Markwest Energy Partners L P 10-Q 2009 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, 2009
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 o    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. (Check one):

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). Yeso Noý

        The number of the registrant's common units outstanding as of August 3, 2009, was 60,240,782.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets at June 30, 2009 and December 31, 2008	2
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2009 and 2008	3
	Unaudited Condensed Consolidated Statement of Changes in Partners' Capital for the six months ended June 30, 2009	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2009 and 2008	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	60
Item 4.	Controls and Procedures	61
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 3.	Defaults Upon Senior Securities	63
Item 4.	Submission of Matters to a Vote of Security Holders	63
Item 5.	Other Information	64
Item 6.	Exhibits	64
SIGNATURES		65

        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. prior to the redemption and merger completed on February 21, 2008.

Glossary of Terms

        The abbreviations, acronyms and industry technology used in this quarterly report are defined as follows.

ARB	Accounting Research Bulletin
Bbl/d	Barrels of oil per day
Btu	One British thermal unit, an energy measurement
Dth/d	Dekatherms per day
EBITDA	Earnings Before Interest, Taxes, Depreciation and Amortization
EITF	Emerging Issues Task Force
FERC	Federal Energy Regulatory Commission
FASB	Financial Accounting Standards Board
FSP	FASB Staff Position
GAAP	Accounting principles generally accepted in the United States of America
Gal/d	Gallons per day
LIBOR	London Interbank Offered Rate
Mcf/d	One thousand cubic feet of natural gas per day
Merger	On February 21, 2008, the Partnership completed the transactions contemplated by its plan of redemption and merger with MarkWest Hydrocarbon, Inc. and MWEP, L.L.C., a wholly-owned subsidiary of the Partnership. Refer to Note 3 of the Partnership's December 31, 2008 Annual Report on Form 10-K as modified by the Current Report on Form 8-K as filed with the SEC on May 18, 2009.
MMBtu	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
SFAS	Statement of Financial Accounting Standards
1996 Hydrocarbon Plan	1996 Hydrocarbon Stock Incentive Plan
2002 LTIP	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, 2009			December 31, 2008
ASSETS
Current assets:
	Cash and cash equivalents		$	56,455		$	3,321
	Receivables and other current assets			135,376			145,153
	Fair value of derivative instruments			25,294			126,949
		Total current assets		217,125			275,423
Property, plant and equipment				1,938,602			1,650,692
Less: accumulated depreciation				(122,986	)		(81,167	)
		Total property, plant and equipment, net		1,815,616			1,569,525
Other long-term assets:
	Intangibles, net of accumulated amortization of $63,349 and $42,972, respectively			674,798			695,917
	Fair value of derivative instruments			27,468			55,389
	Other long-term assets			95,305			76,800
		Total other long-term assets		797,571			828,106
		Total assets	$	2,830,312		$	2,673,054
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
	Fair value of derivative instruments		$	47,629		$	37,633
	Other current liabilities			169,172			186,553
		Total current liabilities		216,801			224,186
Deferred income taxes				12,148			47,465
Fair value of derivative instruments				32,861			14,801
Long-term debt, net of discounts of $43,688 and $11,735, respectively				1,339,546			1,172,965
Other long-term liabilities				9,189			5,878
Commitments and contingencies (Note 17)
Partners' Capital:
	MarkWest Energy Partners, L.P. partners' capital (60,229 and 56,640 common units outstanding, respectively)			1,081,037			1,204,458
	Non-controlling interest in consolidated subsidiaries			138,730			3,301
		Total partners' capital		1,219,767			1,207,759
		Total liabilities and partners' capital	$	2,830,312		$	2,673,054

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,
			2009			2008			2009			2008
Revenue:
	Revenue		$	185,000		$	278,158		$	368,367		$	563,200
	Derivative loss			(83,235	)		(312,591	)		(74,931	)		(358,841	)
		Total revenue		101,765			(34,433	)		293,436			204,359
Operating expenses:
	Purchased product costs			80,652			153,273			182,966			308,208
	Derivative loss (gain) related to purchased product costs			2,625			(47,097	)		32,138			(79,094	)
	Facility expenses			32,336			24,762			63,780			47,428
	Derivative gain related to facility expenses			(854	)		(310	)		(1,225	)		(353	)
	Selling, general and administrative expenses			14,861			16,614			30,788			39,075
	Depreciation			23,414			16,498			44,357			31,023
	Amortization of intangible assets			10,212			10,469			20,445			17,318
	Other operating expenses			114			33			890			68
	Impairment of long-lived assets			5,855			5,009			5,855			5,009
		Total operating expenses		169,215			179,251			379,994			368,682
		Loss from operations		(67,450	)		(213,684	)		(86,558	)		(164,323	)
Other income (expense):
	Earnings from unconsolidated affiliates			1,196			577			1,091			2,128
	Interest expense			(22,742	)		(17,450	)		(40,524	)		(28,599	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(2,046	)		(5,164	)		(3,437	)		(6,207	)
	Other income			2,443			2,837			1,822			3,318
		Loss before provision for income tax		(88,599	)		(232,884	)		(127,606	)		(193,683	)
Provision for income tax (benefit) expense:
	Current			323			4,565			6,576			15,332
	Deferred			(19,726	)		(59,682	)		(35,317	)		(47,006	)
		Total provision for income tax		(19,403	)		(55,117	)		(28,741	)		(31,674	)
		Net loss		(69,196	)		(177,767	)		(98,865	)		(162,009	)
Net loss attributable to non-controlling interest				1,690			—			1,710			3,393
		Net loss attributable to the Partnership	$	(67,506	)	$	(177,767	)	$	(97,155	)	$	(158,616	)
Net loss attributable to the Partnership's common unitholders (Note 15):
	Basic		$	(1.18	)	$	(3.20	)	$	(1.71	)	$	(3.51	)
	Diluted		$	(1.18	)	$	(3.20	)	$	(1.71	)	$	(3.51	)
Weighted average number of outstanding common units:
	Basic			57,603			55,742			57,207			45,326
	Diluted			57,603			55,742			57,207			45,326
Cash distribution declared per common unit(1)			$	0.64		$	0.60		$	1.28		$	0.79

(1)

Under the Merger, the shareholders of the Corporation exchanged each share of Corporation common stock for consideration equal to 1.9051 Partnership common units (the "Exchange Ratio"). The first quarter 2008 distribution represents MarkWest Hydrocarbon's dividend as adjusted to reflect the Exchange Ratio to give effect to the Merger.

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

3

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statement of Changes in Partners' Capital

(unaudited, in thousands)

	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
Common units issued for vested phantom units		254		608			—			608
Distributions paid		—		(73,596	)		—			(73,596	)
Share-based compensation related to equity awards		—		2,257			—			2,257
Issuance of units in public offering, net of offering costs		3,335		57,665			—			57,665
Net proceeds from sale of equity interest in joint ventures		—		(7,311	)		131,250			123,939
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,
			2009			2008
Net cash provided by operating activities			$	114,847		$	163,958
Cash flows from investing activities:
	Change in restricted cash			(25	)		—
	Equity investments			(4,984	)		(23,620	)
	Cash paid to acquire General Partnership's non-controlling interest			—			(21,484	)
	Cash paid in Merger for MarkWest Hydrocarbon, Inc. stock			—			(248,395	)
	Proceeds from sale of available for sale securities			—			6,226
	Capital expenditures			(320,788	)		(172,188	)
	Proceeds from disposal of property, plant and equipment			—			8
		Net cash flows used in investing activities		(325,797	)		(459,453	)
Cash flows from financing activities:
	Proceeds from long-term debt			541,700			958,234
	Payments of long-term debt			(376,600	)		(515,001	)
	Payments for debt issuance costs, deferred financing costs and registration costs			(7,825	)		(21,155	)
	Proceeds from public offering, net			57,665			171,395
	Net proceeds from sale of equity interest in joint ventures			123,939			—
	Share-based payment activity			(1,199	)		1,092
	Payment of distributions and dividends			(73,596	)		(38,801	)
	Distributions to MarkWest Energy unitholders prior to the Merger			—			(19,651	)
		Net cash flows provided by financing activities		264,084			536,113
Net increase in cash				53,134			240,618
Cash and cash equivalents at beginning of year				3,321			37,695
Cash and cash equivalents at end of period			$	56,455		$	278,313
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized			$	38,174		$	19,141
Cash paid for income taxes				1,971			9,603
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment			$	28,656		$	32,851
Interest capitalized on construction in progress				7,136			2,654
Property, plant and equipment asset retirement obligation				397			9
Merger step-up of fair value				—			605,100
Issuance of common units for vesting of share-based payment awards				8,683			1,997

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 on January 25, 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 natural gas liquids, or 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 the context of the consolidated financial statements accompanying notes included in the Partnership's December 31, 2008 Annual Report on Form 10-K as modified by the Current Report on Form 8-K as filed with the SEC on May 18, 2009 for the retrospective applications of SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB 51 ("SFAS 160") and FSP EITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities ("FSP EITF 03-6-1"). The presentation of the condensed consolidated statements has been updated to conform to the requirements of SFAS 160 and FSP EITF 03-6-1. 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, 2009 are not necessarily indicative of results for the full year 2009, or any other future period.

        The Partnership's condensed consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Liberty Midstream & Resources L.L.C. ("MarkWest Liberty Midstream") and MarkWest Pioneer, L.L.C. ("MarkWest Pioneer"), variable interest entities for which the Partnership has been determined to be the primary beneficiary, are included in the condensed consolidated financial statements (see Note 4 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, and is not the primary beneficiary, are accounted for using the equity method.

2. Significant Accounting Policies

        There have not been any material changes during the six months ended June 30, 2009 to the significant accounting policies previously disclosed in the Partnership's 2008 Annual Report on Form 10-K as modified by the Current Report on Form 8-K as filed with the SEC on May 18, 2009 for the retrospective applications of SFAS 160 and FSP EITF 03-6-1 except for the following items related to the application of SFAS No. 71,Accounting for the Effects of Certain Types of Regulation by certain of the Partnership's regulated operations and the accounting for embedded derivatives related to long-term debt under SFAS No. 133,Accounting for Derivatives and Hedging Activities ("SFAS 133").

6

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

2. Significant Accounting Policies (Continued)

Property, Plant and Equipment for FERC Regulated Assets

        Depreciation is generally computed over the asset's estimated useful life using the straight-line method. The composite weighted-average depreciation rates will be 4% for 2009. When the Partnership retires its regulated property, plant and equipment, the Partnership charges the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization.

Allowance for Funds Used During Construction

        Allowance for funds used during construction ("AFUDC"), which represents the estimated debt and equity costs of capital funds necessary to finance the construction and expansion of regulated facilities, consists of an equity component and an interest expense component. The equity component is a non-cash item. AFUDC is capitalized as a component of property, plant and equipment, with offsetting credits to the Condensed Consolidated Statements of Operations included inOther income for the equity component andInterest expense for the interest component. After construction is completed, the Partnership is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Condensed Consolidated Statements of Operations was $4.4 million for the six months ended June 30, 2009 (an equity component of $2.2 million and an interest expense component of $2.2 million).

Embedded Derivatives Related to Long-Term Debt

        The fair value of embedded derivatives related to long-term debt is included as a component ofLong-term debt in the Condensed Consolidated Balance Sheet. Changes in the fair value of embedded derivatives related to long-term debt are recorded throughOther income in the Condensed Consolidated Statements of Operations.

3. Recent Accounting Pronouncements

        In May 2009 the FASB issued SFAS No. 165,Subsequent Events ("SFAS 165") which provides guidance on management's assessment of subsequent events. SFAS 165 clarifies that management must evaluate, as of each reporting period, events or transactions that occur after the balance sheet date through the date that the financial statements are issued or are available to be issued. SFAS 165 is effective for the Partnership as of the period ended June 30, 2009. The adoption of SFAS 165 did not have a material impact on the Partnership's financial statements.

        In June 2009 the FASB issued SFAS No. 167,Amendments to FASB Interpretation No. 46(R) ("SFAS 167") which amends the consolidation guidance that applies to Variable Interest Entities ("VIEs"). The amendments will significantly affect the overall consolidation analysis under GAAP. Specifically, the Partnership must reconsider its previous VIE conclusions and what types of financial statement disclosures are appropriate. SFAS 167 is effective for the Partnership on January 1, 2010. The Partnership is currently evaluating the impact of SFAS 167 on its financial statements.

        In June 2009 the FASB issued SFAS No. 168,The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles—A Replacement of Statement No. 162 which identifies the FASB Accounting Standards Codification (the "FASB Codification") as the source of authoritative GAAP. Once the FASB Codification is in effect, all of the FASB's content will carry the

7

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

3. Recent Accounting Pronouncements (Continued)

same level of authority. The FASB Codification is effective for the Partnership for the interim period beginning July 1, 2009. The adoption of the FASB Codification is not expected to have a material impact on the Partnership's financial statements but will change the way in which the Partnership references GAAP.

4. Variable Interest Entities

MarkWest Liberty Midstream

        On February 27, 2009, the Partnership entered into a joint venture with M&R MWE Liberty L.L.C. ("M&R"), an affiliate of NGP Midstream & Resources, L.P. which is a private equity firm focused on investments in selected areas of the energy infrastructure and natural resources sectors. The joint venture entity, MarkWest Liberty Midstream, operates in the natural gas midstream business in and around the Marcellus Shale in western Pennsylvania and northern West Virginia. The Partnership contributed its existing Marcellus Shale natural gas gathering and processing assets to MarkWest Liberty Midstream in exchange for a 60% ownership interest. The agreed-to value and net book value of the contributed assets was approximately $107.5 million. At closing, M&R contributed cash of $50.0 million in exchange for a 40% ownership interest. A wholly-owned subsidiary of the Partnership will serve as the operator of MarkWest Liberty Midstream and will provide the field operating and general and administrative services. A portion of the fee for providing these services is fixed. The Partnership is in the process of allocating net assets and such allocation and the value of contributed assets is subject to further adjustment.

        The Partnership has determined that MarkWest Liberty Midstream is a variable interest entity primarily due to the insufficiency of equity, as defined by FASB Interpretation No. 46(R),Consolidation of Variable Interest Entities, an interpretation of ARB No. 51 ("FIN 46R"), at its inception as evidenced by the capital requirements outlined below. The Partnership is considered the primary beneficiary due mainly to its 60% share of profits and losses relative to the equal participation by both members in certain management decisions. The Partnership assumes additional variability based on its compensation as the operator of MarkWest Liberty Midstream. The Partnership's maximum exposure to loss as a result of its involvement with MarkWest Liberty Midstream includes its equity investment, the additional capital contribution commitments and any operating expense in excess of its compensation as the operator of MarkWest Liberty Midstream. MarkWest Liberty Midstream has no debt and will be funded entirely by the Partnership and M&R.

