MarkWest Energy Partners Reports Third Quarter Financial Results And Increases Common Unit Distribution By 11 Percent

The Partnership’s portion of growth capital expenditures for 2012 has increased primarily due to accelerated spending on key expansion projects in the Marcellus Shale, and is forecasted to be approximately $1.8 billion. This range excludes the Keystone purchase price of $509.6 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership forecasts DCF in a range of $500 million to $575 million based on its current forecast of operational volumes and prices for crude oil, natural gas and natural gas liquids; and derivative instruments currently outstanding. The midpoint of this range results in approximately 141 percent coverage of the Partnership’s full-year distribution based on current quarterly distributions and common units outstanding. A commodity price sensitivity analysis for forecasted 2013 DCF is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2013 is forecasted in a range of $1.4 billion to $1.9 billion.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, November 8, 2012, at 12:00 p.m. Eastern Time to review its third quarter 2012 financial results. Interested parties can participate in the call by dialing [phone] (passcode “MarkWest”) approximately ten minutes prior to the scheduled start time. To access the webcast, please visit the Investor Relations section of the Partnership’s website at www.markwest.com. A replay of the conference call will be available on the MarkWest website or by dialing [phone] (no passcode required).

MarkWest Energy Partners, L.P. is a master limited partnership engaged in the gathering, transportation, and processing of natural gas; the transportation, fractionation, marketing, and storage of natural gas liquids; and the gathering and transportation of crude oil. MarkWest has extensive natural gas gathering, processing, and transmission operations in the southwest, Gulf Coast, and northeast regions of the United States, including the Marcellus Shale, and is the largest natural gas processor and fractionator in the Appalachian region.

This press release includes “forward-looking statements.” All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although MarkWest believes that the expectations reflected in the forward-looking statements are reasonable, MarkWest can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings with the Securities and Exchange Commission (SEC). Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed with the SEC, including MarkWest’s Annual Report on Form 10-K for the year ended December 31, 2011 and its Quarterly Reports on Form 10-Q for the quarters ended March 31, 2012, June 30, 2012 and September 30, 2012. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading “Risk Factors.” MarkWest does not undertake any duty to update any forward-looking statement except as required by law.

MarkWest Energy Partners, L.P. Financial Statistics (unaudited, in thousands, except per unit data)
		Three months ended September 30,									Nine months ended September 30,
Statement of Operations Data		2012					2011				2012				2011
Revenue:
Revenue		$	320,137				$	400,883			$	1,029,304			$	1,109,632
Derivative (loss) gain			(36,400	)				106,943				50,952				61,854
Total revenue			283,737					507,826				1,080,256				1,171,486
Operating expenses:
Purchased product costs			119,369					189,284				386,655				497,493
Derivative loss (gain) related to purchased product costs			11,643					(1,274	)			(21,136	)			17,866
Facility expenses			53,293					44,236				150,671				124,358
Derivative loss (gain) related to facility expenses			4,028					(2,787	)			1,136				(2,871	)
Selling, general and administrative expenses			21,922					20,162				69,025				60,454
Depreciation			48,136					38,715				132,199				110,280
Amortization of intangible assets			14,988					10,985				38,280				32,632
Loss on disposal of property, plant and equipment			655					147				2,983				4,619
Accretion of asset retirement obligations			141					557				540				934
Total operating expenses			274,175					300,025				760,353				845,765
Income from operations			9,562					207,801				319,903				325,721
Other income (expense):
Earnings (loss) from unconsolidated affiliates			246					(507	)			788				(1,262	)
Interest income			64					62				295				214
Interest expense			(30,621	)				(26,899	)			(86,855	)			(83,036	)
Amortization of deferred financing costs and discount (a component of interest expense)			(1,428	)				(1,002	)			(3,943	)			(3,873	)
Loss on redemption of debt			-					(133	)			-				(43,461	)
Miscellaneous income (expense), net			1					(4	)			63				127
(Loss) Income before provision for income tax			(22,176	)				179,318				230,251				194,430
Provision for income tax (benefit) expense:
Current			(17,948	)				3,959				2,202				8,104
Deferred			10,528					21,905				39,396				18,338
Total provision for income tax			(7,420	)				25,864				41,598				26,442
Net (loss) income			(14,756	)				153,454				188,653				167,988
Net loss (income) attributable to non-controlling interest			416					(13,142	)			(65	)			(33,208	)
Net (loss) income attributable to the Partnership		$	(14,340	)			$	140,312			$	188,588			$	134,780
Net (loss) income attributable to the Partnership's common unitholders per common unit:
Basic		$	(0.13	)			$	1.77			$	1.77			$	1.75
Diluted		$	(0.13	)			$	1.77			$	1.49			$	1.75
Weighted average number of outstanding common units:
Basic			113,994					78,619				105,916				76,118
Diluted			113,994					78,760				126,595				76,276
Cash Flow Data
Net cash flow provided by (used in):
Operating activities		$	133,281				$	124,885			$	389,718			$	331,249
Investing activities		$	(658,573	)			$	(125,637	)		$	(1,746,071	)		$	(587,686	)
Financing activities		$	814,894				$	64,894			$	1,654,401			$	348,164
Other Financial Data
Distributable cash flow		$	104,289				$	85,311			$	304,649			$	244,391
Adjusted EBITDA		$	108,180				$	107,013			$	371,655			$	323,204
Balance Sheet Data		September 30, 2012					December 31, 2011
Working capital		$	(17,336	)			$	4,234
Total assets			6,237,143					4,070,425
Total debt			2,522,854					1,846,062
Total equity		$	2,620,940				$	1,502,067

