Westmoreland Resource Partners (WMLPQ) 10-Q 2010 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2010

OR

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

Commission file number: 001-34815

Oxford Resource Partners, LP

(Exact name of registrant as specified in its charter)

Delaware	77-0695453
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

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

(614) 643-0314
(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.YESo NOþ

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yeso Noo

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

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

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

As of August 9, 2010, 10,280,368 common 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. CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)		1
Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009		1
Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009		2
Condensed Consolidated Statements of Partners’ Capital for the Six Months Ended June 30, 2010 and 2009		3
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009		4
Notes to Condensed Consolidated Financial Statements		5
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		17
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		31
ITEM 4. CONTROLS AND PROCEDURES		32
PART II
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS		33
ITEM 1A. RISK FACTORS		33
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		33
ITEM 3. DEFAULTS UPON SENIOR SECURITIES		34
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		34
ITEM 5. OTHER INFORMATION		34
ITEM 6. EXHIBITS		35
Exhibit 10.3
Exhibit 10.4
Exhibit 10.5
Exhibit 10.6
Exhibit 10.7
Exhibit 10.14
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

i

PART I
FINANCIAL INFORMATION

Item 1.Consolidated Financial Statements

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(in thousands, except for unit data)

	June 30,		December 31,
	2010		2009
ASSETS
Cash and cash equivalents	$	1,486	$	3,366
Trade accounts receivable		25,570		24,403
Inventory		11,344		8,801
Advance royalties		2,887		1,674
Prepaid expenses and other current assets		7,413		1,424
Total current assets		48,700		39,668
Property, plant and equipment, net		168,996		149,461
Advance royalties		6,059		7,438
Other long-term assets		9,198		6,796
Total assets	$	232,953	$	203,363
LIABILITIES
Current maturities of long-term debt	$	2,079	$	4,113
Accounts payable		42,154		21,655
Asset retirement obligation — current portion		8,020		7,377
Deferred revenue — current portion		—		2,090
Accrued taxes other than income taxes		1,484		1,464
Accrued payroll and related expenses		2,422		2,045
Other current liabilities		3,962		5,714
Total current liabilities		60,121		44,458
Long-term debt, less current maturities		109,185		91,598
Asset retirement obligation		6,101		5,966
Other long-term liabilities		3,421		4,229
Total liabilities	$	178,828	$	146,251
Commitments and Contingencies
PARTNERS’ CAPITAL
Limited partner unitholders (11,985,748 and 11,964,547 units outstanding as of June 30, 2010 and December 31, 2009, respectively)	$	49,214	$	53,960
General partner unitholders (244,607 and 242,023 units outstanding as of June 30, 2010 and December 31, 2009, respectively)		1,006		1,085
Total Oxford Resource Partners, LP Capital		50,220		55,045
Noncontrolling interest		3,905		2,067
Total partners’ capital		54,125		57,112
Total liabilities and partners’ capital	$	232,953	$	203,363

See accompanying notes to unaudited condensed consolidated financial statements.

1

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(in thousands, except for unit data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenue
Coal sales	$	78,571		$	52,882		$	155,327		$	120,259
Transportation revenue		9,841			7,012			19,371			15,672
Royalty and non-coal revenue		1,736			1,396			3,510			3,798
Total revenue		90,148			61,290			178,208			139,729
Costs and expenses
Cost of coal sales (excluding depreciation, depletion, and amortization, shown separately)		59,311			36,152			114,497			76,977
Cost of purchased coal		6,968			1,331			14,827			9,836
Cost of transportation		9,841			7,012			19,371			15,672
Depreciation, depletion and amortization		9,555			5,670			18,332			11,358
Selling, general and administrative expenses		2,867			2,993			6,402			6,094
Total costs and expenses		88,542			53,158			173,429			119,937
Income from operations		1,606			8,132			4,779			19,792
Interest income		7			11			8			22
Interest expense		(2,040	)		(1,392	)		(3,873	)		(2,515	)
Net income (loss)		(427	)		6,751			914			17,299
Less: net income attributable to noncontrolling interest		(1,680	)		(1,303	)		(3,308	)		(2,468	)
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(2,107	)	$	5,448		$	(2,394	)	$	14,831
Net income (loss) allocated to general partners	$	(42	)	$	108		$	(48	)	$	295
Net income (loss) allocated to limited partners	$	(2,065	)	$	5,340		$	(2,346	)	$	14,536
Basic earnings (loss) per limited partner unit	$	(0.17	)	$	0.50		$	(0.20	)	$	1.35
Dilutive earnings (loss) per limited partner unit	$	(0.17	)	$	0.50		$	(0.20	)	$	1.35
Weighted average number of limited partner units outstanding basic		11,985,748			10,733,696			11,979,621			10,729,239
Weighted average number of limited partner units outstanding diluted		11,985,748			10,757,032			11,979,621			10,750,640
Distributions paid per limited partner unit	$	—		$	0.23		$	0.23		$	0.46

See accompanying notes to unaudited condensed consolidated financial statements.

2

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
For the Six Months Ended June 30, 2010 and 2009
(UNAUDITED)
(in thousands, except for unit data)

	Limited		Limited			General		General			Non-			Total
	Partner		Partners’			Partner		Partners’			controlling			Partners’
	Units		Capital			Units		Capital			Interest			Capital
Balance at December 31, 2008		10,724,625	$	32,371			217,867	$	653		$	2,297		$	35,321
Net income				14,536					295			2,468			17,299
Partners’ distributions				(4,950	)				(100	)		(1,470	)		(6,520	)
Equity based compensation				214											214
Issuance of units to Long-Term Incentive Plan participants upon vesting		9,065
Balance at June 30, 2009		10,733,690	$	42,171			217,867	$	848		$	3,295		$	46,314
Balance at December 31, 2009		11,964,547	$	53,960			242,023	$	1,085		$	2,067		$	57,112
Net income (loss)				(2,346	)				(48	)		3,308			914
Partners’ contributions							2,584		25						25
Partners’ distributions				(2,762	)				(56	)		(1,470	)		(4,288	)
Equity based compensation				456											456
Issuance of units to Long-Term Incentive Plan participants upon vesting		21,201		(94	)										(94	)
Balance at June 30, 2010		11,985,748	$	49,214			244,607	$	1,006		$	3,905		$	54,125

See accompanying notes to unaudited condensed consolidated financial statements.

3

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)

	Six Months
	Ended June 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(2,394	)	$	14,831
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		18,332			11,358
Interest rate swap or rate cap adjustment to market		34			(978	)
Loan fee amortization		335			236
Non-cash equity compensation expense		456			214
Advanced royalty recoupment		965			524
Loss on disposal of property and equipment		452			208
Noncontrolling interest in subsidiary earnings		3,308			2,468
(Increase) in assets:
Accounts receivable		(1,167	)		(2,512	)
Inventory		(2,543	)		(1,906	)
Other assets		(6,135	)		(7,409	)
Increase (decrease) in liabilities:
Accounts payable and other liabilities		5,387			(731	)
Asset retirement obligations		778			348
Provision for below-market contracts and deferred revenue		(3,115	)		(6,280	)
Net cash provided by operating activities		14,693			10,371
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of mineral rights and land		(2,228	)		(1,346	)
Mine development costs		(1,489	)		(1,405	)
Royalty advances		(409	)		(273	)
Purchase of property and equipment		(10,333	)		(13,783	)
Proceeds from sale of property and equipment		1,259			21
Change in restricted cash		(2,765	)		(2,071	)
Net cash used in investing activities		(15,965	)		(18,857	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment on borrowings		(2,345	)		(2,179	)
Capital contributions from partners		25			—
Advances on line of credit		6,000			6,650
Distributions to noncontrolling interest		(1,470	)		(1,470	)
Distributions to partners		(2,818	)		(5,050	)
Net cash used in financing activities		(608	)		(2,049	)
Net decrease in cash		(1,880	)		(10,535	)
CASH AND CASH EQUIVALENTS, beginning of period		3,366			15,179
CASH AND CASH EQUIVALENTS, end of period	$	1,486		$	4,644

See accompanying notes to unaudited condensed consolidated financial statements.

4

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In our opinion, the interim condensed consolidated financial statements reflect all adjustments necessary for a fair presentation of the results of operations and financial position for such periods. All such adjustments reflected in the interim condensed consolidated financial statements are considered to be of a normal recurring nature. The results of operations for any interim period are not necessarily indicative of results for the full year. Accordingly, these interim condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2009 and notes thereto, included in our final prospectus dated July 15, 2010 (the “Prospectus”) and filed with the Securities and Exchange Commission (the “SEC”).