        M&R contributed an additional $50.0 million in April 2009 and will contribute at least an additional $100.0 million during the remainder of 2009 to fund the capital expenditures of MarkWest Liberty Midstream. If MarkWest Liberty Midstream capital expenditures in 2009 exceed M&R's quarterly contributions, the Partnership would be required to fund the excess. The Partnership contributed approximately $12.9 million to MarkWest Liberty Midstream during the six months ended June 30, 2009. Due to M&R's financing of the majority of 2009 capital expenditures, the capital contributed to MarkWest Liberty Midstream will be disproportionate to each party's respective ownership interests. Under the terms of the joint venture agreement, the Partnership will make additional capital contributions to fund MarkWest Liberty Midstream's capital expenditures between January 1, 2010 and December 31, 2011 in order for the Partnership's share of contributed capital to be proportionate to its ownership interest. MarkWest Liberty Midstream's capital plan for 2010 and 2011

8

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Variable Interest Entities (Continued)

has not been finalized and the exact timing of these contributions is currently uncertain. If the Partnership has not contributed capital in proportion to its ownership interest by the end of 2011, M&R may require the Partnership to contribute the amount of the shortfall at December 31, 2011, or may allow the Partnership to continue to fund 100% of MarkWest Liberty Midstream's capital expenditures until its total contributed capital is proportionate to its 60% ownership interest. After the date at which each party's contributed capital is proportionate to its respective ownership interest, M&R will have the option to fund future capital expenditures in relation to its ownership interest or have its ownership interest diluted to the extent that it elects not to fund its proportionate share. Refer to Note 21 for discussion of potential modification of MarkWest Liberty Midstream's limited liability company agreement ("LLC agreement").

MarkWest Pioneer

        On May 1, 2009, the Partnership entered into a joint venture with Arkoma Pipeline Partners, L.L.C. ("ArcLight"), an affiliate of ArcLight Capital Partners, L.L.C. which is an investment firm focused on opportunities throughout the energy industry. ArcLight acquired a 50% equity interest in MarkWest Pioneer for a total purchase price of $62.5 million. At closing, ArcLight contributed cash of $31.25 million and has an obligation to fund an additional $31.25 million on the pipeline's commercial operations date (see Note 21). The Partnership retains a 50% equity interest and is obligated to fund all capital expenditures necessary to complete construction of the Arkoma Connector Pipeline in excess of $125.0 million (the "Excess Capital Expenditures").

        MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline, a 50-mile interstate pipeline that will provide approximately 638,000 Dth/d of Woodford Shale takeaway capacity and interconnects with the Midcontinent Express Pipeline and Gulf Crossing Pipeline. A wholly-owned subsidiary of the Partnership will serve as the operator of MarkWest Pioneer and will provide the field operating and general and administrative services for fixed fees.

        The Partnership has determined that MarkWest Pioneer is a variable interest entity under FIN 46R. This determination is based primarily on disproportionate economic interests as compared to voting interests. The Partnership has economic interests that do not match its 50% voting interest due to its obligation to fund the Excess Capital Expenditures.

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 Partnership has not provided any financial support that it was not contractually obligated to provide.

9

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

4. Variable Interest Entities (Continued)

        The Partnership reflected the following amounts in its Condensed Consolidated Balance Sheet for MarkWest Liberty Midstream and MarkWest Pioneer (in thousands):

			As of June 30, 2009
			MarkWest Liberty Midstream		MarkWest Pioneer
ASSETS
	Receivables and other current assets		$	9,693	$	—
	Property, plant and equipment, net of accumulated depreciation of $3,137 and $0, respectively			223,892		146,264
	Other long-term assets			7,215		—
		Total assets	$	240,800	$	146,264
LIABILITIES
	Other current liabilities		$	19,245	$	17,028
	Other long-term liabilities			76		—
		Total liabilities	$	19,321	$	17,028

        The assets of MarkWest Liberty Midstream and MarkWest Pioneer are the property of the respective ventures and are not available to the Partnership for any other purpose, including collateral for its secured debt (see Note 11 and Note 19). The liabilities of MarkWest Liberty Midstream and MarkWest Pioneer do not represent additional claims against the Partnership's general assets. The Partnership's Liberty segment includes the results of operations of MarkWest Liberty Midstream (see Note 18). The Partnership's Southwest segment includes the results of operations of MarkWest Pioneer (see Note 18). The cash flow information for MarkWest Liberty Midstream and MarkWest Pioneer comprise substantially all of the cash flow information of non-guarantors (see Note 19).

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

		Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
Net loss attributable to the Partnership		$	(67,506	)	$	(97,155	)
Transfers to the non-controlling interests:
	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 to Partners' Capital for transfer to non-controlling interest from sale of equity interest in MarkWest Pioneer		(5,889	)		(5,889	)
Net loss attributable to the Partnership and transfers to the non-controlling interests		$	(75,242	)	$	(110,355	)

10

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. 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 and Condensed Consolidated Statements of Operations. Accordingly, the volatility in any given period related to unrealized gains or losses 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.

        To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has primarily entered into derivative financial instruments relating to the future price of 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 all of the risk management activity and continually monitors the risk management program and expects to continue to adjust its financial positions as conditions warrant.

        To manage its commodity price risk, the Partnership utilizes a combination of fixed-price forward contracts, fixed-for-floating price swaps and options available in 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 where deemed necessary. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements). Due to the timing of purchases and sales, direct exposure to price volatility may result because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through marketing and derivative activities, direct price exposure may occur naturally or the Partnership may choose direct exposure when it is favorable as compared to the keep-whole risk.

        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) sales volumes are less than expected, requiring market purchases to meet commitments, 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 similarly insulated against unfavorable changes in such prices.

11

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Derivative Financial Instruments (Continued)

        The Partnership's Credit Agreement limits its ability to enter into transactions with parties that require margin calls under certain derivative instruments and prevents members of the participating bank group from requiring margin calls. As of June 30, 2009 approximately 7% of the Partnership's derivative positions, measured volumetrically, are with non-bank group counterparties and are subject to margin deposit requirements under OTC agreements that it plans to meet with letters of credit, if necessary. In the unlikely event that the Partnership were unable to meet these margin calls with letters of credit, it would be forced to terminate the corresponding contracts.

        The Partnership values its derivative instruments and estimates fair value as discussed in Note 6. The Partnership has not designated any of its instruments as cash flow or fair value hedges. The Partnership did not designate any contracts as normal purchase or sales contracts.

Other Contracts

Embedded Derivatives Related to Long-Term Debt

        On May 26, 2009, the Partnership completed the private placement of senior notes with two contingent written put options as described in Note 11. The written put options are considered embedded derivatives and are not considered clearly and closely related to the indenture. In accordance with GAAP, when a hybrid contract contains more than one embedded derivative requiring separate accounting, the embedded derivatives must be aggregated and accounted for as one compound embedded derivative. The initial fair value of the compound embedded derivative in the indenture (the "Compound Derivative") is recorded as a component ofLong-term debt in the Condensed Consolidated Balance Sheets with a corresponding increase in the recorded balance of the original issue discount related to the senior notes issued in May 2009. See Note 6 for a discussion on the methodology used to determine the fair value of the Compound Derivative.

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

			Asset Derivatives				Liability Derivatives
Derivative contracts not designated as hedging instruments under SFAS 133 and their balance sheet location			Fair Value at June 30, 2009		Fair Value at December 31, 2008		Fair Value at June 30, 2009			Fair Value at December 31, 2008
Commodity Contracts
	Fair value of derivative instruments—current		$	25,294	$	126,949	$	(47,629	)	$	(37,633	)
	Fair value of derivative instruments—long-term			27,468		55,389		(32,861	)		(14,801	)
Other Contracts
	Long-term debt			—		—		(435	)		—
		Total	$	52,762	$	182,338	$	(80,925	)	$	(52,434	)

12

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Derivative Financial Instruments (Continued)

			Three months ended June 30,						Six months ended June 30,
Derivative contracts not designated as hedging instruments under SFAS 133 and the location of gain or (loss) recognized in income
			2009			2008			2009			2008
Revenue: Derivative gain (loss)
	Realized gain (loss)		$	15,299		$	(23,805	)	$	76,413		$	(42,764	)
	Unrealized loss			(98,534	)		(288,786	)		(151,344	)		(316,077	)
		Total Revenue: derivative loss		(83,235	)		(312,591	)		(74,931	)		(358,841	)
Derivative gain (loss) related to purchased product costs
	Realized (loss) gain			(11,009	)		8,582			(27,259	)		8,439
	Unrealized gain (loss)			8,384			38,515			(4,879	)		70,655
		Total derivative (loss) gain related to purchased product costs		(2,625	)		47,097			(32,138	)		79,094
Derivative gain related to facility expenses
	Unrealized gain			854			310			1,225			353
Other income
	Unrealized gain			91			—			91			—
		Total	$	(84,915	)	$	(265,184	)	$	(105,753	)	$	(279,394	)

        The change in market value of commodity derivatives, realized and unrealized, is recorded as a component of revenue, purchased product costs or facility expenses. Revenue gains and losses relate to contracts utilized to economically hedge the cash flow for the sale of a product. Purchased product costs gains and losses relate to contracts utilized to economically hedge costs, typically in a keep-whole arrangement. Facility expenses gains and losses relate to a contract utilized to economically hedge electricity costs for a facility. The unrealized gain or loss related to changes in the fair value of the Compound Derivative is recorded inOther income in the accompanying Condensed Consolidated Statements of Operations.

        At June 30, 2009, the fair value of the Partnership's commodity derivative instruments is inclusive of premium payments of $10.7 million, net of amortization. The Partnership amortizes the premium payments over the effective term of the underlying derivative commodity option contracts through realized loss. For the three months ended June 30, 2009 and 2008, the Realized gain (loss)—revenue includes amortization of premium payments of $1.4 million and $0.3 million, respectively. For the six months ended June 30, 2009 and 2008, the Realized gain (loss)—revenue includes amortization of premium payments of $2.6 million and $0.4 million, respectively.

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 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 and

13

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Derivative Financial Instruments (Continued)

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. The aggregate fair value of all derivative instruments with a credit risk related contingent feature that is in a liability position at June 30, 2009 is $5.5 million; however, for all outstanding transactions with this counterparty, the Partnership has a net asset position of $3.2 million. If the credit risk contingent feature was triggered as of June 30, 2009, 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.

Outstanding Derivative Contracts

        The following tables provide information on the volume of the Partnership's commodity derivative activity for positions related to long liquids and keep-whole price risk at June 30, 2009, including the weighted average prices ("WAVG"):

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2009		3,425	$	67.50	$	77.83	$	(511	)
2010 (Apr - Dec)		1,297		66.48		74.49		(1,650	)
2011		822		60.00		80.13		(1,945	)
2012		822		60.00		85.87		(1,809	)

WTI Crude Puts	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		Fair Value (in thousands)
2009		2,279	$	80.00	$	4,469
2010		1,191		80.00		5,357
2011		1,818		80.00		8,725

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2009		1,526	$	119.49	$	13,319
2010		2,094		65.56		(7,127	)
2011		535		68.20		(1,921	)
2012		529		70.30		(1,785	)

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2009		10,505	$	8.37	$	(8,921	)

14

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

5. Derivative Financial Instruments (Continued)

        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, 2009, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2009		3,578	$	69.85	$	(1,608	)
2010		2,428		70.25		(4,274	)
2011		3,027		87.66		9,924
2012 (Jan)		2,142		91.50		754

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2009		21,572	$	7.81	$	(13,983	)
2010		7,412		10.91		(12,590	)
2011		14,662		8.88		(9,984	)

        The Partnership has a commodity contract with a producer in the Appalachia region which creates a floor on the frac spread for gas purchases of 9,000 Dth/d. Under SFAS 133, the value of this contract is marked based on an index price through purchased product costs. As of June 30, 2009, the estimated fair value of this contract was $(2.8) million.

        The Partnership has a commodity contract which gives it an option to fix a component of the utilities cost to an index price on electricity at one of its plant locations. Under SFAS 133, the value of the derivative component of this contract is marked to market through facility expense. As of June 30, 2009, the estimated fair value of this contract was $0.6 million.

        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 does not represent trading activity. The settlement was recorded as $26.5 million of realized gains in Realized (loss) gain—revenue and $11.3 million loss is included in Realized gain (loss)—purchased product costs in the accompanying Condensed Consolidated Statements of Operations.

15

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

6. Fair Value

        The following table presents the financial instruments carried at fair value as of June 30, 2009 and December 31, 2008 and by SFAS 157 valuation hierarchy (in thousands):

	Assets
					Liabilities
	Trading Securities
As of June 30, 2009			Derivatives		Derivatives
Quoted prices in active markets for identical assets (Level 1)	$	—	$	—	$	—
Significant other observable inputs (Level 2)		—		28,801		(66,998	)
Significant unobservable inputs (Level 3)		—		23,961		(13,927	)
Total carrying value in Condensed Consolidated Balance Sheet	$	—	$	52,762	$	(80,925	)

	Assets
					Liabilities
	Trading Securities
As of December 31, 2008			Derivatives		Derivatives
Quoted prices in active markets for identical assets (Level 1)	$	—	$	—	$	—
Significant other observable inputs (Level 2)		—		106,826		(49,378	)
Significant unobservable inputs (Level 3)		512		75,512		(3,056	)
Total carrying value in Condensed Consolidated Balance Sheet	$	512	$	182,338	$	(52,434	)

Compound Derivative

        The Partnership uses an interest rate lattice model to estimate the fair value of the Compound Derivative. The model incorporates assumptions about the evolution of interest rates and management's estimates about the probability of specific events occurring in the future. Management's estimates and the assumptions included in the model are considered significant unobservable inputs. Accordingly, the Partnership has classified the Compound Derivative as a Level 3 fair value measurement. See Note 5 for a discussion of the separate accounting for the Compound Derivative under GAAP and Note 11 for a description of the two contingent written put options that comprise the Compound Derivative.

Changes in Level 3 Fair Value Measurements

        The tables below include a rollforward of the balance sheet amounts for the three and six months ended June 30, 2009 and 2008 (including the change in fair value) for financial instruments classified by the Partnership within Level 3 of the valuation hierarchy (in thousands). When a determination is made to classify a financial instrument within Level 3 of the valuation hierarchy, the determination is based upon the significance of the unobservable inputs to the overall fair value measurement. However, Level 3 financial instruments typically include, in addition to the unobservable or Level 3 inputs, observable inputs (that is, inputs that are actively quoted and can be validated to external sources); accordingly, the gains and losses in the tables below include changes in fair value due in part to observable inputs that are part of the valuation methodology. Level 3 financial instruments include the Compound Derivative and all NGL transactions and crude oil options as they have significant

16

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

6. Fair Value (Continued)

unobservable market parameters. Additionally, NGL transactions and crude oil options are also traded less actively. For the period ended June 30, 2008 the Partnership considered options to be Level 2. After further consideration, options are considered Level 3 due to significant unobservable inputs. Therefore, the rollforwards presented below for the three and six months ended June 30, 2009 include options.

