Glossary of Terms

Bbl		Barrel
Bbl/d		Barrels per day
Bcf/d		Billion cubic feet per day
Btu		One British thermal unit, an energy measurement
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
IFRS		International Financial Reporting Standards
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, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss)
NGL		Natural gas liquids, such as ethane, propane, butanes and natural gasoline
N/A		Not applicable
OTC		Over-the-Counter
SEC		Securities and Exchange Commission
SMR		Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation facility in Corpus Christi, Texas
VIE		Variable interest entity
WTI		West Texas Intermediate

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	March 31, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents ($2,460 and $2,684, respectively)	$	350,634		$	117,016
Restricted cash	25,238			26,193
Receivables, net ($1,540 and $1,569, respectively)	197,115			226,561
Inventories	17,205			41,006
Fair value of derivative instruments	3,797			8,698
Deferred income taxes	14,885			14,885
Other current assets ($122 and $169, respectively)	8,197			11,748
Total current assets	617,071			446,107

Property, plant and equipment ($161,716 and $156,808, respectively)	3,568,459			3,302,369
Less: accumulated depreciation ($17,115 and $15,551, respectively)	(478,771		)	(438,062		)
Total property, plant and equipment, net	3,089,688			2,864,307

Other long-term assets:
Investment in unconsolidated affiliate	26,944			27,853
Intangibles, net of accumulated amortization of $179,153 and $168,168, respectively	592,782			603,767
Goodwill	67,918			67,918
Deferred financing costs, net of accumulated amortization of $14,462 and $13,194, respectively	40,530			41,798
Deferred contract cost, net of accumulated amortization of $2,340 and $2,262, respectively	910			988
Fair value of derivative instruments	8,270			16,092
Other long-term assets ($102 and $102, respectively)	1,534			1,595
Total assets	$	4,445,647		$	4,070,425

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($140 and $96, respectively)	$	182,149		$	179,871
Accrued liabilities ($1,898 and $1,144, respectively)	215,930			171,451
Fair value of derivative instruments	105,648			90,551
Total current liabilities	503,727			441,873

Deferred income taxes	99,783			93,664
Fair value of derivative instruments	85,800			65,403
Long-term debt, net of discounts of $1,021 and $1,050, respectively	1,780,091			1,846,062
Other long-term liabilities ($75 and $73, respectively)	123,945			121,356

Commitments and contingencies (Note 9)

Equity:
Common units (102,694 and 94,940 common units issued and outstanding, respectively)	1,030,497			679,309
Class B units (19,954 units issued and outstanding)	752,531			752,531
Non-controlling interest in consolidated subsidiaries	69,273			70,227

Total equity	1,852,301			1,502,067
Total liabilities and equity	$	4,445,647		$	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 March 31,
	2012			2011
Revenue:
Revenue	$	399,181		$	348,900
Derivative loss	(48,715		)	(85,679		)
Total revenue	350,466			263,221

Operating expenses:
Purchased product costs	154,555			153,629
Derivative loss related to purchased product costs	18,800			19,394
Facility expenses	48,840			39,424
Derivative gain related to facility expenses	(1,746		)	(3,011		)
Selling, general and administrative expenses	25,224			21,712
Depreciation	41,145			34,364
Amortization of intangible assets	10,985			10,817
Loss on disposal of property, plant and equipment	986			2,099
Accretion of asset retirement obligations	238			87
Total operating expenses	299,027			278,515

Income (loss) from operations	51,439			(15,294		)

Other income (expense):
Loss from unconsolidated affiliate	(9		)	(539		)
Interest income	72			89
Interest expense	(29,472		)	(28,263		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,270		)	(1,428		)
Loss on redemption of debt	—			(43,328		)
Miscellaneous income (expense), net	58			(38		)
Income (loss) before provision for income tax	20,818			(88,801		)

Provision for income tax expense (benefit):
Current	15,341			56
Deferred	(10,796		)	(14,186		)
Total provision for income tax	4,545			(14,130		)

Net income (loss)	16,273			(74,671		)

Net income attributable to non-controlling interest	(253		)	(9,358		)

Net income (loss) attributable to the Partnership	$	16,020		$	(84,029	)

Net income (loss) attributable to the Partnership’s common unitholders per common unit (Note 11):
Basic	$	0.16		$	(1.13	)
Diluted	$	0.14		$	(1.13	)

Weighted average number of outstanding common units:
Basic	96,840			74,531
Diluted	117,593			74,531

Cash distribution declared per common unit	$	0.76		$	0.65

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	7,508	425,629			—	—		—			425,629
Distributions paid	—	(73,410		)	—	—		(1,962		)	(75,372		)
Contributions from non-controlling interest	—	—			—	—		755			755
Share-based compensation activity	246	(2,343		)	—	—		—			(2,343		)
Excess tax benefits related to share-based compensation	—	2,207			—	—		—			2,207
Deferred income tax impact from changes in equity	—	(16,915		)	—	—		—			(16,915		)
Net income	—	16,020			—	—		253			16,273
March 31, 2012	102,694	$	1,030,497		19,954	$	752,531	$	69,273		$	1,852,301

	Common Units				Non-controlling
	Units	Amounts			Interest			Total
December 31, 2010	71,440	$	993,049		$	465,517		$	1,458,566
Share-based compensation activity	270	314			—			314
Excess tax benefits related to share-based compensation	—	1,096			—			1,096
Distributions paid	—	(49,274		)	(13,568		)	(62,842		)
Issuance of units in public offering, net of offering costs	3,450	138,163			—			138,163
Contributions to MarkWest Liberty Midstream joint venture	—	—			8,000			8,000
Net (loss) income	—	(84,029		)	9,358			(74,671		)
March 31, 2011	75,160	$	999,319		$	469,307		$	1,468,626

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)

	Three months ended March 31,
	2012			2011
Cash flows from operating activities:
Net income (loss)	$	16,273		$	(74,671	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	41,145			34,364
Amortization of intangible assets	10,985			10,817
Loss on redemption of debt	—			43,328
Amortization of deferred financing costs and discount	1,270			1,428
Accretion of asset retirement obligations	238			87
Amortization of deferred contract cost	78			78
Phantom unit compensation expense	5,709			5,636
Equity in loss of unconsolidated affiliate	9			539
Distributions from unconsolidated affiliate	900			—
Unrealized loss on derivative instruments	48,217			80,829
Loss on disposal of property, plant and equipment	986			2,099
Deferred income taxes	(10,796		)	(14,186		)
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	30,279			13,751
Inventories	23,812			9,148
Other current assets	3,503			(2,658		)
Accounts payable and accrued liabilities	32,556			(3,024		)
Other long-term assets	61			(372		)
Other long-term liabilities	2,688			8,126
Net cash provided by operating activities	207,913			115,319