NOTE 1: ORGANIZATION AND PRESENTATION

Significant Relationships Referenced in Notes to Consolidated Financial Statements

• “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.

In conjunction with closing our initial public offering on July 19, 2010, the board of directors of our GP declared a unit split at a ratio of 1.82097973 new units for each existing unit held. All references in the accompanying condensed consolidated financial statements to unit and per unit amounts have been retroactively restated to reflect the unit split. See Note 15.

Organization

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

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

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

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

Subsequent to our formation, AIM Oxford and C&T Coal made several capital contributions for various purposes including purchasing property, plant and equipment and acquiring the surface mining operations of Phoenix Coal Corporation (“Phoenix Coal”). The capital contributions were not all in direct proportion to AIM Oxford’s and C&T Coal’s initial limited partner interests in us. As a result of the disproportionate capital contributions, AIM Oxford’s and C&T Coal’s ownership of the Partnership, as of June 30, 2010, was 64.26% and 32.70%, respectively, with 2.00% and 1.04% interests being owned by our GP and participants in the Partnership’s Long-Term Incentive Plan (“LTIP”), respectively. AIM Oxford and C&T Coal, as of June 30, 2010, owned 66.27% and 33.73%, respectively, in our GP.

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 the consolidated balance sheet.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

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

New Accounting Standards Issued and Adopted

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

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

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

NOTE 3: ACQUISITION

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

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

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

The following unaudited pro forma financial information reflects the consolidated results of operations as if the Phoenix Coal acquisition had occurred at the beginning of 2009. The pro forma information includes adjustments primarily for depreciation, depletion and amortization based upon fair values of property, plant and equipment and mineral rights, the lease of $11.1 million of equipment, and interest expense for acquisition debt and additional capital contributions. The pro forma financial information is not necessarily indicative of results that actually would have occurred if we had assumed operation of these assets on the date indicated nor are they indicative of future results.

	Three		Six Months
	Months Ended		Ended
	June 30, 2009		June 30, 2009
Revenue	$	80,053,000	$	177,963,000
Net income attributable to Oxford Resource Partners, LP unitholders		1,026,000		3,017,000

NOTE 4: INVENTORY

Inventory consisted of the following:

	June 30,		December 31,
	2010		2009
Coal	$	6,226,000	$	4,759,000
Fuel		1,335,000		1,264,000
Supplies and spare parts		3,783,000		2,778,000
Total	$	11,344,000	$	8,801,000

NOTE 5: PROPERTY, PLANT AND EQUIPMENT, NET

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

	June 30,		December 31,
	2010		2009
Property, plant and equipment, gross
Land	$	3,374,000	$	3,374,000
Coal reserves		54,779,000		39,905,000
Mine development costs		9,990,000		8,606,000
Total property		68,143,000		51,885,000
Buildings and tipple		2,066,000		2,025,000
Machinery and equipment		152,469,000		133,667,000
Vehicles		4,077,000		3,913,000
Furniture and fixtures		1,174,000		690,000
Railroad sidings		160,000		160,000
Total property, plant and equipment, gross		228,089,000		192,340,000
Less: accumulated depreciation, depletion and amortization		59,093,000		42,879,000
Total property, plant and equipment, net	$	168,996,000	$	149,461,000

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

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

	Three Months Ended				Six Months Ended
	June 30,		June 30,		June 30,		June 30,
	2010		2009		2010		2009
Expense type:
Depreciation	$	7,031,000	$	4,405,000	$	13,981,000	$	8,002,000
Depletion		1,695,000		856,000		3,024,000		2,427,000
Amortization		740,000		310,000		1,153,000		730,000

NOTE 6: OPERATING LEASES

We lease certain equipment and operating facilities under non-cancelable lease agreements that expire on various dates through 2015. Generally the lease agreements are for a period of four years. As of June 30, 2010, aggregate lease payments that are required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year are set forth below:

For the years ending December 31, 2010	$	4,143,000
2011		7,866,000
2012		6,283,000
2013		3,405,000
2014		1,206,000
Thereafter		121,000

For the three month periods ended June 30, 2010 and 2009, we incurred lease expenses of approximately $2,095,000 and $1,031,000, respectively. For the six month periods ended June 30, 2010 and 2009, we incurred lease expenses of approximately $4,331,000 and $2,149,000, respectively. On July 19, 2010, we terminated all of our equipment leases and purchased the equipment that was under lease with proceeds from our initial public offering and borrowings on our $175 million credit facility. See Note 15.

We also entered into various coal reserve lease agreements under which future royalty payments are due based on production. Such payments are capitalized as advance royalties at the time of payment, and amortized into royalty expense based on the stated recoupment rate.

NOTE 7: LONG-TERM DEBT

Our credit facility evidenced by our credit agreement with a syndicate of lenders, for which FirstLight Funding I, Ltd. acted as Administrative Agent (our “$115 million credit facility”), provided for borrowings of up to $115 million in the form of term loans of $70 million, acquisition loans of up to $25 million and a revolving credit facility of $20 million. As of June 30, 2010, we had $96.3 million of borrowings outstanding under our $115 million credit facility.

In connection with our initial public offering (see Note 15), we paid off the amounts outstanding under our $115 million credit facility and entered into a $175 million credit facility with Citicorp USA, Inc., as Administrative Agent, Citibank, N.A., as Swing Line Bank, Barclays Bank PLC and The Huntington National Bank, as Co-Syndication Agents, Fifth Third Bank and Comerica Bank, as Co-Documentation Agents, and the lenders party thereto (our “$175 million credit facility”). Our $175 million credit facility became effective on July 19, 2010, the closing date of our initial public offering, and provides for a $115 million revolver and a $60 million term loan. We are required to make quarterly principal payments of $1.5 million on the term loan commencing on September 30, 2010 and continuing until the maturity date in 2014 when the remaining balance is to be paid. The revolver and term loan will mature in 2013 and 2014, respectively, and borrowings will bear interest at a variable rate per annum equal to, at our option, LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin are each defined in the credit agreement evidencing our $175 million credit facility).

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OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

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, loans or advances, make distributions to our unitholders, make dispositions or enter into sales and leasebacks, or enter into a merger or sale 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 (ratio of consolidated indebtedness to adjusted EBITDA) to no greater than 2.75x and limiting our interest coverage ratio (ratio of adjusted EBITDA to consolidated interest expense) to no less than 4.0x. In addition, we are not permitted under our $175 million credit facility to fund capital expenditures in any fiscal year in excess of certain specified amounts.

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

As of August 9, 2010, we had $83.0 million of borrowings outstanding under our $175 million credit facility.

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

NOTE 8: FAIR VALUE OF FINANCIAL INSTRUMENTS

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

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

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

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

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

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

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

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

9

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

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

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

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

We estimated the fair value of the interest rate cap agreement using calculations based on market rates.

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 its fair value due to the short maturity of these instruments.

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

Variable rate debt: The fair 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:

	June 30, 2010				December 31, 2009
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Fixed rate debt	$	14,958,000	$	14,311,000	$	4,982,000	$	4,952,000
Variable rate debt		96,306,000		96,306,000		90,729,000		90,729,000

NOTE 9: LONG-TERM INCENTIVE PLAN

Under our LTIP, we recognize compensation expense over the vesting period of the units, which is generally four years for each award. For the three month periods ended June 30, 2010 and 2009, our equity compensation expense was approximately $152,000 and $105,000, respectively. For the six month periods ended June 30, 2010 and 2009, our equity compensation expense was approximately $456,000 and $214,000. These amounts are included in selling, general and administrative expenses in our consolidated statements of operations. As of June 30, 2010 and December 31, 2009, approximately $1,028,000 and $840,000, respectively, of cost remained unamortized which we expect to recognize using the straight-line method over a remaining weighted average period of one year.

10

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

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

				Weighted
				Average
				Grant
				Date Fair
	Units			Value
Unvested balance at December 31, 2009		143,933		$	6.48
Granted		67,779		$	9.57
Issued		(21,201	)	$	8.11
Surrendered		(10,428	)	$	7.62
Unvested balance at June 30, 2010		180,083		$	7.38

The value of LTIP units vested during the six-month periods ended June 30, 2010 and 2009 was $244,000 and $83,000, respectively. No LTIP units vested during the three-month periods ended June 30, 2010 and 2009.

NOTE 10: EARNINGS PER UNIT

For purposes of our earnings per unit calculation, we have applied the two-class method. The classes of units are our limited partner and general partner units. All outstanding units share pro rata in income allocations and distributions and our general partner has sole voting rights. Limited partner units have been separated into Class A and Class B to prepare for a potential transaction such as an initial public offering.