MarkWest Energy Partners, L.P. Operating Statistics
		Three months ended September 30,				Nine months ended September 30,
		2012		2011		2012		2011
Southwest
East Texas gathering systems throughput (Mcf/d)		471,200		417,400		440,700		423,800
East Texas natural gas processed (Mcf/d)		270,200		229,700		260,400		226,000
East Texas NGL sales (gallons, in thousands)		67,800		59,000		199,300		175,200
Western Oklahoma gathering system throughput (Mcf/d) (1)		227,900		241,300		247,300		224,400
Western Oklahoma natural gas processed (Mcf/d)		209,600		153,200		210,800		156,600
Western Oklahoma NGL sales (gallons, in thousands)		50,900		37,000		169,900		111,100
Southeast Oklahoma gathering system throughput (Mcf/d)		484,400		512,600		496,200		507,500
Southeast Oklahoma natural gas processed (Mcf/d) (2)		128,600		105,400		116,700		103,100
Southeast Oklahoma NGL sales (gallons, in thousands)		46,700		30,600		121,000		92,100
Arkoma Connector Pipeline throughput (Mcf/d)		310,400		298,600		323,400		294,300
Other Southwest gathering system throughput (Mcf/d)		23,600		29,900		25,000		31,500
Northeast
Natural gas processed (Mcf/d) (3)		318,500		277,400		322,800		300,700
NGLs fractionated (Bbl/d) (4)		16,500		19,300		16,800		21,400
Keep-whole sales (gallons, in thousands)		23,200		21,700		96,500		82,600
Percent-of-proceeds sales (gallons, in thousands)		33,700		31,600		103,500		95,600
Total NGL sales (gallons, in thousands) (5)		56,900		53,300		200,000		178,200
Crude oil transported for a fee (Bbl/d)		8,700		9,900		9,100		10,500
Liberty
Natural gas processed (Mcf/d)		479,400		366,200		424,300		306,700
Gathering system throughput (Mcf/d)		444,700		258,300		373,700		228,900
NGLs fractionated (Bbl/d) (6)		22,300		12,400		20,700		9,300
NGL sales (gallons, in thousands) (7)		90,800		61,100		264,200		163,500
Gulf Coast
Refinery off-gas processed (Mcf/d)		123,800		122,000		120,000		113,200
Liquids fractionated (Bbl/d)		23,800		23,100		23,000		21,400
NGL sales (gallons excluding hydrogen, in thousands)		92,100		89,200		264,400		245,500

(1)		Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as it is one integrated area of operations.
(2)		The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or other third-party processors.
(3)		Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plants in February 2011. The volumes reported for the nine months ended September 30, 2011 are the average daily rates for the days of operation.
(4)		Amount includes zero barrels per day and 4,400 barrels per day fractionated on behalf of Liberty for the three months ended September 30, 2012 and 2011, respectively and includes zero barrels per day and 5,100 barrels per day fractionated on behalf of Liberty for the nine months ended September 30, 2012 and 2011, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionates NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011, except during outages or force majeure events.
(5)		Represents sales from the Siloam facilities. The total sales exclude approximately 600,000 gallons and 17,100,000 gallons sold by the Northeast on behalf of Liberty for the three months ended September 30, 2012 and 2011, respectively and 975,000 gallons and 58,600,000 gallons sold for the nine months ended September 30, 2012 and 2011, respectively. These volumes are included as part of NGLs sold at Liberty.
(6)		Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility.
(7)		Includes sale of all purity products fractionated at the Liberty facilities and sale of all unfractionated NGLs. Also includes the sale of purity products fractionated and sold from the Siloam facilities on behalf of Liberty.

