Westmoreland Resource Partners (WMLPQ) 10-Q 2013 Q3 Quarterly report

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 September 30, 2013

OR

☐ 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 November 1, 2013, 10,556,204 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 September 30, 2013 and December 31, 2012	2
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012	3
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012	4
	Condensed Consolidated Statements of Partners’ Capital (Deficit) for the Nine Months Ended September 30, 2013 and 2012	5
	Notes to Condensed Consolidated Financial Statements	6
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	32
ITEM 4.	Controls and Procedures	32
	PART II. OTHER INFORMATION
ITEM 1.	Legal Proceedings	33
ITEM 1A.	Risk Factors	33
ITEM 4.	Mine Safety Disclosures	33
ITEM 6.	Exhibits	33

i 

PART I. FINANCIAL INFORMATION

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS 

(UNAUDITED) 

(in thousands, except for unit data)

	As of September 30, 2013			As of December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,738		$	3,977
Accounts receivable		28,489			19,792
Inventory		12,065			12,554
Advance royalties		4,155			4,461
Prepaid expenses and other assets		1,767			2,046
Assets held for sale		-			6,106
Total current assets		49,214			48,936
PROPERTY, PLANT AND EQUIPMENT, NET		150,143			158,483
ADVANCE ROYALTIES, LESS CURRENT PORTION		6,194			4,861
INTANGIBLE ASSETS, NET		1,251			1,442
OTHER LONG-TERM ASSETS		24,224			7,177
Total assets	$	231,026		$	220,899
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	24,332		$	26,893
Current portion of long-term debt		5,929			102,970
Current portion of reclamation and mine closure costs		5,937			3,869
Accrued taxes other than income taxes		1,175			1,213
Accrued payroll and related expenses		2,507			1,629
Other liabilities		2,529			2,491
Total current liabilities		42,409			139,065
LONG-TERM DEBT		152,491			41,557
RECLAMATION AND MINE CLOSURE COSTS		28,267			25,144
WARRANTS		7,314			-
OTHER LONG-TERM LIABILITIES		3,730			3,806
Total liabilities		234,211			209,572
PARTNERS’ (DEFICIT) CAPITAL:
Limited partners (20,836,584 and 20,751,190 units outstandingas of September 30, 2013 and December 31, 2012, respectively)		(5,706	)		9,593
General partner (423,494 units outstanding as of September 30,2013 and December 31, 2012)		(2,343	)		(2,010	)
Total Oxford Resource Partners, LP (deficit) capital		(8,049	)		7,583
Noncontrolling interest		4,864			3,744
Total partners’ (deficit) capital		(3,185	)		11,327
Total liabilities and partners’ (deficit) capital	$	231,026		$	220,899

 

See accompanying notes to condensed consolidated financial statements.

2

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 September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
REVENUES:
Coal sales	$	84,742		$	95,027		$	255,226		$	279,806
Other revenue		2,844			2,187			9,211			7,223
Total revenues		87,586			97,214			264,437			287,029
COSTS AND EXPENSES:
Cost of coal sales:
Produced coal		68,175			72,896			202,159			221,101
Purchased coal		5,881			6,274			17,774			16,121
Total cost of coal sales (excluding depreciation, depletion and amortization)		74,056			79,170			219,933			237,222
Cost of other revenue		455			499			1,228			1,285
Depreciation, depletion and amortization		12,017			13,110			37,760			39,019
Selling, general and administrative expenses		3,051			3,901			13,056			11,475
Impairment and restructuring expenses		150			206			1,012			13,843
(Gain) loss on disposal of assets, net		(1,107	)		357			(6,594	)		(4,156	)
Total costs and expenses		88,622			97,243			266,395			298,688
INCOME (LOSS) FROM OPERATIONS		(1,036	)		(29	)		(1,958	)		(11,659	)
INTEREST AND OTHER EXPENSES:
Interest income		1			1			3			7
Interest expense		(6,808	)		(3,012	)		(14,146	)		(8,522	)
Change in fair value of warrants		2,714			-			565			-
Total interest and other expenses		(4,093	)		(3,011	)		(13,578	)		(8,515	)
NET LOSS		(5,129	)		(3,040	)		(15,536	)		(20,174	)
Net income attributable to noncontrolling interest		(470	)		(274	)		(1,120	)		(371	)
Net loss attributable to Oxford Resource Partners, LP unitholders		(5,599	)		(3,314	)		(16,656	)		(20,545	)
Net loss allocated to general partner		(112	)		(66	)		(333	)		(410	)
Net loss allocated to limited partners	$	(5,487	)	$	(3,248	)	$	(16,323	)	$	(20,135	)
Net loss per limited partner unit:
Basic	$	(0.22	)	$	(0.16	)	$	(0.74	)	$	(0.97	)
Diluted		(0.22	)		(0.16	)		(0.74	)		(0.97	)
Weighted average number of limited partner units outstanding:
Basic		24,587,411			20,717,734		��	22,159,610			20,702,042
Diluted		24,587,411			20,717,734			22,159,610			20,702,042
Distributions paid per unit:
Limited partners:
Common	$	-		$	0.4375		$	-		$	1.3125
Subordinated		-			0.1000			-			0.6375
General partner		-			0.2688			-			0.9750

See accompanying notes to condensed consolidated financial statements.

3

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands) 

	For the Nine Months Ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		(15,536	)		(20,174	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion and amortization		37,760			39,019
Impairment and restructuring expenses		1,012			13,843
Change in fair value of warrants		(565	)		-
Interest rate swap and fuel contract adjustments to market		(12	)		(194	)
Non-cash interest expense		2,238			-
Amortization and write-off of deferred financing costs		3,040			1,527
Non-cash equity-based compensation expense		1,090			966
Accretion of reclamation and mine closure costs		1,683			1,189
Amortization of below-market coal sales contracts		(60	)		(543	)
(Gain) loss on disposal of assets, net		(6,594	)		(4,156	)
Changes in assets and liabilities:
Accounts receivable		(8,697	)		(2,246	)
Inventory		489			(478	)
Advance royalties		(1,265	)		442
Other assets		(276	)		(1,981	)
Accounts payable		(2,561	)		(6	)
Reclamation and mine closure costs		(6,837	)		(6,413	)
Accrued taxes other than income taxes		(38	)		(392	)
Accrued payroll and related expenses		878			(315	)
Other liabilities		(248	)		(3,327	)
Net cash from operating activities		5,501			16,761
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property and equipment		(12,641	)		(15,226	)
Purchase of coal reserves and land		(14	)		(51	)
Mine development costs		(2,612	)		(2,760	)
Proceeds from sale of assets		6,284			8,543
Insurance proceeds		3,035			-
Change in restricted cash		1,429			3,092
Net cash from investing activities		(4,519	)		(6,402	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		150,000			-
Payments on borrowings		(56,071	)		(9,417	)
Advances on line of credit		43,588			41,000
Payments on line of credit		(119,088	)		(17,000	)
Debt issuance costs		(9,517	)		(1,086	)
Collateral for reclamation bonds		(11,133	)		-
Capital contributions from partners		-			7
Distributions to partners		-			(20,644	)
Net cash from financing activities		(2,221	)		(7,140	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		(1,239	)		3,219
CASH AND CASH EQUIVALENTS, beginning of period		3,977			3,032
CASH AND CASH EQUIVALENTS, end of period	$	2,738		$	6,251

See accompanying notes to condensed consolidated financial statements.