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 is adjusted to include phantom units that have not yet vested and that will convert to Class A units upon vesting. In years of a loss, the phantom units are not included in the earnings per unit calculation.

General Partner Units: Basic earnings per unit are computed by dividing net income attributable to our 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.

11

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(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 June 30,					Six Months Ended June 30,
	2010			2009		2010			2009
	(in thousands except unit and per unit amounts)
Limited partner units
Average units outstanding:
Basic		11,985,748			10,733,696		11,979,621			10,729,239
Effect of unit-based awards		n/a			23,336		n/a			21,401
Diluted		11,985,748			10,757,032		11,979,621			10,750,640
Net income attributable to limited partners
Basic	$	(2,065	)	$	5,340	$	(2,346	)	$	14,536
Diluted	$	(2,065	)	$	5,340	$	(2,346	)	$	14,536
Earnings per limited partner unit
Basic	$	(0.17	)	$	0.50	$	(0.20	)	$	1.35
Diluted	$	(0.17	)	$	0.50	$	(0.20	)	$	1.35
General partner units
Average units outstanding:
Basic and diluted		244,607			217,867		243,454			217,867
Net income attributable to general partner
Basic	$	(42	)	$	108	$	(48	)	$	295
Diluted	$	(42	)	$	108	$	(48	)	$	295
Earnings per general partner unit
Basic	$	(0.17	)	$	0.50	$	(0.20	)	$	1.35
Diluted	$	(0.17	)	$	0.50	$	(0.20	)	$	1.35

The computation of earnings per unit above reflects the impact of the unit split on July 19, 2010 as discussed in Note 15. However, the computation excludes additional units issued in our initial public offering on July 19, 2010.

NOTE 11: COMMITMENTS AND CONTINGENCIES

Coal Sales Contracts

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

Purchase Commitments

We use independent contractors to mine some of our coal at a few of our mines. We also purchase coal 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 June 30, 2010, we expect this contract to continue beyond five years. Additionally, we buy coal on the spot market, and the cost of that coal is dependent upon the market price and quality of the coal. Supply disruptions could impair our ability to fill customer orders or require us to purchase coal from other sources at a higher cost to us in order to satisfy these orders.

12

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

Transportation

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

Defined Contribution Pension Plan and 401(k) Plan

At June 30, 2010, we had an obligation to pay our GP for the purpose of funding our GP’s commitments to our former money purchase pension plan and new 401(k) plan in the amount of $2,295,000. Of this amount, $1,388,000 related to our former money purchase pension plan for plan year 2009 and was paid in July 2010. The remainder of $907,000 is related to our new 401(k) plan for plan year 2010 and is expected to be paid by September 2011. The money purchase pension plan was terminated on December 31, 2009 and all funds have been transferred to our new 401(k) plan effective January 1, 2010.

Performance Bonds and Guarantees

As of June 30, 2010, we had $33,250,000 in surety bonds and $14,000 in cash bonds outstanding to secure certain reclamation obligations. Additionally, as of June 30, 2010, we had letters of credit outstanding in support of these surety bonds of $6,925,000 and also a letter of credit of $1,320,000 guaranteeing an equipment operating lease that was paid off in full with proceeds from our initial public offering subsequent to June 30, 2010. See Note 15 related to the purchase of all of our equipment under operating leases. Further, as of June 30, 2010, we had certain road bonds of $645,000 outstanding and performance bonds outstanding of $7,330,000. Our management believes these bonds and letters of credit will expire without any claims or payments thereon and thus any subrogation or other rights with respect thereto will not have a material adverse effect on our financial position, liquidity or operations.

Legal

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

Guarantees

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

NOTE 12: RELATED PARTY TRANSACTIONS

In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (the “Services Agreement”) with our GP. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Pursuant to the Services Agreement, we reimbursed our GP for costs primarily related to payroll for all the periods after August 24, 2007, of which $3,561,000 and $2,504,000 were included in our accounts payable at June 30, 2010 and December 31, 2009, respectively. These amounts include amounts payable for funding the money purchase pension plan and 401(k) plan for plan years 2009 and 2010, respectively.

13

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

Also in connection with our formation in August 2007, Oxford Mining entered into an advisory services agreement (the “Advisory Agreement”) with certain affiliates of AIM Oxford. The Advisory Agreement runs for a term of ten years until August 2017, subject to earlier termination at any time by the AIM Oxford affiliates. Under the terms of the Advisory Agreement, the AIM Oxford affiliates have 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 consist 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 are rendered at the reasonable request of Oxford Mining. The basic annual fee under the Advisory Agreement was $250,000 for 2008 and for 2009 and each year thereafter increased based on the percentage increase in gross revenues. Further fees are payable for additional significant services requested. Pursuant to the Advisory Agreement, advisory fees were $133,000 and $91,000 for the three-month periods ended June 30, 2010 and 2009, respectively, and $210,000 and $154,000 for the six-month periods ended June 30, 2010 and 2009, respectively. The Advisory Agreement was terminated with a termination payment subsequent to June 30, 2010. See subsequent events Note 15 for further details of the Advisory Agreement termination.

Contract services were provided to Tunnell Hill Reclamation, LLC, a company with common owners, in the amount of $339,000 and $71,000 for the three-month periods ended June 30, 2010 and 2009, respectively, and $545,000 and $143,000 for the six-month periods ended June 30, 2010 and 2009, respectively. Accounts receivable were $231,000 and $70,000 from Tunnell Hill at June 30, 2010 and December 31, 2009, respectively.

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

NOTE 13: SUPPLEMENTAL CASH FLOW INFORMATION

	Six Months Ended June 30,
	2010		2009
Cash paid for:
Interest	$	4,291,000	$	3,178,000
Noncash investing activities:
Purchases of property and equipment financed through accounts payable		14,862,000		2,165,000
Purchase of coal reserves by note payable		11,858,000		1,387,000
Purchase of coal reserves through accounts payable		850,000		—
Mine development financed through accounts payable		520,000		—
Royalty advances financed through accounts payable		50,000		—
Noncash financing activities:
Market value of common units vested in LTIP		288,000		83,000

NOTE 14: 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 companies share customers and a particular customer may receive coal from any one of the operating subsidiaries.

14

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

NOTE 15: SUBSEQUENT EVENTS

The following represents material events that have occurred subsequent to June 30, 2010 and through the date the financial statements were issued.

Purchase of Coal Reserves

On June 22, 2010, our 51% owned subsidiary, Harrison Resources, entered into an agreement with CONSOL to purchase approximately 3.4 million tons of coal reserves located near the Harrison mining complex. This purchase closed on August 9, 2010 and is discussed further in Note 7.

Initial Public Offering

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

Upon closing of our initial public offering on July 19, 2010, we issued 8,750,000 of the common units that were registered at a price per unit of $18.50 (with an additional 1,312,500 common units that were registered being reserved for issuance upon the exercise of the underwriters’ over-allotment option). The aggregate offering amount of the securities sold pursuant to the Registration Statement was $161,875,000.

After deducting underwriting discounts and commissions of approximately $10.5 million paid to the underwriters, estimated offering expenses of approximately $3.1 million and a structuring fee of approximately $0.8 million, the net proceeds from our initial public offering were approximately $147.4 million. We used all of the net offering proceeds from our initial public offering for the uses described in the Prospectus. These uses included the following:

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

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

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

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

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

Unit Split

Immediately prior to the closing of our 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 accompanying presentations of the consolidated balance sheets, statements of partners’ capital and earnings per unit reflect the effect of this unit split.

15

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
(CONTINUED)

Credit Facility

In connection with our initial public offering, we paid off the amounts outstanding under our $115 million credit facility and our $175 million credit facility became effective. Our $175 million credit facility provides for a $115 million revolver and a $60 million term loan. The revolver and term loan will mature in 2013 and 2014, respectively, and borrowings will bear interest at a variable rate per annum equal to, at our option, LIBOR or the Base Rate, as the case may be, plus the Applicable Margin (LIBOR, Base Rate and Applicable Margin are each defined in the credit agreement evidencing our $175 million credit facility). See Note 7 for further information regarding our $175 million credit facility. As of August 9, 2010, we had $83.0 million of borrowings outstanding under our $175 million credit facility

Harrison Resources Distribution

Our majority owned subsidiary Harrison Resources made a $2,000,000 distribution in August 2010 of which we and the noncontrolling interest holder received $1,020,000 and $980,000, respectively.

