Westmoreland Resource Partners, LP - FORM 10-Q

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EXCEL - IDEA: XBRL DOCUMENT - Westmoreland Resource Partners, LP	Financial_Report.xls
EX-10 - EXHIBIT 10.32 - Westmoreland Resource Partners, LP	ex10-32.htm
EX-31 - EXHIBIT 31.2 - Westmoreland Resource Partners, LP	ex31-2.htm
EX-95 - EXHIBIT 95 - Westmoreland Resource Partners, LP	ex95.htm
EX-10 - EXHIBIT 10.33 - Westmoreland Resource Partners, LP	ex10-33.htm
EX-32 - EXHIBIT 32.2 - Westmoreland Resource Partners, LP	ex32-2.htm
EX-31 - EXHIBIT 31.1 - Westmoreland Resource Partners, LP	ex31-1.htm
EX-32 - EXHIBIT 32.1 - Westmoreland Resource Partners, LP	ex32-1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2014

☐	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) 643-0337

(Registrant’s Telephone Number, Including Area Code)

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

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

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

Large accelerated filer ☐ Accelerated filer ☐

Non-accelerated filer ☐ (Do not check if a smaller reporting company) Smaller reporting company ☒

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

As of August 4, 2014, 10,727,939 common units and 10,280,380 subordinated units were outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “OXF.”

	TABLE OF CONTENTS

	PART I. FINANCIAL INFORMATION	Page

ITEM 1.	Condensed Consolidated Financial Statements (Unaudited)	2
	Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	2
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013	3
	Condensed Consolidated Statements of Partners’ (Deficit) Capital for the Six Months Ended June 30, 2014 and 2013	4
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	5
	Notes to Condensed Consolidated Financial Statements	6
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	29
ITEM 4.	Controls and Procedures	29

	PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	30
ITEM 1A.	Risk Factors	30
ITEM 4.	Mine Safety Disclosures	30
ITEM 6.	Exhibits	30

PART I. FINANCIAL INFORMATION

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

(in thousands, except for unit data)

	As of June 30, 2014			As of December 31, 2013

ASSETS
CURRENT ASSETS:
Cash	$	3,533		$	3,089
Accounts receivable		27,704			25,850
Inventory		14,345			13,840
Advance royalties		2,884			2,604
Prepaid expenses and other assets		1,492			1,737
Total current assets		49,958			47,120

PROPERTY, PLANT AND EQUIPMENT, NET		128,777			144,426
ADVANCE ROYALTIES, LESS CURRENT PORTION		7,762			8,800
INTANGIBLE ASSETS, NET		1,074			1,188
OTHER LONG-TERM ASSETS		20,301			22,821
Total assets	$	207,872		$	224,355

LIABILITIES AND PARTNERS' (DEFICIT) CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	22,904		$	23,932
Current portion of long-term debt		8,906			7,901
Current portion of reclamation and mine closure obligations		9,086			5,996
Accrued taxes other than income taxes		1,198			1,293
Accrued payroll and related expenses		1,193			3,389
Other liabilities		2,862			3,457
Total current liabilities		46,149			45,968

LONG-TERM DEBT		154,710			155,375
RECLAMATION AND MINE CLOSURE OBLIGATIONS		24,199			25,658
WARRANTS		3,129			4,599
OTHER LONG-TERM LIABILITIES		3,738			3,753
Total liabilities		231,925			235,353


PARTNERS’ (DEFICIT) CAPITAL:
Limited partners (21,008,319 and 20,867,073 units outstanding as of June 30, 2014 and December 31, 2013, respectively)		(25,414	)		(13,460	)
General partner (423,494 units outstanding as of June 30, 2014 and December 31, 2013)		(2,766	)		(2,507	)
Total Oxford Resource Partners, LP (deficit) capital		(28,180	)		(15,967	)
Noncontrolling interest		4,127			4,969
Total partners’ (deficit) capital		(24,053	)		(10,998	)
Total liabilities and partners’ (deficit) capital	$	207,872		$	224,355

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

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

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
REVENUES:
Coal sales	$	79,586		$	85,691		$	156,356		$	170,484
Other revenue		2,415			2,434			3,649			6,367
Total revenues		82,001			88,125			160,005			176,851
COSTS AND EXPENSES:
Cost of coal sales:
Produced coal		66,527			66,556			131,734			133,984
Purchased coal		768			5,292			1,287			11,893
Total cost of coal sales (excluding depreciation, depletion and amortization)		67,295			71,848			133,021			145,877
Cost of other revenue		369			370			771			773
Depreciation, depletion and amortization		10,072			12,810			21,296			25,743
Selling, general and administrative expenses		3,270			5,847			6,926			10,005
Impairment and restructuring expenses		-			721			75			862
Gain on disposal of assets, net		(763	)		(5,905	)		(559	)		(5,487	)
Total costs and expenses		80,243			85,691			161,530			177,773
INCOME (LOSS) FROM OPERATIONS		1,758			2,434			(1,525	)		(922	)
INTEREST AND OTHER INCOME (EXPENSES):
Interest income		2			1			3			2
Interest expense		(7,003	)		(4,416	)		(13,873	)		(7,338	)
Change in fair value of warrants		1,885			(2,149	)		1,470			(2,149	)
Total interest and other expenses		(5,116	)		(6,564	)		(12,400	)		(9,485	)
NET LOSS		(3,358	)		(4,130	)		(13,925	)		(10,407	)
Net loss (income) attributable to noncontrolling interest		461			(380	)		842			(650	)
Net loss attributable to Oxford Resource Partners, LP unitholders		(2,897	)		(4,510	)		(13,083	)		(11,057	)
Net loss allocated to general partner		(57	)		(89	)		(259	)		(221	)
Net loss allocated to limited partners	$	(2,840	)	$	(4,421	)	$	(12,824	)	$	(10,836	)

Net loss per limited partner unit:
Basic	$	(0.11	)	$	(0.21	)	$	(0.52	)	$	(0.52	)
Diluted		(0.11	)		(0.21	)		(0.52	)		(0.52	)

Weighted average number of limited partner units outstanding:
Basic		24,734,018			21,093,448			24,686,947			20,779,901
Diluted		24,734,018			21,093,448			24,686,947			20,779,901

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' (DEFICIT) CAPITAL

(UNAUDITED)

(in thousands, except for unit data)

	Limited Partners																							Total
	Common					Subordinated					Total					General Partner					Non-			Partners'
	Units		Capital			Units		Deficit			Units		Capital (Deficit)			Units		Deficit			controlling Interest			Capital (Deficit)
Balance at December 31, 2012		10,470,810	$	93,930			10,280,380	$	(84,337	)		20,751,190	$	9,593			423,494	$	(2,010	)	$	3,744		$	11,327
Net (loss) income		-		(5,482	)		-		(5,354	)		-		(10,836	)		-		(221	)		650			(10,407	)
Equity-based compensation		-		739			-		-			-		739			-		-			-			739
Issuance of units to LTIP participants		66,161		(66	)		-		-			66,161		(66	)		-		-			-			(66	)
Balance at June 30, 2013		10,536,971	$	89,121			10,280,380	$	(89,691	)		20,817,351	$	(570	)		423,494	$	(2,231	)	$	4,394		$	1,593

Balance at December 31, 2013		10,586,693	$	82,931			10,280,380	$	(96,391	)		20,867,073	$	(13,460	)		423,494	$	(2,507	)	$	4,969		$	(10,998	)
Net loss		-		(6,538	)		-		(6,286	)		-		(12,824	)		-		(259	)		(842	)		(13,925	)
Equity-based compensation		-		921			-		-			-		921			-		-			-			921
Issuance of units to LTIP participants		141,246		(51	)		-		-			141,246		(51	)		-		-			-			(51	)
Balance at June 30, 2014		10,727,939	$	77,263			10,280,380	$	(102,677	)		21,008,319	$	(25,414	)		423,494	$	(2,766	)	$	4,127		$	(24,053	)

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

	For the Six Months Ended June 30,
	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(13,925	)	$	(10,407	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion and amortization		21,296			25,743
Impairment and restructuring expenses		75			862
Change in fair value of warrants		(1,470	)		2,149
Interest rate swap adjustment to market		-			(12	)
Non-cash interest expense		3,786			347
Amortization and write-off of deferred financing costs		1,923			2,114
Non-cash equity-based compensation expense		921			739
Non-cash reclamation and mine closure expense		1,125			1,058
Amortization of below-market coal sales contracts		-			(60	)
Gain on disposal of assets, net		(559	)		(5,487	)
Changes in assets and liabilities:
Accounts receivable		(1,854	)		(7,149	)
Inventory		(505	)		705
Advance royalties		758			(1,981	)
Restricted cash		(496	)		(6,537	)
Prepaid expenses and other assets		240			(973	)
Accounts payable		(1,028	)		(2,002	)
Reclamation and mine closure obligations		(2,115	)		(4,138	)
Accrued taxes other than income taxes		(95	)		65
Accrued payroll and related expenses		(2,196	)		312
Other liabilities		(734	)		(951	)
Net cash from operating activities		5,147			(5,603	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment		(5,241	)		(5,694	)
Purchase of coal reserves and land		(5	)		(14	)
Mine development costs		(618	)		(1,940	)
Proceeds from sale of assets		3,599			6,249
Insurance proceeds		-			14
Net cash from investing activities		(2,265	)		(1,385	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		-			150,000
Payments on borrowings		(1,947	)		(45,009	)
Advances on line of credit		13,500			28,888
Payments on line of credit		(15,000	)		(104,000	)
Debt issuance costs		9			(9,354	)
Collateral for reclamation bonds		1,000			(11,471	)
Net cash from financing activities		(2,438	)		9,054

NET CHANGE IN CASH		444			2,066
CASH, beginning of period		3,089			3,977
CASH, end of period	$	3,533		$	6,043

See accompanying notes to condensed consolidated financial statements.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

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

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“US GAAP”) for interim financial information and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by US GAAP for complete financial statements. In our opinion, the condensed consolidated financial statements reflect all adjustments necessary for a fair presentation of the results of operations and financial position for such periods. All such adjustments reflected in the condensed consolidated financial statements are considered to be of a normal recurring nature. The results of operations for any interim period are not necessarily indicative of results for the full year. Accordingly, these condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2013 (the “Annual Report”) and filed with the U.S. Securities and Exchange Commission (the “SEC”).

