PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	March 31, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents ($0 and $4,114, respectively)	$	123,481		$	85,305
Restricted cash	10,000			10,000
Receivables, net ($8,306 and $5,346, respectively)	283,249			299,107
Inventories ($6,065 and $2,553, respectively)	47,666			41,363
Fair value of derivative instruments	10,906			11,457
Deferred income taxes	17,205			23,200
Other current assets ($7,782 and $5,527, respectively)	42,146			44,068
Total current assets	534,653			514,500

Property, plant and equipment ($1,906,365 and $1,655,789, respectively)	9,223,296			8,583,767
Less: accumulated depreciation ($52,668 and $33,583, respectively)	(992,101		)	(890,598		)
Total property, plant and equipment, net	8,231,195			7,693,169

Other long-term assets:
Restricted cash	10,000			10,000
Investment in unconsolidated affiliates	82,006			75,627
Intangibles, net of accumulated amortization of $301,709 and $285,732, respectively	858,815			874,792
Goodwill	144,856			144,856
Deferred financing costs, net of accumulated amortization of $26,702 and $25,083, respectively	51,183			52,132
Deferred contract cost, ($5,795 and $6,591, respectively), net of accumulated amortization of $3,761 and $2,886 ($796 and $0), respectively	26,081			26,955
Fair value of derivative instruments	31			505
Other long-term assets ($313 and $658, respectively)	3,427			3,887
Total assets	$	9,942,247		$	9,396,423

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($100,613 and $82,007, respectively)	$	435,589		$	401,088
Accrued liabilities ($124,817 and $112,029, respectively)	426,747			437,847
Fair value of derivative instruments	22,295			28,838
Total current liabilities	884,631			867,773

Deferred income taxes	301,646			287,566
Fair value of derivative instruments	21,461			27,763
Long-term debt, net of discounts of $6,746 and $6,929, respectively	3,400,554			3,023,071
Other long-term liabilities	159,659			156,500

Commitments and contingencies (Note 8)
Redeemable non-controlling interest (Note 2)	131,565			235,617

Equity:
Common units (162,225 and 157,766 common units issued and outstanding, respectively)	3,613,507			3,476,295
Class B units (15,964 and 15,964 units issued and outstanding, respectively)	602,025			602,025
Non-controlling interest in consolidated subsidiaries	827,199			719,813
Total equity	5,042,731			4,798,133
Total liabilities and equity	$	9,942,247		$	9,396,423

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

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

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Operations

(unaudited, in thousands, except per unit amounts)

	Three months ended March 31,
	2014			2013
Revenue:
Revenue	$	516,443		$	373,458
Derivative loss	(3,967		)	(185		)
Total revenue	512,476			373,273

Operating expenses:
Purchased product costs	211,564			152,557
Derivative gain related to purchased product costs	(7,798		)	(10,704		)
Facility expenses	83,705			59,510
Derivative gain related to facility expenses	(268		)	(332		)
Selling, general and administrative expenses	35,290			25,242
Depreciation	101,929			68,017
Amortization of intangible assets	15,978			14,830
(Gain) loss on disposal of property, plant and equipment	(93		)	138
Accretion of asset retirement obligations	168			352
Total operating expenses	440,475			309,610

Income from operations	72,001			63,663

Other income (expense):
Equity in earnings from unconsolidated affiliates	250			235
Interest income	9			149
Interest expense	(40,984		)	(38,336		)
Amortization of deferred financing costs and debt discount (a component of interest expense)	(2,824		)	(1,830		)
Loss on redemption of debt	—			(38,455		)
Miscellaneous income, net	10			—
Income (loss) before provision for income tax	28,462			(14,574		)

Provision for income tax expense (benefit):
Current	345			(5,414		)
Deferred	12,201			11,971
Total provision for income tax	12,546			6,557

Net income (loss)	15,916			(21,131		)

Net (income) loss attributable to non-controlling interest	(3,424		)	5,673
Net income (loss) attributable to the Partnership’s unitholders	$	12,492		$	(15,458	)

Net income (loss) attributable to the Partnership’s common unitholders per common unit:
Basic	$	0.08		$	(0.12	)
Diluted	$	0.07		$	(0.12	)

Weighted average number of outstanding common units:
Basic	158,808			128,615
Diluted	175,488			128,615

