Westmoreland Resource Partners, LP - FORM 8-K - EX-99.1

Attached files

file	filename
8-K - FORM 8-K - Westmoreland Resource Partners, LP	c13096e8vk.htm

Exhibit 99.1

Partnership Contact:
Brian Meilton
(614) 643-0314
ir@OxfordResources.com

Oxford Resource Partners, LP Reports Fourth Quarter and
Full Year 2010 Financial Results

COLUMBUS, Ohio, February 24, 2011 — Oxford Resource Partners, LP (NYSE: OXF) (the “Partnership” or “Oxford”) today announced results for the fourth quarter and full year 2010. Net loss for the fourth quarter of 2010 was $1.6 million, or $0.05 per diluted limited partner unit, compared to net income for the fourth quarter of 2009 of $0.9 million, or $0.02 per diluted limited partner unit. Adjusted EBITDA, a non-GAAP financial measure, was $14.4 million for the fourth quarter of 2010, up 10.8% from $13.0 million for the fourth quarter of 2009. Fourth quarter 2009 results included a temporary price increase that positively impacted net income and adjusted EBITDA by $3.0 million in that quarter.

For the year ended December 31, 2010, coal production increased 28.3% to 7.4 million tons from 5.8 million tons in 2009. The Partnership’s tons sold increased 29.2% to 8.2 million tons in 2010 from 6.3 million tons in 2009. During 2010, 96% of tons sold were sold under long-term coal sales contracts. Total revenue for the year ended December 31, 2010 was $356.6 million compared to $293.8 million for 2009. The full year 2010 net loss was $7.4 million, or $0.45 per diluted limited partner unit, compared to the full year 2009 net income of $23.5 million, or $2.08 per diluted limited partner unit. Net income in 2009 was positively impacted by a temporary price increase and gain on acquisition of $13.3 million and $3.8 million, respectively. The 2010 net loss included higher depreciation, depletion and amortization (DD&A) of $16.4 million, primarily due to the full year impact on DD&A of the Partnership’s 2009 acquisition of Phoenix Coal’s active Illinois Basin surface mining assets in western Kentucky and the partial year impact on DD&A from the Partnership’s purchase of previously leased and additional major mining equipment using proceeds from the Partnership’s initial public offering and borrowings under the Partnership’s credit facility.

Adjusted EBITDA for 2010 was $51.6 million versus $57.0 million for 2009. Adjusted EBITDA in 2009 was positively impacted by the aforementioned $13.3 million temporary price increase.

Distributable cash flow, a non-GAAP financial measure, was $8.5 million for the last two quarters of 2010 during which Oxford was a publicly-traded partnership. Of the $8.5 million in distributable cash flow, $5.2 million was attributable to the fourth quarter of 2010.

Definitions of adjusted EBITDA and distributable cash flow, which are non-GAAP financial measures referred to in the preceding four paragraphs of this press release, and reconciliations to comparable GAAP financial measures, are included in the non-GAAP financial measures tables presented at the end of this press release. Adjusted EBITDA and distributable cash flow have been recalculated and/or redefined with resulting adjustments to previously-reported amounts, as shown in the non-GAAP financial measures tables presented at the end of this press release.

President and Chief Executive Officer Charles C. Ungurean commented, “The 2010 year was a momentous one as we became a publicly-traded partnership and integrated our Illinois Basin assets while maintaining strong operational execution and excellent mine safety. I am extremely pleased with our full year and fourth quarter 2010 results, which were achieved while dealing with a number of unexpected challenges.”

Ungurean continued, “Looking ahead, we believe the domestic steam coal market dynamics will continue to be strong as electricity consumption is projected to increase while utility coal stockpiles continue to deplete. Meanwhile, production volumes remain challenged in certain coal producing regions, particularly in Central Appalachia. Coal from our production regions — Northern Appalachia and the Illinois Basin — should benefit from the supply pressures faced in the Central Appalachia region. In addition, the export markets remain very solid, which will further reduce domestic supply. We believe we are well positioned to benefit from these dynamics given our foothold in Northern Appalachia and the Illinois Basin. During 2010, we increased coal sales by 29% year-over-year and anticipate continued growth in sales and production in 2011 with a higher average sales price while maintaining our cost structure thereby realizing additional margin growth.”

