EX-99.1 2 a11-29298_2ex99d1.htm EX-99.1

Exhibit 99.1

MarkWest Energy Partners, L.P.	Contact:	Frank Semple, Chairman, President & CEO
1515 Arapahoe Street		Nancy Buese, Senior VP and CFO
Tower 1, Suite 1600		Dan Campbell, VP of Finance & Treasurer
Denver, Colorado 80202	Phone:	(866) 858-0482
	E-mail:	investorrelations@markwest.com

MarkWest Energy Partners Reports Record Quarterly Distributable Cash Flow,
Increases Quarterly Common Unit Distribution by 14.1 Percent,
Increases 2011 DCF Guidance, and Provides 2012 Guidance

DENVER—November 7, 2011—MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported record quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $85.3 million for the three months ended September 30, 2011, and $244.4 million for the nine months ended September 30, 2011. Distributable cash flow for the three and nine months ended September 30, 2011, represents distribution coverage of 138 percent and 146 percent, respectively. The third quarter distribution of $62.0 million, or $0.73 per common unit, will be paid on November 14, 2011, to unitholders of record on November 7, 2011. The third quarter 2011 distribution represents an increase of $0.03 per common unit, or 4.3 percent, over the second quarter 2011 distribution and an increase of $0.09 per common unit, or 14.1 percent, over the third quarter 2010 distribution. As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF. A reconciliation of DCF to net income (loss), the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported Adjusted EBITDA of $107.0 million for the three months ended September 30, 2011, and $323.2 million for the nine months ended September 30, 2011. MarkWest believes the presentation of Adjusted EBITDA provides useful information because it is commonly used by investors in Master Limited Partnerships to assess financial performance and operating results of ongoing business operations. A reconciliation of Adjusted EBITDA to net income (loss), the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported income before provision for income tax for the three months and nine months ended September 30, 2011, of $179.3 million and $194.4 million, respectively. Income before provision for income tax includes non-cash gains associated with the change in fair value of derivative instruments of $126.8 million and $102.7 million for the three and nine months ended September 30, 2011, respectively, and costs associated with the redemption of debt of $(0.1) million and $(43.5) million for the three and nine months ended September 30, 2011, respectively. Excluding these items, income before provision for income tax for the three and nine months ended September 30, 2011, would have been $52.6 million and $135.2 million, respectively.

“Our record distributable cash flow for the third quarter allowed us to deliver more than 14% year-over-year distribution growth for our unitholders and still maintain a coverage ratio of 1.38 times,” said Frank Semple, Chairman, President and Chief Executive Officer. “This strong financial performance is a direct result of providing exceptional service for our producer customers and completing $2 billion of organic growth projects and acquisitions over the past three years. Equally as exciting is the extensive inventory of future growth projects that should continue to deliver strong distribution growth and total returns for our unitholders for years to come.”

BUSINESS HIGHLIGHTS

Capital Markets

· On July 13, 2011, the Partnership completed a common unit equity offering of 4.025 million common units. The net proceeds of approximately $185 million were used to repay amounts outstanding under its revolving credit facility and to fund its ongoing capital expenditure program.

· On September 7, 2011, the Partnership completed the expansion and extension of its senior secured revolving credit facility. As amended, the credit facility provides up to $750 million of borrowing capacity with improved pricing that will result in significant interest expense savings. The maturity date of the credit facility was extended to September 2016.

· On October 13, 2011, the Partnership completed a common unit equity offering of 5.750 million common units. The net proceeds of approximately $251 million were used to repay amounts outstanding under its revolving credit facility and to fund its ongoing capital expenditure program.

· On November 3, 2011, the Partnership completed a public offering of $700 million of 6.25% senior unsecured notes due 2022 resulting in net proceeds of approximately $689 million. The Partnership intends to use the net proceeds from the offering to purchase up to $334.4 million in aggregate principal amount of its outstanding 8.75% senior notes due 2018 pursuant to a tender offer launched October 25, 2011, for any and all of such outstanding senior notes. The tender offer for the senior notes due 2018 expires on November 25, 2011. All remaining net proceeds will be used to fund its ongoing capital expenditure program.

Business Development

· Southwest — in September 2011, MarkWest commenced operations of a 75 million cubic feet per day (MMcf/d) expansion of its cryogenic natural gas processing capacity at its Arapaho complex in Western Oklahoma. With the addition of the incremental capacity, MarkWest has 235 MMcf/d of cryogenic processing capacity available to serve increasing volumes of liquids-rich natural gas production from Granite Wash producers in the Texas panhandle.