	Three Months Ended
	June 30, 2009					June 30, 2008
	Trading Securities		Derivatives (net)			Trading Securities		Derivatives (net)
Fair Value at Beginning of Period	$	—	$	51,672		$	1,198	$	(64,150	)
Total gain or loss (realized and unrealized) included in earnings(a)(b)		—		(34,819	)		—		(140,495	)
Purchases, sales, issuances and settlements (net)		—		(6,819	)		—		17,292
Transfers in or out of Level 3 (net)		—		—			—		—
Fair Value at End of Period	$	—	$	10,034		$	1,198	$	(187,353	)
The amount of total gains or losses for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at June 30, 2009 and 2008, respectively(a)	$	—	$	(34,075	)	$	—	$	(128,383	)

	Six Months Ended
	June 30, 2009						June 30, 2008
	Trading Securities			Derivatives (net)			Trading Securities			Derivatives (net)
Fair Value at Beginning of Period	$	512		$	72,456		$	3,674		$	(84,367	)
Total gain or loss (realized and unrealized) included in earnings(a)(b)		40			(35,636	)		(76	)		(152,481	)
Purchases, sales, issuances and settlements (net)		(552	)		(26,786	)		(2,400	)		49,495
Transfers in or out of Level 3 (net)		—			—			—			—
Fair Value at End of Period	$	—		$	10,034		$	1,198		$	(187,353	)
The amount of total gains or losses for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at June 30, 2009 and 2008, respectively(a)	$	—		$	(41,360	)	$	—		$	(123,694	)

(a)

See Note 5 for the financial statement presentation of gains and losses on derivatives.

(b)

Gains and losses on trading securities are realized and recorded inOther income.

17

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

6. Fair Value (Continued)

Assets and liabilities measured at fair value on a nonrecurring basis

        Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the instruments are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. As of June 30, 2009, certain long-lived assets of Wirth Gathering Partnership ("Wirth"), a consolidated subsidiary, were required to be measured at fair value in accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-lived Assets. Property, plant and equipment and intangible assets with a net book value of $5.2 million and $0.7 million, respectively, were written down to an estimated fair value of zero, resulting in an impairment charge of $5.9 million. The Partnership estimated the fair value of these assets based on an income approach using significant unobservable inputs (Level 3). See Note 9 for further discussion of the impairment.

7. Inventories

        Inventories is included inReceivables and other current assets in the Condensed Consolidated Balance Sheet. Inventories consist of the following (in thousands):

		June 30, 2009		December 31, 2008
Natural gas and natural gas liquids		$	16,436	$	29,171
Spare parts			8,508		2,385
	Total inventories	$	24,944	$	31,556

8. Goodwill

        The Partnership's $9.4 million goodwill balance as of June 30, 2009 and December 31, 2008 consisted of $3.9 million allocated to the Northeast segment and $5.5 million allocated to the Southwest segment. The goodwill balance is included inOther long-term assets in the Condensed Consolidated Balance Sheet. In accordance with SFAS No. 142,Goodwill and Other Intangible Assets, goodwill is not amortized but instead tested for impairment annually on November 30, or more frequently when events and circumstances occur indicating that the recorded goodwill may not be recoverable. As of June 30, 2009, the Partnership did not test goodwill for impairment as there were no indicators that the goodwill balance may not be recoverable.

9. Impairment of Long-Lived Assets

        The Partnership's policy is to evaluate whether there has been an impairment in the value of long-lived assets when certain events indicate that the remaining balance may not be recoverable. The Partnership evaluates the carrying value of its property, plant and equipment on at least a segment level and at lower levels where the cash flows for specific assets can be identified.

        An analysis completed during the second quarter of 2009 indicated that the future estimated operating cash flows could be at or below zero for Wirth which operates a small natural gas gathering system included in the Partnership's Southwest segment. The Partnership owns a 50% interest in Wirth and consolidates its assets, liabilities, and results of operations in the accompanying Condensed Consolidated Financial Statements. Wirth's expected future cash flows were adversely impacted by a

18

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

9. Impairment of Long-Lived Assets (Continued)

significant reduction to the primary producer's drilling plan disclosed in the second quarter of 2009, as well as increased operating expenses resulting from an agreement reached in May 2009 with the non-controlling partner. The Partnership used the income approach for determining the assets' fair value and recognized an impairment of long-lived assets of approximately $5.9 million for the three and six months ended June 30, 2009. After considering the impact of the non-controlling interest, the impairment increased the net loss attributable to the Partnership for the three and six months ended June 30, 2009 by approximately $2.9 million, before provision for income tax.

        An analysis completed during the second quarter of 2008 indicated that the future estimated operating cash flows would be below zero for the Partnership's gas-gathering assets in Manistee County, Michigan, which are part of the Partnership's Northeast segment, due to the decision to move the Fisk plant to Pennsylvania and to outsource the gas processing to a third party. The Partnership used the income approach for determining the assets' fair value and recognized an impairment of long-lived assets of $5.0 million for the three and six months ended June 30, 2008.

10. Investments in Unconsolidated Affiliates

        The Partnership's investment in its unconsolidated affiliates, Starfish Pipeline Company, L.L.C. ("Starfish") and Centrahoma Processing L.L.C. ("Centrahoma"), is included inOther long-term assets in the accompanying Condensed Consolidated Balance Sheet. The Partnership's share of income from its investments in unconsolidated affiliates is included inEarnings from unconsolidated affiliates in the accompanying Condensed Consolidated Statements of Operations.

        Summarized financial information for 100% of Starfish and the Partnership's share of Starfish's net income is as follows (unaudited, in thousands):

	Three months ended June 30,				Six months ended June 30,
	2009		2008		2009		2008
Revenues	$	7,691	$	6,656	$	14,070	$	14,377
Operating income		4,877		1,329		8,287		4,199
Net income		2,154		1,369		2,974		4,542
Partnership's share of net income	$	1,077	$	612	$	1,445	$	2,126

        In addition, the Partnership received approximately $0.6 million in June 2009 from the settlement of certain insurance claims related to damage and business interruption caused by Hurricane Ike in 2008. The insurance settlements are included inOther income in the Condensed Consolidated Statements of Operations.

19

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

10. Investments in Unconsolidated Affiliates (Continued)

        Summarized financial information for 100% of Centrahoma and the Partnership's share of Centrahoma's net income (loss) is as follows (unaudited, in thousands):

	Three months ended June 30,					Six months ended June 30,
	2009		2008			2009			2008
Revenues	$	2,480	$	1,642		$	4,199		$	2,045
Operating income (loss)		1,872		(188	)		1,768			(4	)
Net income (loss)		295		(188	)		(886	)		(4	)
Partnership's share of net income (loss)	$	119	$	(35	)	$	(354	)	$	2

        The table below shows the carrying value of the Partnership's investments in unconsolidated affiliates (in thousands):

		June 30, 2009		December 31, 2008
Investment in Starfish		$	22,437	$	17,181
Investment in Centrahoma			29,730		28,911
	Total investment in unconsolidated affiliates	$	52,167	$	46,092

11. Long-Term Debt

        Long-term debt is summarized below (in thousands):

			June 30, 2009		December 31, 2008
Credit Facility
	Revolver facility, 4.79% and 2.51% interest at June 30, 2009 and December 31, 2008, respectively, due February 2012		$	232,800	$	184,700
Senior Notes (collectively the "Senior Notes")
	Senior Notes, 6.875% interest, net of discount of $8,913 and $9,676, respectively, issued October 2004 and due November 2014			216,087		215,324
	Senior Notes, 6.875% interest, net of discount of $32,839 and $0, respectively, issued May 2009 and due November 2014(1)			117,595		—
	Senior Notes, 8.5% interest, net of discount of $821 and $882, respectively, issued July 2006 and due July 2016			274,179		274,118
	Senior Notes, 8.75% interest, net of discount of $1,115 and $1,177, respectively, issued April 2008 and due April 2018			498,885		498,823
		Total long-term debt	$	1,339,546	$	1,172,965

(1)

Includes fair value of the written put options as discussed below.

20

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

11. Long-Term Debt (Continued)

Credit Facility

        On January 28, 2009, the Partnership entered into the first amendment to its Partnership Credit Agreement which became effective March 2, 2009. The amendment expands the Partnership's borrowing capacity under the revolving facility by $85.6 million from $350.0 million to $435.6 million. Pursuant to the amendment, the term of the original credit agreement has been reduced by one year and is now due on February 20, 2012. The accordion feature established under the original credit agreement was reset to $200.0 million of uncommitted funds. The borrowings under the revolving credit facility of the Partnership Credit Agreement will continue to bear interest at a variable interest rate, plus basis points. The variable interest rate typically is based on LIBOR; however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5%, and b) a rate set by the Partnership Credit Agreement's administrative agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Partnership's Consolidated Funded Debt (as defined in the Partnership Credit Agreement) to Adjusted Consolidated EBITDA (as defined in the Partnership Credit Agreement). Under the original agreement, the basis points ranged from 50 to 125 for Base Rate loans, and 150 to 225 for LIBOR loans. Under the terms of the amendment, the basis points range from 150 to 225 for Base Rate loans and 250 to 325 for LIBOR loans. The amendment also established a floor of 2% for the LIBOR rate used to determine the interest rate on the LIBOR loans. The Partnership incurred and capitalized approximately $4.3 million of debt modification fees and other professional services as a result of the amendment. The amendment also resulted in the write-off of approximately $0.3 million of previously capitalized deferred finance costs during the first quarter of 2009, which is included inAmortization of deferred financing costs and discount in the accompanying Condensed Consolidated Statements of Operations.

        Under the provisions of the Partnership Credit Agreement, the Partnership is subject to a number of restrictions and covenants as defined by the agreement. 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, 2009, the Partnership had $232.8 million of borrowings outstanding and $29.7 million of letters of credit outstanding under the revolving credit facility, leaving approximately $173.1 million available for borrowing.

        The recorded value of the amounts outstanding under the revolving credit facility as of June 30, 2009 approximate fair value due to the variable interest rate and short-term nature of the borrowings.

Senior Notes

        As of June 30, 2009, MarkWest Energy Partners, L.P. in conjunction with its wholly-owned subsidiary MarkWest Energy Finance Corporation (the "Issuers") had four series of Senior Notes outstanding. On May 26, 2009, the Issuers completed a private placement of $150.0 million in aggregate principal amount of 6.875% senior unsecured notes due 2014 to qualified institutional buyers under Rule 144A. The Partnership received proceeds of approximately $113.8 million, after deducting the initial purchasers' discounts and other expenses of the private placement. The proceeds were primarily used to repay borrowings under the Partnership's revolving credit facility. Interest on these senior notes is payable on each May 1 and November 1 and will accrue from May 26, 2009.

21

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

11. Long-Term Debt (Continued)

        On July 2, 2009, the Partnership filed an exchange offer registration statement, pursuant to the registration rights agreement for the senior notes issued in May 2009. The Partnership anticipates initiating the exchange offer in the third quarter of 2009 and expects to complete the exchange offer within the time provided for in the subscription agreements.

        The indenture for the senior notes issued in May 2009 contains the following two contingent written put options exercisable by the debt holders (see Note 5 for more information on the separate accounting for the written put options under GAAP and Note 6 for more information on the determination of the fair value under GAAP):

        Change in Control Put—In the event of a change in control of the Partnership, the debt holders have the option to put the notes at 101% of principal amount, plus any accrued interest.

        Asset Sale Offer Put—In the event the Partnership consummates an asset sale, as defined in the indenture, and fails to use the net proceeds in excess of $10.0 million to: (i) pay off indebtedness under the Credit Facility; (ii) to make capital expenditures; (iii) to acquire other long-term tangible assets or (iv) to invest the proceeds in any other approved investment, the Partnership must use the excess proceeds to offer to repurchase some portion of the senior notes at 100% of principal amount, plus any accrued interest.

        The written put options are considered embedded derivatives primarily due to the fact that they are contingently exercisable and the notes were issued at a substantial discount. Substantially similar contingent written put options are also in the indentures for the Partnership's previous senior note offerings, but they do not require separate accounting because their issuance in prior years was not at a substantial discount.

        The estimated fair value of all outstanding Senior Notes was approximately $980.6 million and $627.1 million at June 30, 2009 and December 31, 2008, respectively, based on quoted market prices.

        The Issuers have no independent operating assets or operations. All wholly-owned subsidiaries, other than MarkWest Energy Finance Corporation, guarantee the Senior Notes, jointly and severally and fully and unconditionally. The Partnership's less than wholly-owned subsidiaries do not guarantee the Senior Notes (see Note 19 for required condensed consolidating financial information). The notes are senior unsecured obligations equal in right of payment with all of the Partnership's existing and future senior debt. These notes are senior in right of payment to all of the Partnership's future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership's obligations in respect of the Partnership Credit Agreement.

        The indentures governing the Senior Notes limit the activity of the Partnership and its restricted subsidiaries. Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indentures pursuant to Rule 144A and Regulation S under the Securities Act of 1933. If at any time the Senior Notes are rated investment grade by both Moody's Investors Service, Inc. and Standard & Poor's Rating Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will be suspended during the period of time in which the foregoing requirements are met or will terminate entirely, in which case the Partnership and its subsidiaries will cease to be subject to such terminated covenants.

22

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

12. Income Taxes

        A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate of 35% to the loss before income taxes for the six months ended June 30, 2009 and 2008 is as follows (in thousands):

		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			(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	%

		Six months ended June 30, 2008
		Corporation			Partnership			Eliminations			Consolidated
Loss before provision for income tax		$	(75,627	)	$	(111,239	)	$	(6,817	)	$	(193,683	)
Federal statutory rate			35	%		0	%		0	%
Federal income tax at statutory rate		$	(26,469	)	$	—		$	—		$	(26,469	)
Permanent items			24			—			—			24
State income taxes net of federal benefit			(1,920	)		(699	)		—			(2,619	)
Provision on income from Class A units			(9,876	)		—			—			(9,876	)
Write-off of deferred income tax assets			7,471			—			—			7,471
Other			(205	)		—			—			(205	)
	Provision for income tax	$	(30,975	)	$	(699	)	$	—		$	(31,674	)
Effective tax rate												16.4	%

13. Incentive Compensation Plans

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,
	2009		2008		2009		2008
Phantom units	$	1,469	$	4,176	$	4,172	$	6,174
Distribution equivalent rights		330		141		668		238
Restricted stock		—		—		—		75
General partner interests under Participation Plan		—		274		—		5,470
Total compensation expense	$	1,799	$	4,591	$	4,840	$	11,957

23

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. Incentive Compensation Plans (Continued)

        The interests in the Partnership's General Partner sold by the Corporation to certain directors and employees were referred to as the Participation Plan. The Participation Plan was considered a compensatory arrangement. In conjunction with the Merger, all of the outstanding interests in the General Partner were acquired for a combination of 0.9 million common units with a fair value of approximately $30.1 million and approximately $21.5 million in cash.