During 2010, the Partnership executed over $250 million in long-term coal sales contracts primarily having an effect beginning in 2012. These contracts, the majority of which were related to the Illinois Basin operations, were executed at prices significantly higher than current levels. For 2011, 2012, 2013 and 2014, the Partnership currently has long-term coal sales contracts in place that represent 100%, 78%, 52% and 47%, respectively, of the Partnership’s estimated 2011 coal sales of 9.1 million tons.

Update on Temporary Factors Impacting Second Half 2010 Performance

The second half 2010 net loss, adjusted EBITDA and distributable cash flow were negatively impacted by $6.6 million, $4.3 million and $2.3 million, respectively, in the third and fourth quarters of 2010 together, as more fully described below.

•

In the Illinois Basin, the unexpected delay in the receipt of the Partnership’s Rose France mine 404 permit adversely impacted production by 36,000 tons in the third quarter and 64,000 tons in the fourth quarter. This delay increased operating costs by approximately $0.5 million in the third quarter and $0.7 million in the fourth quarter, or $0.24 and $0.37 per ton, respectively.

•

Production is currently ramping up and the Partnership expects to achieve full production at this mine by the end of the first quarter of 2011.

•

In Northern Appalachia, geologic conditions at the Partnership’s Plainfield complex and higher strip ratios (the ratio of removed earth overburden to extracted coal) at certain of the Partnership’s other Ohio mining complexes increased operating costs by approximately $1.3 million in the third quarter and $1.6 million in the fourth quarter, or $0.68 and $0.85 per ton, respectively.

•

The Partnership implemented a plan to resolve these issues and eliminate the impact to future quarters. To compensate for the resulting reduced production at its Plainfield complex, Oxford took the necessary steps to replace lost future production by relocating some equipment and personnel from its Plainfield complex to other Oxford mining complexes (including the Belmont County complex for which Oxford also took the related step of acquiring additional permitted reserves), thereby positioning Oxford to increase its production at those other mining complexes.

•

Higher repair and maintenance expenses increased operating costs by approximately $1.9 million in the third quarter due to timing differences.

•

Repair and maintenance expenses were back in line with historical levels in the fourth quarter.

•

A temporary reduction in royalty payments on the Partnership’s underground reserves leased to a third party reduced royalty and non-coal revenue by approximately $0.6 million in the third quarter.

•

Mining activity resumed on the Partnership’s royalty-generating property in late September, resulting in the normal level of royalty payments being received in the fourth quarter.

Production and Sales Information Summary

A summary of certain production and sales information providing year-over-year comparisons for the full year and fourth quarter 2010 and 2009 and comparisons for the fourth quarter over the third quarter 2010 is presented in the table set forth below.


	Year Ended						Three Months Ended
	December 31,						December 31,						September 30,
(tons in thousands)	2010			2009			2010			2009			2010

Tons of coal produced (clean)		7,417			5,781			1,904			1,810			1,902
Tons of coal purchased		734			530			117			223			122
Tons of coal sold		8,151			6,311			2,021			2,033			2,024
Tons sold under long-term contracts ⁽¹⁾		95.9	%		97.8	%		95.2	%		97.7	%		95.2	%

Average sales price per ton ⁽²⁾	$	38.22		$	40.27		$	38.66		$	38.10		$	38.60
Cost of purchased coal sales per ton	$	30.00		$	36.79		$	29.15		$	32.14		$	31.10
Cost of coal sales per ton	$	30.94		$	29.52		$	30.38		$	30.35		$	30.04

Number of operating days — NAPP operations		275.5			274.5			67.0			67.5			69.5
Number of operating days — ILB operations		273.0			60.5			65.5			60.5			69.5


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

(2)		Average sales price per ton was positively impacted by $2.10 and $1.45 for the year and quarter ended December 31, 2009, respectively, due to a temporary price increase from a customer.