Cash distribution declared per common unit	$	0.86		$	0.82

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						Redeemable Non-controlling Interest (Temporary
	Units	Amount			Units	Amount		Interest			Total Equity			Equity)
December 31, 2013	157,766	$	3,476,295		15,964	$	602,025	$	719,813		$	4,798,133		$	235,617
Issuance of units in public offerings, net of offering costs	4,249	271,880			—	—		—			271,880			—
Distributions paid	—	(136,405		)	—	—		(90		)	(136,495		)	—
Redeemable non-controlling interest classified as temporary equity	—	—			—	—		104,052			104,052			(104,052		)
Share-based compensation activity	210	(2,881		)	—	—		—			(2,881		)	—
Deferred income tax impact from changes in equity	—	(7,874		)	—	—		—			(7,874		)	—
Net income	—	12,492			—	—		3,424			15,916			—
March 31, 2014	162,225	$	3,613,507		15,964	$	602,025	$	827,199		$	5,042,731		$	131,565

	Common Units				Class B Units			Non- controlling						Redeemable Non-controlling Interest (Temporary
	Units	Amount			Units	Amount		Interest			Total Equity			Equity)
December 31, 2012	127,494	$	2,097,404		19,954	$	752,531	$	261,463		$	3,111,398		$	—
Issuance of units in public offerings, net of offering costs	1,921	103,937			—	—		—			103,937			—
Distributions paid	—	(105,945		)	—	—		(81		)	(106,026		)	—
Contributions from non-controlling interest	—	—			—	—		385,219			385,219			—
Redeemable non-controlling interest classified as temporary equity	—	—			—	—		(326,249		)	(326,249		)	326,249
Share-based compensation activity	161	(1,204		)	—	—		—			(1,204		)	—
Excess tax benefits related to share-based compensation	—	651			—	—		—			651			—
Deferred income tax impact from changes in equity	—	(10,235		)	—	—		—			(10,235		)	—
Net loss	—	(15,458		)	—	—		(5,673		)	(21,131		)	—
March 31, 2013	129,576	$	2,069,150		19,954	$	752,531	$	314,679		$	3,136,360		$	326,249

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

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Cash Flows

(unaudited, in thousands)

	Three months ended March 31,
	2014			2013
Cash flows from operating activities:
Net income (loss)	$	15,916		$	(21,131	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation	101,929			68,017
Amortization of intangible assets	15,978			14,830
Loss on redemption of debt	—			38,455
Amortization of deferred financing costs and debt discount	2,824			1,830
Accretion of asset retirement obligations	168			352
Amortization of deferred contract cost	875			78
Phantom unit compensation expense	6,043			4,002
Equity in earnings from unconsolidated affiliates	(250		)	(235		)
Distributions from unconsolidated affiliates	1,369			766
Unrealized gain on derivative instruments	(11,820		)	(9,033		)
(Gain) loss on disposal of property, plant and equipment	(93		)	138
Deferred income taxes	12,201			11,971

Changes in operating assets and liabilities:
Receivables	(3,132		)	(13,818		)
Inventories	(6,303		)	4,119
Other current assets	1,922			10,932
Accounts payable and accrued liabilities	(29,798		)	(30,500		)
Other long-term assets	460			33
Other long-term liabilities	4,084			2,952
Net cash provided by operating activities	112,373			83,758

Cash flows from investing activities:
Restricted cash	—			25,000
Capital expenditures	(587,120		)	(631,558		)
Investment in unconsolidated affiliates	(7,498		)	(3,012		)
Proceeds from disposal of property, plant and equipment	19,144			209
Net cash flows used in investing activities	(575,474		)	(609,361		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	271,880			103,937
Proceeds from Credit Facility	377,300			—
Proceeds from long-term debt	—			1,000,000
Payments of long-term debt	—			(501,112		)
Payments of premiums on redemption of long-term debt	—			(31,516		)
Payments for debt issuance costs, deferred financing costs and registration costs	(1,890		)	(14,046		)
Contributions from non-controlling interest	—			385,219
Payments of SMR liability	(594		)	(545		)
Cash paid for taxes related to net settlement of share-based payment awards	(8,924		)	(5,206		)
Excess tax benefits related to share-based compensation	—			651
Payment of distributions to common unitholders	(136,405		)	(105,945		)
Payment of distributions to non-controlling interest	(90		)	(81		)
Net cash flows provided by financing activities	501,277			831,356

Net increase in cash and cash equivalents	38,176			305,753
Cash and cash equivalents at beginning of year	85,305			345,756
Cash and cash equivalents at end of period	$	123,481		$	651,509

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, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the gathering and transportation of crude oil. The Partnership has a leading presence in many unconventional gas plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formations.

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, 2013. In management’s opinion, the Partnership has made all adjustments necessary for a fair presentation of its results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. Finally, results for the three months ended March 31, 2014 are not necessarily indicative of results for the full year 2014 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”), a VIE for which the Partnership has been determined to be the primary beneficiary, is included in the condensed consolidated financial statements (see Note 2). All intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”) and Centrahoma Processing, LLC (“Centrahoma”), in which the Partnership exercises significant influence but does not control and is not the primary beneficiary, are accounted for using the equity method.