        As of June 30, 2009, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP and 2006 Hydrocarbon Plan was approximately $17.4 million, with a weighted average remaining vesting period of approximately 1.5 years. Total compensation expense not yet recognized related to unvested awards under the 2002 LTIP was approximately $0.5 million, with a weighted-average remaining vesting period of approximately 0.9 years. The actual compensation expense recognized for awards under the 2002 LTIP may differ as they qualify as liability awards under SFAS No. 123R,Share-Based Payment, which are affected by changes in fair value.

2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan

        The following is a summary of phantom unit activity under the 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan:

		Number of Units			Weighted-average Grant-date Fair Value
Unvested at December 31, 2008			909,306		$	31.80
	Granted(1)		435,535			8.40
	Vested(2)		(284,503	)		31.86
	Forfeited(3)		(25,963	)		22.41
Unvested at June 30, 2009(4)			1,034,375			22.16

(1)

Includes 154,500 phantom units granted to senior executives and other key employees which contain performance vesting criteria ("performance units").



(2)

Includes 139,050 performance units.



(3)

Includes 13,950 performance units.



(4)

Includes 465,000 performance units. Compensation expense recorded for the performance units expected to vest was approximately $0.3 million and $1.7 million for the six months ended June 30, 2009 and 2008, respectively.

	Three months ended June 30,				Six months ended June 30,
	2009		2008		2009		2008
	(in thousands)
Total grant-date fair value of phantom units granted during the period	$	9	$	762	$	3,658	$	29,153
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	—	$	—	$	9,064	$	125

24

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

13. 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, 2008			145,927		$	31.45
	Granted		—			—
	Vested		(65,655	)		29.80
	Forfeited		(4,610	)		33.50
Unvested at June 30, 2009			75,662			32.76

	Three months ended June 30,				Six months ended June 30,
	2009		2008		2009		2008
	(in thousands)
Total grant-date fair value of phantom units granted during the period	$	—	$	—	$	—	$	2,670
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	—	$	—	$	818	$	1,872

14. Equity Offering

        On June 10, 2009, the Partnership completed a public offering of approximately 3.34 million newly issued common units, which included the exercise of the overallotment option by the underwriters, representing limited partner interests at a purchase price of $18.15 per common unit. Net proceeds of approximately $57.7 million were used to partially fund the Partnership's 2009 capital expenditure requirements, and the remainder was used to pay down borrowings under its revolving credit facility of the Partnership Credit Agreement.

        On April 14, 2008, the Partnership completed a public offering of 5.75 million newly issued common units, which included the exercise of the overallotment option by the underwriters, representing limited partner interests at a purchase price of $31.15 per common unit. Net proceeds of approximately $171.4 million were used to partially fund the Partnership's 2008 capital expenditure requirements, and the remainder was used to pay down borrowings under its revolving credit facility of the Partnership Credit Agreement.

15. Earnings Per Unit

        As a result of the adoption of FSP EITF 03-6-1 on January 1, 2009, the Partnership's outstanding phantom units are considered to be participating securities, and therefore basic and diluted earnings per common unit are calculated pursuant to the two-class method described in SFAS No. 128,Earnings per Share. In accordance with the two-class method, basic earnings per common unit is calculated by dividing net income attributable to the Partnership, after deducting amounts that are allocable to the outstanding phantom units, by the weighted-average number of common units outstanding during the period. The amount allocable to the phantom units is generally calculated as if all of the net income attributable to the Partnership were distributed, and not on the basis of actual cash distributions for the

25

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

15. Earnings Per Unit (Continued)

period. However, during periods in which a net loss attributable to the Partnership is reported or periods in which the total distributions exceed the reported net income attributable to the Partnership, the amount allocable to the phantom units is based on actual distributions to the phantom unit holders. Diluted earnings per unit is calculated by dividing net income attributable to the Partnership, after deducting amounts allocable to the outstanding phantom units, by the weighted-average number of potential common units outstanding during the period. Potential common units are excluded from the calculation of diluted earnings per unit during periods in which the Partnership incurs a net loss as the impact would be anti-dilutive.

        The following table shows the computation of basic and diluted net loss attributable to the Partnership per common unit, for the three and six months ended June 30, 2009 and 2008, and the weighted-average units used to compute diluted net loss attributable to the Partnership per common unit (in thousands, except per unit data):

		Three months ended June 30,						Six months ended June 30,
		2009			2008			2009			2008
Net loss attributable to the Partnership		$	(67,506	)	$	(177,767	)	$	(97,155	)	$	(158,616	)
Less: Income allocable to phantom units			382			487			772			487
Loss available for common unitholders		$	(67,888	)	$	(178,254	)	$	(97,927	)	$	(159,103	)
Weighted average common units outstanding—basic			57,603			55,742			57,207			45,326
Effect of dilutive instruments(1)			—			—			—			—
Weighted average common units outstanding—diluted			57,603			55,742			57,207			45,326
Net loss attributable to the Partnership's common unitholders
	Basic	$	(1.18	)	$	(3.20	)	$	(1.71	)	$	(3.51	)
	Diluted	$	(1.18	)	$	(3.20	)	$	(1.71	)	$	(3.51	)

(1)

Phantom units are considered to be participating securities under EITF 03-6-1. As a result, the Partnership had no potential common units outstanding during the three months ended June 30, 2008 and during three and six months ended June 30, 2009. For the six months ended June 30, 2008, 6 units were excluded from the calculation of diluted units which include MarkWest Hydrocarbon stock options outstanding prior to the Merger.

16. Distributions to Unitholders

Quarter Ended	Distribution Per Common Unit		Declaration Date		Ex-dividend Date		Record Date		Payment Date
June 30, 2009	$	0.64		July 23, 2009		July 30, 2009		August 3, 2009		August 14, 2009
March 31, 2009	$	0.64		April 23, 2009		April 30, 2009		May 4, 2009		May 15, 2009
December 31, 2008	$	0.64		January 27, 2009		February 4, 2009		February 6, 2009		February 13, 2009

26

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

17. 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. 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 Production Company 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. A hearing has been set for November 3, 2009. MarkWest believes it has viable and mitigating defenses to the remaining counts and will vigorously defend all applicable assertions of violations at the hearing.

        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 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 based on initial evaluation and consultations, it appears at this time that this action should not have a material adverse impact on the Partnership's financial position or results of operations.

27

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

17. Commitments and Contingencies (Continued)

        On June 26, 2009, MarkWest Liberty Midstream entered into a Consent Order and Agreement with the Commonwealth of Pennsylvania, Department of Environmental Protection relating to alleged violations of Pennsylvania's stormwater and dam safety regulations in connection with the construction of facilities installed or acquired by MarkWest Liberty Midstream. Under the Consent Order and Agreement, MarkWest Liberty Midstream agreed to pay civil penalties and administrative oversight costs in an aggregate amount of $0.2 million and to perform certain corrective actions, the cost of which is not expected to have a material impact on the Partnership's financial condition, liquidity, or results of operations.

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

18. Segment Information

        The Partnership's chief operating decision maker is the Chief Executive Officer ("CEO"). The CEO reviews the Partnership's discrete financial information on a geographic and operational basis, as the products and services are closely related within each geographic region and business operation. Accordingly, the CEO makes operating decisions, assesses financial performance and allocates resources on a geographical basis. The Partnership has four segments: Southwest, Northeast, Gulf Coast and Liberty. The Southwest segment provides gathering, processing, transportation, and storage services. The Northeast segment provides gathering, processing, transportation, fractionation and storage services. The Gulf Coast segment provides processing, transportation, fractionation and storage services. The Liberty segment provides gathering, processing, and transportation services. The Liberty segment is a new segment beginning in 2009 and consists primarily of the operations in the Marcellus Shale region of western Pennsylvania and northern West Virginia. For the year ended December 31, 2008, the results of operations in the Liberty segment were included in the Northeast segment because all of the aggregation criteria under SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information, were satisfied and the results of the Liberty segment were immaterial. However, because the Liberty operations may grow to become a larger portion of the Partnership's business in the future, management believes that transparency to the Liberty segment will provide useful information to investors.

        The Partnership prepares segment information in accordance with GAAP, except that certain items belowLoss 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. The segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests.

28

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

18. Segment Information (Continued)

        The tables below present information about operating income for the three and six months ended June 30, 2009 and 2008 and capital expenditures for the reported segments for the six months ended June 30, 2009 and 2008 (in thousands).

Three months ended June 30, 2009 and 2008

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

Three months ended June 30, 2008:			Southwest		Northeast		Liberty(1)		Gulf Coast		Total
Revenue			$	185,812	$	64,893	$	—	$	27,453	$	278,158
Operating expenses:
	Purchased product costs			109,524		43,749		—		—		153,273
	Facility expenses			14,644		5,207		—		4,429		24,280
		Operating income before items not allocated to segments	$	61,644	$	15,937	$	—	$	23,024	$	100,605

(1)

The Partnership began construction in the Liberty segment in May 2008 and operations commenced in October 2008.

29

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

18. Segment Information (Continued)

        The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to loss before provision for income tax for the three months ended June 30, 2009 and 2008 (in thousands).

			Three months ended June 30,
			2009			2008
Total segment revenue			$	185,000		$	278,158
	Derivative loss not allocated to segments			(83,235	)		(312,591	)
		Total revenue	$	101,765		$	(34,433	)
Operating income before items not allocated to segments			$	70,864		$	100,605
	Portion of operating income attributable to non-controlling interests			1,362			—
	Derivative loss not allocated to segments			(85,006	)		(265,184	)
	Compensation expense included in facility expenses not allocated to segments			(214	)		(482	)
	Selling, general and administrative expenses			(14,861	)		(16,614	)
	Depreciation			(23,414	)		(16,498	)
	Amortization of intangible assets			(10,212	)		(10,469	)
	Other operating expenses			(114	)		(33	)
	Impairment of long-lived assets			(5,855	)		(5,009	)
		Loss from operations		(67,450	)		(213,684	)
	Earnings from unconsolidated affiliates			1,196			577
	Interest expense			(22,742	)		(17,450	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(2,046	)		(5,164	)
	Other income			2,443			2,837
		Loss before provision for income tax	$	(88,599	)	$	(232,884	)

30

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

18. Segment Information (Continued)

Six months ended June 30, 2009 and 2008

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

Six months ended June 30, 2008:			Southwest		Northeast		Liberty(1)		Gulf Coast		Total
Revenue			$	343,888	$	168,697	$	—	$	50,615	$	563,200
Operating expenses:
	Purchased product costs			202,162		106,046		—		—		308,208
	Facility expenses			28,519		9,989		—		8,256		46,764
		Operating income before items not allocated to segments	$	113,207	$	52,662	$	—	$	42,359	$	208,228
Capital expenditures			$	129,199	$	14,669	$	—	$	25,725	$	169,593
Capital expenditures not allocated to segments												2,595
		Total capital expenditures									$	172,188

(1)

The Partnership began construction in the Liberty segment in May 2008 and operations commenced in October 2008.

31

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

18. Segment Information (Continued)

        The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to loss before provision for income tax for the six months ended June 30, 2009 and 2008 (in thousands).

			Six months ended June 30,
			2009			2008
Total segment revenue			$	368,367		$	563,200
	Derivative loss not allocated to segments			(74,931	)		(358,841	)
		Total revenue	$	293,436		$	204,359
Operating income before items not allocated to segments			$	120,509		$	208,228
	Portion of operating income attributable to non-controlling interests			1,670			—
	Derivative loss not allocated to segments			(105,844	)		(279,394	)
	Compensation expense included in facility expenses not allocated to segments			(558	)		(664	)
	Selling, general and administrative expenses			(30,788	)		(39,075	)
	Depreciation			(44,357	)		(31,023	)
	Amortization of intangible assets			(20,445	)		(17,318	)
	Other operating expenses			(890	)		(68	)
	Impairment of long-lived assets			(5,855	)		(5,009	)
		Loss from operations		(86,558	)		(164,323	)
	Earnings from unconsolidated affiliates			1,091			2,128
	Interest expense			(40,524	)		(28,599	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(3,437	)		(6,207	)
	Other income			1,822			3,318
		Loss before provision for income tax	$	(127,606	)	$	(193,683	)

32

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

18. Segment Information (Continued)

        The tables below present information about segment assets as of June 30, 2009 and December 31, 2008 (in thousands):

As of June 30, 2009:		Southwest		Northeast		Liberty		Gulf Coast		Total
Total segment assets		$	1,600,950	$	225,398	$	240,800	$	565,788	$	2,632,936
Assets not allocated to segments:
	Certain cash and cash equivalents										54,398
	Fair value of derivatives										52,762
	Investment in unconsolidated affiliates(1)										52,167
	Other(2)										38,049
										$	2,830,312

(1)

Included inOther long-term assets in the Condensed Consolidated Balance Sheets.

(2)

Includes corporate fixed assets, income tax receivable and other corporate assets not allocated to segments.

As of December 31, 2008:		Southwest		Northeast		Liberty		Gulf Coast		Total
Total segment assets		$	1,487,205	$	233,403	$	127,785	$	548,503	$	2,396,896
Assets not allocated to segments:
	Certain cash and cash equivalents										137
	Fair value of derivatives										182,338
	Investment in unconsolidated affiliates(1)										46,092
	Other(2)										47,591
										$	2,673,054

(1)

Included inOther long-term assets in the Condensed Consolidated Balance Sheets.

(2)

Includes corporate fixed assets, income tax receivable and other corporate assets not allocated to segments.

