PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	September 30, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents ($2,710 and $2,684, respectively)	$	415,064		$	117,016
Restricted cash	25,000			26,193
Receivables, net ($1,448 and $1,569, respectively)	196,296			226,561
Inventories	33,537			41,006
Fair value of derivative instruments	15,766			8,698
Deferred income taxes	6,544			14,885
Other current assets ($10 and $169, respectively)	24,645			11,748
Total current assets	716,852			446,107

Property, plant and equipment ($306,023 and $156,808, respectively)	4,975,209			3,302,369
Less: accumulated depreciation ($20,420 and $15,551, respectively)	(568,670		)	(438,062		)
Total property, plant and equipment, net	4,406,539			2,864,307

Other long-term assets:
Investment in unconsolidated affiliate	26,441			27,853
Intangibles, net of accumulated amortization of $206,375 and $168,168, respectively	870,196			603,767
Goodwill	144,582			67,918
Deferred financing costs, net of accumulated amortization of $17,091 and $13,194, respectively	52,085			41,798
Deferred contract cost, net of accumulated amortization of $2,496 and $2,262, respectively	754			988
Fair value of derivative instruments	17,423			16,092
Other long-term assets ($102 and $102, respectively)	2,271			1,595
Total assets	$	6,237,143		$	4,070,425

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($14,834 and $96, respectively)	$	281,868		$	179,871
Accrued liabilities ($60,441 and $1,144, respectively)	419,497			171,451
Fair value of derivative instruments	32,823			90,551
Total current liabilities	734,188			441,873

Deferred income taxes	199,574			93,664
Fair value of derivative instruments	29,715			65,403
Long-term debt, net of discounts of $8,258 and $1,050, respectively	2,522,854			1,846,062
Other long-term liabilities ($77 and $73, respectively)	129,872			121,356

Commitments and contingencies (Note 11)

Equity:
Common units (117,594 and 94,940 common units issued and outstanding, respectively)	1,745,672			679,309
Class B units (19,954 units issued and outstanding)	752,531			752,531
Non-controlling interest in consolidated subsidiaries	122,737			70,227
Total equity	2,620,940			1,502,067
Total liabilities and equity	$	6,237,143		$	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 September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Revenue:
Revenue	$	320,137		$	400,883		$	1,029,304		$	1,109,632
Derivative (loss) gain	(36,400		)	106,943			50,952			61,854
Total revenue	283,737			507,826			1,080,256			1,171,486

Operating expenses:
Purchased product costs	119,369			189,284			386,655			497,493
Derivative loss (gain) related to purchased product costs	11,643			(1,274		)	(21,136		)	17,866
Facility expenses	53,293			44,236			150,671			124,358
Derivative loss (gain) related to facility expenses	4,028			(2,787		)	1,136			(2,871		)
Selling, general and administrative expenses	21,922			20,162			69,025			60,454
Depreciation	48,136			38,715			132,199			110,280
Amortization of intangible assets	14,988			10,985			38,280			32,632
Loss on disposal of property, plant and equipment	655			147			2,983			4,619
Accretion of asset retirement obligations	141			557			540			934
Total operating expenses	274,175			300,025			760,353			845,765

Income from operations	9,562			207,801			319,903			325,721

Other income (expense):
Earnings (loss) from unconsolidated affiliate	246			(507		)	788			(1,262		)
Interest income	64			62			295			214
Interest expense	(30,621		)	(26,899		)	(86,855		)	(83,036		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,428		)	(1,002		)	(3,943		)	(3,873		)
Loss on redemption of debt	—			(133		)	—			(43,461		)
Miscellaneous income (expense), net	1			(4		)	63			127
(Loss) Income before provision for income tax	(22,176		)	179,318			230,251			194,430

Provision for income tax (benefit) expense:
Current	(17,948		)	3,959			2,202			8,104
Deferred	10,528			21,905			39,396			18,338
Total provision for income tax	(7,420		)	25,864			41,598			26,442

Net (loss) income	(14,756		)	153,454			188,653			167,988

Net loss (income) attributable to non-controlling interest	416			(13,142		)	(65		)	(33,208		)
Net (loss) income attributable to the Partnership’s unitholders	$	(14,340	)	$	140,312		$	188,588		$	134,780

Net (loss) income attributable to the Partnership’s common unitholders per common unit (Note 13):
Basic	$	(0.13	)	$	1.77		$	1.77		$	1.75
Diluted	$	(0.13	)	$	1.77		$	1.49		$	1.75

Weighted average number of outstanding common units:
Basic	113,994			78,619			105,916			76,118
Diluted	113,994			78,760			126,595			76,276

Cash distribution declared per common unit	$	0.80		$	0.70		$	2.35		$	2.02

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	22,408	1,191,066			—	—		—			1,191,066
Distributions paid	—	(244,169		)	—	—		(4,495		)	(248,664		)
Contributions from non-controlling interest	—	—			—	—		56,940			56,940
Share-based compensation activity	246	3,517			—	—		—			3,517
Excess tax benefits related to share-based compensation	—	2,216			—	—		—			2,216
Deferred income tax impact from changes in equity	—	(74,855		)	—	—		—			(74,855		)
Net income	—	188,588			—	—		65			188,653
September 30, 2012	117,594	$	1,745,672		19,954	$	752,531	$	122,737		$	2,620,940

	Common Units				Non-controlling
	Units	Amounts			Interest			Total
December 31, 2010	71,440	$	993,049		$	465,517		$	1,458,566
Issuance of units in public offering, net of offering costs	7,475	323,492			—			323,492
Distributions paid	—	(155,931		)	(49,099		)	(205,030		)
Contributions from non-controlling interest	—	—			80,332			80,332
Share-based compensation activity	275	5,213			—			5,213
Excess tax benefits related to share-based compensation	—	1,089			—			1,089
Net income	—	134,780			33,208			167,988
September 30, 2011	79,190	$	1,301,692		$	529,958		$	1,831,650

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)

	Nine months ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	188,653		$	167,988
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	132,199			110,280
Amortization of intangible assets	38,280			32,632
Loss on redemption of debt	—			43,461
Amortization of deferred financing costs and discount	3,943			3,873
Accretion of asset retirement obligations	540			934
Amortization of deferred contract cost	234			234
Phantom unit compensation expense	11,579			10,611
Equity in (earnings) loss of unconsolidated affiliate	(788		)	1,262
Distributions from unconsolidated affiliate	2,200			300
Unrealized gain on derivative instruments	(101,815		)	(99,400		)
Loss on disposal of property, plant and equipment	2,983			4,619
Deferred income taxes	39,396			18,338
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	32,739			(12,776		)
Inventories	7,590			(19,470		)
Other current assets	(12,707		)	(725		)
Accounts payable and accrued liabilities	36,737			56,716
Other long-term assets	(676		)	(284		)
Other long-term liabilities	8,631			12,656
Net cash provided by operating activities	389,718			331,249

Cash flows from investing activities:
Restricted cash	1,003			—
Capital expenditures	(1,240,866		)	(359,926		)
Acquisition of business, net of cash acquired	(506,797		)	(230,728		)
Proceeds from disposal of property, plant and equipment	589			2,968
Net cash flows used in investing activities	(1,746,071		)	(587,686		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	1,191,066			323,492
Proceeds from Credit Facility	511,100			1,074,700
Payments of Credit Facility	(577,100		)	(929,600		)
Proceeds from long-term debt	742,613			499,000
Payments of long-term debt	—			(440,638		)
Payments of premiums on redemption of long-term debt	—			(39,642		)
Payments for debt issuance costs, deferred financing costs and registration costs	(14,184		)	(7,795		)
Contributions from non-controlling interest	56,940			80,332
Payments of SMR liability	(1,525		)	(1,390		)
Cash paid for taxes related to net settlement of share-based payment awards	(8,061		)	(6,354		)
Excess tax benefits related to share-based compensation	2,216			1,089
Payment of distributions to common unitholders	(244,169		)	(155,931		)
Payment of distributions to non-controlling interest	(4,495		)	(49,099		)
Net cash flows provided by financing activities	1,654,401			348,164

Net increase in cash and cash equivalents	298,048			91,727
Cash and cash equivalents at beginning of year	117,016			67,450
Cash and cash equivalents at end of period	$	415,064		$	159,177

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

1. Organization and Basis of Presentation

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

These unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the SEC for interim financial reporting. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. These condensed consolidated financial statements should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. In management’s opinion, the Partnership has made all adjustments necessary for a fair presentation of its results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. Finally, results for the three and nine months ended September 30, 2012 are not necessarily indicative of results for the full year 2012 or any other future period.

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

2. Recent Accounting Pronouncements

In May 2011, the FASB amended the accounting guidance for fair value measurement and disclosure. The amendment primarily clarifies the application of the existing guidance and provides for increased disclosures, particularly related to Level 3 fair value measurements. The amended guidance is effective for the Partnership prospectively as of January 1, 2012. Except for the additional disclosures included in Note 6, the adoption of the amended guidance did not have a material effect on the Partnership’s condensed consolidated financial statements.

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

3. Business Combination

Keystone Acquisition

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

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

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The Keystone Acquisition is accounted for as a business combination. The total purchase price is allocated to identifiable assets acquired and liabilities assumed based on the estimated fair values at the acquisition date. The remaining purchase price in excess of the fair value of the identifiable assets and liabilities is recorded as goodwill. The acquired assets and the related results of operations are included in the Partnership’s Liberty segment. The following table summarizes the preliminary purchase price allocation for the Keystone Acquisition (in thousands):

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

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

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

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

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

Pro forma financial results that give effect to the Keystone Acquisition are not presented as any pro forma adjustments would not be material to the Partnership’s historical results.