2. Variable Interest Entity

MarkWest Utica EMG

Effective January 1, 2012, the Partnership and EMG Utica, LLC (“EMG Utica”) (together the “Members”), 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.

In February 2013, the Members entered into the Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG (“Amended Utica LLC Agreement”) which replaced the original agreement. Pursuant to the Amended Utica LLC Agreement, the aggregate funding commitment of EMG Utica increased to $950.0 million (the “Minimum EMG Investment”). EMG Utica was required to fund all capital until the Minimum EMG Investment was satisfied, which occurred in May 2013. As EMG Utica has funded the Minimum EMG Investment, the Partnership is required to fund, as needed, 100% of future capital for MarkWest Utica EMG until such time as the aggregate capital that has been contributed by the Members equals $2.0 billion. After such time, and 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”), EMG Utica will have the right, but not the obligation, to fund up to 10% of each capital call for MarkWest Utica EMG, and the Partnership will be required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization Date, the Partnership and EMG Utica will have the right, but not the obligation, to fund its pro rata portion (based on the respective investment balances) of any additional required capital and may also fund additional capital which the other party elects not to fund. As of March 31, 2014, EMG Utica has contributed $950.0 million and the Partnership has contributed $799.4 million to MarkWest Utica EMG.

Under the Amended Utica LLC Agreement, after EMG Utica has contributed more than $500.0 million to MarkWest Utica EMG and prior to December 31, 2016, EMG Utica’s investment balance will also be increased by a quarterly special non-cash allocation of income (“Preference Amount”) that is based upon the amount of capital contributed by EMG Utica in excess of $500.0 million. No Preference Amount will accrue to EMG Utica’s investment balance after December 31, 2016. EMG Utica received a special non-cash allocation of income of approximately $8.8 million for the three months ended March 31, 2014.

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If the Partnership’s investment balance does not equal at least 51% of the aggregate investment balances of both Members as of December 31, 2016, then EMG Utica may require that the Partnership purchase membership interests from EMG Utica so that, following the purchase, the Partnership’s investment balance equals 51% of the aggregate investment balances of the Members. The purchase price payable would equal the investment balance associated with the membership interests acquired from EMG Utica. If EMG Utica makes this election, the Partnership would be required to purchase the membership interests on or before March 1, 2017, but effective as of January 1, 2017. The amount of non-controlling interest subject to the redemption option as of March 31, 2014 is reported as Redeemable non-controlling interest in the mezzanine equity section of the Partnership’s Consolidated Balance Sheets.

Under the Amended Utica LLC Agreement, the Partnership will continue to receive 60% of cash generated by MarkWest Utica EMG that is available for distribution until the earlier of December 31, 2016 and the date on which the Partnership’s investment balance equals 60% of the aggregate investment balances of the Partnership and EMG Utica. After the earlier of those dates, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Partnership and EMG Utica in proportion to their respective investment balances.

The Partnership has determined that MarkWest Utica EMG is a VIE primarily due to MarkWest Utica EMG’s inability to fund its planned activities without additional subordinated financial support. The Partnership has concluded that it is the primary beneficiary of MarkWest Utica EMG. As the primary beneficiary of MarkWest Utica EMG, the Partnership consolidates the entity and recognizes non-controlling interest and redeemable non-controlling interest. The decision to consolidate MarkWest Utica EMG is re-evaluated quarterly and is subject to change.

The assets of MarkWest Utica EMG are the property of MarkWest Utica EMG and are not available to the Partnership for any other purpose, including as collateral for its secured debt (see Notes 6 and 12). MarkWest Utica EMG’s asset balances can only be used to settle its own obligations. The liabilities of MarkWest Utica EMG do not represent additional claims against the Partnership’s general assets and the creditors or beneficial interest holders of MarkWest Utica EMG 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 MarkWest Utica EMG includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. Other than temporary funding due to the timing of the administrative process associated with capital calls in the beginning of 2013, the Partnership did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the quarters ended March 31, 2014 and 2013.