33

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

19. Supplemental Condensed Consolidating Financial Information

        MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of June 30, 2009, the Partnership's obligations under the outstanding Senior Notes (see Note 11) were fully and unconditionally guaranteed, jointly and severally, by all of its wholly-owned subsidiaries. Separate financial statements for each of the Partnership's guarantor subsidiaries are not provided because such information would not be material to its investors or lenders. As of February 2009, following the closing of the joint venture with M&R and May 2009, following the closing of the joint venture with ArcLight (see Note 4), 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, MarkWest Energy Finance Corporation, are not material and therefore have been included with the Parent's financial information. Comparative financial statements have not been provided because the non-guarantor subsidiaries as of December 31, 2008 were minor subsidiaries individually and in the aggregate. Condensed consolidating financial information for MarkWest Energy

34

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

19. Supplemental Condensed Consolidating Financial Information (Continued)

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

Condensed Consolidating Balance Sheet

			As of June 30, 2009
			Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
	Cash and cash equivalents		$	—	$	53,916	$	2,539	$	—		$	56,455
	Receivables and other current assets			1,999		123,342		10,035		—			135,376
	Intercompany receivables			1,753,748		268,757		2,028		(2,024,533	)		—
	Fair value of derivative instruments			—		25,294		—		—			25,294
		Total current assets		1,755,747		471,309		14,602		(2,024,533	)		217,125
	Total property, plant and equipment, net			1,909		1,446,380		371,407		(4,080	)		1,815,616
Other long-term assets:
	Investment in consolidated affiliates			478,319		215,768		—		(694,087	)		—
	Intangibles, net of accumulated amortization			—		674,166		632		—			674,798
	Fair value of derivative instruments			—		27,468		—		—			27,468
	Intercompany notes receivable			203,600		—		—		(203,600	)		—
	Other long-term assets			22,413		65,677		7,215		—			95,305
		Total other long-term assets		704,332		983,079		7,847		(897,687	)		797,571
		Total assets	$	2,461,988	$	2,900,768	$	393,856	$	(2,926,300	)	$	2,830,312
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
	Intercompany payables		$	3	$	2,021,663	$	2,867	$	(2,024,533	)	$	—
	Fair value of derivative instruments			—		47,629		—		—			47,629
	Other current liabilities			31,503		101,254		36,415		—			169,172
		Total current liabilities		31,506		2,170,546		39,282		(2,024,533	)		216,801
Intercompany notes payable				—		203,600		—		(203,600	)		—
Fair value of derivative instruments				—		32,861		—		—			32,861
Long-term debt, net of discounts				1,339,546		—		—		—			1,339,546
Other long-term liabilities				5,819		15,442		76		—			21,337
Partners' Capital:
	MarkWest Energy Partners, L.P. partners' capital			1,085,117		478,319		354,498		(836,897	)		1,081,037
	Non-controlling interest in consolidated subsidiaries			—		—		—		138,730			138,730
		Total partners' capital		1,085,117		478,319		354,498		(698,167	)		1,219,767
		Total liabilities and partners' capital	$	2,461,988	$	2,900,768	$	393,856	$	(2,926,300	)	$	2,830,312

35

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

19. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statement of Operations

			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) income from operations		(11,462	)		(51,578	)		(5,431	)		1,021			(67,450	)
Earnings from consolidated affiliates				(36,620	)		(615	)		—			37,235			—
Other (expense) income				(16,159	)		(3,532	)		3,126			(4,584	)		(21,149	)
		Net (loss) income 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) income		(63,943	)		(36,620	)		(2,305	)		33,672			(69,196	)
Net loss attributable to non-controlling interest				—			—			—			1,690			1,690
		Net (loss) income attributable to the Partnership	$	(63,943	)	$	(36,620	)	$	(2,305	)	$	35,362		$	(67,506	)

36

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

19. 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) income from operations		(23,415	)		(59,065	)		(5,540	)		1,462			(86,558	)
Earnings from consolidated affiliates				(40,213	)		(691	)		—			40,904			—
Other (expense) income				(29,790	)		(8,855	)		3,139			(5,542	)		(41,048	)
		Net (loss) income 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) income		(93,075	)		(40,213	)		(2,401	)		36,824			(98,865	)
Net loss attributable to non-controlling interest				—			—			—			1,710			1,710
		Net (loss) income 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)

19. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statement of Cash Flows

			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:
	Change in restricted cash			—			—			(25	)		—			(25	)
	Equity investments			(24,908	)		(110,753	)		—			130,677			(4,984	)
	Distributions from consolidated affiliates			—			36,267			—			(36,267	)		—
	Collection of notes receivable			27,800			—			—			(27,800	)		—
	Capital expenditures			(317	)		(143,538	)		(181,055	)		4,122			(320,788	)
	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 long-term debt			541,700			—			—			—			541,700
	Payments of long-term debt			(376,600	)		(27,800	)		—			27,800			(376,600	)
	Payments for debt issuance costs, deferred financing costs and registration costs			(7,825	)		—			—			—			(7,825	)
	Contributed capital, net of transaction fees			(7,311	)		24,908			205,769			(99,427	)		123,939
	Proceeds from public offering, net			57,665			—			—			—			57,665
	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

38

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

20. Supplemental Disclosure of Changes in Partners' Capital

        The following table provides a reconciliation of total partners' capital attributable to MarkWest Energy Partners, L.P. and total partners' capital attributable to the non-controlling interest for the six months ended June 30, 2008 (in thousands).

		MarkWest Energy Partners, L.P. Unitholders
		Common Units			Partners' Capital			Accumulated Other Comprehensive Income (loss)			Non-controlling Interest			Total
December 31, 2007			22,861		$	38,463		$	928		$	524,583		$	563,974
Option exercises			98			375			—			—			375
Dividends paid			—			(4,338	)		—			—			(4,338	)
Distributions paid			—			(34,463	)		—			—			(34,463	)
Distributions to non-controlling interest holders			—			—			—			(19,651	)		(19,651	)
Share-based compensation related to equity awards			—			5,051			—			—			5,051
APIC pool for excess tax benefits under SFAS 123R			—			717			—			—			717
Other			—			—			—			758			758
Merger and Redemption:
	Redemption of MarkWest Hydrocarbon, Inc. Common Stock		(7,458	)		(240,513	)		—			—			(240,513	)
	Conversion of restricted stock to phantom units in connection with the Merger of MarkWest Hydrocarbon, Inc. and MarkWest Energy Partners,  L.P.		(45	)		—			—			—			—
	Participation Plan liability settlement associated with the Merger of MarkWest Hydrocarbon, Inc. and MarkWest Energy Partners,  L.P.		946			30,078			—			—			30,078
	Purchase of non-controlling interest of MarkWest Energy Partners, L.P.		34,474			1,095,917			—			(502,297	)		593,620
Issuance of units in public offering, net of offering costs			5,750			171,395			—			—			171,395
Net loss			—			(158,616	)		—			(3,393	)		(162,009	)
Realized loss on marketable securities			—			—			(928	)		—			(928	)
Comprehensive loss															(162,937	)
June 30, 2008			56,626		$	904,066		$	—		$	—		$	904,066

39

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (Continued)

(unaudited)

21. Subsequent Events

        In accordance with SFAS 165, the Partnership has evaluated subsequent events through August 10, 2009, the date the financial statements were issued, and identified the events disclosed below.

        In June 2009, the Partnership entered into an agreement to sell the Steam Methane Reformer ("SMR") currently being constructed at its Javelina gas processing and fractionation facility in Corpus Christi, Texas. Under the terms of the agreement, the purchaser will complete the construction of the SMR. The Partnership will have continuing involvement with the SMR pursuant to a long-term agreement to purchase all of the hydrogen produced by the SMR. The Partnership intends to use proceeds from the sale to pay down amounts outstanding under its revolving credit facility and for the continued development of other strategic projects. The potential divestiture of the SMR is anticipated to close in the third quarter of 2009 and is subject to certain closing conditions.

        In July 2009, MarkWest Pioneer completed construction and commenced commercial operations of the Arkoma Connector Pipeline. As a result, the Partnership received the remaining $31.25 million from the sale of a 50% equity interest in MarkWest Pioneer (see Note 4).

        In July 2009, the Partnership entered into fixed-to-variable interest rate swap agreements having a combined notional principal amount of $275.0 million. The Partnership has designated these interest rate swaps as fair value hedges. The fair value hedges are intended to hedge against changes in fair value due to changes in the benchmark interest rate (one-month LIBOR). The Partnership is hedging a portion of its senior notes that mature on November 1, 2014.

        In 2008, MarkWest Pioneer was granted the option to purchase a 10% membership interest in Midcontinent Express Pipeline LLC ("MEP") upon the satisfaction of certain conditions. MEP is currently owned by Energy Transfer Partners, L.P. and Kinder Morgan Energy Partners, L.P., and is constructing the Midcontinent Express Pipeline, which will run from Bennington, Oklahoma to Perryville, Louisiana. On August 3, 2009, MEP notified MarkWest Pioneer that the conditions to its purchase option had been satisfied. It is likely that MarkWest Pioneer will elect to conduct due diligence in order to evaluate its option to purchase the 10% membership interest in MEP. The option is subject to termination by MarkWest Pioneer during a specified period of time in order to complete the due diligence.

        On August 10, 2009, the Partnership and M&R signed an agreement to modify MarkWest Liberty Midstream's LLC agreement. This modification, subject to certain closing conditions, will allow M&R to increase its participation in MarkWest Liberty Midstream by an additional $150.0 million. Under the modified LLC agreement, the Partnership and M&R will maintain a 60%/40% respective ownership interest in MarkWest Liberty Midstream until January 1, 2011, at which time M&R's ownership interest will increase from 40% to 49%. 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 51% ownership interest (the "Equalization Date"), which will occur on or before December 31, 2012. 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%.

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, 2008 Annual Report on Form 10-K as modified by our Current Report on Form 8-K as filed with the SEC on May 18, 2009 for the retrospective applications of SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB 51 and FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. 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 natural gas liquids; 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, 2009 are listed below. Refer toResults of Operations andLiquidity and Capital Resources for further details.

•

Total segment operating income before items not allocated to segments decreased approximately $29.7 million, or 30%, for the three months ended June 30, 2009 compared to the same period in 2008. The decrease is due primarily to significantly lower NGL and natural gas prices in 2009. The decrease related to commodity prices was partially offset by the following:

•

increased gathered and processed volumes in the Southwest segment due to the 2008 acquisition of the Stiles Ranch gathering system, the continued expansion of the Woodford gathering system, and the expansion of the processing facilities in western Oklahoma and East Texas.

•

increased contracted volumes from a large producer and expansion of the processing facilities in the Northeast segment.

•

continued expansion of our Marcellus Shale operations in the Liberty segment. These operations commenced in October 2008.

•

During the three months ended June 30, 2009, the prices of NGLs relative to the price of crude oil have been significantly below the historical averages. This has reduced the effectiveness of our hedging program and has adversely impacted our cash flow and results of operations.

•

In May 2009 we received net proceeds of $113.8 million from a private placement of senior notes. These notes, with an aggregate principal amount of $150.0 million, will be due in November 2014.

•

In May 2009 we sold a 50% equity interest in MarkWest Pioneer, L.L.C. ("MarkWest Pioneer") for a total purchase price of $62.5 million.

•

In June 2009 we received net proceeds of $57.7 million from a public offering of approximately 3.34 million newly issued common units.

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 usage of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

        The following is a reconciliation to loss 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,
		2009			2008			2009			2008
Revenue		$	185,000		$	278,158		$	368,367		$	563,200
Purchased product costs			80,652			153,273			182,966			308,208
	Net operating margin		104,348			124,885			185,401			254,992
Facility expenses			32,336			24,762			63,780			47,428
Total derivative loss			85,006			265,184			105,844			279,394
Selling, general and administrative expenses			14,861			16,614			30,788			39,075
Depreciation			23,414			16,498			44,357			31,023
Amortization of intangible assets			10,212			10,469			20,445			17,318
Other operating expenses			114			33			890			68
Impairment of long-lived assets			5,855			5,009			5,855			5,009
	Loss from operations	$	(67,450	)	$	(213,684	)	$	(86,558	)	$	(164,323	)

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 arrangements described below. We provide services under the following different types of arrangements:

•

Fee-based arrangements:  Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, processing and transmission of natural gas; transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue we earn from these arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain cases, our arrangements provide for minimum annual payments or fixed demand charges. If a sustained decline in commodity prices were to result in a decline in volumes, however, our revenues from these arrangements would be reduced.

42

•

Percent-of-proceeds arrangements:  Under percent-of-proceeds arrangements, we gather and process natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and remit to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, we deliver an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes we keep to third parties at market prices. The percentage of volumes that we retain can be either fixed or variable. Generally, under these types of arrangements our revenues and gross margins increase as natural gas, condensate and NGL prices increase, and our revenues and net operating margins decrease as natural gas, condensate and NGL prices decrease. Due to current market and financial conditions, we have seen decreases in natural gas, condensate and NGL prices, and it is uncertain if prices will remain at these lower levels in the future.

•

Percent-of-index arrangements:  Under percent-of-index arrangements, we purchase natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. We then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price, or at a different percentage discount to the index price. With respect to (1) and (3) above, the net operating margins we realize under the arrangements decrease in periods of low natural gas prices because these net operating margins are based on a percentage of the index price. Conversely, our net operating margins increase during periods of high natural gas prices.

•

Keep-whole arrangements:  Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require us to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio. Accordingly, under these arrangements our revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and decrease as the price of natural gas increases relative to the price of condensate and NGLs.

•

Settlement margin:  Typically, we are allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed-line losses. To the extent that we operate our gathering systems more or less efficiently than specified per contract allowance, we will retain the benefit or loss for our own account.

        The terms of our contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common, and other market factors, including current market and financial conditions which have increased the risk of volatility in oil, natural gas and NGL prices. Any change in mix will influence our long-term financial results.

        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 5 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q. For the six

43

months ended June 30, 2009, we calculated 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		22	%		34	%		9	%		35	%		100	%
Net operating margin		44	%		26	%		4	%		26	%		100	%

(1)

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

(2)

Includes settlement margin and other types of arrangements tied to natural gas prices.

(3)

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

        While the percentages in the table above accurately reflect the percentages by contract type, we manage our business by taking into account the partial offset of short natural gas positions by long positions primarily in our Southwest segment, required levels of operational flexibility and the fact that our hedge plan is implemented on this basis. When the partial offset of our natural gas positions is considered, the calculated percentages for the net operating margin in the table above for percent-of-proceeds, percent-of-index and keep-whole contracts change to 43%, 0% and 13%, respectively.

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 segment 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 capture information in this MD&A by segment. The segment information appearing in Note 18 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q is presented on a basis consistent with our internal management reporting, in accordance with SFAS No. 131,Disclosure about Segments of an Enterprise and Related Information.

Southwest

•

East Texas.  Our East Texas system 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 and Travis Peak and Haynesville formations, which collectively form one of the largest natural gas producing regions in the United States. 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 the 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

44

Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities. All of the gathered gas ultimately is compressed and delivered to the processing plant. Under an agreement executed in 2008 with Newfield Exploration Mid-Continent Inc., we own and operate a gathering system in the Granite Wash formation in the Texas panhandle that is connected to our Foss Lake processing plants. We also own the Grimes gathering system, which is located in Roger Mills and Beckham Counties in western Oklahoma. In addition, we own a natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. In July 2008, we acquired a subsidiary of PetroQuest Energy, L.L.C. ("PetroQuest") that owns natural gas gathering assets located primarily in Pittsburg County in southeast Oklahoma as part of our expansion of the Woodford gathering system.