Interest Rate Swap Agreement

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 amount declines over the term of the swap at a rate of $1.5 million each quarter. Under the swap agreement, we will pay interest at a monthly fixed rate of 1.39% and will receive interest at a variable rate equal to LIBOR (with a 1% floor) based on the notional amount. The swap is effective August 9, 2010.

16

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the unaudited condensed consolidated financial statements and the related notes thereto included elsewhere in this Quarterly Report on Form 10-Q and the audited consolidated financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations for the year ended December 31, 2009 included in our final prospectus dated July 15, 2009 (the “Prospectus”) and filed with the 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 report contains certain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements included in this report that are not historical facts, that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements are made by us based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in these statements. Any differences could be caused by a number of factors, including, but not limited to:

• our productivity levels, margins earned and the level of our 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 to existing contracts, or other failures to perform;

• our ability to acquire additional coal reserves;

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

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

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

17

• legislation, 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 Harrison Resources, LLC (“Harrison Resources”), and the ability of Harrison Resources to acquire additional reserves on economical terms from CONSOL Energy in the future;

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

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

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

• risks associated with major mine-related accidents;

• results of litigation, including claims not yet asserted;

• our ability to attract and retain key management personnel;

• greater than expected shortage of skilled labor;

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

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

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

18

Overview

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

We operate in a single business segment and have three operating subsidiaries, Oxford Mining Company, LLC (“Oxford Mining”), Oxford Mining Company-Kentucky, LLC and Harrison Resources. All 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 17 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 second quarter of 2010, we produced 1.8 million tons of coal and sold 2.1 million tons of coal, including 0.2 million tons of purchased coal. We purchase coal in the open market and under contracts to satisfy a portion of our sales commitments. During each of the last two quarters, we produced 0.4 million tons of coal from the reserves we acquired in western Kentucky from Phoenix Coal on September 30, 2009. As is customary in the coal industry, we have entered into long-term coal sales contracts with many of our customers.

Recent Developments

We recently completed the initial public offering of our common units and closed our $175 million credit facility as described below. With the successful completion of these transactions we have increased our financial flexibility, which we believe will help us execute our strategic plan. Specifically, we reinvested a portion of the net proceeds from these transactions to drive per ton costs lower and increase earnings and cash flow in future periods. At the close of these transactions, we bought out of all of our equipment operating leases. As a result, our operating expenses will be reduced by approximately $2 million per quarter beginning in the third quarter of 2010. We have also invested in additional major mining equipment, some of which will enable us to reduce operating costs beginning in the third quarter of 2010 and the remainder of which will enable us to realize benefits beginning in 2011.

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, estimated offering expenses of approximately $3.1 million and a structuring fee of approximately $0.8 million, the net proceeds from our initial public offering were approximately $147.4 million. We used all of the net offering proceeds from our initial public offering for the uses described in the Prospectus. These uses included the following:

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

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

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

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

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

19

Credit Facility

In connection with our initial public offering, we paid off the amounts outstanding under our 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 revolver and a $60 million term loan. As of August 9, 2010, we had $83.0 million of borrowings outstanding under our $175 million credit facility.

We utilized a portion of the draws from our $175 million credit facility for the purchase of equipment under operating leases as well as to purchase additional major mining equipment.

Interest Rate Swap Agreement

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 amount declines over the term of the swap at a rate of $1.5 million each quarter. Under the swap agreement, we will pay interest at a monthly fixed rate of 1.39% and will receive interest at a variable rate equal to LIBOR (with a 1% floor), based on the notional amount. The swap is effective August 9, 2010.

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 purchased coal; and

• our adjusted EBITDA, 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. 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 fixed prices, over the contract term. Two of our long-term coal sales contracts have price re-openers that provide for a market-based adjustment to the initial price every three years. These contracts will terminate if we cannot agree upon a market-based price with the customer. In addition, most of our long-term coal sales contracts have full or partial cost pass through or inflation adjustment provisions. Cost pass through provisions typically provide for increases in our sales prices in rising operating cost environments and for decreases in our sales prices in declining operating cost environments. Inflation adjustment provisions typically provide some protection in rising operating cost environments.

20

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, coal sales volume and average sales prices per ton for the periods indicated:

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(tons in thousands)
Tons of coal produced		1,838			1,279			3,643			2,675
Tons of coal purchased		238			40			495			232
Tons of coal sold		2,071			1,280			4,106			2,838
Tons sold under long-term contracts(1)		97.6	%		98.5	%		98.2	%		98.0	%
Average sales price per ton	$	37.94		$	41.32		$	37.83		$	42.37

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(tons in thousands)
Average sales price per ton	$	37.94	$	41.32	$	37.83	$	42.37
Cost of coal sales per ton produced	$	32.27	$	28.27	$	31.43	$	28.78
Tons of coal produced		1,838		1,279		3,643		2,675

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 0.6 million tons of coal in 2010 and 0.4 million tons of coal each year thereafter until the coal reserves covered by the contract are depleted. Based on the proven and probable coal reserves in place at December 31, 2009, we expect this contract to continue beyond five years.

We evaluate our cost of purchased coal on a per ton basis. For the three months and six months ended June 30, 2010, we sold 0.2 million tons and 0.5 million tons of purchased coal, respectively. The following table provides summary information for the dates indicated for our cost of purchased coal per ton and the tons of purchased coal:

	Three Months Ended June 30,				Six Months Ended June 30,
	2010		2009		2010		2009
	(tons in thousands)
Average sales price per ton	$	37.94	$	41.32	$	37.83	$	42.37
Cost of purchased coal sales per ton	$	29.32	$	33.29	$	29.94	$	42.42
Tons of coal purchased		238		40		495		232

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Adjusted EBITDA

Adjusted EBITDA represents net income (loss) attributable to our unitholders before interest, taxes, DD&A, gain from purchase of a business, amortization of below-market coal sales contracts, non-cash equity compensation expense and the change in the fair value of our future asset retirement obligation (“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 “— Summary” for reconciliations of adjusted EBITDA to net income (loss) attributable to our unitholders 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 provisions or inflation adjustment provisions.

For 2010, 2011, 2012 and 2013, we currently have long-term coal sales contracts that represent 97.6%, 101.5%, 81.0% and 50.7%, respectively, of our 2010 estimated coal sales of 8.2 million tons. During 2010, 2011, 2012 and 2013, we have committed to deliver 8.0 million tons, 8.3 million tons, 6.7 million tons and 4.2 million tons of coal, respectively, under long-term coal sales contracts. These amounts include contracts with re-openers as described below. The current term of our long-term coal sales contract with American Electric Power Service Corporation, or AEP, runs through 2012 but it can be extended for two additional three year terms if AEP gives us six months advance notice of its election to extend the contract. For each extension term, we will negotiate with AEP to agree upon a market-based price based on similar term contracts. In addition, the contract contains substantial cost pass through and inflation adjustment provisions. If AEP elects to extend this contract, we will be committed to deliver an additional 2.0 million tons in 2013, and our 2013 coal sales under long-term coal sales contracts, as a percentage of 2010 estimated coal sales, would increase to 75.0%.

The terms of our coal sales contracts result from competitive bidding and negotiations with customers. As a result, the terms of these contracts — including price re-openers, coal quality requirements, quantity parameters, permitted sources of supply, effects of future regulatory changes, extension options, force majeure, termination and assignment provisions — vary by customer. However, most of our long-term coal sales contracts have full or partial cost pass through provisions or inflation adjustment provisions. For 2010, 2011, 2012 and 2013, 62%, 74%, 91% and 100% of the coal, respectively, that we have committed to deliver under our current long-term coal sales contracts are subject to full or partial cost pass through or inflation adjustment provisions. Cost pass through provisions increase or decrease our coal sales price for all or a specified percentage of changes in the cost of fuel, explosives and, in certain cases, labor. Inflation adjustment provisions adjust the initial contract price over the term of the contract either by a specific percentage or a percentage determined by reference to various inflation related indices.

Certain of our long-term coal sales contracts 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 a fixed price, 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 a fixed price, an additional 200,000 tons of coal per half year. We are currently negotiating with AEP to reduce the quantity of coal that we deliver to AEP under our long-term coal sales contract by approximately 280,000 tons in the second half of 2010 and by approximately 150,000 tons and 400,000 tons, respectively, in 2011 and 2012. In addition, we expect this amendment will eliminate AEP’s right to purchase its half-year option tons and its monthly option tons, be replaced with quarterly option tons in a lesser aggregate amount per calendar year for any extension period through 2020. In light of these negotiations, we do not believe that AEP will elect its half-year option tons or its monthly option tons during the next twelve months. If AEP were to elect its option tons, we believe that we will have the production capacity to produce and deliver those tons profitably, as the coal prices under the contract through 2012 are significantly higher than our production costs and the contract contains substantial cost pass through and inflation adjustment provisions.