Ohio Gathering

Ohio Gathering Company L.L.C. (“Ohio Gathering”) is a consolidated subsidiary of MarkWest Utica EMG and is engaged in providing natural gas gathering services in the Utica Shale in eastern Ohio. As of March 31, 2014, MarkWest Utica EMG owns more than 99% of Ohio Gathering. In December 2013, Blackhawk Midstream LLC (“Blackhawk”) agreed to sell its interest in Ohio Gathering to Summit Midstream Partners (“Summit”); the transaction closed in January 2014. As of March 31, 2014, Summit owns less than a 1% interest in Ohio Gathering, but has an option to acquire up to a 40% voting interest in Ohio Gathering (“Ohio Gathering Option”). If Summit elects to exercise the Ohio Gathering Option and contributes capital to Ohio Gathering, its ownership interest will equal the amount of its contribution expressed as a percentage of the total capital contributed to Ohio Gathering since inception (inclusive of the amounts contributed by Summit upon exercise of the Ohio Gathering Option). The Ohio Gathering Option expires on May 11, 2014 and the result in ownership change would be effective on June 1, 2014. As noted in the MarkWest EMG Utica Condensate and Ohio Condensate section below, Summit also has an option to acquire up to a 40% interest in Ohio Condensate (as defined below). If Summit elects to exercise one of the options it must exercise the other at the same time and for the same percentage ownership.

The results of operations of MarkWest Utica EMG and its subsidiary, Ohio Gathering, are shown separately as the Utica segment (see Note 11) and are shown in parentheses on the Consolidated Balances Sheets.

MarkWest Utica EMG Condensate and Ohio Condensate

In December 2013, the Partnership and The Energy & Minerals Group (“EMG”) (together the “Condensate Members”) executed the Limited Liability Company Agreement of MarkWest Utica EMG Condensate, L.L.C. (“Utica Condensate LLC Agreement”) to form MarkWest Utica EMG Condensate (“Utica Condensate”) for the purpose of engaging in wellhead condensate gathering, stabilization, terminalling, storage and marketing in the state of Ohio.

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Under the terms of the Utica Condensate LLC Agreement, until the Condensate Equalization Date (as defined below) the Partnership has a 55% ownership interest and EMG has a 45% ownership interest in Utica Condensate. After the Condensate Equalization Date, each Condensate Member’s ownership interest will be equal to its investment balance expressed as a percentage of the aggregate investment balance of all Condensate Members. However, both before and after the Condensate Equalization Date, allocations of profits and losses and distributions of available cash will be made to the Condensate Members based upon the investment balances of the Condensate Members. The investment balances of the Condensate Members are subject to reduction if, and to the extent, that the Condensate Members receive distributions of available cash prior to the Condensate Equalization Date as a result of the exercise of the Ohio Condensate Option by Summit as described below. EMG is required to provide 100% of the capital funding to Utica Condensate until the earlier of 1) such time that EMG has contributed $100.0 million (“Tier 1 Condensate Contributions”) or 2) September 1, 2014. If EMG completes the Tier 1 Condensate Contributions prior to September 1, 2014, the Partnership is required to contribute 100% of the required capital until the earlier of 1) September 1, 2014, 2) such time as the total capital contributed equals $125.0 million (the earlier of the two foregoing dates, the “Required Condensate True Up Date”) and 3) the date on which the Partnership has an investment balance equal to 55% of the aggregate investment balances of the Condensate Members (the earlier of the three foregoing dates, the “Condensate Equalization Date”). If the Partnership’s investment balance in Utica Condensate does not equal 55% of the total investment balances of the Condensate Members as of the Required Condensate True Up Date, the Partnership is required to purchase ownership interests from EMG such that following the purchase the Partnership’s investment balance associated with its ownership interest will equal 55% (“Required True Up Transaction”). The purchase price payable would equal the investment balance associated with the ownership interests so acquired from EMG. If Utica Condensate requires additional capital subsequent to the Condensate Equalization Date, each member has the right, but not the obligation, to contribute capital in proportion to its ownership interest.

Under the Utica Condensate LLC Agreement, oversight of the business and affairs of Utica Condensate will be managed by a board of managers. Prior to the Condensate Equalization Date, the board of managers will consist of three managers designated by the Partnership and three managers designated by EMG. Thereafter, the number of managers that each Condensate Member may designate will be determined based upon ownership interests. In addition, each of the Partnership and EMG have consent rights with respect to certain specified material transactions involving Utica Condensate; therefore, management has concluded that Utica Condensate is under joint control and will be accounted for as an equity method investment.

Initially, Utica Condensate’s business will be conducted solely through a subsidiary, Ohio Condensate Company L.L.C. (“Ohio Condensate”), which was formed in December 2013 when Utica Condensate and Blackhawk executed the Limited Liability Company Agreement of Ohio Condensate Company, L.L.C. (“Ohio Condensate LLC Agreement). As of March 31, 2014, Utica Condensate owned 99% of Ohio Condensate. As of March 31, 2014, Summit owned a 1% interest in Ohio Condensate, and had an option to acquire up to a 40% voting interest in Ohio Condensate (“Ohio Condensate Option”). In December 2013, Blackhawk agreed to sell its interest and the Ohio Condensate Option to Summit; the transaction closed in January 2014. If Summit elects to exercise the Ohio Condensate Option and contribute capital to Ohio Condensate, its ownership interest will equal the amount of its contribution expressed as a percentage of the total capital contributed to Ohio Condensate since inception (inclusive of the amounts contributed by Summit upon exercise of the Ohio Condensate Option). The Ohio Condensate Option expires on May 11, 2014 and the result in ownership change would be effective on June 1, 2014. As noted above, Summit can only exercise the Ohio Gathering Option and Ohio Condensate Option if both are exercised at the same time and for the same percentage ownership.

