				25
Change in restricted cash			(339	)			(3,498	)
Net cash used in investing activities			(13,091	)			(10,280	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on borrowings			(1,606	)			(344	)
Advances on line of credit			11,000				3,000
Capital contributions from partners			5				25
Distributions to noncontrolling interest			(1,470	)			—
Distributions to partners			(9,206	)			(2,818	)
Net cash used in financing activities			(1,277	)			(137	)
Net increase (decrease) in cash			2,851				(2,076	)
CASH AND CASH EQUIVALENTS, beginning of period			889				3,366
CASH AND CASH EQUIVALENTS, end of period		$	3,740			$	1,290

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

		Limited Partner																								Non-				Total
		Common								Subordinated								General Partner								controlling				Partners’
		Units				Capital				Units				Capital				Units				Capital				Interest				Capital
Balance at December 31, 2009											11,964,547			$	53,960				242,023			$	1,085			$	2,067			$	57,112
Net income															(281	)							(6	)			1,628				1,341
Partners’ contributions																			2,584				25								25
Partners’ distributions															(2,762	)							(56	)							(2,818	)
Equity-based compensation															304																304
Issuance of units to Long-Term Incentive Plan participants upon vesting											21,201				(101	)															(101	)
Balance at March 31, 2010			—			$	—				11,985,748			$	51,120				244,607			$	1,048			$	3,695			$	55,863
Balance at December 31, 2010			10,330,603			$	145,592				10,280,380			$	(39,908	)			420,633			$	(63	)		$	3,142			$	108,763
Net income (loss)							(871	)							(864	)							(35	)			1,571				(199	)
Partners’ contributions																			220				5								5
Partners’ distributions							(4,527	)							(4,495	)							(184	)			(1,470	)			(10,676	)
Equity-based compensation							364																								364
Issuance of units to Long -Term Incentive Plan participants upon vesting			21,916				(383	)																							(383	)
Balance at March 31, 2011			10,352,519			$	140,175				10,280,380			$	(45,267	)			420,853			$	(277	)		$	3,243			$	97,874

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for 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 condensed consolidated financial statements reflect all adjustments necessary for a fair presentation of the results of operations and financial position for such periods. All such adjustments reflected in the condensed consolidated financial statements are considered to be of a normal recurring nature. The results of operations for any interim period are not necessarily indicative of results for the full year. Accordingly, these condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2010 (the “Annual Report”) and filed with the U.S. Securities and Exchange Commission (the “SEC”).

NOTE 1: ORGANIZATION AND PRESENTATION

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

	•		“We,” “us,” “our,” or the “Partnership” means the business and operations of Oxford Resource Partners, LP, the parent entity, as well as its consolidated subsidiaries.
	•		“ORLP” means Oxford Resource Partners, LP, individually as the parent entity, and not on a consolidated basis.
	•		Our “GP” means Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP.

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 one of our limited partners, C&T Coal, Inc. (“C&T Coal”).

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

On July 19, 2010, we completed the closing of our initial public offering as discussed further in the Initial Public Offering section of this Note 1. Immediately prior to the offering, all of the limited partner and general partner interests in us were split as discussed further in the Unit Split section of this Note 1. As a result of these transactions, AIM Oxford’s and C&T Coal’s ownership of the Partnership, as of December 31, 2010, was 36.82% and 18.74%, respectively, with our GP’s ownership being 2.00%. The remaining 42.44% was held by the general public and our long-term incentive plan (“LTIP”) participants. AIM Oxford and C&T Coal held 65.98% and 33.58%, respectively, of the ownership interests in our GP as of December 31, 2010, with the remaining 0.44% ownership interest therein being held by Jeffrey M. Gutman, our Senior Vice President, Chief Financial Officer and Treasurer.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 1: ORGANIZATION AND PRESENTATION (continued)

On January 1, 2011, our GP issued additional ownership interests. Additionally, on February 28, 2011, each of AIM Oxford and C&T Coal sold a portion of our common units held by them under Rule 144 in private transactions. Further, in January and March 2011, there were issuances of our common units to participants in our LTIP. As a result of these transactions, AIM Oxford’s and C&T Coal’s ownership of the Partnership, as of March 31, 2011, was 35.73% and 18.18%, respectively, with our GP’s ownership being 2.00%. The remaining 44.09% was held by the general public and our LTIP participants. AIM Oxford and C&T Coal owned 65.65% and 33.41%, respectively, of the ownership interests in our GP as of March 31, 2011, with the remaining ownership interests therein being a 0.47% ownership interest held by Jeffrey M. Gutman, our Senior Vice President, Chief Financial Officer and Treasurer, and a 0.47% ownership interest held by Daniel M. Maher, our Senior Vice President, Chief Legal Officer and Secretary.

Basis of Presentation and Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries and are prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).

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 condensed consolidated balance sheets and statements of operations.

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 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 our final prospectus dated July 15, 2010 and filed with the SEC (the “Prospectus”).

Concurrent with our initial public offering, we entered into our $175 million credit facility and paid off the amounts outstanding under our $115 million credit facility.

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 condensed consolidated financial statements and these notes thereto have been retroactively restated to reflect this unit split.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

There were no changes to our significant accounting policies from those disclosed in the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2010.

