MarkWest Energy Partners Reports Second Quarter Financial Results And Increases Common Unit Distribution By 14.3 Percent

The Partnership’s portion of growth capital expenditures for 2012 remains unchanged and is forecasted in a range of $1.1 billion to $1.5 billion. This range excludes the Keystone purchase price of $509.6 million. Maintenance capital for 2012 is forecasted at approximately $20 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Friday, August 3, 2012, at 12:00 p.m. Eastern Time to review its second 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, it can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect MarkWest’s operations, financial performance, and other factors as discussed in its filings with the Securities and Exchange Commission. 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 Report on Form 10-Q for the quarter ended March 31, 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 June 30,										Six months ended June 30,
Statement of Operations Data			2012					2011					2012					2011
Revenue:
Revenue			$	309,986				$	359,849				$	709,167				$	708,749
Derivative gain (loss)				136,067					40,590					87,352					(45,089	)
Total revenue				446,053					400,439					796,519					663,660
Operating expenses:
Purchased product costs				112,731					154,580					267,286					308,209
Derivative (gain) loss related to purchased product costs				(51,579	)				(254	)				(32,779	)				19,140
Facility expenses				48,538					40,698					97,378					80,122
Derivative (gain) loss related to facility expenses				(1,146	)				2,927					(2,892	)				(84	)
Selling, general and administrative expenses				21,879					18,580					47,103					40,292
Depreciation				42,918					37,201					84,063					71,565
Amortization of intangible assets				12,307					10,830					23,292					21,647
Loss on disposal of property, plant and equipment				1,342					2,373					2,328					4,472
Accretion of asset retirement obligations				161					290					399					377
Total operating expenses				187,151					267,225					486,178					545,740
Income from operations				258,902					133,214					310,341					117,920
Other income (expense):
Income (loss) from unconsolidated affiliates				551					(216	)				542					(755	)
Interest income				159					63					231					152
Interest expense				(26,762	)				(27,874	)				(56,234	)				(56,137	)
Amortization of deferred financing costs and discount (a component of interest expense)				(1,245	)				(1,443	)				(2,515	)				(2,871	)
Loss on redemption of debt				-					-					-					(43,328	)
Miscellaneous income, net				4					169					62					131
Income before provision for income tax				231,609					103,913					252,427					15,112
Provision for income tax expense (benefit):
Current				4,809					4,089					20,150					4,145
Deferred				39,664					10,619					28,868					(3,567	)
Total provision for income tax				44,473					14,708					49,018					578
Net income				187,136					89,205					203,409					14,534
Net income attributable to non-controlling interest				(228	)				(10,708	)				(481	)				(20,066	)
Net income (loss) attributable to the Partnership			$	186,908				$	78,497				$	202,928				$	(5,532	)
Net income (loss) attributable to the Partnership's common unitholders per common unit:
Basic			$	1.74				$	1.03				$	1.98				$	(0.09	)
Diluted			$	1.47				$	1.03				$	1.66				$	(0.09	)
Weighted average number of outstanding common units:
Basic				106,825					75,160					101,833					74,847
Diluted				127,468					75,266					122,531					74,847
Cash Flow Data
Net cash flow provided by (used in):
Operating activities			$	48,524				$	91,045				$	256,437				$	206,364
Investing activities			$	(834,529	)			$	(120,428	)			$	(1,087,498	)			$	(462,049	)
Financing activities			$	560,833				$	51,266				$	839,507				$	283,270
Other Financial Data
Distributable cash flow			$	91,183				$	82,944				$	200,360				$	159,080
Adjusted EBITDA			$	130,533				$	120,004				$	263,475				$	216,191
Balance Sheet Data			June 30, 2012					December 31, 2011
Working capital			$	(114,875	)			$	4,234
Total assets				5,134,598					4,070,425
Total debt				1,997,985					1,846,062
Total equity				2,362,431					1,502,067

