UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

xQUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2011

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to           

Commission File Number 001-31239

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

1515 Arapahoe Street, Tower 1, Suite 1600, Denver, Colorado 80202-2137

(Address of principal executive offices)

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

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

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

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

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

The number of the registrant’s common units outstanding as of July 28, 2011, was 79,185,105.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets at June 30, 2011 and December 31, 2010	2
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2011 and 2010	3
	Unaudited Condensed Consolidated Statements of Changes in Equity for the six months ended June 30, 2011 and 2010	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2011 and 2010	5
	Unaudited Notes to the Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 4.	Controls and Procedures	49
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 6.	Exhibits	49
SIGNATURES		51

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

Glossary of Terms

Bbl	Barrel
Bbl/d	Barrels per day
Credit Facility	Revolving credit facility as provided under the Amended and Restated Credit Agreement, dated July 1, 2010, among the Partnership, Wells Fargo Bank, National Association, as administrative agent, RBC Capital Markets, as syndication agent, BNP Paribas, Morgan Stanley Bank and U.S. Bank National Association, as documentation agents, and the lender parties thereto.
Dth/d	Dekatherms per day
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
Gal	Gallon
Gal/d	Gallons per day
IFRS	International Financial Reporting Standards
Mcf/d	One thousand cubic feet of natural gas per day
MMBtu	One million British thermal units, an energy measurement
MMBtu/d	One million British thermal units per day
MMcf/d	One million cubic feet of natural gas per day
Net operating margin (a non-GAAP financial measure)	Segment revenue less purchased product costs, excluding any derivative gain (loss)
NGL	Natural gas liquids, such as ethane, propane, butanes and natural gasoline
N/A	Not applicable
OTC	Over-the-Counter
SEC	Securities and Exchange Commission
SMR	Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation facility in Corpus Christi, Texas
TSR Performance Units	Phantom units containing performance vesting criteria related to the Partnership’s total shareholder return.
WTI	West Texas Intermediate
VIE	Variable interest entity

1

PART I—FINANCIAL INFORMATION

Item 1.  Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	June 30, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents ($22,863 and $2,913, respectively)	$	95,035		$	67,450
Receivables, net ($12,639 and $43,783, respectively)	188,706			179,209
Inventories ($12,511 and $8,431, respectively)	31,396			23,432
Fair value of derivative instruments	2,835			4,345
Deferred income taxes	16,090			16,090
Other current assets ($746 and $272, respectively)	7,494			8,020
Total current assets	341,556			298,546
Property, plant and equipment ($1,011,845 and $849,986, respectively)	2,967,240			2,613,027
Less: accumulated depreciation ($56,369 and $38,169, respectively)	(363,398		)	(294,003		)
Total property, plant and equipment, net	2,603,842			2,319,024
Other long-term assets:
Restricted cash ($28,100 and $28,001, respectively)	28,100			28,001
Investment in unconsolidated affiliate	27,633			28,688
Intangibles, net of accumulated amortization of $146,198 and $124,568, respectively	625,737			613,578
Goodwill	67,918			9,421
Deferred financing costs, net of accumulated amortization of $12,839 and $11,445, respectively	33,975			32,901
Deferred contract cost, net of accumulated amortization of $2,106 and $1,950, respectively	1,144			1,300
Fair value of derivative instruments	3,349			417
Other long-term assets ($370 and $383, respectively)	1,771			1,486
Total assets	$	3,735,025		$	3,333,362
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($14,567 and $5,945, respectively)	$	152,623		$	122,473
Accrued liabilities ($49,078 and $64,713, respectively)	135,763			153,869
Deferred income taxes	11			11
Fair value of derivative instruments	78,345			65,489
Total current liabilities	366,742			341,842
Deferred income taxes	6,860			10,427
Fair value of derivative instruments	81,121			66,290
Long-term debt, net of discounts of $1,550 and $1,566, respectively	1,582,102			1,273,434
Other long-term liabilities ($161 and $154, respectively)	115,798			105,349
Commitments and contingencies (Note 11)
Equity:
MarkWest Energy Partners, L.P. partners’ capital (75,160 and 71,440 common units issued and outstanding, respectively)	1,106,950			1,070,503
Non-controlling interest in consolidated subsidiaries	475,452			465,517
Total equity	1,582,402			1,536,020
Total liabilities and equity	$	3,735,025		$	3,333,362

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

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

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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,
	2011			2010			2011			2010
Revenue:
Revenue	$	359,849		$	276,948		$	708,749		$	592,563
Derivative gain (loss)	40,590			46,902			(45,089		)	39,666
Total revenue	400,439			323,850			663,660			632,229
Operating expenses:
Purchased product costs	154,580			128,123			308,209			272,419
Derivative (gain) loss related to purchased product costs	(254		)	(8,392		)	19,140			4,997
Facility expenses	40,698			37,427			80,122			75,332
Derivative loss (gain) related to facility expenses	2,927			934			(84		)	128
Selling, general and administrative expenses	18,580			16,419			40,292			37,927
Depreciation	37,201			29,818			71,565			58,005
Amortization of intangible assets	10,830			10,193			21,647			20,386
Loss on disposal of property, plant and equipment	2,373			188			4,472			179
Accretion of asset retirement obligations	290			69			377			212
Total operating expenses	267,225			214,779			545,740			469,585
Income from operations	133,214			109,071			117,920			162,644
Other (expense) income:
(Loss) earnings from unconsolidated affiliate	(216		)	1,585			(755		)	1,517
Interest income	63			377			152			763
Interest expense	(27,874		)	(25,755		)	(56,137		)	(49,537		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,443		)	(2,280		)	(2,871		)	(4,892		)
Derivative gain related to interest expense	—			—			—			1,871
Loss on redemption of debt	—			—			(43,328		)	—
Miscellaneous income (expense), net	169			(9		)	131			1,053
Income before provision for income tax	103,913			82,989			15,112			113,419
Provision for income tax expense (benefit):
Current	4,089			923			4,145			6,721
Deferred	10,619			15,098			(3,567		)	13,726
Total provision for income tax	14,708			16,021			578			20,447
Net income	89,205			66,968			14,534			92,972
Net income attributable to non-controlling interest	(10,708		)	(6,751		)	(20,066		)	(11,245		)
Net income (loss) attributable to the Partnership	$	78,497		$	60,217		$	(5,532	)	$	81,727
Net income (loss) attributable to the Partnership’s common unitholders per common unit (Note 14):
Basic	$	1.03		$	0.84		$	(0.09	)	$	1.18
Diluted	$	1.03		$	0.84		$	(0.09	)	$	1.18
Weighted average number of outstanding common units:
Basic	75,160			71,111			74,847			68,795
Diluted	75,266			71,298			74,847			68,889
Cash distribution declared per common unit	$	0.67		$	0.64		$	1.32		$	1.28

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

3

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Changes in Equity

(unaudited, in thousands)

	MarkWest Energy Partners, L.P. Unitholders				Non-controlling
	Common Units	Partners’ Capital			Interest			Total
December 31, 2010	71,440	$	1,070,503		$	465,517		$	1,536,020
Share-based compensation activity	270	2,778			—			2,778
Excess tax benefits related to share-based compensation	—	1,096			—			1,096
Distributions paid	—	(100,058		)	(34,531		)	(134,589		)
Issuance of units in public offering, net of offering costs	3,450	138,163			—			138,163
Contributions to MarkWest Liberty Midstream joint venture	—	—			24,400			24,400
Net (loss) income	—	(5,532		)	20,066			14,534
June 30, 2011	75,160	$	1,106,950		$	475,452		$	1,582,402

	MarkWest Energy Partners, L.P. Unitholders				Non-controlling
	Common Units	Partners’ Capital			Interest			Total
December 31, 2009	66,275	$	1,096,654		$	282,739		$	1,379,393
Share-based compensation activity	271	5,495			—			5,495
Excess tax benefits related to share-based compensation	—	97			—			97
Distributions paid	—	(88,858		)	(2,715		)	(91,573		)
Issuance of units in public offering, net of offering costs	4,887	142,255			—			142,255
Contributions to MarkWest Liberty Midstream joint venture	—	—			120,557			120,557
Net income	—	81,727			11,245			92,972
June 30, 2010	71,433	$	1,237,370		$	411,826		$	1,649,196

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,
	2011			2010
Cash flows from operating activities:
Net income	$	14,534		$	92,972
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	71,565			58,005
Amortization of intangible assets	21,647			20,386
Loss on redemption of debt	43,328			—
Amortization of deferred financing costs and discount	2,871			4,892
Accretion of asset retirement obligations	377			212
Amortization of deferred contract cost	156			156
Phantom unit compensation expense	8,093			8,253
Loss (earnings) of unconsolidated affiliate	755			(1,517		)
Distribution from unconsolidated affiliate	300			1,155
Unrealized loss (gain) on derivative instruments	26,265			(62,987		)
Loss on disposal of property, plant and equipment	4,472			179
Deferred income taxes	(3,567		)	13,726
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	(9,215		)	(16,829		)
Inventories	(6,326		)	(378		)
Other current assets	526			4,812
Accounts payable and accrued liabilities	20,473			5,803
Other long-term assets	(384		)	(618		)
Other long-term liabilities	10,494			2,414
Net cash provided by operating activities	206,364			130,636
Cash flows from investing activities:
Capital expenditures	(234,116		)	(253,260		)
Acquisitions	(230,728		)	—
Proceeds from disposal of property, plant and equipment	2,795			417
Net cash used in investing activities	(462,049		)	(252,843		)
Cash flows from financing activities:
Proceeds from revolving credit facility	781,700			213,404
Payments of revolving credit facility	(535,200		)	(221,204		)
Proceeds from long-term debt	499,000			—
Payments of long-term debt	(437,848		)	—
Payments of premiums on redemption of long-term debt	(39,520		)	—
Payments for debt issuance costs, deferred financing costs and registration costs	(6,747		)	—
Contributions to MarkWest Liberty Midstream joint venture	24,400			120,557
Payments of SMR liability	(916		)	(480		)
Proceeds from public offering, net	138,163			142,255
Cash paid for taxes related to net settlement of share-based payment awards	(6,269		)	(3,730		)
Excess tax benefits related to share-based compensation	1,096			97
Payment of distributions to common unitholders	(100,058		)	(88,858		)
Payment of distributions to non-controlling interest	(34,531		)	(2,715		)
Net cash provided by financing activities	283,270			159,326
Net increase in cash	27,585			37,119
Cash and cash equivalents at beginning of year	67,450			97,752
Cash and cash equivalents at end of period	$	95,035		$	134,871

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

5

MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

1. Organization and Basis of Presentation

MarkWest Energy Partners, L.P. was formed in 2002 as a Delaware limited partnership. The Partnership is engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. The Partnership has extensive natural gas gathering, processing and transmission operations in the southwest, Gulf Coast, and northeast regions of the United States, including the Marcellus Shale, and is the largest natural gas processor and fractionator in the Appalachian region.

These unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the SEC for interim financial reporting. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. These condensed consolidated financial statements should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010. In management’s opinion, the Partnership has made all adjustments necessary for a fair presentation of its results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. Finally, results for the three and six months ended June 30, 2011 are not necessarily indicative of results for the full year 2011, or any other future period.

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

2. Recent Accounting Pronouncements

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

In May 2011, the FASB amended the accounting guidance for fair value measurement and disclosure.  The amended guidance was intended to converge the fair value measurement and disclosure requirements under GAAP and  IFRS. The amendment primarily clarifies the application of the existing guidance and provides for increased disclosures, particularly related to Level 3 fair value measurements.  The amended guidance is effective for the Partnership prospectively as of January 1, 2012.  Except for the additional disclosures, the adoption of the amended guidance will not have a material effect on the Partnership’s condensed consolidated financial statements.

3. Business Combination

Langley Acquisition

On February 1, 2011, the Partnership acquired natural gas processing and NGL transportation assets from EQT Gathering, LLC, a subsidiary of EQT Corporation (together with all of its affiliates, “EQT”), for a cash purchase price of approximately $230.7 million.  The assets acquired include natural gas processing facilities located near Langley, Kentucky, consisting of a cryogenic natural gas processing plant with a capacity of approximately 100 MMcf/d and a refrigeration natural gas processing plant with a capacity of approximately 75 MMcf/d (together, the “Langley Processing Facilities”), a partially constructed NGL pipeline (the “Ranger Pipeline”) that will extend through parts of Kentucky and West Virginia, and certain other related assets. The acquired assets do not include certain residue gas compression and transportation facilities at the same location as the Langley Processing Facilities. This acquisition is referred to as the Langley Acquisition. In connection with the Langley Acquisition, the Partnership will complete the construction of the Ranger Pipeline to connect

6

the Langley Processing Facilities to the Partnership’s existing pipeline that transports NGLs to its Siloam fractionation facility in South Shore, Kentucky.

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

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

The following table summarizes the purchase price allocation for the Langley Acquisition (in thousands):

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

The goodwill recognized from the Langley Acquisition results primarily from the Partnership’s ability to continue to grow its business in the liquids-rich gas areas of the Appalachian Basin and access additional markets in a competitive environment as a result of securing the processing rights for a large area of dedicated acreage and acquiring expanded midstream infrastructure in the acquisition. All of the goodwill is deductible for tax purposes.

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

The results of operations from the Langley Acquisition are included in the condensed consolidated financial statements from the acquisition date. Revenue and net income related to the Langley Acquisition were approximately $6.2 million and $2.2 million, respectively, for the quarter ended June 30, 2011 and $10.1 million and $3.6 million, respectively, for the six months ended June 30, 2011.

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

4. Variable Interest Entities

MarkWest Liberty Midstream

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

As of June 30, 2011, the capital contributed to MarkWest Liberty Midstream is disproportionate to each member’s respective ownership interest. The cumulative capital contributed by M&R exceeded its ownership interest by $7.8 million. Under the terms of the joint venture agreement, M&R received a special $1.3 million allocation of net income from MarkWest Liberty Midstream during the first six months of 2011 due to its excess contributions. The non-cash allocation is recorded in Net income attributable to non-controlling interest.

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MarkWest Pioneer

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

Financial Statement Impact of VIEs

As the primary beneficiary of MarkWest Liberty Midstream and MarkWest Pioneer, the Partnership consolidates the entities and recognizes non-controlling interests. The following tables show the consolidated assets and liabilities attributable to VIEs, excluding intercompany balances, as of June 30, 2011 and December 31, 2010 (in thousands):

	As of June 30, 2011
	MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents	$	20,491	$	2,372	$	22,863
Receivables, net	11,311		1,328		12,639
Inventories	12,511		—		12,511
Other current assets	746		—		746
Property, plant and equipment, net of accumulated depreciation of $43,944 and $12,425, respectively	811,555		143,921		955,476
Restricted cash	28,100		—		28,100
Other long-term assets	267		103		370
Total assets	$	884,981	$	147,724	$	1,032,705
LIABILITIES
Accounts payable	$	14,532	$	35	$	14,567
Accrued liabilities	48,177		901		49,078
Other long-term liabilities	90		71		161
Total liabilities	$	62,799	$	1,007	$	63,806

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

The assets of the VIEs are the property of the respective entities and are not available to the Partnership for any other purpose, including as collateral for its secured debt (see Note 9 and Note 16). VIE asset balances can only be used to settle obligations of each respective VIE. The liabilities of the VIEs do not represent additional claims against the

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Partnership’s general assets, and the creditors or beneficial interest holders of the VIE do not have recourse to the general credit of the Partnership. The Partnership’s Liberty segment includes the results of operations of MarkWest Liberty Midstream and the Partnership’s Southwest segment includes the results of operations of MarkWest Pioneer (see Note 15). The cash flow information for MarkWest Liberty Midstream and MarkWest Pioneer comprise substantially all of the cash flow information of the Partnership’s non-guarantor subsidiaries (see Note 16). The Partnership’s maximum exposure to loss as a result of its involvement with the VIEs includes its equity investment, any additional capital contribution commitments and any operating expense incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the six months ended June 30, 2011 and 2010.

5. Derivative Financial Instruments

Commodity Derivatives

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

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

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

As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2014. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

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

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

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As of June 30, 2011, the Partnership had the following outstanding commodity contracts that were entered into to economically hedge future sales of NGLs or future purchases of natural gas.

Derivative contracts not designated as hedging instruments	Notional Quantity (net)
Crude oil (bbl)	6,382,676
Natural gas (MMBtu)	15,635,865
Refined products (gal)	151,776,610

Embedded Derivatives in Commodity Contracts

The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative loss related to purchased product costs. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of June 30, 2011, the estimated fair value of this contract was a liability of $104.1 million and the recorded value was $50.6 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of June 30, 2011 (in thousands).

Fair value of commodity contract	$	104,074
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of June 30, 2011	$	50,567

The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at one of its plant locations through the fourth quarter of 2014. The value of the derivative component of this contract is marked to market through Derivative gain related to facility expenses. As of June 30, 2011, the estimated fair value of this contract was an asset of $1.1 million.

Financial Statement Impact of Derivative Instruments

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

	Assets				Liabilities
Derivative instruments not designated as hedging instruments and their balance sheet location	June 30, 2011		December 31, 2010		June 30, 2011			December 31, 2010
Fair value of derivative instruments - current	$	2,835	$	4,345	$	(78,345	)	$	(65,489	)
Fair value of derivative instruments - long-term	3,349		417		(81,121		)	(66,290		)
Total	$	6,184	$	4,762	$	(159,466	)	$	(131,779	)

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Derivative instruments not designated as hedging	Three months ended June 30,						Six months ended June 30,
instruments and the location of gain or (loss) recognized in income	2011			2010			2011			2010
Revenue: Derivative gain (loss)
Realized loss	$	(12,186	)	$	(5,690	)	$	(26,577	)	$	(18,819	)
Unrealized gain (loss)	52,776			52,592			(18,512		)	58,485
Total revenue: derivative gain (loss)	40,590			46,902			(45,089		)	39,666
Derivative gain (loss) related to purchased product costs
Realized loss	(5,560		)	(5,733		)	(13,447		)	(11,171		)
Unrealized gain (loss)	5,814			14,125			(5,693		)	6,174
Total derivative gain (loss) related to purchased product costs	254			8,392			(19,140		)	(4,997		)
Derivative (loss)gain related to facility expenses
Unrealized (loss) gain	(2,927		)	(934		)	84			(128		)
Derivative gain related to interest expense
Realized gain	—			—			—			2,380
Unrealized loss	—			—			—			(509		)
Total derivative gain related to interest expense	—			—			—			1,871
Miscellaneous income (expense), net
Unrealized gain	—			3			—			59
Total gain (loss)	$	37,917		$	54,363		$	(64,145	)	$	36,471

At June 30, 2011, the fair value of the Partnership’s commodity derivative contracts is inclusive of premium payments of $2.3 million, net of amortization. For the three months ended June 30, 2011 and 2010, the Realized loss—revenue includes amortization of premium payments of $1.1 million and $0.5 million, respectively. For the six months ended June 30, 2011 and 2010, the Realized loss—revenue includes amortization of premium payments of $2.1 million and $1.1 million, respectively.