On May 1, 2009, we entered into a joint venture with Arkoma Pipeline Partners, L.L.C. ("ArcLight"), an affiliate of ArcLight Capital Partners, L.L.C. ArcLight acquired a 50% equity interest in MarkWest Pioneer for a total purchase price of $62.5 million. MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline, a 50-mile interstate pipeline that provides approximately 638,000 Dth/d of Woodford Shale takeaway capacity and interconnects with Midcontinent Express Pipeline and Gulf Crossing Pipeline. A complete discussion of the formation of and accounting treatment for MarkWest Pioneer appears in Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q.

•

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. 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 crude oil pipeline in Michigan as well as a natural gas gathering system in Manistee County, Michigan.

Liberty

•

MarkWest Liberty Gas Gathering, L.L.C. and MarkWest Liberty Midstream & Resources, L.L.C.  We operate natural gas gathering systems and processing facilities located primarily in western Pennsylvania and northern West Virginia. Prior to February 27, 2009, we owned a 100% interest in these assets through MarkWest Liberty Gas Gathering, L.L.C., a wholly-owned subsidiary. On February 27, 2009, we contributed these assets to a newly-formed entity, MarkWest Liberty Midstream & Resources, L.L.C. ("MarkWest Liberty Midstream"), and sold a 40% interest in MarkWest Liberty Midstream to an affiliate of NGP Midstream & Resources, L.P. ("M&R"). A complete discussion of the formation of and accounting treatment for MarkWest Liberty Midstream appears in Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q. MarkWest Liberty Midstream

45

currently operates a mechanical refrigeration plant with a capacity of 30 MMcf/d and a cryogenic processing facility with a capacity of 30 MMcf/d that was placed into service in the second quarter of 2009. We plan on adding additional processing capacity before the end of the third quarter of 2009, and a second cryogenic facility with a capacity of 120 MMcf/d is expected to be in service by early 2010.

Gulf Coast

•

Javelina.  We own and operate the Javelina Processing Facility, a natural gas processing facility in Corpus Christi, Texas, that treats and processes off-gas from six local refineries.

        The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by identifiable segment, for the six months ended June 30, 2009:

	Southwest			Northeast			Liberty			Gulf Coast			Total
Revenue		59	%		30	%		4	%		7	%		100	%
Net operating margin		64	%		15	%		7	%		14	%		100	%

Equity investments in unconsolidated affiliates

        Starfish.    We own a 50% non-operating membership interest in Starfish Pipeline Company, L.L.C. ("Starfish"), a joint venture with Enbridge Offshore Pipelines, L.L.C. that is accounted for using the equity method. The financial results of Starfish are included inEarnings from unconsolidated affiliates in the accompanying Condensed Consolidated Statements of Operations and are not included in our segment results. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas gathering system and West Cameron dehydration facility. All of these assets are located in the Gulf of Mexico or southwestern Louisiana.

        Centrahoma.    We own a 40% non-operating membership interest in Centrahoma Processing, L.L.C. ("Centrahoma"), a joint venture with Antero Midstream Resources Corporation that is accounted for using the equity method. The financial results of Centrahoma are included inEarnings from unconsolidated affiliates in the accompanying Condensed Consolidated Statements of Operations and are not included in our segment results. 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.

Three months ended June 30, 2009, compared to three months ended June 30, 2008

        Items belowLoss from operations in our 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 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 30, 2009 and 2008.

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Southwest

		Three months ended June 30,
		2009			2008		$ Change			% Change
		(in thousands)
Revenue		$	111,569		$	185,812	$	(74,243	)		(40	)%
Operating expenses:
	Purchased product costs		46,497			109,524		(63,027	)		(58	)%
	Facility expenses		19,577			14,644		4,933			34	%
Total operating expenses before items not allocated to segments			66,074			124,168		(58,094	)		(47	)%
Portion of operating loss attributable to non-controlling interests			(1	)		—		(1	)		N/A
Operating income before items not allocated to segments		$	45,496		$	61,644	$	(16,148	)		(26	)%

        Revenue.    Revenue decreased primarily due to lower commodity prices. Revenue from NGL, natural gas and condensate sales decreased across the segment by $80.9 million. The effect of the decrease in commodity prices on NGL sales was partially offset by increases in volumes processed at our East Texas facilities and increase in volumes processed at the Arapaho facilities associated with the Stiles Ranch gathering system that began operations in the fourth quarter of 2008. The revenue declines associated with lower commodity prices were also partially offset by a $7.0 million increase in gathering and treating fee revenue due to the continued expansion of our operations in the Woodford Shale.

        Purchased Product Costs.    NGL and natural gas purchases decreased due primarily to lower commodity prices as well as decreased volumes in the Other Southwest areas.

        Facility Expenses.    Facility expenses increased due primarily to the continued expansion of operations for the Woodford gathering system, including the PetroQuest acquisition in July of 2008, the expansion of the Foss Lake gathering and processing operations, and increased repairs and maintenance resulting from non-recurring environmental remediation costs in East Texas.

Northeast

		Three months ended June 30,
		2009		2008		$ Change			% Change
		(in thousands)
Revenue		$	48,619	$	64,893	$	(16,274	)		(25	)%
Operating expenses:
	Purchased product costs		32,080		43,749		(11,669	)		(27	)%
	Facility expenses		4,799		5,207		(408	)		(8	)%
Total operating expenses before items not allocated to segments			36,879		48,956		(12,077	)		(25	)%
Operating income before items not allocated to segments		$	11,740	$	15,937	$	(4,197	)		(26	)%

        Revenue.    Revenue decreased due primarily to lower commodity prices realized on NGL sales from the Appalachia region. The decrease in revenue from lower commodity prices was partially offset by increased volumes which resulted from upgrades to our processing facilities in this area and increased volumes from a large producer due to expansion of the contracted volumes.

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        Purchased Product Costs.    Purchased product costs decreased due to lower prices for the natural gas that must be purchased to satisfy the keep-whole arrangements in the Appalachia area.

Liberty

		Three months ended June 30,
		2009		2008		$ Change		% Change
		(in thousands)
Revenue		$	10,064	$	—	$	10,064		N/A
Operating expenses:
	Purchased product costs		2,075		—		2,075		N/A
	Facility expenses		4,583		—		4,583		N/A
Total operating expenses before items not allocated to segments			6,658		—		6,658		N/A
Portion of operating income attributable to non-controlling interests			1,363		—		1,363		N/A
Operating income before items not allocated to segments		$	2,043	$	—	$	2,043		N/A

        The results of operations for the three months ended June 30, 2009 include our operations in the northern West Virginia and western Pennsylvania areas. Revenue for the three months ended June 30, 2009 consists of approximately $6.9 million of gathering fees that are based primarily on a fixed return on the capital invested in the gathering system. Approximately $3.2 million of the revenue relates to NGL product sales under primarily percent-of-proceeds arrangements.

        We did not have any operations in the Marcellus Shale during the three months ended June 30, 2008. We began construction in the second quarter of 2008 and gas gathering and processing operations in the fourth quarter of 2008.

Gulf Coast

		Three months ended June 30,
		2009		2008		$ Change			% Change
		(in thousands)
Revenue		$	14,748	$	27,453	$	(12,705	)		(46	)%
Operating expenses:
	Facility expenses		3,163		4,429		(1,266	)		(29	)%
Total operating expenses before items not allocated to segments			3,163		4,429		(1,266	)		(29	)%
Operating income before items not allocated to segments		$	11,585	$	23,024	$	(11,439	)		(50	)%

        Revenue.    Revenue decreased due to lower commodity prices.

        Facility Expenses.    Facility expenses decreased due to lower utilities and repairs and maintenance expenses.

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Reconciliation of Segment Operating Income to Consolidated 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 loss before provision for income tax for the three months ended June 30, 2009 and 2008. 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,
			2009			2008			$ Change			% Change
			(in thousands)
Total segment revenue			$	185,000		$	278,158		$	(93,158	)		(33	)%
	Derivative loss not allocated to segments			(83,235	)		(312,591	)		229,356			(73	)%
		Total revenue	$	101,765		$	(34,433	)	$	136,198			(396	)%
Operating income before items not allocated to segments			$	70,864		$	100,605		$	(29,741	)		(30	)%
	Portion of operating income attributable to non-controlling interests			1,362			—			1,362			N/A
	Derivative loss not allocated to segments			(85,006	)		(265,184	)		180,178			(68	)%
	Compensation expense included in facility expenses not allocated to segments			(214	)		(482	)		268			(56	)%
	Selling, general and administrative expenses			(14,861	)		(16,614	)		1,753			(11	)%
	Depreciation			(23,414	)		(16,498	)		(6,916	)		42	%
	Amortization of intangible assets			(10,212	)		(10,469	)		257			(2	)%
	Other operating expenses			(114	)		(33	)		(81	)		245	%
	Impairment of long-lived assets			(5,855	)		(5,009	)		(846	)		17	%
		Loss from operations		(67,450	)		(213,684	)		146,234			(68	)%
	Earnings from unconsolidated affiliates			1,196			577			619			107	%
	Interest expense			(22,742	)		(17,450	)		(5,292	)		30	%
	Amortization of deferred financing costs and discount (a component of interest expense)			(2,046	)		(5,164	)		3,118			(60	)%
	Other income			2,443			2,837			(394	)		(14	)%
		Loss before provision for income tax	$	(88,599	)	$	(232,884	)	$	144,285			(62	)%

        Derivative Loss Not Allocated to Segments.    Unrealized loss from the mark-to-market of our derivative instruments changed by $160.7 million while realized gain from the settlement of our derivative instruments changed by $19.5 million, due mainly to volatility in commodity prices when comparing prices in 2009 with 2008.

        Selling, General and Administrative Expenses.    Selling, general and administrative expenses decreased primarily due to lower expense related to share-based and bonus compensation plans as the established targets are not currently expected to be fully achieved.

        Depreciation.    Depreciation increased due to depreciation on additional projects completed during 2008 and the first half of 2009.

        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. During the three months ended June 30, 2008, we recognized an impairment of $5.0 million related to certain gas-gathering assets in the Northeast segment. Refer to Note 9 of the accompanying

49

Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q for further discussion.

        Interest Expense.    Interest expense increased primarily due to additional borrowings in 2008 and 2009 at higher interest rates to fund the Merger and our capital plan.

        Amortization of Deferred Financing Costs and Discount.    Amortization of deferred financing costs and discount decreased primarily due to the $4.2 million write off of financing costs related to a term loan that was repaid in April 2008. This was offset by an increase in amortization related the senior notes issued in April 2008 and May 2009 and a write off related to our revolving credit facility.

        Provision for Income Tax.    The total provision for income tax benefit was $19.4 million which includes a deferred benefit of $19.7 million related primarily to the net unrealized derivative loss during the period. The current provision for income tax expense was $0.3 million. Approximately $(0.1) million is attributable to MarkWest Hydrocarbon, Inc. and the remaining $0.4 million is related to taxes payable by the Partnership associated with the Texas Margin tax and Michigan Business Taxes.

Six months ended June 30, 2009, compared to six months ended June 30, 2008

        The tables below present information about operating income for the reported segments for the six months ended June 30, 2009 and 2008.

Southwest

		Six months ended June 30,
		2009		2008		$ Change			% Change
		(in thousands)
Revenue		$	216,175	$	343,888	$	(127,713	)		(37	)%
Operating expenses:
	Purchased product costs		97,031		202,162		(105,131	)		(52	)%
	Facility expenses		37,702		28,519		9,183			32	%
Total operating expenses before items not allocated to segments			134,733		230,681		(95,948	)		(42	)%
Portion of operating income attributable to non-controlling interests			27		—		27			N/A
Operating income before items not allocated to segments		$	81,415	$	113,207	$	(31,792	)		(28	)%

        Revenue.    Revenue decreased primarily due to lower commodity prices. Revenue from NGL, natural gas and condensate sales decreased across the segment by $141.0 million. The effect of the decrease in commodity prices on NGL sales was partially offset by increases in volumes processed at the Arapaho facilities associated with the Stiles Ranch gathering system that began operations in the fourth quarter of 2008. The revenue declines associated with lower commodity prices were also partially offset by a $10.9 million increase in gathering and treating fee revenue due to the continued expansion of our operations in the Woodford Shale.

        Purchased Product Costs.    NGL and natural gas purchases decreased across the segment due primarily to lower commodity prices as well as decreased volumes in the Other Southwest areas.

        Facility Expenses.    Facility expenses increased due primarily to the continued expansion of operations for the Woodford gathering system, including the PetroQuest acquisition in July of 2008, the

50

expansion of the Foss Lake gathering and processing operations, and increased repairs and maintenance resulting from non-recurring environmental remediation costs in East Texas.

Northeast

		Six months ended June 30,
		2009		2008		$ Change			% Change
		(in thousands)
Revenue		$	110,211	$	168,697	$	(58,486	)		(35	)%
Operating expenses:
	Purchased product costs		83,034		106,046		(23,012	)		(22	)%
	Facility expenses		9,964		9,989		(25	)		(0	)%
Total operating expenses before items not allocated to segments			92,998		116,035		(23,037	)		(20	)%
Operating income before items not allocated to segments		$	17,213	$	52,662	$	(35,449	)		(67	)%

        Revenue.    Revenue decreased due mainly to lower commodity prices realized on NGL sales from the Appalachia region. The decrease in revenue from lower commodity prices was partially offset by increased volumes which resulted from upgrades to our processing facilities in this area and increased volumes from a large producer due to expansion of the contracted volumes.

        Purchased Product Costs.    Purchased product costs decreased due to lower prices for the natural gas that must be purchased to satisfy the keep-whole arrangements in the Appalachia area.

Liberty

		Six months ended June 30,
		2009		2008		$ Change		% Change
		(in thousands)
Revenue		$	16,720	$	—	$	16,720		N/A
Operating expenses:
	Purchased product costs		2,901		—		2,901		N/A
	Facility expenses		7,122		—		7,122		N/A
Total operating expenses before items not allocated to segments			10,023		—		10,023		N/A
Portion of operating income attributable to non-controlling interests			1,643		—		1,643		N/A
Operating income before items not allocated to segments		$	5,054	$	—	$	5,054		N/A

        The results of operations for the six months ended June 30, 2009 include our operations in the northern West Virginia and western Pennsylvania areas. Revenue for the six months ended June 30, 2009 consists of approximately $12.6 million of gathering fees that are based primarily on a fixed return on the capital invested in the gathering system. Approximately $4.1 million of the revenue relates to NGL product sales under percent-of-proceeds arrangements.