· Liberty — in September 2011, MarkWest Liberty announced three critical milestones in the ongoing development of the hydrocarbon-rich area of the Marcellus Shale. The first milestone was the announcement by Sunoco Logistics, LP of the successful completion of the Mariner West open season and the execution of definitive transportation agreements. Mariner West is a 50,000 barrel per day (Bbl/d) pipeline project jointly developed by Sunoco and MarkWest Liberty that will deliver Marcellus ethane to petrochemical markets in Sarnia, Ontario, Canada. Mariner West will support the long-term development of more than 1.5 billion cubic feet per day (Bcf/d) of liquids-rich Marcellus gas in southwest Pennsylvania and northern West Virginia.

The second milestone was the start-up of MarkWest Liberty’s Houston, Pennsylvania fractionation facility with design capacity of 60,000 Bbl/d. The facility is the largest natural gas liquids (NGLs) fractionation and marketing complex in the northeast United States and produces high-purity propane, butane, and natural gasoline for sale into the premium Northeast markets.

The third milestone was MarkWest Liberty’s announcement of the development of up to 115,000 Bbl/d of purity ethane production capacity at its Houston and Majorsville processing complexes. The first phase of this expansion will provide capacity to produce approximately 75,000 Bbl/d and will commence operation in mid-2013 to support Mariner West.

· Liberty — In October 2011, MarkWest Liberty entered into definitive agreements with subsidiaries of Magnum Hunter Resources Corporation to provide long-term midstream processing and related services in the liquids-rich area of the Marcellus Shale in northern West Virginia. MarkWest Liberty will install a 200 MMcf/d cryogenic natural gas processing plant at its Mobley processing complex in West Virginia. When combined with the 120 MMcf/d Mobley I plant currently under construction, MarkWest Liberty expects to operate 320 MMcf/d of cryogenic processing capacity at its Mobley complex by the second half of 2012. The NGLs recovered at the Mobley complex will be transported via a newly constructed liquids pipeline to MarkWest Liberty’s fractionation, storage, and marketing complex in Houston, Pennsylvania.

· Liberty — MarkWest Liberty is in active discussions with existing and new producer customers to develop additional midstream projects in the liquids-rich areas of the Marcellus, including significant processing, NGL transportation, fractionation, storage, and marketing infrastructure that is critical to the full development of the Marcellus.

FINANCIAL RESULTS

Balance Sheet

· At September 30, 2011, the Partnership had $86.4 million of cash and cash equivalents in wholly owned subsidiaries and $577.6 million available for borrowing under its $750 million revolving credit facility after consideration of $27.3 million of outstanding letters of credit. Pro forma for the equity issuance and senior notes offering in October and November 2011, respectively, and assuming all borrowings under the revolving credit facility at September 30, 2011, are repaid, MarkWest would have $881.3 million of cash and cash equivalents and $722.7 million available for borrowing under its revolving credit facility, resulting in total available liquidity of $1.6 billion.

Operating Results

· Operating income before items not allocated to segments for the three months ended September 30, 2011, was $147.8 million, an increase of $41.2 million when compared to segment operating income of $106.6 million in the same period in 2010. This increase is primarily attributable to favorable commodity prices compared to the prior year quarter, expanding operations in the Liberty and Northeast segments, and increased processing volumes in the Southwest segment.

A reconciliation of operating income before items not allocated to segments to income (loss) before provision for income tax, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

· Operating income before items not allocated to segments does not include gain (loss) on commodity derivative instruments. Realized losses on commodity derivative instruments were $(15.8) million in the third quarter of 2011 compared to realized losses of $(5.7) million in the third quarter of 2010.

Capital Expenditures

· For the three and nine months ended September 30, 2011, the Partnership’s portion of capital expenditures was $111.3 million and $522.2 million, respectively. Capital expenditures for the nine months ended September 30, 2011, include the $230.7 million acquisition of EQT’s Langley processing complex and the partially completed Ranger NGL pipeline.

2011 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

The Partnership increased its 2011 DCF forecast to a range of $325 million to $345 million. The midpoint of this range provides for approximately 135 percent coverage of the Partnership’s full-year distribution based on current quarterly distributions and common units outstanding.