Cash flows from investing activities:
Restricted cash	1,003			—
Capital expenditures	(254,263		)	(113,652		)
Acquisition of business	—			(230,728		)
Proceeds from disposal of property, plant and equipment	291			2,759
Net cash flows used in investing activities	(252,969		)	(341,621		)

Cash flows from financing activities:
Proceeds from public equity offering, net	425,629			138,163
Proceeds from revolving credit facility	13,700			307,600
Payments of revolving credit facility	(79,700		)	(168,400		)
Proceeds from long-term debt	—			499,000
Payments of long-term debt	—			(437,848		)
Payments of premiums on redemption of long-term debt	—			(39,520		)
Payments for debt issuance costs, deferred financing costs and registration costs	—			(6,524		)
Contributions from non-controlling interest	755			8,000
Payments of SMR liability	(497		)	(452		)
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	(73,410		)	(49,274		)
Payment of distributions to non-controlling interest	(1,962		)	(13,568		)
Net cash flows provided by financing activities	278,674			232,004

Net increase in cash and cash equivalents	233,618			5,702
Cash and cash equivalents at beginning of year	117,016			67,450
Cash and cash equivalents at end of period	$	350,634		$	73,152

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 months ended March 31, 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. (“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 3). 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 5, 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 was 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 the additional disclosures, the adoption of the amended guidance is not expected to have a material effect on the Partnership’s consolidated financial statements.

3. 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,

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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 would be made in accordance with those adjusted membership interests. Following the First Equalization Date, the Partnership shall have the right to elect to continue to fund up to 100% of any additional capital required until such time as the investment balances of the Partnership and EMG Utica are in the ratio of 70% and 30%, respectively (such time being referred to as the “Second Equalization Date”). To the extent the Partnership does not fully exercise such right at any time prior to the Second Equalization Date, EMG Utica shall have the right, but not the obligation, to contribute such additional capital that is requested and that is not contributed by the Partnership. After the Second Equalization Date, EMG Utica shall have the right, but not the obligation, to maintain a 30% interest in MarkWest Utica EMG by funding 30% of any additional required capital.

The Partnership has determined that MarkWest Utica EMG is a VIE primarily due to the Partnership’s disproportionate economic interests as compared to its stated ownership interests and voting interests. The Partnership’s 60% ownership interest in the entity is disproportionate to its economic interest due to the timing of the capital funding requirements described above. The Partnership has concluded that it is the primary beneficiary of MarkWest Utica EMG based on its role as the operator and its right to receive benefits and absorb losses of MarkWest Utica EMG. The Partnership believes that its role as the operator along with its equity interests give it the power to direct the activities that most significantly affect the economic performance of MarkWest Utica EMG.

MarkWest Pioneer

MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline. The Partnership and Arkoma Pipeline Partners, LLC share the equity interests in MarkWest Pioneer equally (50% and 50%). As discussed in Note 4 in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011, the Partnership determined that MarkWest Pioneer is a VIE and the Partnership is the primary beneficiary.

Financial Statement Impact of VIEs

As the primary beneficiary of MarkWest Pioneer and MarkWest Utica EMG, the Partnership consolidates the entities and recognizes non-controlling interests. As of December 31, 2011, MarkWest Pioneer was the only VIE included in the Partnership’s condensed consolidated financial statements and its assets and liabilities are disclosed parenthetically on the accompanying Condensed Consolidated Balance Sheets. The following tables show the consolidated assets and liabilities attributable to VIEs, excluding intercompany balances, as of March 31, 2012 (in thousands):

	As of March 31, 2012
	MarkWest Pioneer		MarkWest Utica EMG		Total
ASSETS
Cash and cash equivalents	$	2,097	$	363	$	2,460
Receivables, net	1,540		—		1,540
Other current assets	122		—		122
Property, plant and equipment, net of accumulated depreciation of $17,114 and $1, respectively	140,721		3,880		144,601
Other long-term assets	102		—		102
Total assets	$	144,582	$	4,243	$	148,825

LIABILITIES
Accounts payable	$	104	$	36	$	140
Accrued liabilities	1,338		560		1,898
Other long-term liabilities	75		—		75
Total liabilities	$	1,517	$	596	$	2,113

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 7 and Note 13). 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

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the performance of the operating services. The Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the three months ended March 31, 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 12). The result of operations and cash flows for MarkWest Pioneer are not material to the Partnership. During the three months ended March 31, 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.

4. 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. The risk management policy does not allow for trading derivative contracts.

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

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

As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2014. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions 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 standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).

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

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As of March 31, 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	8,888,207
Natural Gas (MMBtu)	Long	14,301,553
NGLs (gal)	Short	36,896,028

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 March 31, 2012, the estimated fair value of this contract was a liability of $123.6 million and the recorded value was a liability of $70.1 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 March 31, 2012 (in thousands):

Fair value of commodity contract	$	123,573
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of March 31, 2012	$	70,066

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 March 31, 2012, the estimated fair value of this contract was an asset of $9.3 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):

Derivative instruments not designated as hedging instruments and their balance sheet location	Assets				Liabilities
	March 31, 2012		December 31, 2011		March 31, 2012			December 31, 2011
Commodity contracts(1)
Fair value of derivative instruments - current	$	3,797	$	8,698	$	(105,648	)	$	(90,551	)
Fair value of derivative instruments - long-term	8,270		16,092		(85,800		)	(65,403		)
Total	$	12,067	$	24,790	$	(191,448	)	$	(155,954	)

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

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Derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in income	Three months ended March 31,
	2012			2011
Revenue: Derivative loss
Realized loss	$	(10,478	)	$	(14,391	)
Unrealized loss	(38,237		)	(71,288		)
Total revenue: derivative loss	(48,715		)	(85,679		)

Derivative loss related to purchased product costs
Realized loss	(7,074		)	(7,887		)
Unrealized loss	(11,726		)	(11,507		)
Total derivative loss related to purchased product costs	(18,800		)	(19,394		)

Derivative gain related to facility expenses
Unrealized gain	1,746			3,011
Total loss	$	(65,769	)	$	(102,062	)

For the three months ended March 31, 2012 and 2011, the Realized loss—revenue includes amortization of premium payments of zero and $1.0 million, respectively.

