PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	June 30, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents ($3,168 and $2,684, respectively)	$	125,462		$	117,016
Restricted cash	25,285			26,193
Receivables, net ($1,428 and $1,569, respectively)	138,371			226,561
Inventories	22,209			41,006
Fair value of derivative instruments	28,556			8,698
Deferred income taxes	6,544			14,885
Other current assets ($69 and $169, respectively)	8,915			11,748
Total current assets	355,342			446,107

Property, plant and equipment ($187,048 and $156,808, respectively)	4,164,402			3,302,369
Less: accumulated depreciation ($18,704 and $15,551, respectively)	(520,766		)	(438,062		)
Total property, plant and equipment, net	3,643,636			2,864,307

Other long-term assets:
Investment in unconsolidated affiliate	26,695			27,853
Intangibles, net of accumulated amortization of $191,388 and $168,168, respectively	885,183			603,767
Goodwill	144,582			67,918
Deferred financing costs, net of accumulated amortization of $15,726 and $13,194, respectively	41,581			41,798
Deferred contract cost, net of accumulated amortization of $2,418 and $2,262, respectively	832			988
Fair value of derivative instruments	35,237			16,092
Other long-term assets ($102 and $102, respectively)	1,510			1,595
Total assets	$	5,134,598		$	4,070,425

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($292 and $96, respectively)	$	208,019		$	179,871
Accrued liabilities ($14,306 and $1,144, respectively)	231,719			171,451
Fair value of derivative instruments	30,479			90,551
Total current liabilities	470,217			441,873

Deferred income taxes	156,783			93,664
Fair value of derivative instruments	18,951			65,403
Long-term debt, net of discounts of $992 and $1,050, respectively	1,997,985			1,846,062
Other long-term liabilities ($76 and $73, respectively)	128,231			121,356

Commitments and contingencies (Note 11)

Equity:
Common units (110,694 and 94,940 common units issued and outstanding, respectively)	1,540,189			679,309
Class B units (19,954 units issued and outstanding)	752,531			752,531
Non-controlling interest in consolidated subsidiaries	69,711			70,227

Total equity	2,362,431			1,502,067
Total liabilities and equity	$	5,134,598		$	4,070,425

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,
	2012			2011			2012			2011
Revenue:
Revenue	$	309,986		$	359,849		$	709,167		$	708,749
Derivative gain (loss)	136,067			40,590			87,352			(45,089		)
Total revenue	446,053			400,439			796,519			663,660

Operating expenses:
Purchased product costs	112,731			154,580			267,286			308,209
Derivative (gain) loss related to purchased product costs	(51,579		)	(254		)	(32,779		)	19,140
Facility expenses	48,538			40,698			97,378			80,122
Derivative (gain) loss related to facility expenses	(1,146		)	2,927			(2,892		)	(84		)
Selling, general and administrative expenses	21,879			18,580			47,103			40,292
Depreciation	42,918			37,201			84,063			71,565
Amortization of intangible assets	12,307			10,830			23,292			21,647
Loss on disposal of property, plant and equipment	1,342			2,373			2,328			4,472
Accretion of asset retirement obligations	161			290			399			377
Total operating expenses	187,151			267,225			486,178			545,740

Income from operations	258,902			133,214			310,341			117,920

Other income (expense):
Earnings (loss) from unconsolidated affiliate	551			(216		)	542			(755		)
Interest income	159			63			231			152
Interest expense	(26,762		)	(27,874		)	(56,234		)	(56,137		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,245		)	(1,443		)	(2,515		)	(2,871		)
Loss on redemption of debt	—			—			—			(43,328		)
Miscellaneous income, net	4			169			62			131
Income before provision for income tax	231,609			103,913			252,427			15,112

Provision for income tax expense (benefit):
Current	4,809			4,089			20,150			4,145
Deferred	39,664			10,619			28,868			(3,567		)
Total provision for income tax	44,473			14,708			49,018			578

Net income	187,136			89,205			203,409			14,534

Net income attributable to non-controlling interest	(228		)	(10,708		)	(481		)	(20,066		)
Net income (loss) attributable to the Partnership	$	186,908		$	78,497		$	202,928		$	(5,532	)

Net income (loss) attributable to the Partnership’s common unitholders per common unit (Note 13):
Basic	$	1.74		$	1.03		$	1.98		$	(0.09	)
Diluted	$	1.47		$	1.03		$	1.66		$	(0.09	)

Weighted average number of outstanding common units:
Basic	106,825			75,160			101,833			74,847
Diluted	127,468			75,266			122,531			74,847

Cash distribution declared per common unit	$	0.79		$	0.67		$	1.55		$	1.32

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 Changes in Equity

(unaudited, in thousands)

	Common Units				Class B Units			Non- controlling
	Units	Amounts			Units	Amounts		Interest			Total
December 31, 2011	94,940	$	679,309		19,954	$	752,531	$	70,227		$	1,502,067
Issuance of units in public offering, net of offering costs	15,508	852,873			—	—		—			852,873
Distributions paid	—	(155,073		)	—	—		(2,937		)	(158,010		)
Contributions from non-controlling interest	—	—			—	—		1,940			1,940
Share-based compensation activity	246	537			—	—		—			537
Excess tax benefits related to share-based compensation	—	2,207			—	—		—			2,207
Deferred income tax impact from changes in equity	—	(42,592		)	—	—		—			(42,592		)
Net income	—	202,928			—	—		481			203,409
June 30, 2012	110,694	$	1,540,189		19,954	$	752,531	$	69,711		$	2,362,431

	Common Units				Non-controlling
	Units	Amounts			Interest			Total
December 31, 2010	71,440	$	993,049		$	465,517		$	1,458,566
Issuance of units in public offering, net of offering costs	3,450	138,163			—			138,163
Distributions paid	—	(100,058		)	(34,531		)	(134,589		)
Contributions to MarkWest Liberty Midstream joint venture	—	—			24,400			24,400
Share-based compensation activity	270	2,778			—			2,778
Excess tax benefits related to share-based compensation	—	1,096			—			1,096
Net (loss) income	—	(5,532		)	20,066			14,534
June 30, 2011	75,160	$	1,029,496		$	475,452		$	1,504,948

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 Cash Flows

(unaudited, in thousands)

	Six months ended June 30,
	2012			2011
Cash flows from operating activities:
Net income	$	203,409		$	14,534
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	84,063			71,565
Amortization of intangible assets	23,292			21,647
Loss on redemption of debt	—			43,328
Amortization of deferred financing costs and discount	2,515			2,871
Accretion of asset retirement obligations	399			377
Amortization of deferred contract cost	156			156
Phantom unit compensation expense	8,585			8,093
Equity in (earnings) loss of unconsolidated affiliate	(542		)	755
Distributions from unconsolidated affiliate	1,700			300
Unrealized (gain) loss on derivative instruments	(145,527		)	26,265
Loss on disposal of property, plant and equipment	2,328			4,472
Deferred income taxes	28,868			(3,567		)
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	90,664			(9,215		)
Inventories	18,895			(6,326		)
Other current assets	2,738			526
Accounts payable and accrued liabilities	(71,784		)	20,473
Other long-term assets	85			(384		)
Other long-term liabilities	6,593			10,494
Net cash provided by operating activities	256,437			206,364

Cash flows used in investing activities:
Restricted cash	1,003			—
Capital expenditures	(582,203		)	(234,116		)
Acquisition of business, net of cash acquired	(506,797		)	(230,728		)
Proceeds from disposal of property, plant and equipment	499			2,795
Net cash flows used in investing activities	(1,087,498		)	(462,049		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	852,873			138,163
Proceeds from revolving credit facility	238,065			781,700
Payments of revolving credit facility	(86,200		)	(535,200		)
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	(2,315		)	(6,747		)
Contributions from non-controlling interest	1,940			24,400
Payments of SMR liability	(1,005		)	(916		)
Cash paid for taxes related to net settlement of share-based payment awards	(8,048		)	(6,269		)
Excess tax benefits related to share-based compensation	2,207			1,096
Payment of distributions to common unitholders	(155,073		)	(100,058		)
Payment of distributions to non-controlling interest	(2,937		)	(34,531		)
Net cash flows provided by financing activities	839,507			283,270

Net increase in cash and cash equivalents	8,446			27,585
Cash and cash equivalents at beginning of year	117,016			67,450
Cash and cash equivalents at end of period	$	125,462		$	95,035

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

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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, 2011. 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, 2012 are not necessarily indicative of results for the full year 2012 or any other future period.

The Partnership’s unaudited condensed consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Utica EMG, L.L.C. and its subsidiaries (“MarkWest Utica EMG”), 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 intercompany investments, accounts and transactions have been eliminated. The Partnership’s investment in Centrahoma Processing, LLC (“Centrahoma”), in which the Partnership exercises significant influence but does not control and is not the primary beneficiary, is accounted for using the equity method.

2. Recent Accounting Pronouncements

In May 2011, the FASB amended the accounting guidance for fair value measurement and disclosure. 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 included in Note 6, the adoption of the amended guidance did not have a material effect on the Partnership’s condensed consolidated financial statements.

In December 2011, the FASB amended the accounting guidance for balance sheet offsetting for financial assets and financial liabilities. The amended guidance is intended to help investors and other financial statement users to better assess the effect or potential effect of offsetting arrangements on a company’s financial position and provides for increased disclosures. The amended guidance is effective for the Partnership prospectively as of January 1, 2013. Except for additional disclosures related to our offsetting arrangements, the adoption of the amended guidance is not expected to have a material effect on the Partnership’s consolidated financial statements.

3. Business Combination

Keystone Acquisition

On May 29, 2012, the Partnership acquired natural gas gathering and processing assets from Keystone Midstream Services, LLC (“Keystone”) for a cash purchase price of approximately $509.6 million, subject to finalization of working capital adjustments. Keystone’s existing assets are located in Butler County, Pennsylvania and include two cryogenic gas processing plants totaling 90 MMcf/d of processing capacity, a gas gathering system and associated field compression. The acquisition is referred to as the Keystone Acquisition.

As a result of the Keystone Acquisition, the Partnership became a party to a long-term fee-based agreement to gather and process certain natural gas owned or controlled by R.E. Gas Development, L.L.C. (“Rex”), a subsidiary of Rex Energy Corporation, and Summit Discovery Resources II, L.L.C. (“Summit”), a subsidiary of Sumitomo Corporation, at the acquired facilities and in 2013 to exchange the resulting NGLs for fractionated products at facilities already owned and operated by the Partnership. Rex and Summit have dedicated an area of approximately 900 square miles to the Partnership as part of this long-term gathering and processing agreement. As a result of the Keystone Acquisition, the Partnership has expanded its position in the liquids rich Marcellus Shale area into northwest Pennsylvania.