MarkWest Energy Partners, L.P. Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure Operating Income before Items not Allocated to Segments (unaudited, in thousands)
Three months ended September 30, 2012		Southwest				Northeast				Liberty				Gulf Coast			Total
Revenue		$	181,456			$	39,987			$	78,852			$	21,477		$	321,772
Operating expenses:
Purchased product costs			92,112				11,054				16,203				-			119,369
Facility expenses			20,527				6,267				20,241				8,928			55,963
Total operating expenses before items not allocated to segments			112,639				17,321				36,444				8,928			175,332
Portion of operating income attributable to non-controlling interests			1,543				-				(627	)			-			916
Operating income before items not allocated to segments		$	67,274			$	22,666			$	43,035			$	12,549		$	145,524
Three months ended September 30, 2011		Southwest				Northeast				Liberty				Gulf Coast			Total
Revenue		$	241,998			$	55,920			$	78,586			$	26,868		$	403,372
Operating expenses:
Purchased product costs			141,067				15,947				32,270				-			189,284
Facility expenses			21,043				6,879				9,108				9,798			46,828
Total operating expenses before items not allocated to segments			162,110				22,826				41,378				9,798			236,112
Portion of operating income attributable to non-controlling interests			1,227				-				18,223				-			19,450
Operating income before items not allocated to segments		$	78,661			$	33,094			$	18,985			$	17,070		$	147,810
		Three months ended September 30,
		2012				2011
Operating income before items not allocated to segments		$	145,524			$	147,810
Portion of operating income attributable to non-controlling interests			916				19,450
Derivative (loss) gain not allocated to segments			(52,071	)			111,004
Revenue deferral adjustment			(1,635	)			(2,489	)
Compensation expense included in facility expenses not allocated to segments			(193	)			(263	)
Facility expenses adjustments			2,863				2,855
Selling, general and administrative expenses			(21,922	)			(20,162	)
Depreciation			(48,136	)			(38,715	)
Amortization of intangible assets			(14,988	)			(10,985	)
Loss on disposal of property, plant and equipment			(655	)			(147	)
Accretion of asset retirement obligations			(141	)			(557	)
Income from operations			9,562				207,801
Other income (expense):
Earnings (loss) from unconsolidated affiliate			246				(507	)
Interest income			64				62
Interest expense			(30,621	)			(26,899	)
Amortization of deferred financing costs and discount (a component of interest expense)			(1,428	)			(1,002	)
Loss on redemption of debt			-				(133	)
Miscellaneous income (expense), net			1				(4	)
(Loss) Income before provision for income tax		$	(22,176	)		$	179,318

MarkWest Energy Partners, L.P. Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure Operating Income before Items not Allocated to Segments (unaudited, in thousands)
Nine months ended September 30, 2012		Southwest				Northeast				Liberty				Gulf Coast			Total
Revenue		$	585,343			$	168,956			$	213,906			$	66,703		$	1,034,908
Operating expenses:
Purchased product costs			288,137				49,662				48,856				-			386,655
Facility expenses			66,553				17,577				46,135				28,173			158,438
Total operating expenses before items not allocated to segments			354,690				67,239				94,991				28,173			545,093
Portion of operating income attributable to non-controlling interests			4,579				-				(740	)			-			3,839
Operating income before items not allocated to segments		$	226,074			$	101,717			$	119,655			$	38,530		$	485,976
Nine months ended September 30, 2011		Southwest				Northeast				Liberty				Gulf Coast			Total
Revenue		$	679,347			$	201,687			$	168,142			$	73,310		$	1,122,486
Operating expenses:
Purchased product costs			373,251				72,527				51,715				-			497,493
Facility expenses			62,055				19,402				22,875				27,100			131,432
Total operating expenses before items not allocated to segments			435,306				91,929				74,590				27,100			628,925
Portion of operating income attributable to non-controlling interests			3,745				-				45,782				-			49,527
Operating income before items not allocated to segments		$	240,296			$	109,758			$	47,770			$	46,210		$	444,034
		Nine months ended September 30,
		2012				2011
Operating income before items not allocated to segments		$	485,976			$	444,034
Portion of operating income attributable to non-controlling interests			3,839				49,527
Derivative gain not allocated to segments			70,952				46,859
Revenue deferral adjustment			(5,604	)			(12,854	)
Compensation expense included in facility expenses not allocated to segments			(826	)			(1,491	)
Facility expenses adjustments			8,593				8,565
Selling, general and administrative expenses			(69,025	)			(60,454	)
Depreciation			(132,199	)			(110,280	)
Amortization of intangible assets			(38,280	)			(32,632	)
Loss on disposal of property, plant and equipment			(2,983	)			(4,619	)
Accretion of asset retirement obligations			(540	)			(934	)
Income from operations			319,903				325,721
Other income (expense):
Earnings (loss) from unconsolidated affiliate			788				(1,262	)
Interest income			295				214
Interest expense			(86,855	)			(83,036	)
Amortization of deferred financing costs and discount (a component of interest expense)			(3,943	)			(3,873	)
Loss on redemption of debt			-				(43,461	)
Miscellaneous income, net			63				127
Income before provision for income tax		$	230,251			$	194,430