5. Fair Value

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 4. The following table presents the derivative instruments carried at fair value as of March 31, 2012 and December 31, 2011 (in thousands):

As of March 31, 2012	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	583	$	(101,710	)
Significant unobservable inputs (Level 3)
Commodity contracts	2,222		(19,672		)
Embedded derivatives in commodity contracts	9,262		(70,066		)
Total carrying value in Condensed Consolidated Balance Sheet	$	12,067	$	(191,448	)

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 March 31, 2012:

Level 3 Instrument	Balance Sheet Classification	Valuation Technique	Unobservable Inputs	Value Range (2)(3)(4)			Time Period
Commodity contracts	Assets	Market approach	Forward propane prices (per gallon)	$1.23	-	$1.33	Jan. 2013 - Dec. 2014

			Forward natural gasoline prices (per gallon)	$2.18	-	$2.38	Jan. 2013 - Dec. 2014

			Crude option volatilities (%)	14.80 %	-	37.42%	Apr. 2012 - Dec. 2014

	Liabilities	Market approach	Forward propane prices (per gallon)	$1.23	-	$1.33	Jan. 2013 - Dec. 2014

			Forward isobutane prices (per gallon)	$1.76	-	$2.05	Jan. 2013 - Dec. 2014

			Forward normal butane prices (per gallon)	$1.68	-	$1.90	Jan. 2013 - Dec. 2014

			Forward natural gasoline prices (per gallon)	$2.18	-	$2.38	Jan. 2013 - Dec. 2014

			Crude option volatilities (%)	14.80 %	-	37.42%	Apr. 2012 - Dec. 2013

Embedded derivatives in commodity contracts	Liability	Market Approach	Forward propane prices (per gallon)	$1.16	-	$1.33	Apr. 2012 - Dec. 2022

			Forward isobutane prices (per gallon)	$1.64	-	$2.05	Apr. 2012 - Dec. 2022

			Forward normal butane prices (per gallon)	$1.58	-	$1.90	Apr. 2012 - Dec. 2022

			Forward natural gasoline prices (per gallon)	$2.05	-	$2.38	Apr. 2012 - Dec. 2022

			Forward natural gas prices (per mmbtu)	$2.16	-	$6.36	Apr. 2012 - Dec. 2022

			Probability of renewal (1)		0 %

	Asset	Market Approach	ERCOT Pricing (per MegaWatt Hour)	$22.74	-	$66.30	Apr. 2012 - Dec. 2014

(1)

The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of years until the renewal options are exercisable and the high level of uncertainty regarding the counterparty’s future business strategy, the future commodity price environment, and the future competitive environment for midstream services in the Appalachia area, management determined that a 0% probability of renewal is an appropriate assumption.

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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 months ended March 31, 2012 and 2011 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

	Three months ended March 31, 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)	(12,076		)	(10,438		)
Settlements	(2,409		)	3,538
Fair value at end of period	$	(17,450	)	$	(60,804	)

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)	$	(14,050	)	$	(10,620	)

	Three months ended March 31, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(14,357	)	$	(34,936	)
Total loss (realized and unrealized) included in earnings (1)	(22,993		)	(19,280		)
Settlements	1,444			3,609
Fair value at end of period	$	(35,906	)	$	(50,607	)

The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	(22,779	)	$	(18,692	)

(1) Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Derivative loss related to revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs, Derivative loss related to purchased product costs and Derivative gain related to facility expenses.

6. Inventories

Inventories consist of the following (in thousands):

	March 31, 2012		December 31, 2011
NGLs	$	7,359	$	32,352
Spare parts, materials and supplies	9,846		8,654
Total inventories	$	17,205	$	41,006

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7. Long-Term Debt

Debt is summarized below (in thousands):

	March 31, 2012		December 31, 2011
Credit Facility
Revolving credit facility, 4.25% interest, due September 2016	$	—	$	66,000

Senior Notes (1)
2018 Senior Notes, 8.75% interest, net of discount of $124 and $129, respectively, issued April and May 2008 and due April 2018	80,988		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 $897 and $921, respectively, issued February and March 2011 and due August 2021	499,103		499,079
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022	700,000		700,000
Total long-term debt	$	1,780,091	$	1,846,062

(1) The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $1,895.1 million and $1,880.7 million as of March 31, 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

Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by the Partnership’s wholly-owned subsidiaries and collateralized by substantially all of the Partnership’s assets and those of its wholly-owned subsidiaries. As of March 31, 2012, the Partnership had $22.3 million of letters of credit outstanding under the Credit Facility and $877.7 million available for borrowing.

8. Equity

Equity Offerings

In January 2012, the Partnership issued approximately 0.7 million units 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 will be 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 will be used to partially fund the Partnership’s ongoing capital expenditure program.

Distributions of Available Cash

Quarter Ended	Distribution Per Common Unit		Declaration Date	Record Date	Payment Date
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

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9. Commitments and Contingencies

Legal

The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Partnership maintains insurance policies in amounts and with coverage and deductibles as it believes reasonable and prudent. However, the Partnership cannot assure that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect the Partnership from all material expenses related to future claims for property loss or business interruption to the Partnership, or for third-party claims of personal and property damage, or that the coverages or levels of insurance it currently has will be available in the future at economical prices. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the 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 of 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 but those delays exacerbated construction conditions. In addition, the Partnership has continued to experience extraordinary weather events which have resulted in additional delays. Delay charges for delays other than due to force majeure events are up to $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 for other than 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 is also developing solutions to provide alternative processing capabilities for its customers to mitigate the impact of these delays.

10. 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 three months ended March 31, 2012 and 2011 is as follows (in thousands):

	Three months ended March 31, 2012
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	7,525		$	14,097		$	(804	)	$	20,818
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	2,634			—			—			2,634
Permanent items	4			—			—			4
State income taxes net of federal benefit	339			66			—			405
Provision on income from Class A units (1)	1,502			—			—			1,502
Provision for income tax	$	4,479		$	66		$	—		$	4,545

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

(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.

11. Earnings (Loss) Per Common Unit

The following table shows the computation of basic and diluted net income (loss) per common unit for the three months ended March 31, 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 March 31,
	2012		2011
Net income (loss) attributable to the Partnership	$	16,020	$	(84,029	)
Less: Income allocable to phantom units	520		420
Income (loss) available for common unitholders - basic	15,500		(84,449		)
Add: Income allocable to phantom units and DER expense	535		—
Income (loss) available for common unitholders - diluted	$	16,035	$	(84,449	)

Weighted average common units outstanding — basic	96,840		74,531
Potential common shares (Class B and phantom units)	20,753		—
Weighted average common units outstanding — diluted	117,593		74,531

Net income (loss) attributable to the Partnership’s common unitholders per common unit (1)
Basic	$	0.16	$	(1.13	)
Diluted	$	0.14	$	(1.13	)

(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.

12. 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, and capital expenditures for the reported segments for the three months ended March 31, 2012 and 2011 (in thousands).