As of March 31, 2014, Utica Condensate and its subsidiary had not commenced operating activities and therefore had no impact on the Partnership’s operating results. The Partnership sold approximately $17 million of assets under construction to Utica Condensate in December 2013 and has recorded that amount in Receivables, net in the accompanying Condensed Consolidated Balance Sheets as of December 31, 2013. The Partnership received the $17 million in the first quarter of 2014 and has recorded the proceeds in the Proceeds from disposal of property, plant and equipment in the accompanying Condensed Consolidated Statement of Cash Flows for the three months ended March 31, 2014.

MarkWest Pioneer — Restatement

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 3 to the Consolidated Financial Statements in Item 8 of the Partnership’s Form 10-K for the fiscal year ended December 31, 2013, the Partnership determined that MarkWest Pioneer should not have been consolidated and should have been accounted for under the equity method since the Partnership sold 50% of its interests to Arkoma Pipeline Partners, L.L.C. in 2009.

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The Partnership has restated the accompanying Condensed Consolidated Statements of Operations, the Condensed Consolidated Statement of Cash Flows and the Condensed Consolidated Statement of Changes in Equity for the three months ended March 31, 2013. The impact of the misstatement is shown in the tables below (in thousands).

	Three months ended March 31, 2013
Statement of Operations	As previously reported			As restated
Revenue	$	376,137		$	373,458
Total revenue	375,952			373,273

Facility expenses	59,755			59,510
Selling, general and administrative expenses	25,408			25,242
Depreciation	69,597			68,017
Accretion of asset retirement obligations	353			352
Total operating expenses	311,602			309,610

Income from operations	64,350			63,663
Equity in earnings from unconsolidated affiliates	(85		)	235
Loss before provision for income tax	(14,207		)	(14,574		)
Net loss	(20,764		)	(21,131		)
Net loss attributable to non-controlling interest	5,304			5,673
Net loss attributable to the Partnership’s unitholders	(15,460		)	(15,458		)

	Three months ended March 31, 2013
Statement of Cash Flows	As previously reported			As restated
Cash flows from operating activities:
Net loss	$	(20,764	)	$	(21,131	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation	69,597			68,017
Accretion of asset retirement obligations	353			352
Equity in earnings from unconsolidated affiliates	85			(235		)
Distributions from unconsolidated affiliates	—			766
Receivables	(14,026		)	(13,818		)
Other current assets	10,983			10,932
Accounts payable and accrued liabilities	(30,561		)	(30,500		)
Other long-term liabilities	2,953			2,952
Net cash provided by operating activities	85,043			83,758

Cash flows from financing activities:
Payment of distributions to non-controlling interest	(848		)	(81		)
Net cash flows provided by financing activities	830,589			831,356

Net increase in cash and cash equivalents	306,271			305,753
Cash and cash equivalents at beginning of year	347,899			345,756
Cash and cash equivalents at end of period	654,170			651,509

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	Common Units						Non-controlling Interest						Total Equity
Statement of Changes in Equity	As previously reported			As restated			As previously reported			As restated			As previously reported			As restated
December 31, 2012	$	2,134,714		$	2,097,404		$	328,346		$	261,463		$	3,215,591		$	3,111,398
Distributions paid	(105,945		)	(105,945		)	(848		)	(81		)	(106,793		)	(106,026		)
Deferred income tax impact from changes in equity	(10,088		)	(10,235		)	—			—			(10,088		)	(10,235		)
Net loss	(15,460		)	(15,458		)	(5,304		)	(5,673		)	(20,764		)	(21,131		)
March 31, 2013	2,106,605			2,069,150			381,164			314,679			3,240,300			3,136,360

3. 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 plans, the Partnership executes a strategy governed by the risk management policy approved by the General Partner’s board of directors. The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps and options traded on the OTC market and fixed price forward contracts. The risk management policy does not allow the Partnership to take speculative positions with its 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 currently manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. A portion of the Partnership’s NGL price exposure is managed by using crude oil contracts that were primarily executed when there was a strong relationship between changes in NGL and crude oil prices. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the crude oil contracts create increased risk and additional gains or losses. The Partnership may settle its crude oil contracts prior to the contractual settlement date in order to take advantage of favorable terms and reduce the future exposure resulting from the less effective crude oil contracts. Based on our current volume forecasts, the majority of our derivative positions used to manage our future commodity price exposure are direct product NGL derivative contracts.