Three Months Ended December 31, 2010

Coal Production. Tons of coal produced increased 5.2% to 1.9 million tons in the fourth quarter of 2010 from 1.8 million tons in the fourth quarter of 2009. This increase was primarily due to a 4.0% increase in production from the Ohio mining complexes in Northern Appalachia (“NAPP”) and a 9.1% increase in production from the Muhlenberg County complex in the Illinois Basin (“ILB”). As noted previously, fourth quarter 2010 production was negatively impacted by the delayed start-up of the Rose France mine and adverse geologic conditions at the Plainfield complex.

Sales Volume. The Partnership sold 2.0 million tons in each of the fourth quarters of 2010 and 2009, and also sold 2.0 million tons in the third quarter of 2010.

Average Sales Price. Average sales price per ton increased 1.5% to $38.66 in the fourth quarter of 2010 from $38.10 in the fourth quarter of 2009. Adjusted for a 2009 temporary price increase from a customer, the increase in average sales price per ton for the fourth quarter 2010 would have been 5.5% year-over-year. The increase from the prior year’s fourth quarter was attributable to higher-priced committed sales for both NAPP and ILB operations. Average sales price per ton in the fourth quarter of 2010 was slightly higher than the third quarter of 2010.

Coal Sales Revenue. For the fourth quarter of 2010, coal sales revenue increased by $0.6 million, or 0.8%, to $78.1 million from $77.5 million for the fourth quarter of 2009 due to a higher average sales price. Compared to the third quarter of 2010, fourth quarter 2010 coal sales revenue was at the same level.

Royalty and Non-Coal Revenue. For the fourth quarter of 2010, royalty and non-coal revenue was equal to the fourth quarter of 2009. Compared to the third quarter of 2010, royalty and non-coal revenue for the fourth quarter of 2010 increased $0.3 million, or 23.5%, from $1.3 million due primarily to mining activity resuming on the Partnership’s royalty-generating property as previously discussed, partially offset by lower non-coal revenues due to a retroactive adjustment to limestone sales included in the third quarter of 2010 non-coal revenue.

Cost of Coal Sales (Excluding DD&A). Cost of coal sales (excluding DD&A) increased 5.3% to $57.8 million in the fourth quarter of 2010 from $54.9 million in the fourth quarter of 2009 due primarily to higher production volumes. Excluding the unfavorable impact of the temporary factors related to Rose France and Plainfield discussed previously, cost of coal sales per ton for the fourth quarter of 2010 would have totaled $29.16 per ton, or 3.9% lower than the $30.35 per ton for the fourth quarter of 2009. This reduction in cost per ton was primarily due to cost improvements at the Muhlenberg County complex in the ILB. Cost of coal sales per ton increased 1.1% from $30.04 in the third quarter of 2010 to $30.38 in the fourth quarter of 2010. This increase was primarily due to a shift in production mix in the fourth quarter as compared to the third quarter of 2010.

Cost of Purchased Coal. Cost of purchased coal declined to $3.4 million in the fourth quarter of 2010 from $7.2 million in the fourth quarter of 2009 and $3.8 million in the third quarter of 2010, due to both a lower average cost of purchased coal per ton and a lower volume of coal purchased. Average cost of purchased coal per ton decreased by 9.3% to $29.15 per ton in the fourth quarter of 2010 compared to the fourth quarter of 2009 due to a significant portion of purchases in the fourth quarter of 2010 being supplied under a favorably-priced long-term coal purchase contract assumed in the acquisition of ILB assets compared to a high percentage of purchases in the fourth quarter of 2009 through higher-priced spot market purchases. Average cost of purchased coal per ton in the fourth quarter of 2010 declined 6.3% from $31.10 in the third quarter of 2010 due to a greater amount of purchases being supplied under the favorably-priced long-term coal purchase contract and a lower volume of higher-priced spot market purchases.

Depreciation, Depletion and Amortization (DD&A). DD&A expense in the fourth quarter of 2010 was $11.7 million compared to $8.6 million in the fourth quarter of 2009, an increase of $3.1 million. This increase resulted primarily from an increase in depreciation due to the Partnership’s 2010 purchase of previously leased and additional major mining equipment using proceeds from the Partnership’s initial public offering and borrowings under the Partnership’s credit facility. DD&A expense in the fourth quarter of 2010 declined to $11.7 million from $12.3 million in the third quarter of 2010.