4. Variable Interest Entities

MarkWest Utica EMG

Effective January 1, 2012, the Partnership and EMG Utica, LLC (“EMG Utica”) executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in Eastern Ohio. Under the terms of the agreements, the Partnership made 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 made 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 Utica has not funded the Minimum EMG Investment by December 31, 2016, then commencing on January 1, 2017, the Partnership is required to fund, as needed, 100% of all capital required to develop projects within MarkWest Utica EMG until such time as the total investment balances of the Partnership and EMG Utica are in the ratio of 60% and 40%, respectively (such time being referred to as the “First Equalization Date”). If the First Equalization Date has not occurred by December 31, 2016, each member’s ownership interest will be adjusted to equal the proportionate share of capital that it has

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contributed, and allocations of profits and losses and distributions of available cash will 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 MarkWest Pioneer and MarkWest Utica EMG, excluding intercompany balances, as of September 30, 2012 (in thousands).

	As of September 30, 2012
	MarkWest Pioneer		MarkWest Utica EMG		Total
ASSETS
Cash and cash equivalents	$	2,710	$	—	$	2,710
Receivables, net	1,298		150		1,448
Other current assets	10		—		10
Property, plant and equipment, net of accumulated depreciation of $20,278 and $142, respectively	137,666		147,937		285,603
Other long-term assets	102		—		102
Total assets	$	141,786	$	148,087	$	289,873

LIABILITIES
Accounts payable	$	48	$	14,786	$	14,834
Accrued liabilities	1,067		59,374		60,441
Other long-term liabilities	77		—		77
Total liabilities	$	1,192	$	74,160	$	75,352

The assets of the VIEs are the property of the respective entities and are not available to the Partnership for any other purpose, including as collateral for its secured debt (see Note 9 and Note 15). VIE asset balances can only be used to settle obligations of each respective VIE. The liabilities of the VIEs do not represent additional claims against the Partnership’s general assets, and the creditors or beneficial interest holders of the VIE do not have recourse to the general credit of the Partnership. The Partnership’s maximum exposure to loss as a result of its involvement with the VIEs includes its equity investment, any additional capital

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contribution commitments and any operating expense incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership may temporarily fund MarkWest Utica EMG for certain projects due to the timing of the capital call process. The Partnership will receive distributions as reimbursement for any temporary funding. Other than temporary funding, the Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the nine months ended September 30, 2012 and 2011.

The results of operations of MarkWest Utica EMG and MarkWest Pioneer are included in the Partnership’s Liberty and Southwest segments, respectively (see Note 14). Construction began for MarkWest Utica EMG assets in the second quarter of 2012 with total cash capital expenditures of approximately $88.6 million for the nine months ended September 30, 2012. With limited operating activities commencing in the third quarter 2012, the results of operations and cash flows, other than capital expenditures, related to MarkWest Utica EMG are not material to the Partnership. The result of operations and cash flows for MarkWest Pioneer are not material to the Partnership.

5. Derivative Financial Instruments

Commodity Derivatives

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

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. The Partnership often manages a portion of its NGL price risk using crude oil contracts, referred to as “proxy contracts”, as the NGL financial markets are not as liquid and historically there has been a strong relationship between changes in NGL and crude oil prices. The pricing relationship between NGLs and crude oil, which may vary in certain periods due to various market conditions, has significantly weakened during the first nine months of 2012. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the Partnership incurs increased risk and additional gains or losses. The Partnership may settle its derivative positions prior to the contractual settlement date in order to take advantage of favorable terms at which the Partnership could settle these proxy contracts that are expected to be less effective. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory.

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

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

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MarkWest Liberty Midstream and its subsidiaries. The Partnership uses standard master netting arrangements that allow for offset of positive and negative exposures.

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

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

Derivative contracts not designated as hedging instruments	Financial Position	Notional Quantity (net)
Crude Oil (bbl)	Short	6,214,543
Natural Gas (MMBtu)	Long	8,467,690
NGLs (gal)	Short	47,006,992

Embedded Derivatives in Commodity Contracts

The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative (loss) gain 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 September 30, 2012, the estimated fair value of this contract was a liability of $87.9 million and the recorded value was a liability of $34.4 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 September 30, 2012 (in thousands):

Fair value of commodity contract	$	87,863
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of September 30, 2012	$	34,356

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 loss (gain) related to facility expenses. As of September 30, 2012, the estimated fair value of this contract was an asset of $6.4 million.

Financial Statement Impact of Derivative Instruments

There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2011. The fair value of the Partnership’s derivative instruments recorded on its Condensed Consolidated Balance Sheets and its Condensed Consolidated Statements of Operations is summarized below (in thousands):

	Assets				Liabilities
Derivative instruments not designated as hedging instruments and their balance sheet location	September 30, 2012		December 31, 2011		September 30, 2012			December 31, 2011
Commodity contracts(1)
Fair value of derivative instruments — current	$	15,766	$	8,698	$	(32,823	)	$	(90,551	)
Fair value of derivative instruments - long-term	17,423		16,092		(29,715		)	(65,403		)
Total	$	33,189	$	24,790	$	(62,538	)	$	(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)	Three months ended September 30,						Nine months ended September 30,
recognized in income	2012			2011			2012			2011
Revenue: Derivative (loss) gain
Realized loss	$	(2,025	)	$	(9,809	)	$	(9,662	)	$	(36,386	)
Unrealized (loss) gain	(34,375		)	116,752			60,614			98,240
Total revenue: derivative (loss) gain	(36,400		)	106,943			50,952			61,854

Derivative (loss) gain related to purchased product costs
Realized loss	(6,334		)	(5,989		)	(21,201		)	(19,436		)
Unrealized (loss) gain	(5,309		)	7,263			42,337			1,570
Total derivative (loss) gain related to purchase product costs	(11,643		)	1,274			21,136			(17,866		)

Derivative (loss) gain related to facility expenses
Unrealized (loss) gain	(4,028		)	2,787			(1,136		)	2,871
Total (loss) gain	$	(52,071	)	$	111,004		$	70,952		$	46,859

For the three months ended September 30, 2012 and 2011, the Realized (loss)gain—revenue includes amortization of premium payments of zero and $1.2 million, respectively. For the nine months ended September 30, 2012 and 2011, the Realized (loss) gain—revenue includes amortization of premium payments of zero and $3.3 million, respectively.

During the first nine months of 2012, the Partnership settled a portion of its crude oil derivative positions related to 2014 commodity price exposure prior to the contractual settlement date in order to take advantage of favorable crude oil prices at which the Partnership could settle these proxy contracts that are expected to be less effective. The Partnership plans to opportunistically enter into future NGL hedge transactions to manage the 2014 NGL price exposure. Upon early settlement, the Partnership received $11.3 million which was recorded as a realized gain in Revenue: Derivative (loss) gain in the accompanying Consolidated Statements of Operations.

6. Fair Value

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 5. The following table presents the derivative instruments carried at fair value as of September 30, 2012 and December 31, 2011 (in thousands):

As of September 30, 2012	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	7,748	$	(25,894	)
Significant unobservable inputs (Level 3)
Commodity contracts	19,060		(2,288		)
Embedded derivatives in commodity contracts	6,381		(34,356		)
Total carrying value in Condensed Consolidated Balance Sheet	$	33,189	$	(62,538	)

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 September 30, 2012. The market approach is used for valuation of all instruments.

Level 3 Instrument	Balance Sheet Classification	Unobservable Inputs	Value Range			Time Period
Commodity contracts	Assets	Forward propane prices (per gallon)	$0.92	-	$0.99	Oct. 2012 - Dec. 2014

		Forward isobutane prices (per gallon)	$1.60	-	$1.67	Jan. 2013 - Dec. 2014

		Forward normal butane prices (per gallon)	$1.41	-	$1.52	Jan. 2013 - Dec. 2014

		Forward natural gasoline prices (per gallon)	$1.89	-	$2.02	Jan. 2013 - Dec. 2014

		Crude option volatilities (%)	17.82%	-	31.96%	Oct. 2012 - Dec. 2014

	Liabilities	Forward propane prices (per gallon)	$0.92	-	$0.95	Oct. 2012 - Mar. 2013

		Crude option volatilities (%)	16.55%	-	37.77%	Oct. 2012 - Dec. 2013

Embedded derivatives in commodity contracts	Asset	ERCOT Pricing (per MegaWatt Hour) (1)	$26.53	-	$60.98	Oct. 2012 - Dec. 2014

	Liability	Forward propane prices (per gallon)	$0.90	-	$0.99	Oct. 2012 - Dec. 2022

		Forward isobutane prices (per gallon)	$1.54	-	$1.70	Oct. 2012 - Dec. 2022

		Forward normal butane prices (per gallon)	$1.37	-	$1.52	Oct. 2012 - Dec. 2022

		Forward natural gasoline prices (per gallon)	$1.81	-	$2.02	Oct. 2012 - Dec. 2022

		Forward natural gas prices (per mmbtu)	$3.01	-	$6.33	Oct. 2012 - Dec. 2022

		Probability of renewal (2)		0%

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Changes in Level 3 Fair Value Measurements

The table below includes a rollforward of the balance sheet amounts for the three and nine months ended September 30, 2012 and 2011 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

	Three months ended September 30, 2012						Nine months ended September 30, 2012
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	29,556		$	(10,395	)	$	(2,965	)	$	(53,904	)
Total (loss) gain (realized and unrealized) included in earnings (1)	(13,199		)	(19,842		)	21,016			17,829
Settlements	415			2,262			(1,279		)	8,100
Fair value at end of period	$	16,772		$	(27,975	)	$	16,772		$	(27,975	)

The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	(11,754	)	$	(15,643	)	$	14,843		$	17,728

	Three months ended September 30, 2011						Nine months ended September 30, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(22,290	)	$	(49,447	)	$	(14,357	)	$	(34,936	)
Total gain (loss) (realized and unrealized) included in earnings (1)	47,939			8,042			35,402			(14,063		)
Settlements	3,167			4,167			7,771			11,761
Fair value at end of period	$	28,816		$	(37,238	)	$	28,816		$	(37,238	)

The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	48,544		$	8,337		$	39,196		$	(10,813	)

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

7. Inventories

Inventories consist of the following (in thousands):

	September 30, 2012		December 31, 2011
NGLs	$	23,120	$	32,352
Spare parts, materials and supplies	10,417		8,654
Total inventories	$	33,537	$	41,006

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8. Goodwill

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

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

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

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

9. Long-Term Debt

Debt is summarized below (in thousands):

	September 30, 2012		December 31, 2011
Credit Facility
Credit Facility, 4.25% interest, due September 2017	$	—	$	66,000

Senior Notes (1)
2018 Senior Notes, 8.75% interest, net of discount of $114 and $129, respectively, issued April and May 2008 and due April 2018	80,998		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 $849 and $921, respectively, issued February and March 2011 and due August 2021	499,151		499,079
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022	700,000		700,000
2023 Senior Notes, 5.5% interest, net of discount of $7,295 and $0, respectively, issued August 2012 and due February 2023	742,705		—
Total long-term debt	$	2,522,854	$	1,846,062

(1) The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $2,706.7 million and $1,880.7 million as of September 30, 2012 and December 31, 2011, respectively, based on quoted prices in an inactive market. The fair value of the Partnership’s Senior Notes is considered a Level 3 measurement.