 

4

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (DEFICIT)

(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, 2011		10,399,744	$	121,911			10,280,380	$	(64,751	)		20,680,124	$	57,160			422,044	$	(1,032	)	$	2,989	$	59,117
Net (loss) income		-		(10,140	)		-		(9,995	)		-		(20,135	)		-		(410	)		371		(20,174	)
Partner contributions		-		-			-		-			-		-			654		7			-		7
Partner distributions		-		(13,682	)		-		(6,550	)		-		(20,232	)		-		(412	)		-		(20,644	)
Equity-based compensation		-		966			-		-			-		966			-		-			-		966
Issuance of units to LTIPparticipants		54,594		(227	)		-		-			54,594		(227	)		-		-			-		(227	)
Balance at September 30, 2012		10,454,338	$	98,828			10,280,380	$	(81,296	)		20,734,718	$	17,532			422,698	$	(1,847	)	$	3,360	$	19,045
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		-		(8,262	)		-		(8,061	)		-		(16,323	)		-		(333	)		1,120		(15,536	)
Partner contributions		-		-			-		-			-		-			-		-			-		-
Partner distributions		-		-			-		-			-		-			-		-			-		-
Equity-based compensation		-		1,090			-		-			-		1,090			-		-			-		1,090
Issuance of units to LTIPparticipants		85,394		(66	)		-		-			85,394		(66	)		-		-			-		(66	)
Balance at September 30, 2013		10,556,204	$	86,692			10,280,380	$	(92,398	)		20,836,584	$	(5,706	)		423,494	$	(2,343	)	$	4,864	$	(3,185	)

 

See accompanying notes to condensed consolidated financial statements.

5

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, 2012 (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 steam 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 steam 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 Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia. These coal reserves are mined by our subsidiaries, Oxford Mining Company, LLC (“Oxford Mining”), Oxford Mining Company - Kentucky, LLC and Harrison Resources, LLC (“Harrison Resources”).

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

As of September 30, 2013, AIM Oxford’s, C&T Coal’s, and our GP’s ownership of the Partnership was 35.38%, 18.01%, and 1.99%, respectively. The remaining 44.62% was held by the general public and participants in our Long-Term Incentive Plan (“LTIP”). AIM Oxford and C&T Coal held 65.81% and 33.49%, respectively, of the ownership interests in our GP with the remaining ownership interests therein being a 0.47% ownership interest held by Daniel M. Maher, our Senior Vice President, Chief Legal Officer and Secretary, and a 0.23% ownership interest held by Jeffrey M. Gutman, a former officer of our GP.

We have a 51% ownership interest in Harrison Resources and also have control for purposes of US GAAP. As a result, we consolidate all of Harrison Resources’ accounts with all material intercompany transactions and balances being eliminated in our condensed consolidated financial statements. The remaining 49% ownershipinterest in Harrison Resources that we do not own is reflected as “noncontrolling interest” in our condensed consolidated balance sheets and statements of operations.

6

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

Significant Accounting Policies

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

Reclassifications

The long-term balance of our term note of $6 million has been reclassified from “long-term debt” to “current portion of long-term debt” in our condensed consolidated balance sheet as of December 31, 2012.

NOTE 3: IMPAIRMENT AND RESTRUCTURING EXPENSES

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

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

In the third quarter of 2012, we idled one additional mine and resumed production at a second mine for a limited period of time that allowed us to meet our coal supply commitments. The wash plant continued to operate on a limited basis through most of the quarter and then was again idled.

In the fourth quarter of 2012 and first half of 2013, production continued at two mines.As of September 30, 2013, production continued at one mine. We have redeployed most of the Illinois Basin equipment to our Northern Appalachian operations. We are seeking to sell a shovel which is our remaining piece of excess mining equipment and would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations.

Impairment Expenses

As a result of the restructuring described above, we recorded asset impairment expenses of $11.6 million during the nine months ended September 30, 2012, none of which were recorded in the three month period then ended. These non-cash expenses related to coal reserves, mine development assets and certain mining equipment (the “Impaired Assets”). No such expenses were recorded in the three and nine month periods ended September 30, 2013.

In determining our impairment expenses, we utilized market prices for similar assets and discounted projected future cash flows to determine the fair value of the Impaired Assets. Our discounted projected future cash flows are based on financial forecasts developed internally for planning purposes. These projections incorporate certain assumptions, including future costs and sales trends, estimated costs to sell and our expected net realizable values for those Impaired Assets. In accordance with applicable accounting guidance under US GAAP, those Impaired Assets that we plan to sell, and that are currently ready for sale and are no longer in production, were presented separately as current assets held for sale in our consolidated balance sheet as of December 31, 2012. Such Impaired Assets are recorded at carrying value, after taking into account the impairment. The Impaired Assets were not depreciated or amortized during the last nine months of 2012 and first three months of 2013.Assets held forsale totaling $6.1 million that were not sold as of March 31, 2013 were reclassified from assets held for sale to machinery and equipment at that date.

7

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

Restructuring expenses related to our Illinois Basin operations totaling $0.2 million during the three months ended September 30, 2013 and 2012, and $1.0 and $2.2 million during the nine months ended September 30, 2013 and 2012, respectively, were recorded. These expenses included termination costs for approximately 200 employees in 2012, professional and legal fees, and transportation costs associated with moving idled equipment to our Northern Appalachian operations. In addition, we terminated one coal lease and wrote off the related asset in the second quarter of 2013. We expect to incur $0.9 million of additional costs as we idle all production activity in the Illinois Basin by the end of 2013 and finish redeploying equipment during the first quarter of 2014. The liabilities related to the restructuring are included in “other current liabilities” in our condensed consolidated balance sheets as of September 30, 2013 and December 31, 2012.

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, 2012		For the Nine Months Ended September 30, 2013					As of September 30, 2013
	Liability		Expense		Payments			Liability
Severance and other termination costs	$	405	$	3	$	(408	)	$	-
Professional and legal fees		18		22		(39	)		1
Equipment relocation costs		20		285		(305	)		-
Coal lease termination costs		-		19		(19	)		-
Total cash restructuring expenses	$	443	$	329	$	(771	)	$	1

The following table summarizes the total impairment and restructuring expenses incurred to date and those expected to be incurred over the remaining course of the restructuring:

	Expenses
	For the Nine Months Ended September 30, 2013		Cumulative Incurred As of September 30, 2013		Total Expected Expenses
Cash:
Severance and other termination costs	$	3	$	1,356	$	1,902
Professional and legal fees		22		1,017		1,017
Equipment relocation costs		285		834		1,190
Coal lease termination costs		19		19		19
Total cash restructuring expenses		329		3,226		4,128
Non-cash:
Coal lease termination costs		683		683		683
Asset impairment		-		12,753		12,753
Total non-cash restructuring expenses		683		13,436		13,436
Total impairment and restructuring expenses	$	1,012	$	16,662	$	17,564

8

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 September 30, 2013		As of December 31, 2012
Coal	$	4,757	$	5,609
Fuel		1,917		1,893
Spare parts and supplies		5,391		5,052
Total	$	12,065	$	12,554

NOTE 5: PROPERTY, PLANT AND EQUIPMENT, NET

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

	As of September 30, 2013			As of December 31, 2012
Property, plant and equipment, gross
Land	$	2,961		$	2,947
Coal reserves		52,839			53,376
Mine development costs		59,404			46,176
Total property		115,204			102,499
Buildings and tipple		1,957			1,957
Machinery and equipment		200,969			195,321
Vehicles		4,436			4,488
Furniture and fixtures		1,584			1,518
Railroad sidings		160			160
Total property, plant and equipment, gross		324,310			305,943
Less: accumulated depreciation, depletion and amortization		(174,167	)		(147,460	)
Total property, plant and equipment, net	$	150,143		$	158,483

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2013		2012		2013		2012
Depreciation	$	7,791	$	8,450	$	23,315	$	26,727
Depletion		1,294		1,301		2,992		4,010
Amortization		2,869		3,319		11,306		8,100
Intangible asset amortization		63		40		147		182
	$	12,017	$	13,110	$	37,760	$	39,019

In June 2013, we sold certain oil and gas rights for $6.1 million, which is recorded in “(gain) loss on disposal of assets, net” in our consolidated statement of operations. As part of that transaction and similar transactions in the prior year, we retained royalty rights equivalent to 20% of net revenue once the wells areproducing. As of September 30, 2013, none of the wells were producing on the properties for which we have sold oil and gas rights.

9

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 COSTS

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

As of September 30, 2013, our liability for reclamation and mine closure costs totaled $34.2 million, including amounts reported as current liabilities. While the precise amount of these future costs cannot be determined with certainty, we estimate that, as of September 30, 2013, the aggregate undiscounted cost of final reclamation and mine closure is approximately $42.8 million.

