Markwest Energy Partners L P 10-Q 2010 Q2 Quarterly report

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 June 30, 2010
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 2, Suite 700, Denver, Colorado 80202-2126
(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 August 2, 2010, was 71,439,687.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets at June 30, 2010 and December 31, 2009	2
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2010 and 2009	3
	Unaudited Condensed Consolidated Statements of Changes in Equity for the six months ended June 30, 2010 and 2009	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009	5
	Unaudited Notes to the Condensed Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 4.	Controls and Procedures	60
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 6.	Exhibits	62
SIGNATURES		63

        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
Btu	One British thermal unit, an energy measurement
Dth/d	Dekatherms per day
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
Gal	Gallon
Gal/d	Gallons per day
LIBOR	London Interbank Offered Rate
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)	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
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)

			June 30, 2010			December 31, 2009
ASSETS
Current assets:
	Cash and cash equivalents ($79,364 and $21,942, respectively)		$	134,871		$	97,752
	Receivables, net ($33,133 and $22,033, respectively)			158,098			140,969
	Inventories ($4,743 and $3,343, respectively)			29,453			29,075
	Fair value of derivative instruments			16,337			8,821
	Deferred income taxes			12,228			12,228
	Other current assets ($390 and $327, respectively)			5,862			10,674
		Total current assets		356,849			299,519
Property, plant and equipment ($676,433 and $494,918, respectively)				2,403,491			2,154,644
Less: accumulated depreciation ($22,833 and $11,324, respectively)				(230,872	)		(173,000	)
		Total property, plant and equipment, net		2,172,619			1,981,644
Other long-term assets:
	Investment in unconsolidated affiliate			29,995			29,633
	Intangibles, net of accumulated amortization of $104,121 and $83,735, respectively			634,025			654,411
	Goodwill			9,421			9,421
	Deferred financing costs, net of accumulated amortization of $10,079 and $6,990, respectively			17,939			21,027
	Deferred contract cost, net of accumulated amortization of $1,794 and $1,638, respectively			1,456			1,612
	Fair value of derivative instruments			20,799			15,810
	Other long-term assets ($293 and $314, respectively)			2,278			1,660
		Total assets	$	3,245,381		$	3,014,737
LIABILITIES AND EQUITY
Current liabilities:
	Accounts payable ($8,969 and $2,745, respectively)		$	100,203		$	87,832
	Accrued liabilities ($54,444 and $44,615, respectively)			126,152			137,687
	Fair value of derivative instruments			35,485			60,464
		Total current liabilities		261,840			285,983
Deferred income taxes				24,760			11,034
Fair value of derivative instruments				37,075			62,519
Long-term debt, net of discounts of $37,586 and $39,417, respectively				1,164,045			1,170,072
Other long-term liabilities ($379 and $365, respectively)				108,465			105,736
Commitments and contingencies (Note 9)
Equity:
	MarkWest Energy Partners, L.P. partners' capital (71,433 and 66,275 common units outstanding, respectively)			1,237,370			1,096,654
	Non-controlling interest in consolidated subsidiaries			411,826			282,739
		Total equity		1,649,196			1,379,393
		Total liabilities and equity	$	3,245,381		$	3,014,737

Asset and liability amounts in parentheses represent the portion of the consolidated balance attributable to variable interest entities.

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 June 30,						Six months ended June 30,
			2010			2009			2010			2009
Revenue:
	Revenue		$	276,948		$	185,000		$	592,563		$	368,367
	Derivative gain (loss)			46,902			(83,235	)		39,666			(74,931	)
		Total revenue		323,850			101,765			632,229			293,436
Operating expenses:
	Purchased product costs			128,123			80,652			272,419			182,966
	Derivative (gain) loss related to purchased product costs			(8,392	)		2,625			4,997			32,138
	Facility expenses			37,427			32,336			75,332			63,780
	Derivative loss (gain) related to facility expenses			934			(854	)		128			(1,225	)
	Selling, general and administrative expenses			16,419			14,861			37,927			30,788
	Depreciation			29,818			23,414			58,005			44,357
	Amortization of intangible assets			10,193			10,212			20,386			20,445
	Loss on disposal of property, plant and equipment			188			70			179			799
	Accretion of asset retirement obligations			69			44			212			91
	Impairment of long-lived assets			—			5,855			—			5,855
		Total operating expenses		214,779			169,215			469,585			379,994
		Income (loss) from operations		109,071			(67,450	)		162,644			(86,558	)
Other income (expense):
	Earnings from unconsolidated affiliates			1,585			1,196			1,517			1,091
	Interest income			377			60			763			101
	Interest expense			(25,755	)		(22,742	)		(49,537	)		(40,524	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(2,280	)		(2,046	)		(4,892	)		(3,437	)
	Derivative gain related to interest expense			—			—			1,871			—
	Miscellaneous (expense) income, net			(9	)		2,383			1,053			1,721
		Income (loss) before provision for income tax		82,989			(88,599	)		113,419			(127,606	)
Provision for income tax expense (benefit):
	Current			923			323			6,721			6,576
	Deferred			15,098			(19,726	)		13,726			(35,317	)
		Total provision for income tax		16,021			(19,403	)		20,447			(28,741	)
		Net income (loss)		66,968			(69,196	)		92,972			(98,865	)
Net (income) loss attributable to non-controlling interest				(6,751	)		1,690			(11,245	)		1,710
		Net income (loss) attributable to the Partnership	$	60,217		$	(67,506	)	$	81,727		$	(97,155	)
Net income (loss) attributable to the Partnership's common unitholders per common unit (Note 12):
	Basic		$	0.84		$	(1.18	)	$	1.18		$	(1.71	)
	Diluted		$	0.84		$	(1.18	)	$	1.18		$	(1.71	)
Weighted average number of outstanding common units:
	Basic			71,111			57,603			68,795			57,207
	Diluted			71,298			57,603			68,889			57,207
Cash distribution declared per common unit			$	0.64		$	0.64		$	1.28		$	1.28

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, 2009		66,275	$	1,096,654		$	282,739		$	1,379,393
Share-based compensation activity		271		5,495			—			5,495
Excess tax benefits related to share-based compensation		—		97			—			97
Distributions paid		—		(88,858	)		(2,715	)		(91,573	)
Issuance of units in public offering, net of offering costs		4,887		142,255			—			142,255
Contributions to MarkWest Liberty Midstream joint venture, net		—		—			120,557			120,557
Net income		—		81,727			11,245			92,972
June 30, 2010		71,433	$	1,237,370		$	411,826		$	1,649,196

	MarkWest Energy Partners, L.P. Unitholders
	Common Units		Partners' Capital			Non-controlling Interest			Total
December 31, 2008		56,640	$	1,204,458		$	3,301		$	1,207,759
Share-based compensation activity		254		2,865			—			2,865
Distributions paid		—		(73,596	)		—			(73,596	)
Issuance of units in public offering, net of offering costs		3,335		57,665			—			57,665
Contributions to MarkWest Liberty Midstream joint venture, net		—		(5,464	)		100,000			94,536
Proceeds from sale of equity interest in joint venture, net		—		(1,847	)		31,250			29,403
Transfer to non-controlling interest from sale of equity interest in joint venture		—		(5,889	)		5,889			—
Net loss		—		(97,155	)		(1,710	)		(98,865	)
June 30, 2009		60,229	$	1,081,037		$	138,730		$	1,219,767

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)

				Six months ended June 30,
				2010			2009
Cash flows from operating activities:
Net income (loss)				$	92,972		$	(98,865	)
	Adjustments to reconcile net income (loss) to net cash provided by operating activities:
		Depreciation			58,005			44,357
		Amortization of intangible assets			20,386			20,445
		Impairment of long-lived assets			—			5,855
		Amortization of deferred financing costs and discount			4,892			3,437
		Accretion of asset retirement obligations			212			91
		Amortization of deferred contract cost			156			156
		Phantom unit compensation expense			8,253			4,172
		Equity in earnings of unconsolidated affiliates			(1,517	)		(1,091	)
		Distribution from unconsolidated affiliate			1,155			—
		Unrealized (gain) loss on derivative instruments			(62,987	)		157,541
		Loss on disposal of property, plant and equipment			179			799
		Deferred income taxes			13,726			(35,317	)
		Gain on sale of trading securities			—			(40	)
		Net sales of trading securities			—			552
	Changes in operating assets and liabilities:
		Receivables			(16,829	)		4,035
		Inventories			(378	)		9,198
		Other current assets			4,812			(845	)
		Accounts payable and accrued liabilities			5,803			4,915
		Other long-term assets			(618	)		(7,367	)
		Other long-term liabilities			2,414			2,819
			Net cash provided by operating activities		130,636			114,847
Cash flows from investing activities:
	Capital expenditures				(253,260	)		(320,788	)
	Equity investments				—			(4,984	)
	Proceeds from disposal of property, plant and equipment				417			—
	Change in restricted cash				—			(25	)
			Net cash flows used in investing activities		(252,843	)		(325,797	)
Cash flows from financing activities:
	Proceeds from revolving credit facility				213,404			424,700
	Payments of revolving credit facility				(221,204	)		(376,600	)
	Proceeds from long-term debt				—			117,000
	Payments for debt issuance costs, deferred financing costs and registration costs				—			(7,825	)
	Contributions to MarkWest Liberty Midstream joint venture, net				120,557			94,536
	Proceeds from sale of equity interest in joint venture, net				—			29,403
	Payments of SMR liability				(480	)		—
	Proceeds from public offering, net				142,255			57,665
	Cash paid for taxes related to net settlement of share-based payment awards				(3,730	)		(1,199	)
	Excess tax benefits related to share-based compensation				97			—
	Payments of distributions to common unitholders				(88,858	)		(73,596	)
	Payments of distributions to non-controlling interest				(2,715	)		—
			Net cash flows provided by financing activities		159,326			264,084
Net increase in cash					37,119			53,134
Cash and cash equivalents at beginning of year					97,752			3,321
Cash and cash equivalents at end of period				$	134,871		$	56,455

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 January 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 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, 2009. 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, consider that results for the three and six months ended June 30, 2010 are not necessarily indicative of results for the full year 2010, 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 3 for further discussion of MarkWest Liberty Midstream and MarkWest Pioneer). All significant intercompany investments, accounts and transactions have been eliminated. Investments in which the Partnership exercises significant influence but does not control, or is not the primary beneficiary, are accounted for using the equity method.

2. Recent Accounting Pronouncements

        In June 2009, the FASB amended the VIE subsections of the consolidation guidance. The amended guidance changes the criteria for determining if a VIE exists and whether or not a VIE should be consolidated. The amended guidance was effective for the Partnership on January 1, 2010, and the Partnership reconsidered its previous VIE conclusions and financial statement disclosures. The amendment had no effect on the Partnership's condensed consolidated financial statements.

        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 is effective prospectively for all revenue arrangements entered into or materially modified in fiscal years beginning after June 15, 2010. The amendment is not expected to have a material effect on the Partnership's condensed consolidated financial statements.

        In February 2010, the FASB amended the embedded derivative and hedging guidance. The amended guidance modified the requirements for determining whether an embedded derivative is clearly and closely related to the host contract. The amended embedded derivative guidance was

6

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

2. Recent Accounting Pronouncements (Continued)

effective for the Partnership on January 1, 2010. The amended guidance had no effect on the Partnership's condensed consolidated financial statements.

        In March 2010, the FASB amended a scope exception for embedded credit derivatives in the derivatives and hedging guidance. The amended guidance clarified which types of embedded credit derivative features are required to be analyzed for potential bifurcation. The amended guidance is effective for the Partnership on July 1, 2010. The amended guidance will have no effect on the Partnership's condensed consolidated financial statements.

3. 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. Equity interests in the entity are owned 60% by the Partnership and 40% by M&R MWE Liberty, LLC ("M&R"), an affiliate of The Energy & Minerals Group and its affiliated funds, until December 31, 2010. Effective January 1, 2011 the equity interests in the entity will be owned 51% and 49% by the Partnership and M&R, respectively. A wholly-owned subsidiary of the Partnership serves as the operator and provides field operating and general and administrative services for a fee, a portion of which is fixed. The Partnership's Liberty segment includes the results of operations of MarkWest Liberty Midstream (see Note 13).

        The Partnership and M&R will jointly fund the capital requirements of MarkWest Liberty Midstream at agreed upon levels until the Partnership's contributed capital is proportionate to its eventual 51% ownership interest (the "Equalization Date"), which is expected to occur on or before December 31, 2012. The Partnership is required to reinvest all cash distributions from MarkWest Liberty Midstream until the Equalization Date has occurred. During 2010, M&R will contribute at least $150.0 million to MarkWest Liberty Midstream and the Partnership will fund all capital expenditures in excess of M&R's contributions. MarkWest Liberty Midstream's capital plan for 2011 and 2012 has not been finalized and the exact timing of the members' contributions is currently uncertain. If the Equalization Date has not occurred by the end of 2012, M&R may require the Partnership to contribute the amount of the shortfall at December 31, 2012, or may allow the Partnership to continue to fund up to 100% of MarkWest Liberty Midstream's capital expenditures until its total contributed capital is proportionate to its ownership interest. Following the Equalization Date, M&R will have pre-emptive rights to maintain its ownership interest in MarkWest Liberty Midstream in a range of between 45% and 49% or have its ownership interest diluted to the extent that it elects not to fund its proportionate share.

        As of June 30, 2010, 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 $113.4 million. Under the terms of the joint venture agreement, M&R received a special $5.2 million non-cash allocation of net income from MarkWest Liberty Midstream during the six months ended June 30, 2010 due to their excess contributions. The non-cash allocation is recorded inNet (income) loss attributable to non-controlling interest.