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The Keystone Acquisition is accounted for as a business combination. The total purchase price is allocated to 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 Liberty segment. The following table summarizes the preliminary purchase price allocation for the Keystone Acquisition (in thousands):

Assets:
Cash	$	2,837
Accounts receivable	1,756
Property, plant and equipment	136,593
Goodwill	76,664
Intangible asset	304,708
Liabilities:
Accounts payable	(12,117		)
Other short-term liabilities	(175		)
Other long-term liabilities	(632		)
Total	$	509,634

As of June 30, 2012, the purchase price for the Keystone Acquisition is $509.6 million subject to further working capital adjustments. Due to the potential changes in the purchase price and the Partnership’s continuing process to finalize the fair value estimates of the acquired assets and liabilities, the purchase price allocation is subject to further adjustment, which could impact depreciation and amortization expense.

The goodwill recognized from the Keystone Acquisition results primarily from synergies created from integrating the Keystone assets with the Partnership’s existing Marcellus Shale operations and the Partnership’s strengthened competitive position as it plans to expand its business in the newly developing liquids-rich areas of the Marcellus Shale. All of the goodwill is deductible for tax purposes.

The intangible asset consists of an identifiable contractual customer relationship with Rex and Summit. The acquired intangible asset will be amortized on a straight-line basis over the estimated customer contract useful life of approximately 19 years.

The results of operations of Keystone are included in the condensed consolidated financial statements from the acquisition date. Revenue and net income related to the Keystone are immaterial for the quarter ended June 30, 2012.

Pro forma financial results that give effect to the Keystone Acquisition are not presented as they are not material to the Partnership’s historical results.

4. Variable Interest Entities

MarkWest Utica EMG

Effective January 1, 2012, the Partnership and EMG Utica, LLC (“EMG Utica”) executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in Eastern Ohio. Under the terms of the agreements, the Partnership will make an initial contribution to MarkWest Utica EMG in a nominal amount in exchange for a 60% membership interest in MarkWest Utica EMG, and EMG Utica will make an initial contribution in a nominal amount and has agreed to contribute to MarkWest Utica EMG $350 million in cash on an as needed basis (the “Initial EMG Contribution”) in exchange for a 40% membership interest in MarkWest Utica EMG. Following the funding of the Initial EMG Contribution, the Partnership has the one time right to elect that (i) EMG Utica fund, as needed, all capital required to develop projects within MarkWest Utica EMG until the earlier of December 31, 2016 or such time as EMG Utica’s total investment balance reaches $500 million (the “Minimum EMG Investment”) or (ii) the Partnership fund 60% of all capital required to develop projects within MarkWest Utica EMG until such time as EMG Utica’s total investment balance equals the Minimum EMG Investment and EMG Utica will be required to fund the remaining 40% of all such capital. Once EMG Utica has funded capital equal to the Minimum EMG Investment, or if EMG has not funded the Minimum EMG Investment by December 31, 2016, then commencing on January 1, 2017, the Partnership is required to fund, as needed, 100% of all capital required to develop projects within MarkWest Utica EMG until such time as the total investment balances of the Partnership and EMG Utica are in the ratio of 60% and 40%, respectively (such time being referred to as the “First Equalization Date”). If the First Equalization Date has not occurred by December 31, 2016, each member’s ownership interest will be adjusted to equal the proportionate share of capital that it has contributed, and allocations of profits and losses and distributions of available cash will be made in accordance with those adjusted

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	As of June 30, 2012
	MarkWest Pioneer		MarkWest Utica EMG		Total
ASSETS
Cash and cash equivalents	$	3,089	$	79	$	3,168
Receivables, net	1,428		—		1,428
Other current assets	69		—		69
Property, plant and equipment, net of accumulated depreciation of $18,696 and $8, respectively	139,246		29,098		168,344
Other long-term assets	102		—		102
Total assets	$	143,934	$	29,177	$	173,111

LIABILITIES
Accounts payable	$	42	$	250	$	292
Accrued liabilities	1,171		13,135		14,306
Other long-term liabilities	76		—		76
Total liabilities	$	1,289	$	13,385	$	14,674

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 15). VIE asset balances can only be used to settle obligations of each respective VIE. The liabilities of the VIEs do not represent additional claims against the Partnership’s general assets, and the creditors or beneficial interest holders of the VIE do not have recourse to the general credit of the Partnership. The Partnership’s 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 may temporarily fund MarkWest Utica EMG for certain projects due to the timing of the capital call process. The Partnership will receive distributions as reimbursement for any temporary funding. Other than temporary funding, 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, 2012 and 2011.

The results of operations of MarkWest Utica EMG and MarkWest Pioneer are included in the Partnership’s Liberty and Southwest segments, respectively (see Note 14). The result of operations and cash flows for MarkWest Pioneer are not material to the Partnership. During the six months ended June 30, 2012, construction began for MarkWest Utica EMG assets, but operating activities have not commenced. Therefore, the results of operations and cash flows related to MarkWest Utica EMG are not material to the Partnership.

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 natural gas drilling by the Partnership’s producer customers, 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 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 (the “Hedge Committee”), 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 and fixed price forward contracts. The risk management policy does not allow for trading derivative contracts.

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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 manages its NGL price risk using crude oil contracts 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, which may vary in certain periods due to various market conditions, has significantly weakened during the first half of 2012. 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 and prices are satisfactory.

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 will be terminated.

The Partnership enters into derivative contracts primarily with financial institutions that are participating members of the Credit Facility (“participating bank group members”). Currently, all of the Partnership’s financial derivative positions are with participating bank group members. Management conducts a standard credit review on counterparties to derivative contracts. There are no collateral requirements for derivative contracts among the Partnership and any participating bank group members. Specifically, the Partnership is not required to post collateral when it enters into derivative contracts with participating bank group members as the participating bank group members have a collateral position in substantially all the wholly-owned assets of the Partnership. The Partnership uses standard master netting arrangements that allow for offset of positive and negative exposures.

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 changes in fair value on derivatives.

As of June 30, 2012, the Partnership had the following outstanding commodity contracts that were entered into to manage cash flow risk associated with future sales of NGLs or future purchases of natural gas.

Derivative contracts not designated as hedging instruments	Financial Position	Notional Quantity (net)
Crude Oil (bbl)	Short	7,241,527
Natural Gas (MMBtu)	Long	11,308,002
NGLs (gal)	Short	40,771,965

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 (gain) 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, 2012, the estimated fair value of this contract was a liability of $74.3 million and the recorded value was a liability of $20.8 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, 2012 (in thousands):

Fair value of commodity contract	$	74,311
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of June 30, 2012	$	20,804

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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 its plant location in the Gulf Coast segment through the fourth quarter of 2014. Changes in the fair value of the derivative component of this contract are recorded in Derivative gain related to facility expenses. As of June 30, 2012, the estimated fair value of this contract was an asset of $10.4 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, 2011. The fair value of the Partnership’s derivative instruments recorded 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, 2012		December 31, 2011		June 30, 2012			December 31, 2011
Commodity contracts(1)
Fair value of derivative instruments — current	$	28,556	$	8,698	$	(30,479	)	$	(90,551	)
Fair value of derivative instruments - long-term	35,237		16,092		(18,951		)	(65,403		)
Total	$	63,793	$	24,790	$	(49,430	)	$	(155,954	)

(1) Includes Embedded Derivatives in Commodity Contracts as discussed above.

Derivative contracts not designated as hedging instruments and the	Three months ended June 30,						Six months ended June 30,
location of gain or (loss) recognized in income	2012			2011			2012			2011
Revenue: Derivative gain (loss)
Realized gain (loss)	$	2,841		$	(12,186	)	$	(7,637	)	$	(26,577	)
Unrealized gain (loss)	133,226			52,776			94,989			(18,512		)
Total revenue: derivative gain (loss)	136,067			40,590			87,352			(45,089		)

Derivative gain (loss) related to purchased product costs
Realized loss	(7,793		)	(5,560		)	(14,867		)	(13,447		)
Unrealized gain (loss)	59,372			5,814			47,646			(5,693		)
Total derivative gain (loss) related to purchased product costs	51,579			254			32,779			(19,140		)

Derivative gain (loss) related to facility expenses
Unrealized gain (loss)	1,146			(2,927		)	2,892			84
Total gain (loss)	$	188,792		$	37,917		$	123,023		$	(64,145	)

For the three months ended June 30, 2012 and 2011, the Realized gain (loss)—revenue includes amortization of premium payments of zero and $1.1 million, respectively. For the six months ended June 30, 2012 and 2011, the Realized gain (loss)—revenue includes amortization of premium payments of zero and $2.1 million, respectively.

During the second quarter of 2012, the Partnership settled a portion of its crude oil derivative positions related to 2014 commodity price exposure prior to the contractual settlement date in order to take advantage of favorable crude oil prices at which the Partnership could settle these proxy hedges that are expected to be less effective. The Partnership plans to opportunistically enter into future NGL hedge transactions to manage the 2014 NGL price exposure. Upon early settlement, the Partnership received $8.8 million which was recorded as a realized gain in Revenue: Derivative gain (loss) in the accompanying Consolidated Statements of Operations.

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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, 2012 and December 31, 2011 (in thousands):

As of June 30, 2012	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	22,846	$	(27,644	)
Significant unobservable inputs (Level 3)
Commodity contracts	30,538		(982		)
Embedded derivatives in commodity contracts	10,409		(20,804		)
Total carrying value in Condensed Consolidated Balance Sheet	$	63,793	$	(49,430	)

As of December 31, 2011	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	5,063	$	(79,358	)
Significant unobservable inputs (Level 3)
Commodity contracts	12,210		(15,175		)
Embedded derivatives in commodity contracts	7,517		(61,421		)
Total carrying value in Condensed Consolidated Balance Sheet	$	24,790	$	(155,954	)

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The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of June 30, 2012. The market approach is used for valuation of all instruments.