Activity affecting the liability for reclamation and mine closure costs for the respective periods is as follows:

	Nine Months Ended September 30, 2013			Twelve Months Ended December 31, 2012
Beginning balance	$	29,013		$	21,789
Accretion expense		1,683			1,567
Payments		(7,239	)		(8,966	)
Revisions in estimated cash flows		10,747			14,623
Total reclamation and mine closure costs		34,204			29,013
Less current portion		(5,937	)		(3,869	)
Noncurrent liability	$	28,267		$	25,144

 

               For the nine months ended September 30, 2013, the revisions in discounted estimated cash flows resulted in a net increase in the reclamation and mine closure costs of $10.7 million. Of this amount, $3.7 million related to four new mines, $4.5 million related to reclamation work in progress at recently closed mines and the remaining $2.5 million related to updated cost estimates for pond removal, grading and water treatment.

In 2012, the revisions in discounted estimated cash flows resulted in a net increase in the reclamation and mine closure costs of $14.6 million. Of this amount, $5.7 million related to eight new mines, $3.6 million related to reclamation work in progress at recently closed mines and $1.5 million related to estimated closing costs and timing for two mines being closed earlier than anticipated, with the remainder due to revisions to estimates of expected costs. The accelerated closures are a result of the restructuring plan for our Illinois Basin operations, which we began implementing in the first quarter of 2012, as further discussed in Note 3.

Adjustments to the liability for reclamation and mine closure costs due to such revisions generally result in a corresponding adjustment to the related mine development assets for active and new mines.

NOTE 7: LONG-TERM DEBT

Credit Facilities Generally

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 (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 second lien lenders) under a financing agreement (the “Second Lien Financing Agreement,” and collectively with the First Lien Financing Agreement, the “Financing Agreements”).

10

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)

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 September 30, 2013, the blended cash interest rate for both credit facilities was 9.52%.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. The initial net proceeds of the credit facilities were used to retire our previous revolving credit and term loan credit facility, to cash collateralize certain existing letters of credit and to pay fees and expenses related to the credit facilities.

As of September 30, 2013, we were in compliance with all covenants under the Financing Agreements.

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 in fair value 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 will be amortized through interest expense over the life of the second lien credit facility using the effective interest method. For the three and nine months ended September 30, 2013, the fair value of the warrants decreased $2.7 million and $0.6 million, respectively. See Note 8 for fair value disclosures.

First Lien Credit Facility

As of September 30, 2013, we had a term loan of $69.3 million outstanding under the first lien credit facility. We 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 September 30, 2013, 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 $16.5 million was outstanding as of September 30, 2013. The revolver bears interest at the same rates as the term loan under the first lien credit facility. As of September 30, 2013, the balance outstanding on the revolver had a weighted average cash interest rate of 8.63%, consisting of either LIBOR of 1.5% plus 6.75% or the Reference Rate of 3.25% plus 6.25%.

Second Lien Credit Facility

A portion of the $75 million of principal 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 at issuance of $7.9 million. The value allocated to the warrants was recorded as a debt discount, with the remaining $67.1 million assigned to the term loan. The debt discount will be amortized to interest expense over the life of the second lien credit facility using the effective interest method. Amortization of the debt discount totaled $0.6 million and $0.7 million for the three and nine months ended September 30, 2013, respectively.

11

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)

We are obligated to make quarterly principal payments of $0.2 million commencing in June 2014, until repayment of the then outstanding balance at maturity. The term loan under the second lien credit facility bears cash interest at a variable rate per annum equal to, at our option, LIBOR (floor of 1.25%) plus 9.75% or the Reference Rate (as defined in the Second Lien Financing Agreement) (floor of 3.00%) plus 11.75%. As of September 30, 2013, 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. PIK Interest totaled $1.1 million and $1.2 million for the three and nine months ended September 30, 2013, respectively.

As of September 30, 2013, the outstanding balance on the second lien term loan is $69.0 million. This amount represents the principal balance of $75.0 million, plus PIK Interest of $1.2 million, net of the unamortized debt discount of $7.2 million.

Notes Payable

Notes payable represent installment purchase agreements to buy coal reserves with various terms. Since these notes have no stated interest rate, interest is imputed. Non-cash interest expense includes $0.2 million and $0.3 million for accretion of imputed interest on these notes for the three and nine months ended September 30, 2013, respectively.

Total Borrowings

	As of September 30, 2013			As of December 31, 2012
First lien debt:
Revolver	$	16,500		$	92,000
Term loan		69,321			45,000
Total first lien debt		85,821			137,000
Second lien debt:
Term loan, net of debt discount		69,040			-
Notes payable		3,559			7,527
Total debt		158,420			144,527
Less current portion		(5,929	)		(102,970	)
Long-term debt	$	152,491		$	41,557

 

As of December 31, 2012, we had $8.9 million of letters of credit outstanding under our previous credit facility. As of September 30, 2013, we had $5.9 million of borrowings outstanding under the First Lien Financing Agreement used to cash collateralize existing letters of credit securing reclamation bonds. We expect these borrowings for cash collateral purposes to ultimately be replaced with letters of credit issued under our revolver. As of September 30, 2013, we had $8.5 million of borrowing capacity available on the revolver.

During the three months ended September 30, 2013, we paid down $5.7 millionof the first lien term loan with proceeds from the sale of oil and gas rights in late June 2013 and the granting of a pipeline right-of-way to a third party in September 2013. The Financing Agreements require mandatory prepayment of principal with proceeds from such events.

12

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)

Debt Maturities

Debt maturities are as follows:

During the years ending December 31:
2013	$	1
2014		7,866
2015		150,553
Total debt	$	158,420

Deferred Financing Costs

For the nine months ended September 30, 2013, net deferred financing costs totaling $0.8 million related to our previous credit facility were written-off as interest expense and we capitalized $9.5 million of deferred financing costs related to our new credit facilities.  These costs, included in “other long-term assets,” represent fees paid to lenders and advisors and for legal services. Deferred financing costs are amortized to interest expense over the life of the related credit facility using the effective interest method.  Amortization of deferred financing costs totaled $0.9 million and $0.4 million for the three months ended September 30, 2013 and 2012, respectively, and $2.2 million and $0.9 million for the nine months ended September 30, 2013 and 2012, respectively.

Selling, general and administrative expenses for nine months ended September 30, 2013 included $0.7 million of fees paid to advisors and for legal services related to refinancing our credit facility, and $2.4 million of fees paid to lenders and advisors and for legal services related to the attempted refinancing of our previous credit facility. There were no such expenses during the three months ended September 30, 2013.

NOTE 8: FAIR VALUE OF FINANCIAL INSTRUMENTS

We utilize fair value measurement guidance that, among other things, defines fair value, requires enhanced disclosures about assets and liabilities carried at fair value and establishes a hierarchal disclosure framework based upon the quality of inputs used to measure fair value. We have elected not to measure any additional financial assets or liabilities at fair value, other than those required to be recorded at fair value.

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

	Fair Value Measurement as of September 30, 2013
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	(Level 1)		(Level 2)			(Level 3)
Warrants	$	—	$	(7,314	)	$	—

	Fair Value Measurement as of December 31, 2012
	Quoted Prices in Active Markets for Identical Liabilities		Significant Other Observable Inputs			Significant Unobservable Inputs
Description	(Level 1)		(Level 2)			(Level 3)
Interest rate swap agreement	$	—	$	(12	)	$	—

13

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 (continued)

The interest rate swap agreement matured in the first quarter of 2013.

The warrants are fair valued at each balance sheet date using the Black-Scholes model. As of September 30, 2013, the fair value of each warrant is $1.94, based on the following assumptions: spot price of $1.95 per unit, strike price of $0.01 per unit, term of 5 years, volatility of 80%, and a five-year treasury rate of 1.4%.

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

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

Derivatives: The fair value of derivatives is established using a discounted cash flow analysis using primarily inputs that can be observed within financial markets, such as LIBOR rates.