New Accounting Standards Issued

In January 2010, the FASB issued ASU 2010-06, Fair Value Measurements and Disclosures — Improving Disclosures about Fair Value Measurements. This guidance requires reporting entities to make new disclosures about recurring or non-recurring 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 for Level 1 and Level 2 reconciliation disclosures and effective December 31, 2010 for Level 3 reconciliation disclosures. The adoption of this guidance did not have a material effect on our consolidated financial statements.

In December 2010, the FASB issued ASU 2010-29, Business Combinations — Disclosure of Supplementary Pro Forma Information for Business Combinations. This guidance requires a public entity to disclose the revenue and earnings of the combined entity in its consolidated financial statements as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. This guidance also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, non-recurring pro forma adjustments directly attributable to the business combination(s) included in the reported pro forma revenue and earnings. These amendments are effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 31, 2010. Early adoption of the guidance is permissible. The adoption of this guidance did not 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 rights to coal reserves of 20 million tons, as well as working capital and various coal sales and purchase contracts.

In connection with the closing of our Phoenix Coal acquisition on September 30, 2009, we entered into an escrow agreement with Phoenix Coal. The purpose of the escrow agreement was to provide a source of funding for any indemnification claims made against Phoenix Coal for breaches of warranties and/or covenants as the seller under the terms of the acquisition agreement. The escrow was funded with $3,300,000. The escrow agreement provided 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 released amounts were subject to offset for any indemnification claims, and there were no such indemnification claims. Pursuant to such release provisions, the escrow agent released one-third of the then owing escrow fund amount, or approximately $1,100,000, to Phoenix Coal at each of the release dates as scheduled, and with the final release on March 31, 2011 the escrow terminated.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 4: INVENTORY

Inventory consisted of the following:

		March 31,				December 31,
		2011				2010
Coal		$	8,106,000			$	6,451,000
Fuel			2,083,000				1,836,000
Supplies and spare parts			5,243,000				4,353,000
Total		$	15,432,000			$	12,640,000

NOTE 5: PROPERTY, PLANT AND EQUIPMENT, NET

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

		March 31,				December 31,
		2011				2010
Property, plant and equipment, gross
Land		$	3,374,000			$	3,374,000
Coal reserves			55,285,000				54,250,000
Mine development costs			15,568,000				12,237,000
Total property			74,227,000				69,861,000
Buildings and tipple			2,113,000				2,084,000
Machinery and equipment			207,090,000				199,924,000
Vehicles			4,324,000				4,267,000
Furniture and fixtures			1,548,000				1,477,000
Railroad sidings			160,000				160,000
Total property, plant and equipment, gross			289,462,000				277,773,000
Less: accumulated depreciation, depletion and amortization			89,450,000				79,079,000
Total property, plant and equipment, net		$	200,012,000			$	198,694,000

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
		March 31,
		2011				2010
Expense type:
Depreciation		$	9,099,000			$	6,950,000
Depletion			1,499,000				1,329,000
Amortization			1,445,000				413,000

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 6: ASSET RETIREMENT OBLIGATIONS

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

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

At March 31, 2011, we had recorded ARO liabilities of $16.2 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with absolute certainty, we estimate that, as of March 31, 2011, the aggregate undiscounted cost of final mine closure is approximately $17.9 million.

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

		March 31, 2011				December 31, 2010
Beginning balance		$	12,987,000			$	13,343,000
Accretion expense			447,000				836,000
Payments			(311,000	)			(3,430,000	)
Revisions in estimated cash flows			3,044,000				2,238,000
Total asset retirement obligations			16,167,000				12,987,000
Less current portion			8,476,000				6,450,000
Noncurrent liability		$	7,691,000			$	6,537,000

For the quarter ended March 31, 2011, the revisions in estimated cash flows increased $3.0 million and were primarily attributed to mine development at four new mines which have now reached full operating capacity and revisions to estimates of the expected costs for stream mitigation as regulatory requirements continue to evolve. Capitalization of the increased liability related solely to stream mitigation resulted in a corresponding adjustment to the related mine development asset of $1.6 million with the remaining portion related to the four mines reaching full operating capacity.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 7: FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

Fair Value Measurement at March 31, 2011

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

$

—

$

(107,000

)

$

—

Fair Value Measurement at December 31, 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

$

—

$

(108,000

)

$

—

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

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

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

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

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

		March 31, 2011								December 31, 2010
		Carrying								Carrying
		Amount				Fair Value				Amount				Fair Value
Fixed rate debt		$	12,880,000			$	12,990,000			$	12,986,000			$	12,926,000
Variable rate debt			99,500,000				99,500,000				90,000,000				90,000,000

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 8: LONG-TERM INCENTIVE PLAN

Under our LTIP, we recognize equity-based compensation expense over the vesting period of the units, which is generally four years for each award. For the three-month periods ended March 31, 2011 and 2010, our equity-based compensation expense was approximately $364,000 and $304,000, respectively. These amounts are included in selling, general and administrative expenses in our condensed consolidated statements of operations. As of March 31, 2011 and December 31, 2010, approximately $1,540,000 and $726,000, respectively, of cost remained unamortized which we expect to recognize using the straight-line method over a remaining weighted average period of 1.5 years.