7

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Variable Interest Entities (Continued)

MarkWest Pioneer

        MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that was placed in service in July 2009. The Arkoma Connector Pipeline interconnects with the Midcontinent Express Pipeline and the Gulf Crossing Pipeline and is designed to provide approximately 638,000 Dth/d of Arkoma Basin takeaway capacity. A wholly-owned subsidiary of the Partnership serves as the operator and provides field operating and general and administrative services for fixed fees. The Partnership's Southwest segment includes the results of operations of MarkWest Pioneer (see Note 13).

        Equity interests in the entity are shared equally by the members. The Partnership was obligated to fund all capital expenditures necessary to complete construction of the Arkoma Connector Pipeline in excess of $125.0 million. As of June 30, 2010, the carrying value of the Partnership's ownership interest exceeds its stated ownership interest in MarkWest Pioneer by approximately $1.9 million. The difference between the carrying value of the Partnership's ownership interest and its stated ownership interest is amortized based upon the respective useful lives of the assets to which the difference relates.

Significant Judgments Regarding VIEs

        The Partnership has determined that MarkWest Liberty Midstream and MarkWest Pioneer are both VIEs primarily due to the Partnership's disproportionate economic interests as compared to its voting interests in each entity. The Partnership has made capital contributions to both entities that differ from its stated ownership interests. Additionally, MarkWest Liberty Midstream has insufficient equity at risk, as evidenced by the additional capital funding requirements discussed above.

        Although voting interests are shared equally between the respective members in both MarkWest Liberty Midstream and MarkWest Pioneer, the Partnership has concluded that it is the primary beneficiary of both entities based on its affiliate's role as the operator. The Partnership believes that its role as the operator along with its equity interests give it the power to direct the activities that most significantly affect the economic performance of each VIE.

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

8

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Variable Interest Entities (Continued)

the assets and liabilities attributable to VIEs as of June 30, 2010 and December 31, 2009 (in thousands):

		As of June 30, 2010
		MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents		$	75,427	$	3,937	$	79,364
Accounts receivable			31,781		1,352		33,133
Inventories			4,743		—		4,743
Other current assets			288		102		390
Property, plant and equipment, net of accumulated depreciation of $16,648 and $6,185, respectively			503,232		150,368		653,600
Other long-term assets			293		—		293
	Total assets	$	615,764	$	155,759	$	771,523
LIABILITIES
Accounts payable		$	8,946	$	23	$	8,969
Accrued liabilities			52,639		1,805		54,444
Other long-term liabilities			83		296		379
	Total liabilities	$	61,668	$	2,124	$	63,792

		As of December 31, 2009
		MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents		$	18,168	$	3,774	$	21,942
Accounts receivable			20,753		1,280		22,033
Inventories			3,343		—		3,343
Other current assets			225		102		327
Property, plant and equipment, net of accumulated depreciation of $8,273 and $3,051, respectively			330,116		153,478		483,594
Other long-term assets			314		—		314
	Total assets	$	372,919	$	158,634	$	531,553
LIABILITIES
Accounts payable		$	2,713	$	32	$	2,745
Accrued liabilities			43,136		1,479		44,615
Other long-term liabilities			80		285		365
	Total liabilities	$	45,929	$	1,796	$	47,725

        The assets of the VIEs are the property of the respective entities and are not available to the Partnership for any other purpose, including collateral for its secured debt (see Note 7 and Note 14).

9

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Variable Interest Entities (Continued)

The liabilities of the VIEs do not represent additional claims against the Partnership's general assets. 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 14). 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 subsidiary's compensation for the performance of those services. The Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the six months ended June 30, 2010 and 2009.

        The following table shows the net income (loss) attributable to the Partnership and transfers to the non-controlling interest for the three and six months ended June 30, 2010 and 2009 (in thousands).

			Three Months Ended					Six Months Ended
			June 30, 2010		June 30, 2009			June 30, 2010		June 30, 2009
Net income (loss) attributable to the Partnership			$	60,217	$	(67,506	)	$	81,727	$	(97,155	)
	Transfers to the non-controlling interest:
		Decrease in Partners' Capital for transaction costs related to sale of equity interest in MarkWest Liberty Midstream and MarkWest Pioneer		—		(1,847	)		—		(7,311	)
		Decrease in Partners' Capital for transfer to non-controlling interest from sale of equity interest in MarkWest Pioneer		—		(5,889	)		—		(5,889	)
Net income (loss) attributable to the Partnership and transfers to the non-controlling interest			$	60,217	$	(75,242	)	$	81,727	$	(110,355	)

4. Derivative Financial Instruments

Commodity Contracts

        The Partnership's primary risk management objective is to reduce downside volatility in its cash flows arising from changes in commodity prices related to future sales or purchases of natural gas, NGLs and crude oil. Swaps, options and fixed price forward contracts may allow the Partnership to reduce downside volatility in its realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership's sales or purchases of physical product. While management largely expects realized derivative gains and losses to be offset by increases or decreases in the value of physical sales and purchases, the Partnership will experience volatility in reported earnings due to the recording of unrealized gains and losses on derivative positions that will have no offset. The Partnership's commodity derivative instruments are recorded at fair value in the Condensed Consolidated Balance Sheets. Accordingly, the volatility in any given period related to unrealized gains or losses reported in the Condensed Consolidated Statements of Operations can be significant to the overall financial results of the Partnership; however, management generally expects those gains and losses to be offset when they become realized. The Partnership does not have any trading derivative financial instruments.

10

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

        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. 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. As a result of these transactions, the Partnership has mitigated a significant portion of its expected commodity price risk with agreements expiring at various times through the fourth quarter of 2012. The Partnership has a committee comprised of the senior management team that oversees risk management activity and continually monitors the risk management program and expects to continue to adjust its derivative positions as conditions warrant.

        To manage its commodity price risk, the Partnership utilizes a combination of swaps, options and fixed price forward contracts available on the OTC market. The Partnership enters into OTC derivatives with financial institutions and other energy company counterparties. Management conducts a standard credit review on counterparties and has agreements containing collateral requirements when deemed necessary. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).

        The use of derivative instruments may create exposure to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) physical sales volumes are less than expected or (iii) OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that the Partnership engages in derivative activities, it may be prevented from realizing the benefits of favorable price changes in the physical market; however, it may be insulated against unfavorable changes in such prices.

        The Partnership's amended credit agreement (the "Partnership Credit Agreement") limits its ability to enter into financial derivative transactions with parties that require margin calls and prevents members of the participating bank group from requiring margin calls. As of June 30, 2010 approximately 3.5% of the Partnership's financial derivative positions, measured volumetrically, are with non-bank group counterparties and are subject to margin deposit requirements under OTC agreements that it meets with letters of credit, if necessary. In the unlikely event that the Partnership was unable to meet these margin calls with letters of credit, it would be forced to terminate the corresponding contracts.

        Subsequent to June 30, 2010, the Partnership executed a joinder agreement to include an additional member in the bank group. As a result, all of the Partnership's financial derivative positions are currently with participating members, and the margin requirements are no longer in effect (see Note 16).

Embedded Derivative in Debt Contract

        The senior notes issued in 2009 contain two contingent written put options. The written put options are considered embedded derivatives and are not considered clearly and closely related to the indenture governing the notes. When a hybrid contract contains more than one embedded derivative requiring separate accounting, the embedded derivatives must be aggregated and accounted for as one

11

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

compound embedded derivative. The fair value of the compound embedded derivative in the indenture is recorded as a component ofLong-term debt in the Condensed Consolidated Balance Sheets.

Interest Rate Contracts

        During the first quarter of 2010, the Partnership terminated all of its outstanding interest rate swap contracts. The financial statement impact is disclosed in the tables below.

Financial Statement Impact of Derivative Contracts

        See Note 5 for a description of how the Partnership values its derivative instruments. There were no material changes to its policy regarding the accounting for these instruments as previously disclosed in the Partnership's 2009 Annual Report on Form 10-K. The impact of the Partnership's derivative instruments on its Condensed Consolidated Balance Sheets is summarized below (in thousands):

			Assets				Liabilities
Derivative contracts not designated as hedging instruments and their balance sheet location			Fair Value at June 30, 2010		Fair Value at December 31, 2009		Fair Value at June 30, 2010			Fair Value at December 31, 2009
Commodity contracts(1)
	Fair value of derivative instruments—current		$	16,337	$	8,312	$	(35,485	)	$	(60,464	)
	Fair value of derivative instruments—long-term			20,799		15,810		(37,075	)		(62,519	)
Interest rate contracts
	Fair value of derivative instruments—current			—		509		—			—
Embedded derivative in debt contract
	Long-term debt			—		—		(131	)		(190	)
		Total	$	37,136	$	24,631	$	(72,691	)	$	(123,173	)

(1)

IncludesEmbedded Derivatives in Commodity Contracts as discussed below.

12

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

        The impact of the Partnership's derivative instruments on its Condensed Consolidated Statements of Operations is summarized below (in thousands):

			Three months ended June 30,						Six months ended June 30,
Derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in income
			2010			2009			2010			2009
Revenue: Derivative gain (loss)
	Realized (loss) gain		$	(5,690	)	$	15,299		$	(18,819	)	$	76,413
	Unrealized gain (loss)			52,592			(98,534	)		58,485			(151,344	)
		Total Revenue: derivative gain (loss)		46,902			(83,235	)		39,666			(74,931	)
Derivative gain (loss) related to purchased product costs
	Realized loss			(5,733	)		(11,009	)		(11,171	)		(27,259	)
	Unrealized gain (loss)			14,125			8,384			6,174			(4,879	)
		Total derivative gain (loss) related to purchased product costs		8,392			(2,625	)		(4,997	)		(32,138	)
Derivative (loss) gain related to facility expenses
	Unrealized (loss) gain			(934	)		854			(128	)		1,225
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			3			91			59			91
		Total gain (loss)	$	54,363		$	(84,915	)	$	36,471		$	(105,753	)

        At June 30, 2010, the fair value of the Partnership's commodity derivative contracts is inclusive of premium payments of $6.6 million, net of amortization. For the three months ended June 30, 2010 and 2009,Realized (loss) gain—revenue includes amortization of premium payments of $0.5 million and $1.4 million, respectively. For the six months ended June 30, 2010 and 2009,Realized (loss) gain—revenue includes amortization of premium payments of $1.1 million and $2.6 million, respectively.

        During the first quarter of 2009, the Partnership settled a portion of its derivative positions covering 2009, 2010, and 2011 for $15.2 million of net realized gains. The settlement was completed prior to the contractual settlement to improve liquidity and to mitigate credit risk with certain counterparties, and as such did not represent trading activity. The settlement was recorded as a $26.5 million realized gain inRealized (loss) gain—revenue and an $11.3 million realized loss included inDerivative loss related to purchased product costs in the accompanying Condensed Consolidated Statements of Operations.

Credit Risk Contingent Feature

        The Partnership has a contractual arrangement with one non-bank group counterparty that contains a credit risk contingent feature. The Partnership has OTC swap and put positions with this

13

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

counterparty. This arrangement contains provisions that if the Partnership's credit rating for its long-term senior unsecured debt, as announced by Moody's Investors Service, Inc. and Standard & Poor's Corporation were to decline below B3 or B-, respectively, the Partnership would be required to post additional collateral in the amount of 15% of all outstanding transactions if the contract value of all outstanding transactions was in a net liability position. The Partnership has a standard master netting arrangement with this counterparty. As of June 30, 2010 the Partnership has a net asset position of $3.6 million with this counterparty. If the credit risk contingent feature was triggered as of June 30, 2010, the Partnership would not be required to post additional collateral as collateral is not required when the net position is an asset. If the Partnership's net position became a liability and collateral was required to be posted, it would be accomplished through a letter of credit due to a restriction in the credit agreement which does not allow cash collateral.

        Subsequent to June 30, 2010, the Partnership executed a joinder agreement to include an additional member in the bank group. As a result, all of the Partnership's financial derivative positions are currently with participating members, and the credit risk contingent feature related to margin requirements is no longer in effect (see Note 16).

Outstanding Derivative Contracts

        The following tables provide information on the volume of the Partnership's derivative activity for positions related to long liquids and keep-whole price risk at June 30, 2010, including the weighted average prices ("WAVG"):

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2010		885	$	66.78	$	76.01	$	(615	)
2011		1,659		67.57		85.05		(1,273	)
2012		820		60.00		85.87		(1,916	)

WTI Crude Puts	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		Fair Value (in thousands)
2010		1,534	$	80.00	$	2,045
2011		1,818		80.00		6,890

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2010		3,485	$	73.80	$	(1,865	)
2011		3,058		81.28		1,782
2012		2,657		85.42		3,976

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2010		5,584	$	5.83	$	(1,394	)
2011		1,210		5.38		(167	)
2012		3,976		5.74		(571	)

14

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

IsoButane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		5,957	$	1.35	$	(63	)

Natural Gasoline Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		11,779	$	1.67	$	79

Normal Butane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		9,671	$	1.29	$	23

Propane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		29,508	$	1.04	$	445

        The following tables provide information on the volume of the Partnership's taxable subsidiary's commodity derivative activity for positions related to keep-whole price risk at June 30, 2010, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012		646	$	70.00	$	91.85	$	(266	)

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2010		3,170	$	74.38	$	(1,553	)
2011		3,150		87.27		8,648
2012		468		91.07		1,643

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2010		4,716	$	6.83	$	(7,641	)
2011		15,429		8.79		(17,927	)
2012		6,465		6.70		(2,068	)

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 primary term of the commodity contract, a component of a broader regional arrangement, expired on December 31, 2009 but the producer exercised its right to extend the processing agreement and the commodity contract through the first quarter of 2015. The fair value of the commodity contract is marked based on an index price throughDerivative (gain) loss related to purchased product costs. As of June 30, 2010, the estimated fair value of this contract was a liability of $23.2 million.