Credit Facility

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

Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by the Partnership’s wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries, and collateralized by substantially all of the Partnership’s assets and those of its wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its

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subsidiaries. As of September 30, 2012, the Partnership had no borrowings outstanding and approximately $21.6 million of letters of credit outstanding under the Credit Facility, leaving approximately $1,178.4 million available for borrowing.

Senior Notes

On August 10, 2012, the Partnership completed a public offering of $750 million in aggregate principal amount of 5.5% senior unsecured notes (“2023 Senior Notes”), which were issued at 99.015% of par. The 2023 Senior Notes mature on February 15, 2023, and interest is payable semi-annually in arrears on February 15 and August 15, commencing February 15, 2013. The Partnership received net proceeds of approximately $731 million from the 2023 Senior Notes offering after deducting the underwriting fees and other third-party expenses. The Partnership used a portion of the net proceeds from the offering to repay borrowings under its Credit Facility and used the remainder for general partnership purposes, including, but not limited to, funding capital expenditures and general working capital.

10. Equity

Equity Offerings

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

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

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

In August 2012, the Partnership completed a public offering of approximately 6.9 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 $338 million and were used to partially fund the Partnership’s capital expenditure program, for general working capital and for other general partnership purposes.

Distributions of Available Cash and Range of Unit Prices

	Common Unit Price				Distribution Per Common
Quarter Ended	High		Low		Unit		Declaration Date	Record Date	Payment Date
September 30, 2012	$	55.04	$	49.01	$	0.81	October 25, 2012	November 7, 2012	November 14, 2012
June 30, 2012	$	60.32	$	45.36	$	0.80	July 26, 2012	August 6, 2012	August 14, 2012
March 31, 2012	$	61.60	$	53.51	$	0.79	April 26, 2012	May 7, 2012	May 15, 2012
December 31, 2011	$	56.82	$	42.18	$	0.76	January 26, 2012	February 6, 2012	February 14, 2012

11. Commitments and Contingencies

Legal

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

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

Contract Contingencies

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

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

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

12. Income Taxes

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

	Nine months ended September 30, 2012
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	74,679		$	153,363		$	2,209		$	230,251
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	26,138			—			—			26,138
Permanent items	21			—			—			21
State income taxes, net of federal benefit	3,418			734			—			4,152
Provision on income from Class A units (1)	11,287			—			—			11,287
Provision for income tax	$	40,864		$	734		$	—		$	41,598

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	Nine months ended September 30, 2011
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	31,993		$	166,649		$	(4,212	)	$	194,430
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	11,198			—			—			11,198
Permanent items	22			—			—			22
State income taxes net of federal benefit	889			848			—			1,737
Provision on income from Class A units (1)	13,359			—			—			13,359
Other	126			—			—			126
Provision for income tax	$	25,594		$	848		$	—		$	26,442

(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 for income tax on income from Class A units includes intra period allocations to continued operations and excludes allocations to equity.

During the three months ended September 30, 2012, management updated its estimates of the Corporation’s taxable income primarily due to additional depreciation recognized for income tax purposes on property, plant and equipment that is expected to be placed into service in 2012. The increase in expected depreciation for income tax purposes resulted in a current tax benefit, and corresponding deferred tax expense, of $17.6 million for the three and nine months ended September 30, 2012.

13. Earnings (Loss) Per Common Unit

The following table shows the computation of basic and diluted net income (loss) per common unit for the three and nine months ended September 30, 2012 and 2011, and the weighted-average units used to compute basic and diluted net income (loss) per common unit (in thousands, except per unit data):

	Three months ended September 30,					Nine months ended September 30,
	2012			2011		2012		2011
Net (loss) income attributable to the Partnership’s unitholders	$	(14,340	)	$	140,312	$	188,588	$	134,780
Less: Income allocable to phantom units	541			1,287		1,595		1,288
(Loss) Income available for common unitholders - basic	(14,881		)	139,025		186,993		133,492
Add: Income allocable to phantom units and DER expense	—			—		1,627		—
(Loss) Income available for common unitholders - diluted	$	(14,881	)	$	139,025	$	188,620	$	133,492

Weighted average common units outstanding - basic	113,994			78,619		105,916		76,118
Potential common shares (Class B and phantom units) (2)	—			141		20,679		158
Weighted average common units outstanding - diluted	113,994			78,760		126,595		76,276

Net (loss) income attributable to the Partnership’s common unitholders per common unit (1)
Basic	$	(0.13	)	$	1.77	$	1.77	$	1.75
Diluted	$	(0.13	)	$	1.77	$	1.49	$	1.75

(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.

(2) For the three months ended September 30, 2012, 20,641 units were excluded from the calculation of diluted units because the impact was anti-dilutive.

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14. Segment Information

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

The tables below present the Partnership’s segment profit measure, Operating income before items not allocated to segments, for the three and nine months ended September 30, 2012 and 2011 and capital expenditures for the nine months ended September 30, 2012 and 2011 for the reported segments (in thousands).

Three months ended September 30, 2012:

	Southwest		Northeast		Liberty			Gulf Coast		Total
Segment revenue	$	181,456	$	39,987	$	78,852		$	21,477	$	321,772
Purchased product costs	92,112		11,054		16,203			—		119,369
Net operating margin	89,344		28,933		62,649			21,477		202,403
Facility expenses	20,527		6,267		20,241			8,928		55,963
Portion of operating income (loss) attributable to non-controlling interests	1,543		—		(627		)	—		916
Operating income before items not allocated to segments	$	67,274	$	22,666	$	43,035		$	12,549	$	145,524

Three months ended September 30, 2011:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	241,998	$	55,920	$	78,586	$	26,868	$	403,372
Purchased product costs	141,067		15,947		32,270		—		189,284
Net operating margin	100,931		39,973		46,316		26,868		214,088
Facility expenses	21,043		6,879		9,108		9,798		46,828
Portion of operating income attributable to non-controlling interests	1,227		—		18,223		—		19,450
Operating income before items not allocated to segments	$	78,661	$	33,094	$	18,985	$	17,070	$	147,810

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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 September 30, 2012 and 2011 (in thousands):

	Three months ended September 30,
	2012			2011

Total segment revenue	$	321,772		$	403,372
Derivative (loss) gain not allocated to segments	(36,400		)	106,943
Revenue deferral adjustment (1)	(1,635		)	(2,489		)
Total revenue	$	283,737		$	507,826

Operating income before items not allocated to segments	$	145,524		$	147,810
Portion of operating income attributable to non-controlling interests	916			19,450
Derivative (loss) gain not allocated to segments	(52,071		)	111,004
Revenue deferral adjustment (1)	(1,635		)	(2,489		)
Compensation expense included in facility expenses not allocated to segments	(193		)	(263		)
Facility expenses adjustments (2)	2,863			2,855
Selling, general and administrative expenses	(21,922		)	(20,162		)
Depreciation	(48,136		)	(38,715		)
Amortization of intangible assets	(14,988		)	(10,985		)

Loss on disposal of property, plant and equipment	(655		)	(147		)
Accretion of asset retirement obligations	(141		)	(557		)
Income from operations	9,562			207,801

Earnings (loss) from unconsolidated affiliate	246			(507		)
Interest income	64			62
Interest expense	(30,621		)	(26,899		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,428		)	(1,002		)
Loss on redemption of debt	—			(133		)
Miscellaneous income, net	1			(4		)
(Loss) Income before provision for income tax	$	(22,176	)	$	179,318

(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 September 30, 2012, approximately $0.2 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. In comparison, for the three months ended September 30, 2011, approximately $0.2 million and $2.3 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 Southwest and Gulf Coast segments, respectively.

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Nine months ended September 30, 2012:

	Southwest		Northeast		Liberty			Gulf Coast		Total
Segment revenue	$	585,343	$	168,956	$	213,906		$	66,703	$	1,034,908
Purchased product costs	288,137		49,662		48,856			—		386,655
Net operating margin	297,206		119,294		165,050			66,703		648,253
Facility expenses	66,553		17,577		46,135			28,173		158,438
Portion of operating income (loss) attributable to non-controlling interests	4,579		—		(740		)	—		3,839
Operating income before items not allocated to segments	$	226,074	$	101,717	$	119,655		$	38,530	$	485,976

Capital expenditures	$	134,630	$	70,206	$	1,019,374		$	11,744	$	1,235,954
Capital expenditures not allocated to segments										4,912
Total capital expenditures										$	1,240,866

Nine months ended September 30, 2011:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	679,347	$	201,687	$	168,142	$	73,310	$	1,122,486
Purchased product costs	373,251		72,527		51,715		—		497,493
Net operating margin	306,096		129,160		116,427		73,310		624,993
Facility expenses	62,055		19,402		22,875		27,100		131,432
Portion of operating income attributable to non-controlling interests	3,745		—		45,782		—		49,527
Operating income before items not allocated to segments	$	240,296	$	109,758	$	47,770	$	46,210	$	444,034

Capital expenditures	$	80,069	$	17,768	$	256,877	$	1,282	$	355,996
Capital expenditures not allocated to segments									3,930
Total capital expenditures									$	359,926

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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 nine months ended September 30, 2012 and 2011 (in thousands):