Level 3 Instrument	Balance Sheet Classification	Unobservable Inputs	Value Range			Time Period
Commodity contracts	Assets	Forward propane prices (per gallon)	$0.84	-	$0.92	Jan. 2013 - Dec. 2014

		Forward isobutane prices (per gallon)	$1.32	-	$1.44	Jan. 2013 - Dec. 2014

		Forward normal butane prices (per gallon)	$1.22	-	$1.30	Jan. 2013 - Dec. 2014

		Forward natural gasoline prices (per gallon)	$1.75	-	$1.83	Jan. 2013 - Dec. 2014

		Crude option volatilities (%)	18.41%	-	39.55%	Jul. 2012 - Dec. 2014

	Liabilities	Forward propane prices (per gallon)	$0.87	-	$0.89	Dec. 2012 - Mar. 2013

		Crude option volatilities (%)	18.41%	-	39.55%	Jul. 2012 - Dec. 2012

Embedded derivatives in commodity contracts	Liability	Forward propane prices (per gallon)	$0.83	-	$0.92	Jul. 2012 - Dec. 2022

		Forward isobutane prices (per gallon)	$1.31	-	$1.44	Jul. 2012 - Dec. 2022

		Forward normal butane prices (per gallon)	$1.18	-	$1.30	Jul. 2012 - Dec. 2022

		Forward natural gasoline prices (per gallon)	$1.74	-	$1.83	Jul. 2012 - Dec. 2022

		Forward natural gas prices (per mmbtu)	$2.75	-	$5.79	Jul. 2012 - Dec. 2022

		Probability of renewal (1)		0%

	Asset	ERCOT Pricing (per MegaWatt Hour) (2)	$25.38	-	$94.26	Jul. 2012 - Dec. 2014

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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, 2012 and 2011 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

	Three months ended June 30, 2012
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(17,450	)	$	(60,804	)
Total gain (realized and unrealized) included in earnings (1)	46,290			48,109
Settlements	716			2,300
Fair value at end of period	$	29,556		$	(10,395	)

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)	$	43,894		$	47,300

	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 (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 gains (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)	$	10,206		$	(2,429	)

	Six months ended June 30, 2012
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(2,965	)	$	(53,904	)
Total loss (realized and unrealized) included in earnings (1)	34,214			37,671
Settlements	(1,693		)	5,838
Fair value at end of period	$	29,556		$	(10,395	)

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)	$	30,304		$	36,698

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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	)

(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, Facility expenses, and Derivative gain (loss) related to facility expenses.

7. Inventories

Inventories consist of the following (in thousands):

	June 30, 2012		December 31, 2011
NGLs	$	12,470	$	32,352
Spare parts, materials and supplies	9,739		8,654
Total inventories	$	22,209	$	41,006

8. Goodwill

Changes in goodwill for the six months ended June 30, 2012 are summarized as follows (in thousands):

	Southwest			Northeast		Liberty		Gulf Coast			Total
Gross goodwill as of December 31, 2011	$	24,324		$	62,445	$	—	$	9,854		$	96,623
Acquisition (1)	—			—		76,664		—			76,664
Gross goodwill as of June 30, 2012	24,324			62,445		76,664		9,854			173,287
Cumulative impairment (2)	(18,851		)	—		—		(9,854		)	(28,705		)
Balance as of June 30, 2012	$	5,473		$	62,445	$	76,664	$	—		$	144,582

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

(2) All impairments recorded in the fourth quarter of 2008.

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9. Long-Term Debt

Debt is summarized below (in thousands):

	June 30, 2012		December 31, 2011
Credit Facility
Revolving credit facility, 4% interest, due September 2017	$	217,865	$	66,000

Senior Notes (1)
2018 Senior Notes, 8.75% interest, net of discount of $119 and $129, respectively, issued April and May 2008 and due April 2018	80,993		80,983
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020	500,000		500,000
2021 Senior Notes, 6.5% interest, net of discount of $873 and $921, respectively, issued February and March 2011 and due August 2021	499,127		499,079
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022	700,000		700,000
Total long-term debt	$	1,997,985	$	1,846,062

(1) The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $1,853.3 million and $1,880.7 million as of June 30, 2012 and December 31, 2011, respectively, based on quoted prices in an inactive market. The fair value of the Partnership’s Senior Notes is considered a Level 3 measurement.

Credit Facility

On June 29, 2012, the Partnership amended the Credit Facility to increase the borrowing capacity to $1.2 billion and retained the existing accordion option, providing for potential future increases of up to an aggregate of $250 million upon the satisfaction of certain requirements. The term of the Credit Facility was extended one year and now matures on September 7, 2017. The Partnership incurred approximately $2.5 million of deferred financing costs associated with modifications of the Credit Facility during the quarter ended June 30, 2012.

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, other than MarkWest Liberty Midstream and its subsidiaries, and collateralized by substantially all of the Partnership’s assets and those of its wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries. As of June 30, 2012, the Partnership had approximately $217.9 million of borrowings outstanding and approximately $22.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $959.8 million available for borrowing.

10. Equity

Equity Offerings

In January 2012, the Partnership issued approximately 0.7 million common units representing limited partner interests pursuant to the underwriters’ exercise of their option to purchase additional common units under the equity offering initiated in December 2011. The total net proceeds from the exercise of this option were approximately $38 million and were used to partially fund the Partnership’s ongoing capital expenditure program.

In March 2012, the Partnership completed a public offering of approximately 6.8 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option. Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $388 million and were used to partially fund the Partnership’s ongoing capital expenditure program.

In May 2012, the Partnership completed a public offering of 8.0 million newly issued common units representing limited partner interests. Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $427 million, which were used to partially fund the Keystone Acquisition.

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Distributions of Available Cash

Quarter Ended	Distribution Per Common Unit		Declaration Date	Record Date	Payment Date
June 30, 2012	$	0.80	July 26, 2012	August 6, 2012	August 14, 2012
March 31, 2012	$	0.79	April 26, 2012	May 7, 2012	May 15, 2012
December 31, 2011	$	0.76	January 26, 2012	February 6, 2012	February 14, 2012

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 the ordinary course of business, the Partnership is a party to various 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.

Contract Contingencies

Certain natural gas processing arrangements in the Partnership’s Liberty and Northeast segments require the Partnership to construct new natural gas processing plants and NGL pipelines. Some contracts contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. The Partnership has experienced delays in the construction of a processing facility in the Partnership’s Liberty Segment due to events that management considers force majeure including inabilities or delays in obtaining requisite permits, as well as due to extreme weather events. The requisite permits were subsequently issued several months later than expected and construction has re-commenced however those delays exacerbated construction conditions. In addition, the Partnership continued to experience extraordinary weather events in the first quarter of 2012 which have resulted in additional delays. Delay charges for delays other than due to force majeure events are $1.0 million for each month (pro-rated for partial months) that the Partnership does not achieve certain intermediate and final completion construction milestones. In addition, if delays (other than due to force majeure events) are six months or longer, the producer has the option to purchase the processing facilities and terminate the processing agreement with a substantial termination fee. The Partnership has made a force majeure claim as the delays were a direct result of permit delays and weather which are force majeure events under the applicable contract. The customer has reserved its rights to dispute the Partnership’s force majeure claim, but has not requested the payment of any delay charges. The Partnership’s management believes it has a convincing legal position and believes that its force majeure claim would be recognized as valid if contested. The Partnership has completed construction of interim compression and transportation facilities and is providing alternative processing services to mitigate the impact of these delays.

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12. Income Taxes

A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate to income (loss) before provision for income tax for the six months ended June 30, 2012 and 2011 is as follows (in thousands):

	Six months ended June 30, 2012
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	94,600		$	155,621		$	2,206		$	252,427
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	33,110			—			—			33,110
Permanent items	16			—			—			16
State income taxes, net of federal benefit	4,259			765			—			5,024
Provision on income from Class A units (1)	10,868			—			—			10,868
Provision for income tax	$	48,253		$	765		$	—		$	49,018

	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

(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. The Class A units share, on a pro-rata basis, in the income or loss of the Partnership, except for items attributable to the Partnership’s ownership of or sale of shares of the Corporation’s common stock. The provision on income from Class A units includes intra period allocations to continued operations and excludes allocations to equity.

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13. 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, 2012 and 2011, and the weighted-average units used to compute basic and diluted net income (loss) per common unit (in thousands, except per unit data):

	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
Net income (loss) attributable to the Partnership	$	186,908	$	78,497	$	202,928	$	(5,532	)
Less: Income allocable to phantom units	1,209		719		1,391		847
Income (loss) available for common unitholders - basic	185,699		77,778		201,537		(6,379		)
Add: Income allocable to phantom units and DER expense	1,218		—		1,414		—
Income (loss) available for common unitholders - diluted	$	186,917	$	77,778	$	202,951	$	(6,379	)

Weighted average common units outstanding - basic	106,825		75,160		101,833		74,847
Potential common shares (Class B and phantom units)	20,643		106		20,698		—
Weighted average common units outstanding - diluted	127,468		75,266		122,531		74,847

Net income (loss) attributable to the Partnership’s common unitholders per common unit (1)
Basic	$	1.74	$	1.03	$	1.98	$	(0.09	)
Diluted	$	1.47	$	1.03	$	1.66	$	(0.09	)

(1) Earnings per Class B units equals zero as Class B unitholders are not entitled to receive distributions and therefore no income is allocable to Class B units under the two class method.

14. 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.

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, 2012 and 2011 and capital expenditures for the six months ended June 30, 2012 and 2011 for the reported segments (in thousands).

Three months ended June 30, 2012:

	Southwest		Northeast		Liberty			Gulf Coast		Total
Segment revenue	$	189,162	$	42,051	$	59,477		$	20,997	$	311,687
Purchased product costs	91,792		12,921		8,018			—		112,731
Net operating margin	97,370		29,130		51,459			20,997		198,956
Facility expenses	23,034		4,932		13,647			9,607		51,220
Portion of operating income (loss) attributable to non-controlling interests	1,590		—		(113		)	—		1,477
Operating income before items not allocated to segments	$	72,746	$	24,198	$	37,925		$	11,390	$	146,259

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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

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, 2012 and 2011 (in thousands):

	Three months ended June 30,
	2012			2011

Total segment revenue	$	311,687		$	362,271
Derivative gain not allocated to segments	136,067			40,590
Revenue deferral adjustment (1)	(1,701		)	(2,422		)
Total revenue	$	446,053		$	400,439

Operating income before items not allocated to segments	$	146,259		$	147,798

Portion of operating income attributable to non-controlling interests	1,477			16,528
Derivative gain not allocated to segments	188,792			37,917
Revenue deferral adjustment (1)	(1,701		)	(2,422		)
Compensation expense included in facility expenses not allocated to segments	(184		)	(188		)
Facility expenses adjustments (2)	2,866			2,855
Selling, general and administrative expenses	(21,879		)	(18,580		)
Depreciation	(42,918		)	(37,201		)
Amortization of intangible assets	(12,307		)	(10,830		)
Loss on disposal of property, plant and equipment	(1,342		)	(2,373		)
Accretion of asset retirement obligations	(161		)	(290		)
Income from operations	258,902			133,214

Earnings (loss) from unconsolidated affiliate	551			(216		)
Interest income	159			63
Interest expense	(26,762		)	(27,874		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,245		)	(1,443		)
Miscellaneous income, net	4			169
Income before provision for income tax	$	231,609		$	103,913

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and $1.5 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the three months ended June 30, 2011, in comparison, 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.