15

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Derivative Financial Instruments (Continued)

        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. The value of the derivative component of this contract is marked to market throughDerivative loss (gain) related to facility expenses. As of June 30, 2010, the estimated fair value of this contract was a liability of $0.4 million.

5. Fair Value

        Fair value measurements and disclosures relate primarily to the Partnership's derivative instruments discussed in Note 4. The derivative contracts are measured at fair value on a recurring basis and classified within Level 2 and Level 3 of the valuation hierarchy. The Level 2 and Level 3 measurements are obtained using a market approach. LIBOR rates are an observable input for the measurement of all derivative contracts. The measurements for all commodity contracts contain observable inputs in the form of forward prices based on WTI crude oil prices; Columbia Appalachia, Henry Hub and Houston Ship Channel natural gas prices; Mont Belvieu and Conway NGL prices; and ERCOT electricity prices. Level 2 instruments include crude oil and natural gas swap contracts; the valuations are based on the appropriate commodity prices and contain no significant unobservable inputs. Level 3 instruments include crude oil options, all NGL transactions, embedded derivatives in commodity contracts and the embedded put options. The significant unobservable inputs for crude oil options, NGL transactions and embedded derivatives in commodity contracts include option volatilities and commodity prices interpolated and extrapolated due to inactive markets. The significant unobservable inputs for the embedded put options are option volatilities and management's assumptions about the probability of specific events occurring in the future.

        The methods and assumptions described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Partnership believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date.

        The following table presents the derivative instruments carried at fair value as of June 30, 2010 and December 31, 2009 (in thousands):

As of June 30, 2010		Assets		Liabilities
Significant other observable inputs (Level 2)
	Commodity contracts	$	25,040	$	(42,176	)
Significant unobservable inputs (Level 3)
	Commodity contracts		11,961		(6,613	)
	Embedded derivatives in commodity contracts		135		(23,771	)
	Embedded derivative in debt contract		—		(131	)
Total carrying value in Condensed Consolidated Balance Sheet		$	37,136	$	(72,691	)

16

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Fair Value (Continued)

As of December 31, 2009		Assets		Liabilities
Significant other observable inputs (Level 2)
	Commodity contracts	$	9,920	$	(63,242	)
Significant unobservable inputs (Level 3)
	Commodity contracts		14,202		(25,542	)
	Embedded derivatives in commodity contracts		—		(34,199	)
	Interest rate contracts		509		—
	Embedded derivative in debt contract		—		(190	)
Total carrying value in Condensed Consolidated Balance Sheet		$	24,631	$	(123,173	)

Changes in Level 3 Fair Value Measurements

        The table below includes a rollforward of the balance sheet amounts for the three and six months ended June 30, 2010 and 2009 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

	Three Months Ended June 30, 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	$	(7,907	)	$	(30,861	)	$	—	$	(134	)
Total gain or loss (realized and unrealized) included in earnings(1)		13,029			4,183			—		3
Purchases, sales, issuances and settlements (net)		226			3,042			—		—
Fair value at end of period	$	5,348		$	(23,636	)	$	—	$	(131	)
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at June 30(1)	$	10,009		$	7,225		$	—	$	3

17

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Fair Value (Continued)

	Three Months Ended June 30, 2009
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Embedded Derivative in Debt Contract			Trading Securities
Fair value at beginning of period	$	53,941		$	(2,269	)	$	—		$	—
Total gain or loss (realized and unrealized) included in earnings(1)		(35,012	)		(1,116	)		91			—
Purchases, sales, issuances and settlements (net)		(6,293	)		1,218			(526	)		—
Fair value at end of period	$	12,636		$	(2,167	)	$	(435	)	$	—
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at June 30(1)	$	(34,268	)	$	102		$	91		$	—

	Six Months Ended June 30, 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)		10,271			5,120			1,871			59
Purchases, sales, issuances and settlements (net)		6,417			5,443			(2,380	)		—
Fair value at end of period	$	5,348		$	(23,636	)	$	—		$	(131	)
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at June 30(1)	$	7,551		$	10,562		$	—		$	59

18

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Fair Value (Continued)

	Six Months Ended June 30, 2009
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Embedded Derivative in Debt Contract			Trading Securities
Fair value at beginning of period	$	72,478		$	(22	)	$	—		$	512
Total gain or loss (realized and unrealized) included in earnings(1)		(33,582	)		(3,572	)		91			40
Purchases, sales, issuances and settlements (net)		(26,260	)		1,427			(526	)		(552	)
Fair value at end of period	$	12,636		$	(2,167	)	$	(435	)	$	—
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at June 30(1)	$	(39,306	)	$	(2,145	)	$	91		$	—

(1)

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

6. Inventories

        Inventories consist of the following (in thousands):

		June 30, 2010		December 31, 2009
Natural gas and natural gas liquids		$	22,372	$	20,939
Spare parts			7,081		8,136
	Total inventories	$	29,453	$	29,075

19

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

7. Long-Term Debt

        Debt is summarized below (in thousands):

			June 30, 2010		December 31, 2009
Credit Facility
	Revolving credit facility, 5.0% and 5.25% interest at June 30, 2010 and December 31, 2009, respectively, due February 2012		$	51,500	$	59,300
Senior Notes(1)
	Senior Notes, 6.875% interest, net of discount of $7,363 and $8,089, respectively, issued October 2004 and due November 2014			217,637		216,911
	Senior Notes, 6.875% interest, net of discount of $28,533 and $29,515, respectively, issued May 2009 and due November 2014(2)			121,598		120,674
	Senior Notes, 8.5% interest, net of discount of $702 and $762, respectively, issued July 2006 and due July 2016			274,298		274,238
	Senior Notes, 8.75% interest, net of discount of $988 and $1,051, respectively, issued April and May 2008 and due April 2018			499,012		498,949
		Total long-term debt	$	1,164,045	$	1,170,072

(1)

The estimated aggregate fair value of the Senior Notes was approximately $1,144.6 million and $1,152.9 million as of June 30, 2010 and December 31, 2009, respectively, based on quoted market prices.

(2)

Includes fair value of written put options of approximately $0.1 million (see Note 4).

Credit Facility

        Under the provisions of the Partnership Credit Agreement, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The credit facility is guaranteed and collateralized by substantially all of the Partnership's assets and those of its wholly-owned subsidiaries. As of June 30, 2010, the Partnership had $51.5 million of borrowings outstanding and $30.5 million of letters of credit outstanding under the revolving credit facility, leaving approximately $353.6 million available for borrowing.

        On July 1, 2010, the Partnership entered into an Amended and Restated Credit Agreement (see Note 16).

8. Equity

Equity Offering

        On April 6, 2010, the Partnership completed a public offering of approximately 4.9 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option, at a price of $30.43 per common unit. Net proceeds of approximately $142.3 million were used to repay borrowings under the revolving credit facility and will be used to partially fund the Partnership's ongoing capital expenditure program.

20

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

8. Equity (Continued)

Distributions of Available Cash

Quarter Ended	Distribution Per Common Unit		Declaration Date		Ex-Dividend Date		Record Date		Payment Date
June 30, 2010	$	0.64		July 22, 2010		July 29, 2010		August 2, 2010		August 13, 2010
March 31, 2010	$	0.64		April 22, 2010		April 29, 2010		May 3, 2010		May 14, 2010
December 31, 2009	$	0.64		January 26, 2010		February 3, 2010		February 5, 2010		February 12, 2010

9. 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 condensed consolidated financial statements.

        In June 2006, the Office of Pipeline Safety ("OPS") 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, 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. An administrative hearing on the matter, previously set for the last week of March 2007, was postponed to allow the administrative record to be produced and to allow OPS an opportunity to respond to MarkWest's and Equitable's motions to dismiss count one of the NOPV, which involves $0.8 million of the $1.1 million proposed penalty. This count arises out of alleged activity in 1982 and 1987, which predates MarkWest's leasing and operation of the pipeline. MarkWest believes it has viable and mitigating defenses to the remaining counts and will vigorously defend all applicable assertions of violations. The administrative hearing request was withdrawn by MarkWest and Equitable in October 2009, and the parties are waiting for initial resolution on the briefs, exhibits and other documents filed or submitted by the parties in the matter.

        MarkWest Javelina Company, L.L.C. is a party to an action styledEsmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128^th Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously dismissed petition captionedJesus Villarreal v. Koch Refining Co. et al., Cause No. 05-01977-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005, which sets forth claims for wrongful death, personal injury or property damage, and nuisance type claims, allegedly incurred as a result of operations and emissions

21

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

9. Commitments and Contingencies (Continued)

from MarkWest Javelina's gas processing plant and from various petroleum, petrochemical and metal processing and refining operations located in the area, which were also named as defendants in the action. The action has been and is being vigorously defended, and management does not believe that this action will have a material adverse impact on the Partnership's financial position or results of operations.

        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.

10. Incentive Compensation Plans

        In April 2010, the General Partner's board of directors (the "Board") granted 282,000 performance phantom units ("TUR Performance Units") under the 2008 LTIP to senior executives and other key employees. The TUR Performance Units are classified as equity awards and do not contain distribution equivalent rights. The TUR Performance Units vest in two equal installments on January 31, 2011 and January 31, 2012, subject to the Partnership's relative total unitholder return (unit price appreciation and distribution performance) over the three-year calendar period prior to the scheduled vesting date compared to the total unitholder return of a defined group of peer companies over the same period ("Market Criteria"). The TUR Performance Units will vest in accordance with the Partnership's relative ranking compared to the peer companies. Zero TUR Performance Units will vest if the Partnership's relative ranking is less than the 40^th percentile; 50% of the TUR Performance Units will vest if the Partnership's relative ranking is in the 40^th to 60^th percentile; 75% of the TUR Performance Units will vest if the Partnership's relative ranking is in the 60^th to 80^th percentile; and 100% of the TUR Performance Units will vest if the Partnership's relative ranking is in the 80^th to 100^th percentile.

        Additionally, the Board can increase or decrease the number of units to vest by up to 25% of the number of units that would otherwise vest based solely on the Market Criteria based on other performance criteria to be determined at the Board's discretion ("Performance Criteria"). The effect of these conditions is that vesting of 75%, or 211,500, of the TUR Performance Units will be determined solely by the Partnership's actual performance with regards to the Market Criteria. The remaining 25%, or 70,500, of the TUR Performance Units will vest based on a combination of the Market Criteria and the Performance Criteria.

        The fair value of the TUR Performance Units is estimated using a Monte Carlo simulation model that determines the most likely outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership's common units as of the valuation date, the historical volatility of the market price of the Partnership's common units, the historical volatility of the market price of the common units or common stock of the peer companies, and the correlation between changes in the market price of the Partnership's common units and those of the peer companies. Compensation expense related to 211,500 of the TUR Performance Units is recognized over the requisite service period based on the fair value of the units as of the grant date. However, a grant date, as defined by GAAP, has not been established for the other 70,500 TUR Performance Units because the Performance Criteria prevents a mutual understanding of the key terms of the award. Therefore, compensation expense related to 70,500 of the TUR Performance Units is recognized over the requisite

22

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

10. Incentive Compensation Plans (Continued)

service period based on the fair value of the units as of the current reporting date. The requisite service period for all TUR Performance Units began in April 2010 when the Board approved the awards. Compensation expense for the 70,500 TUR Performance Units may increase or decrease based on the probability of achieving the Performance Criteria.

Compensation Expense

        Total compensation expense recorded for share-based pay arrangements is as follows (in thousands):

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
Phantom units	$	1,968	$	1,469	$	8,253	$	4,172
Distribution equivalent rights		310		330		621		668
Total compensation expense	$	2,278	$	1,799	$	8,874	$	4,840

        As of June 30, 2010, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP and 2006 Hydrocarbon Plan was approximately $20.0 million, with a weighted-average remaining vesting period of approximately 1.0 years. Total compensation expense not yet recognized under the 2008 LTIP includes approximately $4.9 million related to the TUR Performance Units. Total compensation expense not yet recognized related to unvested awards under the 2002 LTIP was approximately $0.2 million, with a weighted-average remaining vesting period of approximately 0.6 years. The actual compensation expense recognized for awards under the 2002 LTIP may differ as they qualify as liability awards, which are affected by changes in the fair value.

        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 six months ended June 30, 2010 and 2009.

23

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

10. Incentive Compensation Plans (Continued)

2008 LTIP and 2006 Hydrocarbon Plan

        The following is a summary of phantom unit activity under the 2008 LTIP and 2006 Hydrocarbon Plan, including the TUR Performance Units described above:

		Number of Units			Weighted-average Grant-date Fair Value(4)
Unvested at December 31, 2009(1)			977,241		$	22.00
	Granted(2)(3)		554,188			24.99
	Vested(2)		(355,837	)		26.71
	Forfeited		(9,644	)		18.30
Unvested at June 30, 2010(1)(3)			1,165,948			22.01

(1)

Includes 437,100 performance units granted to senior executives and other key employees that contain performance vesting criteria based on the Partnership's operating results. Compensation expense recognized for performance units expected to vest was zero for the three months ended June 30, 2010 and 2009, respectively, and zero and $0.3 million for the six months ended June 30, 2010 and 2009, respectively.

(2)

In January 2010, the Board granted 166,000 unrestricted units to senior executives and other key employees under the 2008 LTIP. The unrestricted units vested immediately and the Partnership recognized approximately $4.8 million of expense related to these units.