The Partnership’s portion of the 2011 growth capital expenditure forecast remains unchanged in a range of $675 million to $700 million, which includes the $230 million acquisition of EQT’s Langley processing complex and the Ranger NGL pipeline. The Partnership forecasts maintenance capital for 2011 at approximately $15 million.

2012 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2012, the Partnership forecasts DCF in a range of $380 million to $440 million based on forecasted operational volumes from existing operations and growth capital projects; derivative instruments currently outstanding; a reasonable range of price estimates for crude oil and natural gas; and no acquisitions. The midpoint of this range results in approximately 165 percent coverage of the Partnership’s full-year distribution based on current quarterly distributions and common units outstanding. A sensitivity analysis for forecasted 2012 DCF is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2012 is forecasted in a range of $600 million to $700 million and maintenance capital for 2012 is forecasted at approximately $20 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Tuesday, November 8, 2011, at 4:00 p.m. Eastern Time to review its third quarter 2011 financial results. Interested parties can participate in the call by dialing (800) 475-0218 (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 (866) 359-6514 (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 we believe that the expectations reflected in the forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect our

operations, financial performance, and other factors as discussed in our 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 we file with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2010, and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011. 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.” We do 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,
	2011			2010			2011			2010
Statement of Operations Data
Revenue:
Revenue	$	400,883		$	292,370		$	1,109,632		$	884,933
Derivative gain (loss)	106,943			(36,959		)	61,854			2,707
Total revenue	507,826			255,411			1,171,486			887,640

Operating expenses:
Purchased product costs	189,284			136,700			497,493			409,119
Derivative (gain) loss related to purchased product costs	(1,274		)	19,996			17,866			24,993
Facility expenses	44,236			37,934			124,358			113,266
Derivative gain related to facility expenses	(2,787		)	(564		)	(2,871		)	(436		)
Selling, general and administrative expenses	20,162			17,137			60,454			55,064
Depreciation	38,715			31,362			110,280			89,367
Amortization of intangible assets	10,985			10,193			32,632			30,579
Loss on disposal of property, plant and equipment	147			1,937			4,619			2,116
Accretion of asset retirement obligations	557			70			934			282
Total operating expenses	300,025			254,765			845,765			724,350

Income from operations	207,801			646			325,721			163,290

Other income (expense):
(Loss) earnings from unconsolidated affiliates	(507		)	—			(1,262		)	1,517
Interest income	62			422			214			1,185
Interest expense	(26,899		)	(26,433		)	(83,036		)	(75,970		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,002		)	(3,625		)	(3,873		)	(8,517		)
Derivative gain related to interest expense	—			—			—			1,871
Loss on redemption of debt	(133		)	—			(43,461		)	—
Miscellaneous (expense) income, net	(4		)	76			127			1,129
Income (loss) before provision for income tax	179,318			(28,914		)	194,430			84,505

Provision for income tax expense (benefit):
Current	3,959			3,533			8,104			10,254
Deferred	21,905			(13,771		)	18,338			(45		)
Total provision for income tax	25,864			(10,238		)	26,442			10,209

Net income (loss)	153,454			(18,676		)	167,988			74,296

Net income attributable to non-controlling interest	(13,142		)	(8,475		)	(33,208		)	(19,720		)

Net income (loss) attributable to the Partnership	$	140,312		$	(27,151	)	$	134,780		$	54,576

Net income (loss) attributable to the Partnership’s common unitholders per common unit:
Basic	$	1.77		$	(0.39	)	$	1.75		$	0.77
Diluted	$	1.77		$	(0.39	)	$	1.75		$	0.77

Weighted average number of outstanding common units:
Basic	78,619			71,438			76,118			69,685
Diluted	78,760			71,438			76,276			69,831

Cash Flow Data
Net cash flow provided by (used in):
Operating activities	$	124,885		$	66,602		$	331,249		$	197,238
Investing activities	$	(125,637	)	$	(120,806	)	$	(587,686	)	$	(373,649	)
Financing activities	$	64,894		$	17,828		$	348,164		$	177,154

Other Financial Data
Distributable cash flow	$	85,311		$	54,694		$	244,391		$	171,942
Adjusted EBITDA	$	107,013		$	83,737		$	323,204		$	244,882

	September 30, 2011			December 31, 2010
Balance Sheet Data
Working capital	$	56,694		$	(43,296	)
Total assets	3,986,201			3,333,362
Total debt	1,477,963			1,273,434
Total equity	1,909,104			1,536,020

MarkWest Energy Partners, L.P.