MarkWest Energy Partners, L.P. Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure Distributable Cash Flow (unaudited, in thousands)
		Three months ended September 30,								Nine months ended September 30,
		2012				2011				2012				2011
Net income		$	(14,756	)		$	153,454			$	188,653			$	167,988
Depreciation, amortization, impairment, and other non-cash operating expenses			63,998				50,482				174,236				148,699
Loss on redemption of debt, net of tax benefit			-				119				-				39,618
Amortization of deferred financing costs and discount			1,428				1,002				3,943				3,873
Non-cash (earnings) loss from unconsolidated affiliate			(246	)			507				(788	)			1,262
Distributions from unconsolidated affiliate			500				-				2,200				300
Non-cash compensation expense			981				995				6,270				3,707
Non-cash derivative activity			43,712				(126,802	)			(101,815	)			(102,681	)
Provision for income tax - deferred			10,528				21,905				39,396				18,338
Cash adjustment for non-controlling interest of consolidated subsidiaries			(490	)			(18,227	)			(2,513	)			(46,285	)
Revenue deferral adjustment			1,635				2,489				5,604				12,854
Other			1,173				1,334				3,962				4,537
Maintenance capital expenditures, net of joint venture partner contributions			(4,174	)			(1,947	)			(14,499	)			(7,819	)
Distributable cash flow		$	104,289			$	85,311			$	304,649			$	244,391
Maintenance capital expenditures		$	4,174			$	2,179			$	14,499			$	8,577
Growth capital expenditures			654,489				123,631				1,226,367				351,349
Total capital expenditures			658,663				125,810				1,240,866				359,926
Acquisitions			-				-				506,797				230,728
Total capital expenditures and acquisitions			658,663				125,810				1,747,663				590,654
Joint venture partner contributions			(55,000	)			(14,474	)			(55,000	)			(68,501	)
Total capital expenditures and acquisitions, net		$	603,663			$	111,336			$	1,692,663			$	522,153
Distributable cash flow		$	104,289			$	85,311			$	304,649			$	244,391
Maintenance capital expenditures, net			4,174				1,947				14,499				7,819
Changes in receivables and other assets			(85,436	)			(17,856	)			26,946				(33,255	)
Changes in accounts payable, accrued liabilities and other long-term liabilities			110,559				38,405				45,368				69,372
Derivative instrument premium payments, net of amortization			-				1,137				-				3,281
Cash adjustment for non-controlling interest of consolidated subsidiaries			490				18,227				2,513				46,285
Other			(795	)			(2,286	)			(4,257	)			(6,644	)
Net cash provided by operating activities		$	133,281			$	124,885			$	389,718			$	331,249

MarkWest Energy Partners, L.P. Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure Adjusted EBITDA (unaudited, in thousands)
		Three months ended September 30,								Nine months ended September 30,
		2012				2011				2012				2011
Net income		$	(14,756	)		$	153,454			$	188,653			$	167,988
Non-cash compensation expense			981				995				6,270				3,707
Non-cash derivative activity			43,712				(126,802	)			(101,815	)			(102,681	)
Interest expense (1)			29,882				25,687				84,260				80,235
Depreciation, amortization, impairment, and other non-cash operating expenses			63,998				50,482				174,236				148,699
Loss on redemption of debt			-				133				-				43,461
Provision for income tax			(7,420	)			25,864				41,598				26,442
Adjustment for cash flow from unconsolidated affiliate			254				507				1,412				1,562
Adjustment related to non-guarantor, consolidated subsidiaries (2)			(7,951	)			(22,713	)			(21,434	)			(44,819	)
Other			(520	)			(594	)			(1,525	)			(1,390	)
Adjusted EBITDA		$	108,180			$	107,013			$	371,655			$	323,204

(1)		Includes amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.
(2)		The non-guarantor subsidiaries, in accordance with Credit Facility covenants, are MarkWest Liberty Midstream & Resources, L.L.C. and its subsidiaries (Liberty), MarkWest Utica EMG L.L.C., MarkWest Pioneer, L.L.C., Wirth Gathering Partnership, and Bright Star Partnership. As of January 1, 2012, Liberty is a wholly owned subsidiary but remains a non-guarantor in accordance with the Credit Facility.

MarkWest Energy Partners, L.P. Distributable Cash Flow Sensitivity Analysis( unaudited, in millions)

MarkWest periodically estimates the effect on DCF resulting from its commodity risk management program, changes in crude oil and natural gas prices, and the ratio of NGL prices to crude oil. The table below reflects MarkWest’s estimate of the range of DCF for 2013 and forecasted crude oil and natural gas prices for 2013. The analysis assumes various combinations of crude oil and natural gas prices as well as three NGL-to-crude oil ratio scenarios, including:

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