(3)

Includes 282,000 TUR Performance Units. Compensation expense recognized related to TUR Performance Units was approximately $1.0 million for the three and six months ended June 30, 2010.

(4)

The calculation of the weighted average grant-date fair value for units granted during the six months ended June 30, 2010 includes the fair value as of June 30, 2010 for 70,500 TUR Performance Units. A grant date, as defined by GAAP, has not been established for these units.

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
	(in thousands)				(in thousands)
Total grant-date fair value of phantom units granted during the period(1)	$	5,879	$	9	$	13,847	$	3,658
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	—	$	—	$	9,505	$	9,064

(1)

The calculation of the grant-date fair value for units granted during the three and six months ended June 30, 2010 includes the fair value of $1.6 million as of June 30, 2010 for 70,500 TUR Performance Units. A grant date, as defined by GAAP, has not been established for these units.

24

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

10. Incentive Compensation Plans (Continued)

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, 2009			69,555		$	32.75
	Granted		—			—
	Vested		(43,308	)		32.06
	Forfeited		(287	)		34.00
Unvested at June 30, 2010			25,960			33.87

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
	(in thousands)				(in thousands)
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	—	$	—	$	1,255	$	818

11. Income Taxes

        A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate of 35% to the income (loss) before income tax for the six months ended June 30, 2010 and 2009 is as follows (in thousands):

		Six months ended June 30, 2010
		Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax		$	29,408		$	86,615		$	(2,604	)	$	113,419
Federal statutory rate			35	%		0	%		0	%
Federal income tax at statutory rate		$	10,293		$	—		$	—		$	10,293
Permanent items			10			—			—			10
State income taxes net of federal benefit			1,049			496			—			1,545
Provision on income from Class A units(1)			8,599			—			—			8,599
	Provision for income tax	$	19,951		$	496		$	—		$	20,447
Effective tax rate												18.0	%

25

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

11. Income Taxes (Continued)

		Six months ended June 30, 2009
		Corporation			Partnership			Eliminations			Consolidated
Loss before provision for income tax		$	(67,378	)	$	(51,712	)	$	(8,516	)	$	(127,606	)
Federal statutory rate			35	%		0	%		0	%
Federal income tax at statutory rate		$	(23,582	)	$	—		$	—		$	(23,582	)
Permanent items			12			—			—			12
State income taxes net of federal benefit			(1,659	)		(346	)		—			(2,005	)
Provision on income from Class A units(1)			(3,908	)		—			—			(3,908	)
Excess book deduction related to equity compensation			739			3			—			742
	Provision for income tax	$	(28,398	)	$	(343	)	$	—		$	(28,741	)
Effective tax rate												22.5	%

(1)

The Corporation and the General Partner of the Partnership own Class A units of the Partnership that were received in the merger. For further discussion, see Item 1.Business in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009.

12. Earnings (Loss) Per Common Unit

        The following table shows the computation of basic and diluted net income (loss) per common unit for the three and six months ended June 30, 2010 and 2009, and the weighted-average units used to compute diluted net income (loss) per common unit (in thousands, except per unit data):

		Three months ended June 30,					Six months ended June 30,
		2010		2009			2010		2009
Net income (loss) attributable to the Partnership		$	60,217	$	(67,506	)	$	81,727	$	(97,155	)
Less: Income allocable to phantom units			455		382			551		772
Income (loss) available for common unitholders		$	59,762	$	(67,888	)	$	81,176	$	(97,927	)
Weighted average common units outstanding—basic			71,111		57,603			68,795		57,207
	Effect of dilutive instruments(1)		187		—			94		—
Weighted average common units outstanding—diluted			71,298		57,603			68,889		57,207
Net income (loss) attributable to the Partnership's common unitholders per common unit
	Basic	$	0.84	$	(1.18	)	$	1.18	$	(1.71	)
	Diluted	$	0.84	$	(1.18	)	$	1.18	$	(1.71	)

(1)

Dilutive instruments include TUR Phantom 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. See Note 10 for further discussion on TUR Phantom Units.

26

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Segment Information

        The Partnership prepares segment information in accordance with GAAP. Certain items belowIncome (loss) from operations in the accompanying Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any unrealized 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.

        The tables below present information about operating income for the three and six months ended June 30, 2010 and 2009 and capital expenditures for the six months ended June 30, 2010 and 2009 for the reported segments (in thousands).

Three Months Ended June 30, 2010 and 2009

Three months ended June 30, 2010:		Southwest		Northeast		Liberty		Gulf Coast		Total
Revenue		$	155,043	$	81,322	$	18,738	$	21,845	$	276,948
Operating expenses:
	Purchased product costs		71,389		56,734		—		—		128,123
	Facility expenses		19,395		5,062		6,140		9,395		39,992
Total operating expenses before items not allocated to segments			90,784		61,796		6,140		9,395		168,115
	Portion of operating income attributable to non-controlling interests		1,556		—		5,208		—		6,764
Operating income before items not allocated to segments		$	62,703	$	19,526	$	7,390	$	12,450	$	102,069

Three months ended June 30, 2009:		Southwest			Northeast		Liberty		Gulf Coast		Total
Revenue		$	111,569		$	48,619	$	10,064	$	14,748	$	185,000
Operating expenses:
	Purchased product costs		46,497			32,080		2,075		—		80,652
	Facility expenses		19,577			4,799		4,583		3,163		32,122
Total operating expenses before items not allocated to segments			66,074			36,879		6,658		3,163		112,774
	Portion of operating (loss) income attributable to non-controlling interests		(1	)		—		1,363		—		1,362
Operating income before items not allocated to segments		$	45,496		$	11,740	$	2,043	$	11,585	$	70,864

27

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Segment Information (Continued)

        The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income (loss) before provision for income tax for the three months ended June 30, 2010 and 2009 (in thousands).

			Three months ended June 30,
			2010			2009
Total segment revenue			$	276,948		$	185,000
	Derivative gain (loss) not allocated to segments			46,902			(83,235	)
		Total revenue	$	323,850		$	101,765
Operating income before items not allocated to segments			$	102,069		$	70,864
	Portion of operating income attributable to non-controlling interests			6,764			1,362
	Derivative gain (loss) not allocated to segments			54,360			(85,006	)
	Compensation expense included in facility expenses not allocated to segments			(286	)		(214	)
	Facility expenses adjustment			2,851			—
	Selling, general and administrative expenses			(16,419	)		(14,861	)
	Depreciation			(29,818	)		(23,414	)
	Amortization of intangible assets			(10,193	)		(10,212	)
	Loss on disposal of property, plant and equipment			(188	)		(70	)
	Accretion of asset retirement obligations			(69	)		(44	)
	Impairment of long-lived assets			—			(5,855	)
		Income (loss) from operations		109,071			(67,450	)
	Earnings from unconsolidated affiliates			1,585			1,196
	Interest income			377			60
	Interest expense			(25,755	)		(22,742	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(2,280	)		(2,046	)
	Miscellaneous (expense) income, net			(9	)		2,383
		Income (loss) before provision for income tax	$	82,989		$	(88,599	)

28

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Segment Information (Continued)

Six Months Ended June 30, 2010 and 2009

Six months ended June 30, 2010:			Southwest		Northeast		Liberty		Gulf Coast		Total
Revenue			$	320,007	$	193,170	$	37,748	$	41,638	$	592,563
Operating expenses:
	Purchased product costs			146,014		123,821		2,584		—		272,419
	Facility expenses			39,884		9,287		13,453		15,090		77,714
Total operating expenses before items not allocated to segments				185,898		133,108		16,037		15,090		350,133
	Portion of operating income attributable to non-controlling interests			3,056		—		8,845		—		11,901
Operating income before items not allocated to segments			$	131,053	$	60,062	$	12,866	$	26,548	$	230,529
Capital expenditures			$	71,734	$	1,113	$	175,848	$	2,990	$	251,685
Capital expenditures not allocated to segments												1,575
		Total capital expenditures									$	253,260

Six months ended June 30, 2009:			Southwest		Northeast		Liberty		Gulf Coast		Total
Revenue			$	216,175	$	110,211	$	16,720	$	25,261	$	368,367
Operating expenses:
	Purchased product costs			97,031		83,034		2,901		—		182,966
	Facility expenses			37,702		9,964		7,122		8,434		63,222
Total operating expenses before items not allocated to segments				134,733		92,998		10,023		8,434		246,188
	Portion of operating income attributable to non-controlling interests			27		—		1,643		—		1,670
Operating income before items not allocated to segments			$	81,415	$	17,213	$	5,054	$	16,827	$	120,509
Capital expenditures			$	164,133	$	18,644	$	104,371	$	32,517	$	319,665
Capital expenditures not allocated to segments												1,123
		Total capital expenditures									$	320,788

29

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Segment Information (Continued)

        The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income (loss) before provision for income tax for the six months ended June 30, 2010 and 2009 (in thousands).

			Six months ended June 30,
			2010			2009
Total segment revenue			$	592,563		$	368,367
	Derivative gain (loss) not allocated to segments			39,666			(74,931	)
		Total revenue	$	632,229		$	293,436
Operating income before items not allocated to segments			$	230,529		$	120,509
	Portion of operating income attributable to non-controlling interests			11,901			1,670
	Derivative gain (loss) not allocated to segments			34,541			(105,844	)
	Compensation expense included in facility expenses not allocated to segments			(1,008	)		(558	)
	Facility expenses adjustment			3,390			—
	Selling, general and administrative expenses			(37,927	)		(30,788	)
	Depreciation			(58,005	)		(44,357	)
	Amortization of intangible assets			(20,386	)		(20,445	)
	Loss on disposal of property, plant and equipment			(179	)		(799	)
	Accretion of asset retirement obligations			(212	)		(91	)
	Impairment of long-lived assets			—			(5,855	)
		Income (loss) from operations		162,644			(86,558	)
	Earnings from unconsolidated affiliates			1,517			1,091
	Interest income			763			101
	Interest expense			(49,537	)		(40,524	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(4,892	)		(3,437	)
	Derivative gain related to interest expense			1,871			—
	Miscellaneous income, net			1,053			1,721
		Income (loss) before provision for income tax	$	113,419		$	(127,606	)

30

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Segment Information (Continued)

        The tables below present information about segment assets as of June 30, 2010 and December 31, 2009 (in thousands):

		June 30, 2010		December 31, 2009
Southwest		$	1,659,690	$	1,637,749
Northeast			233,297		249,804
Liberty			615,764		373,127
Gulf Coast			591,185		587,830
Total segment assets			3,099,936		2,848,510
Assets not allocated to segments:
	Certain cash and cash equivalents		54,225		73,184
	Fair value of derivatives		37,136		24,631
	Investment in unconsolidated affiliate		29,995		29,633
	Other(1)		24,089		38,779
Total assets		$	3,245,381	$	3,014,737

(1)

As of June 30, 2010, includes corporate fixed assets, receivables, deferred financing costs and other corporate assets not allocated to segments. As of December 31, 2009, includes corporate fixed assets, deferred financing costs, income tax receivable and other corporate assets not allocated to segments.

14. Supplemental Condensed Consolidating Financial Information

        MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of June 30, 2010, the Partnership's obligations under the outstanding Senior Notes (see Note 7) 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 MarkWest Energy Partners and its

31

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

combined guarantor and combined non-guarantor subsidiaries as of June 30, 2010 and December 31, 2009 and for the three and six months ended June 30, 2010 and 2009 is as follows (in thousands):

Condensed Consolidating Balance Sheets

			As of June 30, 2010
			Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
	Cash and cash equivalents		$	—	$	54,868	$	80,003	$	—		$	134,871
	Receivables and other current assets			963		166,061		38,631		(14	)		205,641
	Intercompany receivables			1,541,316		3,457		6,672		(1,551,445	)		—
	Fair value of derivative instruments			—		16,337		—		—			16,337
		Total current assets		1,542,279		240,723		125,306		(1,551,459	)		356,849
Total property, plant and equipment, net				3,299		1,522,942		654,757		(8,379	)		2,172,619
Other long-term assets:
	Investment in unconsolidated affiliate			—		29,995		—		—			29,995
	Investment in consolidated affiliates			672,630		302,394		—		(975,024	)		—
	Intangibles, net of accumulated amortization			—		633,429		596		—			634,025
	Fair value of derivative instruments			—		20,799		—		—			20,799
	Intercompany notes receivable			209,510		—		—		(209,510	)		—
	Other long-term assets			17,476		13,325		293		—			31,094
		Total assets	$	2,445,194	$	2,763,607	$	780,952	$	(2,744,372	)	$	3,245,381
LIABILITIES AND EQUITY
Current liabilities:
	Intercompany payables		$	711	$	1,547,988	$	2,746	$	(1,551,445	)	$	—
	Fair value of derivative instruments			—		35,485		—		—			35,485
	Other current liabilities			28,944		133,841		63,584		(14	)		226,355
		Total current liabilities		29,655		1,717,314		66,330		(1,551,459	)		261,840
Deferred income taxes				2,256		22,504		—		—			24,760
Intercompany notes payable				—		209,510		—		(209,510	)		—
Fair value of derivative instruments				—		37,075		—		—			37,075
Long-term debt, net of discounts				1,164,045		—		—		—			1,164,045
Other long-term liabilities				3,489		104,574		402		—			108,465
Equity:
	MarkWest Energy Partners, L.P. partners' capital			1,245,749		672,630		714,220		(1,395,229	)		1,237,370
	Non-controlling interest in consolidated subsidiaries			—		—		—		411,826			411,826
		Total equity		1,245,749		672,630		714,220		(983,403	)		1,649,196
		Total liabilities and equity	$	2,445,194	$	2,763,607	$	780,952	$	(2,744,372	)	$	3,245,381