Operating Statistics

	Three months ended September 30,		Nine months ended September 30,
	2011	2010	2011	2010
Southwest
East Texas gathering systems throughput (Mcf/d)	417,400	433,000	423,800	433,600
East Texas natural gas processed (Mcf/d)	229,700	221,900	226,000	236,900
East Texas NGL sales (gallons, in thousands)	59,000	60,200	175,200	186,300

Western Oklahoma gathering system throughput (Mcf/d) (1)	241,300	183,600	224,400	189,300
Western Oklahoma natural gas processed (Mcf/d)	153,200	143,300	156,600	129,600
Western Oklahoma NGL sales (gallons, in thousands)	37,000	33,800	111,100	93,400

Southeast Oklahoma gathering system throughput (Mcf/d)	512,600	535,800	507,500	524,100
Southeast Oklahoma natural gas processed (Mcf/d) (2)	105,400	94,500	103,100	79,000
Southeast Oklahoma NGL sales (gallons, in thousands)	30,600	29,900	92,100	72,300
Arkoma Connector Pipeline throughput (Mcf/d)	298,600	396,800	294,300	378,900

Other Southwest gathering system throughput (Mcf/d) (3)	29,900	37,000	31,500	40,200

Northeast (4)
Natural gas processed (Mcf/d)	277,400	190,300	300,700	194,400
NGLs fractionated (Bbl/d) (5)	19,300	21,200	21,400	20,500

Keep-whole sales (gallons, in thousands)	21,700	28,700	82,600	105,300
Percent-of-proceeds sales (gallons, in thousands)	31,600	30,800	95,600	87,900
Total NGL sales (gallons, in thousands) (6)	53,300	59,500	178,200	193,200

Crude oil transported for a fee (Bbl/d)	9,900	12,100	10,500	12,400

Liberty
Gathering system throughput (Mcf/d)	258,300	153,300	228,900	127,700
Natural gas processed (Mcf/d)	366,200	156,300	306,700	122,300
NGLs fractionated (Bbl/d) (7)	12,400	4,200	9,300	3,500
NGL sales (gallons, in thousands) (8)	61,100	32,400	163,500	77,400

Gulf Coast
Refinery off-gas processed (Mcf/d)	122,000	123,000	113,200	118,400
Liquids fractionated (Bbl/d)	23,100	23,100	21,400	22,800
NGL sales (gallons excluding hydrogen, in thousands)	89,200	89,300	245,500	261,700

(1)	Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as management considers this one integrated area of operations.
(2)	The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or a third-party processor.
(3)	Excludes lateral pipelines where revenue is not based on throughput.
(4)	Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported are the average daily rates for the days of operation.
(5)	Amount includes 4,400 barrels per day and 4,300 barrels per day fractionated on behalf of Liberty for the three months ended September 30, 2011 and 2010, respectively, and includes 5,100 barrels per day and 3,500 barrels per day fractionated on behalf of Liberty for the nine months ended September 30, 2011 and 2010, respectively. Beginning in the fourth quarter of 2011, Siloam will no longer fractionate NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011.
(6)	Represents sales at the Siloam fractionator. The total sales exclude approximately 17,100,000 gallons and 16,700,000 gallons sold by the Northeast on behalf of Liberty for the three months ended September 30, 2011 and 2010, respectively, and approximately 58,600,000 gallons and 40,000,000 gallons sold for the nine months ended September 30, 2011 and 2010, respectively. These volumes are included as part of NGLs sold at Liberty.
(7)	Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility. Through August 2011, only propane was recovered at our Liberty facilities. In September 2011, Liberty’s fractionation facility commenced operations and Liberty now has full fractionation capabilities.
(8)	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 at 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, 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, 2010	Southwest		Northeast		Liberty		Gulf Coast		Total
Revenue	$	159,044	$	83,400	$	28,606	$	21,320	$	292,370

Operating expenses:
Purchased product costs	74,835		55,879		5,986		—		136,700
Facility expenses	20,659		5,268		5,668		8,785		40,380
Total operating expenses before items not allocated to segments	95,494		61,147		11,654		8,785		177,080

Portion of operating income attributable to non-controlling interests	1,906		—		6,772		—		8,678
Operating income before items not allocated to segments	$	61,644	$	22,253	$	10,180	$	12,535	$	106,612