Selling, General and Administrative Expenses (SG&A). SG&A expenses in the fourth quarter of 2010 were $4.3 million compared to $3.9 million in the fourth quarter of 2009, primarily due to expenses related to being a publicly-traded partnership. SG&A expenses in the fourth quarter of 2010 increased $0.3 million from the third quarter of 2010 primarily due to additional publicly-traded partnership expenses and additional administrative expenses for supporting the Muhlenberg County complex in the ILB.

Recent Developments

Oxford has reached an agreement in principle with an existing customer for the sale and delivery of approximately 400,000 additional tons of coal in 2012 and 600,000 additional tons of coal in 2013. Based on the agreement in principle, the Partnership will receive a base price increase over its current pricing with the customer along with standard fuel and other price escalators. A definitive agreement documenting such agreement in principle has not yet been negotiated and executed, and there is no certainty that the Partnership will be able to successfully complete the negotiation and execution of such definitive agreement.

2011 Subsequent Event

On January 21, 2011, the Partnership declared a cash distribution of $0.4375 per unit for the quarter ended December 31, 2010. The distribution was paid on February 14, 2011 to all unitholders of record as of the close of business on February 1, 2011.

2011 Outlook

President and Chief Executive Officer Charles C. Ungurean commented, “We believe our performance in 2011 will be driven by our fully contracted sales book and record volume along with cost efficiencies realized from the investments we made in 2010. We believe our cost per ton will be in-line in 2011 as compared to 2010, primarily from cost improvements in our Illinois Basin operations, offset by low single-digit cost inflation. With our expected average sales price increasing at least 5% and up to 7% from the 2010 level, we believe we will be able to achieve growth in our revenue, net income, adjusted EBITDA and distributable cash flow in 2011. We are excited about the future of the coal markets and for Oxford, and we expect to fully cover our distribution in 2011. And with our committed sales portfolio, we believe we are poised to provide growth in distributions to unitholders in subsequent years.”

The below table sets forth the Partnership’s outlook for 2011 performance.


(In thousands, except per ton and	Full Year 2011							2011 Percentage
percentage change amounts)	(Range)					2010		Change from 2010

Tons of coal produced (clean)		8,200	—		8,700		7,417		11	%	—	17	%
Tons of coal sold		8,800	—		9,300		8,151		8	%	—	14	%

Average sales price per ton	$	40.00	—	$	41.00	$	38.22		5	%	—	7	%

DD&A	$	44,000	—	$	47,000	$	42,329		4	%	—	11	%
Maintenance capital expenditures (including reserve replacement)	$	37,000	—	$	40,000		*				*


*		Prior to the completion of our initial public offering in July 2010, we did not separately determine maintenance capital expenditures by distinguishing between maintenance and expansion capital expenditures.

Conference Call

Oxford will host a conference call at 10:00 a.m. Eastern Time today to review its financial results for the fourth quarter and full year 2010. To participate in the call, dial (866) 356-4281 or (617) 597-5395 for international callers and provide the passcode 11965302. The call will also be webcast live on the Internet in the Investor Relations section of Oxford’s website at www.OxfordResources.com.

An audio replay of the conference call will be available for seven days beginning at 1:00 p.m. Eastern Time on February 24, 2011 and can be accessed at (888) 286-8010 or (617) 801-6888 for international callers. The replay passcode is 80949258. The webcast will also be archived on the Partnership’s website at www.OxfordResources.com for 30 days following the call.

About Oxford Resource Partners, LP

Oxford Resource Partners, LP is a low cost producer of high value steam coal in Northern Appalachia and the Illinois Basin. Oxford markets its coal primarily to large electric utilities with coal-fired, base-load scrubbed power plants under long-term coal sales contracts. As of December 31, 2010, Oxford controlled 93.5 million tons of proven and probable coal reserves, and it currently operates 18 active mines that are managed as eight mining complexes. The Partnership is headquartered in Columbus, Ohio.

