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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2011
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                             to

Commission File Number 001-31239

MARKWEST ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization) 27-0005456
(IRS Employer
Identification No.)

1515 Arapahoe Street, Tower 1, Suite 1600, Denver, Colorado 80202-2137
(Address of principal executive offices)

Registrant's telephone number, including area code: 303-925-9200

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    No o

        Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý Accelerated filer o Non-accelerated filer o
(Do not check if a
smaller reporting company) Smaller reporting company o

        Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2 of the Exchange Act). Yes o    No ý

        The number of the registrant's common units outstanding as of May 2, 2011, was 75,160,105.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets at March 31, 2011 and December 31, 2010	2
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010	3
	Unaudited Condensed Consolidated Statements of Changes in Equity for the three months ended March 31, 2011 and 2010	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010	5
	Unaudited Notes to the Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	48
Item 4.	Controls and Procedures	51
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	52
Item 6.	Exhibits	52
SIGNATURES		54

        Throughout this document we make statements that are classified as "forward-looking." Please refer to the "Forward-Looking Statements" included in Part I, Item 2 for an explanation of these types of assertions. Also, in this document, unless the context requires otherwise, references to "we," "us," "our," "MarkWest Energy" or the "Partnership" are intended to mean MarkWest Energy Partners, L.P., and its consolidated subsidiaries. References to "MarkWest Hydrocarbon" or the "Corporation" are intended to mean MarkWest Hydrocarbon, Inc., a wholly-owned taxable subsidiary of the Partnership.

Glossary of Terms

Bbl	Barrel
Bbl/d	Barrels per day
Credit Facility	Revolving credit facility as provided under the Partnership's amended and restated credit agreement entered into in July 2010
Dth/d	Dekatherms per day
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
Mcf/d	One thousand cubic feet of natural gas per day
MMBtu	One million British thermal units, an energy measurement
MMBtu/d	One million British thermal units per day
MMcf/d	One million cubic feet of natural gas per day
Net operating margin (a non-GAAP financial measure)	Segment revenue, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss)
NGL	Natural gas liquids, such as ethane, propane, butanes and natural gasoline
N/A	Not applicable
OTC	Over-the-Counter
SEC	Securities and Exchange Commission
SMR	Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation facility in Corpus Christi, Texas
TSR	Total shareholder return
WTI	West Texas Intermediate
VIE	Variable interest entity
2002 LTIP	2002 Long-Term Incentive Plan
2006 Hydrocarbon Plan	2006 Hydrocarbon Stock Incentive Plan
2008 LTIP	2008 Long-Term Incentive Plan

1

PART I—FINANCIAL INFORMATION

Item 1.    Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

					March 31, 2011			December 31, 2010
				ASSETS
Current assets:
	Cash and cash equivalents ($9,037 and $2,913, respectively)				$	73,152		$	67,450
	Receivables, net ($14,288 and $43,783, respectively)					165,718			179,209
	Inventories ($4,832 and $8,431, respectively)					15,922			23,432
	Fair value of derivative instruments					6,138			4,345
	Deferred income taxes					16,090			16,090
	Other current assets ($77 and $272, respectively)					10,678			8,020
		Total current assets				287,698			298,546
Property, plant and equipment ($928,866 and $849,986, respectively)						2,849,638			2,613,027
Less: accumulated depreciation ($46,434 and $38,169, respectively)						(327,286	)		(294,003	)
		Total property, plant and equipment, net				2,522,352			2,319,024
Other long-term assets:
	Restricted cash ($28,052 and $28,001, respectively)					28,052			28,001
	Investment in unconsolidated affiliate					28,149			28,688
	Intangibles, net of accumulated amortization of $135,367 and $124,568, respectively					636,568			613,578
	Goodwill					67,918			9,421
	Deferred financing costs, net of accumulated amortization of $11,432 and $11,445, respectively					35,158			32,901
	Deferred contract cost, net of accumulated amortization of $2,028 and $1,950, respectively					1,222			1,300
	Fair value of derivative instruments					3,037			417
	Deferred income taxes					5,425			—
	Other long-term assets ($378 and $383, respectively)					1,807			1,486
		Total assets			$	3,617,386		$	3,333,362
			LIABILITIES AND EQUITY
Current liabilities:
	Accounts payable ($10,673 and $5,945, respectively)				$	130,654		$	122,473
	Accrued liabilities ($48,750 and $64,713, respectively)					134,030			153,869
	Deferred income taxes					11			11
	Fair value of derivative instruments					102,810			65,489
		Total current liabilities				367,505			341,842
Deferred income taxes						1,666			10,427
Fair value of derivative instruments						114,211			66,290
Long-term debt, net of discounts of $1,595 and $1,566, respectively						1,474,757			1,273,434
Other long-term liabilities ($157 and $154, respectively)						113,167			105,349
Commitments and contingencies (Note 11)
Equity:
	MarkWest Energy Partners, L.P. partners' capital (75,160 and 71,440 common units issued and outstanding, respectively)					1,076,773			1,070,503
	Non-controlling interest in consolidated subsidiaries					469,307			465,517
		Total equity				1,546,080			1,536,020
		Total liabilities and equity			$	3,617,386		$	3,333,362

        Asset and liability amounts in parentheses represent the portion of the consolidated balance attributable to VIEs.

The accompanying notes are an integral part of these condensed consolidated financial statements.

2

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Operations

(unaudited, in thousands, except per unit amounts)

			Three months ended March 31,
			2011			2010
Revenue:
	Revenue		$	348,900		$	315,615
	Derivative loss			(85,679	)		(7,236	)
		Total revenue		263,221			308,379
Operating expenses:
	Purchased product costs			153,629			144,296
	Derivative loss related to purchased product costs			19,394			13,389
	Facility expenses			39,424			37,905
	Derivative gain related to facility expenses			(3,011	)		(806	)
	Selling, general and administrative expenses			21,712			21,508
	Depreciation			34,364			28,187
	Amortization of intangible assets			10,817			10,193
	Loss (gain) on disposal of property, plant and equipment			2,099			(9	)
	Accretion of asset retirement obligations			87			143
		Total operating expenses		278,515			254,806
		(Loss) income from operations		(15,294	)		53,573
Other (expense) income:
	Loss from unconsolidated affiliate			(539	)		(68	)
	Interest income			89			386
	Interest expense			(28,263	)		(23,782	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(1,428	)		(2,612	)
	Derivative gain related to interest expense			—			1,871
	Loss on redemption of debt			(43,328	)		—
	Miscellaneous (expense) income, net			(38	)		1,062
		(Loss) income before provision for income tax		(88,801	)		30,430
Provision for income tax (benefit) expense:
	Current			56			5,798
	Deferred			(14,186	)		(1,372	)
		Total provision for income tax		(14,130	)		4,426
		Net (loss) income		(74,671	)		26,004
Net income attributable to non-controlling interest				(9,358	)		(4,494	)
		Net (loss) income attributable to the Partnership	$	(84,029	)	$	21,510
Net (loss) income attributable to the Partnership's common unitholders per common unit (Note 14):
	Basic		$	(1.13	)	$	0.32
	Diluted		$	(1.13	)	$	0.32
Weighted average number of outstanding common units:
	Basic			74,531			66,453
	Diluted			74,531			66,453
Cash distribution declared per common unit			$	0.65		$	0.64

The accompanying notes are an integral part of these condensed consolidated financial statements.

3

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Changes in Equity

(unaudited, in thousands)

	MarkWest Energy Partners, L.P. Unitholders
	Common Units		Partners' Capital			Non-controlling Interest			Total
December 31, 2010		71,440	$	1,070,503		$	465,517		$	1,536,020
Share-based compensation activity		270		314			—			314
Excess tax benefits related to share-based compensation		—		1,096			—			1,096
Distributions paid		—		(49,274	)		(13,568	)		(62,842	)
Issuance of units in public offering, net of offering costs		3,450		138,163			—			138,163
Contributions to MarkWest Liberty Midstream joint venture		—		—			8,000			8,000
Net (loss) income		—		(84,029	)		9,358			(74,671	)
March 31, 2011		75,160	$	1,076,773		$	469,307		$	1,546,080

	MarkWest Energy Partners, L.P. Unitholders
	Common Units		Partners' Capital			Non-controlling Interest			Total
December 31, 2009		66,275	$	1,096,654		$	282,739		$	1,379,393
Share-based compensation activity		271		3,622			—			3,622
Excess tax benefits related to share-based compensation		—		97			—			97
Distributions paid		—		(42,866	)		(1,270	)		(44,136	)
Contributions to MarkWest Liberty Midstream joint venture		—		—			42,220			42,220
Net income		—		21,510			4,494			26,004
March 31, 2010		66,546	$	1,079,017		$	328,183		$	1,407,200

The accompanying notes are an integral part of these condensed consolidated financial statements.

4

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Cash Flows

(unaudited, in thousands)

				Three months ended March 31,
				2011			2010
Cash flows from operating activities:
Net (loss) income				$	(74,671	)	$	26,004
	Adjustments to reconcile net (loss) income to net cash provided by operating activities:
		Depreciation			34,364			28,187
		Amortization of intangible assets			10,817			10,193
		Loss on redemption of debt			43,328			—
		Amortization of deferred financing costs and discount			1,428			2,612
		Accretion of asset retirement obligations			87			143
		Amortization of deferred contract cost			78			78
		Phantom unit compensation expense			5,636			6,285
		Equity in loss of unconsolidated affiliate			539			68
		Unrealized loss on derivative instruments			80,829			2,269
		Loss (gain) on disposal of property, plant and equipment			2,099			(9	)
		Deferred income taxes			(14,186	)		(1,372	)
	Changes in operating assets and liabilities, net of working capital acquired:
		Receivables			13,751			(5,968	)
		Inventories			9,148			9,149
		Other current assets			(2,658	)		6,096
		Accounts payable and accrued liabilities			(3,024	)		28,507
		Other long-term assets			(372	)		36
		Other long-term liabilities			8,126			2,082
			Net cash provided by operating activities		115,319			114,360
Cash flows from investing activities:
		Capital expenditures			(113,652	)		(95,322	)
		Acquisitions			(230,728	)		—
		Proceeds from disposal of property, plant and equipment			2,759			292
			Net cash used in investing activities		(341,621	)		(95,030	)
Cash flows from financing activities:
		Proceeds from revolving credit facility			307,600			135,604
		Payments of revolving credit facility			(168,400	)		(141,904	)
		Proceeds from long-term debt			499,000			—
		Payments of long-term debt			(437,848	)		—
		Payments of premiums on redemption of long-term debt			(39,520	)		—
		Payments for debt issuance costs, deferred financing costs and registration costs			(6,524	)		—
		Contributions to MarkWest Liberty Midstream joint venture			8,000			42,220
		Payments of SMR liability			(452	)		(58	)
		Proceeds from public equity offering, net			138,163			—
		Cash paid for taxes related to net settlement of share-based payment awards			(6,269	)		(3,730	)
		Excess tax benefits related to share-based compensation			1,096			97
		Payment of distributions to common unitholders			(49,274	)		(42,866	)
		Payment of distributions to non-controlling interest			(13,568	)		(1,270	)
			Net cash provided by (used in) financing activities		232,004			(11,907	)
Net increase in cash					5,702			7,423
Cash and cash equivalents at beginning of year					67,450			97,752
Cash and cash equivalents at end of period				$	73,152		$	105,175

The accompanying notes are an integral part of these condensed consolidated financial statements.

5

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

1. Organization and Basis of Presentation

        MarkWest Energy Partners, L.P. was formed in 2002 as a Delaware limited partnership. The Partnership is engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. The Partnership 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.

        These unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the SEC for interim financial reporting. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. These condensed consolidated financial statements should be read in conjunction with the Partnership's consolidated financial statements included in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2010. In management's opinion, the Partnership has made all adjustments necessary for a fair presentation of its results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. Finally, results for the three months ended March 31, 2011 are not necessarily indicative of results for the full year 2011, or any other future period.