	Three months ended September 30,
	2011			2010

Operating income before items not allocated to segments	$	147,810		$	106,612
Portion of operating income attributable to non-controlling interests	19,450			8,678
Derivative gain (loss) not allocated to segments	111,004			(56,391		)
Revenue deferral adjustment	(2,489		)	—
Compensation expense included in facility expenses not allocated to segments	(263		)	(404		)
Facility expenses adjustments	2,855			2,850
Selling, general and administrative expenses	(20,162		)	(17,137		)
Depreciation	(38,715		)	(31,362		)
Amortization of intangible assets	(10,985		)	(10,193		)
Loss on disposal of property, plant and equipment	(147		)	(1,937		)
Accretion of asset retirement obligations	(557		)	(70		)
Income from operations	207,801			646
Other income (expense):
Loss from unconsolidated affiliate	(507		)	—
Interest income	62			422
Interest expense	(26,899		)	(26,433		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,002		)	(3,625		)
Loss on redemption of debt	(133		)	—
Miscellaneous (expense) income, net	(4		)	76
Income (loss) before provision for income tax	$	179,318		$	(28,914	)

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, 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, 2010	Southwest		Northeast		Liberty		Gulf Coast		Total
Revenue	$	479,051	$	276,570	$	66,354	$	62,958	$	884,933

Operating expenses:
Purchased product costs	220,849		179,700		8,570		—		409,119
Facility expenses	60,543		14,555		19,121		23,875		118,094
Total operating expenses before items not allocated to segments	281,392		194,255		27,691		23,875		527,213

Portion of operating income attributable to non-controlling interests	4,962		—		15,617		—		20,579
Operating income before items not allocated to segments	$	192,697	$	82,315	$	23,046	$	39,083	$	337,141

	Nine months ended September 30,
	2011			2010

Operating income before items not allocated to segments	$	444,034		$	337,141
Portion of operating income attributable to non-controlling interests	49,527			20,579
Derivative gain (loss) not allocated to segments	46,859			(21,850		)
Revenue deferral adjustment	(12,854		)	—
Compensation expense included in facility expenses not allocated to segments	(1,491		)	(1,412		)
Facility expenses adjustments	8,565			6,240
Selling, general and administrative expenses	(60,454		)	(55,064		)
Depreciation	(110,280		)	(89,367		)
Amortization of intangible assets	(32,632		)	(30,579		)
Loss on disposal of property, plant and equipment	(4,619		)	(2,116		)
Accretion of asset retirement obligations	(934		)	(282		)
Income from operations	325,721			163,290
Other income (expense):
(Loss) earnings from unconsolidated affiliate	(1,262		)	1,517
Interest income	214			1,185
Interest expense	(83,036		)	(75,970		)
Amortization of deferred financing costs and discount (a component of interest expense)	(3,873		)	(8,517		)
Derivative gain related to interest expense	—			1,871
Loss on redemption of debt	(43,461		)	—
Miscellaneous income, net	127			1,129
Income before provision for income tax	$	194,430		$	84,505

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,
	2011			2010			2011			2010

Net income (loss)	$	153,454		$	(18,676	)	$	167,988		$	74,296
Depreciation, amortization, impairment, and other non-cash operating expenses	50,482			43,640			148,699			122,578
Loss on redemption of debt, net of tax benefit	119			—			39,618			—
Amortization of deferred financing costs and discount	1,002			3,625			3,873			8,517
Non-cash loss (earnings) from unconsolidated affiliate	507			—			1,262			(1,517		)
Distributions from unconsolidated affiliate	—			1,353			300			2,508
Non-cash compensation expense	995			1,447			3,707			6,456
Non-cash derivative activity	(126,802		)	50,610			(102,681		)	(14,782		)
Provision for income tax - deferred	21,905			(13,771		)	18,338			(45		)
Cash adjustment for non-controlling interest of consolidated subsidiaries	(18,227		)	(8,274		)	(46,285		)	(19,317		)
Revenue deferral adjustment	2,489			—			12,854			—
Other	1,334			(1,259		)	4,537			561
Maintenance capital expenditures, net of joint venture partner contributions	(1,947		)	(4,001		)	(7,819		)	(7,313		)
Distributable cash flow	$	85,311		$	54,694		$	244,391		$	171,942