32

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

			As of December 31, 2009
			Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
	Cash and cash equivalents		$	—	$	74,448	$	23,304	$	—		$	97,752
	Receivables and other current assets			870		165,421		26,655		—			192,946
	Intercompany receivables			1,543,169		2,091		88		(1,545,348	)		—
	Fair value of derivative instruments			246		8,575		—		—			8,821
		Total current assets		1,544,285		250,535		50,047		(1,545,348	)		299,519
Total property, plant and equipment, net				3,307		1,499,233		484,788		(5,684	)		1,981,644
Other long-term assets:
	Investment in unconsolidated affiliate			—		29,633		—		—			29,633
	Investment in consolidated affiliates			529,846		203,895		—		(733,741	)		—
	Intangibles, net of accumulated amortization			—		653,797		614		—			654,411
	Fair value of derivative instruments			—		15,810		—		—			15,810
	Intercompany notes receivable			210,060		—		—		(210,060	)		—
	Other long-term assets			20,538		13,182		—		—			33,720
		Total assets	$	2,308,036	$	2,666,085	$	535,449	$	(2,494,833	)	$	3,014,737
LIABILITIES AND EQUITY
Current liabilities:
	Intercompany payables		$	1,195	$	1,543,257	$	896	$	(1,545,348	)	$	—
	Fair value of derivative instruments			—		60,464		—		—			60,464
	Other current liabilities			28,673		149,319		47,527		—			225,519
		Total current liabilities		29,868		1,753,040		48,423		(1,545,348	)		285,983
Deferred income taxes				2,694		8,340		—		—			11,034
Intercompany notes payable				—		210,060		—		(210,060	)		—
Fair value of derivative instruments				—		62,519		—		—			62,519
Long-term debt, net of discounts				1,170,072		—		—		—			1,170,072
Other long-term liabilities				3,064		102,280		392		—			105,736
Equity:
	MarkWest Energy Partners, L.P. partners' capital			1,102,338		529,846		486,634		(1,022,164	)		1,096,654
	Non-controlling interest in consolidated subsidiaries			—		—		—		282,739			282,739
		Total equity		1,102,338		529,846		486,634		(739,425	)		1,379,393
		Total liabilities and equity	$	2,308,036	$	2,666,085	$	535,449	$	(2,494,833	)	$	3,014,737

33

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Operations

			Three Months Ended June 30, 2010
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Total revenue			$	—		$	300,437		$	23,413	$	—		$	323,850
Operating expenses:				—			—			—		—
	Purchased product costs			—			119,707			24		—			119,731
	Facility expenses			—			31,350			7,174		(163	)		38,361
	Selling, general and administrative expenses			11,259			4,893			1,477		(1,210	)		16,419
	Depreciation and amortization			144			33,924			6,025		(82	)		40,011
	Other operating expenses			—			250			7		—			257
		Total operating expenses		11,403			190,124			14,707		(1,455	)		214,779
		(Loss) income from operations		(11,403	)		110,313			8,706		1,455			109,071
Earnings from consolidated affiliates				93,532			2,436			—		(95,968	)		—
Other (expense) income, net				(19,585	)		(3,537	)		481		(3,441	)		(26,082	)
		Income before provision for income tax		62,544			109,212			9,187		(97,954	)		82,989
Provision for income tax expense				341			15,680			—		—			16,021
		Net income		62,203			93,532			9,187		(97,954	)		66,968
Net income attributable to non-controlling interest				—			—			—		(6,751	)		(6,751	)
		Net income attributable to the Partnership	$	62,203		$	93,532		$	9,187	$	(104,705	)	$	60,217

34

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

			Three Months Ended June 30, 2009
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue			$	—		$	91,195		$	10,570		$	—		$	101,765
Operating expenses:
	Purchased product costs			—			81,186			2,091			—			83,277
	Facility expenses			—			26,517			5,073			(108	)		31,482
	Selling, general and administrative expenses			11,319			3,577			836			(871	)		14,861
	Depreciation and amortization			143			31,380			2,145			(42	)		33,626
	Other operating expenses			—			113			1			—			114
	Impairment of long-lived assets			—			—			5,855			—			5,855
		Total operating expenses		11,462			142,773			16,001			(1,021	)		169,215
		Loss from operations		(11,462	)		(51,578	)		(5,431	)		1,021			(67,450	)
Loss from consolidated affiliates				(36,620	)		(615	)		—			37,235			—
Other (expense) income, net				(16,159	)		(3,532	)		3,126			(4,584	)		(21,149	)
		Loss before provision for income tax		(64,241	)		(55,725	)		(2,305	)		33,672			(88,599	)
Provision for income tax benefit				(298	)		(19,105	)		—			—			(19,403	)
		Net Loss		(63,943	)		(36,620	)		(2,305	)		33,672			(69,196	)
Net loss attributable to non-controlling interest				—			—			—			1,690			1,690
		Net loss attributable to the Partnership	$	(63,943	)	$	(36,620	)	$	(2,305	)	$	35,362		$	(67,506	)

35

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

			Six Months Ended June 30, 2010
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Total revenue			$	—		$	585,581		$	46,648	$	—		$	632,229
Operating expenses:
	Purchased product costs			—			274,780			2,636		—			277,416
	Facility expenses			—			60,143			15,643		(326	)		75,460
	Selling, general and administrative expenses			23,040			14,528			2,787		(2,428	)		37,927
	Depreciation and amortization			291			66,634			11,622		(156	)		78,391
	Other operating expenses			—			95			296		—			391
		Total operating expenses		23,331			416,180			32,984		(2,910	)		469,585
		(Loss) income from operations		(23,331	)		169,401			13,664		2,910			162,644
Earnings from consolidated affiliates				147,385			3,265			—		(150,650	)		—
Other (expense) income, net				(39,136	)		(5,330	)		846		(5,605	)		(49,225	)
		Income before provision for income tax		84,918			167,336			14,510		(153,345	)		113,419
Provision for income tax expense				496			19,951			—		—			20,447
		Net income		84,422			147,385			14,510		(153,345	)		92,972
Net income attributable to non-controlling interest				—			—			—		(11,245	)		(11,245	)
		Net income attributable to the Partnership	$	84,422		$	147,385		$	14,510	$	(164,590	)	$	81,727

36

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

			Six Months Ended June 30, 2009
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue			$	—		$	280,039		$	13,397		$	—		$	293,436
Operating expenses:
	Purchased product costs			—			212,175			2,929			—			215,104
	Facility expenses			—			56,213			6,450			(108	)		62,555
	Selling, general and administrative expenses			23,129			7,974			997			(1,312	)		30,788
	Depreciation and amortization			286			61,853			2,705			(42	)		64,802
	Other operating expenses			—			889			1			—			890
	Impairment of long-lived assets			—			—			5,855			—			5,855
		Total operating expenses		23,415			339,104			18,937			(1,462	)		379,994
		Loss from operations		(23,415	)		(59,065	)		(5,540	)		1,462			(86,558	)
Loss from consolidated affiliates				(40,213	)		(691	)		—			40,904			—
Other (expense) income, net				(29,790	)		(8,855	)		3,139			(5,542	)		(41,048	)
		Loss before provision for income tax		(93,418	)		(68,611	)		(2,401	)		36,824			(127,606	)
Provision for income tax benefit				(343	)		(28,398	)		—			—			(28,741	)
		Net Loss		(93,075	)		(40,213	)		(2,401	)		36,824			(98,865	)
Net loss attributable to non-controlling interest				—			—			—			1,710			1,710
		Net loss attributable to the Partnership	$	(93,075	)	$	(40,213	)	$	(2,401	)	$	38,534		$	(97,155	)

37

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Cash Flows

			Six Months Ended June 30, 2010
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities			$	(48,230	)	$	158,451		$	23,266		$	(2,851	)	$	130,636
Cash flows from investing activities:
	Capital expenditures			(282	)		(76,186	)		(179,643	)		2,851			(253,260	)
	Equity investments			(20,540	)		(101,629	)		—			122,169			—
	Distributions from consolidated affiliates			25,238			6,395			—			(31,633	)		—
	Collection of intercompany notes receivable, net			550			—			—			(550	)		—
	Proceeds from disposal of property, plant and equipment			—			417			—			—			417
		Net cash flows provided by (used in) investing activities		4,966			(171,003	)		(179,643	)		92,837			(252,843	)
Cash flows from financing activities:
	Proceeds from revolving credit facility			213,404			—			—			—			213,404
	Payments of revolving credit facility			(221,204	)		—			—			—			(221,204	)
	Payments of intercompany notes receivable, net			—			(550	)		—			550			—
	Contributions to wholly-owned subsidiaries, net			—			20,540			—			(20,540	)		—
	Contributions to joint ventures, net			—			—			222,186			(101,629	)		120,557
	Payments of SMR liability			—			(480	)		—			—			(480	)
	Proceeds from public offering, net			142,255			—			—			—			142,255
	Share-based payment activity			(3,730	)		97			—			—			(3,633	)
	Payment of distributions			(88,858	)		(25,238	)		(9,110	)		31,633			(91,573	)
	Intercompany advances, net			1,397			(1,397	)		—			—			—
		Net cash flows provided by (used in) financing activities		43,264			(7,028	)		213,076			(89,986	)		159,326
Net (decrease) increase in cash				—			(19,580	)		56,699			—			37,119
Cash and cash equivalents at beginning of year				—			74,448			23,304			—			97,752
Cash and cash equivalents at end of period			$	—		$	54,868		$	80,003		$	—		$	134,871

38

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

14. Supplemental Condensed Consolidating Financial Information (Continued)

			Six Months Ended June 30, 2009
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities			$	(43,639	)	$	152,497		$	10,111		$	(4,122	)	$	114,847
Cash flows from investing activities:
	Capital expenditures			(317	)		(143,538	)		(181,055	)		4,122			(320,788	)
	Equity investments			(24,908	)		(110,753	)		—			130,677			(4,984	)
	Change in restricted cash			—			—			(25	)		—			(25	)
	Distributions from consolidated affiliates			—			36,267			—			(36,267	)		—
	Collection of intercompany notes receivable, net			27,800			—			—			(27,800	)		—
	Proceeds from sale of equity interest in consolidated subsidiary			—			31,250			—			(31,250	)		—
		Net cash flows provided by (used in) investing activities		2,575			(186,774	)		(181,080	)		39,482			(325,797	)
Cash flows from financing activities:
	Proceeds from revolving credit facility			424,700			—			—			—			424,700
	Payments of revolving credit facility			(376,600	)		—			—			—			(376,600	)
	Proceeds from long-term debt			117,000			—			—			—			117,000
	Payments of intercompany notes receivable, net			—			(27,800	)		—			27,800			—
	Payments for debt issuance costs, deferred financing costs and registration costs			(7,825	)		—			—			—			(7,825	)
	Proceeds from public offering, net			57,665			—			—			—			57,665
	Contributions to joint ventures, net			(5,464	)		24,908			205,769			(130,677	)		94,536
	Proceeds from sale of equity interest in joint venture, net			(1,847	)		—			—			31,250			29,403
	Share-based payment activity			(1,199	)		—			—			—			(1,199	)
	Payment of distributions			(73,596	)		—			(36,267	)		36,267			(73,596	)
	Intercompany advances, net			(91,770	)		91,085			685			—			—
		Net cash flows provided by (used in) financing activities		41,064			88,193			170,187			(35,360	)		264,084
Net increase (decrease) in cash				—			53,916			(782	)		—			53,134
Cash and cash equivalents at beginning of year				—			—			3,321			—			3,321
Cash and cash equivalents at end of period			$	—		$	53,916		$	2,539		$	—		$	56,455

39

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

15. Supplemental Cash Flow Information

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

	Six months ended June 30,
	2010		2009
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	49,541	$	38,174
Cash paid for income taxes, net of refunds		4,690		1,971
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	56,578	$	28,656
Interest capitalized on construction in progress		2,705		7,136
Property, plant and equipment asset retirement obligation		727		397
Issuance of common units for vesting of share-based payment awards		7,030		8,683

16. Subsequent Events

        On July 1, 2010, the Partnership entered into an amended and restated credit agreement (the "Amended and Restated Credit Agreement"). The Amended and Restated Credit Agreement replaces the Partnership's existing credit agreement in its entirety and provides for a revolving loan facility (the "Facility") of up to $700 million, with an uncommitted accordion feature of up to $200 million. The borrowings under the Facility continue to bear interest at a variable interest rate, plus basis points. The variable interest rate is based either on LIBOR ("LIBOR Loans"), or the higher of (a) the prime rate set by the Facility's administrative agent, (b) the Federal Funds Rate plus 0.5% and (c) the rate for LIBOR for a one month interest period plus 1% ("Alternate Base Rate Loans"). The basis points correspond to the ratio of the Partnership's Consolidated Funded Debt (as defined in the Amended and Restated Credit Agreement) to the Partnership's Adjusted Consolidated EBITDA (as defined in the Amended and Restated Credit Agreement), ranging from 1.5% to 2.5% for Alternate Base Rate Loans and from 2.5% to 3.5% for LIBOR Loans. The Partnership may use up to $150 million of the Facility for the issuance of letters of credit and $10 million for shorter term swingline loans.

        On July 29, 2010, the Partnership executed a joinder agreement to include an additional member in the bank group under the Amended and Restated Credit Agreement and to exercise a portion of the accordion feature under the Facility, thereby increasing the borrowing capacity to $705 million. As a result of adding the new member to the bank group, all of the Partnership's financial derivative positions are currently with participating members, and the credit risk contingent feature related to margin requirements, as described in Note 4, is no longer in effect.