        We did not have any operations in the Marcellus Shale during the six months ended June 30, 2008. We began construction in the second quarter of 2008 and gas gathering and processing operations in the fourth quarter of 2008.

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Gulf Coast

		Six months ended June 30,
		2009		2008		$ Change			% Change
		(in thousands)
Revenue		$	25,261	$	50,615	$	(25,354	)		(50	)%
Operating expenses:
	Facility expenses		8,434		8,256		178			2	%
Total operating expenses before items not allocated to segments			8,434		8,256		178			2	%
Operating income before items not allocated to segments		$	16,827	$	42,359	$	(25,532	)		(60	)%

        Revenue.    Revenue decreased due to lower commodity prices and decreased inlet volumes. The decrease in revenue was partially offset by a higher percent-of-proceeds received from one of our refinery customer contracts that changed from a fixed percent-of-proceeds to variable percent-of-proceeds during the first quarter of 2008.

Reconciliation of Segment Operating Income to Consolidated 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 loss before provision for income tax for the six months ended June 30, 2009 and 2008. 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,
			2009			2008			$ Change			% Change
			(in thousands)
Total segment revenue			$	368,367		$	563,200		$	(194,833	)		(35	)%
	Derivative loss not allocated to segments			(74,931	)		(358,841	)		283,910			(79	)%
		Total revenue	$	293,436		$	204,359		$	89,077			44	%
Operating income before items not allocated to segments			$	120,509		$	208,228		$	(87,719	)		(42	)%
	Portion of operating income attributable to non-controlling interests			1,670			—			1,670			N/A
	Derivative loss not allocated to segments			(105,844	)		(279,394	)		173,550			(62	)%
	Compensation expense included in facility expenses not allocated to segments			(558	)		(664	)		106			(16	)%
	Selling, general and administrative expenses			(30,788	)		(39,075	)		8,287			(21	)%
	Depreciation			(44,357	)		(31,023	)		(13,334	)		43	%
	Amortization of intangible assets			(20,445	)		(17,318	)		(3,127	)		18	%
	Other operating expenses			(890	)		(68	)		(822	)		1,209	%
	Impairment of long-lived assets			(5,855	)		(5,009	)		(846	)		17	%
		Loss from operations		(86,558	)		(164,323	)		77,765			(47	)%
	Earnings from unconsolidated affiliates			1,091			2,128			(1,037	)		(49	)%
	Interest expense			(40,524	)		(28,599	)		(11,925	)		42	%
	Amortization of deferred financing costs and discount (a component of interest expense)			(3,437	)		(6,207	)		2,770			(45	)%
	Other income			1,822			3,318			(1,496	)		(45	)%
		Loss before provision for income tax	$	(127,606	)	$	(193,683	)	$	66,077			(34	)%

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        Derivative Loss Not Allocated to Segments.    Unrealized loss from the mark-to-market of our derivative instruments changed by $90.1 million while realized gain from the settlement of our derivative instruments changed by $83.5 million, due mainly to volatility in commodity prices when comparing prices in 2009 with 2008. Realized gains during 2009 also include net gains of $15.2 million due to the early settlement of certain positions during 2009 as discussed in Note 5 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q.

        Selling, General and Administrative Expenses.    Selling, general and administrative expenses decreased primarily due to lower expense related to share-based and bonus compensation plans as the established targets are not currently expected to be fully achieved. Additionally, we incurred $2.6 million of expenses related to the Merger during the six months ended June 30, 2008, which did not recur in 2009.

        Depreciation and Amortization of Intangible Assets.    Depreciation and amortization expense increased partially due to a $4.4 million increase caused by the step-up in value of property, plant, and equipment and intangible assets as a result of the Merger. The remaining increase is due to depreciation on additional projects completed during 2008 and the first half of 2009.

        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. During the six months ended June 30, 2008, we recognized an impairment of $5.0 million related to certain gas-gathering assets in the Northeast segment. Refer to Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q for further discussion.

        Interest Expense.    Interest expense increased primarily due to additional borrowings in 2008 and 2009 at higher interest rates to fund the Merger and our capital plan. The increase in interest expense was partially offset by a $4.5 million increase in capitalized interest.

        Amortization of Deferred Financing Costs and Discount.    Amortization of deferred financing costs and discount decreased primarily due to the $4.2 million write off of financing costs related to a term loan that was repaid in April 2008. This was offset by an increase in amortization related the senior notes issued in April 2008 and May 2009 and a write off related to our revolving credit facility.

        Other Income.    Other income decreased primarily due to interest earnings on additional money market investments resulting from the cash raised in the debt and equity offerings in April 2008. Due to the Partnership's capital spending requirements, there was significant reduction in the excess cash available for short-term investments during the first six months of 2009 and interest rates were lower on the amounts that were invested.

        Provision for Income Tax.    The total provision for income tax benefit was $28.7 million which includes a deferred benefit of $35.3 million related primarily to the net unrealized derivative loss during the period. The current provision for income tax was $6.6 million. Approximately $5.5 million is attributable to MarkWest Hydrocarbon, Inc. and the remaining $1.0 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,
			2009		2008		% Change			2009		2008		% Change
Southwest
	East Texas
		Gathering systems throughput (Mcf/d)		463,900		431,200		7.6	%		457,400		426,600		7.2	%
		NGL product sales (gallons)		64,692,600		46,871,700		38.0	%		113,062,600		91,355,100		23.8	%
	Oklahoma
		Foss Lake gathering system throughput (Mcf/d)		93,300		95,300		(2.1	)%		92,900		99,600		(6.7	)%
		Stiles Ranch gathering system throughput (Mcf/d)(1)		91,000		N/A		N/A			92,200		N/A		N/A
		Grimes gathering system throughput (Mcf/d)		10,000		13,700		(27.0	)%		10,400		13,400		(22.4	)%
		Arapaho NGL product sales (gallons)		31,697,300		20,139,800		57.4	%		59,130,100		42,160,100		40.3	%
		Southeast Oklahoma gathering systems throughput (Mcf/d)		403,300		252,600		59.7	%		411,100		229,100		79.4	%
	Other Southwest
		Appleby gathering system throughput (Mcf/d)		49,000		62,900		(22.1	)%		53,300		62,000		(14.0	)%
		Other gathering systems throughput (Mcf/d)(2)		10,800		12,000		(10.0	)%		10,800		10,700		0.9	%
Northeast
	Appalachia(3)
		Natural gas processed (Mcf/d)		197,100		190,300		3.6	%		197,900		200,500		(1.3	)%
		Keep-whole sales (gallons)		33,255,100		19,804,500		67.9	%		84,233,000		68,852,400		22.3	%
		Percent-of-proceeds sales (gallons)		20,180,700		10,266,200		96.6	%		39,543,800		21,369,800		85.0	%
		Total NGL product sales (gallons)(4)		53,435,800		30,070,700		77.7	%		123,776,800		90,222,200		37.2	%
	Michigan
		Natural gas processed for a fee (Mcf/d)		1,900		2,700		(29.6	)%		1,700		2,700		(37.0	)%
		NGL product sales (gallons)		492,100		768,700		(36.0	)%		1,052,100		1,224,000		(14.0	)%
		Crude oil transported for a fee (Bbl/d)		12,500		13,900		(10.1	)%		12,600		13,800		(8.7	)%
Liberty(5)
		Gathering systems throughput (Mcf/d)		43,400		N/A		N/A			38,500		N/A		N/A
		NGL product sales (gallons)		7,053,000		N/A		N/A			8,436,200		N/A		N/A
Gulf Coast
		Refinery off-gas processed (Mcf/d)		124,800		122,200		2.1	%		114,600		125,100		(8.4	)%
		Liquids fractionated (Bbl/d)		25,200		24,400		3.3	%		22,600		24,900		(9.2	)%

(1)

We acquired the Stiles Ranch gathering system in August 2008, and completed construction of a 60-mile pipeline connecting the system to our Arapaho processing plants in November 2008.

(2)

Excludes lateral pipelines where revenue is not based on throughput.

(3)

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

(4)

Represents sales at the Siloam fractionator. The total sales in 2009 exclude 5.1 million gallons and 6.5 million gallons sold by the Northeast on behalf of Liberty for the three and six months ended June 30, 2009, respectively.

(5)

We began natural gas gathering and processing operations in the Marcellus Shale in October 2008.

Liquidity and Capital Resources

        In 2008 we spent approximately $638.6 million on organic growth projects and two third-party acquisitions. We also completed the Merger with MarkWest Hydrocarbon. Our 2009 capital plan includes approximately $480.0 million of capital expenditures for board-approved growth projects, of which a significant portion will be funded by our joint venture partners and by our potential divestiture of the Steam Methane Reformer ("SMR") facility as discussed in theAlternative Financing section

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below, plus approximately $5.0 million to $10.0 million for maintenance capital. As of June 30, 2009 we have spent approximately $320.8 million, including the amounts funded by M&R.

        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. In response to the recent capital market conditions, we have utilized alternative financing strategies such as entering into joint venture arrangements and sales of non-strategic assets. During the six month months ended June 30, 2009, we completed the following transactions that have improved our liquidity position:

•

amended our Partnership Credit Agreement to increase our borrowing capacity under the revolving credit facility from $350.0 million to $435.6 million.

•

received net proceeds of $113.8 million from a private placement of senior notes.

•

received net proceeds of $57.7 million from a public offering of common units.

•

entered into a joint venture agreement with M&R to partially fund our growth plan in the Marcellus Shale region.

•

entered into a joint venture agreement with ArcLight to finance a significant portion of the cost of the Arkoma Connector Pipeline.

•

announced an agreement to sell our SMR for approximately $70.0 million.

        As a result of these financing activities, which are discussed in further detail below, 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 and our current borrowing capacity under the expanded revolving credit facility. However, it may be necessary to raise additional funds to finance our future capital requirements.

Debt Financing Activities

        Effective March 2, 2009, the revolving credit facility was amended in order to accommodate the MarkWest Liberty Midstream joint venture with M&R and the available credit was expanded to $435.6 million to provide additional liquidity. Under the terms of the amendment, the accordion feature was reset to $200.0 million of uncommitted funds. The term of the original credit agreement has been reduced by one year and is now due on February 20, 2012. Under the provisions of the Partnership Credit Agreement we are subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of August 3, 2009, we had $196.0 million of borrowings outstanding and $24.0 million of letters of credit outstanding under the revolving credit facility, leaving $215.6 million available for borrowing.

        On May 26, 2009, we completed a private placement of $150.0 million in aggregate principal amount of 6.875% senior unsecured notes due 2014 to qualified institutional buyers under Rule 144A. We received proceeds of approximately $113.8 million, after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under the Partnership's revolving credit facility.

        As of June 30, 2009, we had four series of senior notes outstanding: $225.0 million aggregate principal issued in October 2004 and due November 2014; $275.0 million aggregate principal issued in July 2006 and due July 2016; $500.0 million aggregate principal issued in April 2008 and due April 2018; and $150.0 million aggregate principal issued in May 2009 and due November 2014 (altogether the "Senior Notes"). For further discussion of the Senior Notes see Note 11 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q.

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        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 Partnership Credit Agreement limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Partnership Credit Agreement prevents members of the participating bank group from requiring margin calls. As of August 3, 2009, approximately 93% 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.

        In July 2009, we entered into fixed-to-variable interest rate swap agreements having a combined notional principal amount of $275.0 million. We have designated these interest rate swaps as fair value hedges. The fair value hedges are intended to hedge against changes in fair value due to changes in the benchmark interest rate (one-month LIBOR). We are hedging a portion of our senior notes that mature on November 1, 2014. See Item 3.Quantitative and Qualitative Disclosures about Market Risk for further details of these interest rate swaps.

Equity Offering

        On June 10, 2009, we completed a public offering of approximately 3.34 million newly issued common units, which included the exercise of the overallotment option by the underwriters, representing limited partner interests at a purchase price of $18.15 per common unit. Net proceeds of approximately $57.7 million were used to partially fund our 2009 capital expenditure requirements and the remainder was used to pay down borrowings under our revolving credit facility of the Partnership Credit Agreement.

Alternative Financing Arrangements

        On February 27, 2009, we entered into a joint venture agreement in which M&R acquired a 40% interest in MarkWest Liberty Midstream (see Note 4 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q for further details of the joint venture agreement). MarkWest Liberty Midstream operates our natural gas midstream business in and around the Marcellus Shale in western Pennsylvania and northern West Virginia. As noted above, our 2009 growth capital plan is $480.0 million, of which approximately $200.0 million relates to projects included within MarkWest Liberty Midstream. In accordance with the joint venture agreement, M&R will make contributions of at least $200.0 million to MarkWest Liberty Midstream in 2009, offsetting our total 2009 cash requirements. M&R contributed $100.0 million during the six months ended June 30, 2009 and $50.0 million in July 2009, and is expected to contribute at least an additional $50.0 million prior to December 31, 2009.

        Under the joint venture agreement with M&R, we will make additional capital contributions to fund MarkWest Liberty Midstream's capital expenditures between January 1, 2010 and December 31,

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2011 in order for our share of contributed capital to be proportionate to our ownership interest. MarkWest Liberty Midstream's capital plan for 2010 and 2011 has not been finalized, so the exact timing of these contributions is currently uncertain. If we have not contributed capital in proportion to our ownership interest by the end of 2011, M&R may require us to contribute the amount of the shortfall at December 31, 2011, or may allow us to continue to fund 100% of MarkWest Liberty Midstream's capital expenditures until our total contributed capital is proportionate to our 60% ownership interest.

        On May 1, 2009, we entered into a joint venture with ArcLight. The joint venture entity, MarkWest Pioneer, operates a 50-mile interstate pipeline that connects our gathering systems in the Woodford Shale to the Midcontinent Express Pipeline and Gulf Crossing Pipeline. ArcLight acquired a 50% equity interest in MarkWest Pioneer for a total purchase price of $62.5 million. At closing, ArcLight contributed cash of $31.25 million and contributed an additional $31.25 million in July 2009, corresponding with the pipeline's commercial operations date. We retain a 50% equity interest and we are obligated to fund all capital expenditures necessary to complete construction of the Arkoma Connector Pipeline in excess of $125.0 million.

        In June 2009, we entered into an agreement to sell the SMR currently being constructed at our Javelina gas processing and fractionation facility in Corpus Christi, Texas. Under the terms of the agreement, we will receive proceeds of approximately $70.0 million and the purchaser will complete the construction of the SMR. We will have continuing involvement with the SMR pursuant to a long-term agreement to purchase all of the hydrogen produced by the SMR. We intend to use proceeds from the sale to pay down amounts outstanding under our revolving credit facility and for the continued development of other strategic projects. The potential divestiture of the SMR is anticipated to close in the third quarter of 2009 and is subject to certain closing conditions.