6. Fair Value

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 5. The following table presents the derivative instruments carried at fair value as of June 30, 2011 and December 31, 2010 (in thousands):

As of June 30, 2011	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	333	$	(81,878	)
Significant unobservable inputs (Level 3)
Commodity contracts	4,731		(27,021		)
Embedded derivatives in commodity contracts	1,120		(50,567		)
Total carrying value in Condensed Consolidated Balance Sheet	$	6,184	$	(159,466	)

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

Changes in Level 3 Fair Value Measurements

The table below includes a rollforward of the balance sheet amounts for the three and six months ended June 30, 2011 and 2010 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

	Three months ended June 30, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(35,906	)	$	(50,607	)
Total gain or (loss) (realized and unrealized) included in earnings (1)	10,456			(2,825		)
Settlements	3,160			3,985
Fair value at end of period	$	(22,290	)	$	(49,447	)
The amount of total gain or (loss) for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	10,206		$	(2,429	)

	Three months ended June 30, 2010
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Embedded Derivative in Debt Contract
Fair value at beginning of period	$	(7,907	)	$	(30,861	)	$	(134	)
Total gain (realized and unrealized) included in earnings (1)	13,029			4,183			3
Settlements (net)	226			3,042			—
Fair value at end of period	$	5,348		$	(23,636	)	$	(131	)
The amount of total gain for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	10,009		$	7,225		$	3

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	Six months ended June 30, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(14,357	)	$	(34,936	)
Total loss (realized and unrealized) included in earnings (1)	(12,537		)	(22,105		)
Settlements	4,604			7,594
Fair value at end of period	$	(22,290	)	$	(49,447	)
The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	(10,578	)	$	(20,277	)

	Six months ended June 30, 2010
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Interest Rate Contracts			Embedded Derivative in Debt Contract
Fair value at beginning of period	$	(11,340	)	$	(34,199	)	$	509		$	(190	)
Total gain (realized and unrealized) included in earnings (1)	10,271			5,120			1,871			59
Settlements (net)	6,417			5,443			(2,380		)	—
Fair value at end of period	$	5,348		$	(23,636	)	$	—		$	(131	)
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	7,551		$	10,562		$	—		$	59

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

7. Inventories

Inventories consist of the following (in thousands):

	June 30, 2011		December 31, 2010
Natural gas liquids	$	22,456	$	15,930
Spare parts	8,940		7,502
Total inventories	$	31,396	$	23,432

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8. Goodwill

Changes in goodwill for the six months ended June 30, 2011 are summarized as follows (in thousands):

	Southwest			Northeast		Gulf Coast			Total
Historical goodwill	$	24,324		$	3,948	$	9,854		$	38,126
Cumulative impairment	(18,851		)	—		(9,854		)	(28,705		)
Balance as of December 31, 2010	5,473			3,948		—			9,421
Acquisition(1)	—			58,497		—			58,497
Balance as of June 30, 2011	$	5,473		$	62,445	$	—		$	67,918

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

9. Long-Term Debt

Debt is summarized below (in thousands):

	June 30, 2011		December 31, 2010
Credit Facility
Revolving credit facility, 4.22% average interest due July 2015	$	246,500	$	—
Senior Notes (1)
Senior Notes, 8.5% interest, net of discount of $6 and $642, respectively, issued July 2006 and due July 2016	2,784		274,358
Senior Notes, 8.75% interest, net of discount of $576 and $924, respectively, issued April and May 2008 and due April 2018	333,786		499,076
Senior Notes, 6.75% interest, issued November 2010 and due November 2020	500,000		500,000
Senior Notes, 6.5% interest, net of discount of $968, issued February and March 2011 and due August 2021	499,032		—
Total long-term debt	$	1,582,102	$	1,273,434

(1)The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $1,366.2 million and $1,333.9 million as of June 30, 2011 and December 31, 2010, respectively, based on quoted market prices.

Credit Facility

On June 15, 2011, the Partnership executed a joinder agreement to the Credit Facility to include an additional member in the bank group and to exercise a portion of the accordion feature under the Credit Facility, thereby increasing the borrowing capacity of the Credit Facility to $745 million and reducing the uncommitted accordion feature to $155 million.

Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by the Partnership’s wholly-owned subsidiaries and collateralized by substantially all of the Partnership’s assets and those of its wholly-owned subsidiaries. As of June 30, 2011, the Partnership had $27.3 million of letters of credit outstanding under the Credit Facility and approximately $471.2 million available for borrowing.

Senior Notes

On February 24, 2011, the Partnership completed a public offering of $300 million in aggregate principal amount of 6.5% senior unsecured notes (“2021 Senior Notes”), which were issued at par. On March 10, 2011, the Partnership completed a follow-on public offering of an additional $200 million in aggregate principal amount of 2021 Senior Notes, which were issued at 99.5% of par and are treated as a single class of debt securities with the 2021 Senior Notes issued on February 24, 2011. The 2021 Senior Notes mature on August 15, 2021, and interest is payable semi-annually in arrears on February 15 and August 15, commencing August 15, 2011. The Partnership received aggregate net proceeds of approximately $492 million from the 2021 Senior Notes offerings after deducting the underwriting fees and other third-party expenses. The Partnership

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used the net proceeds from these offerings to fund the repurchase of approximately $272.2 million in aggregate principal amount of the Partnership’s 8.5% senior unsecured notes due 2016 (the “2016 Senior Notes”) and approximately $165.6 million in aggregate principal amount of the Partnership’s 8.75% senior unsecured notes due 2018 (the “2018 Senior Notes”). The remaining proceeds were used to repay borrowings under the Credit Facility. The Partnership recorded a pre-tax loss on redemption of debt of approximately $43.3 million in the first quarter of 2011 related to the  repurchase of  the 2016 Senior Notes and 2018 Senior Notes, which consisted of approximately $3.8 million for the non-cash write off of the unamortized discount and deferred finance costs and approximately $39.5 million for the payment of the related tender premiums and third-party expenses.

10. Equity

Equity Offering

On January 14, 2011, the Partnership completed a public offering of approximately 3.45 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriter’s over-allotment option. Net proceeds after deducting the underwriter’s fees and third-party offering expenses were approximately $138.2 million and were used to partially fund the Partnership’s ongoing capital expenditure program, including a portion of the costs associated with the Langley Acquisition (see Note 3).

Distributions of Available Cash

Quarter Ended	Distribution Per Common Unit		Record Date	Payment Date
June 30, 2011	$	0.70	August 1, 2011	August 12, 2011
March 31, 2011	$	0.67	May 2, 2011	May 13, 2011
December 31, 2010	$	0.65	February 7, 2011	February 14, 2011

11. Commitments and Contingencies

Legal

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

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

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

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12. Incentive Compensation Plans

Compensation Expense

Total compensation expense recorded for share-based pay arrangements for the three and six months ended June 30, 2011 and 2010 is as follows (in thousands):

	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011		2010
Phantom units	$	2,457	$	1,968	$	8,093	$	8,253
Distribution equivalent rights	110		310		212		621
Total compensation expense	$	2,567	$	2,278	$	8,305	$	8,874

13. Income Taxes

A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate to (loss) income before provision for income tax for the six months ended June 30, 2011 and 2010 is as follows (in thousands):

	Six months ended June 30, 2011
	Corporation			Partnership			Eliminations			Consolidated
(Loss) income before provision for income tax	$	(2,541	)	$	20,951		$	(3,298	)	$	15,112
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	$	(889	)	$	—		$	—		$	(889	)
Permanent items	(5		)	—			—			(5		)
State income taxes net of federal benefit	(72		)	107			—			35
Provision on income from Class A units (1)	1,311			—			—			1,311
Other	126			—			—			126
Provision for income tax	$	471		$	107		$	—		$	578

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

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

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14. Earnings (Loss) Per Common Unit

The following table shows the computation of basic and diluted net income (loss) per common unit for the three and six months ended June 30, 2011 and 2010, and the weighted-average units used to compute diluted net income (loss) per common unit (in thousands, except per unit data):

	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011			2010
Net income (loss) attributable to the Partnership	$	78,497	$	60,217	$	(5,532	)	$	81,727
Less: Income allocable to phantom units	719		455		847			551
Income (loss) available for common unitholders	$	77,778	$	59,762	$	(6,379	)	$	81,176
Weighted average common units outstanding - basic	75,160		71,111		74,847			68,795
Effect of dilutive instruments (1)	106		187		—			94
Weighted average common units outstanding - diluted (1)	75,266		71,298		74,847			68,889
Net income (loss) attributable to the Partnership’s common unitholders per common unit
Basic	$	1.03	$	0.84	$	(0.09	)	$	1.18
Diluted	$	1.03	$	0.84	$	(0.09	)	$	1.18

(1)Dilutive instruments include TSR Performance Units and are based on the number of units, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period. For the six months ended June 30, 2011, 131 units were excluded from the calculation of diluted units because the impact was anti-dilutive.

15. Segment Information

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

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The tables below present the Partnership’s segment profit measure, Operating income before items not allocated to segments, for the three and six months ended June 30, 2011 and 2010 and capital expenditures for the six months ended June 30, 2011 and 2010 for the reported segments (in thousands).

Three months ended June 30, 2011:	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	235,575	$	53,676	$	48,337	$	24,683	$	362,271
Purchased product costs	128,988		15,702		9,890		—		154,580
Net operating margin	106,587		37,974		38,447		24,683		207,691
Facility expenses	20,855		6,929		7,269		8,312		43,365
Portion of operating income attributable to non-controlling interests	1,346		—		15,182		—		16,528
Operating income before items not allocated to segments	$	84,386	$	31,045	$	15,996	$	16,371	$	147,798

Three months ended June 30, 2010:	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	155,043	$	81,322	$	18,738	$	21,845	$	276,948
Purchased product costs	71,389		56,734		—		—		128,123
Net operating margin	83,654		24,588		18,738		21,845		148,825
Facility expenses	19,395		5,062		6,140		9,395		39,992
Portion of operating income attributable to non-controlling interests	1,556		—		5,208		—		6,764
Operating income before items not allocated to segments	$	62,703	$	19,526	$	7,390	$	12,450	$	102,069

The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the three months ended June 30, 2011 and 2010 (in thousands).