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Three months ended March 31, 2012:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	214,725	$	86,918	$	75,577	$	24,229	$	401,449
Purchased product costs	104,233		25,687		24,635		—		154,555
Net operating margin	110,492		61,231		50,942		24,229		246,894
Facility expenses	22,992		6,378		12,247		9,638		51,255
Portion of operating income attributable to non-controlling interests	1,446		—		—		—		1,446
Operating income before items not allocated to segments	$	86,054	$	54,853	$	38,695	$	14,591	$	194,193

Capital expenditures	$	48,040	$	23,302	$	178,689	$	2,543	$	252,574
Capital expenditures not allocated to segments									1,689
Total capital expenditures									$	254,263

Three months ended March 31, 2011:

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

Capital expenditures	$	17,156	$	709	$	94,146	$	294	$	112,305
Capital expenditures not allocated to segments									1,347
Total capital expenditures									$	113,652

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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 three months ended March 31, 2012 and 2011 (in thousands):

	Three months ended March 31,
	2012			2011

Total segment revenue	$	401,449		$	356,843
Derivative loss not allocated to segments	(48,715		)	(85,679		)
Revenue deferral adjustment (1)	(2,268		)	(7,943		)
Total revenue	$	350,466		$	263,221

Operating income before items not allocated to segments	$	194,193		$	148,426
Portion of operating income attributable to non-controlling interests	1,446			13,549
Derivative loss not allocated to segments	(65,769		)	(102,062		)
Revenue deferral adjustment (1)	(2,268		)	(7,943		)
Compensation expense included in facility expenses not allocated to segments	(449		)	(1,040		)
Facility expenses adjustments (2)	2,864			2,855
Selling, general and administrative expenses	(25,224		)	(21,712		)
Depreciation	(41,145		)	(34,364		)
Amortization of intangible assets	(10,985		)	(10,817		)
Loss on disposal of property, plant and equipment	(986		)	(2,099		)
Accretion of asset retirement obligations	(238		)	(87		)
Income (loss) from operations	51,439			(15,294		)

Loss from unconsolidated affiliate	(9		)	(539		)
Interest income	72			89
Interest expense	(29,472		)	(28,263		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,270		)	(1,428		)
Loss on redemption of debt	—			(43,328		)
Miscellaneous income (expense), net	58			(38		)
Income (loss) before provision for income tax	$	20,818		$	(88,801	)

(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 three months ended March 31, 2012, approximately $0.2 million and $2.1 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the three months ended March 31, 2011, approximately $6.5 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

(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.

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

	March 31, 2012		December 31, 2011
Southwest	$	1,693,321	$	1,701,919
Northeast	498,185		533,591
Liberty	1,279,066		1,114,654
Gulf Coast	551,313		553,043
Total segment assets	4,021,885		3,903,207
Assets not allocated to segments:
Certain cash and cash equivalents	342,684		66,212
Fair value of derivatives	12,067		24,790
Investment in unconsolidated affiliate	26,944		27,853
Other (1)	42,067		48,363
Total assets	$	4,445,647	$	4,070,425

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

13. Supplemental Condensed Consolidating Financial Information

The Partnership has no operations independent of its subsidiaries. As of March 31, 2012, the Partnership’s obligations under the outstanding Senior Notes (see Note 7) were fully, jointly and severally guaranteed, by all of its wholly-owned subsidiaries other than MarkWest Liberty Midstream. 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 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 March 31, 2012 and December 31, 2011 and for the three months ended March 31, 2012 and 2011 is as follows (in thousands):

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Condensed Consolidating Balance Sheets

	As of March 31, 2012
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	270,022	$	77,759	$	2,853	$	—		$	350,634
Restricted cash	—		—		25,238		—			25,238
Receivables and other current assets	7,401		187,646		42,355		—			237,402
Intercompany receivables	30,017		12,597		12,159		(54,773		)	—
Fair value of derivative instruments	—		3,797		—		—			3,797
Total current assets	307,440		281,799		82,605		(54,773		)	617,071

Total property, plant and equipment, net	3,915		1,771,460		1,334,520		(20,207		)	3,089,688

Other long-term assets:
Investment in unconsolidated affiliate	—		26,944		—		—			26,944
Investment in consolidated affiliates	3,109,581		1,185,801		—		(4,295,382		)	—
Intangibles, net of accumulated amortization	—		592,248		534		—			592,782
Fair value of derivative instruments	—		8,270		—		—			8,270
Intercompany notes receivable	184,300		—		—		(184,300		)	—
Other long-term assets	40,231		70,314		347		—			110,892
Total assets (1)	$	3,645,467	$	3,936,836	$	1,418,006	$	(4,554,662	)	$	4,445,647

LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	12,506	$	36,887	$	5,380	$	(54,773	)	$	—
Fair value of derivative instruments	—		105,065		583		—			105,648
Other current liabilities	45,821		218,921		133,337		—			398,079
Total current liabilities	58,327		360,873		139,300		(54,773		)	503,727

Deferred income taxes	660		99,123		—		—			99,783
Intercompany notes payable	—		161,300		23,000		(184,300		)	—
Fair value of derivative instruments	—		85,576		224		—			85,800
Long-term debt, net of discounts	1,780,091		—		—		—			1,780,091
Other long-term liabilities	3,154		120,383		408		—			123,945

Equity:
Common units	1,050,704		3,109,581		1,255,074		(4,384,862		)	1,030,497
Class B units	752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries	—		—		—		69,273			69,273
Total equity	1,803,235		3,109,581		1,255,074		(4,315,589		)	1,852,301
Total liabilities and equity	$	3,645,467	$	3,936,836	$	1,418,006	$	(4,554,662	)	$	4,445,647

(1) In accordance with the December 2011 amendment to the Partnership’s Credit Facility, certain assets in the Liberty segment included in Total property, plant, and equipment, net were contributed from a non-guarantor subsidiary to a guarantor subsidiary in April 2012. The contributed assets, with a net book value of approximately $105 million, include only the natural gas processing facilities at the Partnership’s Houston Complex and other equipment related solely to these processing facilities.