Fixed rate debt:  The fair value of fixed rate debt is estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows. As such, the fair value of fixed rate debt is considered level 2.

Variable rate debt:  The fair value of variable rate debt is estimated using discounted cash flow analyses, based on our best estimates of market rate for instruments with similar cash flows. As such, the fair value of variable rate debt is considered level 2.

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

	As of September 30, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Fixed rate debt	$	3,559	$	3,287	$	7,527	$	7,642
Variable rate debt		154,861		154,861		137,000		137,000

NOTE 9: LONG-TERM INCENTIVE PLAN

Under 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 2,056,075 units under the LTIP. As of September 30, 2013, 1,094,490 units remain available for issuance in the future assuming that all grants issued and currently outstanding are settled with common units, without reduction for tax withholding, and no future forfeitures occur.

For the three months ended September 30, 2013 and 2012, we recognized equity-based compensation expense of $351 and $490, respectively. For the nine months ended September 30, 2013 and 2012, we recognized equity-based compensation expense of $1,090 and $966, respectively. These amounts are included in selling, general and administrative expenses. As of September 30, 2013 and December 31, 2012, $2,463 and $1,843, respectively, of cost remained unamortized. We expect to recognize these costs using the straight-line method over a remaining weighted average period of 1.2years as of September 30, 2013.

14

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

NOTE 9: LONG-TERM INCENTIVE PLAN (continued)

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

	Units			Weighted Average Grant Date Fair Value
Unvested balance at December 31, 2012		257,963		$	11.67
Granted		408,501			4.19
Issued		(85,394	)		7.36
Surrendered		(21,886	)		13.59
Unvested balance at September 30, 2013		559,184			6.79

The value of LTIP units vested during the three months ended September 30, 2013 and 2012 was $38 and $284, respectively. The value of LTIP units vested during the nine months ended September 30, 2013 and 2012 was $926 and $841, respectively.

NOTE 10: EARNINGS (LOSSES) PER UNIT

For purposes of our earnings (losses) per unit calculation, we have applied the two class method. The classes are our limited partner units and our general partner units. All outstanding units share pro rata in income (loss) allocations and distributions and our general partner has sole voting rights.

Limited Partner Units: Basic earnings (losses) per unit are computed by dividing net income attributable to limited partners by the weighted average units outstanding, including unexercised participating warrants, during the reporting period. Diluted earnings (losses) per unit are computed similar to basic earnings (losses) per unit except that the weighted average units outstanding and net income attributable to limited partners are increased to include phantom units that have not yet vested and that will convert to limited partnership units upon vesting. In periods of a loss, the phantom units are anti-dilutive and therefore not included in the earnings (losses) per unit calculation.

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

15

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 (continued)

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 September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
Limited partner units
Average units outstanding:
Basic		24,587,411			20,717,734			22,159,610			20,702,042
Effect of equity-based compensation	N/A			N/A			N/A			N/A
Diluted		24,587,411			20,717,734			22,159,610			20,702,042
Net loss allocated to limited partners
Basic	$	(5,504	)	$	(3,248	)	$	(16,344	)	$	(20,135	)
Diluted		(5,504	)		(3,248	)		(16,344	)		(20,135	)
Net loss per limited partner unit
Basic	$	(0.22	)	$	(0.16	)	$	(0.74	)	$	(0.97	)
Diluted		(0.22	)		(0.16	)		(0.74	)		(0.97	)
General partner units
Average units outstanding:
Basic		423,730			422,677			423,580			422,461
Diluted		423,730			422,677			423,580			422,461
Net loss allocated to general partner
Basic	$	(95	)	$	(66	)	$	(312	)	$	(410	)
Diluted		(95	)		(66	)		(312	)		(410	)
Net loss per general partner unit
Basic	$	(0.22	)	$	(0.16	)	$	(0.74	)	$	(0.97	)
Diluted		(0.22	)		(0.16	)		(0.74	)		(0.97	)
Anti-dilutive units(1) (2)		-			10,541			-			-
Distributions paid per unit:
Limited partners:
Common	$	-		$	0.4375		$	-		$	1.3125
Subordinated		-			0.1000			-			0.6375
General partner		-			0.2688			-			0.9750

⁽¹⁾ Anti-dilutive units are not used in calculating diluted average units due to the net operating loss in the period.

⁽²⁾Unvested LTIP units are not dilutive units for the three and nine months ended September 30, 2013 and 2012.

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 September 30, 2013, the total arrearage amount was $19.7 million. In the first quarter 2013, due to continued weakness in the coal markets, distributions related to the fourth quarter 2012 and going forward were suspended to further preserve liquidity. Distributions are also 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 September 30, 2013, the remaining terms of our long-term contracts ranged from one to two years.

16

OXFORD RESOURCE PARTNERS, 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)

We received a contract termination notice in March 2012 from a customer of our Illinois Basin operations. This contract required us to supply the customer with 0.8 million tons of coal per year. Absent any termination thereof, the term of the contract continued until December 31, 2015. We believe that this customer’s action was taken in bad faith, motivated by the combination of the price increase that had recently gone into effect and current coal market conditions. We are aggressively pursuing compensation for our damages through all appropriate legal measures.

Purchase Commitments

From time to time, we purchase coal from third parties in order to meet quality or delivery requirements under our customer contracts. 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 on February 12, 2013 under which the parties agreed to terminate the contract with the supplier making a one-time payment of $2.1 million to us.

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, 2014.

401(k) Plan

As of September 30, 2013, we satisfied the obligation to pay our GP for the purpose of funding our GP’s commitment to our 401(k) plan in the amount of $1.9 million related to plan year 2012.

Surety and Performance Bonds

As of September 30, 2013, we had $37.1 million in surety bonds outstanding to secure certain reclamation obligations which were collateralized by cash of $11.2 million. Such cash bonds are included in “other long-term assets” on our condensed consolidated balance sheet. We are currently working to replace the cash collateral with letters of credit. Additionally, we had road bonds totaling $0.6 million and performance bonds totaling $2.1 million outstanding to secure contractual performance. We believe these bonds and letters of credit will expire without any claims or payments thereon and therefore will not have a material adverse effect on our financial position, liquidity or operations.

Legal

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

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.

17

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS- (Continued)

(UNAUDITED)

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

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 (“Services Agreement”) with our GP. The Services Agreement is terminable by either party upon thirty days’ written notice. Under the terms of the Services Agreement, our GP provides services through its employees to us and is reimbursed for all related costs incurred on our behalf. Our GP provides us with services such as general administrative and management, human resources, legal, information technology, finance and accounting, corporate development, real property, marketing, engineering, operations (including mining operations), geological, risk management and insurance services. Pursuant to the Services Agreement, the primary reimbursements to our GP were for costs related to payroll. Reimbursable costs under the Services Agreement totaling $3,134 and $3,442 were included in accounts payable as of September 30, 2013 and December 31, 2012, 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. We sold equipment to Tunnell Hill for $877 in 2012. Sales to Tunnell Hill were $302 and $187 for the nine months ended September 30, 2013 and 2012, respectively. Accounts receivable from Tunnell Hill were $289 at September 30, 2013 and de minimis at December 31, 2012.

From time to time for business purposes, we charter the use of an airplane from Zanesville Aviation located in Zanesville, Ohio. C&T Coal owns an airplane that it leases to Zanesville Aviation and that Zanesville Aviation uses in providing chartering services to its customers including us. The aforementioned transactions were de minimis at September 30, 2013 and December 31, 2012, and for the three and nine months ending September 30, 2013 and 2012.