For more information about Oxford Resource Partners, LP (NYSE: OXF), please visit www.OxfordResources.com. Financial and other information about us is routinely posted on and accessible at www.OxfordResources.com.

This announcement is intended to be a qualified notice under Treasury Regulation Section 1.1446-4(b), with 100% of Oxford’s distributions to foreign investors attributable to income that is effectively connected with a United States trade or business. Accordingly, Oxford’s distributions to foreign investors are subject to federal income tax withholding at the highest applicable tax rate.

FORWARD-LOOKING STATEMENTS: Except for historical information, statements made in this press release are “forward-looking statements.” All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements, including the statements and information included under the heading “2011 Outlook.” These statements are based on certain assumptions made by the Partnership based on its management’s experience and perception of historical trends, current conditions, expected future developments and other factors the Partnership’s management believes are appropriate in the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the Partnership’s control, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: productivity levels, margins earned and the level of operating costs; weakness in global economic conditions or in customers’ industries; changes in governmental regulation of the mining industry or the electric power industry and the increased costs of complying with those changes; decreases in demand for electricity and changes in coal consumption patterns of U.S. electric power generators; the Partnership’s dependence on a limited number of customers; the Partnership’s inability to enter into new long-term coal sales contracts at attractive prices and the renewal and other risks associated with the Partnership’s existing long-term coal sales contracts, including risks related to adjustments to price, volume or other terms of those contracts; difficulties in collecting the Partnership’s receivables because of credit or financial problems of major customers, and customer bankruptcies, cancellations or breaches to existing contracts, or other failures to perform; the Partnership’s ability to acquire additional coal reserves; the Partnership’s ability to respond to increased competition within the coal industry; fluctuations in coal demand, prices and availability due to labor and transportation costs and disruptions, equipment availability or governmental regulations; significant costs imposed on the Partnership’s mining operations by extensive environmental laws and regulations, and greater than expected environmental regulation, costs and liabilities; legislation, regulatory and related court decisions and interpretations including issues related to climate change and miner health and safety; a variety of operational, geologic, permitting, labor and weather-related factors; limitations in the cash distributions the Partnership receives from Harrison Resources, LLC, and the ability of Harrison Resources, LLC to acquire additional reserves on economical terms from Consolidation Coal Company in the future; the potential for inaccuracies in estimates of the Partnership’s coal reserves; the accuracy of the assumptions underlying the Partnership’s reclamation and mine closure obligations; liquidity constraints; risks associated with major mine-related accidents; results of litigation; the Partnership’s ability to attract and retain key management personnel; greater than expected shortage of skilled labor; the Partnership’s ability to maintain satisfactory relations with employees; and failure to obtain, maintain or renew security arrangements. The Partnership undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in the Partnership’s filings with the U.S. Securities and Exchange Commission, which are incorporated by reference.

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(in thousands, except for unit information)


	As of December 31,
	2010			2009
ASSETS
Cash and cash equivalents	$	889		$	3,366
Trade accounts receivable		28,108			24,403
Inventory		12,640			8,801
Advance royalties		924			1,674
Prepaid expenses and other current assets		1,023			1,424

Total current assets		43,584			39,668
Property, plant and equipment, net		198,694			149,461
Advance royalties		7,693			7,438
Other long-term assets		11,100			6,796

Total assets	$	261,071		$	203,363


LIABILITIES
Current portion of long-term debt	$	7,249		$	4,113
Accounts payable		26,074			21,655
Asset retirement obligation — current portion		6,450			7,377
Deferred revenue — current portion		780			2,090
Accrued taxes other than income taxes		1,643			1,464
Accrued payroll and related expenses		2,625			2,045
Other current liabilities		2,952			5,714

Total current liabilities		47,773			44,458
Long-term debt		95,737			91,598
Asset retirement obligations		6,537			5,966
Other long-term liabilities		2,261			4,229

Total liabilities		152,308			146,251
Commitments and contingencies		—			—

PARTNERS’ CAPITAL
Limited partners (20,610,983 and 11,964,547 units outstanding as of December 31, 2010 and 2009, respectively)		105,684			53,960
General partner (420,633 and 242,023 units outstanding as of December 31, 2010 and 2009, respectively)		(63	)		1,085