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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
Intercompany notes 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 March 31, 2012
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	271,071		$	79,395		$	—		$	350,466
Operating expenses:
Purchased product costs	—			148,601			24,754			—			173,355
Facility expenses	—			33,936			13,334			(176		)	47,094
Selling, general and administrative expenses	14,417			9,048			3,131			(1,372		)	25,224
Depreciation and amortization	164			39,293			12,911			(238		)	52,130
Other operating expenses	—			1,111			113			—			1,224
Total operating expenses	14,581			231,989			54,243			(1,786		)	299,027

(Loss) income from operations	(14,581		)	39,082			25,152			1,786			51,439

Earnings from consolidated affiliates	56,431			24,234			—			(80,665		)	—
Other expense, net	(23,344		)	(2,406		)	(665		)	(4,206		)	(30,621		)
Income before provision for income tax	18,506			60,910			24,487			(83,085		)	20,818
Provision for income tax expense	66			4,479			—			—			4,545
Net income	18,440			56,431			24,487			(83,085		)	16,273
Net income attributable to non-controlling interest	—			—			—			(253		)	(253		)
Net income attributable to the Partnership	$	18,440		$	56,431		$	24,487		$	(83,338	)	$	16,020

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

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Condensed Consolidating Statements of Cash Flows

	Three Months Ended March 31, 2012
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(27,744	)	$	149,912		$	88,402		$	(2,657	)	$	207,913

Cash flows from investing activities:
Restricted cash	—			—			1,003			—			1,003
Capital expenditures	(68		)	(91,090		)	(166,976		)	3,871			(254,263		)
Equity investments	(13,230		)	(66,356		)	—			79,586			—
Distributions from consolidated affiliates	16,496			2,139			—			(18,635		)	—
Collection of intercompany notes, net	51,400			—			—			(51,400		)	—
Proceeds from disposal of property, plant and equipment	—			1,505			—			(1,214		)	291
Net cash flows provided by (used in) investing activities	54,598			(153,802		)	(165,973		)	12,208			(252,969		)

Cash flows from financing activities:
Proceeds from public equity offering, net	425,629			—			—			—			425,629
Proceeds from revolving credit facility	13,700			—			—			—			13,700
Payments of revolving credit facility	(79,700		)	—			—			—			(79,700		)
Payments of intercompany notes, net	—			(51,400		)	—			51,400			—
Contributions from parent and affiliates	—			13,230			66,356			(79,586		)	—
Contribution from non-controlling interest	—			—			755			—			755
Payments of SMR liability	—			(497		)	—			—			(497		)
Share-based payment activity	(8,048		)	2,207			—			—			(5,841		)
Payment of distributions	(73,410		)	(16,496		)	(4,101		)	18,635			(75,372		)
Intercompany advances, net	(35,025		)	35,025			—			—			—
Net cash flows provided by (used in) financing activities	243,146			(17,931		)	63,010			(9,551		)	278,674

Net increase (decrease) in cash	270,000			(21,821		)	(14,561		)	—			233,618
Cash and cash equivalents at beginning of year	22			99,580			17,414			—			117,016
Cash and cash equivalents at end of period	$	270,022		$	77,759		$	2,853		$	—		$	350,634

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

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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 March 31, 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) increased approximately $45.8 million, or 31%, for the three months ended March 31, 2012 compared to the same period in 2011. The increase is due primarily to expanding operations in our Liberty segment and our acquisition of EMG’s interest in MarkWest Liberty Midstream. Additionally, we had an increase in processed volumes in our Southwest and Northeast segments.

· In January 2012, we received net proceeds of approximately $38 million from the sale of approximately 0.7 million newly issued common units representing limited partner interests, resulting from the exercise of the underwriters’ option to purchase additional common units under the equity offering initiated in December 2011.

· In March 2012, we received net proceeds of approximately $388 million from 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.

· Effective January 1, 2012, we and EMG Utica executed agreements to form MarkWest Utica EMG to develop significant natural gas processing and NGL fractionation, transportation and marketing infrastructure in the Utica Shale beginning in late-2012 (see Note 3 in the accompanying Notes to the Condensed Consolidated Financial Statements).

· In March 2012, we announced the execution of long-term gathering and processing agreements with Anadarko Petroleum Corporation that will support the 120 MMcf/d expansion of our cryogenic processing capacity in East Texas that is currently under construction. The expansion will provide critical midstream services to Anadarko and other producer customers that are expanding their drilling programs in East Texas. In addition, the expansion will expand the Partnership’s gathering capacity in East Texas by 140 MMcf/d and residue gas outlet capacities by 60 MMcf/d.

· In January 2012, we announced a 400 MMcf/d expansion of our processing facilities in Majorsville, West Virginia (“Majorsville Complex”) that is supported by long-term processing agreements with CONSOL Energy, Noble Energy and Range Resources.

· 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 described above, 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 facility 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 Sherwood Complex.

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 12 to the accompanying condensed consolidated financial statements and are considered non-GAAP financial measures when presented outside of the notes to

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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 12 to the accompanying condensed consolidated financial statements for the reconciliations of segment revenue and operating income before items not allocated to segments to the respective most comparable GAAP measure.

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

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 March 31,
	2012			2011
Segment revenue	$	401,449		$	356,843
Purchased product costs	(154,555		)	(153,629		)
Net operating margin	246,894			203,214
Facility expenses	(48,840		)	(39,424		)
Derivative loss	(65,769		)	(102,062		)
Revenue deferral adjustment	(2,268		)	(7,943		)
Selling, general and administrative expenses	(25,224		)	(21,712		)
Depreciation	(41,145		)	(34,364		)
Amortization of intangible assets	(10,985		)	(10,817		)
Loss on disposal of property, plant and equipment	(986		)	(2,099		)
Accretion of asset retirement obligations	(238		)	(87		)
Income (loss) from operations	$	51,439		$	(15,294	)

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 three months ended March 31, 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	24	%	35	%	2	%	39	%
Net operating margin (4)	39	%	24	%	0	%	37	%

(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. Our access to over 60 million gallons of propane storage capacity provided by our own storage facilities and a firm capacity arrangement with a third party allows us to manage this seasonality. However, the mild winter this past year has resulted in constraints in available propane storage in the Northeast, which may present difficulties in securing adequate propane storage capacity until next winter. If we are unable to fully utilize our storage capacity due to third party capacity constraints or other reasons, our operations would be adversely affected. Also 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 12 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 another third-party processor. 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 3 of the accompanying Notes to Condensed Consolidated Financial Statements.

· 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 significant portion of the natural gas produced from fields adjacent to our gathering systems, including from wells targeting the Haynesville Shale. In many areas we are the primary gatherer, and in some of the areas served by our smaller systems we are the sole gatherer. Our Hobbs, New Mexico natural gas lateral pipeline is subject to regulation by FERC.