(2) 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.

Six months ended June 30, 2012:

	Southwest		Northeast		Liberty			Gulf Coast		Total
Segment revenue	$	403,887	$	128,969	$	135,054		$	45,226	$	713,136
Purchased product costs	196,025		38,608		32,653			—		267,286
Net operating margin	207,862		90,361		102,401			45,226		445,850
Facility expenses	46,026		11,310		25,894			19,245		102,475
Portion of operating income (loss) attributable to non-controlling interests	3,036		—		(113		)	—		2,923
Operating income before items not allocated to segments	$	158,800	$	79,051	$	76,620		$	25,981	$	340,452

Capital expenditures	$	95,657	$	43,475	$	432,287		$	7,052	$	578,471
Capital expenditures not allocated to segments										3,732
Total capital expenditures										$	582,203

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

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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, 2012 and 2011 (in thousands):

	Six months ended June 30,
	2012			2011

Total segment revenue	$	713,136		$	719,114
Derivative gain (loss) not allocated to segments	87,352			(45,089		)
Revenue deferral adjustment (1)	(3,969		)	(10,365		)
Total revenue	$	796,519		$	663,660

Operating income before items not allocated to segments	$	340,452		$	296,224
Portion of operating income attributable to non-controlling interests	2,923			30,077
Derivative gain (loss) not allocated to segments	123,023			(64,145		)
Revenue deferral adjustment (1)	(3,969		)	(10,365		)
Compensation expense included in facility expenses not allocated to segments	(633		)	(1,228		)
Facility expenses adjustments (2)	5,730			5,710
Selling, general and administrative expenses	(47,103		)	(40,292		)
Depreciation	(84,063		)	(71,565		)
Amortization of intangible assets	(23,292		)	(21,647		)
Loss on disposal of property, plant and equipment	(2,328		)	(4,472		)
Accretion of asset retirement obligations	(399		)	(377		)
Income from operations	310,341			117,920

Earnings (loss) from unconsolidated affiliate	542			(755		)
Interest income	231			152
Interest expense	(56,234		)	(56,137		)
Amortization of deferred financing costs and discount (a component of interest expense)	(2,515		)	(2,871		)
Loss on redemption of debt	—			(43,328		)
Miscellaneous income, net	62			131
Income before provision for income tax	$	252,427		$	15,112

(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 Partnership’s 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, 2012, approximately $0.4 million and $3.6 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. 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.

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The tables below present information about segment assets as of June 30, 2012 and December 31, 2011 (in thousands):

	June 30, 2012		December 31, 2011
Southwest	$	1,698,454	$	1,701,919
Northeast	491,428		533,591
Liberty	2,147,784		1,114,654
Gulf Coast	527,147		553,043
Total segment assets	4,864,813		3,903,207
Assets not allocated to segments:
Certain cash and cash equivalents	113,529		66,212
Fair value of derivatives	63,793		24,790
Investment in unconsolidated affiliate	26,695		27,853
Other (1)	65,768		48,363
Total assets	$	5,134,598	$	4,070,425

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

15. Supplemental Condensed Consolidating Financial Information

The Partnership has no operations independent of its subsidiaries. As of June 30, 2012, the Partnership’s obligations under the outstanding Senior Notes (see Note 9) were fully, jointly and severally guaranteed, by all of its wholly-owned subsidiaries other than MarkWest Liberty Midstream and its subsidiaries. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures. MarkWest Liberty Midstream, MarkWest Utica EMG 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 the 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 subsidiaries and combined non-guarantor subsidiaries as of June 30, 2012 and December 31, 2011 and for the three and six months ended June 30, 2012 and 2011 is as follows (in thousands):

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Condensed Consolidating Balance Sheets

	As of June 30, 2012
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	118,908	$	6,554	$	—		$	125,462
Restricted cash	—		—		25,285		—			25,285
Receivables and other current assets	5,824		137,690		32,525		—			176,039
Intercompany receivables	772,994		7,818		7,866		(788,678		)	—
Fair value of derivative instruments	—		26,883		1,673		—			28,556
Total current assets	778,818		291,299		73,903		(788,678		)	355,342

Total property, plant and equipment, net	3,811		1,926,844		1,832,027		(119,046		)	3,643,636

Other long-term assets:
Investment in unconsolidated affiliate	—		26,695		—		—			26,695
Investment in consolidated affiliates	3,294,718		1,813,342		—		(5,108,060		)	—
Intangibles, net of accumulated amortization	—		581,273		303,910		—			885,183
Fair value of derivative instruments	—		34,472		765		—			35,237
Intercompany notes receivable	219,000		—		—		(219,000		)	—
Other long-term assets	41,289		70,212		77,004		—			188,505
Total assets	$	4,337,636	$	4,744,137	$	2,287,609	$	(6,234,784	)	$	5,134,598

LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	268	$	774,338	$	14,072	$	(788,678	)	$	—
Fair value of derivative instruments	—		30,398		81		—			30,479
Other current liabilities	25,851		151,498		262,389		—			439,738
Total current liabilities	26,119		956,234		276,542		(788,678		)	470,217

Deferred income taxes	1,059		155,724		—		—			156,783
Long-term intercompany financing payable	—		196,000		125,349		(321,349		)	—
Fair value of derivative instruments	—		18,951		—		—			18,951
Long-term debt, net of discounts	1,997,985		—		—		—			1,997,985
Other long-term liabilities	3,056		122,510		2,665		—			128,231

Equity:
Common units	1,556,886		3,294,718		1,883,053		(5,194,468		)	1,540,189
Class B units	752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries	—		—		—		69,711			69,711
Total equity	2,309,417		3,294,718		1,883,053		(5,124,757		)	2,362,431

Total liabilities and equity	$	4,337,636	$	4,744,137	$	2,287,609	$	(6,234,784	)	$	5,134,598

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	As of December 31, 2011
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	22	$	99,580	$	17,414	$	—		$	117,016
Restricted cash	—		—		26,193		—			26,193
Receivables and other current assets	7,097		232,010		55,098		(5		)	294,200
Intercompany receivables	19,981		40,519		22,193		(82,693		)	—
Fair value of derivative instruments	—		8,015		683		—			8,698
Total current assets	27,100		380,124		121,581		(82,698		)	446,107
Total property, plant and equipment, net	4,012		1,714,857		1,163,226		(17,788		)	2,864,307
Other long-term assets:
Investment in unconsolidated affiliate	—		27,853		—		—			27,853
Investment in consolidated affiliates	3,071,124		1,097,350		—		(4,168,474		)	—
Intangibles, net of accumulated amortization	—		603,224		543		—			603,767
Fair value of derivative instruments	—		16,092		—		—			16,092
Intercompany notes receivable	235,700		—		—		(235,700		)	—
Other long-term assets	41,492		70,434		373		—			112,299
Total assets	$	3,379,428	$	3,909,934	$	1,285,723	$	(4,504,660	)	$	4,070,425

LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	40,503	$	40,374	$	1,816	$	(82,693	)	$	—
Fair value of derivative instruments	—		90,551		—		—			90,551
Other current liabilities	38,775		219,622		92,930		(5		)	351,322
Total current liabilities	79,278		350,547		94,746		(82,698		)	441,873
Deferred income taxes	1,228		92,436		—		—			93,664
Long-term intercompany financing payable	—		212,700		23,000		(235,700		)	—
Fair value of derivative instruments	—		65,403		—		—			65,403
Long-term debt, net of discounts	1,846,062		—		—		—			1,846,062
Other long-term liabilities	3,232		117,724		400		—			121,356
Equity:
Common Units	697,097		3,071,124		1,167,577		(4,256,489		)	679,309
Class B Units	752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries	—		—		—		70,227			70,227
Total equity	1,449,628		3,071,124		1,167,577		(4,186,262		)	1,502,067
Total liabilities and equity	$	3,379,428	$	3,909,934	$	1,285,723	$	(4,504,660	)	$	4,070,425

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Condensed Consolidating Statements of Operations

	Three Months Ended June 30, 2012
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	381,527		$	67,001		$	(2,475	)	$	446,053
Operating expenses:	—			—			—			—
Purchased product costs	—			53,041			8,111			—			61,152
Facility expenses	—			33,111			14,614			(333		)	47,392
Selling, general and administrative expenses	12,539			2,205			11,378			(4,243		)	21,879
Depreciation and amortization	148			40,634			15,572			(1,129		)	55,225
Other operating expenses	—			628			875			—			1,503
Total operating expenses	12,687			129,619			50,550			(5,705		)	187,151

(Loss) income from operations	(12,687		)	251,908			16,451			3,230			258,902

Earnings from consolidated affiliates	217,483			14,518			—			(232,001		)	—
Other expense, net	(20,700		)	(5,169		)	(1,705		)	281			(27,293		)
Income before provision for income tax	184,096			261,257			14,746			(228,490		)	231,609
Provision for income tax expense	699			43,774			—			—			44,473
Net income	183,397			217,483			14,746			(228,490		)	187,136
Net income attributable to non-controlling interest	—			—			—			(228		)	(228		)
Net income attributable to the Partnership	$	183,397		$	217,483		$	14,746		$	(228,718	)	$	186,908

	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

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	Six Months Ended June 30, 2012
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	652,598		$	146,396		$	(2,475	)	$	796,519
Operating expenses:
Purchased product costs	—			201,642			32,865			—			234,507
Facility expenses	—			67,047			27,948			(509		)	94,486
Selling, general and administrative expenses	26,956			7,700			14,509			(2,062		)	47,103
Depreciation and amortization	312			79,927			28,483			(1,367		)	107,355
Other operating expenses	—			1,739			988			—			2,727
Total operating expenses	27,268			358,055			104,793			(3,938		)	486,178

(Loss) income from operations	(27,268		)	294,543			41,603			1,463			310,341

Earnings from consolidated affiliates	273,914			38,752			—			(312,666		)	—
Other expense, net	(44,044		)	(11,128		)	(2,370		)	(372		)	(57,914		)
Income before provision for income tax	202,602			322,167			39,233			(311,575		)	252,427
Provision for income tax expense	765			48,253			—			—			49,018
Net income	201,837			273,914			39,233			(311,575		)	203,409
Net income attributable to non-controlling interest	—			—			—			(481		)	(481		)
Net income attributable to the Partnership	$	201,837		$	273,914		$	39,233		$	(312,056	)	$	202,928