        The Partnership's unaudited condensed consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Liberty Midstream & Resources L.L.C. ("MarkWest Liberty Midstream") and MarkWest Pioneer, L.L.C. ("MarkWest Pioneer"), variable interest entities for which the Partnership has been determined to be the primary beneficiary, are included in the condensed consolidated financial statements (see Note 4). All significant intercompany investments, accounts and transactions have been eliminated. Investments in which the Partnership exercises significant influence but does not control, and is not the primary beneficiary, are accounted for using the equity method.

2. Recent Accounting Pronouncements

        In September 2009, the FASB amended the accounting guidance for revenue recognition for multiple-deliverable arrangements. The amended guidance establishes a hierarchy for determining the selling price of each individual deliverable and eliminates the residual value method of allocating the selling price. The amended guidance was effective for the Partnership prospectively for all revenue arrangements entered into or materially modified on or after January 1, 2011. The amendment did not have a material effect on the Partnership's condensed consolidated financial statements.

3. Business Combination

Langley Acquisition

        On February 1, 2011, the Partnership acquired natural gas processing and NGL transportation assets from EQT Gathering, LLC, a subsidiary of EQT Corporation (together with all of its affiliates, "EQT"), for a cash purchase price of approximately $230.7 million, subject to customary purchase price adjustments. The assets acquired include natural gas processing facilities located near Langley, Kentucky, consisting of a cryogenic natural gas processing plant with a capacity of approximately 100 MMcf/d and a refrigeration natural gas processing plant with a capacity of approximately

6

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Business Combination (Continued)

75 MMcf/d (together, the "Langley Processing Facilities"), a partially constructed NGL pipeline (the "Ranger Pipeline") that will extend through parts of Kentucky and West Virginia, and certain other related assets. The acquired assets do not include certain residue gas compression and transportation facilities at the same location as the Langley Processing Facilities. This acquisition is referred to as the Langley Acquisition. In connection with the Langley Acquisition, the Partnership will complete the construction of the Ranger Pipeline to connect the Langley Processing Facilities to the Partnership's existing pipeline that transports NGLs to its Siloam fractionation facility in South Shore, Kentucky.

        Concurrently with the closing of the Langley Acquisition, the Partnership entered into a long-term agreement to process certain natural gas owned or controlled by EQT at the Langley Processing Facilities. The processing agreement requires the Partnership to install an additional cryogenic natural gas processing plant with a capacity of at least 60 MMcf/d by mid-2012. The Partnership will fractionate the NGLs produced at the Langley Processing Facilities at its Siloam facility and will market the fractionated products on behalf of EQT in accordance with a long-term NGL exchange and marketing agreement. As a result of the acquisition, the Partnership has significantly expanded its midstream operations in the liquids-rich gas areas of the Appalachian Basin.

        The Langley Acquisition is accounted for as a business combination. The total purchase price is allocated to the identifiable assets acquired and liabilities assumed based on the estimated fair values at the acquisition date. The remaining purchase price in excess of the fair value of the identifiable assets and liabilities is recorded as goodwill. The acquired assets and the related results of operations are included in the Partnership's Northeast segment.

        The Partnership is in the process of finalizing the fair value estimates of the acquired assets and liabilities, thus the purchase price allocation is subject to further adjustment, which could impact depreciation and amortization expense. The following table summarizes the preliminary purchase price allocation for the Langley Acquisition (in thousands):

Property, plant and equipment		$	136,525
Goodwill			58,497
Intangibles			33,900
Inventories			1,806
	Total	$	230,728

        The goodwill recognized from the Langley Acquisition results primarily from the benefits associated with combining the acquired assets with the Partnership's existing assets and operations. Management believes that the primary item that generated the goodwill is the Partnership's ability to continue to grow its business in the liquids-rich gas areas of the Appalachian Basin and access additional markets in a competitive environment through the processing rights for a large area of dedicated acreage and the expanded midstream infrastructure obtained in the Langley Acquisition. All of the goodwill is deductible for tax purposes.

        Intangible assets consist of an identifiable customer contract and relationship. The acquired intangibles will be amortized on a straight-line basis over the estimated remaining useful life of approximately twelve years.

7

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Business Combination (Continued)

        The results of operations from the Langley Acquisition are included in the condensed consolidated financial statements from the acquisition date. Revenue and net income related to the Langley Acquisition was approximately $3.9 million and $1.4 million, respectively, for the quarter ended March 31, 2011.

        Pro forma financial results that give effect to the Langley Acquisition are not presented as it is impracticable to obtain the necessary information. EQT did not operate the acquired assets as a stand-alone business, and therefore historical financial information that is consistent with the operations under the current agreements is not available or meaningful.

4. Variable Interest Entities

MarkWest Liberty Midstream

        MarkWest Liberty Midstream operates in the natural gas midstream business in and around the Marcellus Shale in western Pennsylvania and northern West Virginia. Effective January 1, 2011, equity interests in the entity are owned 51% by the Partnership and 49% by M&R MWE Liberty, LLC ("M&R"), an affiliate of The Energy & Minerals Group and its affiliated funds.

        As of March 31, 2011, the capital contributed to MarkWest Liberty Midstream is disproportionate to each member's respective ownership interest. The cumulative capital contributed by M&R exceeded its ownership interest by $43.0 million. Under the terms of the joint venture agreement, M&R received a special $1.1 million allocation of net income from MarkWest Liberty Midstream during the first quarter of 2011 due to its excess contributions. The non-cash allocation is recorded in Net income attributable to non-controlling interest.

MarkWest Pioneer

        MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline. Equity interests in the entity are shared equally by the Partnership and Arkoma Pipeline Partners, LLC.

8

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Variable Interest Entities (Continued)

Financial Statement Impact of VIEs

        As the primary beneficiary of MarkWest Liberty Midstream and MarkWest Pioneer, the Partnership consolidates the entities and recognizes non-controlling interests. The following tables show the assets and liabilities attributable to VIEs as of March 31, 2011 and December 31, 2010 (in thousands):

		As of March 31, 2011
		MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents		$	7,369	$	1,668	$	9,037
Receivables, net			12,880		1,408		14,288
Inventories			4,832		—		4,832
Other current assets			77		—		77
Property, plant and equipment, net of accumulated depreciation of $35,572 and $10,862, respectively			736,956		145,476		882,432
Restricted cash			28,052		—		28,052
Other long-term assets			275		103		378
	Total assets	$	790,441	$	148,655	$	939,096
LIABILITIES
Accounts payable		$	10,593	$	80	$	10,673
Accrued liabilities			48,083		667		48,750
Other long-term liabilities			88		69		157
	Total liabilities	$	58,764	$	816	$	59,580

		As of December 31, 2010
		MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents		$	—	$	2,913	$	2,913
Receivables, net			42,181		1,602		43,783
Inventories			8,431		—		8,431
Other current assets			271		1		272
Property, plant and equipment, net of accumulated depreciation of $28,869 and $9,300, respectively			664,778		147,039		811,817
Restricted cash			28,001		—		28,001
Other long-term assets			281		102		383
	Total assets	$	743,943	$	151,657	$	895,600
LIABILITIES
Accounts payable		$	5,945	$	—	$	5,945
Accrued liabilities			63,450		1,263		64,713
Other long-term liabilities			86		68		154
	Total liabilities	$	69,481	$	1,331	$	70,812

9

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Variable Interest Entities (Continued)

        The assets of the VIEs are the property of the respective entities and are not available to the Partnership for any other purpose, including as collateral for its secured debt (see Note 9 and Note 16). VIE asset balances can only be used to settle obligations of each respective VIE. The liabilities of the VIEs do not represent additional claims against the Partnership's general assets, and the creditors or beneficial interest holders of the VIE do not have recourse to the general credit of the Partnership. The Partnership's Liberty segment includes the results of operations of MarkWest Liberty Midstream and the Partnership's Southwest segment includes the results of operations of MarkWest Pioneer (see Note 15). The cash flow information for MarkWest Liberty Midstream and MarkWest Pioneer comprise substantially all of the cash flow information of the Partnership's non-guarantor subsidiaries (see Note 16). The Partnership's maximum exposure to loss as a result of its involvement with the VIEs includes its equity investment, any additional capital contribution commitments and any operating expense incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the three months ended March 31, 2011 and 2010.

5. Derivative Financial Instruments

Commodity Derivatives

        NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership's control. The Partnership's profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its processing plants or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of drilling activity, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so that the Partnership can meet its cash distribution objectives, debt service and capital expenditures, the Partnership executes a hedging strategy governed by the risk management policy approved by the General Partner's board of directors (the "Board"). The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps and options traded on the OTC market. The risk management policy does not allow for speculative derivative contracts.

        To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. Generally the Partnership hedges its NGL price risk using crude oil as NGL financial markets lack adequate liquidity and historically there has been a strong relationship between changes in NGL and crude oil prices. The pricing relationship between NGLs and crude oil may vary in certain periods due to various market conditions. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the Partnership incurs increased risk and additional gains or losses. The Partnership enters into NGL derivative contracts when adequate market liquidity exists.

10

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Derivative Financial Instruments (Continued)

        To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas and takes into account the partial offset of its long and short gas positions resulting from normal operating activities.

        As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2013. For entities that are not wholly owned by the Partnership, commodity risk is mitigated only for the Partnership's ownership interest. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

        The Partnership enters into derivative contracts primarily with financial institutions that are participating members of the Credit Facility as collateral is not posted by the Partnership as the participating members have a collateral position in substantially all the wholly-owned assets of the Partnership. All of the Partnership's financial derivative positions are currently with participating bank group members. Management conducts a standard credit review on counterparties and the Partnership has agreements containing collateral requirements. For all participating bank group members, collateral requirements do not exist when a derivative contract favors the Partnership. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).

        The Partnership records derivative contracts at fair value in the Condensed Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation which may cause volatility in the Condensed Consolidated Statements of Operations as the Partnership recognizes in current earnings all unrealized gains and losses from the mark to market on derivative activity.

        As of March 31, 2011, the Partnership had the following outstanding commodity contracts that were entered into to economically hedge future sales of NGLs or future purchases of natural gas.

Derivative contracts not designated as hedging instruments	Notional quantity (net)
Crude Oil (bbl)		8,562,749
Natural Gas (MMBtu)		14,528,806

Embedded Derivatives in Commodity Contracts

        The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative loss related to purchased product costs. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related

11

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Derivative Financial Instruments (Continued)

processing agreement from March 31, 2015 to December 31, 2022. As of March 31, 2011, the estimated fair value of this contract was a liability of $108.2 million and the recorded value was $54.7 million. The recorded liability does not include the fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of March 31, 2011 (in thousands).

Fair value of commodity contract	$	108,161
Inception value for period from April 1, 2015 to December 31, 2022		(53,507	)
Derivative liability as of March 31, 2011	$	54,654

        The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at one of its plant locations through the fourth quarter of 2014. The value of the derivative component of this contract is marked to market through Derivative gain related to facility expenses. As of March 31, 2011, the estimated fair value of this contract was an asset of $4.0 million.