	Nine months ended September 30,
	2012			2011

Total segment revenue	$	1,034,908		$	1,122,486
Derivative gain not allocated to segments	50,952			61,854
Revenue deferral adjustment (1)	(5,604		)	(12,854		)
Total revenue	$	1,080,256		$	1,171,486

Operating income before items not allocated to segments	$	485,976		$	444,034
Portion of operating income attributable to non-controlling interests	3,839			49,527
Derivative gain not allocated to segments	70,952			46,859
Revenue deferral adjustment (1)	(5,604		)	(12,854		)
Compensation expense included in facility expenses not allocated to segments	(826		)	(1,491		)
Facility expenses adjustments (2)	8,593			8,565
Selling, general and administrative expenses	(69,025		)	(60,454		)
Depreciation	(132,199		)	(110,280		)
Amortization of intangible assets	(38,280		)	(32,632		)
Loss on disposal of property, plant and equipment	(2,983		)	(4,619		)
Accretion of asset retirement obligations	(540		)	(934		)
Income from operations	319,903			325,721

Earnings (loss) from unconsolidated affiliate	788			(1,262		)
Interest income	295			214
Interest expense	(86,855		)	(83,036		)
Amortization of deferred financing costs and discount (a component of interest expense)	(3,943		)	(3,873		)
Loss on redemption of debt	—			(43,461		)
Miscellaneous income, net	63			127
Income before provision for income tax	$	230,251		$	194,430

(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 nine months ended September 30, 2012, approximately $0.6 million and $5.0 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the nine months ended September 30, 2011, approximately $6.9 million and $5.9 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

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

	September 30, 2012		December 31, 2011
Southwest	$	1,716,013	$	1,701,919
Northeast	573,832		533,591
Liberty	2,894,407		1,114,654
Gulf Coast	538,732		553,043
Total segment assets	5,722,984		3,903,207
Assets not allocated to segments:
Certain cash and cash equivalents	365,957		66,212
Fair value of derivatives	33,189		24,790
Investment in unconsolidated affiliate	26,441		27,853
Other (1)	88,572		48,363
Total assets	$	6,237,143	$	4,070,425

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

15. Supplemental Condensed Consolidating Financial Information

The Partnership has no operations independent of its subsidiaries. As of September 30, 2012, the Partnership’s obligations under the outstanding Senior Notes (see Note 9) were fully, jointly and severally guaranteed, by all of its wholly-owned subsidiaries other than MarkWest Liberty Midstream and its subsidiaries. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures. MarkWest Liberty Midstream, MarkWest Utica EMG and MarkWest Pioneer, together with certain of the Partnership’s other subsidiaries that do not guarantee the outstanding Senior Notes, have significant assets and operations in the aggregate. For the purpose of the following financial information, the Partnership’s investments in its subsidiaries and the guarantor subsidiaries’ investments in their subsidiaries are presented in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. The operations, cash flows and financial position of the co-issuer of the Senior Notes, MarkWest Energy Finance Corporation, are minor and therefore have been included with the Parent’s financial information. Condensed consolidating financial information for the Partnership, its combined guarantor subsidiaries and combined non-guarantor subsidiaries as of September 30, 2012 and December 31, 2011 and for the three and nine months ended September 30, 2012 and 2011 is as follows (in thousands):

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Condensed Consolidating Balance Sheets

	As of September 30, 2012
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	300,013	$	111,456	$	3,595	$	—		$	415,064
Restricted cash	—		—		25,000		—			25,000
Receivables and other current assets	4,087		194,248		62,687		—			261,022
Intercompany receivables	1,196,163		7,686		20,908		(1,224,757		)	—
Fair value of derivative instruments	—		14,703		1,063		—			15,766
Total current assets	1,500,263		328,093		113,253		(1,224,757		)	716,852

Total property, plant and equipment, net	3,672		1,981,143		2,539,813		(118,089		)	4,406,539

Other long-term assets:
Investment in unconsolidated affiliate	—		26,441		—		—			26,441
Investment in consolidated affiliates	3,308,731		2,310,456		—		(5,619,187		)	—
Intangibles, net of accumulated amortization	—		570,297		299,899		—			870,196
Fair value of derivative instruments	—		17,061		362		—			17,423
Intercompany notes receivable	225,000		—		—		(225,000		)	—
Other long-term assets	51,791		70,116		77,785		—			199,692
Total assets	$	5,089,457	$	5,303,607	$	3,031,112	$	(7,187,033	)	$	6,237,143

LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	4,215	$	1,199,639	$	20,903	$	(1,224,757	)	$	—
Fair value of derivative instruments	—		32,324		499		—			32,823
Other current liabilities	43,798		185,656		471,911		—			701,365
Total current liabilities	48,013		1,417,619		493,313		(1,224,757		)	734,188

Deferred income taxes	1,176		198,398		—		—			199,574
Long-term intercompany financing payable	—		225,000		101,923		(326,923		)	—
Fair value of derivative instruments	—		29,715		—		—			29,715
Long-term debt, net of discounts	2,522,854		—		—		—			2,522,854
Other long-term liabilities	3,045		124,144		2,683		—			129,872

Equity:
Common units	1,761,838		3,308,731		2,433,193		(5,758,090		)	1,745,672
Class B units	752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries	—		—		—		122,737			122,737
Total equity	2,514,369		3,308,731		2,433,193		(5,635,353		)	2,620,940

Total liabilities and equity	$	5,089,457	$	5,303,607	$	3,031,112	$	(7,187,033	)	$	6,237,143

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

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

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Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2012
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	205,629		$	81,584		$	(3,476	)	$	283,737
Operating expenses:
Purchased product costs	—			114,685			16,327			—			131,012
Facility expenses	—			36,437			21,061			(177		)	57,321
Selling, general and administrative expenses	10,241			5,633			7,342			(1,294		)	21,922
Depreciation and amortization	146			41,593			22,963			(1,578		)	63,124
Other operating expenses	—			488			308			—			796
Total operating expenses	10,387			198,836			68,001			(3,049		)	274,175

(Loss) income from operations	(10,387		)	6,793			13,583			(427		)	9,562

Earnings from consolidated affiliates	20,122			10,848			—			(30,970		)	—
Other expense, net	(24,637		)	(4,908		)	(3,151		)	958			(31,738		)
(Loss) income before provision for income tax	(14,902		)	12,733			10,432			(30,439		)	(22,176		)
Provision for income tax expense	(31		)	(7,389		)	—			—			(7,420		)
Net (loss) income	(14,871		)	20,122			10,432			(30,439		)	(14,756		)
Net income attributable to non-controlling interest	—			—			—			416			416
Net (loss) income attributable to the Partnership’s unitholders	$	(14,871	)	$	20,122		$	10,432		$	(30,023	)	$	(14,340	)

	Three Months Ended September 30, 2011
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	425,142		$	82,684		$	—		$	507,826
Operating expenses:
Purchased product costs	—			155,612			32,398			—			188,010
Facility expenses	—			31,351			10,263			(165		)	41,449
Selling, general and administrative expenses	11,270			7,768			2,421			(1,297		)	20,162
Depreciation and amortization	182			38,391			11,314			(187		)	49,700
Other operating expenses	—			1,069			(365		)	—			704
Total operating expenses	11,452			234,191			56,031			(1,649		)	300,025

(Loss) income from operations	(11,452		)	190,951			26,653			1,649			207,801

Earnings from consolidated affiliates	174,458			13,479			—			(187,937		)	—
Loss on redemption of debt	(133		)	—			—			—			(133		)
Other expense, net	(20,609		)	(4,849		)	(32		)	(2,860		)	(28,350		)
Income before provision for income tax	142,264			199,581			26,621			(189,148		)	179,318
Provision for income tax expense	741			25,123			—			—			25,864
Net income	141,523			174,458			26,621			(189,148		)	153,454
Net income attributable to non-controlling interest	—			—			—			(13,142		)	(13,142		)
Net income attributable to the Partnership’s unitholders	$	141,523		$	174,458		$	26,621		$	(202,290	)	$	140,312

Table of Contents

	Nine Months Ended September 30, 2012
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	858,227		$	227,980		$	(5,951	)	$	1,080,256
Operating expenses:
Purchased product costs	—			316,327			49,192			—			365,519
Facility expenses	—			103,484			49,009			(686		)	151,807
Selling, general and administrative expenses	37,197			13,333			21,851			(3,356		)	69,025
Depreciation and amortization	458			121,520			51,446			(2,945		)	170,479
Other operating expenses	—			2,227			1,296			—			3,523
Total operating expenses	37,655			556,891			172,794			(6,987		)	760,353

(Loss) income from operations	(37,655		)	301,336			55,186			1,036			319,903

Earnings from consolidated affiliates	294,036			49,600			—			(343,636		)	—
Other expense, net	(68,681		)	(16,036		)	(5,521		)	586			(89,652		)
Income before provision for income tax	187,700			334,900			49,665			(342,014		)	230,251
Provision for income tax expense	734			40,864			—			—			41,598
Net income	186,966			294,036			49,665			(342,014		)	188,653
Net income attributable to non-controlling interest	—			—			—			(65		)	(65		)
Net income attributable to the Partnership’s unitholders	$	186,966		$	294,036		$	49,665		$	(342,079	)	$	188,588

	Nine Months Ended September 30, 2011
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	991,993		$	179,493		$	—		$	1,171,486
Operating expenses:
Purchased product costs	—			463,459			51,900			—			515,359
Facility expenses	—			95,701			26,285			(499		)	121,487
Selling, general and administrative expenses	35,348			23,139			6,390			(4,423		)	60,454
Depreciation and amortization	538			112,868			30,010			(504		)	142,912
Other operating expenses	673			4,895			(15		)	—			5,553
Total operating expenses	36,559			700,062			114,570			(5,426		)	845,765