NOTE 13: SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information:

	For the Nine Months Ended September 30,
	2013		2012
Cash paid for:
Interest	$	8,588	$	8,482
Non-cash activities:
Coal reserves acquired with debt		-		307
Property and equipment acquired with debt		1,000		-
Reclamation and mine closure costs capitalized in mine development		10,669		6,411
Value of debt assigned to warrants		7,879		-
Market value of common units vested in LTIP		255		764

NOTE 14: SEGMENT INFORMATION

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

18

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the condensed consolidated financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q and the audited consolidated financial statements and notes thereto and management’s discussion and analysis of financial condition and results of operations for the year ended December 31, 2012 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 on Form 10-Q that are not historical facts are forward-looking statements within the “safe harbor” provision of the Private Securities Litigation Reform Act of 1995 and may involve a number of risks and uncertainties. We have used the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements.These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to various risks, uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements. The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

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

● 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 and expansion or consolidation;

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

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

● 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;

19

● timing of reductions or increases in customer coal inventories;

● long-term coal supply arrangements;

● reductions and/or deferrals of purchases by major customers;

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

● unexpected maintenance and equipment failure;

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

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

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

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

● employee benefits costs and labor relations issues;

● replacement of our reserves;

● our assumptions concerning economically recoverable coal reserve estimates;

● 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;

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

● adequacy and sufficiency of our internal controls;

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

● the need to recognize additional impairment and/or restructuring expenses associated with our operations, as well as any changes to previously identified impairment or restructuring expense estimates, including additional impairment and restructuring expenses associated with our Illinois Basin operations.

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

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Overview

We are a low-cost producer and marketer of high-value steam coal to United States 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 steam 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 Illinois, Indiana, Kentucky, Ohio, Pennsylvania and West Virginia.

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

We currently have 17 active surface mines and we manage these mines as eight mining complexes. Our reserves and operations are strategically located near our customers with the flexibility to ship by barge, truck or rail. During the three and nine months ended September 30, 2013, we produced 1.5 and 4.6 million tons of coal, respectively, and sold 1.7 and 5.0 million tons of coal, respectively, including 0.2 and 0.4 million tons of purchased coal, respectively.

As previously disclosed in our public filings, 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 idled one Illinois Basin mine and the related wash plant, closed our Illinois Basin lab, reduced operations at two other mines,terminated a significant number of employees and substituted purchased coal for mined and washed coal on certain sales contracts. As of September 30, 2013, production continued at one mine. We have redeployed most of the Illinois Basin equipment to our Northern Appalachian operations.

Based on current market conditions, we intend to idle all production activity in the Illinois Basin by the end of 2013 and to finish redeploying equipment during the first quarter of 2014. We expect these remaining restructuring efforts to cost an additional $0.9 million.Additionally, we are seeking to sell one large-capacity shovel and would consider offers for the remaining coal reserves and/or facilities related to the Illinois Basin operations. The remaining mining equipment will be moved to support Northern Appalachian operations.

Evaluating Our Results of Operations

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

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

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

● our net loss; and

● our Adjusted EBITDA, a non-GAAP financial measure.

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

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	Three Months Ended September 30,								Nine Months Ended September 30,
	2013			2012			% Change		2013			2012			% Change
	(tons in thousands, unaudited)								(tons in thousands, unaudited)
Produced tons		1,549			1,776			(12.8%)		4,650			5,285			(12.0%)
Purchased tons		121			146			(17.1%)		367			366			0.3%
Tons of coal sold		1,670			1,922			(13.1%)		5,017			5,651			(11.2%)
Tons sold under long-term contracts		93.5	%		94.0	%	n/a			94.5	%		93.0	%	n/a
Coal sales revenue per ton	$	50.74		$	49.45			2.6%	$	50.87		$	49.51			2.7%
Amortization of below-market coal sales contracts per ton		-			(0.06	)		(100.0%)		(0.01	)		(0.10	)		(90.0%)
Cash coal sales revenue per ton		50.74			49.39			2.7%		50.86			49.41			2.9%
Cash cost of coal sales per ton		(44.34	)		(41.20	)		7.6%		(43.84	)		(41.98	)		4.4%
Cash margin per ton	$	6.40		$	8.19			(21.9%)	$	7.02		$	7.43			(5.5%)
Number of operating days		64.0			67.0			(4.5%)		192.3			202.6			(5.1%)

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 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. Please read “— Cost of Coal Sales” for more information regarding our purchased coal.

Our long-term coal sales contracts typically provide for a fixed price, or a schedule of prices that are set by 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 certain items, such as fuel and inflation. Cost adjustment provisions adjust the initial contract price over the term of the contract either by a specific percentage or a percentage determined by reference to various cost-related indices, including cost-related indices for fuel and cost-of-living.

Cost of Coal Sales

We evaluate, on a cost per ton sold basis, our cost of coal sales, which excludes cost of other revenues, impairment and restructuring expenses, and gain or loss on asset disposals, non-cash costs such as depreciation, depletion, and amortization (“DD&A”), and indirect costs such as selling, general and administrative expenses. 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.

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

In March 2012, we entered into a long-term coal purchase contract with a supplier for our Illinois Basin operations for delivery of 0.4 million tons of coal in each of 2012 and 2013. A majority of the tons purchased for the year ended December 31, 2012 and the nine months ended September 30, 2013 were under this contract.

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 changes in mine reclamation obligations, and certain non-recurring items. 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 financing methods, capital structure or income taxes; our ability to generate cash sufficient to pay interest on our indebtedness, make distributions and fund capital expenditures; and our compliance with certaincredit 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.

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For a reconciliation of Net Loss to Adjusted EBITDA for the three and nine months ended September 30, 2013 and 2012, 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 nine months ended September 30, 2013, approximately 94.5%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.

Our projected coal sales volume is fully committed and priced for the balance of 2013.For 2014, 2015 and 2016, we have 5.0 million, 4.1 million and 2.1 million tons, respectively, committed under the terms of coal supply contracts. Of these amounts, in each of 2014 and 2015, 1.7 million tons are to be priced based on market indices, and in each of 2015 and 2016, 2.1 million tons are dependent upon reaching agreement 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 qualified workers, (5) the availability of transportation for coal shipments and/or (6) the costs and availability of key supplies and commodities such asdiesel fuel, steel, explosives and tires.

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

Factors Affecting the Comparability of Our Results of Operations

The comparability of our results of operations was impacted by impairment and restructuring expenses resulting from the actions taken with respect to our Illinois Basin operations as described above under “Overview.” For additional information regarding these impairment and restructuring charges, refer to “Part I. – Financial Information – Item 1. – Condensed Consolidated Financial Statements (Unaudited) – Notes to the Condensed Consolidated Financial Statements – Note 3 – Impairment and Restructuring Expenses.”

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Summary

The following table presents historical condensed consolidated financial data for the three and nine months ended September 30, 2013 and 2012:

SELECTED FINANCIAL AND OPERATING DATA                                

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands, unaudited)
STATEMENT OF OPERATIONS DATA:
REVENUE:
Coal sales	$	84,742		$	95,027		$	255,226		$	279,806
Other revenues		2,844			2,187			9,211			7,223
Total revenues		87,586			97,214			264,437			287,029
COSTS AND EXPENSES:
Cost of coal sales:
Produced coal		68,175			72,896			202,159			221,101
Purchased coal		5,881			6,274			17,774			16,121
Total cost of coal sales (excluding depreciation,depletion and amortization)		74,056			79,170			219,933			237,222
Cost of other revenue		455			499			1,228			1,285
Depreciation, depletion and amortization		12,017			13,110			37,760			39,019
Selling, general and administrative expenses		3,051			3,901			13,056			11,475
Impairment and restructuring expenses		150			206			1,012			13,843
(Gain) loss on disposal of assets, net		(1,107	)		357			(6,594	)		(4,156	)
Total costs and expenses		88,622			97,243			266,395			298,688
INCOME (LOSS) FROM OPERATIONS:		(1,036	)		(29	)		(1,958	)		(11,659	)
INTEREST AND OTHER INCOME (EXPENSE)
Interest income		1			1			3			7
Interest expense		(6,808	)		(3,012	)		(14,146	)		(8,522	)
Change in fair value of warrants		2,714			-			565			-
Total interest and other expenses		(4,093	)		(3,011	)		(13,578	)		(8,515	)
NET LOSS		(5,129	)		(3,040	)		(15,536	)		(20,174	)
Net income attributable to noncontrolling interest		(470	)		(274	)		(1,120	)		(371	)
Net loss attributable to Oxford Resource
Partners, LP unitholders	$	(5,599	)	$	(3,314	)	$	(16,656	)	$	(20,545	)