NOTE 1: ORGANIZATION AND PRESENTATION

Basis of Presentation and Principles of Consolidation

The accompanying unaudited condensed consolidated financial statements include the accounts and operations of the Partnership and its consolidated subsidiaries.

Significant Relationships Referenced in Notes to Condensed 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.

●

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

Organization

We are a low-cost producer of high-value thermal coal and the largest producer of surface-mined coal in Ohio. We market our coal primarily to large electric utilities with coal fired, base-load scrubbed power plants under long-term coal sales contracts. We focus on acquiring thermal coal reserves that we can efficiently mine with our large scale equipment. Our reserves and operations are strategically located to serve our primary market area of Indiana, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia. These coal reserves are mined by our subsidiaries, Oxford Mining Company, LLC (“Oxford Mining”), Oxford Mining Company - Kentucky, LLC and Harrison Resources, LLC (“Harrison Resources”).

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

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Significant Accounting Policies

There were no changes to our significant accounting policies from those disclosed in the audited consolidated financial statements and notes thereto contained in the Annual Report.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Liquidity

We have incurred net losses in the past few years resulting in an accumulated deficit of $24.1 million at June 30, 2014. We have managed our liquidity for the six months ended June 30, 2014, with $5.1 million of cash flows provided from operations and $2.4 million of cash flows used in financing activities. As of June 30, 2014, our available liquidity was $10.5 million, which consisted of $3.5 million in cash on hand and $7.0 million of borrowing capacity under our credit facilities. Further, we have an option for an additional $10 million term loan if requested by us and approved by the issuing second lien lender. As the maturity dates approach, we will pursue extending our current financing agreements or refinancing our debt in its entirety. If we are unable to extend or refinance our debt, our ability to continue as a going concern will be impacted.

Should we have difficulty meeting our forecasts, this could have an adverse effect on our liquidity position. Management expects to be able to achieve its forecasted results for the year ending December 31, 2014. However, there can be no assurance that our cash flows will be sufficient to allow us to continue as a going concern if we are unable to meet our forecasts.

Accounting Pronouncement Effective in the Future

In April 2014, the FASB issued ASU 2014-08, Presentation of Financial Statements and Property, Plant and Equipment, which changes the presentation of discontinued operations on the statements of operations and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. The new guidance is effective for interim and annual periods beginning after December 15, 2014. We plan to adopt ASU 2014-08 effective January 1, 2015.

In May 2014, the FASB issued ASU 2014-09, Revenue From Contracts With Customers, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract. Entities have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard. The new guidance is effective for the interim and annual periods beginning after December 15, 2016; early adoption is not permitted. We are currently assessing the impact that this standard will have on our consolidated financial statements.

NOTE 3: IMPAIRMENT AND RESTRUCTURING EXPENSES

In March 2012, we received a termination notice from a customer related to a 0.8 million tons per year coal supply contract fulfilled from our Illinois Basin operations. In response, we initially idled some of our Illinois Basin operations, terminated a significant number of employees related to such operations and substituted purchased coal for mined and washed coal on certain sales contracts. Subsequently over time, the remainder of our Illinois Basin operations were idled and the related employees terminated with the result that our Illinois Basin operations were fully idled as of December 31, 2013. During that period, we also sold some of our excess Illinois Basin equipment while redeploying most of the equipment to our Northern Appalachian operations, with such redeployment being completed during the first quarter of 2014. Additionally, we sold our Illinois Basin dock in April 2014. Finally, we are seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers to purchase the remaining coal reserves and/or facilities related to our Illinois Basin operations.

Impairment Expenses

As a result of the restructuring described above, we recorded asset impairment expenses of $12.8 million during 2012. These non-cash expenses related to coal reserves, mine development assets and certain mining equipment. No such expenses were recorded in the three- and six-month periods ended June 30, 2014 and 2013, respectively.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 3: IMPAIRMENT AND RESTRUCTURING EXPENSES (continued)

Restructuring Expenses

The restructuring related to our Illinois Basin operations were completed March 31, 2014. Accordingly, no restructuring expenses were recorded in the second quarter of 2014, while $0.7 million of restructuring expenses were recorded in the second quarter of 2013. Restructuring expenses of $0.1 and $0.9 million were incurred during the six months ended June 30, 2014 and 2013, respectively. These expenses included termination costs for approximately 35 employees in 2013, professional and legal fees, and transportation costs associated with moving idled equipment to our Northern Appalachian operations. The liabilities related to the restructuring are included in “other liabilities” in our condensed consolidated balance sheet as of December 31, 2013. There is no liability remaining as of June 30, 2014.

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

	As of December 31, 2013		For the Six Months Ended June 30, 2014						As of June 30, 2014
	Liability		Expense			Payments			Liability

Severance and other termination costs	$	404	$	(42	)	$	(362	)	$	-
Equipment relocation costs		252		117			(369	)		-
Total cash restructuring expenses	$	656	$	75		$	(731	)	$	-

The following table summarizes the total impairment and restructuring expenses incurred during the six months ended June 30, 2014 and over the course of the restructuring which was completed by March 31, 2014:

	Expenses
	For the Six Months Ended June 30, 2014			Incurred Through June 30, 2014		Total Expenses
Cash:
Severance and other termination costs	$	(42	)	$	1,846	$	1,846
Professional and legal fees		-			1,021		1,021
Equipment relocation costs		117			1,161		1,161
Coal lease termination costs		-			23		23
Total cash restructuring expenses		75			4,051		4,051

Non-cash:
Coal lease termination costs		-			683		683
Asset impairment		-			12,753		12,753
Total non-cash restructuring expenses		-			13,436		13,436
Total impairment and restructuring expenses	$	75		$	17,487	$	17,487

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 4: INVENTORY

Inventory consisted of the following:

	As of June 30, 2014		As of December 31, 2013

Coal	$	6,738	$	5,957
Fuel		1,618		1,879
Spare parts and supplies		5,989		6,004
Total	$	14,345	$	13,840

NOTE 5: PROPERTY, PLANT AND EQUIPMENT, NET

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

	As of June 30, 2014			As of December 31, 2013

Property, plant and equipment, gross
Land	$	2,161		$	3,016
Coal reserves		49,579			49,574
Mine development costs		61,576			58,077
Buildings and tipple		1,824			1,957
Machinery and equipment		197,893			202,663
Vehicles		4,468			4,522
Furniture and fixtures		1,311			1,584
Railroad sidings		160			160
Total property, plant and equipment, gross		318,972			321,553
Less: accumulated depreciation, depletion and amortization		(190,195	)		(177,127	)
Total property, plant and equipment, net	$	128,777		$	144,426

The amounts of depreciation expense related to fixed assets, depletion expense related to coal reserves, amortization expense related to mine development costs and amortization expense related to intangible assets for the respective periods are as follows:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2014		2013		2014		2013

Depreciation	$	6,835	$	8,307	$	14,137	$	15,524
Depletion		1,210		908		2,411		1,698
Mine development amortization		1,967		3,532		4,626		8,437
Intangible asset amortization		60		63		122		84
	$	10,072	$	12,810	$	21,296	$	25,743

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 6: RECLAMATION AND MINE CLOSURE OBLIGATIONS

As of June 30, 2014, our liability for reclamation and mine closure obligations totaled $33.3 million, including amounts reported as current liabilities. While the amount of these future obligations cannot be determined with certainty, we estimate that, as of June 30, 2014, the aggregate undiscounted obligations for final reclamation and mine closure totaled $40.9 million.