(Loss) income from operations	(36,559		)	291,931			64,923			5,426			325,721

Earnings from consolidated affiliates	287,377			31,623			—			(319,000		)	—
Loss on redemption of debt	(43,461		)	—			—			—			(43,461		)
Other expense, net	(67,574		)	(10,583		)	(92		)	(9,581		)	(87,830		)
Income before provision for income tax	139,783			312,971			64,831			(323,155		)	194,430
Provision for income tax expense	848			25,594			—			—			26,442
Net (loss) income	138,935			287,377			64,831			(323,155		)	167,988
Net income attributable to non-controlling interest	—			—			—			(33,208		)	(33,208		)
Net income attributable to the Partnership’s unitholders	$	138,935		$	287,377		$	64,831		$	(356,363	)	$	134,780

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Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2012
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(89,558	)	$	301,270		$	179,334		$	(1,328	)	$	389,718

Cash flows from investing activities:
Restricted cash	—			—			1,003			—			1,003
Capital expenditures	(120		)	(236,153		)	(1,006,431		)	1,838			(1,240,866		)
Equity investments	(42,120		)	(1,367,484		)	—			1,409,604			—
Acquisition of business, net of cash acquired	—			—			(506,797		)	—			(506,797		)
Distributions from consolidated affiliates	48,973			100,238			—			(149,211		)	—
Investment in intercompany notes, net	(12,300		)	—			—			12,300			—
Proceeds from disposal of property, plant and equipment	—			1,718			84			(1,213		)	589
Net cash flows provided by (used in) investing activities	(5,567		)	(1,501,681		)	(1,512,141		)	1,273,318			(1,746,071		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	1,191,066			—			—			—			1,191,066
Proceeds from Credit Facility	511,100			—			—			—			511,100
Payments of Credit Facility	(577,100		)	—			—			—			(577,100		)
Proceeds from long-term debt	742,613			—			—			—			742,613
Proceeds (Payments) related to intercompany financing, net	—			12,300			(703		)	(11,597		)	—
Payments for debt issue costs and deferred financing costs	(14,184		)	—			—			—			(14,184		)
Contributions from parent and affiliates	—			42,120			1,367,484			(1,409,604		)	—
Contribution from non-controlling interest	—			—			56,940			—			56,940
Share-based payment activity	(8,061		)	2,216			—			—			(5,845		)
Payment of distributions	(244,169		)	(48,973		)	(104,733		)	149,211			(248,664		)
Payments of SMR liability	—			(1,525		)	—			—			(1,525		)
Intercompany advances, net	(1,206,149		)	1,206,149			—			—			—
Net cash flows provided by financing activities	395,116			1,212,287			1,318,988			(1,271,990		)	1,654,401

Net increase (decrease) in cash	299,991			11,876			(13,819		)	—			298,048
Cash and cash equivalents at beginning of year	22			99,580			17,414			—			117,016
Cash and cash equivalents at end of period	$	300,013		$	111,456		$	3,595		$	—		$	415,064

Table of Contents

	Nine Months Ended September 30, 2011
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(89,044	)	$	303,401		$	121,551		$	(4,659	)	$	331,249

Cash flows from investing activities:
Capital expenditures	(785		)	(100,155		)	(264,996		)	6,010			(359,926		)
Acquisition of business	—			(230,728		)	—			—			(230,728		)
Equity investments	(34,246		)	(204,428		)	—			238,674			—
Distributions from consolidated affiliates	37,978			50,019			—			(87,997		)	—
Investment in intercompany notes, net	(17,600		)	—			—			17,600			—
Proceeds from disposal of property, plant and equipment	—			365			3,954			(1,351		)	2,968
Net cash flows used in investing activities	(14,653		)	(484,927		)	(261,042		)	172,936			(587,686		)

Cash flows from financing activities:
Proceeds from public equity offering, net	323,492			—			—			—			323,492
Proceeds from Credit Facility	1,074,700			—			—			—			1,074,700
Payments of Credit Facility	(929,600		)	—			—			—			(929,600		)
Proceeds from long-term debt	499,000			—			—			—			499,000
Payments of long-term debt	(440,638		)	—			—			—			(440,638		)
Payments of premiums on redemption of long-term debt	(39,642		)	—			—			—			(39,642		)
(Payments) proceeds related to intercompany financing, net	—			(5,400		)	23,000			(17,600		)	—
Payments for debt issuance costs, deferred financing costs and registration costs	(7,795		)	—			—			—			(7,795		)
Contributions from parent and affiliates	—			34,246			204,428			(238,674		)	—
Contributions from non-controlling interest	—			—			80,332			—			80,332
Share-based payment activity	(6,354		)	1,089			—			—			(5,265		)
Payment of distributions	(155,931		)	(37,978		)	(99,118		)	87,997			(205,030		)
Payments of SMR liability	—			(1,390		)	—			—			(1,390		)
Intercompany advances, net	(213,532		)	213,532			—			—			—
Net cash flows provided by financing activities	103,700			204,099			208,642			(168,277		)	348,164

Net increase in cash	3			22,573			69,151			—			91,727
Cash and cash equivalents at beginning of year	—			63,850			3,600			—			67,450
Cash and cash equivalents at end of period	$	3		$	86,423		$	72,751		$	—		$	159,177

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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 September 30, 2012 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

· Total segment operating income before items not allocated to segments (a non-GAAP financial measure, see below) decreased approximately $2.3 million, or 2%, for the three months ended September 30, 2012 compared to the same period in 2011. The decrease is due primarily to a decline in NGL prices which was partially offset by our acquisition of M&R MWE Liberty, L.L.C.’s (“M&R”) interest in MarkWest Liberty Midstream and over 20% increase in total processed volumes, primarily due to our expanding operations in the Liberty and Southwest segments.

· Realized losses from the settlement of our derivative instruments were $8.4 million for the three months ended September 30, 2012 compared to $15.8 million for the same period in 2011. Changes in the correlation between the price of NGLs and price of crude oil has reduced the effectiveness of our crude oil derivative positions that are used as a proxy contract for managing NGL price risk.

· In July 2012, we announced a long-term fee-based agreement with XTO Energy Inc. (“XTO”) to extend our NGL gathering pipeline in northwest Pennsylvania to XTO’s processing plant in Butler County, Pennsylvania, which is expected to commence operations in late 2012. The NGLs will be transported by truck until the pipeline is complete in late 2013.

· In August 2012, we received net proceeds of approximately $338 million from a public offering of approximately 6.9 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option.

· In August 2012, we received net proceeds of approximately $731 million from a public offering of $750 million in aggregate principal amount of 5.5% senior unsecured notes due in 2023, which were issued at 99.015% of par.

· In September 2012, we signed a 10-year agreement to become a firm shipper on the Mariner East (“Mariner East’) pipeline subject to final regulatory approvals. Mariner East is currently designed to transport ethane and propane sourced at our Houston, Pennsylvania processing and fractionation complex (“Houston Complex”) to Sunoco Inc.’s (“Sunoco”) Marcus Hook facility near Philadelphia, Pennsylvania. Once delivered, the ethane-propane mix will be re-fractionated into purity products for sale into domestic and international markets.

· In October 2012, we commenced operations of the 200 MMcf/d Sherwood I processing facility and associated gathering and compression in Doddridge County, West Virginia. These assets are supported by a long-term, fee-based agreement with Antero Resources.

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· In November 2012, we announced plans to expand the processing capacity at our Mobley complex in Wetzel County, West Virginia by 200 MMcf/d. This expansion is supported by an existing long-term, fee-based agreement with EQT Corporation and is expected to be completed in the fourth quarter of 2013.

· In November 2012, MarkWest Utica EMG announced the execution of long-term fee-based agreements with Antero Resources to provide gas processing, fractionation and marketing services in Noble County, Ohio. Services under these agreements will be provided using the assets currently under construction for our Utica Shale operations as described below in “Results of Operations-Segment Reporting-Utica”.

Non-GAAP Measures

In evaluating our financial performance, management utilizes the segment performance measures, segment revenues and operating income before items not allocated to segments. These financial measures are presented in Note 14 to the accompanying condensed consolidated financial statements and are considered non-GAAP financial measures when presented outside of the notes to the condensed consolidated financial statements. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Note 14 to the accompanying condensed consolidated financial statements for the reconciliations of segment revenue and operating income before items not allocated to segments to the respective most comparable GAAP measure.

Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure). These adjustments have been made for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting.

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

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Segment revenue	$	321,772		$	403,372		$	1,034,908		$	1,122,486
Purchased product costs	(119,369		)	(189,284		)	(386,655		)	(497,493		)
Net operating margin	202,403			214,088			648,253			624,993
Facility expenses	(53,293		)	(44,236		)	(150,671		)	(124,358		)
Derivative gain (loss)	(52,071		)	111,004			70,952			46,859
Revenue deferral adjustment	(1,635		)	(2,489		)	(5,604		)	(12,854		)
Selling, general and administrative expenses	(21,922		)	(20,162		)	(69,025		)	(60,454		)
Depreciation	(48,136		)	(38,715		)	(132,199		)	(110,280		)
Amortization of intangible assets	(14,988		)	(10,985		)	(38,280		)	(32,632		)
Loss on disposal of property, plant and equipment	(655		)	(147		)	(2,983		)	(4,619		)
Accretion of asset retirement obligations	(141		)	(557		)	(540		)	(934		)
Income from operations	$	9,562		$	207,801		$	319,903		$	325,721

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.

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The following table does not give effect to our active commodity risk management program. For the nine months ended September 30, 2012, we calculated the following approximate percentages of our segment revenue and net operating margin from the following types of contracts:

	Fee-Based		Percent-of-Proceeds (1)		Percent-of-Index (2)		Keep-Whole (3)
Segment revenue	29	%	35	%	3	%	33	%
Net operating margin (4)	47	%	26	%	0	%	27	%

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

(2) Includes arrangements tied to natural gas prices.

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

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

Seasonality

Our business is affected by seasonal fluctuations in commodity prices. Sales volumes also are affected by various other factors such as fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast and Liberty segments are particularly impacted by seasonality. In our Northeast and Liberty segments, we store a portion of the propane that is produced in the summer to be sold in the winter months. To manage this seasonality, we have access to approximately 50 million gallons of propane storage capacity provided by our own storage facilities and a firm capacity arrangement with a third-party. 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. As a result of our seasonality, we generally expect the sales volumes in our Northeast and Liberty segments to be higher in the first quarter and fourth quarter, however, the expected growth and expansion in our Liberty segment may partially counteract this seasonality impact on sales volumes.