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 2015. 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.

Currently, all of the Partnership’s financial derivative positions are with financial institutions that are syndicated members of the Credit Facility (“syndicated 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 syndicated bank group members. Specifically, the Partnership is not required to post collateral when it enters into derivative contracts with syndicated bank group members as the syndicated bank group members have a collateral position in substantially all the wholly-owned assets of the Partnership other than MarkWest Liberty Midstream and its subsidiaries. A separate agreement with certain syndicated bank group members allows MarkWest Liberty Midstream to enter into derivative

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positions without posting cash collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures (“master netting arrangements”) in the event of default or other terminating events, including bankruptcy.

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 of derivatives.

As of March 31, 2014, 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	1,092,881
Natural Gas (MMBtu)	Long	2,382,342
NGLs (gal)	Short	101,979,453

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 with the producer’s option to extend the agreement for successive five-year terms through December 31, 2032. As of March 31, 2014, the estimated fair value of this contract was a liability of $85.5 million and the recorded value was a liability of $32.0 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of March 31, 2014 (in thousands):

Fair value of commodity contract	$	85,537
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of March 31, 2014	$	32,030

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 Southwest segment through the fourth quarter of 2014. Changes in the fair value of the derivative component of this contract are recorded in Derivative loss related to facility expenses. As of March 31, 2014, the estimated fair value of this contract was an asset of $3.5 million.

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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, 2013. The impact of the Partnership’s derivative instruments on its Condensed Consolidated Balance Sheets is summarized below (in thousands):

	Assets				Liabilities
Derivative instruments not designated as hedging instruments and their balance sheet location	Fair Value at March 31, 2014		Fair Value at December 31, 2013		Fair Value at March 31, 2014			Fair Value at December 31, 2013
Commodity contracts(1)
Fair value of derivative instruments — current	$	10,906	$	11,457	$	(22,295	)	$	(28,838	)
Fair value of derivative instruments — long-term	31		505		(21,461		)	(27,763		)
Total	$	10,937	$	11,962	$	(43,756	)	$	(56,601	)

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

Although certain derivative positions are subject to master netting agreements, the Partnership has elected not to offset any derivative assets and liabilities. The gross amounts in the table below equal the balances presented in the Condensed Consolidated Balance Sheets. The table below summarizes the impact if the Partnership had elected to net its derivative positions that are subject to master netting arrangements (in thousands):

	Assets							Liabilities
As of March 31, 2014	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	7,362	$	(5,143	)	$	2,219	$	(11,645	)	$	5,143	$	(6,502	)
Embedded derivatives in commodity contracts	3,544		—			3,544		(10,650		)	—		(10,650		)
Total current derivative instruments	10,906		(5,143		)	5,763		(22,295		)	5,143		(17,152		)

Non-current

Commodity contracts	31		(31		)	—		(81		)	31		(50		)
Embedded derivatives in commodity contracts	—		—			—		(21,380		)	—		(21,380		)
Total non-current derivative instruments	31		(31		)	—		(21,461		)	31		(21,430		)

Total derivative instruments	$	10,937	$	(5,174	)	$	5,763	$	(43,756	)	$	5,174	$	(38,582	)

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	Assets							Liabilities
As of December 31, 2013	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	8,181	$	(7,017	)	$	1,164	$	(18,293	)	$	7,017	$	(11,276	)
Embedded derivatives in commodity contracts	3,276		—			3,276		(10,545		)	—		(10,545		)
Total current derivative instruments	11,457		(7,017		)	4,440		(28,838		)	7,017		(21,821		)

Non-current

Commodity contracts	505		—			505		—			—		—
Embedded derivatives in commodity contracts	—		—			—		(27,763		)	—		(27,763		)
Total non-current derivative instruments	505		—			505		(27,763		)	—		(27,763		)

Total derivative instruments	$	11,962	$	(7,017	)	$	4,945	$	(56,601	)	$	7,017	$	(49,584	)

In the tables above, the Partnership does not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although the Partnership’s master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of a default, the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented above.