The changes in the liability for reclamation and mine closure obligations on a discounted basis for the six months ended June 30, 2014 and the year ended December 31, 2013 are as follows:

	Six Months Ended			Year Ended
	June 30, 2014			December 31, 2013

Balance at beginning of period	$	31,654		$	29,013
Accretion expense		1,125			2,293
Adjustment resulting from additional mines		2,702			3,671
Adjustments to the liability from annual recosting and other		149			5,333
Payments		(2,345	)		(8,656	)
Total reclamation and mine closure obligations		33,285			31,654
Less current portion		(9,086	)		(5,996	)
Long-term reclamation and mine closure obligations	$	24,199		$	25,658

NOTE 7: LONG-TERM DEBT

Long-term debt as of June 30, 2014 and December 31, 2013 consisted of the following:

	As of June 30, 2014			As of December 31, 2013

First lien debt:
Revolver	$	18,000		$	19,500
Term loan		68,071			69,321
Total first lien debt		86,071			88,821
Second lien debt:
Term loan		74,813			75,000
Paid-in-kind interest		4,580			2,318
Debt discount, net		(5,004	)		(6,456	)
Total second lien debt, net of debt discount		74,389			70,862
Notes payable		3,156			3,593
Total debt		163,616			163,276
Less current portion		(8,906	)		(7,901	)
Long-term debt	$	154,710		$	155,375

In June 2013, we closed on $175 million of credit facilities that replaced our previous term loan and revolving credit facility. These facilities include (i) a first lien credit facility consisting of a $75 million term loan and a $25 million revolver under a financing agreement maturing September 30, 2015, as amended (the “First Lien Financing Agreement”) and (ii) a second lien credit facility consisting of a $75 million term loan (with an option for an additional $10 million term loan if requested by us and approved by the issuing second lien lender) under a financing agreement maturing December 31, 2015, as amended (the “Second Lien Financing Agreement,” and collectively with the First Lien Financing Agreement, the “Financing Agreements”). The Financing Agreements allow for nine-month extensions which we may exercise provided that certain conditions are met.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 7: LONG-TERM DEBT (continued)

In conjunction with executing the Financing Agreements, we incurred $9.6 million in debt issuance costs recorded in “other long-term assets.”

As of June 30, 2014, we were in compliance with all covenants under the terms of the Financing Agreements.

First Lien Credit Facility

As of June 30, 2014, we had a term loan of $68.1 million outstanding under the first lien credit facility. We began making and are obligated to make quarterly principal payments of $1.3 million commencing in June 2014, until repayment of the then outstanding balance at maturity. Borrowings on the term loan bear interest at a variable rate per annum equal to, at our option, the London Interbank Offered Rate (“LIBOR”) (floor of 1.5%) plus 6.75% or the Reference Rate (as defined in the First Lien Financing Agreement) (floor of 3.00%) plus 6.25%. As of June 30, 2014, the first lien credit facility term loan had a cash interest rate of 8.25%, consisting of LIBOR of 1.5% plus 6.75%.

The first lien credit facility also includes a $25 million revolving credit facility under which $18.0 million was outstanding as of June 30, 2014. As of June 30, 2014, the balance outstanding on the revolving credit facility had a weighted average cash interest rate of 8.25%, consisting of LIBOR of 1.5% plus 6.75%.

During the year ended December 31, 2013, we paid down $5.7 million of the first lien term loan with proceeds from the sale of oil and gas rights. The Financing Agreements require mandatory prepayment of principal with proceeds from such events.

Second Lien Credit Facility

As of June 30, 2014, we had a term loan, net of debt discount, of $74.4 million outstanding under the second lien credit facility. We began making and are obligated to make quarterly principal payments of $0.2 million commencing in June 2014, until repayment of the then outstanding balance at maturity. As of June 30, 2014, the second lien credit facility term loan had a cash interest rate of 11.00%, consisting of LIBOR of 1.25% plus 9.75%.

The second lien credit facility also provides for PIK Interest (paid-in-kind interest as defined in the Second Lien Financing Agreement) at the rate of 5.75%. PIK Interest is added quarterly to the then-outstanding principal amount of the term loan as additional principal obligations. For the three months ended June 30, 2014 and 2013, PIK Interest totaled $1.2 million and $0.1 million, respectively. For the six months ended June 30, 2014 and 2013, PIK Interest totaled $2.3 million and $0.1 million, respectively.

In conjunction with the Second Lien Financing Agreement, certain lenders and lender affiliates received warrants entitling them to purchase 1,955,666 common units and 1,814,185 subordinated units at $0.01 per unit. The warrants, classified as a liability, were recorded at their fair value of $7.9 million at issuance as a debt discount. The warrants are subsequently marked to fair value with the change in fair value reported in earnings. This discount will be amortized through interest expense over the life of the second lien credit facility using the effective interest method. For the three months ended June 30, 2014 and 2013, amortization of the debt discount totaled $0.8 million and $0.1 million, respectively. For the six months ended June 30, 2014 and 2013, amortization of the debt discount totaled $1.5 million and $0.1 million, respectively.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 8: FAIR VALUE OF FINANCIAL INSTRUMENTS

The book values of cash, restricted cash, accounts receivable and accounts payable are considered to be representative of their respective fair values because of the immediate short-term maturity of these financial instruments. The fair value of the Partnership’s first and second lien credit facilities and warrants were determined based upon a market approach and approximates the carrying value at June 30, 2014.

The warrants are fair valued at each balance sheet date using the Black-Scholes model. As of June 30, 2014, the fair value of each warrant was $0.83, based on the following assumptions: spot price of $0.84 per unit, exercise price of $0.01 per unit, term of 4.00 years, volatility of 79% and a five-year treasury rate of 1.62%.

The fair value of the Partnership’s first and second lien credit facilities and warrants are a Level 2 measurement.

NOTE 9: LONG-TERM INCENTIVE PLAN

Under our Long-Term Incentive Plan (our “LTIP”), we recognize equity-based compensation expense over the vesting period of the units. These units are subject to conditions and restrictions as determined by our Compensation Committee, including continued employment or service. Historically, these units generally vested in equal annual increments over four years with accelerated vesting of the first increment in certain cases. Beginning in 2012, some of the units granted to executive officers vest based on specified performance criteria.

We are authorized to distribute up to 2,806,075 units under the LTIP. As of June 30, 2014, 433,757 units remained available for issuance in the future assuming that all grants issued and currently outstanding are settled with common units, without reduction for tax withholding, and no future forfeitures occur.

For the three months ended June 30, 2014 and 2013, we recognized equity-based compensation expense of $465 and $416, respectively. For the six months ended June 30, 2014 and 2013, we recognized equity-based compensation expense of $921 and $739, respectively. These amounts are included in selling, general and administrative expenses and cost of coal sales. As of June 30, 2014 and December 31, 2013, $2,936 and $2,150, respectively, of cost remained unamortized. We expect to recognize these costs using the straight-line method over a remaining weighted average period of 1.3 years as of June 30, 2014.

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

	Units			Weighted Average Grant Date Fair Value

Unvested balance at December 31, 2013		559,184		$	6.79
Granted		1,420,132			1.22
Issued		(141,246	)		4.92
Surrendered		(39,888	)		9.69

Unvested balance at June 30, 2014		1,798,182			2.47

The value of LTIP units vested during the three months ended June 30, 2014 and 2013 was $37 in each year. The value of LTIP units vested during the six months ended June 30, 2014 and 2013 was $1,043 and $888, respectively.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 10: EARNINGS (LOSSES) PER UNIT

The computation of basic and diluted earnings (losses) per unit under the two class method for limited partner units and general partner units is presented as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013

*Limited partner units*
Average units outstanding:
Basic		24,734,018			21,093,448			24,686,947			20,779,901
Effect of equity-based compensation	N/A			N/A			N/A			N/A
Diluted		24,734,018			21,093,448			24,686,947			20,779,901

Net loss allocated to limited partners
Basic	$	(2,848	)	$	(4,421	)	$	(12,862	)	$	(10,836	)
Diluted		(2,848	)		(4,421	)		(12,862	)		(10,836	)

Net loss per limited partner unit
Basic	$	(0.11	)	$	(0.21	)	$	(0.52	)	$	(0.52	)
Diluted		(0.11	)		(0.21	)		(0.52	)		(0.52	)

*General partner units*
Average units outstanding:
Basic		423,730			423,512			423,730			423,494
Diluted		423,730			423,512			423,730			423,494

Net loss allocated to general partner
Basic	$	(49	)	$	(89	)	$	(221	)	$	(221	)
Diluted		(49	)		(89	)		(221	)		(221	)

Net loss per general partner unit
Basic	$	(0.11	)	$	(0.21	)	$	(0.52	)	$	(0.52	)
Diluted		(0.11	)		(0.21	)		(0.52	)		(0.52	)

Under the Partnership’s partnership agreement, arrearage amounts resulting from suspension of the common units distribution accumulate, while those related to the subordinated units do not. In the future, if and as distributions are made for any quarter, the first priority is to pay the then minimum quarterly distribution to common unitholders (including the holders of common unit warrants). Any additional distribution amounts paid at that time are then paid to common unitholders (including the holders of common unit warrants) until their previously unpaid accumulated arrearage amounts have been paid in full. As of June 30, 2014, the total arrearage amount was $36.9 million. Distributions are prohibited by our credit facilities as long as we have outstanding borrowings thereunder.