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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 under the terms of the contract, we could be obligated to deliver coal to those customers at a price that is below the market price for coal on the date the option is exercised. For 2010, 2011, 2012 and 2013, we have outstanding option tons of 0.7 million, 1.0 million, 0.9 million and 0.2 million, respectively. If our customers do elect to receive these option tons, we believe we will have the operating flexibility to meet these requirements through increased production at our mining complexes.

Two of our long-term coal sales contracts contain provisions that provide for price re-openers. These price-reopeners provide for market-based adjustments to the initial contract price every three years. These contracts will terminate if we cannot agree upon a market-based price with the customer. For 2011, 2012 and 2013, 0.4 million tons, 0.4 million tons and 0.6 million tons of coal, respectively, that we have committed to deliver under our long-term coal sales contracts are subject to price re-opener provisions.

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

Results of Operations

Factors Affecting the Comparability of Our Results of Operations

The comparability of our results of operations is impacted by (i) the Phoenix Coal acquisition on September 30, 2009 and (ii) an amendment to a long-term coal sales contract with a major customer in December 2008.

We acquired all of Phoenix Coal’s active surface mining operations on September 30, 2009. This acquisition increased our coal production for the three months and six months ended June 30, 2010 by 28.0% and 28.3%, respectively, compared to the same periods in 2009.

In December 2008, we and one of our major customers agreed to amend a long-term coal sales contract. As part of this amendment, we agreed to give this customer two additional three-year term extension options with market-based price adjustments for each extension. In exchange, we received a substantial one-time increase in the price per ton of coal for 2009 along with inflation adjusters and certain cost pass through provisions for the complete term of the contract, which expires at the end of 2012. This price increase contributed $13.25 million to revenues and adjusted EBITDA in 2009.

Summary

The following table presents certain of our historical consolidated financial data for the periods indicated.

Adjusted EBITDA is not defined under GAAP. The GAAP measure most directly comparable to adjusted EBITDA is net income (loss) attributable to Oxford Resource Partners, LP unitholders. Our non-GAAP financial measure of adjusted EBITDA should not be considered as an alternative to the GAAP measure of net income (loss) attributable to Oxford Resource Partners, LP unitholders. Adjusted EBITDA has important limitations as an analytical tool because it excludes some, but not all, items that affect net income. You should not consider adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because adjusted EBITDA may be defined differently by other companies in our industry, our definition of adjusted EBITDA may not be comparable to the similarly titled measure of other companies, thereby diminishing its utility.

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Management compensates for the limitations of adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measure, understanding the differences between adjusted EBITDA compared to net income attributable to our unitholders and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measure that our management uses in evaluating our operating results.

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
	(in thousands)
Statement of Operations Data:
Revenue:
Coal Sales	$	78,571		$	52,882		$	155,327		$	120,259
Transportation revenue		9,841			7,012			19,371			15,672
Royalty and non-coal revenue		1,736			1,396			3,510			3,798
Total revenue		90,148			61,290			178,208			139,729
Costs and expenses:
Cost of coal sales (excluding DD&A, shown separately)		59,311			36,152			114,497			76,977
Cost of purchased coal		6,968			1,331			14,827			9,836
Cost of transportation		9,841			7,012			19,371			15,672
Depreciation, depletion, and amortization		9,555			5,670			18,332			11,358
Selling, general and administrative expenses		2,867			2,993			6,402			6,094
Total costs and expenses		88,542			53,158			173,429			119,937
Income from operations		1,606			8,132			4,779			19,792
Interest income		7			11			8			22
Interest expense		(2,040	)		(1,392	)		(3,873	)		(2,515	)
Net income (loss)		(427	)		6,751			914			17,299
Net loss attributable to noncontrolling interest		(1,680	)		(1,303	)		(3,308	)		(2,468	)
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(2,107	)	$	5,448		$	(2,394	)	$	14,831
Other Financial Data:
Adjusted EBITDA(1)	$	9,454		$	11,489		$	19,493		$	28,271

⁽¹⁾ Adjusted EBITDA represents net income (loss) attributable to our unitholders before interest, taxes, DD&A, gain from purchase of a business, amortization of below-market coal sales contracts, non-cash equity compensation expense and the change in our ARO. The change in our ARO represents the change in fair value of our future ARO that we are required to calculate on a present value basis which is included in reclamation expense in our financial statements.

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

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

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

• our compliance with certain credit facility financial covenants; and

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

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Adjusted EBITDA should not be considered 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. Adjusted EBITDA excludes some, but not all, items that affect net income (loss) attributable to our unitholders, income from operations and cash flows, and this measure may vary among other companies. Therefore, adjusted EBITDA as presented may not be comparable to the similarly titled measure of other companies. The following table presents a reconciliation of adjusted EBITDA to net income (loss) attributable to our unitholders for each of the periods indicated:

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(2,107	)	$	5,448		$	(2,394	)	$	14,831
PLUS:
Depreciation, depletion, and amortization		9,555			5,670			18,332			11,358
Interest expense		2,040			1,392			3,873			2,515
Non-cash equity compensation expense		152			105			456			214
Non-cash portion of reclamation expenses		221			(1,115	)		259			(625	)
LESS:
Interest income		7			11			8			22
Amortization of below-market coal sales contracts		400			—			1,025			—
Adjusted EBITDA	$	9,454		$	11,489		$	19,493		$	28,271

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

Overview.We reported net loss attributable to our unitholders of $2.1 million for the three months ended June 30, 2010 compared to net income attributable to our unitholders of $5.4 million for the three months ended June 30, 2009. Our adjusted EBITDA decreased to $9.5 million in the second quarter of 2010 from $11.5 million in the second quarter of 2009. Our second quarter 2010 performance reflected the contribution from the assets acquired in western Kentucky from Phoenix Coal on September 30, 2009 where we experienced increased operating costs as a result of the closure of two fully depleted mines, the opening of a new mine and weather related issues that disrupted production. Additionally, our second quarter results did not include a one-time price increase which positively impacted our net income and adjusted EBITDA for the second quarter of 2009 by $3.2 million. Excluding the non-recurring price increase, results for the second quarter of 2009 would have reflected net income attributable to our unitholders of $2.3 million and adjusted EBITDA of $8.3 million. This would have resulted in a year over year increase in our adjusted EBITDA of approximately 13.9% compared to the second quarter of 2009, as adjusted.

Coal Production.Our tons of coal produced increased 43.7% to 1.8 million tons in the second quarter of 2010 from 1.3 million tons in the second quarter of 2009. This increase was primarily due to the inclusion of 0.4 million tons of coal we produced in the second quarter of 2010 from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009, as well as a 15.7% increase in production from our Ohio mining complexes.

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Sales Volume.Our tons of coal sold increased 61.8% to 2.1 million tons in the second quarter of 2010 from 1.3 million tons in the second quarter of 2009. This increase was primarily attributable to the 0.5 million tons of coal we sold in the second quarter of 2010 from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009 and 0.3 million tons of higher coal sales to our major utility customers, partially offset by a decline in sales to our industrial customers.

Average Sales Price Per Ton. Our average sales price per ton decreased 8.2% to $37.94 in the second quarter of 2010 from $41.32 in the second quarter of 2009. This $3.38 per ton decrease was primarily the result of a non-recurring price increase during 2009 from a major customer, the expiration of which accounted for approximately $2.49 of the decrease. Excluding this non-recurring price increase, our average sales price would have decreased by $0.89 per ton due to the effect of the lower priced legacy coal sales contracts that we assumed in the Phoenix Coal acquisition.

Coal Sales Revenue.Our coal sales revenue for the second quarter of 2010 increased by $25.7 million, or 48.6%, compared to the second quarter of 2009. This increase is primarily attributable to coal sales from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009 and higher sales to our major utility customers, partially offset by lower coal sales to our industrial customers during the second quarter of 2010 and the inclusion in the second quarter of 2009 of $3.2 million of revenue relating to the non-recurring price increase discussed above.

Royalty and Non-Coal Revenue. Our royalty and non-coal revenue includes our royalty revenue from our Tusky mining complex, 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 $1.7 million in the second quarter of 2010 from $1.4 million in the second quarter of 2009. This increase was primarily attributable to an increase in fees for providing earth moving services and fees relating to a short-term barge handling contract.