The impact of the Partnership’s derivative instruments on its Condensed Consolidated Statements of Operations is summarized below (in thousands):

Derivative contracts not designated as hedging instruments and the location of	Three months ended March 31,
gain or (loss) recognized in income	2014			2013
Revenue: Derivative loss
Realized (loss) gain	$	(7,607	)	$	3,898
Unrealized gain (loss)	3,640			(4,083		)
Total revenue: derivative (loss)	(3,967		)	(185		)

Derivative (loss) gain related to purchased product costs
Realized loss	(114		)	(2,080		)
Unrealized gain	7,912			12,784
Total derivative gain related to purchase product costs	7,798			10,704

Derivative gain related to facility expenses
Unrealized gain	268			332
Total gain	$	4,099		$	10,851

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4. Fair Value

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 3. The following table presents the derivative instruments carried at fair value as of March 31, 2014 and December 31, 2013 (in thousands):

As of March 31, 2014	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	202	$	(3,784	)
Significant unobservable inputs (Level 3)
Commodity contracts	7,191		(7,942		)
Embedded derivatives in commodity contracts	3,544		(32,030		)
Total carrying value in Condensed Consolidated Balance Sheet	$	10,937	$	(43,756	)

As of December 31, 2013	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	544	$	(4,691	)
Significant unobservable inputs (Level 3)
Commodity contracts	8,142		(13,602		)
Embedded derivatives in commodity contracts	3,276		(38,308		)
Total carrying value in Condensed Consolidated Balance Sheet	$	11,962	$	(56,601	)

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The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of March 31, 2014. 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) (1)	$	1.06-$1.10	Apr. 2014 - Dec. 2014

		Forward isobutane prices (per gallon) (1)	$	1.28-$1.31	Apr. 2014 - Dec. 2014

		Forward normal butane prices (per gallon) (1)	$	1.21-$1.27	Apr. 2014 - Dec. 2014

		Forward natural gasoline prices (per gallon) (1)	$	2.05-$2.17	Apr. 2014 - Dec. 2014

		Crude option volatilities (%)	12.02%-18.77%		Apr. 2014 - Dec. 2014

	Liabilities	Forward propane prices (per gallon) (1)	$	1.06-$1.10	Apr. 2014 - Dec. 2014

		Forward isobutane prices (per gallon) (1)	$	1.28-$1.31	Apr. 2014 - Dec. 2014

		Forward normal butane prices (per gallon) (1)	$	1.21-$1.27	Apr. 2014 - Dec. 2014

		Forward natural gasoline prices (per gallon) (1)	$	2.05-$2.17	Apr. 2014 - Dec. 2014

		Crude option volatilities (%)	10.02%-20.69%		Apr. 2014 — Nov. 2014

Embedded derivatives in commodity contracts	Asset	ERCOT Pricing (per MegaWatt Hour) (2)	$	36.36-$71.77	Apr. 2014 - Dec. 2014

	Liabilities	Forward propane prices (per gallon) (1)	$	0.94-$1.10	Apr. 2014 - Dec. 2022

		Forward isobutane prices (per gallon) (1)	$	1.17-$1.32	Apr. 2014 - Dec. 2022

		Forward normal butane prices (per gallon) (1)	$	1.08-$1.28	Apr. 2014 - Dec. 2022

		Forward natural gasoline prices (per gallon) (1)	$	1.72-$2.17	Apr. 2014 - Dec. 2022

		Forward natural gas prices (per MMBtu) (3)	$	3.52-$4.93	Apr. 2014 - Dec. 2022

		Probability of renewal(4)	0%

(1) NGL prices decrease over the respective period.

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Changes in Level 3 Fair Value Measurements

The table below includes a roll forward of the balance sheet amounts for the three months ended March 31, 2014 and 2013 for net assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

	Three months ended March 31, 2014
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(5,460	)	$	(35,032	)
Total loss (realized and unrealized) included in earnings (1)	(2,277		)	4,410
Settlements	6,986			2,136
Fair value at end of period	$	(751	)	$	(28,486	)

The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	802		$	4,036

	Three months ended March 31, 2013
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	12,449		$	(33,957	)
Total loss (realized and unrealized) included in earnings (1)	3,324			6,532
Settlements	(3,296		)	2,544
Fair value at end of period	$	12,477		$	(24,881	)

The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	3,431		$	6,675

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

5. Inventories

Inventories consist of the following (in thousands):

	March 31, 2014		December 31, 2013
NGLs	$	23,478	$	21,131
Line fill	12,589		7,960
Spare parts, materials and supplies	11,599		12,272
Total inventories	$	47,666	$	41,363

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6. Long-Term Debt

Debt is summarized below (in thousands):

	March 31, 2014		December 31, 2013
Credit Facility
Credit Facility, variable interest, due March 2019 (1)	$	377,300	$	—

Senior Notes (2)
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 $459 and $474, respectively, issued February and March 2011 and due August 2021	324,541		324,526
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022	455,000		455,000
2023A Senior Notes, 5.5% interest, net of discount of $6,287 and $6,455, respectively, issued August 2012 and due February 2023	743,713		743,545
2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023	1,000,000		1,000,000
Total long-term debt	$	3,400,554	$	3,023,071

(1) Applicable interest rate was 4.5% at March 31, 2014.