The following table presents a reconciliation of net loss to Adjusted EBITDA for the three and nine months ended September 30, 2013 and 2012:

 RECONCILIATION OF NET LOSS TO ADJUSTED EBITDA 

	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands, unaudited)
Net loss	$	(5,129	)	$	(3,040	)	$	(15,536	)	$	(20,174	)
Adjustments:
Interest expense, net of interest income		6,807			3,011			14,143			8,515
Depreciation, depletion and amortization		12,017			13,110			37,760			39,019
Change in fair value of warrants		(2,714	)		-			(565	)		-
Impairment and restructuring expenses		150			206			1,012			13,843
(Gain) loss on disposal of assets, net		(1,107	)		357			(6,594	)		(4,156	)
Amortization of below-market coal sales contracts		-			(121	)		(60	)		(543	)
Non-cash equity-based compensation expense		351			490			1,090			966
Non-cash changes in mine reclamation obligations		625			384			1,683			1,189
Non-recurring items:
Debt refinancing expenses		-			-			3,059			-
Other		-			(227	)		(2,100	)		1,238
Adjusted EBITDA	$	11,000		$	14,170		$	33,892		$	39,897

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Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

Overview

Net loss for the three months ended September 30, 2013 was $5.1 million, compared to $3.0 million for the three months ended September 30, 2012. Total revenue was $87.6 million for the three months ended September 30, 2013, a decrease of $9.6 million, or 9.9%, from $97.2 million for the three months ended September 30, 2012. Adjusted EBITDA was $11.0 million for the three months ended September 30, 2013, a decrease of $3.2 million from $14.2 million for the three months ended September 30, 2012. Cash margin per ton was $6.40 for the three months ended September 30, 2013, a decrease of $1.79, or 21.9%, per ton from $8.19 per ton for the three months ended September 30, 2012.

Coal Sales Revenue

Coal sales revenue was $84.7 million for the three months ended September 30, 2013, a decrease of $10.3 million, or 10.8%, from $95.0 million for the three months ended September 30, 2012. The decrease was primarily attributable to a 13.1% reduction in tons sold with a value of $12.5 million that was a result of the lower sales volume from the Illinois Basin operations, partially offset by a price increase of $1.29 per ton, or an aggregate $2.2 million, increase in coal sales revenue for the three months ended September 30, 2013.

Other Revenue

Other revenue, primarily from clay and limestone sales and royalty income, was $2.8 million for the three months ended September 30, 2013, an increase of $0.6 million, or 30.0%, from $2.2 million for the three months ended September 30, 2012. Non-coal revenue increased $1.2 million to $1.5 million for the three months ended September 30, 2013 from $0.3 million for the three months ended September 30, 2012, due primarily to a one-time payment of $1.3 million for lost coal in connection with granting third-party access through a small portion of a mine complex. The $1.2 million increase in non-coal revenue was offset by $0.4 million and $0.2 million decreases in royalty income and clay and limestone sales, respectively. Royalty income was de minimis for the three months ended September 30, 2013 due to a temporary cessation of production at an underground mine leased to a third party, as compared to royalty income of $0.4 million for the three months ended September 30, 2012. Clay and limestone sales were $1.3 million for the three months ended September 30, 2013, a decrease of $0.2 million from $1.5 million for the three months ended September 30, 2012.

Cost of Coal Sales (Excluding DD&A)

Cost of coal sales (excluding DD&A) was $74.1 million for the three months ended September 30, 2013, a decrease of $5.1 million, or 6.5%, from $79.2 million for the three months ended September 30, 2012. The decrease was primarily attributable to a 13.1% reduction in tons sold with a cost of $10.3 million, partially offset by an increase in cost to produce coal of $3.14 per ton, or an aggregate $5.2 million, for the three months ended September 30, 2013. Cost of coal sales per ton was $44.34 for the three months ended September 30, 2013, an increase of $3.14, or 7.6%, per ton from $41.20 per ton for the three months ended September 30, 2012. The $3.14 per ton increase was primarily attributable to a $1.4 million increase in transportation expense, a $1.3 million increase in employee wages, a $1.2 million increase in explosives expense, and a $1.1 million increase in tire expense. Transportation expense for the three months ended September 30, 2013 increased $0.83 per ton sold, or an aggregate $1.4 million, due to longer haul routes. Employee cost increased $0.93 per ton sold, or 2.2%, primarily the result of producing 0.2 million fewer tons.

Depreciation, Depletion and Amortization

DD&A expense was $12.0 million for the three months ended September 30, 2013, a decrease of $1.1 million, or 8.3%, from $13.1 million for the three months ended September 30, 2012. The $0.6 million decrease in depreciation expense to $7.8 million for the three months ended September 30, 2013 was primarily attributable to the restructuring related to our Illinois Basin operations. Depletion expense remained flat at $1.3 million, in spite of a reduction in coal tons mined, due to the mix of coal tons mined from owned reserves versus leased reserves for the three months ended September 30, 2013 and 2012. Amortization expense decreased $0.5 million, or 13.2%, to $2.9 million for the three months ended September 30, 2013, primarily due to a decrease inreclamation adjustments at closed mines.

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Selling, General and Administrative Expenses

Selling, general and administrative expenses were $3.1 million for the three months ended September 30, 2013, a decrease of $0.8 million, or 21.8%, from $3.9 million for the three months ended September 30, 2012. The decrease of $0.8 million was primarily the result of a $0.4 million decrease in compensation and lower insurance and professional fees experienced during the three months ended September 30, 2013 compared to the three months ended September 30, 2012.

Impairment and Restructuring Expenses 

Impairment and restructuring expenses remained flat at $0.2 million for the three months ended September 30, 2013 and 2012. These expenses consisted of professional fees and equipment transportation costs associated with the restructuring relating to our Illinois Basin operations.

(Gain) Loss on Disposal of Assets, Net

The net gain on the disposal of assets of $1.1 million for the three months ended September 30, 2013 represents an increase of $1.5 million from a net loss of $0.4 million for the three months ended September 30, 2012. The $1.1 million gain on the disposal of assets for the three months ended September 30, 2013 was primarily due to the $3.0 million of insurance proceeds received on equipment lost in mining activities with a carrying value of $1.6 million, resulting in a $1.4 million gain. These gains were offset by net losses generated from the disposal of equipment in the normal course of business of $0.3 million for the three months ended September 30, 2013 compared to $0.4 million for the three months ended September 30, 2012.

Net Income Attributable to Noncontrolling Interest

Net income attributable to noncontrolling interest relates to the 49% ownership interest in Harrison Resources owned by a subsidiary of CONSOL Energy. Net income attributable to noncontrolling interest was $0.5 million for the three months ended September 30, 2013, an increase of $0.2 million from $0.3 million for the three months ended September 30, 2012. This increase in net income attributable to noncontrolling interest was primarily due to lower costs at the Harrison mine.

Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Overview

Net loss for the nine months ended September 30, 2013 was $15.5 million, compared to $20.2 million for the nine months ended September 30, 2012. The $4.7 million decrease in net loss was attributed in part to a decrease in impairment and restructuring expenses of $12.8 million and a positive change in fair value of warrants of $0.6 million, offset by costs associated with refinancing of our credit facility, including a $5.6 million increase in interest expense, $3.1 million in debt refinancing expenses, and an $0.8 million write-off of deferred financing costs related to our previous credit facility. Total revenue was $264.4 million for the nine months ended September 30, 2013, a decrease of $22.6 million, or 7.9%, from $287.0 million for the nine months ended September 30, 2012. Adjusted EBITDA was $33.9 million for the nine months ended September 30, 2013, a decrease of $6.0 million from $39.9 million for the nine months ended September 30, 2012. Cash margin per ton was $7.02 for the nine months ended September 30, 2013, a decrease of $0.41, or 5.5%, per ton from $7.43 per ton for the nine months ended September 30, 2012.