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

						Weighted
						Average
						Grant Date
		Units				Fair Value
Unvested balance at December 31, 2010			124,480			$	7.80
Granted			48,152			$	24.49
Issued			(21,916	)		$	11.98
Surrendered			(14,616	)		$	9.37
Unvested balance at March 31, 2011			136,100			$	12.86

The value of LTIP units vested during the three-month periods ended March 31, 2011 and 2010 was $399,000 and $244,000, 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 and general partner units. All outstanding units share pro rata in income allocations and distributions and our general partner has sole voting rights. Prior to our initial public offering (see the Initial Public Offering section in Note 1), limited partner units were separated into Class A and Class B units to prepare for a potential transaction such as an initial public offering. In connection with and since our initial public offering, our limited partner units were converted to and are maintained as 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 weighted average units outstanding and net income attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to LTIP units upon vesting. In years of a loss, the phantom units are anti-dilutive and therefore not included in the earnings per unit calculation.

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

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 9: EARNINGS PER UNIT (continued)

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

		Three Months Ended
		March 31,
		2011				2010
		(in thousands, except for unit
		and per unit amounts)
Limited partner units
Average units outstanding:
Basic			20,621,793				11,973,402
Effect of equity-based compensation			n/a				n/a
Diluted			20,621,793				11,973,402
Net loss allocated to limited partners
Basic		$	(1,735	)		$	(281	)
Diluted		$	(1,735	)		$	(281	)
Net loss per limited partner unit
Basic		$	(0.08	)		$	(0.02	)
Diluted		$	(0.08	)		$	(0.02	)
General partner units
Average units outstanding:
Basic and diluted			420,779				242,285
Net loss allocated to general partner
Basic		$	(35	)		$	(6	)
Diluted		$	(35	)		$	(6	)
Net loss per general partner unit
Basic		$	(0.08	)		$	(0.02	)
Diluted		$	(0.08	)		$	(0.02	)
Anti-dilutive units (1)			45,466				63,119

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

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 10: COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts

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

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 March 31, 2011, we expect this contract to continue for approximately 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, 2012.

401(k) Plan

Effective January 1, 2010, our former defined contribution pension plan was replaced with our current 401(k) plan. At March 31, 2011, we had an obligation to pay our GP $2,430,000 for the purpose of funding our GP’s commitment to our 401(k) plan. Of this amount, $1,877,000 related to plan year 2010 and is expected to be paid by September 2011. The remainder of $553,000 is related to plan year 2011 and is expected to be paid by September 2012.

Performance Bonds

As of March 31, 2011, we had outstanding $35.3 million in surety bonds and $14,000 in cash bonds to secure certain reclamation obligations. Additionally, as of March 31, 2011, we had outstanding letters of credit in support of these surety bonds of $6.7 million. Further, as of March 31, 2011, we had outstanding certain road bonds of $0.7 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.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 10: COMMITMENTS AND CONTINGENCIES (continued)

Guarantees

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

NOTE 11: RELATED PARTY TRANSACTIONS

In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (the “Services Agreement”) with our GP. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Our GP provides us with services such as general administrative and management, human resources, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geological, risk management and insurance services. Pursuant to the Services Agreement, the primary reimbursements to our GP were for costs related to payroll, and for such reimbursable costs the amounts of $5,221,000 and $2,618,000 were included in our accounts payable at March 31, 2011 and December 31, 2010, 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. Under the terms of the Advisory Agreement, the AIM Oxford affiliates had duties 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. Pursuant to the Advisory Agreement, advisory fees were paid to AIM Oxford affiliates of zero and $77,000 for the three months ended March 31, 2011 and 2010, respectively. The Advisory Agreement was terminated on July 19, 2010 with a termination payment of $2,500,000 being made in connection with the closing of our initial public offering and such termination 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 (“Mr. C. Ungurean”), Thomas T. Ungurean, our Senior Vice President, Equipment, Procurement and Maintenance (“Mr. T. Ungurean”), and affiliates of AIM Oxford, in the amounts of $555,000 and $206,000 for the three months ended March 31, 2011 and 2010, respectively. Accounts receivable were $407,000 and $329,000 from Tunnell Hill Reclamation, LLC at March 31, 2011 and December 31, 2010, respectively. We have concluded that Tunnell Hill Reclamation, LLC does not represent a variable interest entity.

From time to time for business purposes we charter an airplane from Zanesville Aviation located in Zanesville, Ohio. T&C Holdco LLC, a company that is owned by Mr. C. Ungurean and Mr. T. Ungurean, owns an airplane that it has leased to Zanesville Aviation since April 2010 and that Zanesville Aviation uses in providing chartering services to its customers including us. Under its lease with Zanesville Aviation, T&C Holdco LLC receives compensation from Zanesville Aviation for the use of T&C Holdco LLC’s airplane. The airplane owned by T&C Holdco LLC was chartered by us on a number of occasions during the three months ended March 31, 2011, and we paid Zanesville Aviation an aggregate of approximately $21,000 for those charters. Because it was not leased to Zanesville Aviation during the first quarter of 2010, the airplane owned by T&C Holdco was not available for charter and was not chartered to us during the three months ended March 31, 2010.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(CONTINUED)

NOTE 12: SUPPLEMENTAL CASH FLOW INFORMATION

		Three Months Ended
		March 31,
		2011				2010
Cash paid for:
Interest		$	1,540,000			$	1,711,000
Non-cash activities:
Market value of common units vested in LTIP			949,000				288,000
Accounts payable for purchase of property and equipment as of March 31			2,571,000				3,074,000

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

On April 21, 2011, the GP’s Board of Directors declared a cash distribution by the Partnership of $0.4375 per unit with respect to the first quarter of 2011. This distribution, totaling approximately $9,211,000, will be paid on May 13, 2011 to unitholders of record as of the close of business on May 2, 2011.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q and the audited consolidated financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations for the year ended December 31, 2010 included in our Annual Report on Form 10-K and filed with the U.S. Securities and Exchange Commission (the “SEC”). This discussion contains forward-looking statements that reflect management’s current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements or as a result of certain factors such as those set forth below under “Cautionary Statement Regarding Forward-Looking Statements.”