        The Amended and Restated Credit Agreement matures on July 1, 2015; however, the maturity date will be accelerated to May 1, 2014 if the Partnership has not refinanced or repaid the 2014 Senior Notes by such date. The Facility is guaranteed by all of the Partnership's wholly-owned subsidiaries and is collateralized by substantially all of the Partnership's assets and those of its wholly-owned subsidiaries.

        The Partnership incurred approximately $11.5 million of deferred financing costs associated with the Amended and Restated Credit Agreement.

40

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

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 December 31, 2009 Annual Report on Form 10-K. These statements are based on current expectations and assumptions that are subject to risks and uncertainties. Actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors.

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 in the Appalachian region.

Significant Financial and Other Highlights

        Significant financial and other highlights for the three months ended June 30, 2010 are listed below. Refer toResults of Operations andLiquidity and Capital Resources for further details.

•

Total segment operating income before items not allocated to segments increased approximately $31.2 million, or 44%, for the three months ended June 30, 2010 compared to the same period in 2009 (seeResults of Operations for a reconciliation of segment operating income before items not allocated to segments to our consolidated income (loss) before provision for income tax). The increase is due primarily to higher NGL and natural gas prices in 2010, expanding operations in our Liberty segment and increased volumes from a large producer in our Southwest segment. The increase in segment income was partially offset by a $15.7 million decrease in net cash received from the settlement of derivative positions.

•

In April 2010, we received net proceeds of approximately $142.3 million from a public offering of approximately 4.9 million newly issued common units.

•

During the three months ended June 30, 2010, we received approximately $78.3 million of contributions to MarkWest Liberty Midstream from M&R.

•

MarkWest Liberty Midstream is developing a combined pipeline and marine project ("Mariner Project") to deliver purity ethane produced in the Marcellus Shale to Louisiana markets. The Mariner Project is a joint project with Sunoco Logistics and is anticipated to have initial capacity to transport up to 50,000 Bbl/d of ethane by mid-2012 and can be expanded to support additional Marcellus production.

•

MarkWest Liberty Midstream and NiSource Gas Transmission & Storage ("NGT&S") intend to jointly develop natural gas gathering, processing, and transmission projects to support increased Marcellus production volumes in the northern West Virginia area of the Appalachian Basin. The joint project would initially include existing and new pipelines that deliver gas to NGT&S' Smithfield, West Virginia, compressor station where MarkWest Liberty Midstream would install a 120 MMcf/d cryogenic processing facility as early as late-2011. MarkWest Liberty Midstream would complement these processing facilities with fractionation services provided at its Houston, Pennsylvania NGL fractionation, storage, and marketing complex to take advantage of the premium regional markets and to maximize the value of the producers' gas.

41

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 revenue, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss). These charges have been excluded 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 income (loss) from operations, the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

		Three months ended June 30,						Six months ended June 30,
		2010			2009			2010			2009
Revenue		$	276,948		$	185,000		$	592,563		$	368,367
Purchased product costs			128,123			80,652			272,419			182,966
	Net operating margin		148,825			104,348			320,144			185,401
Facility expenses			37,427			32,336			75,332			63,780
Total derivative (gain) loss			(54,360	)		85,006			(34,541	)		105,844
Selling, general and administrative expenses			16,419			14,861			37,927			30,788
Depreciation			29,818			23,414			58,005			44,357
Amortization of intangible assets			10,193			10,212			20,386			20,445
Loss on disposal of property, plant and equipment			188			70			179			799
Accretion of asset retirement obligations			69			44			212			91
Impairment of long-lived assets			—			5,855			—			5,855
	Income (loss) from operations	$	109,071		$	(67,450	)	$	162,644		$	(86,558	)

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 2009 Annual Report on Form 10-K for further discussion of each of these types of arrangements.

        The following table is prepared as if we did not have an active commodity risk management program in place. For further discussion of how we have reduced the downside volatility to the portion of our net operating margin that is not fee-based, see Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements. For the six months ended June 30, 2010, we calculated

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the following approximate percentages of our 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
Revenue		20	%		39	%		4	%		37	%		100	%
Net operating margin(4)		36	%		34	%		0	%		30	%		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 the Appalachia area, 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 and Liberty segments to be higher in the first quarter and fourth quarter.

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 13 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 segment, we purchase the NGLs from the producers primarily under percent-of-proceeds arrangements, or we transport volumes for a fee.

•

Oklahoma.  We own a Foss Lake natural gas 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 and operate a gathering system in the Granite Wash formation in the Texas panhandle that is connected to our Foss Lake processing plants and our Grimes gathering system that is located in Roger Mills and Beckham

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Counties in western Oklahoma. In addition, we own a natural gas gathering system in the Woodford Shale in the Arkoma Basin of southeast Oklahoma. Natural gas gathered in the Woodford system is processed by Centrahoma, our equity investment discussed below.

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

•

Other Southwest.  We own a number of natural gas gathering systems 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 formation. 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.

Northeast

•

Appalachia.  We are the largest processor 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 and Kermit natural gas processing plants, an NGL pipeline, the Siloam NGL fractionation plant and two caverns for storing propane.

•

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 western Pennsylvania and northern West Virginia through MarkWest Liberty Midstream. We have a 35 MMcf/d and a 120 MMcf/d cryogenic plant at our Houston, Pennsylvania processing complex and plan to complete the installation of a 200 MMcf/d cryogenic plant in the first half of 2011. We plan to complete the installation of a 120 MMcf/d cryogenic plant at our Majorsville site in the third quarter of 2010 and expect to increase the cryogenic processing capacity at our Majorsville site to approximately 270 MMcf/d in the third quarter of 2011. We also plan to complete a 60,000 Bbl/d fractionation facility at our Houston complex in the first half of 2011. Until such time, the raw NGLs produced at our Liberty facilities are fractionated at the Siloam NGL fractionation plant in our Northeast segment. We expect the total planned processing capacity of 625 MMcf/d to be supported by long-term agreements with our producer customers. We have also completed construction of an interconnect with a key interstate NGL pipeline providing a market outlet for the propane produced at our Liberty facilities.

Gulf Coast

•

Javelina.  We own and operate the Javelina Processing Facility, a natural gas processing facility in Corpus Christi, Texas, which treats and processes off-gas from six local refineries operated by three different refinery customers. We have a hydrogen supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the hydrogen processed by the steam methane reformer ("SMR") that is owned and operated by a third party. The hydrogen 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 revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by segment, for the six months ended June 30, 2010:

	Southwest			Northeast			Liberty			Gulf Coast			Total
Revenue		54	%		33	%		6	%		7	%		100	%
Net operating margin		54	%		22	%		11	%		13	%		100	%

Equity Investment in Unconsolidated Affiliate

        We own a 40% non-operating membership interest in Centrahoma Processing LLC ("Centrahoma"), a joint venture with Antero Midstream Resources Corporation that is accounted for using the equity method. Centrahoma owns certain processing plants in the Arkoma Basin. We have signed agreements to dedicate our processing rights in certain acreage in the Woodford Shale to Centrahoma through March 1, 2018. The financial results for Centrahoma are included inEarnings from unconsolidated affiliates and are not included in our segment results.

Three months ended June 30, 2010 compared to three months ended June 30, 2009

        Items belowIncome (loss) 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 information about operating income for the reported segments for the three months ended June, 2010 and 2009.

Southwest

		Three months ended June 30,
		2010		2009			$ Change			% Change
		(in thousands)
Revenue		$	155,043	$	111,569		$	43,474			39	%
Operating expenses:
	Purchased product costs		71,389		46,497			24,892			54	%
	Facility expenses		19,395		19,577			(182	)		(1	)%
Total operating expenses before items not allocated to segments			90,784		66,074			24,710			37	%
Portion of operating income (loss) attributable to non-controlling interests			1,556		(1	)		1,557			N/A
Operating income before items not allocated to segments		$	62,703	$	45,496		$	17,207			38	%

        Revenue.    Revenue increased primarily due to higher commodity prices. Revenue from NGL, natural gas and condensate sales increased approximately $36.7 million across the segment. An increase in volumes from a large producer in our Woodford Shale operations also contributed to the increase in product sales. Gathering and compression fee revenue also increased $5.9 million due to the higher volumes in the Woodford Shale and Stiles Ranch, and the start of the Arkoma Connector Pipeline in

45

July 2009. The increase in revenue was partially offset by a decrease in gathered volumes in East Texas and the Other Southwest areas and a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas.

        Purchased Product Costs.    Purchased product costs increased primarily due to higher commodity prices and increased volumes in the Woodford Shale and Stiles Ranch, which was partially offset by a decrease in gathered volumes in East Texas and the Other Southwest areas and a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas.

        Portion of Operating Income (Loss) Attributable to Non-controlling Interests.    Portion of operating income (loss) attributable to non-controlling interests represents our partners' share in net operating income of MarkWest Pioneer and Wirth Gathering Partnership. The increase resulted from the Arkoma Connector Pipeline being placed in service in July 2009.

Northeast

		Three months ended June 30,
		2010		2009		$ Change		% Change
		(in thousands)
Revenue		$	81,322	$	48,619	$	32,703		67	%
Operating expenses:
	Purchased product costs		56,734		32,080		24,654		77	%
	Facility expenses		5,062		4,799		263		5	%
Total operating expenses before items not allocated to segments			61,796		36,879		24,917		68	%
Operating income before items not allocated to segments		$	19,526	$	11,740	$	7,786		66	%

        Revenue.    Revenue increased primarily due to higher commodity prices realized on NGL sales from the Appalachia region, as well as an increase in volumes from a significant customer.

        Purchased Product Costs.    Purchased product costs increased due to higher prices for the natural gas that is purchased to satisfy the keep-whole arrangements in the Appalachia area.

        Facility Expenses.    Facility expenses increased primarily due to higher repairs and maintenance expense, which was partially offset by ceasing our natural gas gathering and processing operations in Western Michigan in the third quarter of 2009.

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Liberty

		Three months ended June 30,
		2010		2009		$ Change			% Change
		(in thousands)
Revenue		$	18,738	$	10,064	$	8,674			86	%
Operating expenses:
	Purchased product costs		—		2,075		(2,075	)		(100	)%
	Facility expenses		6,140		4,583		1,557			34	%
Total operating expenses before items not allocated to segments			6,140		6,658		(518	)		(8	)%
Portion of operating income attributable to non-controlling interests			5,208		1,363		3,845			282	%
Operating income before items not allocated to segments		$	7,390	$	2,043	$	5,347			262	%

        Revenue.    Revenue increased due to ongoing expansion of the Liberty facilities. Revenue increased approximately $6.6 million related to gathering fees and approximately $2.1 million related to NGL and condensate sales under percent-of-proceeds arrangements.

        Purchased Product Costs.    Purchased product costs decreased due to closing the interim plant at the Liberty facilities in January 2010. The NGLs produced at the interim plant were the only Liberty volumes purchased.

        Facility Expenses.    Facility expenses increased primarily due to the ongoing expansion of the Liberty facilities, which was partially offset by a decrease in compressor rental expense as we have purchased certain compressors for the Liberty operation.

        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests represents M&R's 40% interest in net operating income of MarkWest Liberty Midstream. The increase is the result of the ongoing expansion of the Liberty facilities.

Gulf Coast

		Three months ended June 30,
		2010		2009		$ Change		% Change
		(in thousands)
Revenue		$	21,845	$	14,748	$	7,097		48	%
Operating expenses:
	Facility expenses		9,395		3,163		6,232		197	%
Total operating expenses before items not allocated to segments			9,395		3,163		6,232		197	%
Operating income before items not allocated to segments		$	12,450	$	11,585	$	865		7	%

        Revenue.    Revenue increased due to $5.0 million received under a hydrogen sales contract that began March 2010 related to the SMR operations and higher commodity prices, which was partially offset by lower percent-of-proceeds received from one of our refinery customers under a variable percent-of-proceeds contract.

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        Facility Expenses.    Facility expenses increased primarily due to $4.7 million of SMR operating expenses, as well as increased repairs and maintenance expense.

Reconciliation of Segment Operating Income to Consolidated Income (Loss) 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 income (loss) before provision for income tax for the three months ended June 30, 2010 and 2009. The ensuing items listed below theTotal segment revenue andOperating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

			Three months ended June 30,
			2010			2009			$ Change			% Change
			(in thousands)
Total segment revenue			$	276,948		$	185,000		$	91,948			50	%
	Derivative gain (loss) not allocated to segments			46,902			(83,235	)		130,137			(156	)%
		Total revenue	$	323,850		$	101,765		$	222,085			218	%
Operating income before items not allocated to segments			$	102,069		$	70,864		$	31,205			44	%
	Portion of operating income attributable to non-controlling interests			6,764			1,362			5,402			397	%
	Derivative gain (loss) not allocated to segments			54,360			(85,006	)		139,366			(164	)%
	Compensation expense included in facility expenses not allocated to segments			(286	)		(214	)		(72	)		34	%
	Facility expenses adjustment			2,851			—			2,851			N/A
	Selling, general and administrative expenses			(16,419	)		(14,861	)		(1,558	)		10	%
	Depreciation			(29,818	)		(23,414	)		(6,404	)		27	%
	Amortization of intangible assets			(10,193	)		(10,212	)		19			(0	)%
	Loss on disposal of property, plant and equipment			(188	)		(70	)		(118	)		169	%
	Accretion of asset retirement obligations			(69	)		(44	)		(25	)		57	%
	Impairment of long-lived assets			—			(5,855	)		5,855			(100	)%
		Income (loss) from operations		109,071			(67,450	)		176,521			(262	)%
	Earnings from unconsolidated affiliates			1,585			1,196			389			33	%
	Interest income			377			60			317			528	%
	Interest expense			(25,755	)		(22,742	)		(3,013	)		13	%
	Amortization of deferred financing costs and discount (a component of interest expense)			(2,280	)		(2,046	)		(234	)		11	%
	Miscellaneous (expense) income, net			(9	)		2,383			(2,392	)		(100	)%
		Income (loss) before provision for income tax	$	82,989		$	(88,599	)	$	171,588			(194	)%

        Derivative Gain (Loss) Not Allocated to Segments.    Unrealized gain from the mark-to-market of our derivative instruments was $65.8 million for the three months ended June 30, 2010 compared to unrealized loss of $89.3 million for the same period in 2009. Realized loss from the settlement of our derivative instruments was $11.4 million for the three months ended June 30, 2010 compared to realized gain of $4.3 million for the same period in 2009. The total change of $139.4 million is primarily due to volatility in commodity prices.