Financial Statement Impact of Derivative Instruments

        There were no material changes to the Partnership's policy regarding the accounting for these instruments as previously disclosed in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2010. The impact of the Partnership's derivative instruments on its Condensed Consolidated Balance Sheets is summarized below (in thousands):

		Assets				Liabilities
Derivative instruments not designated as hedging instruments and their balance sheet location		March 31, 2011		December 31, 2010		March 31, 2011			December 31, 2010
Fair value of derivative instruments—current		$	6,138	$	4,345	$	(102,810	)	$	(65,489	)
Fair value of derivative instruments—long-term			3,037		417		(114,211	)		(66,290	)
	Total	$	9,175	$	4,762	$	(217,021	)	$	(131,779	)

12

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Derivative Financial Instruments (Continued)

        The impact of the Partnership's derivative instruments on its Condensed Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010 is summarized below (in thousands):

			Three months ended March 31,
Derivative instruments not designated as hedging instruments and the location of gain or (loss) recognized in income			2011			2010
Revenue: Derivative loss
	Realized loss		$	(14,391	)	$	(13,129	)
	Unrealized (loss) gain			(71,288	)		5,893
		Total revenue: derivative loss		(85,679	)		(7,236	)
Derivative loss related to purchased product costs
	Realized loss			(7,887	)		(5,438	)
	Unrealized loss			(11,507	)		(7,951	)
		Total derivative loss related to purchase product costs		(19,394	)		(13,389	)
Derivative gain related to facility expenses
	Unrealized gain			3,011			806
Derivative gain related to interest expense
	Realized gain			—			2,380
	Unrealized loss			—			(509	)
		Total derivative gain related to interest expense		—			1,871
Miscellaneous (expense) income, net
	Unrealized gain			—			56
		Total loss	$	(102,062	)	$	(17,892	)

        At March 31, 2011, the fair value of the Partnership's commodity derivative contracts is inclusive of premium payments of $3.4 million, net of amortization. For the three months ended March 31, 2011 and 2010, the Realized loss—revenue includes amortization of premium payments of $1.0 million and $0.6 million, respectively.

13

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

6. Fair Value

        Fair value measurements and disclosures relate primarily to the Partnership's derivative positions discussed in Note 5. The following table presents the derivative instruments carried at fair value as of March 31, 2011 and December 31, 2010 (in thousands):

As of March 31, 2011		Assets		Liabilities
Significant other observable inputs (Level 2)
	Commodity contracts	$	492	$	(121,825	)
Significant unobservable inputs (Level 3)
	Commodity contracts		4,636		(40,542	)
	Embedded derivatives in commodity contracts		4,047		(54,654	)
Total carrying value in Condensed Consolidated Balance Sheet		$	9,175	$	(217,021	)

As of December 31, 2010		Assets		Liabilities
Significant other observable inputs (Level 2)
	Commodity derivative contracts	$	52	$	(77,776	)
Significant unobservable inputs (Level 3)
	Commodity derivative contracts		3,674		(18,031	)
	Embedded derivatives in commodity contracts		1,036		(35,972	)
Total carrying value in Condensed Consolidated Balance Sheet		$	4,762	$	(131,779	)

Changes in Level 3 Fair Value Measurements

        The table below includes a rollforward of the balance sheet amounts for the three months ended March 31, 2011 and 2010 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

	Three months ended March 31, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(14,357	)	$	(34,936	)
Total loss (realized and unrealized) included in earnings(1)		(22,993	)		(19,280	)
Settlements		1,444			3,609
Fair value at end of period	$	(35,906	)	$	(50,607	)
The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period(1)	$	(22,779	)	$	(18,692	)

14

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

6. Fair Value (Continued)

	Three months ended March 31, 2010
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Interest Rate Contracts			Embedded Derivative in Debt Contract
Fair value at beginning of period	$	(11,340	)	$	(34,199	)	$	509		$	(190	)
Total gain or loss (realized and unrealized) included in earnings(1)		(2,758	)		936			1,871			56
Purchases, sales, issuances and settlements (net)		6,191			2,402			(2,380	)		—
Fair value at end of period	$	(7,907	)	$	(30,861	)	$	—		$	(134	)
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period(1)	$	(3,521	)	$	3,338		$	—		$	56

(1)

Losses on Commodity Derivative Contracts classified as Level 3 are recorded in Derivative loss related to revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs, Derivative loss related to purchased product costs and Derivative gain related to facility expenses. Gains on Embedded Derivatives in Debt Contract are recorded in Miscellaneous (expense) income, net. Gains on Interest Rate Contracts are recorded in Derivative gain related to interest expense.

7. Inventories

        Inventories consist of the following (in thousands):

		March 31, 2011		December 31, 2010
Natural gas and natural gas liquids		$	7,383	$	15,930
Spare parts			8,539		7,502
	Total inventories	$	15,922	$	23,432

15

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

8. Goodwill

        Changes in goodwill for the three months ended March 31, 2011 are summarized as follows (in thousands):

	Southwest			Northeast		Gulf Coast			Total
Historical goodwill	$	24,324		$	3,948	$	9,854		$	38,126
Cumulative impairment		(18,851	)		—		(9,854	)		(28,705	)
Balance as of December 31, 2010		5,473			3,948		—			9,421
Acquisition(1)		—			58,497		—			58,497
Balance as of March 31, 2011	$	5,473		$	62,445	$	—		$	67,918

(1)

Represents goodwill associated with the Langley Acquisition (see Note 3).

9. Long-Term Debt

        Debt is summarized below (in thousands):

			March 31, 2011		December 31, 2010
Credit Facility
	Revolving credit facility, 4.29% interest due July 2015		$	139,200	$	—
Senior Notes(1)
	Senior Notes, 8.5% interest, net of discount of $6 and $642, respectively, issued July 2006 and due July 2016			2,784		274,358
	Senior Notes, 8.75% interest, net of discount of $597 and $924, respectively, issued April and May 2008 and due April 2018			333,765		499,076
	Senior Notes, 6.75% interest, issued November 2010 and due November 2020			500,000		500,000
	Senior Notes, 6.5% interest, net of discount of $992, issued February and March 2011 and due August 2021			499,008		—
		Total long-term debt	$	1,474,757	$	1,273,434

(1)

The estimated aggregate fair value of the Senior Notes was approximately $1,382.7 million and $1,333.9 million as of March 31, 2011 and December 31, 2010, respectively, based on quoted market prices.

Credit Facility

        Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly

16

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

9. Long-Term Debt (Continued)

basis. The Credit Facility is guaranteed by the Partnership's wholly-owned subsidiaries and collateralized by substantially all of the Partnership's assets and those of its wholly-owned subsidiaries. As of March 31, 2011, the Partnership had $139.2 million of borrowings outstanding and $27.4 million of letters of credit outstanding under the Credit Facility, leaving approximately $538.4 million available for borrowing.

Senior Notes

        On February 24, 2011, the Partnership completed a public offering of $300 million in aggregate principal amount of 6.5% senior unsecured notes ("2021 Senior Notes"), which were issued at par. The 2021 Senior Notes mature on August 15, 2021, and interest is payable semi-annually in arrears on February 15 and August 15, commencing August 15, 2011. The Partnership received net proceeds of approximately $296 million after deducting the underwriting fees and other third-party expenses associated with the offering. The Partnership used the net proceeds from this offering to fund the concurrent repurchase of approximately $272.2 million in aggregate principal amount of the Partnership's 2016 Senior Notes, pursuant to the Partnership's tender offer for any and all of the outstanding 2016 Senior Notes, and the remaining proceeds were used to repay borrowings under the Credit Facility. The Partnership recorded a pre-tax loss on redemption of debt of approximately $21.0 million in the first quarter of 2011 related to the 2016 Senior Notes, which consisted of approximately $1.1 million for the non-cash write off of the unamortized discount and deferred finance costs and approximately $19.9 million for the payment of the related tender premiums and third-party expenses.

        On March 10, 2011, the Partnership completed a follow-on public offering of an additional $200 million in aggregate principal amount of 2021 Senior Notes, which were issued at 99.5% of par and are treated as a single class of debt securities under the same indenture as the 2021 Senior Notes issued on February 24, 2011. The Partnership received net proceeds of approximately $196 million after deducting the underwriting fees and other third-party expenses associated with the offering. The Partnership used the net proceeds from this offering to fund the concurrent repurchase of approximately $165.6 million in aggregate principal amount of the Partnership's 2018 Senior Notes pursuant to the Partnership's tender offer for up to $170 million of the outstanding 2018 Senior Notes and the remaining proceeds were used to repay borrowings under the Credit Facility. The Partnership recorded a pre-tax loss on redemption of debt of approximately $22.3 million in the first quarter of 2011 related to the 2018 Senior Notes, which consisted of approximately $2.7 million for the non-cash write off of the unamortized discount and deferred finance costs and approximately $19.6 million for the payment of the related tender premiums and third-party expenses.

10. Equity

Equity Offering

        On January 14, 2011, the Partnership completed a public offering of approximately 3.45 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option, at a price of $41.20 per common unit. Net proceeds of approximately $138.2 million were used to partially fund the Partnership's ongoing capital expenditure program, including a portion of the costs associated with the Langley Acquisition (see Note 3).

17

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

10. Equity (Continued)

Distributions of Available Cash

Quarter Ended	Distribution Per Common Unit		Record Date		Payment Date
March 31, 2011	$	0.67		May 2, 2011		May 13, 2011
December 31, 2010	$	0.65		February 7, 2011		February 14, 2011

11. Commitments and Contingencies

Legal

        The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Partnership maintains insurance policies in amounts and with coverage and deductibles as it believes reasonable and prudent. However, the Partnership cannot assure that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect the Partnership from all material expenses related to future claims for property loss or business interruption to the Partnership, or for third-party claims of personal and property damage, or that the coverages or levels of insurance it currently has will be available in the future at economical prices. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the consolidated financial statements.

        In June 2006, the Pipeline and Hazardous Materials Safety Administration issued a Notice of Probable Violation and Proposed Civil Penalty ("NOPV") (CPF No. 2-2006-5001) to both MarkWest Hydrocarbon and Equitable Production Company ("Equitable"). The NOPV is associated with the pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 in Ivel, Kentucky on an NGL pipeline owned by Equitable and leased and operated by a subsidiary of the Partnership, MarkWest Energy Appalachia, L.L.C. The NOPV sets forth six counts of violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1.1 million. In March 2011, MarkWest received an order assessing a penalty solely against Equitable for count one of the NOPV in the amount of $0.5 million and assessing a penalty jointly and severally against MarkWest and Equitable for four of the other counts in the NOPV in the amount of $0.2 million. In March 2011, the parties filed separate petitions for reconsideration, which remain pending.

        In the ordinary course of business, the Partnership is a party to various other legal and regulatory actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership's financial condition, liquidity or results of operations.

18

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

12. Incentive Compensation Plans

Compensation Expense

        Total compensation expense recorded for share-based pay arrangements for the three months ended March 31, 2011 and 2010 is as follows (in thousands):

	Three months ended March 31,
	2011		2010
Phantom units	$	5,636	$	6,285
Distribution equivalent rights		102		311
Total compensation expense	$	5,738	$	6,596

        As of March 31, 2011, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP was approximately $19.1 million, with a weighted-average remaining vesting period of approximately 1.5 years.

        As part of a net settlement option, employees may elect to surrender a certain number of phantom units upon vesting, and in exchange, the Partnership will assume the income tax withholding obligations related to the vesting. Other than the amounts paid related to the net settlement option, there were no cash settlements and the Partnership received no proceeds for issuing phantom units during the three months ended March 31, 2011 and 2010.

2008 LTIP and 2006 Hydrocarbon Plan

        The following is a summary of phantom unit activity under the 2008 LTIP and 2006 Hydrocarbon Plan:

		Number of Units			Weighted-average Grant-date Fair Value
Unvested at December 31, 2010			1,329,160		$	24.86
	Granted(1)		302,362			42.59
	Vested(2)		(390,651	)		26.93
	Forfeited(3)		(296,100	)		31.81
Unvested at March 31, 2011(4)			944,771			27.75

(1)

Includes 35,250 phantom units containing performance vesting criteria related to the Partnership's relative total shareholder return ("TSR Performance Units"). In January 2011, based on the Partnership's actual 2010 performance and management's execution of the business plan, the Board exercised its discretion to vest an additional 35,250 TSR Performance Units related to the January 31, 2011 vesting installment.