	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	)

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Condensed Consolidating Statements of Cash Flows

	Six Months Ended June 30, 2012
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(77,181	)	$	211,915		$	121,980		$	(277	)	$	256,437

Cash flows from investing activities:
Restricted cash	—			—			1,003			—			1,003
Capital expenditures	(114		)	(166,926		)	(416,377		)	1,214			(582,203		)
Equity investments	(26,640		)	(843,960		)	—			870,600			—
Acquisition of business, net of cash acquired	—			—			(506,797		)	—			(506,797		)
Distributions from consolidated affiliates	36,575			53,355			—			(89,930		)	—
Collection of intercompany notes, net	16,700			—			—			(16,700		)	—
Proceeds from disposal of property, plant and equipment	—			1,713			—			(1,214		)	499
Net cash flows provided by (used in) investing activities	26,521			(955,818		)	(922,171		)	763,970			(1,087,498		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	852,873			—			—			—			852,873
Proceeds from revolving credit facility	238,065			—			—			—			238,065
Payments of revolving credit facility	(86,200		)	—			—			—			(86,200		)
Payments related to intercompany financing, net	—			(16,700		)	(277		)	16,977			—
Payments for deferred financing costs	(2,315		)	—			—			—			(2,315		)
Contributions from parent and affiliates	—			26,640			843,960			(870,600		)	—
Contribution from non-controlling interest	—			—			1,940			—			1,940
Share-based payment activity	(8,048		)	2,207			—			—			(5,841		)
Payment of distributions	(155,073		)	(36,575		)	(56,292		)	89,930			(158,010		)
Payments of SMR liability	—			(1,005		)	—			—			(1,005		)
Intercompany advances, net	(788,664		)	788,664			—			—			—
Net cash flows provided by financing activities	50,638			763,231			789,331			(763,693		)	839,507

Net increase (decrease) in cash	(22		)	19,328			(10,860		)	—			8,446
Cash and cash equivalents at beginning of year	22			99,580			17,414			—			117,016
Cash and cash equivalents at end of period	$	—		$	118,908		$	6,554		$	—		$	125,462

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	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		)
Acquisitions	—			(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 flows 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 and affiliates	—			21,556			130,361			(151,917		)	—
Contributions from non-controlling interest	—			—			24,400			—			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 flows 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

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16. Supplemental Cash Flow Information

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

	Six months ended June 30,
	2012		2011
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	61,543	$	57,820
Cash paid for income taxes, net	18,425		514

Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	236,495	$	58,429
Interest capitalized on construction in progress	8,048		199
Issuance of common units for vesting of share-based payment awards	2,501		5,282

17. Subsequent Events

Effective July 2012, the Partnership amended its lease for its corporate offices in Denver, Colorado to include additional space and extend the term of the lease through 2024. The following table shows the increase in minimum future lease payments as of June 30, 2012 compared to the amount disclosed in Note 18 Commitments and Contingencies in the Form 10-K for the year ended December 31, 2011 (in thousands):

2012	$	569
2013	4,295
2014	3,995
2015	3,926
2016	4,747
2017 and thereafter	58,221
Total	$	75,753

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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, 2011. 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, 2012 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) decreased approximately $1.5 million, or 1%, for the three months ended June 30, 2012 compared to the same period in 2011. The decrease is due primarily to a decline in NGL prices which was partially offset by our acquisition of M&R MWE Liberty, L.L.C.’s (“M&R”) interest in MarkWest Liberty Midstream and an approximate 20% increase in processed volumes, primarily due to our expanding operations in the Liberty and Southwest segments.

· In May 2012, we received net proceeds of approximately $427 million from a public offering of 8.0 million newly issued common units representing limited partner interests.

· In May 2012, we announced an additional 400 MMcf/d expansion of our Majorsville Complex that is supported by a long-term fee-based processing agreement with an affiliate of Chesapeake Energy Corporation. This expansion, combined with the expansion of the Majorsville Complex announced in the first quarter of 2012, consists of four, 200 MMcf/d processing plants that are expected to begin operations in 2013 and 2014 and will bring total cryogenic processing capacity at the Majorsville Complex to approximately 1.1 Bcf/d.

· In May 2012, we announced a long-term fee-based agreement with Antero Resources Appalachian Corporation (“Antero”) to install significant gathering facilities in support of Antero’s rapidly growing liquids-rich natural gas production in northern West Virginia. The new gathering system will have initial capacity to deliver more than 300 MMcf/d to our processing facilities currently under construction in Sherwood, West Virginia (“Sherwood Complex”). The first phase of the gathering system will be completed in the third quarter of 2012 in conjunction with the completion of the first processing facility at the Sherwood Complex.

· In May 2012, we completed the Keystone Acquisition for approximately $509.6 million, subject to final working capital adjustments. Keystone’s existing assets are located in Butler County, Pennsylvania and include two cryogenic gas processing plants totaling 90 million cubic feet per day of processing capacity, a gas gathering system and associated field compression. Pursuant to a long-term gathering and processing agreement, Rex and Summit have dedicated the production from approximately 900 square miles to the Partnership. The Partnership will gather and process liquids rich gas, and in 2013 exchange NGLs for fractionated products under a long-term, fee-based agreement.

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Non-GAAP Measures

In evaluating our 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 14 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 14 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). 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.

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

	Three months ended June 30,						Six months ended June 30,
	2012			2011			2012			2011
Segment revenue	$	311,687		$	362,271		$	713,136		$	719,114
Purchased product costs	(112,731		)	(154,580		)	(267,286		)	(308,209		)
Net operating margin	198,956			207,691			445,850			410,905
Facility expenses	(48,538		)	(40,698		)	(97,378		)	(80,122		)
Derivative gain (loss)	188,792			37,917			123,023			(64,145		)
Revenue deferral adjustment	(1,701		)	(2,422		)	(3,969		)	(10,365		)
Selling, general and administrative expenses	(21,879		)	(18,580		)	(47,103		)	(40,292		)
Depreciation	(42,918		)	(37,201		)	(84,063		)	(71,565		)
Amortization of intangible assets	(12,307		)	(10,830		)	(23,292		)	(21,647		)
Loss on disposal of property, plant and equipment	(1,342		)	(2,373		)	(2,328		)	(4,472		)
Accretion of asset retirement obligations	(161		)	(290		)	(399		)	(377		)
Income from operations	$	258,902		$	133,214		$	310,341		$	117,920

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, 2011 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, 2012, 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)
Segment revenue	27	%	35	%	3	%	35	%
Net operating margin (4)	44	%	25	%	0	%	31	%

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

(2) Includes arrangements tied to natural gas prices.

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

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

Seasonality

Our business is affected by seasonal fluctuations in commodity prices. Sales volumes also are affected by various other factors such as fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast and Liberty segments are particularly impacted by seasonality. In our Northeast and Liberty segments, we store a portion of the propane that is produced in the summer to be sold in the winter months. To manage this seasonality, we have access to approximately 60 million gallons of propane storage capacity provided by our own storage facilities and a firm capacity arrangement with a third-party. However, the mild winter in 2011 resulted in constraints in available propane storage in the Northeast. As a result of our seasonality, we generally expect the sales volumes in our Northeast and Liberty segments to be higher in the first quarter and fourth quarter, however, the expected growth and expansion in our Liberty segment may partially counteract this seasonality impact on sales volumes.

Results of Operations

Segment Reporting

We present information in this MD&A by segment. The segment information appearing in Note 14 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal management reporting. We conduct our operations in the following operating segments: Southwest, Northeast, Liberty and Gulf Coast. Our assets and operations in each of these segments are described below. In addition, we include a description of our initial plan to development of our Utica operations, which is included in the Liberty segment.

Southwest

· East Texas. We own a system that consists of natural gas gathering pipelines, centralized compressor stations, 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. We expect to complete an additional 120 MMcf/d cryogenic processing plant during the first quarter of 2013, increasing total processing capacity in East Texas to 400 MMcf/d. We also plan to expand gathering capacity in East Texas by 140 MMcf/d and residue gas outlet capacities by 60 MMcf/d.

· Oklahoma. We own a natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. The liquids-rich natural gas gathered in the Woodford system is processed through Centrahoma, our equity investment or other third-party processors. In addition, we own the Foss Lake natural gas gathering system and the Western Oklahoma natural gas processing complex, all located in Roger Mills, Beckham, 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 is ultimately compressed and delivered to the processing plants. We also own a gathering system in the Granite Wash formation in the Texas panhandle that is connected to our Western Oklahoma processing complex.

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. We completed an additional interconnect with the NGPL Pipeline in Bennington, Oklahoma in April 2012. For a complete discussion of the formation of, and accounting treatment for, MarkWest Pioneer, see Note 4 of Item 8. Financial Statement and Supplementary Data, of our Annual Report on Form 10-K for the year ended December 31, 2011.

· Other Southwest. We own a number of natural gas gathering systems and lateral pipelines located in Texas, Louisiana and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. We gather a

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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 with the ability to expand to support higher volumes as needed. Sunoco completed an open season for Mariner West and received binding commitments from shippers that would enable the project to proceed as designed.

· An additional joint project with Sunoco is under consideration (“Mariner East”). Mariner East, a pipeline and marine project, is intended to deliver Marcellus purity ethane and purity propane to the Gulf Coast and international markets.

We continue to evaluate additional projects that would support a comprehensive ethane solution for producers in the Marcellus Shale.

Utica

Effective January 1, 2012, the Partnership and The Energy & Minerals Group (“EMG”) formed MarkWest Utica EMG, a joint venture focused on the development of significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure to serve producers’ drilling programs in the Utica Shale in eastern Ohio. The current Utica development plan includes two new processing complexes with total cryogenic processing capacity of 325 MMcf/d and 100,000 Bbl/d of fractionation, storage, and marketing capabilities. The fractionation facility for propane and heavier components (“Harrison Fractionation Facility”) will be jointly owned by MarkWest Utica EMG and MarkWest Liberty Midstream. The processing complexes will be in Harrison County (the “Harrison Complex”) and Noble County, and are both expected to begin the first phase of operations in late 2012 with interim mechanical refrigeration processing capacity of 105 MMcf/d. The planned cryogenic processing capacity of 325 MMcf/d is expected to be in operation by the end of 2013.