Liquidity Risks and Uncertainties

        The level of uncertainty that currently exists in the financial markets has created an increased risk of counterparty default that could impact our liquidity in several ways. During 2009, we expect that we will continue to borrow additional amounts under our revolving credit 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 most of our derivative instruments, the failure of one of more members could significantly reduce the cash flows 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. The credit worthiness of our trade customers is continuously monitored, and we believe that our current group of customers are sound and represent no abnormal credit risk.

        Our ability to pay distributions to our unitholders and to fund planned capital expenditures and 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 current global economic uncertainty has had a significant adverse impact on the availability of capital funding. Additionally, NGL and natural gas prices have remained at depressed levels since the end of 2008. Our operating performance could continue to be negatively impacted if these conditions do not improve or further deteriorate.

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Cash Flow

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

	Six months ended June 30,
	2009			2008
Net cash provided by operating activities	$	114,847		$	163,958
Net cash flows used in investing activities		(325,797	)		(459,453	)
Net cash flows provided by financing activities		264,084			536,113

        Net cash provided by operating activities decreased $49.1 million. The change resulted primarily from an $87.7 million decrease in operating income, excluding derivative gains and losses, in our operating segments, which was offset by an increase of $83.5 million in net cash received from the settlement of derivative positions. The cash provided by operations for the six months ended June 30, 2008 also included $40.3 million of inflows from the return of margin deposits which did not recur in 2009.

        Net cash used in investing activities decreased $133.7 million. This decrease was primarily due to cash paid as consideration in the Merger of $269.9 million in 2008. This decrease was offset by an increase of $148.6 million in capital expenditures primarily for our organic growth projects.

        Net cash provided by financing activities decreased $272.0 million. The decrease was primarily due to the $278.1 million decrease of net borrowings on long-term debt and the $113.7 million decrease in proceeds from our equity offerings. These decreases were offset by $94.5 million in net proceeds from the sale of an equity interest in MarkWest Liberty Midstream and $29.4 million in net proceeds from the sale of an equity interest in MarkWest Pioneer.

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, 2009, our purchase obligations for the remainder of 2009 were $52.4 million compared to our 2009 obligations of $111.2 million as of December 31, 2008. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

Matters Impacting Future Results

        Due to significant hurricane damage to oil and gas producing assets in the Gulf Coast area in recent years, insurance costs within this region have increased substantially. In response to these increasing costs and deductibles, we will no longer insure our interest in Starfish against future business interruption and property damages caused by named windstorms. As a result, our annual savings on insurance premiums compared to historical annual costs will be approximately $1.7 million. Our annual savings compared to the current cost of maintaining coverage against named windstorms is approximately $4.5 million. However, if a significant uninsured event occurs with respect to Starfish, it could adversely affect our operations and cash flows available for distribution to our unitholders.

Critical Accounting Policies

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

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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; and accounting for risk management activities and derivative financial instruments.

        There have not been any material changes during the six months ended June 30, 2009 to the methodology applied by management for critical accounting policies previously disclosed inManagement's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies in our 2008 Annual Report on Form 10-K, except as noted below.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Impairment of Long-Lived Assets
We evaluate our long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group's carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group.	We consider the volume of reserves behind the asset and future NGL product and natural gas prices to estimate cash flows for each asset group. The amount of additional reserves developed by future drilling activity depends, in part, on expected commodity prices. Projections of reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast.	As a result of the impairment analysis completed on June 30, 2009, we wrote down the value of long-lived assets for Wirth Gathering Partnership to zero resulting in a $5.9 million impairment expense. A significant variance in any of the assumptions or factors considered in our June 30, 2009 impairment analysis could materially affect future cash flows, which could result in the impairment of an asset. A 10% decrease in the estimated future cash flows used in the analysis would have indicated a potential impairment for three additional asset groups with a total net book value of $11.3 million.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Variable Interest Entities
When we own less than a 100% interest in an entity, we must evaluate our interests to determine if we hold a variable interest in that entity. A variable interest can be contractual, ownership, or other economic interests in an entity that change with changes in the fair value of the entity. When we conclude that we hold a variable interest in an entity we must determine if we are the entity's primary beneficiary. A primary beneficiary absorbs a majority of the entity's expected losses or residual returns, or both.	Significant judgment is exercised in evaluating the nature of our interest in an entity and our status as the primary beneficiary. We use qualitative and quantitative analysis to evaluate our interest in an entity primarily to determine if (a) the entity has insufficient equity at risk to finance its own activities and needs continuing financial support; (b) the equity holders of the entity lack the traditional characteristics of a controlling financial interest; or (c) if an equity holder's voting interests are disproportionate to its obligation to absorb expected losses.	Our interests in MarkWest Liberty Midstream and MarkWest Pioneer are considered to be variable interests and we are considered the primary beneficiary. Changes in the design or nature of MarkWest Liberty Midstream or MarkWest Pioneer, or our involvement with either of these entities may require us to reconsider our conclusions on the entity as a variable interest entity and our status as the primary beneficiary. Such reconsideration could result in the deconsolidation of MarkWest Liberty Midstream or MarkWest Pioneer. The deconsolidation would have a significant impact on our financial statements.
We consolidate all variable interest entities when we determine that we are the primary beneficiary.	We evaluate whether we are the primary beneficiary of a variable interest entity by qualitatively evaluating our level of involvement in the design of the entity, and determining if the entity's activities are substantially conducted on our behalf. A combination of qualitative and quantitative analysis is used to determine if we provide more than half of required continuing financial support to the entity, or if we absorb a majority of the entity's expected losses or returns. After initial analysis when reconsideration events occur, we evaluate an entity and our status as the primary beneficiary to determine if the nature of our interest in the entity has changed or if the design or activities of the entity have changed.	We own less than a 100% interest in several other entities including Wirth Gathering Partnership, Brightstar Partnership, Starfish and Centrahoma. We have determined that none of these entities are a variable interest entity. However, changes in the design or nature of these entities or in our involvement with these entities may require us to reconsider our conclusions. Such reconsideration could change the decision of whether or not to consolidate each of these entities. The deconsolidation of an entity that is currently consolidated or the consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements.

Recent Accounting Pronouncements

        Refer to Note 3 of the accompanying Condensed Consolidated Financial Statements for information regarding recent accounting pronouncements.

Item 3.    Quantitative and Qualitative Disclosures about Market Risk

        Except for the discussion of the interest rate risk management and the details of commodity derivative positions included below, the information about market risk for the six months ended June 30, 2009 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, 2008.

Interest Rate Risk Management

        In order to maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We may use interest rate swap agreements to manage the interest rate risk associated with the fair value of our fixed rate borrowings and to effectively convert a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate cash flows in order to achieve our desired mix of fixed and variable rate debt.

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        Since the fair value of fixed rate debt varies inversely with changes in the market rate of interest, we enter into swap agreements to receive a fixed rate and pay a variable rate of interest in order to convert the interest expense associated with certain of our senior notes from fixed rates to variable rates. As a result, our future cash flows from these swap agreements will vary with the market rate of interest. These swaps, therefore, hedge against changes in the fair value of our fixed rate debt that result from market interest rate changes. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings.

        As of June 30, 2009, we had no outstanding interest rate swap agreements. In July 2009, we entered into fixed-to-variable interest rate swap agreements having a combined notional principal amount of $275.0 million. We have designated these interest rate swaps as fair value hedges. The fair value hedges are intended to hedge against changes in fair value due to changes in the benchmark interest rate (one-month LIBOR). We are hedging a portion of our senior notes that mature on November 1, 2014.

        The following table provides information on the interest rate swaps that we have entered into subsequent to June 30, 2009.

Interest Rate Swaps	Settlement Dates	Principal Notional Amount (in millions)		WAVG LIBOR Spread
2014	May 1 and Nov. 1	$	275		3.83	%

Commodity Derivative Positions

        Refer to Note 5 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q for information regarding our derivative positions and trading activity for the six months ended June 30, 2009. The following table provides information on the derivative positions that we have entered into subsequent to June 30, 2009.

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)
2010		329	$	73.12

Item 4.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

        As of June 30, 2009, 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 the Partnership's disclosure controls and procedures as defined in Rule 13a-15(e) under the Exchange Act. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, the Partnership's management, including the Chief Executive Officer and Chief Financial Officer, concluded the Partnership's disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is (a) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (b) accumulated and communicated to the Partnership's management, including the Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

        There has been no change in our internal control over financial reporting during the quarter ended June 30, 2009 that has materially affected, or is 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 17 of the accompanying Notes to the Condensed Consolidated Financial Statements included in Part I, Item 1 of this Form 10-Q for information regarding legal proceedings.

Item 1A.    Risk Factors

        There has been no material change in the risk factors set forth in Part I, Item 1A.Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2008, except as set forth below.

Alternative financing strategies may not be successful.

        Periodically, we will consider the use of alternative financing strategies such as joint venture arrangements and the sale of non-strategic assets. Joint venture agreements may not share the risks and rewards of ownership in proportion to the voting interests. Joint venture arrangements may require us to pay certain costs or to make certain capital investments and we may have little control over the amount or the timing of these payments and investments. We may not be able to negotiate terms that adequately reimburse us for our costs to fulfill service obligations for those joint ventures where we are the operator. In addition, our joint venture partners may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. We may periodically sell assets or portions of our business. Separating the existing operations from our assets or operations of which we dispose may result in significant expense and accounting charges, disrupt our business or divert management's time and attention. We may not achieve expected cost savings from these dispositions or the proceeds from sales of assets or portions of our business may be lower than the net book value of the assets sold. We may not be relieved of all of our obligations related to the assets or businesses sold. These factors could have a material adverse effect on our revenues, income from operations, cash flows and our quarterly distribution on our common units.

Our variable rate debt makes us vulnerable to increases in interest rates.

        As of August 3, 2009, we had consolidated debt outstanding with an aggregate principal amount of $1,346 million (excluding the fair value of interest rate swaps). Of this amount, approximately $471 million was subject to variable interest rates, either as variable rate debt outstanding under our revolving credit facility or as long-term fixed rate debt converted to variable rates through the use of interest rate swaps. If interest rates increase significantly, the amount of cash required to service our debt would increase and our earnings could be adversely affected. For information on our interest rate risk, see Part I, Item 3.Quantitative and Qualitative Disclosures About Market Risk.

        We have elected hedge accounting for our interest rate swaps. The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are economically effective to balance our exposure to fixed and floating interest rates, these transactions may not be considered effective for accounting purposes. Accordingly, our financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at that point. In addition, it is not always possible for us to engage in a hedging transaction that completely mitigates our exposure to fluctuations in interest rates. Our financial statements may reflect a gain or loss arising from an exposure to interest rates for which we are unable to enter into a completely effective hedge.

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds

        None.

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Item 3.    Defaults Upon Senior Securities

        None.

Item 4.    Submission of Matters to a Vote of Security Holders

        At the close of business on April 7, 2009, the record date for the determination of unitholders entitled to vote at the Partnership's annual meeting, there were 56,893,885 common units of the Partnership issued, outstanding and entitled to vote at the meeting. At the annual meeting of unitholders held on June 2, 2009, there were not less than 51,529,324 common units, or approximately 90.6% of the outstanding common units, represented at the meeting and by proxy, therefore establishing the presence of a quorum. The Partnership's unitholders were presented with and asked to vote on two proposals. The following are the results of the voting.

Proposal No. 1:

        The election of Frank M. Semple, John M. Fox, Keith E. Bailey, Michael L. Beatty, Charles K. Dempster, Donald C. Heppermann, William A. Kellstrom, Anne E. Fox Mounsey, William P. Nicoletti and Donald D. Wolf as Directors of MarkWest Energy GP, L.L.C., the general partner of the Partnership, to hold office for a one-year term expiring at the 2010 Annual Meeting of Common Unitholders:

	Number of votes
Director Nominees	For		Authority Withheld
Frank M. Semple		50,676,946		852,378
John M. Fox		50,904,492		624,832
Keith E. Bailey		50,927,330		601,994
Michael L. Beatty		50,906,239		623,085
Charles K. Dempster		49,964,090		1,565,234
Donald C. Heppermann		50,898,150		631,173
William A. Kellstrom		50,934,099		595,225
Anne E. Fox Mounsey		50,874,948		654,376
William P. Nicoletti		50,916,303		613,021
Donald D. Wolf		50,900,416		628,908

        There were no abstentions or broker non-votes applicable to the election of directors.

Proposal No. 2:

        The ratification of Deloitte & Touche LLP as the Partnership's independent accountants for the fiscal year ending December 31, 2009:

For	51,168,207
Against	171,649
Abstained	189,468

        Abstentions had the effect of votes "against" this proposal. Broker non-votes were not counted as votes "for" or "against" this proposal and therefore had no impact on the outcome.

        In accordance with the above, each of the nominees for election to the Board of Directors received the requisite number of votes required for election and proposal number two received the requisite number of votes for approval. Accordingly, Mr. Semple, Mr. Fox, Mr. Bailey, Mr. Beatty, Mr. Dempster, Mr. Heppermann, Mr. Kellstrom, Ms. Fox Mounsey, Mr. Nicoletti and Mr. Wolf have been elected as Directors to serve for a term expiring at the 2010 Annual Meeting of Common

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Unitholders. In addition, the selection of Deloitte & Touche LLP as the Partnership's independent registered public accountants for the fiscal year ending December 31, 2009, was ratified.

Item 5.    Other Information

        None.

Item 6.    Exhibits

4.1	*	Indenture Release of Subsidiary Guarantor, dated as of May 1, 2009, among MarkWest Energy Partners, L.P., and Wells Fargo Bank, N.A.
4.2	(1)	Indenture dated as of May 26, 2009 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, and the several guarantors named therein, and Wells Fargo Bank, N.A., as trustee.
4.3	(1)	Registration Rights Agreement dated as of May 26, 2009 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, and the several guarantors named therein, and J.P. Morgan Securities Inc., RBC Capital Markets Corporation and Wachovia Capital Markets, LLC, as representatives of the several underwriters named therein.
31.1	*	Chief Executive Officer Certification Pursuant to Section 13a-14(a) of the Securities Exchange Act
31.2	*	Chief Financial Officer Certification Pursuant to Section 13a-14(a) of the Securities Exchange Act
32.1	*	Certification of the Chief Executive Officer of the General Partner 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 of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1)

Incorporated by reference to the Current Report on Form 8-K filed May 27, 2009.

*

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 10, 2009		/s/ FRANK M. SEMPLE Frank M. Semple Chairman, President and Chief Executive Officer (Principal Executive Officer)
Date: August 10, 2009		/s/ NANCY K. BUESE Nancy K. Buese Senior Vice President & Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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