	Three months ended June 30,
	2011			2010
Total segment revenue	$	362,271		$	276,948
Derivative gain not allocated to segments	40,590			46,902
Revenue deferral adjustment (1)	(2,422		)	—
Total revenue	$	400,439		$	323,850
Operating income before items not allocated to segments	$	147,798		$	102,069
Portion of operating income attributable to non-controlling interests	16,528			6,764
Derivative gain not allocated to segments	37,917			54,360
Revenue deferral adjustment (1)	(2,422		)	—
Compensation expense included in facility expenses not allocated to segments	(188		)	(286		)
Facility expenses adjustments	2,855			2,851
Selling, general and administrative expenses	(18,580		)	(16,419		)
Depreciation	(37,201		)	(29,818		)
Amortization of intangible assets	(10,830		)	(10,193		)
Loss on disposal of property, plant and equipment	(2,373		)	(188		)
Accretion of asset retirement obligations	(290		)	(69		)
Income from operations	133,214			109,071
(Loss) earnings from unconsolidated affiliate	(216		)	1,585
Interest income	63			377
Interest expense	(27,874		)	(25,755		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,443		)	(2,280		)
Miscellaneous income (expense), net	169			(9		)
Income before provision for income tax	$	103,913		$	82,989

18

(1)Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended June 30, 2011, approximately $0.2 million and $2.2 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

Six months ended June 30, 2011:	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	437,349	$	145,767	$	89,556	$	46,442	$	719,114
Purchased product costs	232,184		56,580		19,445		—		308,209
Net operating margin	205,165		89,187		70,111		46,442		410,905
Facility expenses	41,012		12,523		13,767		17,302		84,604
Portion of operating income attributable to non-controlling interests	2,518		—		27,559		—		30,077
Operating income before items not allocated to segments	$	161,635	$	76,664	$	28,785	$	29,140	$	296,224
Capital expenditures	$	51,312	$	3,370	$	176,027	$	845	$	231,554
Capital expenditures not allocated to segments									2,562
Total capital expenditures									$	234,116

Six months ended June 30, 2010:	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	320,007	$	193,170	$	37,748	$	41,638	$	592,563
Purchased product costs	146,014		123,821		2,584		—		272,419
Net operating margin	173,993		69,349		35,164		41,638		320,144
Facility expenses	39,884		9,287		13,453		15,090		77,714
Portion of operating income attributable to non-controlling interests	3,056		—		8,845		—		11,901
Operating income before items not allocated to segments	$	131,053	$	60,062	$	12,866	$	26,548	$	230,529
Capital expenditures	$	71,734	$	1,113	$	175,848	$	2,990	$	251,685
Capital expenditures not allocated to segments									1,575
Total capital expenditures									$	253,260

19

The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the six months ended June 30, 2011 and 2010 (in thousands).

	Six months ended June 30,
	2011			2010
Total segment revenue	$	719,114		$	592,563
Derivative (loss) gain not allocated to segments	(45,089		)	39,666
Revenue deferral adjustment (1)	(10,365		)	—
Total revenue	$	663,660		$	632,229
Operating income before items not allocated to segments	$	296,224		$	230,529
Portion of operating income attributable to non-controlling interests	30,077			11,901
Derivative (loss) gain not allocated to segments	(64,145		)	34,541
Revenue deferral adjustment (1)	(10,365		)	—
Compensation expense included in facility expenses not allocated to segments	(1,228		)	(1,008		)
Facility expenses adjustments	5,710			3,390
Selling, general and administrative expenses	(40,292		)	(37,927		)
Depreciation	(71,565		)	(58,005		)
Amortization of intangible assets	(21,647		)	(20,386		)
Loss on disposal of property, plant and equipment	(4,472		)	(179		)
Accretion of asset retirement obligations	(377		)	(212		)
Income from operations	117,920			162,644
(Loss) earnings from unconsolidated affiliate	(755		)	1,517
Interest income	152			763
Interest expense	(56,137		)	(49,537		)
Amortization of deferred financing costs and discount (a component of interest expense)	(2,871		)	(4,892		)
Derivative gain related to interest expense	—			1,871
Loss on redemption of debt	(43,328		)	—
Miscellaneous income, net	131			1,053
Income before provision for income tax	$	15,112		$	113,419

(1)Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the six months ended June 30, 2011, approximately $6.7 million and $3.6 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

20

The tables below present information about segment assets as of June 30, 2011 and December 31, 2010 (in thousands):

	June 30, 2011		December 31, 2010
Southwest	$	1,672,813	$	1,646,607
Northeast	453,888		244,219
Liberty	884,981		743,943
Gulf Coast	588,030		573,456
Total segment assets	3,599,712		3,208,225
Assets not allocated to segments:
Certain cash and cash equivalents	65,836		49,776
Fair value of derivatives	6,184		4,762
Investment in unconsolidated affiliate	27,633		28,688
Other (1)	35,660		41,911
Total assets	$	3,735,025	$	3,333,362

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

16. Supplemental Condensed Consolidating Financial Information

The Partnership has no operations independent of its subsidiaries. As of June 30, 2011, the Partnership’s obligations under the outstanding Senior Notes (see Note 9) were fully and unconditionally guaranteed, jointly and severally, by all of its wholly-owned subsidiaries. MarkWest Liberty Midstream and MarkWest Pioneer, together with certain of the Partnership’s other subsidiaries that do not guarantee the outstanding Senior Notes, have significant assets and operations in aggregate. For the purpose of the following financial information, the Partnership’s investments in its subsidiaries and the guarantor subsidiaries’ investments in their subsidiaries are presented in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. The operations, cash flows and financial position of the co-issuer of the Senior Notes, MarkWest Energy Finance Corporation, are minor and therefore have been included with the Parent’s financial information. Condensed consolidating financial information for the Partnership, its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2011 and December 31, 2010 and for the three and six months ended June 30, 2011 and 2010 is as follows (in thousands):

21

Condensed Consolidating Balance Sheets

	As of June 30, 2011
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	3	$	71,584	$	23,448	$	—		$	95,035
Receivables and other current assets	846		216,623		26,217		—			243,686
Intercompany receivables	1,667,583		9,237		9,688		(1,686,508		)	—
Fair value of derivative instruments	—		2,835		—		—			2,835
Total current assets	1,668,432		300,279		59,353		(1,686,508		)	341,556
Total property, plant and equipment, net	4,379		1,657,181		956,486		(14,204		)	2,603,842
Other long-term assets:
Restricted cash	—		—		28,100		—			28,100
Investment in unconsolidated affiliate	—		27,633		—		—			27,633
Investment in consolidated affiliates	825,036		482,222		—		(1,307,258		)	—
Intangibles, net of accumulated amortization	—		625,177		560		—			625,737
Fair value of derivative instruments	—		3,349		—		—			3,349
Intercompany notes receivable	215,160		—		—		(215,160		)	—
Other long-term assets	33,657		70,780		371		—			104,808
Total assets	$	2,746,664	$	3,166,621	$	1,044,870	$	(3,223,130	)	$	3,735,025
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	9,217	$	1,677,066	$	225	$	(1,686,508	)	$	—
Fair value of derivative instruments	—		78,345		—		—			78,345
Other current liabilities	29,173		195,445		63,779		—			288,397
Total current liabilities	38,390		1,950,856		64,004		(1,686,508		)	366,742
Deferred income taxes	1,606		5,254		—		—			6,860
Intercompany notes payable	—		192,160		23,000		(215,160		)	—
Fair value of derivative instruments	—		81,121		—		—			81,121
Long-term debt, net of discounts	1,582,102		—		—		—			1,582,102
Other long-term liabilities	3,412		112,194		192		—			115,798
Equity:
MarkWest Energy Partners, L.P. partners’ capital	1,121,154		825,036		957,674		(1,796,914		)	1,106,950
Non-controlling interest in consolidated subsidiaries	—		—		—		475,452			475,452
Total equity	1,121,154		825,036		957,674		(1,321,462		)	1,582,402
Total liabilities and equity	$	2,746,664	$	3,166,621	$	1,044,870	$	(3,223,130	)	$	3,735,025

22

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

23

Condensed Consolidating Statements of Operations

	Three Months Ended June 30, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	348,371		$	52,068		$	—		$	400,439
Operating expenses:
Purchased product costs	—			144,403			9,923			—			154,326
Facility expenses	—			35,419			8,373			(167		)	43,625
Selling, general and administrative expenses	11,224			7,153			1,932			(1,729		)	18,580
Depreciation and amortization	181			38,008			10,011			(169		)	48,031
Other operating expenses	374			1,987			302			—			2,663
Total operating expenses	11,779			226,970			30,541			(2,065		)	267,225
(Loss) income from operations	(11,779		)	121,401			21,527			2,065			133,214
Earnings from consolidated affiliates	114,152			10,769			—			(124,921		)	—
Other expense, net	(22,071		)	(3,759		)	(50		)	(3,421		)	(29,301		)
Income before provision for income tax	80,302			128,411			21,477			(126,277		)	103,913
Provision for income tax expense	449			14,259			—			—			14,708
Net income	79,853			114,152			21,477			(126,277		)	89,205
Net income attributable to non-controlling interest	—			—			—			(10,708		)	(10,708		)
Net income attributable to the Partnership	$	79,853		$	114,152		$	21,477		$	(136,985	)	$	78,497

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

24

	Six Months Ended June 30, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	566,851		$	96,809		$	—		$	663,660
Operating expenses:
Purchased product costs	—			307,847			19,502			—			327,349
Facility expenses	—			64,350			16,022			(334		)	80,038
Selling, general and administrative expenses	24,078			15,371			3,969			(3,126		)	40,292
Depreciation and amortization	356			74,477			18,696			(317		)	93,212
Other operating expenses	673			3,826			350			—			4,849
Total operating expenses	25,107			465,871			58,539			(3,777		)	545,740
(Loss) income from operations	(25,107		)	100,980			38,270			3,777			117,920
Earnings from consolidated affiliates	112,919			18,144			—			(131,063		)	—
Loss on redemption of debt	(43,328		)	—			—			—			(43,328		)
Other expense, net	(46,965		)	(5,734		)	(60		)	(6,721		)	(59,480		)
(Loss) income before provision for income tax	(2,481		)	113,390			38,210			(134,007		)	15,112
Provision for income tax expense	107			471			—			—			578
Net (loss) income	(2,588		)	112,919			38,210			(134,007		)	14,534
Net income attributable to non-controlling interest	—			—			—			(20,066		)	(20,066		)
Net (loss) income attributable to the Partnership	$	(2,588	)	$	112,919		$	38,210		$	(154,073	)	$	(5,532	)