Both processing complexes are expected to be connected via an NGL gathering pipeline system to the Harrison Fractionation Facility that is expected to be operational by the fourth quarter of 2013. Creating a large network of processing complexes connected through an extensive NGL gathering system has been critical to the full development of the Marcellus, and the announced Ohio facilities represent the first major step in providing Utica Shale producers with the same benefits. Additionally, the Harrison Fractionation Facility, which would be able to market NGLs by truck, rail and pipeline, is expected to be connected to our extensive processing and NGL pipeline network in our Liberty segment and provide for the integrated operation of the two largest fractionation complexes in the Northeast United States.

On June 4, 2012, MarkWest Utica EMG announced agreements with Gulfport Energy Corporation (“Gulfport”) to provide gathering, processing, fractionation, and marketing services in the liquids-rich corridor of the Utica shale. Under the terms of the agreements, MarkWest Utica EMG will develop natural gas gathering infrastructure to provide service to Gulfport, primarily in Harrison, Guernsey, and Belmont Counties, that is expected to commence initial operations beginning in the second half of 2012. MarkWest Utica EMG will process the gas at its Harrison Complex, and is expected to provide NGL fractionation and marketing services at the Harrison Fractionation Facility when it is completed in 2013.

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 is 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, 2012:

	Southwest		Northeast		Liberty		Gulf Coast
Segment revenue	57	%	18	%	19	%	6	%
Net operating margin	47	%	20	%	23	%	10	%

Segment Operating Results

Items below Income (loss) from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual business

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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, 2012 and 2011 and for the six months ended June 30, 2012 and 2011. The information includes net operating margin, a non-GAAP financial measure. See above for a reconciliation of net operating margin to Income (loss) from operations, the most comparable GAAP financial measure.

Three months ended June 30, 2012 compared to three months ended June 30, 2011

Southwest

	Three months ended June 30,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	189,162	$	235,575	$	(46,413	)	(20	)%
Purchased product costs	91,792		128,988		(37,196		)	(29	)%
Net operating margin	97,370		106,587		(9,217		)	(9	)%
Facility expenses	23,034		20,855		2,179			10	%
Portion of operating income attributable to non-controlling interests	1,590		1,346		244			18	%
Operating income before items not allocated to segments	$	72,746	$	84,386	$	(11,640	)	(14	)%

Segment Revenue. Revenue decreased primarily due to lower NGL prices and decrease in natural gas sales volumes. The decrease was partially offset by increased NGL sales volumes, primarily due to the expansion of the Western Oklahoma processing facilities completed in the third quarter of 2011.

Purchased Product Costs. Purchased product costs decreased primarily due to a decrease in the price NGLs and a decrease in the volume of natural gas purchased.

Facility Expenses. Facility expenses increased primarily due to timing of significant repairs and maintenance activities in East Texas facilities, as well as the expansion of our processing and gathering facilities in Western Oklahoma.

Northeast

	Three months ended June 30,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	42,051	$	53,676	$	(11,625	)	(22	)%
Purchased product costs	12,921		15,702		(2,781		)	(18	)%
Net operating margin	29,130		37,974		(8,844		)	(23	)%
Facility expenses	4,932		6,929		(1,997		)	(29	)%
Operating income before items not allocated to segments	$	24,198	$	31,045	$	(6,847	)	(22	)%

Segment Revenue. Revenue decreased due to lower NGL prices, partially offset by an increase in NGL sales volumes. The increase in NGL sales volumes for the three months ended June 30, 2012 compared to the same period in 2011 is partly due to a key transmission pipeline feeding our processing plants, which was damaged and had limited service capacity during the first half of 2011 but that was repaired and fully operational for the entire second quarter of 2012.

Purchased Product Costs. Purchased product costs decreased due to lower prices for natural gas that is purchased to satisfy the keep-whole arrangements in the Appalachia area, partially offset by an increase in sales volumes.

Facility Expenses. Facility expenses decreased primarily due to a reduction in property taxes resulting from a favorable rate determination related to one of our facilities.

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Liberty

	Three months ended June 30,								%
	2012			2011		$ Change			Change
	(in thousands)
Segment revenue	$	59,477		$	48,337	$	11,140		23	%
Purchased product costs	8,018			9,890		(1,872		)	(19	)%
Net operating margin	51,459			38,447		13,012			34	%
Facility expenses	13,647			7,269		6,378			88	%
Portion of operating (loss) income attributable to non-controlling interests	(113		)	15,182		(15,295		)	(101	)%
Operating income before items not allocated to segments	$	37,925		$	15,996	$	21,929		137	%

Segment Revenue. Revenue increased due to ongoing expansion of the Liberty operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $13.0 million related to gathering, processing and fractionation fees, partially offset by approximately $2.5 million decrease related to lower NGL prices and less propane volumes sold.

Facility Expenses. Facility expenses increased due to the ongoing expansion of the Liberty operations.

Portion of Operating Income Attributable to Non-controlling Interests. The portion of operating income attributable to non-controlling interests for the three months ended June 30, 2011 represented the interest of M&R an affiliate of EMG, our former joint venture partner in MarkWest Liberty Midstream, in net operating income of MarkWest Liberty Midstream. As a result of our acquisition of M&R’s interest in MarkWest Liberty Midstream, no portion of its income is attributable to non-controlling interests for the three months ended June 30, 2012. The immaterial portion of loss allocable to the non-controlling interest for the three months ended June 30, 2012 relates to MarkWest Utica EMG and its subsidiaries.

Gulf Coast

	Three months ended June 30,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	20,997	$	24,683	$	(3,686	)	(15	)%
Purchased product costs	—		—		—			N/A
Net operating margin	20,997		24,683		(3,686		)	(15	)%
Facility expenses	9,607		8,312		1,295			16	%
Operating income before items not allocated to segments	$	11,390	$	16,371	$	(4,981	)	(30	)%

Segment Revenue. Revenue decreased primarily due to lower NGL prices.

Facility Expenses. Facility expenses increased primarily due to plant turnaround costs in the second quarter of 2012.

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

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income (loss) before provision for income tax for the three months ended June 30, 2012 and 2011, respectively. 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,									%
	2012			2011			$ Change			Change
	(in thousands)
Total segment revenue	$	311,687		$	362,271		$	(50,584	)	(14	)%
Derivative gain not allocated to segments	136,067			40,590			95,477			235	%
Revenue deferral adjustment	(1,701		)	(2,422		)	721			(30	)%
Total revenue	$	446,053		$	400,439		$	45,614		11	%

Operating income before items not allocated to segments	$	146,259		$	147,798		$	(1,539	)	(1	)%

Portion of operating income attributable to non-controlling interests	1,477			16,528			(15,051		)	(91	)%
Derivative gain not allocated to segments	188,792			37,917			150,875			398	%
Revenue deferral adjustment	(1,701		)	(2,422		)	721			(30	)%
Compensation expense included in facility expenses not allocated to segments	(184		)	(188		)	4			(2	)%
Facility expenses adjustments	2,866			2,855			11			0	%
Selling, general and administrative expenses	(21,879		)	(18,580		)	(3,299		)	18	%
Depreciation	(42,918		)	(37,201		)	(5,717		)	15	%
Amortization of intangible assets	(12,307		)	(10,830		)	(1,477		)	14	%
Loss on disposal of property, plant and equipment	(1,342		)	(2,373		)	1,031			(43	)%
Accretion of asset retirement obligations	(161		)	(290		)	129			(44	)%
Income from operations	258,902			133,214			125,688			94	%

Earnings (loss) from unconsolidated affiliate	551			(216		)	767			(355	)%
Interest income	159			63			96			152	%
Interest expense	(26,762		)	(27,874		)	1,112			(4	)%
Amortization of deferred financing costs and discount (a component of interest expense)	(1,245		)	(1,443		)	198			(14	)%
Miscellaneous income, net	4			169			(165		)	(98	)%
Income before provision for income tax	$	231,609		$	103,913		$	127,696		123	%

Derivative Gain (Loss) Not Allocated to Segments. Unrealized gain from the mark-to-market of our derivative instruments was $193.8 million for the three months ended June 30, 2012 compared to an unrealized gain of $55.7 million for the same period in 2011. Realized loss from the settlement of our derivative instruments was $4.9 million for the three months ended June 30, 2012 compared to $17.7 million for the same period in 2011. The total change of $150.9 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, 2012, approximately $0.2 million and $1.5 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. 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 second quarter 2012’s amount until the beginning

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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.

Selling, General and Administrative Expenses. Selling, general and administrative expenses increased primarily due to higher labor, benefits, office expense and professional services necessary to support the overall growth of our operations.

Depreciation. Depreciation increased due to additional projects completed during 2011 through the second quarter of 2012, as well as the Keystone Acquisition.

Interest Expense. Interest expense decreased as additional expense from the increased amount of outstanding debt was more than offset by lower interest rates and an increase in capitalized interest.

Six months ended June 30, 2012 compared to six months ended June 30, 2011

Southwest

	Six months ended June,							%
	2012		2011		$ Change			Change
	(in thousands)

Segment revenue	$	403,887	$	437,349	$	(33,462	)	(8	)%
Purchased product costs	196,025		232,184		(36,159		)	(16	)%
Net operating margin	207,862		205,165		2,697			1	%
Facility expenses	46,026		41,012		5,014			12	%
Portion of operating income attributable to non-controlling interests	3,036		2,518		518			21	%
Operating income before items not allocated to segments	$	158,800	$	161,635	$	(2,835	)	(2	)%

Segment Revenue. Revenue decreased primarily due to lower NGL prices and a decrease in natural gas sales volumes. The decrease was partially offset by an increase in NGL sales volumes, primarily due to the expansion of the Western Oklahoma processing facilities completed in the third quarter of 2011.

Purchased Product Costs. Purchased product costs decreased primarily due to lower NGL prices and a reduction in the volume of natural gas purchased.

Facility Expenses. Facility expenses increased primarily due to the expansion of our processing and gathering facilities in Western Oklahoma.

Northeast

	Six months ended June,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	128,969	$	145,767	$	(16,798	)	(12	)%
Purchased product costs	38,608		56,580		(17,972		)	(32	)%
Net operating margin	90,361		89,187		1,174			1	%
Facility expenses	11,310		12,523		(1,213		)	(10	)%
Operating income before items not allocated to segments	$	79,051	$	76,664	$	2,387		3	%

Segment Revenue. Revenue decreased due to lower natural gas prices, as well as a contract change related to our acquisition of the Langley processing facilities and related assets (“Langley Acquisition”) in the first quarter of 2011. Subsequent to the Langley Acquisition, we continue to market the NGLs related to natural gas processed at the Langley plant; however we are acting as an agent and therefore record revenue net of purchased product costs. Prior to the contract change we were acting as the principal. The decrease in revenue was offset by increased NGL sales volumes, which was partly due to a key transmission pipeline feeding our processing plants that was damaged and had limited service capacity during the first half of 2011 but that was repaired and fully operational for the entire first half of 2012.