Cautionary Statement Regarding Forward-Looking Statements

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

•

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

•

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

•

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

•

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

•

our dependence on a limited number of customers;

•

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

•

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

•

our ability to acquire additional coal reserves;

•

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

•

fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability, governmental laws and regulations, including those related to emissions from coal-fired plants, 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;

•

limitations in the cash distributions we receive from our majority-owned subsidiary, 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 our Annual Report on Form 10-K for the year ended December 31, 2010 filed with the SEC, as well as other written and oral statements made or incorporated by reference from time to time by us in other reports and filings with the SEC. All forward-looking statements included in this Quarterly Report on Form 10-Q and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, other than as required by law, and we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Overview

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

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

We currently have 21 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 first quarter of 2011, we produced 2.0 million tons of coal and sold 2.1 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. As is customary in the coal industry, we have entered into long-term coal sales contracts with many of our customers. We define long-term coal sales contracts as coal sales contracts having initial terms of one year or more.

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 March 31, 2011, we had $99.5 million of borrowings outstanding under our $175 million credit facility, consisting of term loan borrowings of $55.5 million and revolving credit facility borrowings of $44.0 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.

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 cost adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the costs for items such as fuel, explosives and labor. Cost adjustment provisions adjust the initial contract price over the term of the contract either by a specific percentage or a percentage determined by reference to various cost-related indices, including cost-related indices for fuel, explosives, labor, equipment and cost-of-living generally.

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:

										% Change
										Three
										Months
										Ended
										March 31,
		Three Months Ended								2011
		March 31,								vs.
		2011				2010				2010
		(tons in thousands)
Tons of coal produced (clean)			1,951				1,806				8.1	%
Increase (decrease) in inventory			29				28				3.9	%
Tons of coal purchased			141				258				-45.4	%
Tons of coal sold			2,063				2,036				1.4	%
Tons sold under long-term contracts(1)			92.9	%			98.8	%			-6.0	%
Average sales price per ton		$	40.37			$	37.71				7.1	%

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

Cost of Coal Sales

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

										% Change
										Three
										Months
										Ended
										March 31,
		Three Months Ended								2011
		March 31,								vs.
		2011				2010				2010
		(tons in thousands)
Cost of coal sales per ton produced		$	32.57			$	31.04				4.9	%
Tons of coal produced (clean)			1,951				1,806				8.1	%

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 0.4 million tons of coal in 2011 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 March 31, 2011, we expect this contract to continue for approximately five years.

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

										% Change
										Three
										Months
										Ended
										March 31,
		Three Months Ended								2011
		March 31,								vs.
		2011				2010				2010
		(tons in thousands)
Cost of purchased coal per ton		$	36.44			$	30.51				19.4	%
Tons of coal purchased			141				258				-45.4	%

Adjusted EBITDA

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

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

•

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

•

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

•

our compliance with certain credit facility financial covenants; and

•

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

Distributable Cash Flow

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

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 and/or cost adjustment provisions.

For 2011, 2012, 2013 and 2014, we currently have long-term coal sales contracts that represent 100%, 78%, 52% and 47%, respectively, of our 2011 estimated coal sales. 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 long-term coal sales contracts will terminate in 2013 if we cannot agree upon a market-based price with the applicable customer prior to the termination date. In addition, we have one long-term coal sales contract that will terminate in 2014 if we cannot agree upon a market-based price with the customer prior to the termination date. The coal tonnage which is involved for these two customers through 2014 is 1.0 million tons annually for 2013 and 2014 and 0.4 million tons annually for 2014, respectively.

The current term of our long-term coal sales contract with American Electric Power Service Corporation (“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/or cost adjustment provisions. If AEP elects to extend this contract, we will be committed to deliver an additional 2.0 million tons in 2013 and 2014, and our 2013 and 2014 coal sales under long-term coal sales contracts, as a percentage of 2011 estimated coal sales, would increase to 74% and 69%, respectively. We are continuing 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 that is on 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 and/or cost adjustment provisions. For 2011, 2012, 2013 and 2014, 81%, 96%, 100% and 91%, respectively, of the coal that we have committed to deliver under our current long-term coal sales contracts are subject to full or partial cost pass through and/or cost adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the costs for such items as fuel, explosives and/or labor. Cost adjustment provisions adjust the initial contract price over the term of the contract either by a specific percentage or a percentage determined by reference to various cost-related indices.

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 2011, 2012, 2013 and 2014, we have outstanding option tons of 0.7 million, 0.9 million, 0.9 million and 1.2 million, respectively. If there are customer elections to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production at our mining complexes.