(2)

Includes 176,250 TSR Performance Units.

(3)

Includes 296,100 phantom units containing performance vesting criteria related to established performance goals determined by the Compensation Committee

19

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

12. Incentive Compensation Plans (Continued)

("Performance Units"). The performance criteria were not achieved and the phantom units were forfeited in January 2011.

(4)

The calculation of the grant-date fair value for unvested units at March 31, 2011 includes the fair value as of March 31, 2011 for 35,250 TSR Performance Units. A grant date, as defined by GAAP, has not been established for these units.

Includes 141,000 TSR Performance Units. Compensation expense recognized related to TSR Performance Units was approximately $2.8 million and zero for the three months ended March 31, 2011 and 2010, respectively.

Includes 141,000 Performance Units that are not expected to vest. Compensation expense recognized for these Performance Units was zero for the three months ended March 31, 2011 and 2010.

	Three months ended March 31,
	2011		2010
	(in thousands)
Total grant-date fair value of phantom units granted during the period(1)	$	12,878	$	7,968
Total fair value of phantom units vested during the period(2)	$	10,521	$	9,505

(1)

The calculation of the grant-date fair value for units granted during the three months ended March 31, 2011 includes the fair value of $1.5 million for 35,250 TSR Performance Units.

(2)

The calculation of the fair value of phantom units vested during the three months ended March 31, 2011 includes the fair value of $4.9 million for 176,250 TSR Performance Units.

2002 LTIP

        The following is a summary of phantom unit activity under the 2002 LTIP:

		Number of Units			Weighted-average Grant-date Fair Value
Unvested at December 31, 2010			23,645		$	33.83
	Vested		(23,645	)		33.83
Unvested at March 31, 2011			—			—

	Three months ended March 31,
	2011		2010
	(in thousands)
Total fair value of phantom units vested during the period	$	1,030	$	1,255

20

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Income Taxes

        A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate to (loss) income before provision for income tax for the three months ended March 31, 2011 and 2010 is as follows (in thousands):

		Three months ended March 31, 2011
		Corporation			Partnership			Eliminations			Consolidated
Loss before provision for income tax		$	(19,996	)	$	(67,436	)	$	(1,369	)	$	(88,801	)
Federal statutory rate			35	%		0	%		0	%
Federal income tax at statutory rate		$	(6,999	)	$	—		$	—		$	(6,999	)
Permanent items			(77	)		—			—			(77	)
State income taxes net of federal benefit			(682	)		(343	)		—			(1,025	)
Provision on income from Class A units(1)			(6,029	)		—			—			(6,029	)
	Provision for income tax	$	(13,787	)	$	(343	)	$	—		$	(14,130	)

		Three months ended March 31, 2010
		Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax		$	3,234		$	27,302		$	(106	)	$	30,430
Federal statutory rate			35	%		0	%		0	%
Federal income tax at statutory rate		$	1,132		$	—		$	—		$	1,132
Permanent items			1			—			—			1
State income taxes net of federal benefit			115			155			—			270
Provision on income from Class A units(1)			3,023			—			—			3,023
	Provision for income tax	$	4,271		$	155		$	—		$	4,426

(1)

The Corporation and the General Partner of the Partnership own Class A units of the Partnership that were received in the merger of the Corporation and the Partnership completed in February 2008. For further discussion of Class A units, see Item 1. Business in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2010.

21

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. (Loss) Earnings Per Common Unit

        The following table shows the computation of basic and diluted net (loss) income per common unit for the three months ended March 31, 2011 and 2010, and the weighted-average units used to compute diluted net (loss) income per common unit (in thousands, except per unit data):

		Three months ended March 31,
		2011			2010
Net (loss) income attributable to the Partnership		$	(84,029	)	$	21,510
Less: Income allocable to phantom units			420			277
(Loss) income available for common unitholders		$	(84,449	)	$	21,233
Weighted average common units outstanding—basic			74,531			66,453
Weighted average common units outstanding—diluted(1)			74,531			66,453
Net (loss) income attributable to the Partnership's common unitholders per common unit
	Basic	$	(1.13	)	$	0.32
	Diluted	$	(1.13	)	$	0.32

(1)

Dilutive instruments include TSR Performance Units and are based on the number of units, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period. For the three months ended March 31, 2011, 156 units were excluded from the calculation of diluted units because the impact was anti-dilutive.

15. Segment Information

        The Partnership prepares segment information in accordance with GAAP. Certain items below (Loss) income from operations in the accompanying Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual segments. Management does not consider these items allocable to or controllable by any individual segment and therefore excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests.

22

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

15. Segment Information (Continued)

        The tables below present the Partnership's segment profit measure, Operating income before items not allocated to segments, and capital expenditures for the reported segments for the three months ended March 31, 2011 and 2010 (in thousands).

Three months ended March 31, 2011:			Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue			$	201,774	$	92,091	$	41,219	$	21,759	$	356,843
Purchased product costs				103,196		40,878		9,555		—		153,629
	Net operating margin			98,578		51,213		31,664		21,759		203,214
Facility expenses				20,157		5,594		6,498		8,990		41,239
Portion of operating income attributable to non-controlling interests				1,172		—		12,377		—		13,549
	Operating income before items not allocated to segments		$	77,249	$	45,619	$	12,789	$	12,769	$	148,426
Capital expenditures			$	17,156	$	709	$	94,146	$	294	$	112,305
Capital expenditures not allocated to segments												1,347
		Total capital expenditures									$	113,652

Three months ended March 31, 2010:			Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue			$	164,964	$	111,848	$	19,010	$	19,793	$	315,615
Purchased product costs				74,625		67,087		2,584		—		144,296
	Net operating margin			90,339		44,761		16,426		19,793		171,319
Facility expenses				20,489		4,225		7,313		5,695		37,722
Portion of operating income attributable to non-controlling interests				1,500		—		3,637		—		5,137
	Operating income before items not allocated to segments		$	68,350	$	40,536	$	5,476	$	14,098	$	128,460
Capital expenditures			$	40,133	$	591	$	51,217	$	2,865	$	94,806
Capital expenditures not allocated to segments												516
		Total capital expenditures									$	95,322

23

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

15. Segment Information (Continued)

        The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to (loss) income before provision for income tax for the three months ended March 31, 2011 and 2010 (in thousands).

			Three months ended March 31,
			2011			2010
Total segment revenue			$	356,843		$	315,615
	Derivative loss not allocated to segments			(85,679	)		(7,236	)
	Revenue deferral adjustment(1)			(7,943	)		—
		Total revenue	$	263,221		$	308,379
Operating income before items not allocated to segments			$	148,426		$	128,460
	Portion of operating income attributable to non-controlling interests			13,549			5,137
	Derivative loss not allocated to segments			(102,062	)		(19,819	)
	Revenue deferral adjustment(1)			(7,943	)		—
	Compensation expense included in facility expenses not allocated to segments			(1,040	)		(722	)
	Facility expenses adjustments			2,855			539
	Selling, general and administrative expenses			(21,712	)		(21,508	)
	Depreciation			(34,364	)		(28,187	)
	Amortization of intangible assets			(10,817	)		(10,193	)
	(Loss) gain on disposal of property, plant and equipment			(2,099	)		9
	Accretion of asset retirement obligations			(87	)		(143	)
		(Loss) income from operations		(15,294	)		53,573
	Loss from unconsolidated affiliate			(539	)		(68	)
	Interest income			89			386
	Interest expense			(28,263	)		(23,782	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(1,428	)		(2,612	)
	Derivative gain related to interest expense			—			1,871
	Loss on redemption of debt			(43,328	)		—
	Miscellaneous (expense) income, net			(38	)		1,062
		(Loss) income before provision for income tax	$	(88,801	)	$	30,430

(1)

Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue must be recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the

24

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

15. Segment Information (Continued)

impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended March 31, 2011, approximately $6.5 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

        The tables below present information about segment assets as of March 31, 2011 and December 31, 2010 (in thousands):

		March 31, 2011		December 31, 2010
Southwest		$	1,658,012	$	1,646,607
Northeast			456,441		244,219
Liberty			790,441		743,943
Gulf Coast			571,576		573,456
Total segment assets			3,476,470		3,208,225
Assets not allocated to segments:
	Certain cash and cash equivalents		60,220		49,776
	Fair value of derivatives		9,175		4,762
	Investment in unconsolidated affiliate		28,149		28,688
	Other(1)		43,372		41,911
Total assets		$	3,617,386	$	3,333,362

(1)

Includes corporate fixed assets, deferred financing costs, income tax receivable, receivables and other corporate assets not allocated to segments.

25

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Supplemental Condensed Consolidating Financial Information

        The Partnership has no significant operations independent of its subsidiaries. As of March 31, 2011, the Partnership's obligations under the outstanding Senior Notes (see Note 9) were fully and unconditionally guaranteed, jointly and severally, by all of its wholly-owned subsidiaries. MarkWest Liberty Midstream and MarkWest Pioneer, together with certain of the Partnership's other subsidiaries that do not guarantee the outstanding Senior Notes, have significant assets and operations in aggregate. For the purpose of the following financial information, the Partnership's investments in its subsidiaries and the guarantor subsidiaries' investments in their subsidiaries are presented in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. The operations, cash flows and financial position of the co-issuer of the Senior Notes, MarkWest Energy Finance Corporation, are minor and therefore have been included with the Parent's financial information. Condensed consolidating financial information for the Partnership, its combined guarantor

26

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Supplemental Condensed Consolidating Financial Information (Continued)

and combined non-guarantor subsidiaries as of March 31, 2011 and December 31, 2010 and for the three months ended March 31, 2011 and 2010 is as follows (in thousands):

Condensed Consolidating Balance Sheets

			As of March 31, 2011
			Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
	Cash and cash equivalents		$	10	$	63,314	$	9,828	$	—		$	73,152
	Receivables and other current assets			1,849		187,087		19,472		—			208,408
	Intercompany receivables			1,662,651		1,283		8,866		(1,672,800	)		—
	Fair value of derivative instruments			—		6,138		—		—			6,138
		Total current assets		1,664,510		257,822		38,166		(1,672,800	)		287,698
Total property, plant and equipment, net				4,272		1,647,446		883,482		(12,848	)		2,522,352
Other long-term assets:
	Restricted cash			—		—		28,052		—			28,052
	Investment in unconsolidated affiliate			—		28,149		—		—			28,149
	Investment in consolidated affiliates			717,586		406,842		—		(1,124,428	)		—
	Intangibles, net of accumulated amortization			—		635,999		569		—			636,568
	Fair value of derivative instruments			—		3,037		—		—			3,037
	Intercompany notes receivable			185,660		—		—		(185,660	)		—
	Deferred income taxes			—		5,425		—		—			5,425
	Other long-term assets			34,836		70,891		378		—			106,105
		Total assets	$	2,606,864	$	3,055,611	$	950,647	$	(2,995,736	)	$	3,617,386
LIABILITIES AND EQUITY
Current liabilities:
	Intercompany payables		$	671	$	1,671,337	$	792	$	(1,672,800	)	$	—
	Fair value of derivative instruments			—		102,810		—		—			102,810
	Other current liabilities			36,751		168,426		59,518		—			264,695
		Total current liabilities		37,422		1,942,573		60,310		(1,672,800	)		367,505
Deferred income taxes				1,666		—		—		—			1,666
Intercompany notes payable				—		171,660		14,000		(185,660	)		—
Fair value of derivative instruments				—		114,211		—		—			114,211
Long-term debt, net of discounts				1,474,757		—		—		—			1,474,757
Other long-term liabilities				3,398		109,581		188		—			113,167
Equity:
	MarkWest Energy Partners, L.P. partners' capital			1,089,621		717,586		876,149		(1,606,583	)		1,076,773
	Non-controlling interest in consolidated subsidiaries			—		—		—		469,307			469,307
		Total equity		1,089,621		717,586		876,149		(1,137,276	)		1,546,080
		Total liabilities and equity	$	2,606,864	$	3,055,611	$	950,647	$	(2,995,736	)	$	3,617,386