Coal Sales Revenue

Coal sales revenue was $255.2 million for the nine months ended September 30, 2013, a decrease of $24.6 million, or 8.8%, from $279.8 million for the nine months ended September 30, 2012. The decrease was primarily attributable to an 11.2% reduction in sales tons with a value of $31.4 million that was a result of the lower sales volume from the Illinois Basin operations, partially offset by a $1.36 per ton, or an aggregate $6.8 million, increase in coal sales revenue for the nine months ended September 30, 2013.

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Other Revenue

Other revenue, primarily from clay and limestone sales and royalty income, was $9.2 million for the nine months ended September 30, 2013, an increase of $2.0 million, or 27.5%, from $7.2 million for the nine months ended September 30, 2012. Non-coal revenue increased $4.1 million to $5.0 million for the nine months ended September 30, 2013 from $0.9 million for the nine months ended September 30, 2012, due primarily to one-time payments totaling $2.4 million for lost coal in connection with granting third-party access through small portions of certain mine complexes and a $2.1 million settlement payment from a former coal supplier supporting sales from our Illinois Basin operations made pursuant to a settlement agreement entered into in February 2013. The $4.1 million increase in non-coal revenue was offset by $1.5 million and $0.6 million decreases in royalty income and clay and limestone sales, respectively. Royalty income was de minimis for the nine months ended September 30, 2013 due to a temporary cessation of production at an underground mine leased to a third party, as compared to royalty income of $1.5 million for the nine months ended September 30, 2012. Clay and limestone sales were $4.2 million for the nine months ended September 30, 2013, a decrease of $0.6 million, or 12.5%, from $4.8 million for the nine months ended September 30, 2012.

Cost of Coal Sales (Excluding DD&A)

Cost of coal sales (excluding DD&A) was $219.9 million for the nine months ended September 30, 2013, a decrease of $17.3 million, or 7.3%, from $237.2 million for the nine months ended September 30, 2012. The decrease was primarily attributable to a reduction of 0.7 million in tons sold, which corresponds to a $26.5 million decrease in cost of coal sales, partially offset by an increase in cost to produce coal of $1.86 per ton, or an aggregate $9.2 million, for the nine months ended September 30, 2013. Cost of coal sales per ton was $43.84 for the nine months ended September 30, 2013, an increase of $1.86, or 4.4%, per ton from $41.98 per ton for the nine months ended September 30, 2012. The $1.86 per ton increase was primarily attributable to a $0.69 per ton, or $3.5 million, increase in the cost of purchased coal, a $0.81 per ton, or $4.0 million, increase in transportation expense and a $0.51 per ton, or $2.6 million, increase in tire expense, partially offset by a $0.32 per ton, or $1.6 million, decrease in diesel fuel expense. For the nine months ended September 30, 2013, 367,000 tons of coal were purchased at an average price of $48.43 per ton, which represent increases of 1,000 tons and $4.38 per ton compared to 366,000 tons of coal purchased at an average price of $44.05 per ton for the nine months ended September 30, 2012. Transportation expense for the nine months ended September 30, 2013 increased $0.81 per ton sold, or $4.0 million, due to longer haul routes. Diesel fuel expense decreased $0.32 per ton sold due to lower spot prices in 2013 resulting in $1.6 million in diesel fuel expense savings for the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012.

Depreciation, Depletion and Amortization

DD&A expense was $37.8 million for the nine months ended September 30, 2013, a decrease of $1.2 million, or 3.2%, from $39.0 million for the nine months ended September 30, 2012. Depreciation expense decreased $3.4 million, or 12.6%, to $23.3 million for the nine months ended September 30, 2013, from $26.7 million for the nine months ended September 30, 2012, which decrease was primarily attributable to the restructuring related to our Illinois Basin operations. Depletion expense was $3.0 million for the nine months ended September 30, 2013, a $1.0 million decrease from $4.0 million for the nine months ended September 30, 2012, which decrease was primarily attributable to producing 0.7 million fewer tons of coal for the nine months ended September 30, 2013, compared to the nine months ended September 30, 2012. These decreases in depreciation and depletion expense were mostly offset by a $3.2 million increase in amortization expense for the nine months ended September 30, 2013. Increase in amortization expense of $3.2 million, to $11.5 million, for the nine months ended September 30, 2013 from $8.3 million for the nine months ended September 30, 2012, was primarily attributable to an increase in the cost ofreclamation work.

Selling, General and Administrative Expenses

Selling, general and administrative expenses were $13.1 million for the nine months ended September 30, 2013, an increase of $1.6 million, or 13.8%, from $11.5 million for the nine months ended September 30, 2012. The increase includes $3.1 million of fees, primarily for advisor and legal services, related to the refinancing of our credit facility, offset in part by decreases in wages and contract labor expenses.

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Impairment and Restructuring Expenses

Impairment and restructuring expenses were $1.0 million for the nine months ended September 30, 2013, a decrease of $12.8 million, from $13.8 million for the nine months ended September 30, 2012. Such expenses consisted of equipment transportation costs and coal lease termination costs associated with the restructuring relating to our Illinois Basin operations.

(Gain) Loss on Disposal of Assets, Net

The net gain on disposal of assets of $6.6 million for the nine months ended September 30, 2013 represents an increase of $2.4 million from a net gain of $4.2 million for the nine months ended September 30, 2012. The gain on disposal of assets for the nine months ended September 30, 2013 and 2012 relates to the sale of certain oil and gas rights resulting in net gains of $6.1 million and $6.3 million, respectively. Additionally, $3.0 million in insurance proceeds was received on equipment lost in mining activities with a carrying value of $1.6 million, resulting in a $1.4 million gain. These gains were offset by net losses generated from the disposal of equipment in the normal course of business of $0.9 million for the nine months ended September 30, 2013, compared to $2.1 million in net losses from the disposal of equipment for the nine months ended September 30, 2012.

Net Income Attributable to Noncontrolling Interest

Net income attributable to noncontrolling interest relates to the 49% ownership interest in Harrison Resources owned by a subsidiary of CONSOL Energy. Net income attributable to noncontrolling interest was $1.1 million for the nine months ended September 30, 2013, an increase of $0.7 million from $0.4 million for the nine months ended September 30, 2012. This increase in net income attributable to noncontrolling interest was primarily due to lower costs at the Harrison mine.

Liquidity and Capital Resources

Liquidity

Our business is capital intensive and requires substantial capital expenditures for, among other things, maintaining, purchasing, and upgrading equipment used in mining our coal, and acquiring reserves. Our principal liquidity needs are to finance current operations, fund capital expenditures, including acquisitions from time to time, and service our debt. Liquidity has also been used in the past to pay cash distributions to our unitholders. Our primary sources of liquidity to meet these needs are cash generated by our operations and borrowings under theFinancing Agreements (as defined below). Also, if we are able to effect any asset sales associated with our Illinois Basin restructuring at acceptable values, our liquidity will be enhanced by those amounts.

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

At September 30, 2013, our available liquidity was $11.2 million, which consisted of $2.7 million in cash on hand and $8.5 million of borrowing availability under theFinancing Agreements. For the nine months ended September 30, 2013, we enhanced liquidity through the following:

● the receipt of a settlement payment of $2.1 million from a purchase coal supplier to settle a contract dispute;

● sales of certain oil and gas rights resulting in a $1.8 million increase in liquidity; and

● the receipt of one-time payments totaling $1.1 million for lost coal in connection with grants of third-party access rights through small portions of certain mine complexes.

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Additionally, we continue to pursue the sale of a shovel, which is our remaining piece of excess Illinois Basin equipment to be sold.