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

25

Condensed Consolidating Statements of Cash Flows

	Six Months Ended June 30, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(66,828	)	$	189,342		$	87,113		$	(3,263	)	$	206,364
Cash flows from investing activities:
Capital expenditures	(610		)	(58,715		)	(179,302		)	4,511			(234,116		)
Acqusitions	—			(230,728		)	—			—			(230,728		)
Equity investments	(21,556		)	(130,361		)	—			151,917			—
Distributions from consolidated affiliates	27,208			35,147			—			(62,355		)	—
Investment in intercompany notes, net	(17,450		)	—			—			17,450			—
Proceeds from disposal of property, plant and equipment	—			89			3,954			(1,248		)	2,795
Net cash used in investing activities	(12,408		)	(384,568		)	(175,348		)	110,275			(462,049		)
Cash flows from financing activities:
Proceeds from revolving credit facility	781,700			—			—			—			781,700
Payments of revolving credit facility	(535,200		)	—			—			—			(535,200		)
Proceeds from long-term debt	499,000			—			—			—			499,000
Payments of long-term debt	(437,848		)	—			—			—			(437,848		)
Payments of premiums on redemption of long-term debt	(39,520		)	—			—			—			(39,520		)
(Payments of) proceeds from intercompany notes, net	—			(5,550		)	23,000			(17,450		)	—
Payments for debt issuance costs, deferred financing costs and registration costs	(6,747		)	—			—			—			(6,747		)
Contributions from parent, net	—			21,556			—			(21,556		)	—
Contributions to joint ventures, net	—			—			154,761			(130,361		)	24,400
Payments of SMR liability	—			(916		)	—			—			(916		)
Proceeds from public equity offering, net	138,163			—			—			—			138,163
Share-based payment activity	(6,269		)	1,096			—			—			(5,173		)
Payment of distributions	(100,058		)	(27,208		)	(69,678		)	62,355			(134,589		)
Intercompany advances, net	(213,982		)	213,982			—			—			—
Net cash provided by financing activities	79,239			202,960			108,083			(107,012		)	283,270
Net increase in cash	3			7,734			19,848			—			27,585
Cash and cash equivalents at beginning of year	—			63,850			3,600			—			67,450
Cash and cash equivalents at end of period	$	3		$	71,584		$	23,448		$	—		$	95,035

26

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

27

17. Supplemental Cash Flow Information

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

	Six months ended June 30,
	2011		2010
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	57,820	$	49,541
Cash paid for income taxes, net of refunds	514		4,690
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	58,429	$	56,578
Interest capitalized on construction in progress	199		2,705
Issuance of common units for vesting of share-based payment awards	5,282		7,030

18. Subsequent Events

On July 13, 2011, the Partnership completed a public offering of approximately 4.0 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option.  Net proceeds after deducting underwriters’ fees and other third-party expenses were approximately $185.1 million and were used to repay borrowings under the Credit Facility and to partially fund the ongoing capital expenditure program.

On July 15, 2011, the Partnership repurchased the 2016 Senior Notes that were outstanding as of June 30, 2011.

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

Forward-Looking Statements

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

Overview

We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. We have extensive natural gas gathering, processing and transmission operations in the southwest, Gulf Coast and northeast regions of the United States, including the Marcellus Shale, and are the largest natural gas processor and fractionator in the Appalachian region.

Significant Financial and Other Highlights

Significant financial and other highlights for the three months ended June 30, 2011 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

·Total segment operating income before items not allocated to segments (a non-GAAP financial measure, see below) increased approximately $45.7 million, or 45%, for the three months ended June 30, 2011 compared to the same period in 2010. The increase is due primarily to higher commodity prices in 2011, expanding operations in our Liberty and Northeast segments and increased volumes from a large producer in our Southwest segment. The increase was partially offset by a $6.3 million increase in cash paid for the settlement of commodity derivative positions.

·The cryogenic processing capacity in the Liberty segment increased by 335 MMcf/d to a total of 625 MMcf/d as a 200 MMcf/d processing facility at our Houston, Pennsylvania processing complex began operations in April 2011 and a 135 MMcf/d processing facility at our Majorsville processing complex began operations in June 2011.

Non-GAAP financial measures

In evaluating the Partnership’s financial performance, management utilizes the segment performance measures, segment revenues and operating income before items not allocated to segments. These financial measures are presented in Note 15 to the accompanying condensed consolidated financial statements and are considered non-GAAP financial measures when presented outside of the notes to the condensed consolidated financial statements. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Note 15 to the accompanying condensed consolidated financial statements for the reconciliations of segment revenue and operating income before items not allocated to segments to the respective most comparable GAAP measure.

Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure) which is defined as segment revenue, excluding any derivative gain (loss) and adjusted for the non-cash impact of revenue deferrals related to certain agreements, less purchased product costs, excluding any derivative gain (loss). These adjustments have been made for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting.

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The following is a reconciliation to Income from operations, the most comparable GAAP financial measure to net operating margin (in thousands):

	Three months ended June 30,						Six months ended June 30,
	2011			2010			2011		2010
Segment revenue	$	362,271		$	276,948		$	719,114	$	592,563
Purchased product costs	154,580			128,123			308,209		272,419
Net operating margin	207,691			148,825			410,905		320,144
Facility expenses	40,698			37,427			80,122		75,332
Derivative (gain) loss	(37,917		)	(54,360		)	64,145		(34,541		)
Revenue deferral adjustment	2,422			—			10,365		—
Selling, general and administrative expenses	18,580			16,419			40,292		37,927
Depreciation	37,201			29,818			71,565		58,005
Amortization of intangible assets	10,830			10,193			21,647		20,386
Loss on disposal of property, plant and equipment	2,373			188			4,472		179
Accretion of asset retirement obligations	290			69			377		212
Income from operations	$	133,214		$	109,071		$	117,920	$	162,644

Segment revenues, operating income before items not allocated to segments and net operating margin (collectively the “Non-GAAP Measures”) do not have any standardized definition and therefore are unlikely to be comparable to similar measures presented by other reporting companies. Non-GAAP Measures should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Non-GAAP Measures and the underlying methodology in excluding certain revenues or charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, receive such revenue or incur such charges in future periods.

Our Contracts

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

The following table does not give effect to our active commodity risk management program. For the six months ended June 30, 2011, we calculated the following approximate percentages of our segment revenue and net operating margin from the following types of contracts:

	Fee-Based		Percent-of-Proceeds (1)		Percent-of-Index (2)		Keep-Whole (3)		Total
Segment revenue	21	%	36	%	4	%	39	%	100	%
Net operating margin (4)	37	%	29	%	0	%	34	%	100	%

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

(2)Includes arrangements tied to natural gas prices.

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

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

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Seasonality

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

Results of Operations

Segment Reporting

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

Southwest

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

·Oklahoma.  We own a natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. Natural gas gathered in the Woodford system is processed through Centrahoma Processing LLC (“Centrahoma”), our equity investment. In addition, we own the Foss Lake natural gas gathering system and the Arapaho natural gas processing complex, all located in Roger Mills, Custer and Ellis Counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities. The majority of the gathered gas ultimately is compressed and delivered to the processing plants. We also own the Grimes gathering system that is located in Roger Mills and Beckham Counties in western Oklahoma and a gathering system in the Granite Wash formation in the Texas panhandle that are connected to our Arapaho processing complex. We plan to complete the Arapaho III natural gas processing plant in the third quarter of 2011, which will increase our processing capacity at the Arapaho complex by 75 MMcf/d to a total of 235 MMcf/d. The gathering and processing expansions are supported by long-term agreements with producer customers.

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

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

Northeast

·Appalachia.  We are the largest processor and fractionator of natural gas in the Appalachian Basin, with fully integrated processing, fractionation, storage and marketing operations. The Appalachian Basin is a large natural gas producing region characterized by long-lived reserves and modest decline rates. Our Appalachian assets include the Kenova, Boldman, Cobb, Kermit and the recently acquired Langley natural gas processing plants, an NGL pipeline and the Siloam NGL fractionation plant. In connection with the

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Langley Acquisition, we will complete the construction of the Ranger Pipeline to connect the Langley Processing Facilities to our existing NGL pipeline that transports NGLs to our Siloam fractionation facility. We have an obligation to install an additional cryogenic natural gas processing plant with a capacity of at least 60 MMcf/d in 2012. In addition, we have two caverns for storing propane and additional propane storage capacity under a long-term firm-capacity agreement with a third party. The Appalachia operations include fractionation and marketing services on behalf of the Liberty segment.

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

Liberty

·Marcellus Shale.  We operate natural gas gathering systems and processing facilities located primarily in southwestern Pennsylvania and northern West Virginia through MarkWest Liberty Midstream. We are the largest processor of natural gas in the Marcellus Shale, with fully integrated processing, fractionation, storage and marketing operations that are critical to the liquids-rich gas development in the northeast United States. We currently have 355 MMcf/d of cryogenic processing capacity at our Houston, Pennsylvania processing complex, which includes a 200 MMcf/d cryogenic plant that began operations in the second quarter of 2011. We currently have 270 MMcf/d of cryogenic processing capacity at our Majorsville, West Virginia processing complex, which includes a 135 MMcf/d cryogenic plant that began operations in the second quarter of 2011.  We will also construct a 120 MMcf/d cryogenic processing plant in Mobley, West Virginia to be completed in the first half of 2012. The planned and existing capacity discussed above is supported by long-term agreements with our producer customers. We also plan to construct a 200 MMcf/d cryogenic processing plant in northern West Virginia that is also supported by a long-term agreement, the terms of which are subject to confidentiality obligations. This plant is expected to be completed in the second half of 2012. Each of the processing plants in the Liberty segment will utilize the Houston fractionation facilities through new and existing NGL pipelines. In addition, we will also construct an extension of our Majorsville NGL pipeline to receive NGLs produced at a third-party’s Fort Beeler processing plant. This will allow certain producers to benefit from our integrated NGL fractionation and marketing system.