Cost of Coal Sales (Excluding DD&A).Cost of coal sales (excluding DD&A) increased 64.1% to $59.3 million in the second quarter of 2010 from $36.2 million in the second quarter of 2009. This increase was primarily attributable to the increase of 43.7% in our tons produced and higher operating costs per ton associated with our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009. Our average cost of coal sales per ton increased by 14.2% to $32.27 in the second quarter of 2010 compared to $28.27 per ton in the second quarter of 2009. Excluding our Muhlenberg County complex, our cost of coal sales per ton would have increased by approximately 8.0% from the same period in the prior year primarily as a result of higher reclamation, repair and maintenance and explosives expenses at our Ohio mining complexes. With respect to our newly acquired Muhlenberg County complex, we closed two mines that were fully depleted and opened a new mine that began producing in May 2010. The closure of the two mines and associated reclamation costs coupled with opening a new mine and weather related issues that disrupted production, negatively impacted our per ton operating costs. However, with the new mine fully operational at expected lower operating costs than we experienced with the two depleted mines, we expect our per ton operating costs to decrease in the future.

Cost of Purchased Coal. Cost of purchased coal increased to $7.0 million in the second quarter of 2010 from $1.3 million in the second quarter of 2009. This increase is primarily attributable to higher purchases made under a lower priced long-term supply contract assumed in the Phoenix Coal acquisition. Our average cost of purchased coal per ton decreased by 11.9% to $29.32 per ton in the second quarter of 2010 due to a significant portion of our purchases in that quarter being supplied under the lower priced supply contract compared to a higher percentage of higher-priced spot market purchases in the second quarter of 2009.

Depreciation, Depletion and Amortization (DD&A).DD&A expense in the second quarter of 2010 was $9.6 million compared to $5.7 million in the second quarter of 2009, an increase of $3.9 million. Approximately $2.1 million of this increase relates to higher DD&A expense associated with the assets we acquired in the Phoenix Coal acquisition and the remaining increase of $1.9 million relates primarily to depreciation on equipment placed in service in late 2009 and the first half of 2010.

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Selling, General and Administrative Expenses (SG&A).SG&A expenses for the second quarter of 2010 were $2.9 million compared to $3.0 million for the second quarter of 2009, a decrease of $0.1 million. This decrease is due to lower professional fees of $0.5 million partially offset by $0.3 million of additional administrative expenses for supporting our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009 and $0.1 million of office costs including rental expense relating to our new corporate office in Columbus, Ohio.

Transportation Revenue and Expenses. Our transportation expenses represent the cost to transport our coal by truck or rail from our mines to our river terminals, our rail loading facilities and our customers. Our long-term coal sales contracts have these transportation costs built into the price of our coal. Our transportation revenue reflects the portion of our total revenues that is attributable to reimbursements for transportation expenses. Our transportation revenue fluctuates based on a number of factors, including the volume of coal we transport by truck or rail under those contracts and the related transportation costs. Our transportation revenue and expenses for the second quarter of 2010 increased 40.3% compared to the second quarter of 2009 due to higher coal sales.

Interest Expense. Interest expense for the second quarter of 2010 was $2.0 million compared to $1.4 million for the second quarter of 2009, an increase of $0.6 million. This increase was primarily attributable to higher effective interest rates in the second quarter of 2010 as a result of an amendment to our $115 million credit facility in September 2009, coupled with higher borrowings outstanding during the second quarter of 2010 due to the debt that we incurred to acquire the Phoenix Coal assets.

Net Income Attributable to Noncontrolling Interest. In 2007, we entered into a joint venture, Harrison Resources, with CONSOL Energy to mine surface coal reserves purchased from CONSOL Energy. We own 51.0% of Harrison Resources and CONSOL Energy owns the remaining 49.0% indirectly through one of its subsidiaries. We manage all of the operations of, and perform all of the contract mining and marketing services for, Harrison Resources. Net income attributable to noncontrolling interest relates to the 49.0% of Harrison Resources that we do not own. For the second quarter of 2010, net income attributable to the noncontrolling interest was $1.7 million compared to $1.3 million for the second quarter of 2009. This increase of $0.4 million is primarily attributable to an increase of 54.1% in tons of coal sold by Harrison Resources in the second quarter of 2010 compared to the second quarter of 2009 partially offset by lower average sales prices.

Six Months Ended June 30, 2010 Compared to Six Months Ended June 30, 2009

Overview.We reported net loss attributable to our unitholders of $2.4 million for the first half of 2010 compared to net income attributable to our unitholders of $14.8 million for the first half of 2009. Our adjusted EBITDA decreased to $19.5 million in the first half of 2010 from $28.3 million in the first half of 2009. Our first half 2010 performance reflected the contribution from the assets acquired in western Kentucky from Phoenix Coal on September 30, 2009 where we experienced increased operating costs as a result of the closure of two fully depleted mines, the opening of a new mine and weather related issues that disrupted production. Additionally, our first half results did not include a one-time price increase which positively impacted our net income and adjusted EBITDA for the first half of 2009 by $7.5 million. Excluding the non-recurring price increase, results for the first half of 2009 would have reflected net income attributable to our unitholders of $7.3 million and adjusted EBITDA of $20.7 million. This would have resulted in a year over year decrease in our adjusted EBITDA of approximately 6.0% compared to the first half of 2009, as adjusted.

Coal Production.Our tons of coal produced increased 36.2% to 3.6 million tons in the first half of 2010 from 2.7 million tons in the first half of 2009. This increase was primarily due to the inclusion of 0.8 million tons of coal we produced in the first six months of 2010 from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009, as well as a 7.9% increase in production from our Ohio mining complexes.

Sales Volume.Our tons of coal sold increased 44.7% to 4.1 million tons in the first six months of 2010 from 2.8 million tons in the first six months of 2009. This increase was primarily attributable to the 1.1 million tons of coal we sold in the first half of 2010 from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009 and higher volumes of coal sales to our major utility customers, partially offset by a decline in sales to our industrial customers.

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Average Sales Price Per Ton.Our average sales price per ton decreased 10.7% to $37.83 in the first six months of 2010 from $42.37 in the first six months of 2009. This $4.54 per ton decrease was primarily the result of a non-recurring price increase during 2009 from a major customer, the expiration of which accounted for over 58% of the decrease. Excluding this non-recurring price increase, our average sales price would have decreased by $1.89 per ton due to the effect of the lower priced legacy coal sales contracts that we assumed in the Phoenix Coal acquisition.

Coal Sales Revenue. Our coal sales revenue for the first six months of 2010 increased by $35.1 million, or 29.2%, compared to the first six months of 2009. This increase is primarily attributable to coal sales from our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009 and higher sales to our major utility customers, partially offset by lower coal sales to our industrial customers during the first half of 2010 and the inclusion in the first half of 2009 of $7.5 million of revenue relating to the non-recurring price increase discussed above.

Royalty and Non-Coal Revenue. Our royalty and non-coal revenue decreased to $3.5 million in the first six months of 2010 from $3.8 million in the first six months of 2009. This decline was primarily attributable to a decrease of $0.9 million in royalty revenue in the first half of 2010, partially offset by an increase in fees for providing earth moving services and fees relating to a new barge handling contract. The decrease in royalty revenue was due to lower sales prices and volumes associated with our underground coal reserves that are leased to a third party.

Cost of Coal Sales (Excluding DD&A).Cost of coal sales (excluding DD&A) increased 48.7% to $114.5 million in the first six months of 2010 from $77.0 million in the first six months of 2009. This increase was primarily attributable to the increase of 36.2% in our tons produced and higher operating costs per ton associated with our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009. Our average cost of coal sales per ton increased by 9.2% to $31.43 in the first half of 2010 compared to $28.78 per ton in the first half of 2009. Excluding our Muhlenberg County complex, our cost of coal sales per ton would have increased by approximately 2.8% from the same period in the prior year primarily as a result of higher reclamation, repair and maintenance and explosives expenses at our Ohio mining complexes. With respect to our newly acquired Muhlenberg County complex, we closed two mines that were fully depleted and opened a new mine that began producing in May 2010. The closure of the two mines and associated reclamation costs coupled with opening a new mine and weather related issues that disrupted production, negatively impacted our per ton operating costs. However, with the new mine fully operational at expected lower operating costs than we experienced with the two depleted mines, we expect our per ton operating costs to decrease in the future.

Cost of Purchased Coal. Cost of purchased coal increased to $14.8 million in the first half of 2010 from $9.8 million in the first half of 2009. This increase is primarily attributable to higher purchases made under a lower priced long-term supply contract assumed in the Phoenix Coal acquisition. Our average cost of purchased coal per ton decreased by 29.4% to $29.94 per ton in the first half of 2010 due to a significant portion of our purchases in that period being supplied under the lower priced supply contract compared to a higher percentage of higher-priced spot market purchases in the first half of 2009.