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. Many of these prices are subject to cost pass through or cost adjustment provisions that mitigate some risk from rising costs. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer or us. As of June 30, 2014, the remaining terms of our long-term contracts ranged from one to two years.

Purchase Commitments

From time to time, we purchase coal from third parties in order to meet quality or delivery requirements under our customer contracts. We buy coal on the spot market, and the cost of that coal is dependent upon the market price and quality of the coal. We previously had a long-term purchase contract for 0.4 million tons of coal per year with a separate supplier who had asserted that the contract had terminated by its terms. We entered into a settlement agreement with the supplier in February 2013 under which the parties agreed to terminate the contract with the supplier making a one-time payment of $2.1 million to us, which payment was recorded in “other revenue”.

OXFORD RESOURCE PARTNER, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 11: COMMITMENTS AND CONTINGENCIES (continued)

Transportation

We depend upon barge, rail and truck transportation systems to deliver coal to our customers. We have a long-term rail transportation contract that has been amended and extended through March 31, 2015.

401(k) Plan

The GP did not make a commitment to fund an employer contribution to our 401(k) plan for the year ended December 31, 2013, and consequently no such contribution has been or will be made. As of June 30, 2014, the GP had not made such a commitment for the year ended December 31, 2014 either.

Surety and Performance Bonds

As of June 30, 2014, we had $34.1 million in surety bonds outstanding to secure certain reclamation obligations which were collateralized by cash deposits of $8.6 million. Such collateral is included in “other long-term assets.” Additionally, we had road bonds totaling $0.7 million and performance bonds totaling $3.1 million outstanding to secure contractual performance. We believe these bonds will expire without any claims or payments thereon and therefore will not have a material adverse effect on our financial position, liquidity or operations.

Legal

From time to time, we are involved in various legal proceedings arising in the ordinary course of business. We accrue for such liabilities when it is probable that future costs (including legal fees and expenses) will be incurred and such costs can be reasonably estimated. Accruals are based on developments to date; management’s estimates of the outcomes of these matters; our experience in contesting, litigating and settling similar matters; and any related insurance coverage. While the ultimate outcome of these proceedings cannot be predicted with certainty, we have accrued $870 to resolve various claims as of June 30, 2014, of which $650 was accrued during the three and six months ended June 30, 2014.

Guarantees

Our GP and the Partnership guarantee certain obligations of our subsidiaries. We believe that these guarantees will expire without any liability to the guarantors, and therefore will not have a material adverse effect on our financial position, liquidity or operations.

NOTE 12: RELATED PARTY TRANSACTIONS

In connection with our formation in August 2007, the Partnership and Oxford Mining entered into an administrative and operational services agreement (the “Services Agreement”) with our GP. The Services Agreement is terminable by either party upon thirty days’ written notice. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Our GP provides us with services such as general administrative and management, human resources, legal, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geological, risk management and insurance services. Pursuant to the Services Agreement, the primary reimbursements to our GP were for costs related to payroll. Reimbursable costs under the Services Agreement totaling $1,560 and $624 were included in accounts payable as of June 30, 2014 and December 31, 2013, respectively.

We sell clay and small quantities of coal to Tunnell Hill Reclamation, LLC (“Tunnell Hill”), a company that is indirectly owned by Mr. C. Ungurean, Mr. T. Ungurean, and affiliates of AIM Oxford. Sales to Tunnell Hill were $274 and de minimis for the three months ended June 30, 2014 and 2013, respectively, and $422 and de minimis for the six months ended June 30, 2014 and 2013, respectively. Accounts receivable from Tunnell Hill were $302 at June 30, 2014 and $83 at December 31, 2013.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 13: SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information:

	For the Six Months Ended June 30,
	2014		2013
Cash paid for:
Interest	$	8,243	$	5,156
Non-cash activities:
Reclamation and mine closure costs capitalized in mine development		2,880		9,554
Market value of common units vested in LTIP		217		255

NOTE 14: SEGMENT INFORMATION

We operate in one business segment. We operate surface coal mines in Northern Appalachia and, through December 2013, in the Illinois Basin. We sell high-value thermal coal to utilities, industrial customers, municipalities and other coal-related entities primarily in the eastern United States. Our operating and executive management reviews and bases its decisions upon consolidated reports. Our operating subsidiaries extract coal utilizing surface-mining techniques and prepare it for sale to their customers. Such operating subsidiaries share customers and a particular customer may receive coal from any one of such operating subsidiaries.

NOTE 15: SUBSEQUENT EVENT

In March 2012, a customer of our Illinois Basin operations terminated a coal supply agreement under which we were to supply 800,000 tons of coal per year for the next four years through the end of 2015. We initiated and aggressively pursued litigation to recover damages from the wrongful termination. In July 2014, we entered into a settlement agreement with the customer under which the customer agreed to pay us $19.5 million to compensate us for lost profits on coal sales to the customer due to the termination. We believe this settlement amount substantially compensates us for the damages we incurred due to the wrongful termination. Pursuant to our Financing Agreements, we will out of these settlement proceeds make a prepayment of principal on our first lien debt totaling between $12.5 and $17.5 million. The approximately $2.0 to $7.0 million in remaining settlement proceeds will be retained by the Partnership and enhances our liquidity.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q (this “Quarterly Report”) 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, 2013 included in our Annual Report on Form 10-K (our “Annual Report”) and filed with the United States 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 About Forward-Looking Statements.”

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

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

●

market demand for coal and energy, including changes in consumption patterns by utilities away from the use of coal;

●

availability of qualified workers;

●

future economic or capital market conditions;

●

weather conditions or catastrophic weather-related damage;

●

our production capabilities;

●

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

●

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

●

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

●

availability and costs of credit and surety bonds;

●

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

●

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

●

availability and costs of capital equipment;

●

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

●

timing of reductions or increases in customer coal inventories;

●

long-term coal supply arrangements;

●

reductions and/or deferrals of purchases by major customers;

●

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

●

unexpected maintenance and equipment failure;

●

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

●

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

●

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

●

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

●

employee benefits costs and labor relations issues;

●

replacement of our reserves;

●

our assumptions concerning economically recoverable coal reserve estimates;

●

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

●

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

●

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

●

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

●

adequacy and sufficiency of our internal controls; and

●

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

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

Overview

We are a low-cost producer and marketer of high-value thermal coal (“coal”) to United States (“U.S.”) utilities and industrial users, and we are the largest producer of surface mined coal in Ohio. We market our coal primarily to large electric utilities with coal-fired, base-load scrubbed power plants under long-term coal sales contracts. We focus on acquiring coal reserves that we can efficiently mine with our large-scale equipment. Our reserves and operations are strategically located to serve our primary market area of Indiana, Kentucky, Michigan, Ohio, Pennsylvania and West Virginia.

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

We currently have 12 active surface mines and we manage these mines as six mining complexes. Our coal reserves and operations are strategically located near our customers with the flexibility to ship by barge, truck or rail. During the three and six months ended June 30, 2014, we produced and sold 1.5 and 3.0 million tons, respectively, of coal.

As previously disclosed in our periodic filings with the SEC, in the first quarter of 2012 we received a termination notice from a customer related to a 0.8 million tons per year coal supply contract fulfilled from our Illinois Basin operations. In response, we initially idled some of our Illinois Basin operations, terminated a significant number of employees related to such operations and substituted purchased coal for mined and washed coal on certain sales contracts. Subsequently, over time, the remainder of our Illinois Basin operations were idled and the related employees terminated with the result that our Illinois Basin operations were fully idled as of December 31, 2013. During that period, we also sold some of our excess Illinois Basin equipment while redeploying most of the equipment to our Northern Appalachian operations, with such redeployment being completed during the first quarter of 2014. Additionally, we sold our Illinois Basin dock in April 2014. And finally, we are seeking to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, and would consider offers to purchase the remaining coal reserves and/or facilities related to our Illinois Basin operations.

In July 2014, we concluded litigation, with a former customer who wrongfully terminated its Coal supply agreement with us, by entering into a settlement agreement under which the former customer agreed to pay us $19.5 million to compensate us for lost profits on coal sales to the former customer due to the termination. We believe this settlement amount substantially compensates us for the damages we incurred due to the wrongful termination. Pursuant to our Financing Agreements, we will out of these settlement proceeds make a prepayment of principal on our first lien debt of between $12.5 and $17.5 million. The approximately $2.0 to $7.0 million in remaining settlement proceeds will be retained by us and will further enhance our liquidity.

Evaluating Our Results of Operations

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

●

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

●

our cost of coal sales, including cost of purchased coal;

●

our net (loss) income; 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. 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 market demand. We sell substantially all of our coal under long-term coal sales contracts, and thus sales prices are dependent upon the terms of those contracts.