27

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Supplemental Condensed Consolidating Financial Information (Continued)

			As of December 31, 2010
			Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
	Cash and cash equivalents		$	—	$	63,850	$	3,600	$	—		$	67,450
	Receivables and other current assets			1,708		172,209		52,834		—			226,751
	Intercompany receivables			1,440,302		1,099		7,635		(1,449,036	)		—
	Fair value of derivative instruments			—		4,345		—		—			4,345
		Total current assets		1,442,010		241,503		64,069		(1,449,036	)		298,546
Total property, plant and equipment, net				4,623		1,512,763		812,898		(11,260	)		2,319,024
Other long-term assets:
	Restricted cash			—		—		28,001		—			28,001
	Investment in unconsolidated affiliate			—		28,688		—		—			28,688
	Investment in consolidated affiliates			716,673		368,864		—		(1,085,537	)		—
	Intangibles, net of accumulated amortization			—		613,000		578		—			613,578
	Fair value of derivative instruments			—		417		—		—			417
	Intercompany notes receivable			197,710		—		—		(197,710	)		—
	Other long-term assets			32,587		12,139		382		—			45,108
		Total assets	$	2,393,603	$	2,777,374	$	905,928	$	(2,743,543	)	$	3,333,362
LIABILITIES AND EQUITY
Current liabilities:
	Intercompany payables		$	672	$	1,447,799	$	565	$	(1,449,036	)	$	—
	Fair value of derivative instruments			—		65,489		—		—			65,489
	Other current liabilities			31,882		173,667		70,804		—			276,353
		Total current liabilities		32,554		1,686,955		71,369		(1,449,036	)		341,842
Deferred income taxes				2,533		7,894		—		—			10,427
Intercompany notes payable				—		197,710		—		(197,710	)		—
Fair value of derivative instruments				—		66,290		—		—			66,290
Long-term debt, net of discounts				1,273,434		—		—		—			1,273,434
Other long-term liabilities				3,319		101,852		178		—			105,349
Equity:
	MarkWest Energy Partners, L.P. partners' capital			1,081,763		716,673		834,381		(1,562,314	)		1,070,503
	Non-controlling interest in consolidated subsidiaries			—		—		—		465,517			465,517
		Total equity		1,081,763		716,673		834,381		(1,096,797	)		1,536,020
		Total liabilities and equity	$	2,393,603	$	2,777,374	$	905,928	$	(2,743,543	)	$	3,333,362

28

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Operations

			Three Months Ended March 31, 2011
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue			$	—		$	218,480		$	44,741		$	—		$	263,221
Operating expenses:
	Purchased product costs			—			163,444			9,579			—			173,023
	Facility expenses			—			28,931			7,649			(167	)		36,413
	Selling, general and administrative expenses			12,854			8,218			2,037			(1,397	)		21,712
	Depreciation and amortization			175			36,469			8,685			(148	)		45,181
	Other operating expenses			299			1,839			48			—			2,186
		Total operating expenses		13,328			238,901			27,998			(1,712	)		278,515
		(Loss) income from operations		(13,328	)		(20,421	)		16,743			1,712			(15,294	)
(Loss) earnings from consolidated affiliates				(1,233	)		7,375			—			(6,142	)		—
Loss on redemption of debt				(43,328	)		—			—			—			(43,328	)
Other expense, net				(24,894	)		(1,975	)		(10	)		(3,300	)		(30,179	)
		(Loss) income before provision for income tax		(82,783	)		(15,021	)		16,733			(7,730	)		(88,801	)
Provision for income tax benefit				(342	)		(13,788	)		—			—			(14,130	)
		Net (loss) income		(82,441	)		(1,233	)		16,733			(7,730	)		(74,671	)
Net income attributable to non-controlling interest				—			—			—			(9,358	)		(9,358	)
		Net (loss) income attributable to the Partnership	$	(82,441	)	$	(1,233	)	$	16,733		$	(17,088	)	$	(84,029	)

29

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Supplemental Condensed Consolidating Financial Information (Continued)

			Three Months Ended March 31, 2010
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Total revenue			$	—		$	285,144		$	23,235	$	—		$	308,379
Operating expenses:
	Purchased product costs			—			155,073			2,612		—			157,685
	Facility expenses			—			28,793			8,469		(163	)		37,099
	Selling, general and administrative expenses			11,781			9,635			1,310		(1,218	)		21,508
	Depreciation and amortization			147			32,710			5,597		(74	)		38,380
	Other operating expenses			—			(155	)		289		—			134
		Total operating expenses		11,928			226,056			18,277		(1,455	)		254,806
		(Loss) income from operations		(11,928	)		59,088			4,958		1,455			53,573
Earnings from consolidated affiliates				53,853			829			—		(54,682	)		—
Other (expense) income, net				(19,551	)		(1,793	)		365		(2,164	)		(23,143	)
		Income before provision for income tax		22,374			58,124			5,323		(55,391	)		30,430
Provision for income tax expense				155			4,271			—		—			4,426
		Net income		22,219			53,853			5,323		(55,391	)		26,004
Net income attributable to non-controlling interest				—			—			—		(4,494	)		(4,494	)
		Net income attributable to the Partnership	$	22,219		$	53,853		$	5,323	$	(59,885	)	$	21,510

30

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Cash Flows

			Three Months Ended March 31, 2011
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities			$	(25,444	)	$	83,297		$	59,203		$	(1,737	)	$	115,319
Cash flows from investing activities:
	Capital expenditures			(125	)		(20,629	)		(95,964	)		3,066			(113,652	)
	Acqusitions			—			(230,728	)		—			—			(230,728	)
	Equity investments			(11,496	)		(41,360	)		—			52,856			—
	Distributions from consolidated affiliates			10,446			10,757			—			(21,203	)		—
	Collection of (investment in) intercompany notes, net			12,050			(14,000	)		—			1,950			—
	Proceeds from disposal of property, plant and equipment			—			134			3,954			(1,329	)		2,759
		Net cash provided by (used in) investing activities		10,875			(295,826	)		(92,010	)		35,340			(341,621	)
Cash flows from financing activities:
	Proceeds from revolving credit facility			307,600			—			—			—			307,600
	Payments of revolving credit facility			(168,400	)		—			—			—			(168,400	)
	Proceeds from long-term debt			499,000			—			—			—			499,000
	Payments of long-term debt			(437,848	)		—			—			—			(437,848	)
	Payments of premiums on redemption of long-term debt			(39,520	)		—			—			—			(39,520	)
	(Payments of) proceeds from intercompany notes, net			—			(12,050	)		14,000			(1,950	)		—
	Payments for debt issuance costs, deferred financing costs and registration costs			(6,524	)		—			—			—			(6,524	)
	Contributions from parent, net			—			11,496			—			(11,496	)		—
	Contributions to joint ventures, net			—			—			49,360			(41,360	)		8,000
	Payments of SMR liability			—			(452	)		—			—			(452	)
	Proceeds from public equity offering, net			138,163			—			—			—			138,163
	Share-based payment activity			(6,269	)		1,096			—			—			(5,173	)
	Payment of distributions			(49,274	)		(10,446	)		(24,325	)		21,203			(62,842	)
	Intercompany advances, net			(222,349	)		222,349			—			—			—
		Net cash provided by financing activities		14,579			211,993			39,035			(33,603	)		232,004
Net increase (decrease) in cash				10			(536	)		6,228			—			5,702
Cash and cash equivalents at beginning of year				—			63,850			3,600			—			67,450
Cash and cash equivalents at end of period			$	10		$	63,314		$	9,828		$	—		$	73,152

31

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

16. Supplemental Condensed Consolidating Financial Information (Continued)

			Three Months Ended March 31, 2010
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities			$	(9,729	)	$	112,836		$	12,036		$	(783	)	$	114,360
Cash flows from investing activities:
	Capital expenditures			(53	)		(42,925	)		(53,127	)		783			(95,322	)
	Equity investments			(10,101	)		(34,543	)		—			44,644			—
	Distributions from consolidated affiliates			12,710			1,270			—			(13,980	)		—
	Collection of intercompany notes, net			21,150			—			—			(21,150	)		—
	Proceeds from disposal of property, plant and equipment			—			292			—			—			292
		Net cash provided by (used in) investing activities		23,706			(75,906	)		(53,127	)		10,297			(95,030	)
Cash flows from financing activities:
	Proceeds from revolving credit facility			135,604			—			—			—			135,604
	Payments of revolving credit facility			(141,904	)		—			—			—			(141,904	)
	Payments of intercompany notes, net			—			(21,150	)		—			21,150			—
	Contributions from parent, net			—			10,101			—			(10,101	)		—
	Contributions to joint ventures, net			—			—			76,763			(34,543	)		42,220
	Payments of SMR liability			—			(58	)		—			—			(58	)
	Share-based payment activity			(3,730	)		97			—			—			(3,633	)
	Payment of distributions			(42,866	)		(12,710	)		(2,540	)		13,980			(44,136	)
	Intercompany advances, net			38,919			(38,919	)		—			—			—
		Net cash (used in) provided by financing activities		(13,977	)		(62,639	)		74,223			(9,514	)		(11,907	)
Net (decrease) increase in cash				—			(25,709	)		33,132			—			7,423
Cash and cash equivalents at beginning of year				—			74,448			23,304			—			97,752
Cash and cash equivalents at end of period			$	—		$	48,739		$	56,436		$	—		$	105,175

32

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

17. Supplemental Cash Flow Information

        The following table provides information regarding supplemental cash flow information (in thousands).

	Three months ended March 31,
	2011		2010
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	22,729	$	12,244
Cash paid for income taxes, net of refunds		34		28
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	58,218	$	59,861
Interest capitalized on construction in progress		19		2,557
Issuance of common units for vesting of share-based payment awards		5,282		7,030

33

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

Forward-Looking Statements

        Management's Discussion and Analysis ("MD&A") contains statements that are forward-looking and should be read in conjunction with our condensed consolidated financial statements and accompanying notes included elsewhere in this report and our Annual Report on Form 10-K for the year ended December 31, 2010. Statements that are not historical facts are forward-looking statements. We use words such as "could," "may," "predict," "should," "expect," "hope," "continue," "potential," "plan," "intend," "anticipate," "project," "believe," "estimate," and similar expressions to identify forward-looking statements. These statements are based on current expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. Forward-looking statements are not guarantees and actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors. We do not update publicly any forward-looking statement with new information or future events. Undue reliance should not be placed on forward-looking statements as many of these factors are beyond our ability to control or predict.

Overview

        We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. We have 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 are the largest natural gas processor and fractionator in the Appalachian region.

Significant Financial and Other Highlights

        Significant financial and other highlights for the three months ended March 31, 2011 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

•

Total segment operating income before items not allocated to segments increased approximately $20.0 million, or 16%, for the three months ended March 31, 2011 compared to the same period in 2010. The increase is due primarily to higher commodity prices in 2011, expanding operations in our Liberty and Northeast segments and increased volumes from a large producer in our Southwest segment. The increase was partially offset by a $3.7 million increase in cash paid for the settlement of commodity derivative positions.

•

In January 2011, we received net proceeds of approximately $138.2 million from a public offering of approximately 3.45 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option.

•

In February 2011, we completed the Langley Acquisition whereby we acquired gas processing facilities located near Langley, Kentucky, a partially constructed NGL pipeline extending through parts of Kentucky and West Virginia, and certain other related assets, for a cash purchase price of approximately $230.7 million (see Note 3 of the accompanying Notes to the Condensed Consolidated Financial Statements).