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

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

We are jointly developing two projects with Sunoco Logistics, L.P. (“Sunoco”) to provide Marcellus producers with access to multiple ethane markets to serve the growing liquids-rich gas production in the Marcellus. For both projects, Project Mariner and Mariner West, MarkWest Liberty Midstream would be expected to make minor modifications to its natural gas processing complexes, install ethane extraction facilities at its Houston complex, and construct pipelines from the Houston complex to interconnections with existing Sunoco pipelines. Project Mariner is a pipeline and marine project intended to deliver purity ethane produced in the Marcellus to Gulf Coast and international markets. Project Mariner is anticipated to have initial capacity to transport up to 50,000 Bbl/d of ethane by mid-2013. Mariner West, which was announced during the first quarter of 2011, is a joint pipeline project intended to deliver Marcellus ethane to Sarnia, Ontario, Canada markets. Mariner West, which is being developed at the request of Marcellus producer customers and is supported by Sarnia ethane consumers, would utilize new and existing pipelines and is anticipated to have an initial capacity to transport up to 50,000 Bbl/d of ethane by mid-2013. Priority service will be available to shippers making long-term commitments during the period commencing July 21, 2011 through August 22, 2011.

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Gulf Coast

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

The following summarizes the percentage of our segment revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by segment, for the six months ended June 30, 2011:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	61	%	20	%	13	%	6	%	100	%
Net operating margin	50	%	22	%	17	%	11	%	100	%

Segment Operating Results

Items below Income from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual business segments. Management does not consider these items allocable to or controllable by any individual business segment and therefore excludes these items when evaluating segment performance. The segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests. The tables below present financial information, as evaluated by management, for the reported segments for the three months ended June 30, 2011 and 2010 and for the six months ended June 30, 2011 and 2010. The information includes net operating margin, a non-GAAP financial measure. See above for a reconciliation of net operating margin to Income from operations, the most comparable GAAP financial measure.

Three months ended June 30, 2011 compared to three months ended June 30, 2010

Southwest

	Three months ended June 30,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	235,575	$	155,043	$	80,532		52	%
Purchased product costs	128,988		71,389		57,599			81	%
Net operating margin	106,587		83,654		22,933			27	%
Facility expenses	20,855		19,395		1,460			8	%
Portion of operating income attributable to non-controlling interests	1,346		1,556		(210		)	(14	)%
Operating income before items not allocated to segments	$	84,386	$	62,703	$	21,683		35	%

Segment Revenue.  Revenue increased primarily due to higher commodity prices, higher condensate revenue and an increase in NGL and natural gas volumes in Oklahoma.

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

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Northeast

	Three months ended June 30,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	53,676	$	81,322	$	(27,646	)	(34	)%
Purchased product costs	15,702		56,734		(41,032		)	(72	)%
Net operating margin	37,974		24,588		13,386			54	%
Facility expenses	6,929		5,062		1,867			37	%
Operating income before items not allocated to segments	$	31,045	$	19,526	$	11,519		59	%

Segment Revenue.  Revenue decreased primarily due to a contract change related to the Langley Acquisition. Subsequent to the Langley Acquisition, we continue to market the NGLs, however we are acting as an agent and therefore record revenue net of purchase product costs. Prior to the contract change we were acting as the principal. Revenue also decreased due to a decrease in volumes processed under keep-whole terms primarily due to the required repairs of a significant transmission pipeline feeding our Kenova plant. The transmission pipeline is scheduled to be repaired in the last half of 2011 after which we expect volumes to return to normal levels.

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

Facility Expenses.  Facility expenses increased primarily due to the Langley Acquisition completed on February 1, 2011.

Liberty

	Three months ended June 30,
	2011		2010		$ Change		% Change
	(in thousands)
Segment revenue	$	48,337	$	18,738	$	29,599	158	%
Purchased product costs	9,890		—		9,890		N/A
Net operating margin	38,447		18,738		19,709		105	%
Facility expenses	7,269		6,140		1,129		18	%
Portion of operating income attributable to non-controlling interests	15,182		5,208		9,974		192	%
Operating income before items not allocated to segments	$	15,996	$	7,390	$	8,606	116	%

Segment Revenue.  Revenue increased due to ongoing expansion of the Liberty operations and higher NGL prices. Revenue increased approximately $12.5 million related to gathering and processing fees and approximately $15.9 million related to NGL product sales.

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

Facility Expenses.  Facility expenses increased due to the ongoing expansion of the Liberty operations partially offset by a reduction in compressor rental expense as compressors were purchased in the first quarter of 2010 and by environmental and remediation costs incurred in 2010 that did not recur in 2011.

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

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Gulf Coast

	Three months ended June 30,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	24,683	$	21,845	$	2,838		13	%
Purchased product costs	—		—		—			N/A
Net operating margin	24,683		21,845		2,838			13	%
Facility expenses	8,312		9,395		(1,083		)	(12	)%
Operating income before items not allocated to segments	$	16,371	$	12,450	$	3,921		31	%

Segment Revenue.  Revenue increased primarily due to higher pricing on NGL products offset by lower overall volumes.

Facility Expenses.  Facility expenses decreased primarily due to lower water disposal costs as well as a reduction in property taxes and other miscellaneous operating expenses.

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

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income before provision for income tax for the three months ended June 30, 2011 and 2010. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Three months ended June 30,
	2011			2010			$ Change			% Change
	(in thousands)
Total segment revenue	$	362,271		$	276,948		$	85,323		31	%
Derivative gain not allocated to segments	40,590			46,902			(6,312		)	(13	)%
Revenue deferral adjustment	(2,422		)	—			(2,422		)	N/A
Total revenue	400,439			$	323,850		76,589			24	%
Operating income before items not allocated to segments	$	147,798		$	102,069		$	45,729		45	%
Portion of operating income attributable to non-controlling interests	16,528			6,764			9,764			144	%
Derivative gain not allocated to segments	37,917			54,360			(16,443		)	(30	)%
Revenue deferral adjustment	(2,422		)	—			(2,422		)	N/A
Compensation expense included in facility expenses not allocated to segments	(188		)	(286		)	98			(34	)%
Facility expenses adjustments	2,855			2,851			4			0	%
Selling, general and administrative expenses	(18,580		)	(16,419		)	(2,161		)	13	%
Depreciation	(37,201		)	(29,818		)	(7,383		)	25	%
Amortization of intangible assets	(10,830		)	(10,193		)	(637		)	6	%
Loss on disposal of property, plant and equipment	(2,373		)	(188		)	(2,185		)	1,162	%
Accretion of asset retirement obligations	(290		)	(69		)	(221		)	320	%
Income from operations	133,214			109,071			24,143			22	%
(Loss) gain from unconsolidated affiliate	(216		)	1,585			(1,801		)	(114	)%
Interest income	63			377			(314		)	(83	)%
Interest expense	(27,874		)	(25,755		)	(2,119		)	8	%
Amortization of deferred financing costs and discount (a component of interest expense)	(1,443		)	(2,280		)	837			(37	)%
Miscellaneous income (expense), net	169			(9		)	178			(1,978	)%
Income before provision for income tax	$	103,913		$	82,989		$	20,924		25	%

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Derivative Loss Not Allocated to Segments.  Unrealized gain from the mark-to-market of our derivative instruments was $55.7 million for the three months ended June 30, 2011 compared to an unrealized gain of $65.8 million for the same period in 2010. Realized loss from the settlement of our derivative instruments was $17.7 million for the three months ended June 30, 2011 compared to $11.4 million for the same period in 2010. The total change of $16.4 million is due mainly to volatility in commodity prices.

Revenue Deferral Adjustment.  Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended June 30, 2011, approximately $0.2 million and $2.2 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Based on current commodity prices, management expects the deferred revenue in subsequent periods to approximate the current quarter’s amount until the beginning of 2015 when the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

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

Selling, General and Administrative.  Selling, general and administrative expenses increased primarily due to higher labor and benefits expenses.

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

Interest Expense.  Interest expense increased primarily due to increased borrowings under our Credit Facility and a net increase in our borrowings resulting from our Senior Notes offerings and related redemptions in order to fund our capital plan.

Amortization of Deferred Financing Costs and Discount.  Amortization of deferred financing costs and discount decreased primarily due to the write off of the unamortized discount associated with our 6.875% senior unsecured notes due 2014 (the “2014 Senior Notes”), which were redeemed in the fourth quarter of 2010.

Six months ended June 30, 2011 compared to six months ended June 30, 2010

Southwest

	Six months ended June 30,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	437,349	$	320,007	$	117,342		37	%
Purchased product costs	232,184		146,014		86,170			59	%
Net operating margin	205,165		173,993		31,172			18	%
Facility expenses	41,012		39,884		1,128			3	%
Portion of operating income attributable to non-controlling interests	2,518		3,056		(538		)	(18	)%
Operating income before items not allocated to segments	$	161,635	$	131,053	$	30,582		23	%

Segment Revenue.  Revenue increased primarily due to higher commodity prices, higher condensate revenue and an increase in NGL and natural gas volumes in Oklahoma.

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

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Northeast

	Six months ended June 30,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	145,767	$	193,170	$	(47,403	)	(25	)%
Purchased product costs	56,580		123,821		(67,241		)	(54	)%
Net operating margin	89,187		69,349		19,838			29	%
Facility expenses	12,523		9,287		3,236			35	%
Operating income before items not allocated to segments	$	76,664	$	60,062	$	16,602		28	%

Segment Revenue.  Revenue decreased primarily due to a contract change related to the Langley Acquisition. Subsequent to the Langley Acquisition, we continue to market the NGLs, however we are acting as an agent and therefore record revenue net of purchase product costs. Prior to the contract change we were acting as the principal. Revenue also decreased due to a decrease in volumes processed under keep-whole terms primarily due to the required repairs of a significant transmission pipeline feeding our Kenova plant. The transmission pipeline is scheduled to be repaired in the second half of 2011 after which we expect volumes to return to normal levels.

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

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

Liberty

	Six months ended June 30,
	2011		2010		$ Change		% Change
	(in thousands)
Segment revenue	$	89,556	$	37,748	$	51,808	137	%
Purchased product costs	19,445		2,584		16,861		653	%
Net operating margin	70,111		35,164		34,947		99	%
Facility expenses	13,767		13,453		314		2	%
Portion of operating income attributable to non-controlling interests	27,559		8,845		18,714		212	%
Operating income before items not allocated to segments	$	28,785	$	12,866	$	15,919	124	%

Segment Revenue.  Revenue increased due to ongoing expansion of the Liberty operations and higher NGL prices. Revenue increased approximately $22.8 million related to gathering and processing fees and approximately $26.5 million related to NGL product sales.