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Northeast

· Kentucky and southern West Virginia. Our Northeast segment assets include the Kenova, Boldman, Cobb, Kermit and the Langley natural gas processing plants, an NGL pipeline, and the Siloam NGL fractionation plant. We plan to complete an additional cryogenic natural gas processing plant with a capacity of 150 MMcf/d in the fourth quarter of 2012. In addition, we have two caverns for storing propane at our Siloam facility and additional propane storage capacity under a long-term firm-capacity agreement with a third party. Including our presence in the Marcellus Shale (see Liberty Segment below), we are the largest processor and fractionator of natural gas in the Northeast, with fully integrated processing, fractionation, storage and marketing operations.

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

Liberty

· Marcellus Shale. We provide extensive natural gas midstream services in southwestern Pennsylvania and northern West Virginia through MarkWest Liberty Midstream. With gathering capacity of 325 MMcf/d and current processing capacity of 625 MMcf/d, we are the largest processor of natural gas in the Marcellus Shale, with fully integrated gathering, processing, fractionation, storage and marketing operations that are critical to the liquids-rich gas development in the northeast United States.

The gathering, processing and fractionation facilities currently operating and under construction in our Liberty segment consist of the following:

Gathering

· Existing gathering system with the capacity to deliver 325 MMcf/d to our Houston Complex.

· Planned gathering system with the initial capacity to deliver 300 MMcf/d to our Sherwood Complex. The first phase of the gathering system will be operational in conjunction with the completion of the first processing plant at our Sherwood Complex in the third quarter of 2012.

Processing

· 355 MMcf/d of current cryogenic processing capacity at our Houston, Pennsylvania processing complex (“Houston Complex”).

· 270 MMcf/d of current cryogenic processing capacity at our Majorsville, West Virginia processing complex (“Majorsville Complex”).

· 800 MMcf/d expansion of our Majorsville Complex that is supported by long-term agreements with Chesapeake Energy, CONSOL Energy, Noble Energy and Range Resources. The Majorsville expansion includes four, 200 MMcf/d processing plants that are expected to commence operation in 2013 and 2014 and will bring our total cryogenic processing capacity at Majorsville to approximately 1.1 Bcf/d.

· 320 MMcf/d cryogenic processing capacity under construction in Mobley, West Virginia (“Mobley Complex”) where 120 MMcf/d and 200 MMcf/d cryogenic plants are expected to be completed in the second half of 2012.

· 200 MMcf/d cryogenic processing capacity under construction at our Sherwood Complex that is expected to be completed in the third quarter of 2012. We plan to expand the capacity at our Sherwood Complex with an additional 200 MMcf/d cryogenic processing plant that is expected to be completed in 2013. The expansion plans are based, in part, on Antero’s decision to support the additional capacity under a long-term processing agreement. Antero has publicly stated its intent to move forward with the project but must make its final decision on whether to proceed with the additional plant at the Sherwood Complex by July 1, 2012.

By the end of 2014, MarkWest Liberty Midstream is expected to have 2.1 Bcf/d of cryogenic processing capacity that is supported by long-term agreements with our producer customers. NGLs produced at the Majorsville Complex are delivered through an NGL pipeline (“Majorsville Pipeline”) to the Houston Complex for exchange for fractionated products. We also plan to complete an NGL pipeline connecting each of the planned processing facilities to the Majorsville Pipeline allowing for fractionation at the Houston Complex. By the end of 2012, MarkWest Liberty Midstream expects to have approximately 100 miles of NGL transportation pipeline.

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Both processing complexes are expected to be connected via an NGL pipeline system to the fractionation facilities at the Harrison Complex that is expected to be operational in 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 producers with the same benefits. Additionally, the Harrison Complex fractionation facilities, 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 Northeastern United States.

On March 6, 2012, MarkWest Utica EMG announced the execution of a letter of intent (“LOI”) 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 LOI, which requires the execution of definitive agreements, MarkWest Utica EMG plans to develop extensive natural gas gathering infrastructure with Gulfport and other producers, primarily in Harrison, Guernsey, and Belmont Counties, that is expected to commence initial operations beginning in 2012. MarkWest Utica EMG plans to process the gas at its Harrison Complex, and is expected to provide NGL fractionation and marketing services at the Harrison Complex’s fractionation facilities when they are 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 three months ended March 31, 2012:

	Southwest		Northeast		Liberty		Gulf Coast
Segment revenue	53	%	22	%	19	%	6	%
Net operating margin	44	%	25	%	21	%	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 segments. Management does not consider these items allocable to or controllable by any individual business segment and therefore excludes these items when evaluating segment performance. The segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests. The tables below present financial information, as evaluated by management, for the reported segments for the three months ended March 31, 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.

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Three months ended March 31, 2012 compared to three months ended March 31, 2011

Southwest

	Three months ended March 31,
	2012		2011		$ Change		% Change
	(in thousands)
Segment revenue	$	214,725	$	201,774	$	12,951	6	%
Purchased product costs	104,233		103,196		1,037		1	%
Net operating margin	110,492		98,578		11,914		12	%
Facility expenses	22,992		20,157		2,835		14	%
Portion of operating income attributable to non-controlling interests	1,446		1,172		274		23	%
Operating income before items not allocated to segments	$	86,054	$	77,249	$	8,805	11	%

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

Purchased Product Costs. Although the volumes of natural gas processed and NGLs sold increased, purchased product costs remained relatively consistent primarily due to a decrease in the price and volume of natural gas purchased.

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

Northeast

	Three months ended March 31,
	2012		2011		$ Change			% Change
	(in thousands)
Segment revenue	$	86,918	$	92,091	$	(5,173	)	(6	)%
Purchased product costs	25,687		40,878		(15,191		)	(37	)%
Net operating margin	61,231		51,213		10,018			20	%
Facility expenses	6,378		5,594		784			14	%
Operating income before items not allocated to segments	$	54,853	$	45,619	$	9,234		20	%

Segment Revenue. Revenue decreased primarily due to a contract change related to our acquisition of the Langley processing facilities and related assets (“Langley Acquisition”) in 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 purchase product costs. Prior to the contract change we were acting as the principal. The decrease in revenue was offset by increased volumes as a key transmission pipeline feeding our processing plants was damaged and had limited service capacity during the first quarter of 2011 but was repaired and fully operational for the entire first quarter of 2012.

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

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

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Liberty

	Three months ended March 31,
	2012		2011		$ Change			% Change
	(in thousands)
Segment revenue	$	75,577	$	41,219	$	34,358		83	%
Purchased product costs	24,635		9,555		15,080			158	%
Net operating margin	50,942		31,664		19,278			61	%
Facility expenses	12,247		6,498		5,749			88	%
Portion of operating income attributable to non-controlling interests	—		12,377		(12,377		)	(100	)%
Operating income before items not allocated to segments	$	38,695	$	12,789	$	25,906		203	%

Segment Revenue. Revenue increased due to ongoing expansion of the Liberty operations resulting in increased gathered and fractionated volumes and higher NGL prices. Revenue increased approximately $11.0 million related to gathering and processing fees and approximately $22.7 million related to NGL product sales.