•

In February 2011, we completed a public offering of $300.0 million in aggregate principal amount of 2021 Senior Notes. In March 2011, we completed a follow-on offering of an additional $200.0 million in aggregate principal amount of 2021 Senior Notes. We received combined net proceeds of approximately $492 million from the 2021 Senior Notes offerings, which we used primarily to redeem approximately $272.2 million in aggregate principal amount of 8.5% senior notes due 2016 and approximately $165.6 million in aggregate principal amount of 8.75% senior notes due 2018. We recorded a loss on redemption of debt of approximately

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$43.3 million (see Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements).

Net Operating Margin (a non-GAAP financial measure)

        Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure) which is defined as segment revenue, excluding any derivative gain (loss) and adjusted for the non-cash impact of revenue deferrals related to certain agreements, less purchased product costs, excluding any derivative gain (loss). These adjustments have been made for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and therefore is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Our use of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

        The following is a reconciliation to (Loss) income from operations, the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

		Three months ended March 31,
		2011			2010
Segment revenue		$	356,843		$	315,615
Purchased product costs			153,629			144,296
	Net operating margin		203,214			171,319
Facility expenses			39,424			37,905
Derivative loss			102,062			19,819
Revenue deferral adjustment			7,943			—
Selling, general and administrative expenses			21,712			21,508
Depreciation			34,364			28,187
Amortization of intangible assets			10,817			10,193
Loss (gain) on disposal of property, plant and equipment			2,099			(9	)
Accretion of asset retirement obligations			87			143
	(Loss) income from operations	$	(15,294	)	$	53,573

Our Contracts

        We generate the majority of our revenue and net operating margin (a non-GAAP measure, see above for discussion and reconciliation of net operating margin) from natural gas gathering, transportation and processing; NGL transportation, fractionation, marketing and storage; and crude oil gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the following types of arrangements: fee-based, percent-of-proceeds, percent-of-index and keep-whole. See Item 1. Business—Our Contracts in our Annual Report on Form 10-K for the year ended December 31, 2010 for further discussion of each of these types of arrangements.

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        The following table does not give effect to our active commodity risk management program. For the three months ended March 31, 2011, we calculated the following approximate percentages of our segment revenue and net operating margin from the following types of contracts:

	Fee-Based			Percent-of-Proceeds(1)			Percent-of-Index(2)			Keep-Whole(3)			Total
Segment revenue		21	%		34	%		4	%		41	%		100	%
Net operating margin(4)		36	%		27	%		0	%		37	%		100	%

(1)

Includes condensate sales and other types of arrangements tied to NGL prices.

(2)

Includes arrangements tied to natural gas prices.

(3)

Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices.

(4)

We manage our business by taking into account the partial offset of short natural gas positions by long positions primarily in our Southwest segment. The calculated percentages for the net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial offset of our natural gas positions.

Seasonality

        Our business is affected by seasonal fluctuations in commodity prices. Sales volumes also are affected by various other factors such as fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast segment is particularly impacted by seasonality. In our Northeast segment operations, we store a portion of the propane that is produced in the summer to be sold in the winter months. As a result of our seasonality, we generally expect the sales volumes in our Northeast segment to be higher in the first quarter and fourth quarter. These seasonal factors also impact our Liberty segment; however, we anticipate that the expected growth and expansion in our Liberty segment in 2011 will offset this seasonality impact.

Results of Operations

Segment Reporting

        We classify our business in four reportable segments: Southwest, Northeast, Liberty and Gulf Coast. We present information in this MD&A by segment. The segment information appearing in Note 15 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal management reporting.

Southwest

•

East Texas.  We own a system that consists of natural gas gathering pipelines, centralized compressor stations, a natural gas processing facility and an NGL pipeline. The East Texas system is located in Panola, Harrison and Rusk Counties and services the Carthage Field. Producing formations in Panola County consist of the Cotton Valley, Pettit, Travis Peak and Haynesville formations. For natural gas that is processed in this area, we purchase the NGLs from the producers under percent-of-proceeds arrangements, or we transport and process volumes for a fee.

•

Oklahoma.  We own a natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. Natural gas gathered in the Woodford system is processed by Centrahoma Processing LLC ("Centrahoma"), our equity investment discussed in Equity Investment in Unconsolidated Affiliate below. In addition, we own the Foss Lake natural gas

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gathering system and the Arapaho I and II natural gas processing plants, all located in Roger Mills, Custer and Ellis Counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities. The majority of the gathered gas ultimately is compressed and delivered to the processing plants. We also own the Grimes gathering system that is located in Roger Mills and Beckham Counties in western Oklahoma and a gathering system in the Granite Wash formation in the Texas panhandle that is connected to our Arapaho processing plants. We plan to complete the Arapaho III natural gas processing plant in the third quarter of 2011, which will increase our processing capacity at the Arapaho complex by 75 MMcf/d to a total of 235 MMcf/d. The gathering and processing expansions are supported by long-term agreements with producer customers.

Through our joint venture MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with the Midcontinent Express Pipeline and Gulf Crossing Pipeline at Bennington, Oklahoma and is designed to provide approximately 638,000 Dth/d of Woodford Shale takeaway capacity.

•

Other Southwest.  We own a number of natural gas gathering systems located in Texas, Louisiana, Mississippi and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. We gather a significant portion of the natural gas produced from fields adjacent to our gathering systems, including from wells targeting the Haynesville Shale. In many areas we are the primary gatherer, and in some of the areas served by our smaller systems we are the sole gatherer. In addition, we own four lateral pipelines in Texas and New Mexico. Our Hobbs, New Mexico natural gas pipeline is subject to regulation by FERC.

Northeast

•

Appalachia.  We are the largest processor and fractionator of natural gas in the Appalachian Basin, with fully integrated processing, fractionation, storage and marketing operations. The Appalachian Basin is a large natural gas producing region characterized by long-lived reserves and modest decline rates. Our Appalachian assets include the Kenova, Boldman, Cobb, Kermit and the recently acquired Langley natural gas processing plants, an NGL pipeline and the Siloam NGL fractionation plant. In connection with the Langley Acquisition, we will complete the construction of the Ranger Pipeline to connect the Langley Processing Facilities to our existing NGL pipeline that transports NGLs to our Siloam fractionation facility. We will also install an additional cryogenic natural gas processing plant with a capacity of at least 60 MMcf/d in 2012. In addition, we have two caverns for storing propane and additional propane storage capacity under a long-term firm-capacity agreement with a third party. The Appalachia operations include fractionation and marketing services on behalf of the Liberty segment.

•

Michigan.  We own and operate a FERC-regulated crude oil pipeline in Michigan providing transportation service for three shippers.

Liberty

•

Marcellus Shale.  We operate natural gas gathering systems and processing facilities located primarily in southwestern Pennsylvania and northern West Virginia through MarkWest Liberty Midstream. We are the largest processor of natural gas in the Marcellus Shale, with fully integrated processing, fractionation, storage and marketing operations that are critical to the liquids-rich gas development in the northeast United States. We currently have 355 MMcf/d of cryogenic processing capacity at our Houston, Pennsylvania processing complex, which includes a 200 MMcf/d cryogenic plant that began operations in the second quarter of 2011. We commenced operation of a 135 MMcf/d cryogenic plant at our Majorsville site in the third

37

quarter of 2010 and we expect to increase the cryogenic processing capacity at our Majorsville site to approximately 270 MMcf/d by the third quarter of 2011. We will also construct a 120 MMcf/d cryogenic processing plant in Mobley, West Virginia. The planned and existing capacity discussed above is supported by long-term agreements with our producer customers. We also plan to construct a 200 MMcf/d cryogenic processing plant in northern West Virginia that is also supported by a long-term agreement, the terms of which are subject to confidentiality obligations. Each of the processing plants in the Liberty segment will be connected to the Houston fractionation facilities through new and existing NGL pipelines. In addition, we will also construct an extension of our Majorsville NGL pipeline to receive NGLs produced at a third-party's Fort Beeler processing plant. This will allow certain producers to benefit from our integrated NGL fractionation and marketing system.

We also plan to complete a 60,000 Bbl/d fractionation facility at our Houston complex in 2011. Propane is currently recovered at our Houston processing complex. Further fractionation of the remaining portion of the NGL stream produced at the Liberty processing plants will continue to be performed at the Siloam NGL fractionation plant in our Northeast segment until we have completed construction of our Houston fractionation facility. We also have an interconnect with a key interstate pipeline providing an additional market outlet for the propane produced from this region.

By the end of 2012, MarkWest Liberty Midstream is expected to operate 945 MMcf/d of cryogenic processing capacity serving Marcellus liquids-rich gas producers in southwestern Pennsylvania and northern West Virginia from its Houston, Majorsville, and recently announced Mobley processing complexes.

We are jointly developing two projects with Sunoco Logistics, L.P. ("Sunoco") to provide Marcellus producers with access to multiple ethane markets to serve the growing liquids-rich gas production in the Marcellus. For both projects, Project Mariner and Mariner West, MarkWest Liberty Midstream will make minor modifications to its natural gas processing complexes, will install ethane extraction facilities at its Houston complex, and will construct pipelines from the Houston complex to interconnections with existing Sunoco pipelines. Project Mariner is a pipeline and marine project to deliver purity ethane produced in the Marcellus to Gulf Coast and international markets. Project Mariner is anticipated to have initial capacity to transport up to 50,000 Bbl/d of ethane by mid-2013. Mariner West, which was announced during the first quarter of 2011, is a joint pipeline project to deliver Marcellus ethane to Sarnia, Ontario, Canada markets. Mariner West, which is being developed at the request of Marcellus producer customers and is supported by Sarnia ethane consumers, will utilize new and existing pipelines and is anticipated to have a maximum capacity to transport up to 65,000 Bbl/d of ethane by the third quarter of 2012.

Gulf Coast

•

Javelina.  We own and operate the Javelina processing facility, a natural gas processing facility in Corpus Christi, Texas that treats and processes off-gas from six local refineries operated by three different refinery customers. We have a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the product processed by the SMR that is operated by a third party. The product received under this agreement will be sold to a refinery customer pursuant to a corresponding long-term agreement.

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        The following summarizes the percentage of our segment revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by segment, for the three months ended March 31, 2011:

	Southwest			Northeast			Liberty			Gulf Coast			Total
Segment revenue		56	%		26	%		12	%		6	%		100	%
Net operating margin		48	%		25	%		16	%		11	%		100	%

Equity Investment in Unconsolidated Affiliate

        We own a 40% non-operating membership interest in Centrahoma, a joint venture with Cardinal Midstream, LLC that is accounted for using the equity method. Centrahoma owns certain processing plants in the Arkoma Basin. We have signed long-term agreements to dedicate the processing rights for our natural gas gathering system in the Woodford Shale to Centrahoma. The financial results for Centrahoma are included in Loss from unconsolidated affiliate and are not included in our segment results.

Three months ended March 31, 2011 compared to three months ended March 31, 2010

        Items below (Loss) income from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual business segments. Management does not consider these items allocable to or controllable by any individual business segment and therefore excludes these items when evaluating segment performance. The segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests. The tables below present financial information, as evaluated by management, for the reported segments for the three months ended March 31, 2011 and 2010. The information includes net operating margin, a non-GAAP financial measure. See above for a reconciliation of net operating margin to (Loss) income from operations, the most comparable GAAP financial measure.

Southwest

		Three months ended March 31,
		2011		2010		$ Change			% Change
		(in thousands)
Segment revenue		$	201,774	$	164,964	$	36,810			22	%
Purchased product costs			103,196		74,625		28,571			38	%
	Net operating margin		98,578		90,339		8,239			9	%
Facility expenses			20,157		20,489		(332	)		(2	)%
Portion of operating income attributable to non-controlling interests			1,172		1,500		(328	)		(22	)%
Operating income before items not allocated to segments		$	77,249	$	68,350	$	8,899			13	%

        Segment Revenue.    Revenue increased primarily due to higher commodity prices and an increase in NGL production volumes in Western Oklahoma and our Woodford system. Revenue from NGL, natural gas and condensate sales increased approximately $35.7 million across the segment.