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

Facility Expenses.  Facility expenses increased due to costs related to the expansion of Liberty operations which were offset by a decrease in repair and maintenance expenses.

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

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Gulf Coast

	Six months ended June 30,
	2011		2010		$ Change		% Change
	(in thousands)
Segment revenue	$	46,442	$	41,638	$	4,804	12	%
Purchased product costs	—		—		—		N/A
Net operating margin	46,442		41,638		4,804		12	%
Facility expenses	17,302		15,090		2,212		15	%
Operating income before items not allocated to segments	$	29,140	$	26,548	$	2,592	10	%

Segment Revenue.  Revenue increased primarily due to revenues earned from  the SMR beginning March 2010 and price increases, which were partially offset by a decrease in volumes.

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

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

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income before provision for income tax for the six months ended June 30, 2011 and 2010. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

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	Six months ended June 30,
	2011			2010			$ Change			% Change
	(in thousands)
Total segment revenue	$	719,114		$	592,563		$	126,551		21	%
Derivative (loss) gain not allocated to segments	(45,089		)	39,666			(84,755		)	(214	)%
Revenue deferral adjustment	(10,365		)	—			(10,365		)	N/A
Total revenue	663,660			$	632,229		31,431			5	%
Operating income before items not allocated to segments	$	296,224		$	230,529		$	65,695		28	%
Portion of operating income attributable to non-controlling interests	30,077			11,901			18,176			153	%
Derivative (loss) gain not allocated to segments	(64,145		)	34,541			(98,686		)	(286	)%
Revenue deferral adjustment	(10,365		)	—			(10,365		)	N/A
Compensation expense included in facility expenses not allocated to segments	(1,228		)	(1,008		)	(220		)	22	%
Facility expenses adjustments	5,710			3,390			2,320			68	%
Selling, general and administrative expenses	(40,292		)	(37,927		)	(2,365		)	6	%
Depreciation	(71,565		)	(58,005		)	(13,560		)	23	%
Amortization of intangible assets	(21,647		)	(20,386		)	(1,261		)	6	%
Loss on disposal of property, plant and equipment	(4,472		)	(179		)	(4,293		)	2,398	%
Accretion of asset retirement obligations	(377		)	(212		)	(165		)	78	%
Income from operations	117,920			162,644			(44,724		)	(27	)%
(Loss) earnings from unconsolidated affiliate	(755		)	1,517			(2,272		)	(150	)%
Interest income	152			763			(611		)	(80	)%
Interest expense	(56,137		)	(49,537		)	(6,600		)	13	%
Amortization of deferred financing costs and discount (a component of interest expense)	(2,871		)	(4,892		)	2,021			(41	)%
Derivative gain related to interest expense	—			1,871			(1,871		)	(100	)%
Loss on redemption of debt	(43,328		)	—			(43,328		)	N/A
Miscellaneous income, net	131			1,053			(922		)	(88	)%
Income before provision for income tax	$	15,112		$	113,419		$	(98,307	)	(87	)%

Derivative Loss Not Allocated to Segments.  Unrealized loss from the mark-to-market of our derivative instruments was $24.2 million for the six months ended June 30, 2011 compared to an unrealized gain of $64.5 million for the same period in 2010. Realized loss from the settlement of our derivative instruments was $40.0 million for the six months ended June 30, 2011 compared to $30.0 million for the same period in 2010. The total change of $98.7 million is due mainly to volatility in commodity prices.

Revenue Deferral Adjustment.  Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the six months ended June 30, 2011, approximately $6.7 million and $3.6 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

Facility Expenses Adjustments.  Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR, which is included in facility expenses for the purposes of evaluating the performance of the Gulf Coast segment.  The increase is due to a full six months of interest expenses related to the SMR in 2011 compared to approximately three months of SMR interest expense in 2010.

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Selling, General and Administrative.   Selling, general and administrative expenses increased primarily due to higher labor and benefits expenses.

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

Loss on Disposal of Property, Plant and Equipment. The loss relates to non-recurring disposals of miscellaneous equipment, primarily in the Northeast segment.

Interest Expense.  Interest expense increased primarily due to increased borrowings under our Credit Facility and a net increase in our borrowings resulting from our Senior Notes offerings and related redemptions in order to fund our capital plan. Interest expense also increased approximately $1.9 million related to payments of the SMR liability which began in March 2010.

Amortization of Deferred Financing Costs and Discount.  Amortization of deferred financing costs and discount decreased primarily due to the write off of the unamortized discount associated with our 2014 Senior Notes, which were redeemed in the fourth quarter of 2010 partially offset by the amortization of deferred financing costs related to notes issued in the fourth quarter of 2010 and the first quarter of 2011.

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

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Operating Data

	Three months ended June 30,				Six months ended June 30,
	2011	2010	% Change		2011	2010	% Change
Southwest
East Texas
Gathering systems throughput (Mcf/d)	428,300	438,700	(2	)%	427,000	433,900	(2	)%
NGL product sales (gallons)	59,488,700	61,887,500	(4	)%	116,170,000	126,083,300	(8	)%
Oklahoma
Foss Lake gathering system throughput (Mcf/d)	72,000	70,600	2	%	69,900	72,400	(3	)%
Stiles Ranch gathering system throughput (Mcf/d)	144,400	106,100	36	%	138,500	111,800	24	%
Grimes gathering system throughput (Mcf/d)	7,500	8,000	(6	)%	7,300	8,000	(9	)%
Arapaho NGL product sales (gallons)	35,088,100	30,093,800	17	%	74,108,200	59,537,100	24	%
Southeast Oklahoma gathering system throughput (Mcf/d)	511,700	539,400	(5	)%	504,900	518,100	(3	)%
Southeast Oklahoma NGL product sales (gallons)	32,142,900	23,483,000	37	%	61,505,500	42,367,800	45	%
Arkoma Connector Pipeline throughput (Mcf/d)	298,400	387,500	(23	)%	292,100	372,700	(22	)%
Other Southwest
Appleby gathering system throughput (Mcf/d)	24,800	31,600	(22	)%	25,600	33,100	(23	)%
Other gathering systems throughput (Mcf/d) (1)	6,800	8,700	(22	)%	6,700	8,800	(24	)%
Northeast
Appalachia(2)
Natural gas processed (Mcf/d)	319,600	199,900	60	%	312,500	196,400	59	%
Keep-whole sales (gallons)	21,078,000	30,815,000	(32	)%	60,913,900	76,587,400	(20	)%
Percent-of-proceeds sales (gallons)	33,092,100	30,118,700	10	%	63,987,500	57,123,600	12	%
Total NGL product sales (gallons) (3)	54,170,100	60,933,700	(11	)%	124,901,400	133,711,000	(7	)%
Michigan
Crude oil transported for a fee (Bbl/d)	11,500	12,100	(5	)%	10,800	12,500	(14	)%
Liberty
Marcellus Shale
Natural gas processed (Mcf/d)	298,200	116,000	157	%	276,500	105,000	163	%
Gathering system throughput (Mcf/d)	232,000	128,500	81	%	214,000	114,800	86	%
NGL product sales (gallons)	50,668,000	23,462,500	116	%	102,429,600	44,992,700	128	%
Gulf Coast
Refinery off-gas processed (Mcf/d)	114,600	118,800	(4	)%	108,700	116,100	(6	)%
Liquids fractionated (Bbl/d)	21,900	22,800	(4	)%	20,600	22,700	(9	)%

(1)Excludes lateral pipelines where revenue is not based on throughput.

(2)Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported are the average daily rates for the days of operation.

(3)Represents sales at the Siloam fractionator. The total sales exclude 20,897,000 gallons and 12,648,600 gallons sold by the Northeast on behalf of Liberty for the three months ended June 30, 2011 and 2010, respectively, and 41,542,000 gallons and 23,305,800 gallons sold for the six months ended June 30, 2011 and 2010, respectively.

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Liquidity and Capital Resources

Our primary strategy is to expand our asset base through organic growth projects and selective third-party acquisitions that are accretive to our cash available for distribution per common unit. In 2010, we spent approximately $458.7 million primarily on organic expansion opportunities, of which approximately $184 million was funded by our MarkWest Liberty Midstream joint venture partner.

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

	Full Year Plan						Actual
	Low			High			YTD 6/30/2011
Consolidated growth capital	$	615		$	660		$	228
Liberty joint venture partner’s estimated share of growth capital	(170		)	(190		)	(54		)
Partnership share of growth capital	445			470			174
Langley Acquisition	230			230			231
Partnership share of growth capital and acquisitions	$	675		$	700		$	405
Consolidated maintenance capital	$	15		$	15		$	6

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

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

Management believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partner for capital projects encompassed by the Liberty joint venture, and our current borrowing capacity under the Credit Facility. However, it may be necessary to raise additional funds to finance our future capital requirements. Our access to capital markets can be impacted by factors outside our control, including economic conditions; however, we believe that our strong cash flows and balance sheet, our Credit Facility and our credit rating will provide us with adequate access to funding given our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings assigned by independent rating agencies. As of July 28, 2011, our credit ratings were Ba3 with a Stable outlook by Moody’s Investors Service, BB with a Stable outlook by Standard & Poor’s, which reflects an upgrade in the second quarter of 2011, and BB with a Stable outlook by Fitch Ratings. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

Debt Financing Activities

On June 15, 2011, we executed a joinder agreement to include an additional member in the bank group and to exercise a portion of the accordion feature under the Credit Facility, thereby increasing the borrowing capacity of the Credit Facility to $745 million and reducing the accordion feature to $155 million of uncommitted funds.  The Credit Facility matures on July 1, 2015. Under the provisions of the Credit Facility we are subject to a number of restrictions and covenants. As of June 30, 2011, we were in compliance with all of our debt covenants and we expect to remain in compliance for at least the next twelve months. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of July 28, 2011, we had $10.3 million of borrowings outstanding and $27.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $707.4 million available for borrowing.