Depreciation, Depletion and Amortization (DD&A).DD&A expense in the first half of 2010 was $18.3 million compared to $11.4 million in the first half of 2009, an increase of $6.9 million. Approximately $4.0 million of this increase relates to higher DD&A expense associated with assets we acquired in the Phoenix Coal acquisition and the remaining increase of $2.9 million relates primarily to depreciation on equipment placed in service in late 2009 and the first half of 2010.

Selling, General and Administrative Expenses (SG&A).SG&A expenses for the first six months of 2010 were $6.4 million compared to $6.1 million for the first six months of 2009, an increase of $0.3 million. This increase is due primarily to $0.6 million of additional administrative expenses for supporting our Muhlenberg County complex that we acquired from Phoenix Coal on September 30, 2009, partially offset by lower professional fees.

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Transportation Revenue and Expenses.Our transportation revenue and expenses for the first half of 2010 increased 23.6% compared to the first half of 2009 due to higher coal sales.

Interest Expense. Interest expense for the first six months of 2010 was $3.9 million compared to $2.5 million for the first six months of 2009, an increase of $1.4 million. This increase was primarily attributable to higher effective interest rates in the first half of 2010 as a result of an amendment to our $115 million credit facility in September 2009, coupled with higher borrowings outstanding during the first half of 2010 due to the debt that we incurred to acquire the Phoenix Coal assets.

Net Income Attributable to Noncontrolling Interest.For the first six months of 2010, net income attributable to the noncontrolling interest was $3.3 million compared to $2.5 million for the first six months of 2009. This increase of $0.8 million is primarily attributable to an increase of 57.7% in tons of coal sold by Harrison Resources in the first half of 2010 compared to the first half of 2009.

Liquidity and Capital Resources

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

The principal indicators of our liquidity at June 30, 2010 were our cash on hand and availability under our $115 million credit facility as discussed below. As of June 30, 2010, our available liquidity was $2.7 million, including cash on hand of $1.5 million and $1.2 million available under our $115 million credit facility. Subsequent to June 30, 2010 and concurrent with closing of our initial public offering, we closed on our $175 million credit facility, which is composed of a $115 million revolver and a $60 million term loan. As of August 9, 2010, we have approximately $40 million of borrowing capacity under our $175 million credit facility.

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

• our working capital;

• cash generated from operations;

• borrowing capacity 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 12 months, including operating expenditures, debt service obligations, contingencies and anticipated capital expenditures, and to fund our quarterly distributions to unitholders.

Cash Flows

The following table reflects cash flows for the applicable periods:

	Six Months Ended June 30,
	2010			2009
Net cash provided by (used in)
Operating activities	$	14,693		$	10,371
Investing activities	$	(15,965	)	$	(18,857	)
Financing activities	$	(608	)	$	(2,049	)

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Net cash provided by operating activities was $14.7 million for the first six months of 2010, an increase of $4.3 million from net cash provided by operating activities of $10.4 million for the first six months of 2009. Our lower net income attributable to our unitholders was offset by higher non-cash adjustments and favorable working capital changes for the first half of 2010.

Net cash used in investing activities was $16.0 million for the first half of 2010 compared to $18.9 million for the first half of 2009. This $2.9 million decrease was primarily attributable to a decrease in the purchases of property and equipment in the first six months of 2010 compared to the first six months of 2009.

Net cash used in financing activities was $0.6 million for the first six months of 2010 compared to $2.0 million for the first six months of 2009. This change of $1.4 million was primarily attributable to higher net borrowings in the first six months of 2010 partially offset by higher distributions to our partners during the same period.

Credit Facility

In connection with our initial public offering, we paid off the amounts outstanding under our 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 we entered into a $175 million credit facility. Our $175 million credit facility provides for a $115 million revolver and a $60 million term loan. As of August 9, 2010, we had borrowings of $83.0 million outstanding under our $175 million credit facility.

We utilized a portion of the borrowings from 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 to reduce operating lease expenses beginning in the third quarter of 2010.

Capital Expenditures

Our mining operations require investments to expand, upgrade or enhance existing operations and to comply with environmental regulations. Our capital requirements primarily consist of maintenance capital expenditures and expansion capital expenditures. Maintenance capital expenditures are those capital expenditures required to maintain or replace, including over the long term, our operating capacity, asset base or operating income. Expansion capital expenditures are those capital expenditures made to increase our long-term operating capacity, asset base or operating income. Our partnership agreement, as amended on July 19, 2010, divides maintenance capital expenditures into two categories — reserve replacement expenditures and other maintenance capital expenditures. Examples of reserve replacement expenditures include cash expenditures for the purchase of fee interests in coal reserves and cash expenditures for advance royalties with respect to the acquisition of leasehold interests in coal reserves. Examples of other maintenance capital expenditures include capital expenditures associated with the refurbishment and replacement of equipment. Examples of expansion capital expenditures include the acquisition (by lease or otherwise) of reserves, equipment or a new mine or the expansion of an existing mine, to the extent such expenditures are incurred to increase our long-term operating capacity, asset base or operating income.

Off-Balance Sheet Arrangements

Federal and state laws require us to secure certain long-term obligations such as mine closure and reclamation costs and other obligations. We typically secure these obligations by using surety bonds, an off-balance sheet instrument, and we typically use bank letters of credit to secure our surety bonding obligations. As of June 30, 2010, we had approximately $33.3 million in surety bonds outstanding to secure the performance of our reclamation obligations, which were supported by approximately $6.9 million in letters of credit. As of June 30, 2010, we had approximately $7.3 million of performance bonds outstanding and $0.6 million of road bonds outstanding, none of which were secured by letters of credit. We also had a letter of credit of $1.3 million guaranteeing an operating lease that was paid off in full with proceeds from our initial public offering subsequent to June 30, 2010.

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Critical Accounting Policies

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

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.

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 risk.

Commodity Price Risk

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 long-term coal sales contracts of varying terms and durations, rather than through the use of derivative instruments.

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

Interest Rate Risk

We were exposed to interest rate risk as borrowings under our $115 million credit facility were and borrowings under our $175 million credit facility are at variable rates. On September 11, 2009, we entered into an interest rate cap agreement to hedge our exposure to rising interest rates during 2010. This agreement, which has an effective date of January 4, 2010 and a notional amount of $50.0 million, provides for a LIBOR interest rate cap of 2.0% using three-month LIBOR. The three-month LIBOR rate was 0.5369% as of June 30, 2010. We paid a fixed fee of $85,000 for this agreement which has quarterly settlement dates and matures on December 31, 2010. At June 30, 2010, the value of the interest rate cap was approximately zero. This value is recorded in other assets and the mark-to-market decrease in value of $1,000 is recorded to interest expense in our consolidated statements of operations for the second quarter of 2010. 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 amount declines over the term of the swap at a rate of $1.5 million each quarter. Under the swap agreement, we will pay interest at a monthly fixed rate of 1.39% and will receive interest at a variable rate equal to LIBOR (with a 1% floor) based on the notional amount. The swap is effective August 9, 2010.

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Item 4. Controls and Procedures

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the U.S. Securities and Exchange Commission (the “SEC”) is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act) was performed as of June 30, 2010. This evaluation was performed by our management, with the participation of our Chief Executive Officer and Chief Financial Officer. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that these controls and procedures are effective to ensure that the Partnership is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods, and during the quarterly period ended June 30, 2010 there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

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

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

Sales of Unregistered Securities.

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

Use of Proceeds.

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

Upon closing of our initial public offering on July 19, 2010, we issued 8,750,000 of the common units that were registered at a price per unit of $18.50 (with an additional 1,312,500 common units that were registered being reserved for issuance upon the exercise of the underwriters’ over-allotment option). The Registration Statement registered securities with a maximum aggregate offering price of $250,000,000. The aggregate offering amount of the securities sold pursuant to the Registration Statement was $161,875,000. In our initial public offering, we granted the underwriters a 30 day option to purchase up to 1,312,500 additional units. This option has not been exercised as of August 9, 2010. The proceeds from any exercise of the underwriters’ option to purchase additional common units will be used to redeem from C&T Coal and AIM Oxford that number of common units that corresponds to the number of common units issued upon such exercise.