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Purchased Product Costs. Purchased product costs decreased due to the contract change related to the Langley Acquisition. In addition, purchased product costs decreased due to lower prices for natural gas that is purchased to satisfy the keep-whole arrangements in the Appalachia area, which was partially offset by an increase in sales volumes.

Facility Expenses. Facility expenses decreased primarily due to a reduction in property taxes resulting from a favorable rate determination related to our facilities.

Liberty

	Six months ended June,								%
	2012			2011		$ Change			Change
	(in thousands)
Segment revenue	$	135,054		$	89,556	$	45,498		51	%
Purchased product costs	32,653			19,445		13,208			68	%
Net operating margin	102,401			70,111		32,290			46	%
Facility expenses	25,894			13,767		12,127			88	%
Portion of operating (loss) income attributable to non-controlling interests	(113		)	27,559		(27,672		)	(100	)%
Operating income before items not allocated to segments	$	76,620		$	28,785	$	47,835		166	%

Segment Revenue. Revenue increased due to ongoing expansion of the Liberty operations resulting in increased gathered and fractionated volumes. Revenue increased approximately $28.1 million related to gathering, fractionation and processing fees and approximately $16.1 million related to increased NGL product sales under a percent of proceeds agreement with a producer and an increase in sales of propane from inventory purchased from producer customers.

Purchased Product Costs. Purchased product costs increased primarily due to an increase in the volume of NGLs purchased from a producer customer and then sold.

Facility Expenses. Facility expenses increased due to the ongoing expansion of the Liberty operations.

Portion of Operating Income Attributable to Non-controlling Interests. The portion of operating income attributable to non-controlling interests for the six months ended June 30, 2011 represented M&R’s interest in net operating income of MarkWest Liberty Midstream. As a result of our acquisition of M&R’s interest in MarkWest Liberty Midstream, no portion of its income is attributable to non-controlling interests for the three months ended June 30, 2012. The immaterial portion of income allocable to the non-controlling interest for the three months ended June 30, 2012 relates to MarkWest Utica EMG and its subsidiaries.

Gulf Coast

	Six months ended June,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	45,226	$	46,442	$	(1,216	)	(3	)%
Purchased product costs	—		—		—			N/A
Net operating margin	45,226		46,442		(1,216		)	(3	)%
Facility expenses	19,245		17,302		1,943			11	%
Operating income before items not allocated to segments	$	25,981	$	29,140	$	(3,159	)	(11	)%

Segment Revenue. Revenue decreased primarily due to lower NGL prices, partially offset by an increase in volumes resulting from, increased production as scheduled refinery maintenance in 2011 did not recur in 2012.

Facility Expenses. Facility expenses increased primarily due to plant turnaround costs incurred in the second quarter of 2012, as well as timing of other facility maintenance and repairs.

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

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income (loss) before provision for income tax for the six months ended June 30, 2012 and 2011, respectively. 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.

	Six months ended June,									%
	2012			2011			$ Change			Change
	(in thousands)
Total segment revenue	$	713,136		$	719,114		$	(5,978	)	(1	)%
Derivative gain (loss) not allocated to segments	87,352			(45,089		)	132,441			(294	)%
Revenue deferral adjustment	(3,969		)	(10,365		)	6,396			(62	)%
Total revenue	$	796,519		$	663,660		$	132,859		20	%

Operating income before items not allocated to segments	$	340,452		$	296,224		$	44,228		15	%

Portion of operating income attributable to non-controlling interests	2,923			30,077			(27,154		)	(90	)%
Derivative gain (loss) not allocated to segments	123,023			(64,145		)	187,168			(292	)%
Revenue deferral adjustment	(3,969		)	(10,365		)	6,396			(62	)%
Compensation expense included in facility expenses not allocated to segments.	(633		)	(1,228		)	595			(48	)%
Facility expenses adjustments	5,730			5,710			20			0	%
Selling, general and administrative expenses	(47,103		)	(40,292		)	(6,811		)	17	%
Depreciation	(84,063		)	(71,565		)	(12,498		)	17	%
Amortization of intangible assets	(23,292		)	(21,647		)	(1,645		)	8	%
Loss on disposal of property, plant and equipment	(2,328		)	(4,472		)	2,144			(48	)%
Accretion of asset retirement obligations	(399		)	(377		)	(22		)	6	%
Income from operations	310,341			117,920			192,421			163	%

Earnings (loss) from unconsolidated affiliate	542			(755		)	1,297			(172	)%
Interest income	231			152			79			52	%
Interest expense	(56,234		)	(56,137		)	(97		)	0	%
Amortization of deferred financing costs and discount (a component of interest expense)	(2,515		)	(2,871		)	356			(12	)%
Loss on redemption of debt	—			(43,328		)	43,328			(100	)%
Miscellaneous income, net	62			131			(69		)	(53	)%
Income before provision for income tax	$	252,427		$	15,112		$	237,315		1,570	%

Derivative Gain (Loss) Not Allocated to Segments. Unrealized gain from the mark-to-market of our derivative instruments was $145.5 million for the six months ended June 30, 2012 compared to an unrealized loss of $24.2 million for the same period in 2011. Realized loss from the settlement of our derivative instruments was $22.5 million for the six months ended June 30, 2012 compared to $40.0 million for the same period in 2011. The total change of $187.2 million is due mainly to volatility in commodity prices.

Revenue Deferral Adjustment. Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue 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, 2012, approximately $0.4 million and $3.6 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. 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. Based on current commodity prices, management expects the deferred revenue in subsequent periods to approximate the second quarter 2012’s amount until the beginning

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Operating Data

	Three months ended June 30,		%		Six months ended June 30,		%
	2012	2011	Change		2012	2011	Change
Southwest
East Texas gathering systems throughput (Mcf/d)	440,400	428,300	3	%	425,200	427,000	(0	)%
East Texas natural gas processed (Mcf/d)	268,300	229,000	17	%	255,400	224,100	14	%
East Texas NGL sales (gallons, in thousands)	68,000	59,500	14	%	131,400	116,200	13	%

Western Oklahoma gathering system throughput (Mcf/d) (1)	252,200	223,900	13	%	257,100	215,700	19	%
Western Oklahoma natural gas processed (Mcf/d)	218,900	159,500	37	%	211,400	158,300	34	%
Western Oklahoma NGL sales (gallons, in thousands)	61,700	35,100	76	%	119,000	74,100	61	%

Southeast Oklahoma gathering systems throughput (Mcf/d)	503,300	511,700	(2	)%	502,200	504,900	(1	)%
Southeast Oklahoma natural gas processed (Mcf/d) (2)	119,600	110,200	9	%	110,700	102,000	9	%
Southeast Oklahoma NGL sales (gallons, in thousands)	41,300	32,100	29	%	74,300	61,500	21	%

Arkoma Connector Pipeline throughput (Mcf/d)	331,200	298,400	11	%	329,900	292,100	13	%

Other Southwest gathering system throughput (Mcf/d)	26,700	31,600	(16	)%	25,600	32,300	(21	)%

Northeast
Natural gas processed (Mcf/d) (3)	328,200	319,600	3	%	324,900	312,500	4	%
NGLs fractionated (Bbl/d) (4)	17,200	22,700	(24	)%	16,900	22,500	(25	)%

Keep-whole sales (gallons, in thousands)	23,700	21,100	12	%	73,300	60,900	20	%
Percent-of-proceeds sales (gallons, in thousands)	36,800	33,100	11	%	69,800	64,000	9	%
Total NGL sales (gallons, in thousands) (5)	60,500	54,200	12	%	143,100	124,900	15	%
Crude oil transported for a fee (Bbl/d)	8,300	11,500	(28	)%	9,400	10,800	(13	)%

Liberty
Natural gas processed (Mcf/d)	400,600	298,200	34	%	396,400	276,500	43	%
Gathering system throughput (Mcf/d)	367,400	232,000	58	%	337,800	214,000	58	%
NGLs fractionated (Bbl/d) (6)	19,800	8,400	136	%	19,900	7,700	158	%
NGL sales (gallons, in thousands) (7)	75,900	50,700	50	%	173,400	102,400	69	%

Gulf Coast
Refinery off-gas processed (Mcf/d)	115,800	114,600	1	%	118,000	108,700	9	%
Liquids fractionated (Bbl/d)	21,700	21,900	(1	)%	22,500	20,600	9	%
NGL sales (gallons excluding hydrogen, in thousands)	83,000	83,600	(1	)%	172,300	156,300	10	%

(1) Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as it is one integrated area of operations.

(2) The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or third-party processors.

(3) Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported for the six months ended June 30, 2011 are the average daily rates for the days of operation.

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(4) Amount includes zero barrels per day and 5,500 barrels per day fractionated on behalf of Liberty for the three and six months ended June 30, 2012 and 2011, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionates NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011, except during outages.

(5) Represents sales from the Siloam facilities. The total sales exclude approximately zero gallons and 20,900,000 gallons sold by the Northeast on behalf of Liberty for the three months ended June 30, 2012 and 2011, respectively and zero gallons and 41,500,000 gallons sold for the six months ended June 30, 2012 and 2011, respectively. These volumes are included as part of NGLs sold at Liberty.

(6) Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility.

(7) Includes sale of all purity products fractionated at the Liberty facilities and sale of all unfractionated NGLs. Also includes the sale of purity products fractionated and sold from the Siloam facilities on behalf of Liberty.

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.

Our 2012 capital plan is summarized in the table below (in millions):

							Actual
	2012 Full Year Plan						Six months ended
	Low			High			June 30, 2012
Consolidated growth capital (1)	$	1,350		$	1,800		$	572
Utica joint venture partner’s estimated share of growth capital	(250		)	(300		)	—
Partnership share of growth capital	1,100			1,500			572
Acquisition (2)	510			510			510
Partnership share of growth capital and acquisitions	$	1,610		$	2,010		$	1,082
Consolidated maintenance capital (1)	$	20		$	20		$	10

(1) 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.

(2) As discussed in Note 3 to the accompanying Condensed Consolidated Financial Statements, MarkWest Liberty Midstream and its wholly owned subsidiary acquired Keystone for a purchase price of approximately $509.6 million.

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, contributions from our MarkWest Utica EMG joint venture partner, our Credit Facility and access to both the debt and equity capital markets, public and private. We will also consider the use of alternative financing strategies such as entering into additional joint venture arrangements.