Maintenance capital expenditures	$	2,179		$	4,001		$	8,577		$	7,313
Growth capital expenditures	123,631			116,912			351,349			366,860
Total capital expenditures	125,810			120,913			359,926			374,173
Acquisition	—			—			230,728			—
Total capital expenditures and acquisition	125,810			120,913			590,654			374,173
Joint venture partner contributions	(14,474		)	(53,975		)	(68,501		)	(158,017		)
Total capital expenditures and acquisition, net	$	111,336		$	66,938		$	522,153		$	216,156

Distributable cash flow	$	85,311		$	54,694		$	244,391		$	171,942
Maintenance capital expenditures, net	1,947			4,001			7,819			7,313
Changes in receivables and other assets	(17,856		)	(19,966		)	(33,255		)	(32,979		)
Changes in accounts payable, accrued liabilities and other long-term liabilities	38,405			16,118			69,372			24,335
Derivative instrument premium payments, net of amortization	1,137			492			3,281			1,586
Cash adjustment for non-controlling interest of consolidated subsidiaries	18,227			8,274			46,285			19,317
Other	(2,286		)	2,989			(6,644		)	5,724
Net cash provided by operating activities	$	124,885		$	66,602		$	331,249		$	197,238

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,
	2011			2010			2011			2010

Net income (loss)	$	153,454		$	(18,676	)	$	167,988		$	74,296
Non-cash compensation expense	995			1,447			3,707			6,456
Non-cash derivative activity	(126,802		)	50,610			(102,681		)	(13,980		)
Interest expense (1)	25,687			27,802			80,235			77,777
Depreciation, amortization, impairment, and other non-cash operating expenses	50,482			43,640			148,699			122,578
Loss on redemption of debt	133			—			43,461			—
Provision for income tax	25,864			(10,238		)	26,442			10,209
Adjustment for cash flow from unconsolidated affiliate	507			1,450			1,562			1,089
Adjustment related to non-wholly owned, consolidated subsidiaries	(22,713		)	(11,866		)	(44,819		)	(32,631		)
Other	(594		)	(432		)	(1,390		)	(912		)
Adjusted EBITDA	$	107,013		$	83,737		$	323,204		$	244,882

(1) Includes derivative activity related to interest expense, amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.

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 and forecasted crude oil and natural gas prices for 2012. The analysis assumes various combinations of crude oil and natural gas prices as well as three NGL to crude correlation scenarios, including:

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

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

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

The analysis further assumes derivative instruments outstanding as of October 28, 2011, 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
Crude Oil Price	Three-year NGL Correlation to Crude	$ 3.00		$ 3.50		$ 4.00		$ 4.50		$ 5.00
	One standard deviation above	$	586	$	578	$	569	$	561	$	552
$110	Three-year NGL correlation to crude	$	508	$	500	$	491	$	483	$	474
	One standard deviation below	$	434	$	426	$	417	$	409	$	400

	One standard deviation above	$	545	$	536	$	528	$	519	$	511
$100	Three-year NGL correlation to crude	$	475	$	466	$	458	$	449	$	441
	One standard deviation below	$	408	$	399	$	391	$	382	$	373

	One standard deviation above	$	499	$	491	$	482	$	474	$	465
$90	Three-year NGL correlation to crude	$	438	$	430	$	421	$	413	$	404
	One standard deviation below	$	377	$	369	$	360	$	352	$	341

	One standard deviation above	$	453	$	445	$	436	$	428	$	419
$80	Three-year NGL correlation to crude	$	400	$	392	$	383	$	375	$	366
	One standard deviation below	$	346	$	337	$	329	$	317	$	307

	One standard deviation above	$	413	$	404	$	396	$	387	$	379
$70	Three-year NGL correlation to crude	$	365	$	357	$	348	$	340	$	331
	One standard deviation below	$	318	$	309	$	298	$	288	$	280

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.

Although MarkWest believes the expectations reflected in this analysis are reasonable, MarkWest can give no assurance that such expectations will prove to be correct and readers are cautioned that projected performance, results, or distributions may not be achieved. Actual changes in market prices, and the correlation between crude oil and NGL prices, may differ from the assumptions utilized in the analysis. Actual results, performance, distributions, volumes, events, or transactions could vary significantly from those expressed, considered, or implied in this analysis. All results, performance, distributions, volumes, events, or transactions are subject to a number of uncertainties and risks. Those uncertainties and risks may not be factored into or accounted for in this analysis. Readers are urged to carefully review and consider the cautionary statements and disclosures made in MarkWest’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”