        Purchased Product Costs.    Purchased product costs increased primarily due to higher commodity prices and increased volumes in Western Oklahoma and our Woodford system.

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        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests primarily represents our partners' share in net operating income of MarkWest Pioneer.

Northeast

		Three months ended March 31,
		2011		2010		$ Change			% Change
		(in thousands)
Segment revenue		$	92,091	$	111,848	$	(19,757	)		(18	)%
Purchased product costs			40,878		67,087		(26,209	)		(39	)%
	Net operating margin		51,213		44,761		6,452			14	%
Facility expenses			5,594		4,225		1,369			32	%
Operating income before items not allocated to segments		$	45,619	$	40,536	$	5,083			13	%

        Segment Revenue.    Revenue decreased primarily due to a contract change related to the Langley Acquisition. Subsequent to the Langley Acquisition, we are acting as an agent and marketing the NGLs on behalf of our producer customer. Revenue also decreased due to a decrease in volumes processed under keep-whole terms primarily due to the required repairs of a significant transmission pipeline feeding our Kenova plant. The transmission pipeline is scheduled to be repaired in mid-2011 after which we expect volumes to return to normal levels.

        Purchased Product Costs.    Purchased product costs decreased due to the contract change related to the Langley Acquisition discussed in the Segment Revenue section above. In addition, purchased product costs decreased as a percentage of revenue due to an increase in the spread between NGL and natural gas prices.

        Facility Expenses.    Facility expenses increased primarily due to the Langley Acquisition on February 1, 2011 and increased labor and benefits expense.

Liberty

		Three months ended March 31,
		2011		2010		$ Change			% Change
		(in thousands)
Segment revenue		$	41,219	$	19,010	$	22,209			117	%
Purchased product costs			9,555		2,584		6,971			270	%
	Net operating margin		31,664		16,426		15,238			93	%
Facility expenses			6,498		7,313		(815	)		(11	)%
Portion of operating income attributable to non-controlling interests			12,377		3,637		8,740			240	%
Operating income before items not allocated to segments		$	12,789	$	5,476	$	7,313			134	%

        Segment revenue.    Revenue increased due to ongoing expansion of the Liberty operations and higher NGL prices. Revenue increased approximately $11.0 million related to gathering and processing fees and approximately $11.2 million related to NGL product sales.

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        Purchased Product Costs.    Purchased product costs increased primarily due to the purchase of product from certain producers, which began in the second half of 2010. Purchased product costs also increased due to higher prices.

        Facility Expenses.    Facility expenses decreased primarily due to environmental and remediation costs incurred in 2010, which did not recur in 2011, and a reduction in compressor rental expense as compressors were purchased in the second half of 2010. These decreases were partially offset by the ongoing expansion of the Liberty operations.

        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests represents M&R's interest in net operating income of MarkWest Liberty Midstream. The increase is the result of ongoing expansion of the Liberty operations, as well as M&R's interest increasing from 40% to 49% effective January 1, 2011.

Gulf Coast

		Three months ended March 31,
		2011		2010		$ Change			% Change
		(in thousands)
Segment revenue		$	21,759	$	19,793	$	1,966			10	%
Purchased product costs			—		—		—			N/A
	Net operating margin		21,759		19,793		1,966			10	%
	Facility expenses		8,990		5,695		3,295			58	%
Operating income before items not allocated to segments		$	12,769	$	14,098	$	(1,329	)		(9	)%

        Segment revenue.    Revenue increased primarily due to the operation of the SMR, which was partially offset by a decrease in volumes.

        Facility Expenses.    Facility expenses increased primarily due to the operating expenses of the SMR, which was partially offset by a decrease in repairs and maintenance and utilities expense.

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Reconciliation of Segment Operating Income to Consolidated (Loss) Income Before Provision for Income Tax

        The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated (loss) income before provision for income tax for the three months ended March 31, 2011 and 2010. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

			Three months ended March 31,
			2011			2010			$ Change			% Change
			(in thousands)
Total segment revenue			$	356,843		$	315,615		$	41,228			13	%
	Derivative loss not allocated to segments			(85,679	)		(7,236	)		(78,443	)		1,084	%
	Revenue deferral adjustment			(7,943	)		—			(7,943	)		N/A
		Total revenue	$	263,221		$	308,379		$	(45,158	)		(15	)%
Operating income before items not allocated to segments			$	148,426		$	128,460		$	19,966			16	%
	Portion of operating income attributable to non-controlling interests			13,549			5,137			8,412			164	%
	Derivative loss not allocated to segments			(102,062	)		(19,819	)		(82,243	)		415	%
	Revenue deferral adjustment			(7,943	)		—			(7,943	)		N/A
	Compensation expense included in facility expenses not allocated to segments			(1,040	)		(722	)		(318	)		44	%
	Facility expenses adjustments			2,855			539			2,316			430	%
	Selling, general and administrative expenses			(21,712	)		(21,508	)		(204	)		1	%
	Depreciation			(34,364	)		(28,187	)		(6,177	)		22	%
	Amortization of intangible assets			(10,817	)		(10,193	)		(624	)		6	%
	(Loss) gain on disposal of property, plant and equipment			(2,099	)		9			(2,108	)		(23,422	)%
	Accretion of asset retirement obligations			(87	)		(143	)		56			(39	)%
		(Loss) income from operations		(15,294	)		53,573			(68,867	)		(129	)%
	Loss from unconsolidated affiliate			(539	)		(68	)		(471	)		693	%
	Interest income			89			386			(297	)		(77	)%
	Interest expense			(28,263	)		(23,782	)		(4,481	)		19	%
	Amortization of deferred financing costs and discount (a component of interest expense)			(1,428	)		(2,612	)		1,184			(45	)%
	Derivative gain related to interest expense			—			1,871			(1,871	)		(100	)%
	Loss on redemption of debt			(43,328	)		—			(43,328	)		N/A
	Miscellaneous (expense) income, net			(38	)		1,062			(1,100	)		(104	)%
		(Loss) income before provision for income tax	$	(88,801	)	$	30,430		$	(119,231	)		(392	)%

        Derivative Loss Not Allocated to Segments.    Unrealized loss from the mark-to-market of our derivative instruments was $79.8 million in 2011 compared to $1.3 million in 2010. Realized loss from the settlement of our derivative instruments was $22.3 million in 2011 compared to $18.6 million in 2010. The total change of $82.2 million is due mainly to volatility in commodity prices.

        Revenue Deferral Adjustment.    Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue must be recognized evenly

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over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended March 31, 2011, approximately $6.5 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

        Facility Expenses Adjustments.    Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR, which is included in facility expenses for the purposes of evaluating the performance of the Gulf Coast segment.

        Depreciation.    Depreciation increased due to additional projects completed during 2010 and the first quarter of 2011, as well as the Langley Acquisition.

        Interest Expense.    Interest expense increased primarily due to additional borrowings in 2010 and 2011 to fund our capital plan, including a net increase in our borrowings resulting from our Senior Notes offerings and related redemptions. Interest expense also increased approximately $1.9 million related to the SMR.

        Amortization of Deferred Financing Costs and Discount.    Amortization of deferred financing costs and discount decreased primarily due to the write off of the unamortized discount associated with our 2014 Senior Notes, which were redeemed in the fourth quarter of 2010.

        Derivative Gain Related to Interest Expense.    Derivative gain related to interest expense decreased due to the settlement of all the outstanding interest rate swaps in January 2010.

        Loss on Redemption of Debt.    Loss on redemption of debt relates to the redemption of $272.2 million of our 2016 Senior Notes and $165.6 million of our 2018 Senior Notes in the first quarter of 2011. Approximately $3.8 million relates to the non-cash write off of the unamortized discount and deferred finance costs and approximately $39.5 million relates to the payment of the related tender premiums and third-party expenses. See Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements.

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Operating Data

			Three months ended March 31,
			2011		2010		% Change
Southwest
	East Texas
		Gathering systems throughput (Mcf/d)		425,800		429,000		(1	)%
		NGL product sales (gallons)		56,681,300		64,195,800		(12	)%
	Oklahoma
		Foss Lake gathering system throughput (Mcf/d)		67,800		76,000		(11	)%
		Stiles Ranch gathering system throughput (Mcf/d)		132,600		115,800		15	%
		Grimes gathering system throughput (Mcf/d)		7,000		7,900		(11	)%
		Arapaho NGL product sales (gallons)		39,020,100		29,443,300		33	%
		Southeast Oklahoma gathering system throughput (Mcf/d)		498,000		496,600		0	%
		Arkoma Connector Pipeline throughput (Mcf/d)		285,900		357,800		(20	)%
	Other Southwest
		Appleby gathering system throughput (Mcf/d)		26,400		34,600		(24	)%
		Other gathering systems throughput (Mcf/d)(1)		6,700		9,000		(26	)%
Northeast
	Appalachia
		Natural gas processed (Mcf/d)(2)		304,800		193,000		58	%
		Keep-whole sales (gallons)		39,835,800		45,772,400		(13	)%
		Percent-of-proceeds sales (gallons)		30,895,500		27,005,000		14	%
		Total NGL product sales (gallons)(3)		70,731,300		72,777,400		(3	)%
	Michigan
		Crude oil transported for a fee (Bbl/d)		10,200		12,900		(21	)%
Liberty
	Marcellus Shale
		Natural gas processed (Mcf/d)		254,500		93,800		171	%
		Gathering system throughput (Mcf/d)		195,900		100,900		94	%
		NGL product sales (gallons)		51,761,600		21,530,200		140	%
Gulf Coast
		Refinery off-gas processed (Mcf/d)		102,800		113,300		(9	)%
		Liquids fractionated (Bbl/d)		19,200		22,500		(15	)%

(1)

Excludes lateral pipelines where revenue is not based on throughput.

(2)

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.

(3)

Represents sales at the Siloam fractionator. The total sales exclude 20,654,100 gallons and 10,657,200 gallons sold by the Northeast on behalf of Liberty for the three months ended March 31, 2011 and 2010, respectively.

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Liquidity and Capital Resources

        Our primary strategy is to expand our asset base through organic growth projects and selective third-party acquisitions that are accretive to our cash available for distribution per common unit. In 2010, we spent approximately $458.7 million on organic expansion opportunities, of which a portion was funded by our MarkWest Liberty Midstream joint venture partner.

        Our 2011 capital plan is summarized in the table below (in millions):

		Range
		Low			High
Consolidated growth capital		$	600		$	670
Liberty joint venture partner's estimated share of growth capital			(180	)		(200	)
	Partnership share of growth capital		420			470
Langley Acquisition			230			230
	Partnership share of growth capital and acquisitions	$	650		$	700
Consolidated maintenance capital		$	10		$	20

        As of March 31, 2011 we have spent approximately $113.7 million of consolidated capital, which includes approximately $35.2 million funded by our Liberty joint venture partner through its current period contributions, remaining balances from prior period contributions, and its share of the cash generated from MarkWest Liberty Midstream's operations. We have also spent $230.7 million for the Langley Acquisition.

        Growth capital includes expenditures made to expand the existing operating capacity, to increase the efficiency of our existing assets, and to facilitate an increase in volumes within our operations. Growth capital also includes costs associated with new well connections. Growth capital excludes expenditures for third-party acquisitions and equity investments. Maintenance capital includes capital expenditures made to maintain our operating capacity and asset base.

        Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations, our Credit Facility and access to debt and equity markets, both public and private. We will also consider the use of alternative financing strategies such as entering into additional joint venture arrangements and the sale of non-strategic assets.