Results of Operations

Segment Reporting

We present information in this MD&A by segment. The segment information appearing in Note 14 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal management reporting. We conduct our operations in the following operating segments: Southwest, Northeast, Liberty and Gulf Coast. Our assets and operations in each of these segments are described below. In addition, we include a description of our initial plans to develop our Utica operations, which are 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 either 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 fourth quarter of 2012, increasing total processing capacity in East Texas to 400 MMcf/d. We also plan to expand gathering capacity in East Texas by 140 MMcf/d and residue gas outlet capacities by 60 MMcf/d.

· Oklahoma. We own a natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. The liquids-rich natural gas gathered in the Woodford system is processed through Centrahoma, our equity investment, or other third-party processors. We have agreed to fund our share of a 120 MMcf/d processing plant expansion at Centrahoma in order to support the drilling programs in the Woodford Shale. The expansion is expected to be operational in the first quarter of 2014. 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

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· Recently completed 200 railcar loading facility at our Houston Complex.

We continue to evaluate additional projects to expand our gathering, processing, fractionation, and marketing operations in the Marcellus Shale.

Ethane Recovery and Associated Market Outlets

Due to the increased production of natural gas from the liquids-rich area of the Marcellus Shale, natural gas processors must begin to recover a significant amount of ethane from the raw NGL stream to continue to meet the pipeline gas quality specifications for residue gas. We have been developing solutions that will have the capability to recover and fractionate the required ethane, be scalable to recover and fractionate additional ethane at the option of our producer customers and provide access to attractive ethane markets in North America and Europe. The primary components of our ethane recovery solution consist of the following:

· 76,000 Bbl/d de-ethanization facilities under construction at our Houston Complex and Majorsville Complex that are expected to be completed by mid-2013.

· A third de-ethanization facility at the Majorsville Complex is planned that would increase production capacity of purity ethane to approximately 115,000 Bbl/d in first quarter 2014.

· A joint pipeline project with Sunoco Logistics, L.P. (“Sunoco”) that is currently under construction to deliver Marcellus ethane to Sarnia, Ontario, Canada markets (“Mariner West”). Mariner West will utilize new and existing pipelines and is anticipated to have an initial capacity to transport up to 50,000 Bbl/d of ethane in the third quarter of 2013 with the ability to expand to support higher volumes as needed.

· Mariner East, a pipeline and marine project, is intended to deliver Marcellus purity ethane and purity propane to the Gulf Coast and international markets. Mariner East is expected to begin delivering propane in the second half of 2014 and ethane in the first half of 2015.

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

Utica

Effective January 1, 2012, we formed MarkWest Utica EMG, a joint venture focused on the development of significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure to serve producers’ drilling programs in the Utica Shale in eastern Ohio with The Energy & Minerals Group (“EMG”). The current Utica development plan includes gathering and compression systems and two new processing complexes with total cryogenic processing capacity of 725 MMcf/d and 100,000 Bbl/d of fractionation, storage, and marketing capabilities. The fractionation facility in Harrison County for propane and heavier components (“Harrison Fractionation Facility”) will be jointly owned by MarkWest Utica EMG and MarkWest Liberty Midstream. The processing complexes will be in Cadiz township in Harrison County (“Cadiz Complex”) and in Seneca township in Noble County (“Seneca Complex”). The Cadiz Complex is expected to begin the first phase of operations in the fourth quarter of 2012 with interim mechanical refrigeration processing capacity of 60 MMcf/d. The Seneca Complex is expected to begin the first phase of operations in second quarter 2013 with interim mechanical refrigeration processing capacity of 45 MMcf/d. The total planned cryogenic processing capacity of 725 MMcf/d is expected to be in operation by the first quarter of 2014.

Both processing complexes are expected to be connected via an NGL gathering pipeline system to the Harrison Fractionation Facility that is expected to be operational by the first quarter of 2014. Creating a large network of processing complexes connected through an extensive NGL gathering system has been critical to the full development of the Marcellus, and the announced Ohio facilities represent the first major step in providing Utica Shale producers with the same benefits. From the Harrison Fractionation Facility, we plan to market NGLs by truck, rail and pipeline. A railcar loading facility that can accommodate 200 rail cars and an eight bay truck loading and unloading facility are under construction at Harrison Fractionation Facility and are expected to be complete by mid-2013. Additionally, at our Cadiz Complex we are also constructing de-ethanization capacity and a connection to Enterprise Products Partners L.P.’s NGL pipeline from Appalachia to Texas (“ATEX Pipeline”). We expect to begin delivering ethane to the ATEX Pipeline in the first quarter 2014. Additionally, the Harrison Fractionation Facility is expected to be connected to our extensive processing and NGL pipeline network in our Liberty segment and provide for the integrated operation of the two largest fractionation complexes in the Northeast United States in the first quarter 2014.

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On June 4, 2012, MarkWest Utica EMG announced agreements with Gulfport Energy Corporation (“Gulfport”) to provide gathering, processing, fractionation, and marketing services in the liquids-rich corridor of the Utica Shale. Under the terms of the agreements, MarkWest Utica EMG is developing natural gas gathering infrastructure to provide service to Gulfport, primarily in Harrison, Guernsey, and Belmont Counties, that commenced initial operations beginning in the third quarter of 2012. MarkWest Utica EMG is processing the gas at its Cadiz Complex, and is expected to provide NGL fractionation and marketing services at the Harrison Fractionation Facility when it is completed in the first quarter of 2014.

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 nine months ended September 30, 2012:

	Southwest		Northeast		Liberty		Gulf Coast
Segment revenue	57	%	16	%	21	%	6	%
Net operating margin	46	%	18	%	26	%	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 September 30, 2012 and 2011 and for the nine months ended September 30, 2012 and 2011. The information includes net operating margin, a non-GAAP financial measure. See above for a reconciliation of net operating margin to Income (loss) from operations, the most comparable GAAP financial measure.

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

Southwest

	Three months ended September 30,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	181,456	$	241,998	$	(60,542	)	(25	)%
Purchased product costs	92,112		141,067		(48,955		)	(35	)%
Net operating margin	89,344		100,931		(11,587		)	(11	)%
Facility expenses	20,527		21,043		(516		)	(2	)%
Portion of operating income attributable to non-controlling interests	1,543		1,227		316			26	%
Operating income before items not allocated to segments	$	67,274	$	78,661	$	(11,387	)	(14	)%

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

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

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Northeast

	Three months ended September 30,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	39,987	$	55,920	$	(15,933	)	(28	)%
Purchased product costs	11,054		15,947		(4,893		)	(31	)%
Net operating margin	28,933		39,973		(11,040		)	(28	)%
Facility expenses	6,267		6,879		(612		)	(9	)%
Operating income before items not allocated to segments	$	22,666	$	33,094	$	(10,428	)	(32	)%

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

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

Liberty

	Three months ended September 30,								%
	2012			2011		$ Change			Change
	(in thousands)
Segment revenue	$	78,852		$	78,586	$	266		0	%
Purchased product costs	16,203			32,270		(16,067		)	(50	)%
Net operating margin	62,649			46,316		16,333			35	%
Facility expenses	20,241			9,108		11,133			122	%
Portion of operating (loss) income attributable to non-controlling interests	(627		)	18,223		(18,850		)	(103	)%
Operating income before items not allocated to segments	$	43,035		$	18,985	$	24,050		127	%

Purchased Product Costs. Purchased product costs decreased due to lower NGL prices and lower NGL volumes purchased from a producer.

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

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

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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 September 30, 2012 and 2011, respectively. The ensuing items listed below the Total segment revenue and Operating income before items not allocated to segments lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Three months ended September 30,									%
	2012			2011			$ Change			Change
	(in thousands)
Total segment revenue	$	321,772		$	403,372		$	(81,600	)	(20	)%
Derivative (loss) gain not allocated to segments	(36,400		)	106,943			(143,343		)	(134	)%
Revenue deferral adjustment	(1,635		)	(2,489		)	854			(34	)%
Total revenue	$	283,737		$	507,826		$	(224,089	)	(44	)%

Operating income before items not allocated to segments	$	145,524		$	147,810		$	(2,286	)	(2	)%
Portion of operating income attributable to non-controlling interests	916			19,450			(18,534		)	(95	)%
Derivative (loss) gain not allocated to segments	(52,071		)	111,004			(163,075		)	(147	)%
Revenue deferral adjustment	(1,635		)	(2,489		)	854			(34	)%
Compensation expense included in facility expenses not allocated to segments	(193		)	(263		)	70			(27	)%
Facility expenses adjustments	2,863			2,855			8			0	%
Selling, general and administrative expenses	(21,922		)	(20,162		)	(1,760		)	9	%
Depreciation	(48,136		)	(38,715		)	(9,421		)	24	%
Amortization of intangible assets	(14,988		)	(10,985		)	(4,003		)	36	%
Loss on disposal of property, plant and equipment	(655		)	(147		)	(508		)	346	%
Accretion of asset retirement obligations	(141		)	(557		)	416			(75	)%
Income from operations	9,562			207,801			(198,239		)	(95	)%

Earnings (loss) from unconsolidated affiliate	246			(507		)	753			(149	)%
Interest income	64			62			2			3	%
Interest expense	(30,621		)	(26,899		)	(3,722		)	14	%
Amortization of deferred financing costs and discount (a component of interest expense)	(1,428		)	(1,002		)	(426		)	43	%
Loss on redemption of debt	—			(133		)	133			(100	)%
Miscellaneous income (expense), net	1			(4		)	5			(125	)%
(Loss) income before provision for income tax	$	(22,176	)	$	179,318		$	(201,494	)	(112	)%

Derivative (Loss) Gain Not Allocated to Segments. Unrealized loss from the change in fair value of our derivative instruments was $43.7 million for the three months ended September 30, 2012 compared to an unrealized gain of $126.8 million for the same period in 2011. Realized loss from the settlement of our derivative instruments was $8.4 million for the three months ended September 30, 2012 compared to $15.8 million for the same period in 2011. The total change of $163.1 million is due mainly to volatility in commodity prices. Despite the decline in NGL prices in 2012 compared to 2011, we continued to experience realized losses on our derivative positions used to manage NGL price risk due to the decreased effectiveness of crude oil positions used as a proxy contract for NGLs. We are not able to predict the future effectiveness of our crude oil positions in managing NGL price risk, but ineffectiveness may continue for the near-term.