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 was impacted by transactions related to the closing of our initial public offering and our $175 million credit facility in the third quarter of 2010.

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
		March 31,
		2011				2010
		(in thousands, unaudited)
Statement of Operations Data:
Revenue:
Coal sales		$	83,304			$	76,756
Transportation revenue			10,442				9,530
Royalty and non-coal revenue			2,320				1,774
Total revenue			96,066				88,060
Costs and expenses:
Cost of coal sales (excluding depreciation, depletion and amortization, shown separately)			62,617				55,186
Cost of purchased coal			5,127				7,859
Cost of transportation			10,442				9,530
Depreciation, depletion and amortization			12,111				8,777
Selling, general and administrative expenses			3,966				3,535
Total costs and expenses			94,263				84,887
Income from operations			1,803				3,173
Interest income			1				1
Interest expense			(2,003	)			(1,833	)
Net income (loss)			(199	)			1,341
Net income attributable to noncontrolling interest			(1,571	)			(1,628	)
Net loss attributable to Oxford Resource Partners, LP unitholders		$	(1,770	)		$	(287	)
Other Financial Data
Adjusted EBITDA		$	13,987			$	10,888
Distributable cash flow(1)		$	5,479

(1)		We do not calculate distributable cash flow with respect to the periods prior to becoming a publicly traded limited partnership during the second half of 2010.

Reconciliation to GAAP Measures

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

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

		Three Months Ended
		March 31,
		2011				2010
		(in thousands, unaudited)
Net loss attributable to Oxford Resource Partners, LP unitholders		$	(1,770	)		$	(287	)
PLUS:
Interest expense, net of interest income			2,002				1,832
Depreciation, depletion and amortization			12,111				8,777
Non-cash equity-based compensation expense			364				304
Non-cash loss on asset disposals			166				175
Change in fair value of future asset retirement obligations			1,358				712
LESS:
Amortization of below-market coal sales contracts			244				625
Adjusted EBITDA		$	13,987			$	10,888
LESS:
Cash interest expense, net of interest income			1,539
Estimated reserve replacement expenditures			1,331
Other maintenance capital expenditures			5,638
Distributable cash flow(1)		$	5,479

(1)		We do not calculate distributable cash flow with respect to the periods prior to becoming a publicly traded limited partnership during the second half of 2010.

Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010

Overview. Net loss for the first quarter of 2011 was $1.8 million, or $0.08 per diluted limited partner unit, compared to a net loss for the first quarter of 2010 of $0.3 million, or $0.02 per diluted limited partner unit. Adjusted EBITDA was $14.0 million for the first quarter of 2011, up 28.5% from $10.9 million for the first quarter of 2010. Net cash provided by operations was $17.2 million for the first quarter of 2011, up 106.4% from $8.3 million for the first quarter of 2010. Distributable cash flow was $5.5 million for the first quarter of 2011. We do not calculate distributable cash flow for periods prior to becoming a publicly traded partnership, so there was no comparable amount for the first quarter of 2010.

Coal Production. Our tons of coal produced increased 8.1% to 2.0 million tons in the first quarter of 2011 from 1.8 million tons in the first quarter of 2010. This increase was due primarily to a 36.8% increase in production at our Illinois Basin operations partially offset by a 2.7% reduction in production from our Northern Appalachia operations due to adverse mining conditions.

Sales Volume. Our sales volume increased 1.4% to 2.1 million tons in the first quarter of 2011 from 2.0 million tons in the first quarter of 2010. Interruptions in shipments via road and river barge resulting from adverse weather conditions and flooding during the first quarter of 2011 negatively impacted our sales volume by 169,000 tons. Had we not experienced these interruptions in shipments our sales volume would have increased by 9.7% in the first quarter of 2011 as compared to the first quarter of 2010.

Average Sales Price Per Ton. Our average sales price per ton increased 7.1% to $40.37 in the first quarter of 2011 from $37.71 in the first quarter of 2010. This $2.66 per ton increase was primarily the result of higher contracted sales prices realized from our Northern Appalachia contract portfolio in effect for the first quarter of 2011 compared to the first quarter of 2010.

Coal Sales Revenue. For the first quarter of 2011, coal sales revenue increased by $6.5 million, or 8.5%, compared to the first quarter of 2010. This increase was primarily attributable to the increase of $2.66 per ton in our average sales price. Had we not experienced interruptions in shipments during the first quarter of 2011, coal sales revenue would have increased 17.4% compared to the first quarter of 2010.

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 increased to $2.3 million in the first quarter of 2011 from $1.8 million in the first quarter of 2010. This increase primarily resulted from an increase of $0.4 million in revenue from the sale of limestone in the first quarter of 2011 compared to the first quarter of 2010.

Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased 13.5% to $62.6 million in the first quarter of 2011 from $55.2 million in the first quarter of 2010. Cost of coal sales per ton increased by 4.9% to $32.57 per ton in the first quarter of 2011 compared to $31.04 per ton in the first quarter of 2010. This $1.53 per ton increase resulted from the impact of higher diesel fuel prices which increased operating costs by approximately $2.7 million, or $1.42 per ton.

Cost of Purchased Coal. Cost of purchased coal decreased to $5.1 million in the first quarter of 2011 from $7.9 million in the first quarter of 2010. This decrease was attributable to a reduction in the volume of coal purchased by our Illinois Basin operations.