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

Cash Flows

Cash flows for the nine months ended September 30, 2013 and 2012 are as follows:

	Nine Months Ended September 30,
	2013			2012
	(in thousands,unaudited)
Net cash from:
Operating activities	$	5,501		$	16,761
Investing activities		(4,519	)		(6,402	)
Financing activities		(2,221	)		(7,140	)
Total	$	(1,239	)	$	3,219

Net cash provided by operating activities was $5.5 million for the nine months ended September 30, 2013 compared to $16.8 million in cash flows provided by operating activities for the nine months ended September 30, 2012, a decrease of $11.3 million.We experienced a net loss for the nine months ended September 30, 2013 of $15.5 million, a decrease of $4.7 million, or 23.0%, compared to a net loss of $20.2 million for the nine months ended September 30, 2012. The decrease in the loss was attributable in part to a $12.8 million decrease in impairment and restructuring expenses related to our Illinois Basin operations and a $2.4 million increase in the gain on sale of assets, offset by $3.1 million of expenses related to our debt refinancing, a $0.6 million negative change in the fair value of warrants associated with the refinancing of our credit facility and a $1.5 million increase in amortization and write-off of deferred financing costs. These differences, combined with $3.9 million in unfavorable changes in working capital, are the primary drivers of the decrease in cash provided by operating activities.The unfavorable change in working capital was primarily attributable to a $6.5 million increase in accounts receivable and $2.6 million decrease in accounts payable, combined with a favorable change of $1.0 million in inventory.The inventory change was primarily due to lower coal stockpile levels at September 30, 2013 compared to December 31, 2012.

Net cash used in investing activities was$4.5million for the nine months ended September 30, 2013, compared to$6.4million for the nine months ended September 30, 2012, a decrease of$1.9million. The decreasewas attributed to a $3.0 million increase in insurance proceeds and a favorable change of $2.6 million in the purchase of property and equipment, partially offset by a $1.7 million decrease in restricted cash and a $2.2 million reduction in proceeds from the sale of assets. The $2.6 million favorable change in the purchase of property and equipment results from our ability tosatisfy mining equipment requirements in Northern Appalachia with existing mining equipment transferred from our Illinois Basin operations.

Net cash used in financing activities was$2.2million for the nine months ended September 30, 2013, down$4.9million from net cash used by financing activities of$7.1million for the nine months ended September 30, 2012. The favorable change of$4.9million was primarily attributable to a$20.6million reduction in distributions to partners, partially offset by a$15.7million increase in borrowings, net of payments and financing fees, of which$11.2million of borrowings outstanding under the First Lien Financing Agreement was used to temporarily cash collateralize existing letters of credit securing 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, borrowings under theFinancing Agreements, and proceeds from asset sales.

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The following table summarizes our capital expenditures, net of reinvested insurance proceeds, by type for the three and nine months ended September 30, 2013 and 2012:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
	(in thousands, unaudited)
Coal reserves and land	$	-	$	-	$	14	$	51
Mine development		672		1,123		2,612		2,723
Property and equipment, including components		3,926		4,058		10,606		15,378
Total	$	4,598	$	5,181	$	13,232	$	18,152

 

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 second lien lenders) under a financing agreement (as amended, the “Second Lien Financing Agreement,” and collectively with the First Lien Financing Agreement, the “Financing Agreements”).

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 September 30, 2013, the blended cash interest rate for both credit facilities was 9.52%.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 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 September 30, 2013, and for the period from the date of issuance through September 30, 2013 the fair value of the warrants decreased by $2.7 million and $0.6 million, respectively.

First Lien Credit Facility Borrowings

As of September 30, 2013, we had a term loan of $69.3 million outstanding under the first lien credit facility. We 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 September 30, 2013, 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 $16.5 million was outstanding as of September 30, 2013. The revolver bears interest at the same rates as the term loan under the first lien credit facility. As of September 30, 2013, the balance outstanding on the revolver had a weighted average cash interest rate of 8.63%, consisting of either LIBOR of 1.5% plus 6.75% or the Reference Rate of 3.25% plus 6.25%.

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Second Lien Credit Facility Borrowings

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, or $7.9 million. The value allocated to the warrants was recorded as a debt discount, with the remaining $67.1 million assigned to the term loan. This discount will be amortized to interest expense over the life of the second lien credit facility using the effective interest method. Amortization of the debt discount totaled $0.7 from the date of issuance through September 30, 2013.

We are obligated to make quarterly principal payments of $0.2 million commencing in June 2014, until repayment of the then outstanding balance at maturity. The term loan under the second lien credit facility bears cash interest at a variable rate per annum equal to, at our option, LIBOR (floor of 1.25%) plus 9.75% or the Reference Rate (as defined in the Second Lien Financing Agreement) (floor of 3.00%) plus 11.75%. As of September 30, 2013, the second lien term loan had a cash interest rate of 11.0%, 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. PIK Interest totaled $1.2 million from the date of issuance through September 30, 2013.

As of September 30, 2013, the outstanding balance on the second lien credit facility term loan is $69.0 million. This amount represents the principal balance of $75.0 million, plus PIK Interest of $1.2 million, net of the unamortized debt discount of $7.2 million.

Off-Balance Sheet Arrangements

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

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

As of September 30, 2013, we had $37.1 million in surety bonds outstanding to secure certain reclamation obligations which were collateralized by cash of $11.2 million. Such cash bonds are included in “other long-term assets” on our condensed consolidated balance sheet. We are currently working to replace the cash collateral with letters of credit. Additionally, we had road bonds totaling $0.6 million and performance bonds totaling $2.1 million outstanding to secure contractual performance. We believe these bonds and letters of credit will expire without any claims or payments thereon and therefore will not have a material adverse effect on our financial position, liquidity or operations.

New Accounting Standards Adopted

There were various other updates recently issued, most of which represented technical corrections to the 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.

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Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts. These estimates and assumptions are based on information available as of the date of the financial statements. Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end. The results of operations for the three and nine months ended September 30, 2013 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. Our projected sales for the balance of 2013 are fully 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 for a change in the price per coal ton sold in the event of changes in diesel fuel pricing. As of September 30, 2013, we had such price protection with respect to approximately 95% of our expected diesel fuel purchases for the remainder of 2013.

Item 4. Controls and Procedures

We maintain controls and procedures designed to ensure that information required to be disclosed in the reports we file with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow for timely decisions regarding required disclosure. An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”)) was performed as of September 30, 2013. 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 September 30, 2013 to ensure that the Partnership is able to collect, process and disclose the information it is required to disclose in the reports it files with the SEC within the required time periods. During the quarterly period ended September 30, 2013, there have not been any changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) identified in connection with this evaluation that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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PART II. OTHER INFORMATION

Item 1.    Legal Proceedings

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

Item 1A. Risk Factors

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

Item 4.    Mine Safety Disclosures

Our mining operations are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95 to this Quarterly Report on Form 10-Q.

Item 6.    Exhibits

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

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SIGNATURES

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

 Date: November 5, 2013   

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)

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EXHIBIT INDEX

Exhibit Number	Exhibit Description
3.1	Certificate of Limited Partnership of Oxford Resource Partners, LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (Commission File No. 333-165662) filed on March 24, 2010)
3.2	Third Amended and Restated Agreement of Limited Partnership of Oxford Resource Partners, LP dated July 19, 2010 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (Commission File No. 001-34815) filed on July 19, 2010)
3.2A	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)
10.24A*	Amendment No. 1 to Financing Agreement, dated as of August 13, 2013, by and among Oxford Mining Company, LLC, as borrower, Oxford Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Cerberus Business Finance, LLC, as collateral agent and administrative agent for such lenders
10.25A*	Amendment No. 1 to Financing Agreement, dated as of August 13, 2013, by and among Oxford Mining Company, LLC, as borrower, Oxford Resource Partners, LP, as a guarantor, the other guarantors party thereto, the lenders party thereto, and Obsidian Agency Services, Inc., as collateral agent and administrative agent for such lenders
31.1*	Certification of Charles C. Ungurean, President and Chief Executive Officer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification of Charles C. Ungurean, President and Chief Executive Officer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of Bradley W. Harris, Senior Vice President, Chief Financial Officer and Treasurer of Oxford Resources GP, LLC, the general partner of Oxford Resource Partners, LP, for the September 30, 2013 Quarterly Report on Form 10-Q, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
95*	Mine Safety Disclosures
101*	Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012; (ii) our Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012; (iii) our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012; (iv) our Condensed Consolidated Statements of Partners’ Capital (Deficit) for the nine months ended September 30, 2013 and 2012; and (v) the notes to our Condensed Consolidated Financial Statements. This information is furnished and not filed for purposes of Sections 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934

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

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