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

We evaluate the price we receive for our coal on a per ton basis. Our coal sales revenue per ton represents our coal sales revenue divided by total tons of coal sold. The following table provides operational data including data with respect to our tons of coal produced, purchased and sold, as well as our coal sales revenue, cash cost of coal sales and cash margin on a per ton basis, for the periods indicated:

	Three Months Ended									Six Months Ended
	June 30,									June 30,
	2014			2013			% Change			2014			2013			% Change
	(tons in thousands, unaudited)

Produced tons		1,492			1,566			(4.7	%)		2,913			3,102			(6.1	%)
Purchased tons		24			108			(77.8	%)		42			245			(82.9	%)
Tons of coal sold		1,516			1,674			(9.4	%)		2,955			3,347			(11.7	%)

Tons sold under long-term contracts		96.6	%		96.7	%	n/a				96.7	%		95.0	%	n/a

Coal sales revenue per ton	$	52.49		$	51.21			2.5	%	$	52.91		$	50.94			3.9	%
Amortization of below-market coal sales contracts per ton		-			-			0.0	%		-			(0.02	)		(100.0	%)
Cash coal sales revenue per ton		52.49			51.21			2.5	%		52.91			50.92			3.9	%
Cash cost of coal sales per ton		(44.38	)		(42.93	)		3.4	%		(45.02	)		(43.59	)		3.3	%
Cash margin per ton	$	8.11		$	8.28			(2.1	%)	$	7.89		$	7.33			7.6	%

Cost of Coal Sales

We evaluate, on a cost per ton sold basis, our cost of coal sales which excludes non-cash costs such as depreciation, depletion and amortization (“DD&A”), gain or loss on asset disposals, impairment and restructuring expenses, and indirect costs such as selling, general and administrative expenses. Our cost of coal sales per ton represents our cost of coal sales divided by the tons of coal sold. Our cost of coal sales includes costs for labor, fuel, oil, explosives, royalties, equipment lease expense, repairs and maintenance, and other costs directly related to our mining operations.

At times, we purchase coal from third parties to fulfill a portion of our obligations under our long-term coal sales contracts and, in certain cases, to meet customer coal quality specifications. These costs are included in the cost of purchased coal amount within cost of coal sales.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure used by management to gauge operating performance. We define Adjusted EBITDA as net income or loss before deducting interest, income taxes, depreciation, depletion, amortization, change in fair value of warrants, impairment and restructuring expenses, gain or loss on disposal of assets, amortization of below-market coal sales contracts, non-cash equity-based compensation expense, non-cash reclamation and mine closure expense, and certain non-recurring revenues and costs. Although Adjusted EBITDA is not a measure of financial performance calculated in accordance with GAAP, we believe it is useful to management and others, such as investors and lenders, in evaluating our financial performance without regard to our financing methods, capital structure or income taxes; our ability to generate cash sufficient to pay interest and principal on our indebtedness, make distributions and fund capital expenditures; and our compliance with certain credit facility financial covenants. Because not all companies calculate Adjusted EBITDA the same way, our calculation may not be comparable to similarly titled measures of other companies.

For a reconciliation of Net Loss to Adjusted EBITDA for the three and six months ended June 30, 2014 and 2013, see “— Results of Operations - Summary.”

Long-term Coal Supply Contracts

As is customary in the coal industry, we enter into long-term supply contracts (one year or longer in duration) with substantially all of our customers. These contracts allow customers to secure a supply for their future needs and provide us with greater predictability of sales volumes and prices. For the six months ended June 30, 2014, approximately 96.7% of our coal tons sold were sold under long-term supply contracts. We sell the remainder of our coal through short-term contracts and on the spot market.

The terms of our coal supply contracts result from competitive bidding and extensive negotiations with each customer. Consequently, the terms can vary significantly by contract, and can cover such matters as price adjustment features, price reopener terms, coal quality requirements, quantity adjustment mechanisms, permitted sources of supply, future regulatory changes, extension options, force majeure provisions and termination and assignment provisions. Some long-term contracts provide for a pre-determined adjustment to the stipulated base price at specified times or periodic intervals to account for changes due to inflation or deflation in prevailing market prices.

Also, most contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that influence our costs of production. In addition, some of our contracts contain provisions that allow for the recovery of costs impacted by modifications or changes in the interpretations or application of government statutes.

Price reopener provisions are present in several of our long-term contracts. These price reopener provisions may automatically set a new price based on prevailing market price or, in some instances, require the parties to agree on a new price, sometimes within a specified range. In a limited number of contracts, failure of the parties to agree on a price under a price reopener provision can lead to contract termination.

As of June 30, 2014, 98.1% of our projected coal sales tons for the balance of 2014 were committed and priced. As of June 30, 2014, we had commitments under supply contracts to deliver 4.1 million, 2.1 million and 2.1 million tons of coal to customers in 2015, 2016 and 2017, respectively. Of these amounts, in 2015 and 2016, 3.4 million and 1.7 million tons, respectively, are dependent upon reaching agreement on pricing during reopener periods. In 2017, all 2.1 million tons are dependent upon reaching agreement on pricing during reopener periods.

Factors That Impact Our Business

Our results of operations in the near term could be impacted by a number of factors, including (1) adverse weather conditions and natural disasters, (2) poor mining conditions resulting from geological conditions or the effects of prior mining, (3) equipment problems, (4) the availability of transportation for coal shipments and (5) the availability and costs of key supplies and commodities such as steel, diesel fuel and explosives.

On a long-term basis, our results of operations could be impacted by, among other factors, (1) changes in governmental regulation, (2) the availability and prices of competing electricity-generation fuels, (3) our ability to secure or acquire high-quality coal reserves and (4) our ability to find buyers for coal under favorable supply contracts.

Results of Operations

Summary

The following table presents historical condensed consolidated financial data for the three and six months ended June 30, 2014 and 2013:

SELECTED FINANCIAL AND OPERATING DATA

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
	(in thousands, unaudited)
STATEMENT OF OPERATIONS DATA:
REVENUES:
Coal sales	$	79,586		$	85,691		$	156,356		$	170,484
Other revenue		2,415			2,434			3,649			6,367
Total revenues		82,001			88,125			160,005			176,851
COSTS AND EXPENSES:
Cost of coal sales:
Produced coal		66,527			66,556			131,734			133,984
Purchased coal		768			5,292			1,287			11,893
Total cost of coal sales (excluding depreciation, depletion and amortization)		67,295			71,848			133,021			145,877
Cost of other revenue		369			370			771			773
Depreciation, depletion and amortization		10,072			12,810			21,296			25,743
Selling, general and administrative expenses		3,270			5,847			6,926			10,005
Impairment and restructuring expenses		-			721			75			862
Gain on disposal of assets, net		(763	)		(5,905	)		(559	)		(5,487	)
Total costs and expenses		80,243			85,691			161,530			177,773
INCOME (LOSS) FROM OPERATIONS		1,758			2,434			(1,525	)		(922	)
INTEREST AND OTHER INCOME (EXPENSES):
Interest income		2			1			3			2
Interest expense		(7,003	)		(4,416	)		(13,873	)		(7,338	)
Change in fair value of warrants		1,885			(2,149	)		1,470			(2,149	)
Total interest and other expenses		(5,116	)		(6,564	)		(12,400	)		(9,485	)
NET LOSS		(3,358	)		(4,130	)		(13,925	)		(10,407	)
Net loss (income) attributable to noncontrolling interest		461			(380	)		842			(650	)
Net loss attributable to Oxford Resource Partners, LP unitholders	$	(2,897	)	$	(4,510	)	$	(13,083	)	$	(11,057	)

The following table presents a reconciliation of net loss to Adjusted EBITDA for the three and six months ended June 30, 2014 and 2013:

RECONCILIATION OF NET LOSS TO ADJUSTED EBITDA

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(in thousands, unaudited)
Net loss	$	(3,358	)	$	(4,130	)	$	(13,925	)	$	(10,407	)
Adjustments:
Interest expense, net of interest income		7,001			4,415			13,870			7,336
Depreciation, depletion and amortization		10,072			12,810			21,296			25,743
Change in fair value of warrants		(1,885	)		2,149			(1,470	)		2,149
Impairment and restructuring expenses		-			721			75			862
Gain on disposal of assets, net		(763	)		(5,905	)		(559	)		(5,487	)
Amortization of below-market coal sales contracts		-			(8	)		-			(60	)
Non-cash equity-based compensation expense		465			416			921			739
Non-cash reclamation and mine closure expense		560			550			1,125			1,058
Non-recurring costs:
Debt refinancing expenses		-			2,849			-			3,059
Other		868			-			868			(2,100	)
Adjusted EBITDA	$	12,960		$	13,867		$	22,201		$	22,892

Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Overview

Total revenue was $82.0 million for the three months ended June 30, 2014, a decrease of $6.1 million, or 6.9%, from $88.1 million for the three months ended June 30, 2013. Net loss for the three months ended June 30, 2014 was $3.4 million, compared to a net loss for the three months ended June 30, 2013 of $4.1 million. Adjusted EBITDA was $13.0 million for the three months ended June 30, 2014, a decrease of $0.9 million from $13.9 million for the three months ended June 30, 2013. Cash margin per ton was $8.11 for the three months ended June 30, 2014, a decrease of $0.17, or 2.1%, per ton from $8.28 per ton for the three months ended June 30, 2013.