Depreciation, Depletion and Amortization (DD&A). DD&A expense in the first quarter of 2011 was $12.1 million compared to $8.8 million in the first quarter of 2010, an increase of $3.3 million. This increase was primarily attributable to increased DD&A resulting from the purchase of previously leased and additional major mining equipment using proceeds from our initial public offering and borrowings under our $175 million credit facility.

Selling, General and Administrative Expenses (SG&A). SG&A expenses for the first quarter of 2011 were $4.0 million compared to $3.5 million for the first quarter of 2010, an increase of $0.5 million. This increase was primarily attributable to on-going public company expenses.

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 the actual transportation costs that we incur under those contracts. Our transportation revenue fluctuates based on a number of factors, including the volume and delivery point of the coal and fluctuations in the actual costs we incur with the truck and rail transportation providers. Our transportation revenue and expenses for the first quarter of 2011 increased 9.6% compared to the first quarter of 2010 due to higher coal sales revenue.

Interest Expense. Interest expense for the first quarter of 2011 was $2.0 million compared to $1.8 million for the first quarter of 2010, an increase of $0.2 million. This increase was primarily attributable to an additional $14 million in borrowings outstanding in the first quarter of 2011 compared to the first quarter of 2010.

Net Income Attributable to Noncontrolling Interest. In 2007, we entered into a joint venture, Harrison Resources, with CONSOL Energy to mine surface coal reserves acquired 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 first quarter of each of 2011 and 2010, the net income attributable to noncontrolling interest was $1.6 million.

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 and mining laws and regulations. We primarily require liquidity to finance current operations, fund capital expenditures, including acquisitions from time to time, service our debt and pay cash distributions to our unitholders. Our primary sources of liquidity to meet these needs have been cash generated by our operations, credit facility borrowings and contributions from our partners.

The principal indicators of our liquidity are our cash on hand and availability under our $175 million credit facility, which is described under “— Credit Facility” below. 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 our quarterly distributions to unitholders.

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

Cash Flows

The following table reflects cash flows for the applicable periods:

		Three Months Ended
		March 31,
		2011				2010
Net cash provided by (used in)
Operating activities		$	17,219			$	8,341
Investing activities			(13,091	)			(10,280	)
Financing activities			(1,277	)			(137	)

Net cash provided by operating activities was $17.2 million for the first quarter of 2011, an increase of $8.9 million from net cash provided by operating activities of $8.3 million for the first quarter of 2010. This increase was primarily due to higher non-cash adjustments, principally from DD&A, and favorable changes in assets and liabilities for the first quarter of 2011.

Net cash used in investing activities was $13.1 million for the first quarter of 2011 compared to $10.3 million for the first quarter of 2010. This $2.8 million increase was primarily attributable to higher purchases of major mining equipment in the first quarter of 2011 compared to the first quarter of 2010.

Net cash used in financing activities was $1.3 million for the first quarter of 2011 compared to net cash used in financing activities of $0.1 million for the first quarter of 2010. This change of $1.2 million was primarily attributable to higher distributions paid partially offset by increased net borrowings under our credit facility.

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 March 31, 2011, we had borrowings of $99.5 million outstanding under our $175 million credit facility, consisting of a $55.5 million term loan and borrowings of $44.0 million on the revolving credit facility. We also use our $175 million credit facility to collateralize letters of credit related to surety bonds securing our reclamation obligations. As of March 31, 2011, we had letters of credit outstanding in support of these surety bonds of $6.7 million.

The term loan and revolver will mature in 2014 and 2013, respectively, and borrowings bear interest at a variable rate per annum equal to, at our option, LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin are each defined in the credit agreement that evidences our $175 million credit facility). 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.

Borrowings under our $175 million credit facility are secured by a first-priority lien on and security interest in substantially all of our assets. Our $175 million credit facility contains customary covenants, including restrictions on our ability to incur additional indebtedness, make certain investments, make distributions to our unitholders, make ordinary course dispositions of assets over predetermined levels or enter into equipment leases, as well as enter into a merger or sale of all or substantially all of our property or assets, including the sale or transfer of interests in our subsidiaries. Our $175 million credit facility also requires compliance with certain financial covenant ratios, including limiting our leverage ratio (the ratio of consolidated indebtedness to adjusted EBITDA) 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.

Capital Expenditures

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

For 2011, we expect to incur between $37.0 million and $40.0 million in maintenance capital expenditures consisting of reserve replacement expenditures and other maintenance capital expenditures. In the first quarter of 2011, we had maintenance capital expenditures of $7.0 million, comprised of $1.3 million in reserve replacement expenditures and $5.7 million in other maintenance capital expenditures. We have funded and expect to continue funding maintenance capital expenditures primarily from cash generated by our operations. To the extent we incur expansion capital expenditures, we expect to fund those expenditures with the proceeds of borrowings under our $175 million credit facility, issuance of debt and equity securities and/or other external sources of financing.

Off-Balance Sheet Arrangements

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

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

As of March 31, 2011, we had outstanding $35.3 million in surety bonds and $14,000 in cash bonds to secure certain reclamation obligations. Additionally, as of March 31, 2011, we had outstanding letters of credit in support of these surety bonds of $6.7 million. Further, as of March 31, 2011, we had outstanding road bonds of $0.7 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.