MarkWest Energy Partners, L.P.
Operating Statistics
			Three months ended June 30,						Six months ended June 30,
			2012			2011			2012			2011
Southwest
East Texas gathering systems throughput (Mcf/d)			440,400			428,300			425,200			427,000
East Texas natural gas processed (Mcf/d)			268,300			229,000			255,400			224,100
East Texas NGL sales (gallons, in thousands)			68,000			59,500			131,400			116,200
Western Oklahoma gathering system throughput (Mcf/d) (1)			252,200			223,900			257,100			215,700
Western Oklahoma natural gas processed (Mcf/d)			218,900			159,500			211,400			158,300
Western Oklahoma NGL sales (gallons, in thousands)			61,700			35,100			119,000			74,100
Southeast Oklahoma gathering system throughput (Mcf/d)			503,300			511,700			502,200			504,900
Southeast Oklahoma natural gas processed (Mcf/d) (2)			119,600			110,200			110,700			102,000
Southeast Oklahoma NGL sales (gallons, in thousands)			41,300			32,100			74,300			61,500
Arkoma Connector Pipeline throughput (Mcf/d)			331,200			298,400			329,900			292,100
Other Southwest gathering system throughput (Mcf/d)			26,700			31,600			25,600			32,300
Northeast
Natural gas processed (Mcf/d) (3)			328,200			319,600			324,900			312,500
NGLs fractionated (Bbl/d) (4)			17,200			22,700			16,900			22,500
Keep-whole sales (gallons, in thousands)			23,700			21,100			73,300			60,900
Percent-of-proceeds sales (gallons, in thousands)			36,800			33,100			69,800			64,000
Total NGL sales (gallons, in thousands) (5)			60,500			54,200			143,100			124,900
Crude oil transported for a fee (Bbl/d)			8,300			11,500			9,400			10,800
Liberty
Natural gas processed (Mcf/d)			400,600			298,200			396,400			276,500
Gathering system throughput (Mcf/d)			367,400			232,000			337,800			214,000
NGLs fractionated (Bbl/d) (6)			19,800			8,400			19,900			7,700
NGL sales (gallons, in thousands) (7)			75,900			50,700			173,400			102,400
Gulf Coast
Refinery off-gas processed (Mcf/d)			115,800			114,600			118,000			108,700
Liquids fractionated (Bbl/d)			21,700			21,900			22,500			20,600
NGL sales (gallons excluding hydrogen, in thousands)			83,000			83,600			172,300			156,300

(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 six months ended June 30, 2011 are the average daily rates for the days of operation.
(4)		Amount includes zero barrels per day and 5,500 barrels per day fractionated on behalf of Liberty for the three and six months ended June 30, 2012 and 2011, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionated NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011.
(5)		Represents sales from the Siloam facilities. The total sales exclude approximately zero gallons and 20,900,000 gallons sold by the Northeast on behalf of Liberty for the three months ended June 30, 2012 and 2011, respectively and zero gallons and 41,500,000 gallons sold for the six months ended June 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 June 30, 2012		Southwest				Northeast				Liberty					Gulf Coast				Total
Revenue		$	189,162			$	42,051			$	59,477				$	20,997			$	311,687
Operating expenses:
Purchased product costs			91,792				12,921				8,018					-				112,731
Facility expenses			23,034				4,932				13,647					9,607				51,220
Total operating expenses before items not allocated to segments			114,826				17,853				21,665					9,607				163,951
Portion of operating income attributable to non-controlling interests			1,590				-				(113	)				-				1,477
Operating income before items not allocated to segments		$	72,746			$	24,198			$	37,925				$	11,390			$	146,259
Three months ended June 30, 2011		Southwest				Northeast				Liberty					Gulf Coast				Total
Revenue		$	235,575			$	53,676			$	48,337				$	24,683			$	362,271
Operating expenses:
Purchased product costs			128,988				15,702				9,890					-				154,580
Facility expenses			20,855				6,929				7,269					8,312				43,365
Total operating expenses before items not allocated to segments			149,843				22,631				17,159					8,312				197,945
Portion of operating income attributable to non-controlling interests			1,346				-				15,182					-				16,528
Operating income before items not allocated to segments		$	84,386			$	31,045			$	15,996				$	16,371			$	147,798

		Three months ended June 30,
		2012					2011
Operating income before items not allocated to segments		$	146,259				$	147,798
Portion of operating income attributable to non-controlling interests			1,477					16,528
Derivative gain not allocated to segments			188,792					37,917
Revenue deferral adjustment			(1,701	)				(2,422	)
Compensation expense included in facility expenses not allocated to segments			(184	)				(188	)
Facility expenses adjustments			2,866					2,855
Selling, general and administrative expenses			(21,879	)				(18,580	)
Depreciation			(42,918	)				(37,201	)
Amortization of intangible assets			(12,307	)				(10,830	)
Loss on disposal of property, plant and equipment			(1,342	)				(2,373	)
Accretion of asset retirement obligations			(161	)				(290	)
Income from operations			258,902					133,214
Other income (expense):
Earnings (loss) from unconsolidated affiliate			551					(216	)
Interest income			159					63
Interest expense			(26,762	)				(27,874	)
Amortization of deferred financing costs and discount (a component ofinterest expense)			(1,245	)				(1,443	)
Miscellaneous income, net			4					169
Income before provision for income tax		$	231,609				$	103,913