        Management believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partner for capital projects encompassed by the Liberty joint venture, and our current borrowing capacity under the Credit Facility. However, it may be necessary to raise additional funds to finance our future capital requirements. Our access to capital markets can be impacted by factors outside our control, including economic conditions; however, we believe that our strong cash flows and balance sheet, our Credit Facility and our credit rating will provide us with adequate access to funding given our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings assigned by independent rating agencies. As of May 2, 2011, our credit ratings were Ba3 with a Stable outlook by Moody's Investors Service, BB- with a Stable outlook by Standard & Poor's and BB with a Stable outlook by Fitch Ratings. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

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Debt Financing Activities

        Our Credit Facility, which matures on July 1, 2015, has a borrowing capacity of $705 million with an accordion feature of up to $195 million of uncommitted funds. Under the provisions of the Credit Facility we are subject to a number of restrictions and covenants. As of March 31, 2011, we were in compliance with all of our debt covenants and we expect to remain in compliance for at least the next twelve months. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of May 2, 2011, we had $113.3 million of borrowings outstanding and $27.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $564.4 million available for borrowing.

        On February 24, 2011, we completed a public offering of $300 million in aggregate principal amount of 6.5% senior unsecured notes due 2021. Net proceeds of approximately $296 million were used to fund the concurrent repurchase of approximately $272.2 million in aggregate principal amount of our 2016 Senior Notes. On March 10, 2011, we completed a follow-on public offering of an additional $200 million in aggregate principal amount of 6.5% senior unsecured notes due 2021. Net proceeds of approximately $196 million were used to fund the concurrent repurchase of approximately $165.6 million in aggregate principal amount of our 2018 Senior Notes. The remaining proceeds for each of the Senior Notes offerings were used to repay borrowings under our Credit Facility. The Senior Notes issued on February 24, 2011 and March 10, 2011 are treated as a single class of debt securities under the same indenture. As a result of these refinancing activities, we have significantly reduced the interest rates and extended the terms of our long-term financing.

        As of March 31, 2011, we had four series of Senior Notes outstanding: $500.0 million aggregate principal issued in February and March 2011 and due August 2021; $500.0 million aggregate principal issued in November 2010 and due November 2020; $334.4 million aggregate principal issued in April and May 2008 and due April 2018; and $2.8 million aggregate principal issued in July 2006 and due July 2016. For further discussion of the Senior Notes see Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements.

        The Credit Facility and indentures governing the Senior Notes limit the activity of the Partnership and its restricted subsidiaries. The Credit Facility and indentures place limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends or distributions, make loans or transfer property to the Partnership; engage in transactions with the Partnership's affiliates; sell assets, including equity interests of the Partnership's subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.

        The Credit Facility also limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Credit Facility prevents members of the participating bank group from requiring margin calls. As of May 2, 2011, all of our derivative positions, measured volumetrically, are with members of the participating bank group and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to enter into derivative instruments without utilizing cash for margin calls or requiring the use of letters of credit.

Equity Offering

        On January 14, 2011, we completed a public offering of approximately 3.45 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option, at a price of $41.20 per common unit. Net proceeds of

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approximately $138.2 million were used to partially fund our ongoing capital expenditure program, including a portion of the costs associated with the Langley Acquisition.

Cash Flow

        The following table summarizes cash inflows (outflows) (in thousands):

	Three months ended March 31,
	2011			2010			Change
Net cash provided by operating activities	$	115,319		$	114,360		$	959
Net cash used in investing activities		(341,621	)		(95,030	)		(246,591	)
Net cash provided by (used in) financing activities		232,004			(11,907	)		243,911

        Net cash provided by operating activities increased primarily due to a $20.0 million increase in operating income, excluding derivative gains and losses, in our operating segments, which was partially offset by a $3.7 million increase in net cash payments related to the settlement of commodity derivative positions. The increase in operating income was also partially offset by a decrease in operating cash flow resulting from changes in working capital.

        Net cash used in investing activities increased primarily due to the $230.7 million Langley Acquisition and a $42.9 million increase in capital expenditures in the Liberty segment, partially offset by a $23.0 million decrease in capital expenditures in the Southwest segment.

        Net cash provided by (used in) financing activities increased primarily due to:

•

$206.7 million increase in net borrowings, and

•

$138.2 million increase in proceeds from a public equity offering.

        These increases were partially offset by:

•

$39.5 million increase in premiums paid for the redemption of our 2016 and 2018 Senior Notes,

•

$34.2 million decrease in cash contributions received from our joint venture partner,

•

$18.7 million increase in distributions, and

•

$6.5 million increase in payments for debt issuance costs, deferred financing costs and registration costs.

Contractual Obligations

        We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of March 31, 2011, our purchase obligations for the remainder of 2011 were $112.8 million compared to our 2011 obligations of $56.0 million as of December 31, 2010. The increase is due to obligations related to the ongoing expansion in our Liberty segment. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

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Critical Accounting Policies

        The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

        Estimates are used in accounting for, among other items, valuing identified intangible assets; evaluating impairments of long-lived assets, goodwill and equity investments; share-based compensation; risk management activities and derivative financial instruments; and variable interest entities.

        There have not been any material changes during the three months ended March 31, 2011 to the methodology applied by management for critical accounting policies previously disclosed in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2010, except as noted below.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Acquisitions—Purchase Price Allocation
We allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities is recorded as goodwill. For significant acquisitions, we engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as agent networks, customer relationships, trade names and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, after the acquisition closing date through the end of the measurement period of one year or less as we finalize valuations for the assets acquired and liabilities assumed.	Purchase price allocation methodology requires management to make assumptions and apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities primarily using a market approach, income approach, or replacement cost analysis, as appropriate. Key inputs into the fair value determinations include estimates and assumptions related to future volumes, commodity prices, operating costs and construction costs, as well as an estimate of the expected term of the related customer contract or contracts.	If estimates or assumptions used to complete the purchase price allocation and estimate the fair value of acquired assets and liabilities significantly differed from assumptions made, the allocation of purchase price between goodwill, intangibles, and property plant and equipment could significantly differ. Such a difference would impact future earnings through depreciation and amortization expense. In addition, if forecasts supporting the valuation of the intangibles or goodwill are not achieved, impairments could arise.

Recent Accounting Pronouncements

        Refer to Note 2 of the accompanying Notes to the Condensed Consolidated Financial Statements for information regarding recent accounting pronouncements.

Item 3.    Quantitative and Qualitative Disclosures about Market Risk

        Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price changes and, to a lesser extent, interest rate changes and nonperformance by our customers and counterparties.

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Commodity Price Risk

        The information about commodity price risk for the three months ended March 31, 2011 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2010.

Outstanding Derivative Contracts

        The following tables provide information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at March 31, 2011, including the weighted average prices ("WAVG"):

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2011		1,660	$	67.57	$	85.26	$	(10,532	)
2012		2,634		75.65		97.22		(14,090	)
2013		2,984		85.78		105.24		(6,826	)

WTI Crude Puts	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		Fair Value (in thousands)
2011		1,820	$	80.00	$	406

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2011		3,801	$	83.90	$	(24,402	)
2012		4,813		84.54		(37,054	)
2013		1,510		83.86		(10,239	)

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2011		1,157	$	5.37	$	(322	)
2012		4,650		5.62		(1,438	)
2013		980		5.13		(18	)

        The following tables provide information on the volume of our taxable subsidiary's commodity derivative activity for positions related to keep-whole price risk at March 31, 2011, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012		1,122	$	78.49	$	101.71	$	(4,867	)

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2011		2,308	$	90.22	$	(10,978	)
2012		1,840		86.93		(12,699	)
2013		1,304		94.32		(4,111	)

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2011		16,259	$	7.66	$	(15,860	)
2012		14,419		6.02		(4,495	)
2013		6,582		5.33		286

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        The following table provides information on the derivative positions related to long liquids and keep-whole price risk that we have entered into subsequent to March 31, 2011, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)
2013		730	$	97.50	$	116.48
2014		734		95.36		114.81

        The following tables provide information on the derivative positions of our taxable subsidiary related to keep-whole price risk that we have entered into subsequent to March 31, 2011, including the WAVG:

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)
2013		3,211	$	5.36
2014		4,249		5.69

Propane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)
2013 (Jan-Mar, Oct-Dec)		36,885	$	1.29
2014 (Jan-Mar, Oct-Dec)		87,837		1.25

IsoButane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)
2013		3,081	$	1.70
2014		3,885		1.67

Normal Butane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)
2013		8,512	$	1.61
2014		10,711		1.61

Natural Gasoline Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)
2013		5,600	$	2.26
2014		7,106		2.32

Embedded Derivatives in Commodity Contracts

        We have a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative loss related to purchased product costs. In February 2011, we executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of March 31, 2011, the estimated fair value of this contract was a liability of $108.2 million and the recorded value was $54.7 million. The recorded liability does not include the fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative

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liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of March 31, 2011 (in thousands).

Fair value of commodity contract	$	108,161
Inception value for period from April 1, 2015 to December 31, 2022		(53,507	)
Derivative liability as of March 31, 2011	$	54,654

        We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at one of our plant locations through the fourth quarter of 2014. The value of the derivative component of this contract is marked to market through Derivative gain related to facility expenses. As of March 31, 2011, the estimated fair value of this contract was an asset of $4.0 million.

Interest Rate Risk

        The information about interest rate risk for the three months ended March 31, 2011 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2010.

Credit Risk

        The information about credit risk for the three months ended March 31, 2011 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2010.

Item 4.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

        An evaluation was performed under the supervision and with the participation of the Partnership's management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the 1934 Act, as of March 31, 2011. Based on this evaluation, the Partnership's management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of March 31, 2011, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

Limitations on Controls

        Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives as specified above. Management does not expect, however, that our disclosure controls and procedures will prevent or detect all error and fraud. Any control system, no matter how well designed and operated, is based upon certain assumptions and can provide only reasonable, not absolute, assurance that its objectives will be met. Further, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, within the Partnership have been detected.

Changes in Internal Control Over Financial Reporting

        There were no changes in our internal control over financial reporting during the quarter ended March 31, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1.    Legal Proceedings

        Refer to Note 11 of the accompanying Notes to the Condensed Consolidated Financial Statements for information regarding legal proceedings.

Item 6.    Exhibits

4.1	(1)	Fifth Supplemental Indenture dated as of February 24, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
4.2	(1)	Second Supplemental Indenture dated as of February 24, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
4.3	(1)	Form of 6.5% Senior Notes due 2021 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.2 hereto).
4.4	*	Sixth Supplemental Indenture dated as of March 10, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
4.5	*	Fourth Supplemental Indenture dated as of March 10, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
4.6	*	Third Supplemental Indenture dated as of March 10, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
10.1	*+	Purchase and Sale Agreement dated as of January 3, 2011 by and between EQT Gathering, LLC and MarkWest Energy Appalachia, L.L.C.
10.2	*+	Letter Agreement dated February 1, 2011 between EQT Gathering, LLC and MarkWest Energy Appalachia, L.L.C.
31.1	*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	*	Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	*	Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	*	The following financial information from the quarterly report on Form 10-Q of MarkWest Energy Partners, L.P. for the quarter ended March 31, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Changes in Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

(1)

Incorporated by reference to the Current Report on Form 8-K filed February 24, 2011.

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*

Filed herewith

+

Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.

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SIGNATURES

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

	MarkWest Energy Partners, L.P. (Registrant)
	By:	MarkWest Energy GP, L.L.C.,
		Its General Partner
Date: May 9, 2011	/s/ FRANK M. SEMPLE Frank M. Semple Chairman, President and Chief Executive Officer (Principal Executive Officer)
Date: May 9, 2011	/s/ NANCY K. BUESE Nancy K. Buese Senior Vice President & Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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