After deducting underwriting discounts and commissions of approximately $10.5 million paid to the underwriters, estimated offering expenses of approximately $3.1 million and a structuring fee of approximately $0.8 million, the net proceeds from our initial public offering were approximately $147.4 million. We used all of the net offering proceeds from our initial public offering for the uses described in the final prospectus filed with the SEC pursuant to Rule 424(b) on July 15, 2010. These uses included the following:

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

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

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

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

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

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

Item 3. Defaults Upon Senior Securities

None.

Item 4. [Removed And Reserved]

Item 5. Other Information

Mine Safety

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

In 2010, in response to underground mine accidents, Congress expanded mine safety disclosure requirements pursuant to Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Act. In our second quarter, we received at least nine citations from the Mine Safety and Health Administration, or MSHA, for violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under Section 104 of the Mine Act from the following coal mines and MSHA ID numbers, respectively, as follows: one at Sexton #2, #33-04577; two at Hall’s Creek Mine, #15-18134; one at the Schoate Prep Plant, #15-19365; two at K.O. Mine, #15-19303; one at the Island Dock, #15-18912; one the Oxford Loading Dock, #33-02937; and one for Oxford Mining #2, #33-04213. The total dollar value of the proposed assessments from MSHA under the Mine Act for these citations is $3,414.

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

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Docket No./
Mine/MSHA ID#	Civil Penalty		Status
LAKE 2008-383 Oxford Mining #3 33-04336	$	1,400	Petition for civil penalty assessment for a miner not wearing a hard hat outside of the operating cab of his equipment. The Petition was served on June 6, 2008 and timely answered on July 3, 2008.
LAKE 2009-381-M Oxford Mining #2 33-04213	$	920	Petition for civil penalty assessment for two citations regarding brake lights on mobile equipment. The proposed civil penalty assessment became a final order on January 16, 2009, but the notice of contest was mailed to an incorrect address. A Motion to Reopen the Penalty Assessment was filed on March 19, 2009 and unopposed by the Secretary of Labor. The Commission has approved the Motion, and the matter has been assigned to Administrative Law Judge Barbour pending issuance of a Petition for Penalty Assessment.
LAKE 2009 633 Coshocton Strip Mine 33-04180	$	334	Petition for civil penalty assessment regarding an excavator with an accumulation of oil on and/or around the engine, and the fire extinguisher on the excavator was not at full charge. The Petition was issued September 24, 2009 and timely answered on October 26, 2009. The matter has been settled. The Secretary has filed its Motion to Approve Settlement, which is pending.
LAKE 2009 634 Oxford Mining #2 33-04213	$	616	Petition for civil penalty assessment for two citations: one regards an excavator with an accumulation of oil in and under the hydraulic compartment, undercarriage and tracks; the other regards unlabeled circuit breakers in the warehouse panel box. The Petition was issued September 24, 2009 and timely answered on October 26, 2009. The matter has been settled. The Secretary has filed its Motion to Approve Settlement, which is pending.
LAKE 2010 576 Snyder Mine 33-04414	$	946	Petition for civil penalty assessment for a rock truck operator failing to maintain control of the vehicle and crashing into the highwall; the driver sustained a broken leg. The Petition was served on May 5, 2010 and timely answered on June 7, 2010.
LAKE 2010 577 Snyder Mine 33-04414	$	207	Petition for civil penalty assessment for a dump truck that did not give an audible sound when reverse was engaged when tested. The Petition was served on May 6, 2010 and timely answered on June 7, 2010.

Item 6. Exhibits

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

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SIGNATURES

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

Date: August 10, 2010

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

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EXHIBIT INDEX

Exhibit Number			Exhibit Description
	3.1		Certificate of Limited Partnership of Oxford Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
	3.2		Third Amended and Restated Agreement of Limited Partnership of Oxford Resource Partners, LP dated July 19, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
	3.3		Certificate of Formation of Oxford Resources GP, LLC (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	3.4		Second Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC dated July 19, 2010 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
	10.1A		Credit Agreement dated as of July 6, 2010 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
	10.1B		First Amendment to Credit Agreement and Limited Waiver dated as of July 15, 2010 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
	10.2		Investors’ Rights Agreement, dated August 24, 2007, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC, AIM Oxford Holdings, LLC, C&T Coal, Inc., Charles C. Ungurean and Thomas T. Ungurean (incorporated by reference to Exhibit 10.2 to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
	10.3	*#	Employment Agreement between Oxford Resources GP, LLC and Michael B. Gardner
	10.4	*#	Employment Agreement between Oxford Resources GP, LLC and Jeffrey M. Gutman
	10.5	*#	Employment Agreement between Oxford Resources GP, LLC and Gregory J. Honish
	10.6	*#	Employment Agreement between Oxford Resources GP, LLC and Charles C. Ungurean
	10.7	*#	Employment Agreement between Oxford Resources GP, LLC and Thomas T. Ungurean
	10.8	#	Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Michael B. Gardner (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	10.9	#	Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Jeffrey M. Gutman (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	10.10	#	Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gregory J. Honish (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	10.11	#	Employee Unitholder Agreement among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Denise M. Maksimoski (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	10.12	#	Oxford Resource Partners, LP Amended and Restated Long-Term Incentive Plan dated July 19, 2010 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)

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Exhibit Number			Exhibit Description
	10.13	#	Form of Long-Term Incentive Plan Grant Agreement (incorporated by reference to Exhibit 10.13 to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
	10.14	*#	Non-Employee Director Compensation Plan
	10.15A	#	Form of Non-Employee Director Compensation Plan Grant Agreement (incorporated by reference to Exhibit 10.15A to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
	10.15B	#	Director Unitholder Agreement, dated December 1, 2009, by and among Oxford Resource Partners, LP, Oxford Resources GP, LLC and Gerald A. Tywoniuk (incorporated by reference to Exhibit 10.15B to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	10.16		Acquisition Agreement, dated August 14, 2009, by and among Oxford Mining Company, LLC, Phoenix Coal Inc., Phoenix Coal Corporation and Phoenix Newco, LLC (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	10.17A		Coal Purchase and Sale Agreement No. 10-62-04-900, dated May 21, 2004, by and between Oxford Mining Company, Inc. and American Electric Power Service Corporation, agent for Columbus Southern Power Company (incorporated by reference to Exhibit 10.17A to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
	10.17B		Amendment No. 2004-1 to Coal Purchase and Sale Agreement, dated October 25, 2004 (incorporated by reference to Exhibit 10.17B to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	10.17C		Amendment No. 2005-1 to Coal Purchase and Sale Agreement, dated April 8, 2005 (incorporated by reference to Exhibit 10.17C to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
	10.17D		Amendment No. 2006-3 to Coal Purchase and Sale Agreement, dated December 5, 2006 (incorporated by reference to Exhibit 10.17D to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
	10.17F		Amendment No. 2008-6 to Coal Purchase and Sale Agreement, dated December 29, 2008 (incorporated by reference to Exhibit 10.17F to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
	10.17G		Amendment No. 2009-1 to Coal Purchase and Sale Agreement, dated May 21, 2009 (incorporated by reference to Exhibit 10.17G to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
	10.17H		Amendment No. 2009-3 to Coal Purchase and Sale Agreement, dated December 15, 2009 (incorporated by reference to Exhibit 10.17H to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
	10.17I		Amendment No. 2010-1 to Coal Purchase and Sale Agreement, dated January 11, 2010 (incorporated by reference to Exhibit 10.17I to Amendment No. 4 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 25, 2010)
	10.17J		Amendment No. 2010-2 to Coal Purchase and Sale Agreement, dated February 4, 2010 (incorporated by reference to Exhibit 10.17J to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	10.17K		Amendment No. 2010-3 to Coal Purchase and Sale Agreement, dated April 16, 2010 (incorporated by reference to Exhibit 10.15A to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)

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Exhibit Number			Exhibit Description
	10.18		Non-Compete Agreement by and among Oxford Resource Partners, LP, C&T Coal, Inc., Charles C. Ungurean, Thomas T. Ungurean and Oxford Resources GP, LLC (incorporated by reference to Exhibit 10.18 to Amendment No. 3 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on June 9, 2010)
	10.19		Administrative and Operational Services Agreement, dated August 24, 2007, by and among Oxford Resource Partners, LP, Oxford Mining Company, LLC and Oxford Resources GP, LLC (incorporated by reference to Exhibit 10.19 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
	31.1	*	Certification of Charles C. Ungurean, President and Chief Executive Officer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the June 30, 2010 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	31.2	*	Certification of Jeffrey M. Gutman, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the June 30, 2010 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	32.1	*	Certification of Charles C. Ungurean, President and Chief Executive Officer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the June 30, 2010 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	32.2	*	Certification of Jeffrey M. Gutman, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the June 30, 2010 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

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