On February 24, 2011, we completed a public offering of $300 million in aggregate principal amount of 6.5% senior unsecured notes due 2021. Net proceeds of approximately $296 million were used to fund the concurrent repurchase of approximately $272.2 million in aggregate principal amount of our 2016 Senior Notes. The remaining 2016 Senior Notes were repurchased on July 15, 2011. On March 10, 2011, we completed a follow-on public offering of an additional $200 million in aggregate principal amount of 6.5% senior unsecured notes due 2021. Net proceeds of approximately $196 million were used to fund the concurrent repurchase of approximately $165.6 million in aggregate principal amount of

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our 2018 Senior Notes. The remaining proceeds for each of the 2021 Senior Notes offerings were used to repay borrowings under our Credit Facility. The 2021 Senior Notes, issued on February 24, 2011 and March 10, 2011, are treated as a single class of debt securities under the same indenture. As a result of these refinancing activities, we have significantly reduced the interest rates and extended the terms of our long-term financing.

As of July 28, 2011, we had three series of Senior Notes outstanding: $500.0 million aggregate principal issued in February and March 2011 and due August 2021; $500.0 million aggregate principal issued in November 2010 and due November 2020; $334.4 million aggregate principal issued in April and May 2008 and due April 2018. For further discussion of the Senior Notes see Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements.

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

The Credit Facility also limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Credit Facility prevents members of the participating bank group from requiring margin calls. As of July 28, 2011, all of our derivative positions  are with members of the participating bank group and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to enter into derivative instruments without utilizing cash for margin calls or requiring the use of letters of credit.

Equity Offerings

On January 14, 2011, we completed a public offering of approximately 3.45 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option. Net proceeds of approximately $138.2 million were used to partially fund our ongoing capital expenditure program, including a portion of the costs associated with the Langley Acquisition.

On July 13, 2011, we completed a public offering of approximately 4.0 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriter’s over-allotment option.  Net proceeds after deducting underwriters’ fees and other third-party expenses were approximately $185.1 million and will be used to repay borrowings under our revolving credit facility and to partially fund our ongoing capital expenditure program.

Cash Flow

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

	Six months ended June 30,
	2011			2010			Change
Net cash provided by operating activities	$	206,364		$	130,636		$	75,728
Net cash used in investing activities	(462,049		)	(252,843		)	209,206
Net cash provided by financing activities	283,270			159,326			123,944

Net cash provided by operating activities increased primarily due to a $65.7 million increase in operating income, excluding derivative gains and losses, in our operating segments, which was partially offset by a $6.3 million increase in net cash payments related to the settlement of commodity derivative positions. The increase in operating income was also due to increases in operating cash flow resulting from changes in working capital.

Net cash used in investing activities increased primarily due to the $230.7 million Langley Acquisition.

Net cash provided by financing activities increased primarily due to:

·$315.5 million increase in net borrowings, and

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These increases were partially offset by:

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

·$96.2 million decrease in cash contributions received from our joint venture partner,

·$43.0 million increase in distributions to common unitholders and non-controlling interest holders, and

·$6.7 million increase in payments for debt issuance costs, deferred financing costs and registration costs.

Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of June 30, 2011, our purchase obligations for the remainder of 2011 were $114.7 million compared to our 2011 obligations of $56.0 million as of December 31, 2010. The increase is due primarily to obligations related to the ongoing expansion in our Liberty and Northeast segments. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

Critical Accounting Policies

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

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

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There have not been any material changes during the six months ended June 30, 2011 to the methodology applied by management for critical accounting policies previously disclosed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2010, except as noted below.

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

Recent Accounting Pronouncements

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

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

The information about commodity price risk for the six months ended June 30, 2011 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2010.

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Outstanding Derivative Contracts

The following tables provide information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at June 30, 2011, including the weighted average prices (“WAVG”):

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2011	1,630	$	67.43	$	85.35	$	(3,901	)
2012	2,634	75.65		97.22		(8,908		)
2013	3,714	88.08		107.45		(3,319		)
2014	734	95.36		114.81		708

WTI Crude Puts	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		Fair Value (in thousands)
2011	1,816	$	80.00	$	355

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2011 (1)	—	N/A		$	(10,092	)
2012	3,626	$	84.63	(26,304		)
2013	1,510	83.86		(8,696		)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2011	1,149	$	5.49	$	(255	)
2012	4,650	5.62		(1,703		)
2013	980	5.13		(89		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	92,804	$	1.45	$	(701	)
2012 (Jan-Mar)	126,112	1.41		(519		)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	17,528	$	1.85	$	(113	)
2012 (Jan-Mar)	23,285	1.84		2

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	26,600	$	1.80	$	386
2012 (Jan-Mar)	36,572	1.78		116

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	78,564	$	2.28	$	(1,197	)
2012 (Jan-Mar)	88,765	2.28		(552		)

(1)During the second quarter of 2011 we effectively converted our swap hedges related to our remaining 2011 NGL exposure from crude proxy hedges to direct refined product hedges. We purchased crude swaps for 703,000 barrels to offset the existing crude swap positions and concurrently sold refined products swaps to maintain a hedge on our 2011 NGL sales.

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The following tables provide information on the volume of our taxable subsidiary’s commodity derivative activity for positions related to keep-whole price risk at June 30, 2011, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	1,122	$	78.49	$	101.71	$	(2,814	)

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2011 (1)	—	N/A		$	(4,812	)
2012	1,083	$	87.11	(8,584		)
2013	1,304	94.32		(2,935		)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2011	16,102	$	7.69	$	(11,387	)
2012	14,419	6.02		(5,704		)
2013	9,793	5.34		(601		)
2014	4,249	5.69		(382		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	107,261	$	1.48	$	(722	)
2012 (Jan-Mar)	152,569	1.46		(516		)
2013 (Jan-Mar, Oct-Dec)	36,885	1.29		96
2014 (Jan-Mar, Oct-Dec)	87,837	1.25		(128		)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	12,207	$	1.74	$	(347	)
2012 (Jan-Mar)	8,282	1.82		(38		)
2013	3,081	1.70		30
2014	3,885	1.67		18

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	32,841	$	1.72	$	(105	)
2012 (Jan-Mar)	22,944	1.75		(40		)
2013	8,512	1.61		64
2014	10,711	1.61		98

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Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	22,369	$	2.32	$	(229	)
2012 (Jan-Mar)	14,969	2.28		(116		)
2013	5,600	2.26		(36		)
2014	7,106	2.32		137

(1)During the second quarter of 2011 we effectively converted our swap hedges related to our remaining 2011 and first quarter of 2012 NGL exposure from crude proxy hedges to direct refined product hedges. We purchased crude swaps for 517,000 barrels to offset the existing crude swap positions in 2011 and 277,000 barrels to offset a portion of the existing crude swap positions in the first quarter of 2012.  Concurrently, we sold refined products swaps to maintain a hedge on our 2011 and first quarter 2012 NGL sales.

The following table provides information on the derivative positions related to long liquids and keep-whole price risk that we have entered into subsequent to June 30, 2011, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)
2013	964	$	101.36
2014	601	101.50

Embedded Derivatives in Commodity Contracts

We have a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative loss related to purchased product costs. In February 2011, we executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of June 30, 2011, the estimated fair value of this contract was a liability of $104.1 million and the recorded value was $50.6 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of June 30, 2011 (in thousands).

Fair value of commodity contract	$	104,074
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of June 30, 2011	$	50,567

We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at one of our plant locations through the fourth quarter of 2014. The value of the derivative component of this contract is marked to market through Derivative gain related to facility expenses. As of June 30, 2011, the estimated fair value of this contract was an asset of $1.1 million.

Interest Rate Risk

The information about interest rate risk for the six months ended June 30, 2011 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2010.

Credit Risk

The information about credit risk for the six months ended June 30, 2011 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2010.

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Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the 1934 Act, as of June 30, 2011. Based on this evaluation, the Partnership’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of June 30, 2011, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

Limitations on Controls

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.  Legal Proceedings

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

Item 1A. Risk Factors

There were no material changes to our risk factors as disclosed in Item1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2010, except as set forth below.

New federal pipeline safety regulations relating to liquid pipelines could increase our cost of operations.

The Pipeline and Hazardous Materials Safety Administration recently issued a final rule to extend safety regulations to certain rural low-stress hazardous liquid pipelines that were not previously regulated in such manner.  These regulations impose additional reporting obligations as well as integrity management requirements.  While we do not believe that compliance with these new regulations will have a material adverse effect on our operations, we are in the process of evaluating the application and impact of the new regulations on our facilities.  It is possible that compliance with these new requirements may increase our operating costs and reduce our cash flows available for distribution to our common unitholders.

Item 6.  Exhibits

10.1*+ Amendment No. 2 to Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C. dated as of April 28, 2011, among MarkWest Liberty Midstream & Resources, L.L.C., MarkWest Liberty Gas Gathering, L.L.C. and M&R MWE Liberty, LLC.

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10.2(1)	Joinder Agreement dated as of June 15, 2011 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, individually and as Administrative Agent, Issuing Bank and Swingline Lender, and Citibank, N.A.
31.1*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	The following financial information from the quarterly report on Form 10-Q of MarkWest Energy Partners, L.P. for the quarter ended June 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Statements of Changes in Equity, and (v) Notes to the Condensed Consolidated Financial Statements.

(1)Incorporated by reference to the Current Report on Form 8-K filed June 17, 2011.

*Filed herewith

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

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SIGNATURES

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

		MarkWest Energy Partners, L.P. (Registrant)
	By:	MarkWest Energy GP, L.L.C.,
		Its General Partner
Date: August 8, 2011	/s/ FRANK M. SEMPLE
	Frank M. Semple
	Chairman, President & Chief Executive Officer
	(Principal Executive Officer)
Date: August 8, 2011	/s/ NANCY K. BUESE
	Nancy K. Buese
	Senior Vice President & Chief Financial Officer
	(Principal Financial Officer)
Date: August 8, 2011	/s/ PAULA L. ROSSON
	Paula L. Rosson
	Vice President & Chief Accounting Officer
	(Principal Accounting Officer)

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