Coal Sales Revenue

Coal sales revenue was $79.6 million for the three months ended June 30, 2014, a decrease of $6.1 million, or 7.1%, from $85.7 million for the three months ended June 30, 2013. The decrease was primarily attributable to a 9.4% reduction in tons sold with a value of $8.0 million, partially offset by a $1.28 per ton, or an aggregate $1.9 million, increase in coal sales revenue. The decrease in tons sold was primarily attributable to the idling of our Illinois Basin operations.

Other Revenue

Other revenue, primarily from clay and limestone sales, royalty income and other miscellaneous revenue, was $2.4 million for the three months ended each of June 30, 2014 and 2013. Non-coal revenue decreased $0.8 million to $0.3 million for the three months ended June 30, 2014 from $1.1 million for the three months ended June 30, 2013, due primarily to a one-time payment of $1.1 million for lost coal in connection with a third-party right-of-way access through a small portion of a mine complex during the three months ended June 30, 2013. At the same time, clay and limestone sales increased $0.8 million to $2.1 million for the three months ended June 30, 2014 from $1.3 million for the three months ended June 30, 2013 due primarily to a bulk limestone sale totaling $0.6 million.

Cost of Coal Sales (Excluding DD&A)

Cost of coal sales (excluding DD&A) was $67.3 million for the three months ended June 30, 2014, a decrease of $4.5 million, or 6.3%, from $71.8 million for the three months ended June 30, 2013. The decrease was primarily attributable to a 0.2 million reduction in tons sold, which corresponds to a $6.7 million decrease in cost of coal sales, partially offset by an increase in the cost to produce coal of $1.45 per ton, or an aggregate of $2.2 million. Cost of coal sales per ton was $44.38 for the three months ended June 30, 2014, an increase of $1.45, or 3.4%, per ton from $42.93 per ton for the three months ended June 30, 2013. The $1.45 per ton increase was primarily attributable to a $1.59 per ton, or $2.4 million, increase in compensation and outside labor costs, a $1.37 per ton, or $2.1 million, increase in transportation cost, a $0.39 per ton, or $0.6 million, increase in diesel fuel expense and a $0.24 per ton, or $0.4 million, increase in lease expense, which were partially offset by a $2.65 per ton, or $4.5 million, decrease in purchased coal. Compensation and outside labor costs increased due to pay rate increases implemented in mid-2013 in response to increased competition in the labor market from the growing oil and gas business in southeastern Ohio, in addition to the utilization of contract high-wall miner services at two of our mining operations while no such contract miner was engaged in the comparable period last year. Transportation cost increased due to longer haul routes, diesel fuel expense increased due to higher spot prices, and lease expense increased due to costs incurred to lease heavy equipment.

For the three months ended June 30, 2014, 24,000 tons of coal were purchased, which represents a decrease of 84,000 tons of coal purchased from 108,000 tons of coal purchased for the three months ended June 30, 2013. In the three months ended June 30, 2013, we made a strategic business decision to substitute purchased coal for mined and washed coal on certain sales contracts resulting in more purchased coal in the three months ended June 30, 2013 as compared to the three months ended June 30, 2014 The tons of coal purchased for the three months ended June 30, 2014 were purchased at an average price of $32.00 per ton, which represents a decrease of $17.00 per ton from the average price of $49.00 per ton for the three months ended June 30, 2013. The aggregate cost for tons of coal purchased for the three months ended June 30, 2014 decreased by $4.5 million from the aggregate cost for tons of coal purchased for the three months ended June 30, 2013.

Depreciation, Depletion and Amortization

DD&A expense was $10.1 million for the three months ended June 30, 2014, a decrease of $2.7 million, or 21.4%, from $12.8 million for the three months ended June 30, 2013. Depreciation expense was $6.8 million for the three months ended June 30, 2014, a $1.4 million decrease from $8.2 million for the three months ended June 30, 2013. Amortization expense decreased $1.6 million to $2.1 million for the three months ended June 30, 2014 from $3.7 million for the three months ended June 30, 2013. The 2013 period expense reflects an increase in the estimated cost of reclamation work to be performed at closed mines. Depletion expense was $1.2 million for the three months ended June 30, 2014, a $0.3 million increase from $0.9 million for the three months ended June 30, 2013, which was primarily attributable to an increase in the depletion rate per ton as we mined a higher percentage of owned versus leased tons.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were $3.3 million for the three months ended June 30, 2014, a decrease of $2.5 million, or 44.1%, from $5.8 million for the three months ended June 30, 2013. The decrease of $2.5 million was primarily the result of a $1.9 million decrease in professional fees and a $1.1 million decrease in compensation, offset in part by a $0.6 million increase in the legal reserve. In the 2013 period, we incurred professional fees, principally for advisory and legal services related to the refinancing of our credit facility that was completed in the second quarter of 2013. No such fees were incurred in the 2014 period. The decrease in compensation was primarily the result of lower bonuses being earned during the three months ended June 30, 2014 compared to the three months ended June 30, 2013. The increase in the legal reserve was the result of a legal settlement negotiated in July 2014.

Gain on Disposal of Assets, Net

The net gain on disposal of assets of $0.8 million for the three months ended June 30, 2014 represents a decrease of $5.1 million from a net gain of $5.9 million for the three months ended June 30, 2013. The net gain of $5.9 million for the three months ended June 30, 2013 related to the sale of certain oil and gas rights resulting in a net gain of $6.1 million, offset by net losses generated from the disposal of equipment in the normal course of business of $0.2 million.

Net Loss (Income) Attributable to Noncontrolling Interest

Net loss (income) attributable to noncontrolling interest relates to the 49% ownership interest in Harrison Resources owned by a subsidiary of CONSOL. Net loss attributable to noncontrolling interest was $0.5 million for the three months ended June 30, 2014, a decrease of $0.9 million from net income attributable to noncontrolling interest of $0.4 million for the three months ended June 30, 2013. This decrease was primarily due to an increase in mining costs and a decrease in selling prices resulting from the mining of lower quality of coal.

Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Overview

Total revenue was $160.0 million for the six months ended June 30, 2014, a decrease of $16.9 million, or 9.5%, from $176.9 million for the six months ended June 30, 2013. Net loss for the six months ended June 30, 2014 was $13.9 million, compared to a net loss for the six months ended June 30, 2013 of $10.4 million. Adjusted EBITDA was $22.2 million for the six months ended June 30, 2014, a decrease of $0.7 million from $22.9 million for the six months ended June 30, 2013. Cash margin per ton was $7.89 for the six months ended June 30, 2014, an increase of $0.56, or 7.6%, per ton from $7.33 per ton for the six months ended June 30, 2013.

Coal Sales Revenue

Coal sales revenue was $156.4 million for the six months ended June 30, 2014, a decrease of $14.1 million, or 8.3%, from $170.5 million for the six months ended June 30, 2013. The decrease was primarily attributable to an 11.7% reduction in tons sold with a value of $19.9 million, partially offset by a $1.97 per ton, or an aggregate $5.8 million, increase in coal sales revenue. The decrease in tons sold was primarily attributable to the idling of our Illinois Basin operations.

Other Revenue

Other revenue, primarily from clay and limestone sales, royalty income and other miscellaneous revenue, was $3.6 million for the six months ended June 30, 2014, a decrease of $2.8 million from $6.4 million for the six months ended June 30, 2013. Non-coal revenue decreased $2.9 million to $0.6 million for the six months ended June 30, 2014 from $3.5 million for the six months ended June 30, 2013, due primarily to a one-time payment of $2.1 million from a former coal supplier pursuant to a settlement agreement entered into in February 2013. Additionally, clay and limestone sales increased $0.1 million to $3.0 million for the six months ended June 30, 2014 from $2.9 million for the six months ended June 30, 2013.

Cost of Coal Sales (Excluding DD&A)

Cost of coal sales (excluding DD&A) was $133.0 million for the six months ended June 30, 2014, a decrease of $12.9 million, or 8.8%, from $145.9 million for the six months ended June 30, 2013. The decrease was primarily attributable to a 0.3 million reduction in tons sold, which corresponds to a $17.1 million decrease in cost of coal sales, partially offset by an increase in the cost to produce coal of $1.43 per ton, or an aggregate of $4.2 million. Cost of coal sales per ton was $45.02 for the six months ended June 30, 2014, an increase of $1.43, or 3.3%, per ton from $43.59 per ton for the six months ended June 30, 2013. The $1.43 per ton increase was primarily attributable to a $1.80 per ton, or $5.3 million, increase in compensation and outside labor costs; a $1.10 per ton, or $3.2 million, increase in transportation cost; a $0.70 per ton, or $2.1 million, increase in diesel fuel expense; and a $0.25 per ton, or $0.8 million, increase in lease expense, which were partially offset by a $3.12 per ton, or $10.6 million, decrease in purchased coal. Compensation and outside labor costs increased due to pay rate increases implemented in mid-2013 in response to increased competition in the labor market from the growing oil and gas business in southeastern Ohio, in addition to the utilization of contract high-wall miner services at two of our mining operations while no such contract miner was engaged to provide such services in the comparable period last year. Transportation cost increased due to longer haul routes, diesel fuel expense increased due to higher spot prices and lease expense increased due to costs incurred to lease heavy equipment.