Purchased Product Costs. Purchased product costs increased primarily due to increased NGL product sales.

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 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 income is attributable to non-controlling interests for the three months ended March 31, 2012.

Gulf Coast

	Three months ended March 31,
	2012		2011		$ Change		% Change
	(in thousands)
Segment revenue	$	24,229	$	21,759	$	2,470	11	%
Purchased product costs	—		—		—		N/A
Net operating margin	24,229		21,759		2,470		11	%
Facility expenses	9,638		8,990		648		7	%
Operating income before items not allocated to segments	$	14,591	$	12,769	$	1,822	14	%

Segment Revenue. Revenue increased primarily due to increased production as scheduled refinery maintenance in 2011 did not recur in 2012.

Facility Expenses. Facility expenses increased primarily due to the timing of 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 three months ended March 31, 2012 and 2011. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Three months ended March 31,
	2012			2011			$ Change			% Change
	(in thousands)
Total segment revenue	$	401,449		$	356,843		$	44,606		13	%
Derivative loss not allocated to segments	(48,715		)	(85,679		)	36,964			(43	)%
Revenue deferral adjustment	(2,268		)	(7,943		)	5,675			(71	)%
Total revenue	$	350,466		$	263,221		$	87,245		33	%

Operating income before items not allocated to segments	$	194,193		$	148,426		$	45,767		31	%
Portion of operating income attributable to non-controlling interests	1,446			13,549			(12,103		)	(89	)%
Derivative loss not allocated to segments	(65,769		)	(102,062		)	36,293			(36	)%
Revenue deferral adjustment	(2,268		)	(7,943		)	5,675			(71	)%
Compensation expense included in facility expenses not allocated to segments	(449		)	(1,040		)	591			(57	)%
Facility expenses adjustments	2,864			2,855			9			0	%
Selling, general and administrative expenses	(25,224		)	(21,712		)	(3,512		)	16	%
Depreciation	(41,145		)	(34,364		)	(6,781		)	20	%
Amortization of intangible assets	(10,985		)	(10,817		)	(168		)	2	%
Loss on disposal of property, plant and equipment	(986		)	(2,099		)	1,113			(53	)%
Accretion of asset retirement obligations	(238		)	(87		)	(151		)	174	%
Income (loss) from operations	51,439			(15,294		)	66,733			(436	)%

Loss from unconsolidated affiliate	(9		)	(539		)	530			(98	)%
Interest income	72			89			(17		)	(19	)%
Interest expense	(29,472		)	(28,263		)	(1,209		)	4	%
Amortization of deferred financing costs and discount (a component of interest expense)	(1,270		)	(1,428		)	158			(11	)%
Loss on redemption of debt	—			(43,328		)	43,328			(100	)%
Miscellaneous income (expense), net	58			(38		)	96			(253	)%
Income (loss) before provision for income tax	$	20,818		$	(88,801	)	$	109,619		(123	)%

Derivative Gain (Loss) Not Allocated to Segments. Unrealized gain from the mark-to-market of our derivative instruments was $48.2 million for the three months ended March 31, 2012 compared to an unrealized loss of $79.8 million for the same period in 2011. Realized loss from the settlement of our derivative instruments was $17.6 million for the three months ended March 31, 2012 compared to $22.3 million for the same period in 2011. The total change of $36.3 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 March 31, 2012, approximately $0.2 million and $2.1 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the three months ended March 31, 2011, approximately $6.5 million and $1.4 million of the revenue

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deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Based on current commodity prices, management expects the deferred revenue in subsequent periods to approximate the current quarter’s amount until the beginning of 2015 when the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

Selling, General and Administrative. 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 and the first quarter of 2012.

Interest Expense. Interest expense increased due to an increased amount of outstanding debt partially offset by lower interest rates and increased capitalized interest.

Loss on Redemption of Debt. The decrease in loss on redemption of debt was related to the redemption of debt which occurred in the first quarter of 2011, while no such redemptions of debt occurred during the first quarter of 2012.

Operating Data

	Three months ended March 31,
	2012	2011	% Change
Southwest
East Texas gathering systems throughput (Mcf/d)	410,000	425,800	(4	)%
East Texas natural gas processed (Mcf/d)	242,500	219,200	11	%
East Texas NGL sales (gallons, in thousands)	63,400	56,700	12	%

Western Oklahoma gathering system throughput (Mcf/d) (1)	262,000	207,400	26	%
Western Oklahoma natural gas processed (Mcf/d)	203,800	157,100	30	%
Western Oklahoma NGL sales (gallons, in thousands)	57,300	39,000	47	%

Southeast Oklahoma gathering systems throughput (Mcf/d)	501,200	498,000	1	%
Southeast Oklahoma natural gas processed (Mcf/d) (2)	101,700	93,700	9	%
Southeast Oklahoma NGL sales (gallons, in thousands)	33,000	29,400	12	%
Arkoma Connector Pipeline throughput (Mcf/d)	328,700	285,900	15	%

Other Southwest gathering system throughput (Mcf/d)	25,000	33,100	(24	)%

Northeast
Natural gas processed (Mcf/d) (3)	321,700	304,800	6	%
NGLs fractionated (Bbl/d) (4)	16,700	22,200	(25	)%

Keep-whole sales (gallons, in thousands)	49,500	39,800	24	%
Percent-of-proceeds sales (gallons, in thousands)	33,000	30,900	7	%
Total NGL sales (gallons, in thousands) (5)	82,500	70,700	17	%

Crude oil transported for a fee (Bbl/d)	10,400	10,200	2	%

Liberty
Natural gas processed (Mcf/d)	392,100	254,500	54	%
Gathering system throughput (Mcf/d)	308,100	195,900	57	%
NGLs fractionated (Bbl/d) (6)	20,000	6,900	190	%
NGL sales (gallons, in thousands) (7)	97,500	51,800	88	%

Gulf Coast
Refinery off-gas processed (Mcf/d)	120,300	102,800	17	%
Liquids fractionated (Bbl/d)	23,400	19,200	22	%
NGL sales (gallons excluding hydrogen, in thousands)	89,300	72,700	23	%

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(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 three months ended March 31, 2011 are the average daily rates for the days of operation.

(4) Amount includes zero barrels per day and 5,500 barrels per day fractionated on behalf of Liberty for the three months ended March 31, 2012 and 2011, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionated NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011.