Management believes that expenditures for our currently planned capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partner for capital projects encompassed by MarkWest Utica EMG, our current borrowing capacity under the Credit Facility, additional long-term borrowings, and proceeds from equity or debt offerings. 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 30, 2012, our credit ratings were Ba2 with a Stable outlook by Moody’s Investors Service, BB with a Stable outlook by Standard & Poor’s, and BB with a Stable outlook by Fitch Ratings. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be

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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 29, 2012, we amended our Credit Facility to increase the borrowing capacity to $1.2 billion and extend the maturity date by one year to September 7, 2017, providing us with the additional financial flexibility to continue to execute our growth strategy. See Note 9 of the accompanying Notes to Condensed Consolidated Financial Statements included in Item 1of this Form 10-Q for further details of our Credit Facility.

Under the provisions of the Credit Facility, we are subject to a number of restrictions and covenants. As of June 30, 2012, 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 30, 2012, we had approximately $197.9 million of borrowings outstanding and approximately $21.6 million of letters of credit outstanding under the Credit Facility, leaving approximately $980.5 million available for borrowing.

The Credit Facility and indentures governing the Senior Notes limit our and our restricted subsidiaries’ activity and ability 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 our restricted subsidiaries to pay dividends or distributions, make loans or transfer property to us; engage in transactions with our affiliates; sell assets, including equity interests of our 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 participating bank group members from requiring margin calls. As of July 30, 2012, all of our derivative positions are with participating bank group members 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 13, 2012, we issued approximately 0.7 million units representing limited partner interests pursuant to the underwriters’ exercise of their option to purchase additional common units under the equity offering initiated in December 2011. The total net proceeds from the exercise of this option were approximately $38 million and were used to partially fund the Partnership’s ongoing capital expenditure program.

On March 16, 2012, we completed a public offering of approximately 6.8 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option. Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $388 million and were used to partially fund our ongoing capital expenditure program.

On May 14, 2012, we completed a public offering of 8.0 million newly issued common units representing limited partner interests. Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $427 million, which were used to partially fund the Keystone Acquisition.

Liquidity Risks and Uncertainties

Our ability to pay distributions to our unit holders, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance. That, in turn, will be affected by prevailing economic conditions in our industry, as well as financial, business and other factors, some of which are beyond our control.

Due to lower demand caused primarily by the recent mild winter NGL prices have declined significantly in 2012 compared to 2011 which has adversely impacted our liquidity and operating results and will continue to have an adverse impact if price declines are sustained.

Additionally, we execute a risk management strategy to mitigate our exposure to downward fluctuations in commodity prices. However, we primarily use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk. During the first six months of 2012, the correlation between the price of NGLs and crude oil has weakened significantly and as a result, our derivative financial instruments have not been as effective in offsetting the impact of NGL price declines. If the pricing relationship between crude oil and NGLs does not return to the historical correlation or continues to weaken, our derivative financial instruments will continue to be less effective.

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Cash Flow

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

	Six months ended June 30,
	2012			2011			Change
Net cash provided by operating activities	$	256,437		$	206,364		$	50,073
Net cash flows used in investing activities	(1,087,498		)	(462,049		)	(625,449		)
Net cash flows provided by financing activities	839,507			283,270			556,237

Net cash provided by operating activities increased primarily due to a $44.2 million increase in operating income, excluding derivative gains and losses, in our operating segments. The increase in cash provided by operating activities was also due to changes in working capital.

Net cash used in investing activities increased primarily due to the $506.8 million net cash spent for the Keystone Acquisition which occurred in the second quarter of 2012 and a $348.1 million increase in capital expenditures primarily related to our expansion of Liberty operations, partially offset by the $230.7 million Langley Acquisition which occurred in the first quarter of 2011.

Net cash provided by financing activities increased primarily due to a $714.7 million increase in proceeds from public equity offerings, partially offset by a $116.3 million decrease in net borrowings and a $55.0 million increase in distributions to unit holders.

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, 2012, our purchase obligations for the remainder of 2012 were $454.3 million compared to our 2012 obligations of $181.0 million as of December 31, 2011. The increase is due primarily to obligations related to the ongoing expansion in our Liberty segment. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

Effective July 2012, we amended our lease for our corporate offices in Denver, Colorado to include additional space and extend the term of the lease through 2024. The following table shows the increase in minimum future lease payments as of June 30, 2012 compared to the amount disclosed in Item 7 of the Form 10-K for the year ended December 31, 2011 (in thousands):

Payments Due by Period
Due in 2012	$	569
Due in 2013-2014	8,290
Due in 2015-2016	8,673
Thereafter	58,221
Total Obligation	$	75,753

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; risk management activities and derivative financial instruments; VIEs; and acquisitions.

There have not been any material changes during the six months ended June 30, 2012 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, 2011.

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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, 2012 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, 2011.

Outstanding Derivative Contracts

The following table provides information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at June 30, 2012, including the weighted average prices (“WAVG”):

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	3,340	$	78.77	$	99.77	$	1,099
2013	3,714	88.08		107.45		8,858
2014	734	95.36		114.81		3,252

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2012	7,273	$	86.74	$	1,082
2013	5,416	93.48		9,980
2014	965	96.59		2,980

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2012	16,493	$	4.25	$	(4,325	)
2013	1,453	4.66		(654		)

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, 2012, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	1,242	$	79.53	$	103.55	$	650

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2012	1,751	$	87.07	$	198
2013	1,304	94.32		2,756

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2012	14,226	$	6.02	$	(8,027	)
2013	9,793	5.34		(6,174		)
2014	4,249	5.69		(2,614		)

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Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013 (Jan-Mar, Oct-Dec)	36,885	$	1.29	$	2,517
2014 (Jan-Mar, Oct-Dec)	87,837	1.25		5,455

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	3,081	$	1.70	$	311
2014	3,885	1.67		412

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	8,512	$	1.61	$	1,041
2014	10,711	1.61		1,358

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	5,600	$	2.26	$	861
2014	7,106	2.32		1,331

Propane Fixed Physical	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Oct-Dec)	1,413	$	1.01	$	17
2013 (Jan-Mar)	3,000	1.02		37

The following tables provide information on the volume of MarkWest Liberty Midstream’s commodity derivative activity for positions related to long liquids price risk at June 30, 2012, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)	WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	702	90	$	109.06	$	866
2013	494	92	108.67		1,573

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Oct-Dec)	7,556	$	0.85	$	(14	)
2013 (Jan-Mar)	30,897	0.86		(68		)

Subsequent to June 30, 2012, we settled approximately 676 barrels per day of our crude oil derivative positions related to 2014 commodity price exposure prior to the contractual settlement date in order to take advantage of favorable crude oil prices at which we could settle these proxy hedges that are expected to be less effective. We plan to opportunistically enter into future NGL hedge transactions to manage the 2014 NGL price exposure. Upon early settlement, we received approximately $2.5 million.

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 gain (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, 2012, the estimated fair value of this contract was a liability of $74.3 million and the recorded value was a liability of $20.8 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 on 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, 2012 (in thousands):

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no significant changes to our risk factors as set forth in our Annual Report on form 10-K for the year ended December 31, 2011, except for the additional or updated risk factors below:

Recently approved final rules regulating air emissions from natural gas processing operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the EPA approved final rules that establish new air emission controls for natural gas and NGLs production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities. Among other things, the rules establish specific requirements regarding emissions from compressors and controllers at natural gas gathering and boosting stations and processing plants together with dehydrators and storage tanks at natural gas processing plants, compressor stations and gathering and boosting stations. In addition, the rules establish new requirements for leak detection and repair of leaks at natural gas processing plants that exceed 500 parts per million in concentration. We are currently reviewing this new rule and assessing its potential impacts. Compliance with these requirements may require modifications to certain of our operations, including the installation of new equipment to control emissions from our compressors that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

Our commodity derivative activities may reduce our earnings, profitability and cash flows.

Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices.

The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel requirements and, as a result, we expect to continue to have some direct commodity price exposure. Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to settle all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which could result in a substantial diminution of our liquidity. Alternatively, we may seek to amend the terms of our derivative financial instruments, including to extend the settlement date of such instruments. Additionally, because we use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk, the volatility of our future cash flows and net income may increase if there is a change in the pricing relationship between crude oil and NGLs. As a result of these factors, our risk management activities may not be as effective as we intend in reducing the downside volatility of our cash flows and, in certain circumstances, may actually increase the volatility of our cash flows. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect and our risk management policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

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

Large accelerated filer x		Accelerated filer o

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

Bbl		Barrel
Bbl/d		Barrels per day
Bcf/d		Billion cubic feet per day
Btu		One British thermal unit, an energy measurement
Credit Facility		Amended and restated revolving credit agreement
DER		Distribution equivalent right
Dth/d		Dekatherms per day
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas south zone (around the clock)
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
Mcf		One thousand cubic feet of natural gas
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
VIE		Variable interest entity
WTI		West Texas Intermediate

PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements	4
	Unaudited Condensed Consolidated Balance Sheets at June 30, 2012 and December 31, 2011	4
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2012 and 2011	5
	Unaudited Condensed Consolidated Statements of Changes in Equity for the six months ended June 30, 2012 and 2011	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2012 and 2011	7
	Unaudited Notes to the Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	51
Item 4.	Controls and Procedures	53

PART II—OTHER INFORMATION		54
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 6.	Exhibits	55
SIGNATURES		56

2.1*+		Agreement and Plan of Merger dated as of May 7, 2012 among Keystone Midstream Services, L.L.C., R.E. Gas Development, L.L.C., Stonehenge Energy Resources, L.P., Summit Discovery Resources II, L.L.C., MarkWest Liberty Midstream & Resources, L.L.C., MarkWest Liberty Bluestone, L.L.C. and KMS Shareholder Representative, L.L.C.

10.2(1)		Third Amendment to Amended and Restated Credit Agreement dated as of June 29, 2012, among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto.

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, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Statements of Changes in Equity, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

	MarkWest Energy Partners, L.P. (Registrant)

	By:	MarkWest Energy GP, L.L.C.,
		Its General Partner


Date: August 6, 2012	/s/ FRANK M. SEMPLE
	Frank M. Semple
	Chairman, President & Chief Executive Officer
	(Principal Executive Officer)


Date: August 6, 2012	/s/ NANCY K. BUESE
	Nancy K. Buese
	Senior Vice President & Chief Financial Officer
	(Principal Financial Officer)


Date: August 6, 2012	/s/ PAULA L. ROSSON
	Paula L. Rosson
	Vice President & Chief Accounting Officer
	(Principal Accounting Officer)