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)
Six months ended June 30, 2012		Southwest				Northeast				Liberty					Gulf Coast				Total
Revenue		$	403,887			$	128,969			$	135,054				$	45,226			$	713,136
Operating expenses:
Purchased product costs			196,025				38,608				32,653					-				267,286
Facility expenses			46,026				11,310				25,894					19,245				102,475
Total operating expenses before items not allocated to segments			242,051				49,918				58,547					19,245				369,761
Portion of operating income attributable to non-controlling interests			3,036				-				(113	)				-				2,923
Operating income before items not allocated to segments		$	158,800			$	79,051			$	76,620				$	25,981			$	340,452
Six months ended June 30, 2011		Southwest				Northeast				Liberty					Gulf Coast				Total
Revenue		$	437,349			$	145,767			$	89,556				$	46,442			$	719,114
Operating expenses:
Purchased product costs			232,184				56,580				19,445					-				308,209
Facility expenses			41,012				12,523				13,767					17,302				84,604
Total operating expenses before items not allocated to segments			273,196				69,103				33,212					17,302				392,813
Portion of operating income attributable to non-controlling interests			2,518				-				27,559					-				30,077
Operating income before items not allocated to segments		$	161,635			$	76,664			$	28,785				$	29,140			$	296,224

		Six months ended June 30,
		2012					2011
Operating income before items not allocated to segments		$	340,452				$	296,224
Portion of operating income attributable to non-controlling interests			2,923					30,077
Derivative gain (loss) not allocated to segments			123,023					(64,145	)
Revenue deferral adjustment			(3,969	)				(10,365	)
Compensation expense included in facility expenses not allocated to segments			(633	)				(1,228	)
Facility expenses adjustments			5,730					5,710
Selling, general and administrative expenses			(47,103	)				(40,292	)
Depreciation			(84,063	)				(71,565	)
Amortization of intangible assets			(23,292	)				(21,647	)
Loss on disposal of property, plant and equipment			(2,328	)				(4,472	)
Accretion of asset retirement obligations			(399	)				(377	)
Income from operations			310,341					117,920
Other income (expense):
Earnings (loss) from unconsolidated affiliate			542					(755	)
Interest income			231					152
Interest expense			(56,234	)				(56,137	)
Amortization of deferred financing costs and discount (a component ofinterest expense)			(2,515	)				(2,871	)
Loss on redemption of debt			-					(43,328	)
Miscellaneous income, net			62					131
Income before provision for income tax		$	252,427				$	15,112

MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
		Three months ended June 30,										Six months ended June 30,
		2012					2011					2012					2011
Net income		$	187,136				$	89,205				$	203,409				$	14,534
Depreciation, amortization, impairment, and other non-cash operating expenses			56,806					50,772					110,238					98,217
Loss on redemption of debt, net of tax benefit			-					-					-					39,499
Amortization of deferred financing costs and discount			1,245					1,443					2,515					2,871
Non-cash (earnings) loss from unconsolidated affiliate			(551	)				216					(542	)				755
Distributions from unconsolidated affiliate			800					300					1,700					300
Non-cash compensation expense			2,579					1,134					5,289					2,712
Non-cash derivative activity			(193,744	)				(55,663	)				(145,527	)				24,121
Provision for income tax - deferred			39,664					10,619					28,868					(3,567	)
Cash adjustment for non-controlling interest of consolidated subsidiaries			(1,006	)				(15,536	)				(2,023	)				(28,058	)
Revenue deferral adjustment			1,701					2,422					3,969					10,365
Other			581					1,496					2,789					3,203
Maintenance capital expenditures, net of joint venture partner contributions			(4,028	)				(3,464	)				(10,324	)				(5,872	)
Distributable cash flow		$	91,183				$	82,944				$	200,360				$	159,080
Maintenance capital expenditures		$	4,028				$	3,892				$	10,324				$	6,398
Growth capital expenditures			323,912					116,572					571,879					227,718
Total capital expenditures			327,940					120,464					582,203					234,116
Acquisitions			506,797					-					506,797					230,728
Total capital expenditures and acquisitions			834,737					120,464					1,089,000					464,844
Joint venture partner contributions			-					(18,850	)				-					(54,027	)
Total capital expenditures and acquisitions, net		$	834,737				$	101,614				$	1,089,000				$	410,817
Distributable cash flow		$	91,183				$	82,944				$	200,360				$	159,080
Maintenance capital expenditures, net			4,028					3,464					10,324					5,872
Changes in receivables and other assets			54,727					(35,268	)				112,382					(15,399	)
Changes in accounts payable, accrued liabilities and other long-term liabilities			(100,435	)				25,865					(65,191	)				30,967
Derivative instrument premium payments, net of amortization			-					1,099					-					2,144
Cash adjustment for non-controlling interest of consolidated subsidiaries			1,006					15,536					2,023					28,058
Other			(1,985	)				(2,595	)				(3,461	)				(4,358	)
Net cash provided by operating activities		$	48,524				$	91,045				$	256,437				$	206,364

MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
		Three months ended June 30,										Six months ended June 30,
		2012					2011					2012					2011
Net income		$	187,136				$	89,205				$	203,409				$	14,534
Non-cash compensation expense			2,579					1,134					5,289					2,712
Non-cash derivative activity			(193,744	)				(55,663	)				(145,527	)				24,121
Interest expense (1)			25,826					27,092					54,378					54,548
Depreciation, amortization, impairment, and other non-cash operating expenses			56,806					50,772					110,238					98,217
Loss on redemption of debt			-					-					-					43,328
Provision for income tax			44,473					14,708					49,018					578
Adjustment for cash flow from unconsolidated affiliate			249					516					1,158					1,055
Adjustment related to non-guarantor, consolidated subsidiaries (2)			7,716					(7,416	)				(13,483	)				(22,106	)
Other			(508	)				(344	)				(1,005	)				(796	)
Adjusted EBITDA		$	130,533				$	120,004				$	263,475				$	216,191

(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 correlation of NGL prices to crude oil. The table below reflects MarkWest’s estimate of the range of DCF for 2012 given actual results through June 30, 2012, and forecasted crude oil and natural gas prices for the remainder of 2012. The analysis assumes various combinations of crude oil prices and the ratio of crude oil to gas based on three NGL correlation scenarios, including:

a. The three-year NGL correlation to crude for the remainder of 2012.

b. One standard deviation above the three-year NGL correlation to crude for the remainder of 2012.

c. One standard deviation below the three-year NGL correlation to crude for the remainder of 2012.

The analysis further assumes derivative instruments outstanding as of August 2, 2012, and production volumes estimated through December 31, 2012. The range of stated hypothetical changes in commodity prices considers current and historic market performance.

Estimated Range of 2012 DCF
									Natural Gas Price (Henry Hub)
	Crude Oil Price (WTI)				Three-year NGL Correlation to Crude				$	2.00				$	2.50				$	3.00				$	3.50				$	4.00
					One standard deviation above				$	536				$	534				$	532				$	530				$	528
	$110				Three-year NGL correlation to crude				$	491				$	489				$	487				$	485				$	483
					One standard deviation below				$	449				$	447				$	445				$	443				$	441
					One standard deviation above				$	536				$	534				$	532				$	530				$	528
	$100				Three-year NGL correlation to crude				$	478				$	476				$	474				$	472				$	470
					One standard deviation below				$	449				$	447				$	445				$	443				$	441
					One standard deviation above				$	499				$	497				$	495				$	493				$	491
	$90				Three-year NGL correlation to crude				$	464				$	462				$	460				$	458				$	456
					One standard deviation below				$	429				$	427				$	425				$	424				$	422
					One standard deviation above				$	482				$	480				$	478				$	476				$	474
	$80				Three-year NGL correlation to crude				$	452				$	450				$	448				$	446				$	444
					One standard deviation below				$	421				$	419				$	417				$	416				$	413
					One standard deviation above				$	468				$	466				$	464				$	462				$	460
	$70				Three-year NGL correlation to crude				$	441				$	439				$	437				$	435				$	433
					One standard deviation below				$	413				$	412				$	410				$	408				$	406

The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions MarkWest management may take to mitigate exposure to changes. Nor does the table consider the effects that such hypothetical adverse changes may have on overall economic activity. Historical prices and correlations do not guarantee future results.

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