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 September 30, 2012,

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approximately $0.2 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the three months ended September 30, 2011, approximately $0.2 million and $2.3 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Based on current commodity prices, management expects the deferred revenue in subsequent periods to approximate the third quarter 2012’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 Expenses. Selling, general and administrative expenses increased primarily due to higher labor, benefits, office expense and professional services necessary to support the overall growth of our operations.

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

Amortization of Intangible Assets. Amortization increased due to the customer relationship intangibles acquired in the Keystone Acquisition.

Interest Expense. Interest expense increased due to the increased amount of outstanding debt. The increase was partially offset by an increase in capitalized interest.

Nine months ended September 30, 2012 compared to nine months ended September 30, 2011

Southwest

	Nine months ended September 30,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	585,343	$	679,347	$	(94,004	)	(14	)%
Purchased product costs	288,137		373,251		(85,114		)	(23	)%
Net operating margin	297,206		306,096		(8,890		)	(3	)%
Facility expenses	66,553		62,055		4,498			7	%
Portion of operating income attributable to non-controlling interests	4,579		3,745		834			22	%
Operating income before items not allocated to segments	$	226,074	$	240,296	$	(14,222	)	(6	)%

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

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

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

Northeast

	Nine months ended September 30,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	168,956	$	201,687	$	(32,731	)	(16	)%
Purchased product costs	49,662		72,527		(22,865		)	(32	)%
Net operating margin	119,294		129,160		(9,866		)	(8	)%
Facility expenses	17,577		19,402		(1,825		)	(9	)%
Operating income before items not allocated to segments	$	101,717	$	109,758	$	(8,041	)	(7	)%

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

Facility Expenses. Facility expenses decreased primarily due to timing of repairs and maintenance.

Liberty

	Nine months ended September 30,								%
	2012			2011		$ Change			Change
	(in thousands)
Segment revenue	$	213,906		$	168,142	$	45,764		27	%
Purchased product costs	48,856			51,715		(2,859		)	(6	)%
Net operating margin	165,050			116,427		48,623			42	%
Facility expenses	46,135			22,875		23,260			102	%
Portion of operating (loss) income attributable to non-controlling interests	(740		)	45,782		(46,522		)	(102	)%
Operating income before items not allocated to segments	$	119,655		$	47,770	$	71,865		150	%

Segment Revenue. Revenue increased due to ongoing expansion of the Liberty operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $43.4 million related to gathering, processing and fractionation fees and approximately $1.1 million related to increased NGL product sales under a percent of proceeds agreement with a producer and an increase in sales of propane from inventory purchased from producer customers. NGLs sales increased due to higher volumes partially offset by lower prices.

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

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

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

Gulf Coast

	Nine months ended September 30,							%
	2012		2011		$ Change			Change
	(in thousands)
Segment revenue	$	66,703	$	73,310	$	(6,607	)	(9	)%
Purchased product costs	—		—		—			N/A
Net operating margin	66,703		73,310		(6,607		)	(9	)%
Facility expenses	28,173		27,100		1,073			4	%
Operating income before items not allocated to segments	$	38,530	$	46,210	$	(7,680	)	(17	)%

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

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

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 nine months ended September 30, 2012 and 2011, respectively. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Nine months ended September 30,									%
	2012			2011			$ Change			Change
	(in thousands)
Total segment revenue	$	1,034,908		$	1,122,486		$	(87,578	)	(8	)%
Derivative gain not allocated to segments	50,952			61,854			(10,902		)	(18	)%
Revenue deferral adjustment	(5,604		)	(12,854		)	7,250			(56	)%
Total revenue	$	1,080,256		$	1,171,486		$	(91,230	)	(8	)%

Operating income before items not allocated to segments	$	485,976		$	444,034		$	41,942		9	%
Portion of operating income attributable to non-controlling interests	3,839			49,527			(45,688		)	(92	)%
Derivative gain not allocated to segments	70,952			46,859			24,093			51	%
Revenue deferral adjustment	(5,604		)	(12,854		)	7,250			(56	)%
Compensation expense included in facility expenses not allocated to segments	(826		)	(1,491		)	665			(45	)%
Facility expenses adjustments	8,593			8,565			28			0	%
Selling, general and administrative expenses	(69,025		)	(60,454		)	(8,571		)	14	%
Depreciation	(132,199		)	(110,280		)	(21,919		)	20	%
Amortization of intangible assets	(38,280		)	(32,632		)	(5,648		)	17	%
Loss on disposal of property, plant and equipment	(2,983		)	(4,619		)	1,636			(35	)%
Accretion of asset retirement obligations	(540		)	(934		)	394			(42	)%
Income from operations	319,903			325,721			(5,818		)	(2	)%

Earnings (loss) from unconsolidated affiliate	788			(1,262		)	2,050			(162	)%
Interest income	295			214			81			38	%
Interest expense	(86,855		)	(83,036		)	(3,819		)	5	%
Amortization of deferred financing costs and discount (a component of interest expense)	(3,943		)	(3,873		)	(70		)	2	%
Loss on redemption of debt	—			(43,461		)	43,461			(100	)%
Miscellaneous income, net	63			127			(64		)	(50	)%
Income before provision for income tax	$	230,251		$	194,430		$	35,821		18	%

Derivative Gain Not Allocated to Segments. Unrealized gain from the change in fair value of our derivative instruments was $101.8 million for the nine months ended September 30, 2012 compared to an unrealized gain of $102.7 million for the same period in 2011. Realized loss from the settlement of our derivative instruments was $30.9 million for the nine months ended September 30, 2012 compared to $55.8 million for the same period in 2011. The total change of $24.1 million is due mainly to volatility in commodity prices. Despite the decline in NGL prices in 2012 compared to 2011, we continued to experience realized losses on our derivative positions used to manage NGL price risk due to the decreased effectiveness of crude oil positions used as a proxy contract for NGLs. We are not able to predict the future effectiveness of our crude oil positions in managing NGL price risk, but ineffectiveness may continue for the near-term.

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Operating Data

	Three months ended September 30,		%		Nine months ended September 30,		%
	2012	2011	Change		2012	2011	Change
Southwest
East Texas gathering systems throughput (Mcf/d)	471,200	417,400	13	%	440,700	423,800	4	%
East Texas natural gas processed (Mcf/d)	270,200	229,700	18	%	260,400	226,000	15	%
East Texas NGL sales (gallons, in thousands)	67,800	59,000	15	%	199,300	175,200	14	%

Western Oklahoma gathering system throughput (Mcf/d) (1)	227,900	241,300	(6	)%	247,300	224,400	10	%
Western Oklahoma natural gas processed (Mcf/d)	209,600	153,200	37	%	210,800	156,600	35	%
Western Oklahoma NGL sales (gallons, in thousands)	50,900	37,000	38	%	169,900	111,100	53	%

Southeast Oklahoma gathering systems throughput (Mcf/d)	484,400	512,600	(6	)%	496,200	507,500	(2	)%
Southeast Oklahoma natural gas processed (Mcf/d) (2)	128,600	105,400	22	%	116,700	103,100	13	%
Southeast Oklahoma NGL sales (gallons, in thousands)	46,700	30,600	53	%	121,000	92,100	31	%
Arkoma Connector Pipeline throughput (Mcf/d)	310,400	298,600	4	%	323,400	294,300	10	%

Other Southwest gathering system throughput (Mcf/d)	23,600	29,900	(21	)%	25,000	31,500	(21	)%

Northeast
Natural gas processed (Mcf/d) (3)	318,500	277,400	15	%	322,800	300,700	7	%
NGLs fractionated (Bbl/d) (4)	16,500	19,300	(15	)%	16,800	21,400	(21	)%

Keep-whole sales (gallons, in thousands)	23,200	21,700	7	%	96,500	82,600	17	%
Percent-of-proceeds sales (gallons, in thousands)	33,700	31,600	7	%	103,500	95,600	8	%
Total NGL sales (gallons, in thousands) (5)	56,900	53,300	7	%	200,000	178,200	12	%

Crude oil transported for a fee (Bbl/d)	8,700	9,900	(12	)%	9,100	10,500	(13	)%

Liberty
Natural gas processed (Mcf/d)	479,400	366,200	31	%	424,300	306,700	38	%
Gathering system throughput (Mcf/d)	444,700	258,300	72	%	373,700	228,900	63	%
NGLs fractionated (Bbl/d) (6)	22,300	12,400	80	%	20,700	9,300	123	%
NGL sales (gallons, in thousands) (7)	90,800	61,100	49	%	264,200	163,500	62	%

Gulf Coast
Refinery off-gas processed (Mcf/d)	123,800	122,000	1	%	120,000	113,200	6	%
Liquids fractionated (Bbl/d)	23,800	23,100	3	%	23,000	21,400	7	%
NGL sales (gallons excluding hydrogen, in thousands)	92,100	89,200	3	%	264,400	245,500	8	%

(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 nine months ended September 30, 2011 are the average daily rates for the days of operation.

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(4) Amount includes zero barrels per day and 4,400 barrels per day fractionated on behalf of Liberty for the three months ended September 30, 2012 and 2011, respectively and includes zero barrels per day and 5,100 barrels per day fractionated on behalf of Liberty for the nine months ended September 30, 2012 and 2011, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionates NGLs on behalf of Liberty due to the operation of Liberty’s fractionation facility that began in September 2011, except during outages or force majeure events.

(5) Represents sales from the Siloam facilities. The total sales exclude approximately 600,000 gallons and 17,100,000 gallons sold by the Northeast on behalf of Liberty for the three months ended September 30, 2012 and 2011, respectively and 975,000 gallons and 58,600,000 gallons sold for the nine months ended September 30, 2012 and 2011, respectively. These volumes are included as part of NGLs sold at Liberty.