Critical Accounting Policies

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

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

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

Use of Estimates

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

Allowance for Doubtful Accounts

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

Inventory

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

Property, Plant and Equipment

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

Buildings and tipple		25-39 years
Machinery and equipment		7-12 years
Vehicles		5-7 years
Furniture and fixtures		3-7 years
Railroad siding		7 years

We acquire our coal reserves through purchases or leases. We deplete our coal reserves using the units-of-production method on the basis of tonnage mined in relation to total estimated recoverable tonnage with residual surface values classified as land and not depleted. At March 31, 2011 and December 31, 2010, all of our reserves were attributed to mine complexes engaged in mining operations or leased to third parties. We believe that the carrying value of these reserves will be recovered.

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

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

Advance Royalties

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

Financial Instruments and Derivative Financial Instruments

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

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

We measure our derivatives (interest rate swap agreements 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 7 to our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q under the heading “Fair Value of Financial Instruments.”

Our other financial instruments include fixed price forward contracts for diesel fuel. Our risk management policy requires us to purchase up to 75% of our unhedged diesel fuel gallons under 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 usually have a term of one year or less.

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 by accelerating the depletion rate. To the extent it is determined that an asset’s carrying value will not be recoverable during a shorter mine life, the asset is written down to its recoverable value. There were no indicators of impairment present during the first quarter of 2011 or during the years ended December 31, 2010, 2009 and 2008. Accordingly, no impairment losses were recognized during any of these periods.

Identifiable Intangible Assets and Liabilities

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

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

Asset Retirement Obligations

Our asset retirement obligations (“AROs”) arise from the Surface Mining Control and Reclamation Act (“SMCRA”) and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Our 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 at a lower cost to us. Hence, the estimated costs used in determining the carrying amount of our AROs may exceed the amounts that are eventually paid for reclamation costs 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, estimate future reclamation costs and make assumptions regarding the mine’s productivity. These cash flows are discounted at a credit-adjusted, risk-free interest rate based on U.S. Treasury bonds with a maturity similar to the expected lives of our mines.

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

Adjustments to the ARO liability for the quarter ended March 31, 2011 increased the liability by $3.0 million and were primarily attributed to mine development at four new mines which have now reached full operating capacity and revisions to estimates of the expected costs for stream mitigation as regulatory requirements continue to evolve. Capitalization of the increased liability related solely to stream mitigation resulted in a corresponding adjustment to the related mine development asset of $1.6 million with the remaining portion related to the four mines reaching full operating capacity.

Income Taxes

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

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

Revenue Recognition

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

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

Royalty and non-coal revenue consists of coal royalty income, service fees for providing landfill earth moving and transportation services, commissions that we receive from a third party who sells limestone that we recover during our coal mining process, service fees for operating a coal unloading facility and fees that we receive for trucking ash for municipal utility customers. Revenues are recognized when earned or when services are performed. Royalty revenue relates to the overriding royalty we receive on our underground coal reserves that we sublease to a third party mining company. Prior to June 2008, we did not receive any royalties because we were purchasing the output of this mine and no royalty was due on purchases by us. Starting in June 2008, our sublessee began selling the coal production for its own account which entitled us to start receiving royalty revenue.

Below-Market Coal Sales Contracts

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

Equity-Based Compensation

We account for equity-based compensation awards in accordance with applicable guidance, which establishes standards of accounting for transactions in which an entity exchanges its equity instruments for goods or services. Equity-based compensation expense is recorded based upon the fair value of the award at grant date. Such costs are recognized as expense on a straight-line basis over the corresponding vesting period. Prior to our initial public offering (see the Initial Public Offering section in Note 1 to our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q under the heading “Organization and Presentation”), the fair value of our LTIP units was determined based on the sale price of our limited partner units in arm’s-length transactions. Subsequent to our initial public offering, the unit price fair value is determined based on the closing sales price of our units on the New York Stock Exchange on the grant date. See Note 8 to our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q under the heading “Long-Term Incentive Plan.”

Earnings Per Unit

For purposes of our earnings per unit calculation, we have applied the two class method. The classes of units are our limited partner and general partner units. All outstanding units share pro rata in income allocations and distributions and our general partner has sole voting rights. Prior to our initial public offering (see the Initial Public Offering section in Note 1 to our condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q under the heading “Organization and Presentation”), limited partner units were separated into Class A and Class B units to prepare for a potential transaction such as an initial public offering. In connection with and since our initial public offering, our limited partner units were converted to and are maintained as 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 weighted average units outstanding and net income attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to LTIP units upon vesting. In years of a loss, the phantom units are anti-dilutive and therefore not included in the earnings per unit calculation.

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

Item 3.		Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risks

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

We believe that the price risks associated with our diesel fuel expense is significant. Taking into account our fixed price fuel purchase contracts, we estimate that a hypothetical increase of $0.30 per gallon of diesel fuel would have increased our fuel and hauling costs and reduced net income attributable to our unitholders by $1.2 million for the first quarter of 2011. If this hypothetical increase had occurred, we estimate that fuel cost pass through or cost adjustment provisions in our long-term coal sales contracts would have provided a corresponding increase in revenue and net income attributable to our unitholders in future quarters of $1.2 million as well.

Interest Rate Risks

We are exposed to interest rate risks as borrowings under our $175 million credit facility are at variable rates. At March 31, 2011, 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 decreased by $1,000 in the first quarter of 2011.