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        Facility Expenses Adjustment.    Facility expenses adjustment consists of the reclassification of the MarkWest Pioneer field services fee and the reclassification 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.

        Selling, General and Administrative Expenses.    Selling, general and administrative expenses increased primarily due to increases in headcount, short-term incentive compensation, insurance and corporate office rent. These increases were partially offset by a decrease in professional services.

        Depreciation.    Depreciation increased due to depreciation on additional projects completed during 2009 and the first half of 2010.

        Impairment of Long-Lived Assets.    During the three months ended June 30, 2009, we recognized an impairment of $5.9 million related to certain gas-gathering and intangible assets in the Southwest segment.

        Interest Expense.    Interest expense increased primarily due to additional borrowings in May 2009 to fund our capital plan.

        Provision for Income Tax.    The total provision for income tax expense was $16.0 million, which includes a deferred expense of $15.1 million related primarily to MarkWest Hydrocarbon's ownership of Class A units and the net unrealized derivative gain during the period. The current provision for income tax expense was $0.9 million. Approximately $0.4 million is attributable to MarkWest Hydrocarbon and the remaining $0.5 million is related to taxes payable by the Partnership associated with the Texas Margin Tax and Michigan Business Taxes.

Six months ended June 30, 2010 compared to six months ended June 30, 2009

        Items belowIncome (loss) 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 information about operating income for the reported segments for the six months ended June 30, 2010 and 2009.

Southwest

		Six months ended June 30,
		2010		2009		$ Change		% Change
		(in thousands)
Revenue		$	320,007	$	216,175	$	103,832		48	%
Operating expenses:
	Purchased product costs		146,014		97,031		48,983		50	%
	Facility expenses		39,884		37,702		2,182		6	%
Total operating expenses before items not allocated to segments			185,898		134,733		51,165		38	%
Portion of operating income attributable to non-controlling interests			3,056		27		3,029		11,219	%
Operating income before items not allocated to segments		$	131,053	$	81,415	$	49,638		61	%

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        Revenue.    Revenue increased primarily due to higher NGL prices. Revenue from NGL and condensate sales increased approximately $97.9 million across the segment, partially offset by a $7.6 million decrease in revenue from natural gas sales. An increase in volumes from a large producer in our Woodford Shale operations also contributed to the increase in product sales. Gathering and compression fee revenue also increased $12.1 million due to the higher volumes in the Woodford Shale and Stiles Ranch, and the start of the Arkoma Connector Pipeline in July 2009. The increase in revenue was partially offset by a decrease in volumes in East Texas and the Other Southwest areas and a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas.

        Purchased Product Costs.    Purchased product costs increased primarily due to higher commodity prices and increased volumes in certain areas, which was partially offset by a decrease in gathered volumes in East Texas and the Other Southwest areas and a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas.

        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests represents our partners' share in net operating income of MarkWest Pioneer and Wirth Gathering Partnership. The increase resulted from the Arkoma Connector Pipeline being placed in service in July 2009.

Northeast

		Six months ended June 30,
		2010		2009		$ Change			% Change
		(in thousands)
Revenue		$	193,170	$	110,211	$	82,959			75	%
Operating expenses:
	Purchased product costs		123,821		83,034		40,787			49	%
	Facility expenses		9,287		9,964		(677	)		(7	)%
Total operating expenses before items not allocated to segments			133,108		92,998		40,110			43	%
Operating income before items not allocated to segments		$	60,062	$	17,213	$	42,849			249	%

        Revenue.    Revenue increased primarily due to higher commodity prices realized on NGL sales from the Appalachia region, as well as an increase in volumes from a significant customer.

        Purchased Product Costs.    Purchased product costs increased due to higher prices for the natural gas that is purchased to satisfy the keep-whole arrangements in the Appalachia area, as well as the increase in volumes.

        Facility Expenses.    Facility expenses decreased primarily due to ceasing our natural gas gathering and processing operations in Western Michigan in the third quarter of 2009, as well as a decrease in utilities and other operating expenses.

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Liberty

		Six months ended June 30,
		2010		2009		$ Change			% Change
		(in thousands)
Revenue		$	37,748	$	16,720	$	21,028			126	%
Operating expenses:
	Purchased product costs		2,584		2,901		(317	)		(11	)%
	Facility expenses		13,453		7,122		6,331			89	%
Total operating expenses before items not allocated to segments			16,037		10,023		6,014			60	%
Portion of operating income attributable to non-controlling interests			8,845		1,643		7,202			438	%
Operating income before items not allocated to segments		$	12,866	$	5,054	$	7,812			155	%

        Revenue.    Revenue increased due to ongoing expansion of the Liberty facilities. Revenue increased approximately $12.4 million related to gathering fees and approximately $8.6 million related to NGL product sales under percent-of-proceeds arrangements.

        Purchased Product Costs.    Purchased product costs decreased due to closing the interim plant at the Liberty facilities in January 2010. The NGLs produced at the interim plant were the only Liberty volumes purchased.

        Facility Expenses.    Facility expenses increased primarily due to the ongoing expansion of the Liberty facilities, as well as an increase of approximately $0.6 million related to environmental remediation costs.

        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests represents M&R's 40% interest in net operating income of MarkWest Liberty Midstream. The increase is the result of the formation of the joint venture on February 27, 2009 and the ongoing expansion of the Liberty facilities.

Gulf Coast

		Six months ended June 30,
		2010		2009		$ Change		% Change
		(in thousands)
Revenue		$	41,638	$	25,261	$	16,377		65	%
Operating expenses:
	Facility expenses		15,090		8,434		6,656		79	%
Total operating expenses before items not allocated to segments			15,090		8,434		6,656		79	%
Operating income before items not allocated to segments		$	26,548	$	16,827	$	9,721		58	%

        Revenue.    Revenue increased due to $5.8 million received under a hydrogen sales contract that began March 2010 related to the SMR operations, higher commodity prices and increased volumes. The volumes were lower in 2009 due to a two-week plant turnaround. The increase in revenue was

51

partially offset by lower percent-of-proceeds received from one of our refinery customers under a variable percent-of-proceeds contract.

        Facility Expenses.    Facility expenses increased primarily due to $5.6 million of SMR operating expenses and increased utilities and operating expenses. The increases were partially offset by a decrease related to the plant turnaround completed in 2009 that did not recur in 2010.

Reconciliation of Segment Operating Income to Consolidated Income (Loss) 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 income (loss) before provision for income tax for the six months ended June 30, 2010 and 2009. The ensuing items listed below theTotal segment revenue andOperating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

			Six months ended June 30,
			2010			2009			$ Change			% Change
			(in thousands)
Total segment revenue			$	592,563		$	368,367		$	224,196			61	%
	Derivative gain (loss) not allocated to segments			39,666			(74,931	)		114,597			(153	)%
		Total revenue	$	632,229		$	293,436		$	338,793			115	%
Operating income before items not allocated to segments			$	230,529		$	120,509		$	110,020			91	%
	Portion of operating income attributable to non-controlling interests			11,901			1,670			10,231			613	%
	Derivative gain (loss) not allocated to segments			34,541			(105,844	)		140,385			(133	)%
	Compensation expense included in facility expenses not allocated to segments			(1,008	)		(558	)		(450	)		81	%
	Facility expenses adjustment			3,390			—			3,390			N/A
	Selling, general and administrative expenses			(37,927	)		(30,788	)		(7,139	)		23	%
	Depreciation			(58,005	)		(44,357	)		(13,648	)		31	%
	Amortization of intangible assets			(20,386	)		(20,445	)		59			(0	)%
	Loss on disposal of property, plant and equipment			(179	)		(799	)		620			(78	)%
	Accretion of asset retirement obligations			(212	)		(91	)		(121	)		133	%
	Impairment of long-lived assets			—			(5,855	)		5,855			(100	)%
		Income (loss) from operations		162,644			(86,558	)		249,202			(288	)%
	Loss from unconsolidated affiliates			1,517			1,091			426			39	%
	Interest income			763			101			662			655	%
	Interest expense			(49,537	)		(40,524	)		(9,013	)		22	%
	Amortization of deferred financing costs and discount (a component of interest expense)			(4,892	)		(3,437	)		(1,455	)		42	%
	Derivative gain related to interest expense			1,871			—			1,871			N/A
	Miscellaneous income, net			1,053			1,721			(668	)		(39	)%
		Income (loss) before provision for income tax	$	113,419		$	(127,606	)	$	241,025			(189	)%

        Derivative Gain (Loss) Not Allocated to Segments.    Unrealized gain from the mark-to-market of our derivative instruments was $64.5 million for the six months ended June 30, 2010 compared to unrealized loss of $155.0 million for the same period in 2009. Realized loss from the settlement of our

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derivative instruments was $30.0 million for the six months ended June 30, 2010 compared to realized gain of $49.2 million for the same period in 2009. The total change of $140.4 million is primarily due to volatility in commodity prices.

        Facility Expenses Adjustment.    Facility expenses adjustment consists of the reclassification of the MarkWest Pioneer field services fee and the reclassification 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.

        Selling, General and Administrative Expenses.    Selling, general and administrative expenses increased primarily due to higher share-based compensation expense related to the January 2010 unrestricted unit grant, as well as increases in headcount, short-term incentive compensation, insurance and corporate office rent. These increases were partially offset by a decrease in professional services expense.

        Depreciation.    Depreciation increased due to depreciation on additional projects completed during 2009 and the first half of 2010.

        Impairment of Long-Lived Assets.    During the six months ended June 30, 2009, we recognized an impairment of $5.9 million related to certain gas-gathering and intangible assets in the Southwest segment.

        Interest Expense.    Interest expense increased primarily due to additional borrowings in May 2009 to fund our capital plan.

        Amortization of Deferred Financing Costs and Discount.    Amortization of deferred financing costs and discount increased due primarily to the amortization of the financing costs and discount on the Senior Notes issued in May 2009.

        Derivative Gain Related to Interest Expense.    Derivative gain related to interest expense in 2010 relates to the settlement of all the outstanding interest rate swaps in January 2010. See Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements for further details.

        Provision for Income Tax.    The total provision for income tax expense was $20.4 million, which includes a deferred expense of $13.7 million related primarily to MarkWest Hydrocarbon's ownership of Class A units and the net unrealized derivative gain during the period. The current provision for income tax expense was $6.7 million. Approximately $5.8 million is attributable to MarkWest Hydrocarbon and the remaining $0.9 million is related to taxes payable by the Partnership associated with the Texas Margin Tax and Michigan Business Taxes.

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Operating Data

			Three months ended June 30,							Six months ended June 30,
			2010		2009		% Change			2010		2009		% Change
Southwest
	East Texas
		Gathering systems throughput (Mcf/d)		438,700		463,900		(5.4	)%		433,900		457,400		(5.1	)%
		NGL product sales (gallons)		61,887,500		64,692,600		(4.3	)%		126,083,300		113,062,600		11.5	%
	Oklahoma
		Foss Lake gathering system throughput (Mcf/d)		70,600		93,300		(24.3	)%		72,400		92,900		(22.1	)%
		Stiles Ranch gathering system throughput (Mcf/d)		106,100		91,000		16.6	%		111,800		92,200		21.3	%
		Grimes gathering system throughput (Mcf/d)		8,000		10,000		(20.0	)%		8,000		10,400		(23.1	)%
		Arapaho NGL product sales (gallons)		30,093,800		31,697,300		(5.1	)%		59,537,100		59,130,100		0.7	%
		Southeast Oklahoma gathering system throughput (Mcf/d)		539,400		403,300		33.7	%		518,100		411,100		26.0	%
		Arkoma Connector Pipeline throughput (Mcf/d)(1)		387,500		N/A		N/A			372,700		N/A		N/A
	Other Southwest
		Appleby gathering system throughput (Mcf/d)		31,600		49,000		(35.5	)%		33,100		53,300		(37.9	)%
		Other gathering systems throughput (Mcf/d)(2)		8,700		10,800		(19.4	)%		8,800		10,800		(18.5	)%
Northeast
	Appalachia(3)
		Natural gas processed (Mcf/d)		199,900		197,100		1.4	%		196,400		197,900		(0.8	)%
		Keep-whole sales (gallons)		30,815,000		33,255,100		(7.3	)%		76,587,400		84,233,000		(9.1	)%
		Percent-of-proceeds sales (gallons)		30,118,700		20,180,700		49.2	%		57,123,600		39,543,800		44.5	%
		Total NGL product sales (gallons)(4)		60,933,700		53,435,800		14.0	%		133,711,000		123,776,800		8.0	%
	Michigan
		Crude oil transported for a fee (Bbl/d)		12,100		12,500		(3.2	)%		12,500		12,600		(0.8	)%
Liberty
		Gathering system throughput (Mcf/d)		128,500		43,400		196.1	%		114,800		38,500		198.2	%
		NGL product sales (gallons)		23,462,500		7,053,000		232.7	%		44,992,700		8,436,200		433.3	%
Gulf Coast
		Refinery off-gas processed (Mcf/d)		118,800		124,800		(4.8	)%		116,100		114,600		1.3	%
		Liquids fractionated (Bbl/d)		22,800		25,200		(9.5	)%		22,700		22,600		0.4	%

(1)

We began commercial operation of the Arkoma Connector Pipeline in July 2009.