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

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

Liquidity and Capital Resources

Our primary strategy is to expand our asset base through organic growth projects and selective third-party acquisitions that are accretive to our cash available for distribution per common unit.

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

				Actual
	2012 Full Year Plan			Nine months ended September 30, 2012
Consolidated growth capital (1)	$	2,200		$	1,227
Utica joint venture partner’s estimated share of growth capital	(400		)	(55		)
Partnership share of growth capital	1,800			1,172
Acquisition (2)	510			510
Partnership share of growth capital and acquisitions	$	2,310		$	1,682
Consolidated maintenance capital (1)	$	20		$	14

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

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

Management believes that the cash requirements to meet operating expenses and pay distributions to our unitholders will be funded by cash generated from our operations.

Management believes that expenditures for our currently planned capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partner for capital projects encompassed by MarkWest Utica EMG, our current borrowing capacity under the Credit Facility, additional long-term borrowings, and proceeds from equity or debt offerings. Our access to capital markets can be impacted by factors outside our control, which include but are not limited to general economic conditions and the rights of our Class B unitholders to participate in future equity offerings after July 1, 2013; 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 October 31, 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

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operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

Debt Financing Activities

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

Under the provisions of the Credit Facility, we are subject to a number of restrictions and covenants. As of September 30, 2012, we were in compliance with all of our debt covenants and we expect to remain in compliance for at least the next twelve months. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of October 31, 2012, we had no borrowings outstanding and approximately $21.6 million of letters of credit outstanding under the Credit Facility, leaving approximately $1,178.4 million available for borrowing.

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

The Credit Facility also limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Credit Facility prevents participating bank group members from requiring margin calls. As of October 31, 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.

On August 10, 2012, we completed a public offering of $750 million in aggregate principal amount of 5.5% senior unsecured notes (“2023 Senior Notes”), which were issued at 99.015% of par. The 2023 Senior Notes mature on February 15, 2023, and interest is payable semi-annually in arrears on February 15 and August 15, commencing February 15, 2013. We received net proceeds of approximately $731 million from the 2023 Senior Notes offering after deducting the underwriting fees and other third-party expenses. We used a portion of the net proceeds from the offering to repay borrowings under our Credit Facility and the remainder were used for general partnership purposes, including, but not limited to, funding capital expenditures and general working capital.

Equity Offerings

During the first nine months of 2012, we completed three public offerings and issued approximately 22.4 million common units representing limited partner interests, which includes any units issued for the exercise of the underwriters’ over-allotment option. Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $1.2 billion and were used to fund the Keystone Acquisition, to partially fund the our on-going capital expenditure program, to fund general working capital requirements, and for other general partnership purposes.

Liquidity Risks and Uncertainties

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

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

Additionally, we execute a risk management strategy to mitigate our exposure to downward fluctuations in commodity prices. We primarily use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk. During the first nine months of 2012, the correlation between the price of NGLs and crude oil has weakened significantly and as

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a result, our derivative financial instruments have not been as effective in offsetting the impact of NGL price declines. If the pricing relationship between crude oil and NGLs does not return to the historical correlation or continues to weaken, our derivative financial instruments will continue to be less effective.

Cash Flow

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

	Nine months ended September 30,
	2012			2011			Change
Net cash provided by operating activities	$	389,718		$	331,249		$	58,469
Net cash flows used in investing activities	(1,746,071		)	(587,686		)	(1,158,385		)
Net cash flows provided by financing activities	1,654,401			348,164			1,306,237

Net cash provided by operating activities increased primarily due to a $41.9 million increase in operating income, excluding derivative gains and losses, in our operating segments. The increase in cash provided by operating activities was also due to changes in working capital.

Net cash used in investing activities increased primarily due to the $506.8 million net cash spent for the Keystone Acquisition which occurred in the second quarter of 2012 and a $880.9 million increase in capital expenditures primarily related to our expansion of Liberty operations, partially offset by the $230.7 million Langley Acquisition which occurred in the first quarter of 2011.

Net cash provided by financing activities increased primarily due to an $867.6 million increase in proceeds from public equity offerings and a $512.8 million increase in net borrowings, partially offset by an $88.2 million increase in distributions to unit holders.

Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of September 30, 2012, our purchase obligations for the remainder of 2012 were $507.0 million compared to our 2012 obligations of $181.0 million as of December 31, 2011. The increase is due primarily to obligations related to the ongoing expansion in our Liberty segment. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

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

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

Critical Accounting Policies

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

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

There have not been any material changes during the nine months ended September 30, 2012 to the methodology applied by management for critical accounting policies previously disclosed in Item 7. Management’s Discussion and Analysis of Financial

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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 nine months ended September 30, 2012 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2011.

Outstanding Derivative Contracts

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

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	3,364	$	78.84	$	99.73	$	(509	)
2013	3,714	88.08		107.45		4,008
2014	1,418	90.36		108.73		2,968

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2012	7,111	$	86.81	$	(3,730	)
2013	5,416	93.48		(155		)
2014 (Jul - Dec)	573	93.17		238

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2012	16,435	$	4.34	$	(1,795	)
2013	1,453	4.66		(527		)

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 September 30, 2012, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	1,624	$	82.00	$	106.48	$	49

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2012	2,368	$	86.84	$	(1,295	)
2013	1,304	94.32		347

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Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2012	14,130	$	6.18	$	(3,689	)
2013	9,793	5.34		(5,239		)
2014	4,249	5.69		(2,301		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013 (Jan-Mar, Oct-Dec)	36,885	$	1.29	$	2,164
2014 (Jan-Mar, Oct-Dec)	87,837	1.25		4,266

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	3,081	$	1.70	$	89
2014	3,885	1.67		56

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	8,512	$	1.61	$	517
2014	10,711	1.61		625

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	5,600	$	2.26	$	540
2014	7,106	2.32		1,029

Propane Fixed Physical	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2012	1,413	$	1.01	$	10
2013 (Jan-Mar)	5,222	1.02		35

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 September 30, 2012, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	700	$	90.00	$	109.13	$	138
2013	1,062	89.33		106.78		1,271

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per gal)		Fair Value (in thousands)
2012	73,155	$	0.89	$	(246	)
2013 (Jan-Mar)	30,897	0.86		(238		)

Embedded Derivatives in Commodity Contracts

We have a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative gain (loss) related to purchased product costs. In February 2011, we executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of September 30, 2012, the estimated fair value of this contract was a liability of $87.9 million and the recorded value was a liability of $34.4 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception on February 1, 2011 is deemed to be allocable to the host processing contract and therefore not

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recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of September 30, 2012 (in thousands):

Fair value of commodity contract	$	87,863
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of September 30, 2012	$	34,356

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 (loss) related to facility expenses. As of September 30, 2012, the estimated fair value of this contract was an asset of $6.4 million.

Interest Rate Risk

The information about interest rate risk for the nine months ended September 30, 2012 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2011.

Credit Risk

The information about our credit risk for the nine months ended September 30, 2012 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2011.

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 September 30, 2012. Based on this evaluation, the Partnership’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of September 30, 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.

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 September 30, 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

MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”) received a draft Consent Order dated August 14, 2012 from the West Virginia Department of Environmental Protection (“WVDEP”) alleging violations of West Virginia’s stormwater and erosion and sediment control regulations in connection with the construction of MarkWest Liberty Midstream’s Mobley processing complex near Mobley, West Virginia. The draft Consent Order asserts a civil administrative penalty in the amount of approximately $380,000 as well as requests that MarkWest submit corrective action and stream restoration plans. The Partnership

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believes that it has viable and mitigating defenses to the alleged violations and will vigorously defend against the draft Consent Order and the allegations made by the WVDEP.

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

Item 1A. Risk Factors

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

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

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

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

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

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

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

Large accelerated filer x		Accelerated filer o

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

Bbl		Barrel
Bbl/d		Barrels per day
Bcf/d		Billion cubic feet per day
Btu		One British thermal unit, an energy measurement
Credit Facility		Amended and restated revolving credit agreement
DER		Distribution equivalent right
Dth/d		Dekatherms per day
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas south zone (around the clock)
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
GAAP		Accounting principles generally accepted in the United States of America
Gal		Gallon
Gal/d		Gallons per day
Mcf		One thousand cubic feet of natural gas
Mcf/d		One thousand cubic feet of natural gas per day
MMBtu		One million British thermal units, an energy measurement
MMBtu/d		One million British thermal units per day
MMcf/d		One million cubic feet of natural gas per day
Net operating margin (a non-GAAP financial measure)		Segment revenue less purchased product costs, excluding any derivative gain (loss)
NGL		Natural gas liquids, such as ethane, propane, butanes and natural gasoline
N/A		Not applicable
OTC		Over-the-Counter
SEC		Securities and Exchange Commission
SMR		Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation facility in Corpus Christi, Texas
VIE		Variable interest entity
WTI		West Texas Intermediate

	Nine months ended September 30,
	2012		2011
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	73,624	$	76,876
Cash paid for income taxes, net	18,925		5,051

Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	389,601	$	85,666
Interest capitalized on construction in progress	16,353		571
Issuance of common units for vesting of share-based payment awards	2,506		5,412

PART I—FINANCIAL INFORMATION

Item 1.	Financial Statements	4
	Unaudited Condensed Consolidated Balance Sheets at September 30, 2012 and December 31, 2011	4
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2012 and 2011	5
	Unaudited Condensed Consolidated Statements of Changes in Equity for the nine months ended September 30, 2012 and 2011	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011	7
	Unaudited Notes to the Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	51
Item 4.	Controls and Procedures	53

PART II—OTHER INFORMATION		53
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	54
Item 6.	Exhibits	55
SIGNATURES		56

4.1(1)		Eighth Supplemental Indenture, dated as of August 10, 2012, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.

4.2(1)		Form of 5.5% Senior Notes due 2023 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.1).

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 September 30, 2012, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Statements of Changes in Equity, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

	MarkWest Energy Partners, L.P.
	(Registrant)

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


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


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


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