(5) Represents sales from the Siloam facilities. The total sales exclude approximately zero gallons and 20,700,000 gallons sold by the Northeast on behalf of Liberty for the three months ended March 31, 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. In 2011, we spent approximately $782 million on acquisitions, growth capital projects, and maintenance capital, of which approximately $130 million was funded by our former MarkWest Liberty Midstream joint venture partner.

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

							Actual
	2012 Full Year Plan						Three months ended
	Low			High			March 31, 2012
Consolidated growth capital (1)	$	1,250		$	1,700		$	248
Utica joint venture partner’s estimated share of growth capital	(150		)	(200		)	—
Partnership share of growth capital	1,100			1,500			248
Acquisition (2)	512			512			—
Partnership share of growth capital and acquisitions	$	1,612		$	2,012		$	248
Consolidated maintenance capital (1)	$	20		$	20		$	6

(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 15 to the accompanying Condensed Consolidated Financial Statements, MarkWest Liberty Midstream and its wholly owned subsidiary entered into an agreement to acquire Keystone for a purchase price of approximately $512 million, subject to post-closing adjustments. The closing of the acquisition of Keystone is conditioned upon the termination or expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act and certain other customary closing conditions.

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.

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Management believes that expenditures for our currently planned capital projects and acquisition of Keystone 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 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 April 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 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

Under the provisions of the Credit Facility we are subject to a number of restrictions and covenants. As of March 31, 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 April 30, 2012, we had no borrowings outstanding and $22.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $877.7 million available for borrowing.

The Credit Facility and indentures governing the Senior Notes limit the activity of 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 April 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 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 will be 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.

Cash Flow

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

	Three months ended March 31,
	2012			2011			Change
Net cash provided by operating activities	$	207,913		$	115,319		$	92,594
Net cash flows used in investing activities	(252,969		)	(341,621		)	88,652
Net cash flows provided by financing activities	278,674			232,004			46,670

Net cash provided by operating activities increased primarily due to a $45.8 million increase in operating income, excluding derivative gains and losses, in our operating segments. The increase in operating income was also due to increases in operating cash flow resulting from changes in working capital.

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Net cash used in investing activities decreased primarily due to the $230.7 million Langley Acquisition which occurred in the first quarter of 2011, partially offset by a $140.6 million increase in capital expenditures.

Net cash provided by financing activities increased primarily due to a $287.5 million increase in proceeds from public offerings and a decrease in premiums paid to redeem senior notes, partially offset by a $266.3 million decrease in net borrowings.

Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of March 31, 2012, our purchase obligations for the remainder of 2012 were $413.5 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.

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 three months ended March 31, 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.

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 three months ended March 31, 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 March 31, 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	3,330	$	78.72	$	99.74	$	(8,494	)
2013	3,714	88.08		107.45		(5,077		)
2014	734	95.36		114.81		1,146

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WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2012	7,858	$	86.81	$	(37,799	)
2013	5,461	93.54		(19,264		)
2014	1,773	97.08		(1,085		)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2012	17,118	$	4.15	$	(8,574	)
2013	1,453	4.66		(731		)

The following tables provide information on the volume of our taxable subsidiary’s commodity derivative activity for positions related to keep-whole price risk at March 31, 2012, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	1,116	$	78.41	$	101.97	$	(2,630	)

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2012	1,441	$	87.11	$	(6,901	)
2013	1,304	94.32		(4,174		)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2012	14,322	$	5.93	$	(13,338	)
2013	9,793	5.34		(6,581		)
2014	4,249	5.69		(2,681		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013 (Jan-Mar, Oct-Dec)	36,885	$	1.29	$	(102	)
2014 (Jan-Mar, Oct-Dec)	87,837	$	1.25	$	(425	)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	3,081	$	1.70	$	(233	)
2014	3,885	$	1.67	$	(163	)

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)	Fair Value (in thousands)
2013	8,512	1.61	(495	)
2014	10,711	1.61	(356	)

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)	Fair Value (in thousands)
2013	5,600	2.26	(75	)
2014	7,106	2.32	262

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 March 31, 2012, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)	WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	682	90	$	108.99	$	(442	)
2013	494	92	$	108.67	$	(365	)

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The following table provides information on the derivative positions related to long liquids and keep-whole price risk that we have entered into subsequent to March 31, 2012, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)
2014	1,150	$	98.39

Embedded Derivatives in Commodity Contracts

We have a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative loss related to purchased product costs. In February 2011, we executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of March 31, 2012, the estimated fair value of this contract was a liability of $123.6 million and the recorded value was a liability of $70.1 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 March 31, 2012 (in thousands):

Fair value of commodity contract	$	123,573
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of March 31, 2012	$	70,066

We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at one of our plant locations through the fourth quarter of 2014. The value of the derivative component of this contract is marked to market through Derivative gain related to facility expenses. As of March 31, 2012, the estimated fair value of this contract was an asset of $9.3 million.

Interest Rate Risk

The information about interest rate risk for the three months ended March 31, 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.

Credit Risk

The information about credit risk for the three months ended March 31, 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.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the 1934 Act, as of March 31, 2012. Based on this evaluation, the Partnership’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of March 31, 2012, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

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Limitations on Controls

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2012 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Refer to Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements for information regarding legal proceedings.

Item 1A. Risk Factors

There were no material changes to our risk factors as disclosed in Item1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2011.

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 natural gas liquids 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

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)

	Three months ended March 31,
	2012			2011
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	16,607		$	22,729
Cash (received) paid for income taxes, net	(363		)	34

Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	101,299		$	58,218
Interest capitalized on construction in progress	2,620			19
Issuance of common units for vesting of share-based payment awards	2,501			5,282

PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011	2
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011	3
	Unaudited Condensed Consolidated Statements of Changes in Equity for the three months ended March 31, 2012 and 2011	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011	5
	Unaudited Notes to the Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.	Controls and Procedures	40

PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 6.	Exhibits	43
SIGNATURES		44

4.1*		Seventh Supplemental Indenture dated as of January 30, 2012 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.

31.1*		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101*		The following financial information from the quarterly report on Form 10-Q of MarkWest Energy Partners, L.P. for the quarter ended March 31, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Changes in Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

	MarkWest Energy Partners, L.P. (Registrant)

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



Date: May 7, 2012	/s/ FRANK M. SEMPLE
	Frank M. Semple
	Chairman, President & Chief Executive Officer
	(Principal Executive Officer)


Date: May 7, 2012	/s/ NANCY K. BUESE
	Nancy K. Buese
	Senior Vice President & Chief Financial Officer
	(Principal Financial Officer)


Date: May 7, 2012	/s/ PAULA L. ROSSON
	Paula L. Rosson
	Vice President & Chief Accounting Officer
	(Principal Accounting Officer)