Total Oxford Resource Partners, LP partners’ capital		105,621			55,045
Noncontrolling interest		3,142			2,067

Total partners’ capital		108,763			57,112

Total liabilities and partners’ capital	$	261,071		$	203,363

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(in thousands, except for unit and per unit information)


	For the Year Ended December 31,
	2010			2009

Revenue
Coal sales	$	311,567		$	254,171
Transportation revenue		38,490			32,490
Royalty and non-coal revenue		6,521			7,183

Total revenue		356,578			293,844

Costs and expenses
Cost of coal sales (excluding depreciation, depletion and amortization, shown separately)		229,468			170,698
Cost of purchased coal		22,024			19,487
Cost of transportation		38,490			32,490
Depreciation, depletion and amortization		42,329			25,902
Selling, general and administrative expenses		14,757			13,242
Contract termination and amendment expenses, net		652			—

Total costs and expenses		347,720			261,819

Income from operations		8,858			32,025
Interest income		12			35
Interest expense		(9,511	)		(6,484	)
Gain from purchase of business		—			3,823


Net income (loss)		(641	)		29,399
Less: net income attributable to noncontrolling interest		(6,710	)		(5,895	)


Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(7,351	)	$	23,504

Net income (loss) allocated to general partner	$	(147	)	$	467

Net income (loss) allocated to limited partners	$	(7,204	)	$	23,037

Basic earnings (loss) per limited partner unit	$	(0.45	)	$	2.09

Diluted earnings (loss) per limited partner unit	$	(0.45	)	$	2.08

Weighted average number of limited partner units outstanding basic		15,887,977			11,033,840

Weighted average number of limited partner units outstanding diluted		15,887,977			11,083,170

Distributions paid per limited partner unit*	$	0.58		$	1.20


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

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(in thousands, except for per unit information)


	For the Three Months Ended
	December 31,						September 30,
	2010			2009			2010

Revenue
Coal sales	$	78,113		$	77,466		$	78,127
Transportation revenue		9,514			9,229			9,605
Royalty and non-coal revenue		1,664			1,637			1,347

Total revenue		89,291			88,332			89,079

Costs and expenses
Cost of coal sales (excluding depreciation, depletion and amortization, shown separately)		57,833			54,928			57,138
Cost of purchased coal		3,407			7,174			3,790
Cost of transportation		9,514			9,229			9,605
Depreciation, depletion and amortization		11,742			8,645			12,255
Selling, general and administrative expenses		4,311			3,851			4,044
Contract termination and amendment expenses, net		—			—			652

Total costs and expenses		86,807			83,827			87,484

Income from operations		2,484			4,505			1,595
Interest income		1			4			3
Interest expense		(1,976	)		(1,842	)		(3,662	)


Net income (loss)		509			2,667			(2,064	)
Less: net income attributable to noncontrolling interest		(2,066	)		(1,791	)		(1,336	)


Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(1,557	)	$	876		$	(3,400	)

Net income (loss) allocated to general partner	$	(31	)	$	17		$	(68	)

Net income (loss) allocated to limited partners	$	(1,526	)	$	859		$	(3,332	)

Basic earnings (loss) per limited partner unit	$	(0.05	)	$	0.02		$	(0.20	)

Diluted earnings (loss) per limited partner unit	$	(0.05	)	$	0.02		$	(0.20	)

Distributions paid per limited partner unit*	$	0.35		$	0.23		$	—


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

OXFORD RESOURCE PARTNERS, LP AND SUBSIDIARIES

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


	For the Year Ended December 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(7,351	)	$	23,504
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion and amortization		42,329			25,902
Interest rate swap adjustment to market		142			(1,681	)
Loan fee amortization		1,239			530
Loss on debt extinguishment		1,302			1,252
Non-cash compensation expense		942			472
Advanced royalty recoupment		1,609			1,390
Insurance proceeds		(2,271	)		—
Loss (gain) on disposal of property and equipment		3,499			1,177
(Gain) on acquisition		—			(3,823	)
Noncontrolling interest in subsidiary earnings		6,710			5,895
(Increase) decrease in assets:
Accounts receivable		(3,705	)		(2,875	)
Inventory		(3,542	)		(2,062	)
Other assets		455			(996	)
Increase (decrease) in liabilities:
Accounts payable and other liabilities		956			3,055
Asset retirement obligation		(1,583	)		737
Provision for below-market contracts and deferred revenue		(2,734	)		(13,840	)