For the six months ended June 30, 2014, 42,000 tons of coal were purchased, which represents a decrease of 203,000 tons of coal purchased from 245,000 tons of coal purchased for the six months ended June 30, 2013. In the six months ended June 30, 2013, we made a strategic business decision to substitute purchased coal for mined and washed coal on certain sales contracts, resulting in more purchased coal in the six months ended June 30, 2013 as compared to the six months ended June 30, 2014. The tons of coal purchased for the six months ended June 30, 2014 were purchased at an average price of $30.96 per ton, which represents a decrease of $17.56 per ton from the average price of $48.52 per ton for the six months ended June 30, 2013. The aggregate cost for tons of coal purchased for the six months ended June 30, 2014 decreased by $10.6 million from the aggregate cost for tons of coal purchased for the six months ended June 30, 2013.

Depreciation, Depletion and Amortization

DD&A expense was $21.3 million for the six months ended June 30, 2014, a decrease of $4.4 million, or 17.3%, from $25.7 million for the six months ended June 30, 2013. Depreciation expense was $14.1 million for the six months ended June 30, 2014, a $1.4 million decrease from $15.5 million for the six months ended June 30, 2013. Amortization expense decreased $3.7 million to $4.8 million for the six months ended June 30, 2014 from $8.5 million for the six months ended June 30, 2013. The 2013 period expense reflects an increase in the estimated cost of reclamation work to be performed at closed mines. Depletion expense was $2.4 million for the six months ended June 30, 2014, a $0.7 million increase from $1.7 million for the six months ended June 30, 2013, which was primarily attributable to an increase in the depletion rate per ton as we mined a higher percentage of owned versus leased tons.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were $6.9 million for the six months ended June 30, 2014, a decrease of $3.1 million, or 30.8%, from $10.0 million for the six months ended June 30, 2013. The decrease of $3.1 million was primarily the result of a $2.1 million decrease in professional fees and a $1.2 million decrease in compensation, offset in part by a $0.6 million increase in the legal reserve. In the 2013 period, we incurred professional fees, principally for advisory and legal services related to the refinancing of our credit facility that was completed in the second quarter of 2013. No such fees were incurred in the 2014 period. The decrease in compensation was primarily the result of lower bonuses being earned during the six months ended June 30, 2014 compared to the six months ended June 30, 2013. The increase in the legal reserve was the result of a legal settlement negotiated in July 2014.

Gain on Disposal of Assets, Net

The net gain on disposal of assets of $0.6 million for the six months ended June 30, 2014 represents a decrease of $4.9 million from a net gain of $5.5 million for the six months ended June 30, 2013. The net gain of $5.5 million for the three months ended June 30, 2013 related to the sale of certain oil and gas rights resulting in a net gain of $6.1 million, offset by net losses generated from the disposal of equipment in the normal course of business of $0.6 million.

Net Loss (Income) Attributable to Noncontrolling Interest

Net loss (income) attributable to noncontrolling interest relates to the 49% ownership interest in Harrison Resources owned by a subsidiary of CONSOL. Net loss attributable to noncontrolling interest was $0.8 million for the six months ended June 30, 2014, a decrease of $1.5 million from net income attributable to noncontrolling interest of $0.7 million for the six months ended June 30, 2013. This decrease was primarily due to an increase in mining costs and a decrease in selling prices resulting from the mining of lower quality of coal.

Liquidity and Capital Resources

Liquidity

Our business is capital intensive and requires substantial capital expenditures for, among other things, purchasing, maintaining and upgrading equipment used in developing and mining our coal, and acquiring reserves. Our principal liquidity needs are to finance current operations and fund capital expenditures, including costs of acquisitions from time to time, servicing of our debt and paying cash distributions to our unitholders when we are in a position to do so. Our primary sources of liquidity to meet these needs are cash generated by our operations and borrowings under the Financing Agreements. We were able to sell our Illinois Basin dock in April 2014, thereby enhancing our liquidity by the $2.1 million in proceeds received from the sale. If we are able to sell the remaining Illinois Basin equipment, consisting of a large-capacity shovel and several smaller pieces of equipment, our liquidity will be further enhanced. Additionally, we would consider offers for the remaining coal reserves and/or facilities related to our Illinois Basin operations, which could enhance our liquidity further.

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

We have incurred net losses in the past few years resulting in an accumulated deficit of $24.1 million at June 30, 2014. We have managed our liquidity for the six months ended June 30, 2014, with $5.1 million of cash flows provided from operations and with $2.4 million of cash flows used in financing activities. As of June 30, 2014, our available liquidity was $10.5 million, which consisted of $3.5 million in cash on hand and $7.0 million of borrowing capacity under our credit facilities. Additionally, we have an option for an additional $10 million term loan if requested by us and approved by the issuing second lien lender. As the maturity dates approach, we will pursue extending our current financing agreements or refinancing our debt in its entirety. If we are unable to extend or refinance our debt, our ability to continue as a going concern will be impacted.

In July 2014, we concluded litigation, with a former customer who wrongfully terminated its coal supply agreement with us, by entering into a settlement agreement under which the former customer agreed to pay us $19.5 million to compensate us for lost profits on coal sales to the former customer due to the termination. We believe this settlement amount substantially compensates us for the damages we incurred due to the wrongful termination. Pursuant to our Financing Agreements, we will out of these settlement proceeds make a prepayment of principal on our first lien debt of between $12.5 and $17.5 million. The approximately $2.0 to $7.0 million in remaining settlement proceeds will be retained by us and will further enhance our liquidity.

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

Cash Flows

Cash flows for the six months ended June 30, 2014 and 2013 are as follows:

	Six Months Ended
	June 30
	2014			2013
	(in thousands, unaudited)

Net cash from (used):
Operating activities	$	5,147		$	(5,603	)
Investing activities		(2,265	)		(1,385	)
Financing activities		(2,438	)		9,054
Total	$	444		$	2,066

Net cash provided by operating activities was $5.1 million for the six months ended June 30, 2014 compared to $5.6 million of net cash used in operating activities for the six months ended June 30, 2013, an increase of $10.7 million. We experienced a net loss for the six months ended June 30, 2014 of $13.9 million, an increase of $3.5 million, compared to a net loss for the six months ended June 30, 2013 of $10.4 million. The increase in the net loss was attributable in part to a $3.4 million increase in non-cash interest expense, and a $4.9 million decrease in gain on disposal of assets, net, partially offset by a $4.4 million decrease in depreciation, depletion and amortization and a $3.6 million change in the fair value of warrants. These differences, combined with a $14.5 million favorable change in working capital, are the primary drivers of the increase in net cash provided by operating activities. The favorable change in working capital was primarily attributable to favorable changes of $6.0 million in restricted cash, $5.3 million in accounts receivable and $2.7 million of advanced royalties, partially offset by an unfavorable change in inventory of $1.2 million.

Net cash used in investing activities was $2.3 million for the six months ended June 30, 2014 compared to $1.4 million for the six months ended June 30, 2013, an increase of $0.9 million. The increase was attributable to a $2.7 million decrease in proceeds from the sale of assets, partially offset by a $1.8 million reduction in capital expenditure spending. The $1.8 million reduction in capital expenditure spending consisted of a $1.3 million decrease in mine development costs and a $0.5 million decrease in purchases of property.

Net cash used in financing activities was $2.4 million for the six months ended June 30, 2014, down $11.5 million from net cash provided by financing activities of $9.1 million for the six months ended June 30, 2013. The $11.5 million decrease in net cash provided by financing activities was primarily attributable to $24.0 million less net borrowings for the six months ended June 30, 2014 compared to the six months ended June 30, 2013, partially offset by the recovery of $12.5 million in collateral held for reclamation bonds.

Capital Expenditures

Our mining operations require investments to maintain, expand, and upgrade existing operations and to meet environmental and safety regulations. We have funded and expect to continue funding capital expenditures primarily from cash generated by our operations and borrowings under the Financing Agreements.

The following table summarizes our capital expenditures by type for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(in thousands, unaudited)

Coal reserves and land	$	2	$	-	$	5	$	14
Mine development		429		886		618		1,940
Property and equipment, including components		2,811		3,792		5,241		6,680

Total	$	3,242	$	4,678	$	5,864	$	8,634

Financing Agreements

In June 2013, we closed on $175 million of credit facilities that replaced our previous term loan and revolving credit facility. The facilities are (i) a first lien credit facility consisting of a $75 million term loan and a $25 million revolver under a financing agreement, as amended (the “First Lien Financing Agreement”) and (ii) a second lien credit facility consisting of a $75 million term loan (with an option for an additional $10 million term loan if requested by us and approved by the issuing second lien lender) under a financing agreement, as amended (the “Second Lien Financing Agreement,” and collectively with the First Lien Financing Agreement, the “Financing Agreements”). The Financing Agreements allow for nine-month extensions which we may exercise provided that certain conditions are met.

The first lien credit facility matures in September 2015 with an option to extend to June 2016, and the second lien credit facility matures in December 2015 with an option to extend to September 2016, if certain conditions are met. As of June 30, 2014, the blended cash interest rate for both credit facilities was 9.57%. The Financing Agreements contain customary financial and other covenants, and also preclude making unitholder distributions during the term of the credit facilities. Borrowings under the credit facilities are secured by substantially all of our assets.