(2)

Excludes lateral pipelines where revenue is not based on throughput.

(3)

Includes throughput from the Kenova, Cobb, and Boldman processing plants.

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(4)

Represents sales at the Siloam NGL fractionation plant. The total sales exclude 12,648,600 gallons and 5,136,900 gallons sold by the Northeast on behalf of Liberty for the three months ended June 30, 2010 and 2009, respectively, and 23,305,800 gallons and 6,520,000 gallons sold for the six months ended June 30, 2010 and 2009, respectively.

Liquidity and Capital Resources

        Our primary strategy is to expand our asset base through organic growth and expansion projects and selective third-party acquisitions that are accretive to our cash available for distribution per common unit. In 2009, we spent approximately $487.0 million on internal development and expansion opportunities, of which a significant portion was funded by our joint venture partners and by our divestiture of the SMR facility.

        Our 2010 capital plan includes approximately $490 million to $540 million of capital expenditures for growth projects and approximately $10 million to $15 million for maintenance capital. Our share of growth capital expenditures is expected to be approximately $300 million to $350 million and the remainder will be funded through contributions from our joint venture partners and existing cash balances in the joint ventures. As of June 30, 2010 we have spent approximately $253.3 million, including the amounts funded by our joint venture partners.

        During the six months ended June 30, 2010, we received approximately $120.6 million from M&R to fund capital expenditures at MarkWest Liberty Midstream.

        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 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 partners for capital projects encompassed by the joint venture, and our current borrowing capacity under the revolving 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 August 2, 2010, our credit ratings were Ba3 with a Stable outlook by Moody's Investors Service and BB- with a Stable outlook by Standard & Poor's, which reflect upgrades by both agencies in 2010. Fitch Ratings initiated coverage in June 2010 and assigned us a current credit rating of BB with a Stable outlook. 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.

Debt Financing Activities

        On July 1, 2010, we entered into the Amended and Restated Credit Agreement (see Note 16 of the accompanying Notes to the Condensed Consolidated Financial Statements). The Amended and Restated Credit Agreement replaced our existing credit agreement in its entirety and provides for a Facility of up to $700 million, with an uncommitted accordion feature of up to $200 million. On July 29, 2010, we exercised a portion of the accordion feature and increased our borrowing capacity under the Facility to $705 million. The Amended and Restated Credit Agreement matures on July 1, 2015; however, the maturity date will be accelerated to May 1, 2014 if we have not refinanced or repaid the 2014 Senior Notes by such date.

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        Under the provisions of the Amended and Restated Credit Agreement, we are subject to a number of restrictions and covenants, which are substantially the same as the restrictions and covenants under the Partnership Credit Agreement. As of June 30, 2010, we were in compliance with all of our debt covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of August 2, 2010, we had no borrowings outstanding and $27.4 million of letters of credit outstanding under the Facility, leaving approximately $677.6 million available for borrowing.

        As of June 30, 2010, we had four series of Senior Notes outstanding: $225.0 million aggregate principal issued in October 2004 and due November 2014; $150.0 million aggregate principal issued in May 2009 and due November 2014 with terms substantially the same as the 2014 Senior Notes issued in 2004; $275.0 million aggregate principal issued in July 2006 and due July 2016; and $500.0 million aggregate principal issued in April and May 2008 and due April 2018. For further discussion of the Senior Notes see Note 7 of the accompanying Notes to the Condensed Consolidated Financial Statements.

        The indentures governing the Senior Notes limit the activity of the Partnership and its restricted subsidiaries. The 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 Amended and Restated Credit Agreement limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Amended and Restated Credit Agreement prevents members of the participating bank group from requiring margin calls. As of August 2, 2010, 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; however, there is no certainty that the members of our bank group will continue to participate and in such case, a portion of our available credit could be used for derivative instruments instead of future growth.

Equity Offerings

        On April 6, 2010, we completed a public offering of approximately 4.9 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option, at a price of $30.43 per common unit. Net proceeds of approximately $142.3 million were used to repay borrowings under our revolving credit facility and will be used to partially fund our ongoing capital expenditure program.

Liquidity Risks and Uncertainties

        Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance. That, in turn, will be affected by prevailing economic conditions in our industry, as well as financial, business and other factors, some of which are beyond our control. The global economic recession had a significant adverse impact on commodity prices during 2009. Although NGL and natural gas prices have improved in the first half of 2010 compared to 2009, our operating performance could be negatively impacted if the improvements in commodity prices are not sustained. Additionally, new legislation recently enacted by Congress could limit our ability to execute our hedging strategy, which would increase our exposure to adverse changes in commodity prices.

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        The prevailing uncertainty that exists in the financial markets has created an increased risk of counterparty default that could impact our liquidity in several ways. During 2010, we expect that we will be required to borrow additional amounts under our Facility. However, our ability to access these funds could be adversely impacted by the failure of one or more of the members of the participating bank group. Although management believes that the participating members are financially sound, an increased risk does exist. Also, because the participating members of our bank group are the counterparties to all of our derivative instruments, the failure of one of more members could significantly reduce the cash flow from operations related to the settlement of these positions. The cash flows generated by our operations could also be significantly reduced if any of our major customers defaulted on its obligations to us. The creditworthiness of our trade customers is continuously monitored, and we believe that our current group of customers are sound and do not represent abnormal credit risk. Additionally, our supply of gas is dependent on a few large producers in each of our operating segments. If any of these producers were forced to significantly curtail or cease production due to economic adversity, our cash flows from operations could be significantly reduced.

Cash Flow

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

	Six months ended June 30,
	2010			2009			$ Change
Net cash provided by operating activities	$	130,636		$	114,847		$	15,789
Net cash flows used in investing activities		(252,843	)		(325,797	)		72,954
Net cash flows provided by financing activities		159,326			264,084			(104,758	)

        Net cash provided by operating activities increased primarily due to a $110.0 million increase in operating income, excluding derivative gains and losses, in our operating segments, which was partially offset by a $76.8 million decrease in net cash received from the settlement of derivative positions and a decrease in operating cash flows resulting from changes in working capital.

        Net cash used in investing activities decreased primarily due to a $67.5 million decrease in capital expenditures and a $5.0 million decrease in contributions to equity investments.

        Net cash provided by financing activities decreased primarily due to a $172.9 million decrease in net borrowings and a $15.3 million increase in distributions to common unitholders, which was partially offset by an $84.6 million increase in proceeds from public offerings.

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 June 30, 2010, our purchase obligations for the remainder of 2010 were $77.1 million compared to our 2010 obligations of $16.7 million as of December 31, 2009. 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.

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

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revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used in accounting for, among other items, valuing inventory; 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 six months ended June 30, 2010 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 2009 Annual Report on Form 10-K, except as noted below.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Variable Interest Entities
We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity is a VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership, or other pecuniary interests in an entity that change with changes in the fair value of the VIE's assets. When we conclude that we hold a variable interest in a VIE we must determine if we are the entity's primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling financial interest is evidenced by both (a) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses that could potentially be significant to the VIE or the right to receive benefits that could potentially be significant to the VIE. We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any variable interests in a VIE that is not consolidated.	Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interests in a VIE. We use primarily qualitative analysis to determine if an entity is a VIE. We evaluate the entity's need for continuing financial support; the equity holder's lack of a controlling financial interest; and/or if an equity holders voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our variable interests in a VIE to determine whether we are the primary beneficiary. We use primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions.	MarkWest Liberty Midstream and MarkWest Pioneer are VIEs and we are considered the primary beneficiary; we have a traditional controlling financial interest in the Wirth Gathering Partnership and the Brightstar Partnership, which are less-than wholly-owned. All of these entities are consolidated subsidiaries. Changes in the design or nature of the activities of any of these entities, or our involvement with an entity may require us to reconsider our conclusions on the entity's status as a VIE and/or our status as the primary beneficiary. Such reconsideration could result in the deconsolidation of the affected subsidiary. The deconsolidation of a subsidiary would have a significant impact on our financial statements. We account for our ownership interest in Centrahoma under the equity method and have determined it is not a VIE. However, changes in the design or nature of the activities of the entity may require us to reconsider our conclusions. Such reconsideration would require the identification of the variable interests in the entity and a determination on which party is the entity's primary beneficiary. If Centrahoma were considered a VIE and we were determined to be the primary beneficiary, the change could cause us to consolidate the entity. The consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Accounting for Share-Based Compensation
Our long-term incentive plans permit the grant of restricted units, phantom units, unit options and substitute awards. In April 2010, the Board granted 282,000 phantom units to our senior executives and other key employees that will vest in equal installments on January 31, 2011 and January 31, 2012, subject to Market Criteria and Performance Criteria to be determined at the Board's discretion. The Market Criteria, which must be considered in determining the grant-date fair value of the award, is based on the Partnership's total unitholder return over a three-year calendar period relative to the total unitholder return of a defined group of peer companies over the same period. The Performance Criteria do not affect the fair value of the awards but do impact the recognition of expense as compensation expense is only recognized for those awards that are expected to vest.	We must exercise significant judgment and make several assumptions to estimate the fair value of the awards based on the Market Criteria. This includes determining the appropriate valuation methodology and the related inputs such as the expected volatility of the market price of our common units, the expected volatility of the market price of the common units or common stock of the peer companies, and the correlation between changes in the market price of our common units and those of the peer companies. We utilize a Monte Carlo simulation model which is a commonly accepted methodology for valuing this type of award. We utilized historical volatilities and correlation factors as the key inputs to this model. We have also exercised judgment in assuming that the Board will not increase or decrease the number of units that vest based on the Performance Criteria as there is no basis to conclude that it is probable that any adjustment to the vesting will be made.	If we had used a different valuation methodology or different assumptions regarding expected volatilities and correlations, the estimated fair value and related compensation expense of the phantom units may have been significantly different. Compensation expense could also increase or decrease significantly in future periods if the Board adjusts the number of units that vest based on the Performance Criteria.

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

Commodity Price Risk

        The information about market risk for the six months ended June 30, 2010 does not differ materially from that discussed in Note 7 of the Notes to Consolidated Financial Statements of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009. Refer to Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements for any updates to our quantitative and qualitative disclosures about market risk.

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        The following tables provide information on the volume of our commodity derivative activity for positions related to long liquids and keep-whole price risk entered into subsequent to June 30, 2010.

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)
2012		807	$	81.45
2013		831		82.28

        The following tables provide information on the volume of our taxable subsidiary's commodity derivative activity for positions related to keep-whole price risk entered into subsequent to June 30, 2010.

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)
2012		567	$	87.26

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)
2012		3,113	$	5.70

Interest Rate Risk

        The information about interest rate risk for the six months ended June 30, 2010 does not differ materially from that discussed in Item 7A.Quantitative and Qualitative Disclosures about Market Risk of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2009.

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 June 30, 2010. Based on this evaluation, the Partnership's management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of June 30, 2010, 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 June 30, 2010 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 9 of the accompanying Notes to the Condensed Consolidated Financial Statements for information regarding legal proceedings.

Item 1A.    Risk Factors

        There were no material changes in our risk factors as disclosed in Item 1A.Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2009, except as set forth below.

The enactment of the Dodd-Frank Act could have an adverse impact on our ability to hedge risks associated with our business.

        In July 2010, Congress enacted and the President signed broad financial regulatory reform legislation that, among other things, will impose comprehensive regulation on the OTC derivatives marketplace and will affect the use of derivatives in hedging transactions. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") will subject "swap dealers" and "major swap participants" to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also will require central clearing for transactions unless one of the parties is not a swap dealer or major swap participant, is using the transaction to hedge commercial risk and elects not to clear the transaction under the so-called "end-user" exemption. However, the "end-user" exemption does not expressly extend to margin requirements, and uncleared transactions may still be subject to regulated margin requirements. The Dodd-Frank Act delegates significant authority to generally regulate and develop implementing regulations for OTC commodity derivatives to the Commodity Futures Trading Commission ("CFTC") and the SEC, including express authority to impose position limits for derivatives related to energy commodities. Separately, in late January 2010, the CFTC proposed regulations that would impose speculative position limits for certain futures and option contracts in natural gas, crude oil, heating oil, and gasoline. These proposed regulations would make an exemption available for certainbona fide hedging of commercial risks. The Dodd-Frank Act and regulations promulgated thereunder will generally become effective one year after the date of enactment of the Act. While we know the substance of the Dodd-Frank Act, it is not possible at this time to predict the final form and substance of the CFTC or the SEC regulations that must be adopted to carry out the Act. The CFTC and the SEC must adopt regulations within one year from the date of enactment of the Dodd-Frank Act. Any such regulations that subject us or our counterparties to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity. We may be unable to hedge a significant portion of our exposure to commodity price risk which could have a material adverse impact on our income from operations, cash flows and quarterly distribution to common unitholders.

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Item 6.    Exhibits

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 June 30, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Statements of Changes in Equity, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

*

Filed herewith

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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: August 9, 2010	/s/ FRANK M. SEMPLE Frank M. Semple Chairman, President and Chief Executive Officer (Principal Executive Officer)
Date: August 9, 2010	/s/ NANCY K. BUESE Nancy K. Buese Senior Vice President & Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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