Item 4.		Controls and Procedures

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”)) was performed as of March 31, 2011. This evaluation was performed by our management, with the participation of our Chief Executive Officer and Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective to ensure that the Partnership is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods, and during the quarterly period ended March 31, 2011 there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

PART II. OTHER INFORMATION

Item 1.		Legal Proceedings

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

Item 1A.		Risk Factors

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

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.

Item 3.		Defaults Upon Senior Securities

None.

Item 4.		Mine Safety Disclosure

Mine Safety and Health

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 (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 additional underground mine accidents, Congress expanded mine safety disclosure requirements pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Act. On December 15, 2010, the SEC issued proposed rules to implement Section 1503 by outlining the way in which mining companies must disclose to investors certain information about mine safety and health standards. During the first quarter of 2011, for each coal mine we operated: the total number of violations of mandatory health or safety standards that could significantly and substantially (“S&S”), contribute to the cause and effect of a coal or other mine safety or health hazard under Section 104 of the Mine Act for which we received a citation from the Mine Safety and Health Administration (“MSHA”) was sixteen (16) as shown in the following Table OXF-MSHA-1; the total number of orders issued under Section 104(b) of the Mine Act was zero (0); the total number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under Section 104(d) of the Mine Act was zero (0); the total number of flagrant violations under Section 110(b)(2) of the Mine Act was zero (0); the total number of imminent danger orders issued under Section 107(a) of the Mine Act was one (1); and the total dollar value of the proposed assessments from MSHA under the Mine Act was $6,226. In addition, no coal mine of which we were the operator received 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 that were pending in the first quarter of 2011 before the Federal Mine Safety and Health Review Commission (the “Commission”) are shown in the following Table OXF-MSHA-2.

Table: OXF-MSHA-1
Three Months Ended March 31, 2011

																						(F)								(H)
		(A)				(B)				(C)				(D)				(E)				Proposed								Pending
		Section				Section				Section				Section				Section				Assess-				(G)				Legal
Mining Complex		104				104(b)				104(d)				110(b)(2)				107(a)				ments				Fatalities				Action
Cadiz			1				—				—				—				—			$	1,087.00				—				2
Tuscarawas County			—				—				—				—				—			$	1,612.00				—				—
Belmont County			2				—				—				—				—			$	100.00				—				—
Plainfield			—				—				—				—				—			$	100.00				—				1
New Lexington			—				—				—				—				—			$	—				—				1
Harrison			1				—				—				—				—			$	—				—				—
Noble County			1				—				—				—				—			$	534.00				—				—
Muhlenberg County			11				—				—				—				1			$	2,793.00				—				—
Totals			16				—				—				—				1			$	6,226.00				—				4

(A)		The total number of 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 (30 U.S.C. 814) for which the operator received a citation from MSHA.
(B)		The total number of orders issued under section 104(b) of the Mine Act (30 U.S.C. 814(b)).
(C)		The total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of the Mine Act (30 U.S.C. 814(d)).
(D)		The total number of flagrant violations under section 110(b)(2) of the Mine Act (30 U.S.C. 820(b)(2)).
(E)		The total number of imminent danger orders issued under section 107(a) of the Mine Act (30 U.S.C. 817(a)).
(F)		The total dollar value of proposed assessments from MSHA under the Mine Act (30 U.S.C. 801 et seq.). Includes proposed assessments for non-S&S citations and proposed assessments received in the current period for citations in prior periods.
(G)		The total number of mining-related fatalities.
(H)		Any pending legal action before the Commission involving such coal or other mine. See Table OXF-MSHA-2 below for information regarding pending legal actions.

Table: OXF-MSHA-2
Legal Actions Pending as of March 31, 2011

Docket Number

Proposed

MSHA Mine Name

Civil

Oxford Mine Complex/Name

Citation

Date

Penalty

MSHA ID Number

No.

Issued

Assessment

Status

LAKE 2008-383 Oxford Mining #3 New Lexington/New Lexington 33-04336

7138351

1/9/2008

$

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. The matter was set for trial on April 26, 2011 before Administrative Law Judge (“’ALJ”) David F. Barbour.

LAKE 2009-381-M Oxford Mining #2 Plainfield/Adamsville* 33-04213 *Adamsville mine — reclaimed

7141549 7141550

11/3/2008 11/10/2008

$ $

460 460

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 was assigned to ALJ Barbour pending issuance of a Petition for Penalty Assessment.

LAKE 2010 -576 Snyder Mine Cadiz/County Road 29 33-04414

8017301

8/31/2009

$

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 was assigned to ALJ Harner. The parties conducted a status conference with the ALJ and engaged in settlement discussions. The parties exchanged pre-hearing information and documents in accordance with the Commission’s Order. The matter was set for trial along with Lake 2010-577 on April 28, 2011.

LAKE 2010-577 Snyder Mine Cadiz/County Road 29 33-04414

8024308

2/3/2010

$

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 was assigned to ALJ Harner. The parties conducted a status conference with the ALJ and have engaged in settlement discussions. The parties exchanged pre-hearing information and documents in accordance with the Commission’s Order. The matter was set for trial along with Lake 2010-576 on April 28, 2011.

Item 5.		[Removed and Reserved]

Item 6.		Exhibits

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

SIGNATURES

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

Date: May 6, 2011

		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)