Warrants

In conjunction with the Second Lien Financing Agreement, certain lenders and lender affiliates received warrants entitling them to purchase 1,955,666 common units and 1,814,185 subordinated units at $0.01 per unit. The warrants participate in distributions whether or not exercised. During the five-year term for exercise of the warrants, the warrant exercise price and number of units will be adjusted for unit splits or reverse splits, such that the economics of the warrants remain unchanged. These warrants are free standing financial instruments, within the scope of ASC 480, Distinguishing Liabilities from Equity, since they are detachable from the Second Lien Financing Agreement. The warrants, classified as a liability, were recorded at their fair value of $7.9 million at issuance. The warrants are subsequently marked to fair value with the change reported in earnings. The fair value assigned to the warrants at issuance was recorded as a debt discount, reducing the outstanding debt balance. This discount is being amortized through interest expense over the life of the second lien credit facility using the effective interest method.

First Lien Credit Facility Borrowings

As of June 30, 2014, the outstanding balance on the first lien credit facility term loan was $68.1 million. We made and are obligated to make quarterly principal payments of $1.3 million commencing in June 2014 and continuing until repayment of the then outstanding balance at maturity. As of June 30, 2014, the first lien credit facility term loan had a cash interest rate of 8.25%, consisting of LIBOR of 1.5% plus 6.75%.

The first lien credit facility also includes a $25 million revolving credit facility under which $18.0 million was outstanding as of June 30, 2014. As of June 30, 2014, the balance outstanding on the revolver had a weighted average cash interest rate of 8.25%, consisting of LIBOR of 1.5% plus 6.75%.

Second Lien Credit Facility Borrowings

As of June 30, 2014, the outstanding balance on the second lien credit facility term loan was $74.4 million. This amount represents the principal balance of $75.0 million, plus PIK Interest of $4.4 million, net of the unamortized debt discount of $5.0 million. We made and are obligated to make quarterly principal payments of $0.2 million commencing in June 2014 and continuing until repayment of the then outstanding balance at maturity. As of June 30, 2014, the second lien credit facility term loan had a cash interest rate of 11.0%, consisting of LIBOR of 1.25% plus 9.75%.

The second lien credit facility provides for PIK Interest (paid-in-kind interest as defined in the Second Lien Financing Agreement) at the rate of 5.75%. PIK Interest is added quarterly to the then-outstanding principal amount of the term loan as additional principal obligations. PIK Interest totaled $1.2 million and $2.3 million for the three and six months ended June 30, 2014, respectively.

A portion of the principal of $75 million associated with the term loan issued under the second lien credit facility was allocated to the warrants in an amount equal to their fair value of $7.9 million. The value allocated to the warrants was recorded as a debt discount and is being amortized to interest expense over the life of the second lien credit facility using the effective interest method. Amortization of the debt discount totaled $0.8 million and $1.5 million for the three and six months ended June 30, 2014, respectively.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees and financial instruments with off-balance sheet risk, such as surety, performance, and road bonds.

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

As of June 30, 2014, we had $34.1 million in surety bonds outstanding to secure certain reclamation obligations which were collateralized by cash of $8.6 million. Such collateral is included in “other long-term assets” on our condensed consolidated balance sheets. Additionally, we had road bonds totaling $0.7 million and performance bonds totaling $3.1 million outstanding to secure contractual performance. We believe these bonds will expire without any claims or payments thereon and therefore they will not have a material adverse effect on our financial position, liquidity or operations.

New Accounting Standards Adopted

Various updates have been issued, most of which represent technical corrections to existing accounting literature or application to specific industries. We do not believe that the adoption of the guidance provided by these updates will have a material impact on our consolidated financial statements.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect reported amounts. These estimates and assumptions are based on information available as of the date of the financial statements. Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end. The results of operations for the three and six months ended June 30, 2014 are not necessarily indicative of results that can be expected for the full year. Please refer to the section entitled “Critical Accounting Policies and Estimates” of Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in our Annual Report for a discussion of our critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market price risk in the normal course of mining and selling coal. We manage this risk through the use of long-term coal supply contracts, rather than through the use of derivative instruments. Committed, but unpriced, sales are subject to future market price volatility. As of June 30, 2014, 98.1% of our projected sales for the balance of 2014 were committed and priced.

We are also exposed to market price risk related to diesel fuel pricing. To reduce this risk in part, we enter into forward purchase agreements. Additionally, we are further protected by diesel fuel escalation provisions contained in certain of our coal supply contracts that provide for a change in the price per coal ton sold in the event of changes in diesel fuel pricing. As of June 30, 2014, we had such price protection with respect to 89.0% of our expected diesel fuel purchases for the remainder of 2014.

Item 4. Controls and Procedures

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”)) was performed as of June 30, 2014. 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 were effective as of June 30, 2014 to ensure that we are able to collect, process and disclose the information that we are required to disclose in the reports we file with the SEC within the required time periods. During the quarterly period ended June 30, 2014, there were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The certifications of our Chief Executive Officer and Chief Financial Officer pursuant to Exchange Act Rules 13a-14(a) and 15d-14(a) are filed with this Quarterly Report 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 as Exhibits 32.1 and 32.2.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this Quarterly Report, careful consideration should be given to the risk factors discussed in the “Risk Factors” section of our Annual Report. The risk factor set forth below is a risk not previously disclosed in the “Risk Factors” section of our Annual Report.

Risks Inherent in an Investment in Us

The New York Stock Exchange (“NYSE”) requires us to maintain certain quantitative and qualitative standards. Failure to maintain those standards could result in the delisting of our common units on the NYSE.

The NYSE requires listed entities to maintain a minimum average closing price of $1.00 per unit over any period of 30 consecutive trading days. Failure to do so results in notification from the NYSE that the listed entity has a cure period of six months to regain compliance or be delisted, which could result in the entity’s units being traded on one of the over-the-counter markets.

In July 2014, the NYSE notified us that, as of and for the 30 consecutive trading days ended June 26, 2014, our minimum average closing price was $0.99 per unit. We then timely notified the NYSE that we intend to cure this deficiency. Under the NYSE rules, our common units will continue to be listed on the NYSE during the cure period, subject to our continued compliance with other listing requirements, which include but are not limited to maintaining a minimum market capitalization of $15.0 million over a period of 30 consecutive trading days.

Our ability to cure the deficiency may be affected by events beyond our control, as may our ability to continue to maintain our market capitalization at a minimum of $15.0 million over a period of 30 consecutive trading days. If we are unable to again meet the requirement for a $1.00 per unit minimum average closing price or continue to maintain minimum market capitalization of $15.0 million, we would need to move our common units to trading on one of the over-the-counter markets.

Item 4. Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K for the quarter ended June 30, 2014 is included as Exhibit 95 to this Quarterly Report on Form 10-Q.

Item 6. Exhibits

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

SIGNATURES

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

Date: August 5, 2014

	OXFORD RESOURCE PARTNERS, LP By: OXFORD RESOURCES GP, LLC, its general partner

	By:	/s/ CHARLES C. UNGUREAN
		Charles C. Ungurean President and Chief Executive Officer (Principal Executive Officer)

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

EXHIBIT INDEX

Exhibit Number	Exhibit Description
3.1	Certificate of Limited Partnership of Oxford Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
3.2	Third Amended and Restated Agreement of Limited Partnership of Oxford Resource Partners, LP dated July 19, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
3.2A	First Amendment to Third Amended and Restated Limited Partnership Agreement of Oxford Resource Partners, LP dated June 24, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on June 25, 2013)
3.3	Certificate of Formation of Oxford Resources GP, LLC (incorporated by reference to Exhibit 3.3 to Amendment No. 1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on April 21, 2010)
3.4	Third Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC dated January 1, 2011 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on January 4, 2011)
3.4A	First Amendment to Third Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC dated June 24, 2013 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on June 25, 2013)
3.4B	First Amendment to Third Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC executed as of March 12, 2014 to be effective as of June 24, 2013, entered into to correct, clarify, supersede and replace in its entirety the First Amendment to Third Amended and Restated Limited Liability Company Agreement of Oxford Resources GP, LLC dated June 24, 2013 (incorporated by reference to Exhibit 3.4B to the Quarterly Report on Form 10-Q (Commission File No. 001-34815) filed on May 6, 2014)
10.32*	Mediation Settlement Agreement dated July 15, 2014 between Oxford Mining Company – Kentucky, LLC and Big Rivers Electric Corporation
10.33*	Settlement Agreement effective July 15, 2014 between Oxford Mining Company – Kentucky, LLC and Big Rivers Electric Corporation, supplementing the Mediation Settlement Agreement dated July 15, 2014 between them
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, 2014 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the June 30, 2014 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, 2014 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the June 30, 2014 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
95*	Mine Safety Disclosures
101*	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013; (ii) our Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013; (iii) our Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013; (iv) our Condensed Consolidated Statements of Partners’ Capital (Deficit) for the six months ended June 30, 2014 and 2013; and (v) the notes to our Condensed Consolidated Financial Statements.

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

Attached files

Westmoreland Resource Partners, LP Reports

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