Net cash provided by (used in) operating activities		37,997			38,637
CASH FLOWS FROM INVESTING ACTIVITIES:
Phoenix Coal acquisition		—			(18,275	)
Purchase of property and equipment		(73,657	)		(25,657	)
Purchase of mineral rights and land		(3,120	)		(2,705	)
Mine development costs		(3,029	)		(1,989	)
Royalty advances		(1,169	)		(629	)
Proceeds from sale of property and equipment		36			88
Change in restricted cash		(1,684	)		(4	)

Net cash used in investing activities		(82,623	)		(49,171	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Initial public offering proceeds		150,544			—
Offering expenses		(6,097	)		—
Proceeds from borrowings		60,040			6,650
Payments on borrowings		(92,552	)		(2,646	)
Advances on line of credit		39,000			7,500
Payments on line of credit		(10,500	)		(3,000	)
Credit facility issuance costs		(5,603	)		(1,811	)
Capital contributions from partners		47			11,560
Distributions to noncontrolling interest		(5,635	)		(6,125	)
Distributions to partners		(87,095	)		(13,407	)

Net cash provided by (used in) financing activities		42,149			(1,279	)
Net increase/(decrease) in cash		(2,477	)		(11,813	)
CASH AND CASH EQUIVALENTS, beginning of period		3,366			15,179

CASH AND CASH EQUIVALENTS, end of period	$	889		$	3,366

NON-GAAP FINANCIAL MEASURES TABLE

Reconciliation of Net Income (Loss) Attributable to Oxford Resource Partners, LP
Unitholders to Adjusted EBITDA:


	Year Ended December 31,
	2010			2009
	(in thousands)
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(7,351	)	$	23,504

PLUS:
Interest expense, net of interest income		9,499			6,449
Depreciation, depletion and amortization		42,329			25,902
Contract termination and amendment expenses, net		652			—
Non-cash equity-based compensation expense		942			472
Non-cash loss on asset disposals		1,228			1,177
Non-cash change in future asset retirement obligation		5,742			4,991

LESS:
Gain on purchase of business		—			3,823
Amortization of below-market coal sales contracts		1,424			1,705


Adjusted EBITDA ⁽¹⁾	$	51,617		$	56,967


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

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

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

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

	•		our compliance with certain credit facility financial covenants; and

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

NON-GAAP FINANCIAL MEASURES TABLE

Reconciliation of Net Income (Loss) Attributable to Oxford Resource Partners, LP
Unitholders to Adjusted EBITDA and Distributable Cash Flow:


	Three Months Ended
	December 31,			September 30,
	2010			2010
	(in thousands)
Net income (loss) attributable to Oxford Resource Partners, LP unitholders	$	(1,557	)	$	(3,400	)

PLUS:
Interest expense, net of interest income		1,975			3,659
Depreciation, depletion and amortization		11,742			12,255
Contract termination and amendment expenses, net		—			652
Non-cash equity-based compensation expense		256			230
Non-cash loss on asset disposals		462			314
Non-cash change in future asset retirement obligation		1,677			1,521

LESS:
Amortization of below-market coal sales contracts		(141	)		(258	)


Adjusted EBITDA ⁽¹⁾	$	14,414		$	14,973

LESS:
Cash interest expense, net of interest income		(1,668	)		(1,863	)
Estimated reserve replacement expenditures		(1,313	)		(1,322	)
Other maintenance capital expenditures		(6,246	)		(8,449	)


Distributable cash flow ⁽²⁾	$	5,187		$	3,339


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

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

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

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

	•		our compliance with certain credit facility financial covenants; and

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


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

Westmoreland Resource Partners, LP - FORM 8-K - EX-99.1 - February 24, 2011

Attached files

Westmoreland Resource Partners, LP Reports