(2) The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $3,126 million and $3,079 million as of March 31, 2014 and December 31, 2013, 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 March 20, 2014, the Partnership amended the Credit Facility to increase total borrowing capacity to $1.3 billion, extend the maturity by approximately 18 months to March 20, 2019, amend the pricing terms (as discussed below), expand the existing accordion option from $250 million to $500 million and provide the Partnership with the right to release the collateral securing the Credit Facility (“Collateral Release Date”) once the Partnership’s long-term, senior unsecured debt (“Index Debt”) has received an investment grade rating from Standard & Poor’s equal to or more favorable than BBB- (stable) and from Moody’s equal to or more favorable than Baa3 (stable) and the Partnership’s Total Leverage Ratio (as defined in the Credit Facility) is not greater than 5.00 to 1.00. The Partnership incurred approximately $1.9 million of deferred financing costs associated with modifications of the Credit Facility during the quarter ended March 31, 2014.

The borrowings under the Credit Facility bear interest at a variable interest rate, plus basis points. The variable interest rate is based either on the London interbank market rate (“LIBO Rate Loans”) or the higher of (a) the prime rate set by the Credit Facility’s administrative agent, (b) the Federal Funds Rate plus 0.50% and (c) the rate for LIBO Rate Loans for a one month interest period plus 1% (“Alternate Base Rate Loans”). Prior to the Collateral Release Date, the basis points correspond to the Partnership’s Total Leverage Ratio, ranging from 0.5% to 1.5% for Alternate Base Rate Loans and from 1.5% to 2.5% for LIBO Rate Loans. After the Collateral Release Date, the basis points correspond to the credit rating for the Partnership’s Index Debt issued by Moody’s and Standard & Poor’s, ranging from 0.125% to 1% for Alternate Base Rate Loans and from 1.125% to 2% for LIBO Rate Loans. The Partnership may utilize up to $150.0 million of the Credit Facility for the issuance of letters of credit and $10.0 million for shorter-term swingline loans.

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

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assets. The Credit Facility also limits the Partnership’s ability to enter into transactions with parties that require margin calls under certain derivative instruments. Under the Credit Facility, neither the Partnership nor the bank can require margin calls for outstanding derivative positions.

Significant financial covenants under the Credit Facility include the Interest Coverage Ratio (as defined in the Credit Facility), which must be greater than 2.50 to 1.0 and the Total Leverage Ratio (as defined in the Credit Facility), which must be less than 5.5 to 1.0 prior to December 31, 2014, and thereafter until the Collateral Release Date the maximum permissible Total Leverage Ratio will be 5.25 to 1.0. The Total Leverage Ratio at any fiscal quarter-end on or after the Collateral Release Date shall not be greater than 5.00 to 1.00.

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 100% owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries, and collateralized by substantially all of the Partnership’s assets and those of its 100% owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries. As of March 31, 2014, the Partnership had $377.3 million borrowings outstanding and approximately $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $911.4 million of unused capacity of which approximately $544 million was available for borrowing based on financial covenant requirements. Additionally, the full amount of unused capacity is available for borrowing on a short term basis to provide financial flexibility within a given fiscal quarter.

7. Equity

Equity Offerings

On September 5, 2013, the Partnership entered into an Equity Distribution Agreement with a financial institution (the “2013 Manager”) that established an At the Market offering program (the “September 2013 ATM”) pursuant to which, the Partnership may sell from time to time through the 2013 Manager as its sales agent, common units representing limited partner interests having an aggregate offering price of up to $1 billion. During the three months ended March 31, 2014, the Partnership sold an aggregate of 4.2 million common units under the September 2013 ATM Agreement, receiving net proceeds of approximately $272 million after deducting approximately $3.5 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general Partnership purposes. The Partnership completed the September 2013 ATM on March 31, 2014.

On March 11, 2014, the Partnership entered into an Equity Distribution Agreement with financial institutions (the “2014 Managers”) that established an At the Market offering program (the “March 2014 ATM”) pursuant to which the Partnership may sell from time to time through the 2014 Managers, as its sales agents, common units having an aggregate offering price of up to $1.2 billion. During the three months ended March 31, 2014, no common units were sold under the March 2014 ATM.

All of the Partnership’s Class B units were issued to and are held by M&R MWE Liberty, LLC, an affiliate of EMG, as part of the Partnership’s December 31, 2011 acquisition of the non-controlling interest in MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”). The remaining Class B units will convert to common units on a one-for-one basis in four equal installments beginning on July 1, 2014 and each of the next three anniversaries of such date.

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
March 31, 2014	$	73.42	$	61.60	$	0.87	April 22, 2014	May 7, 2014	May 15, 2014
December 31, 2013	$	75.79	$	62.56	$	0.86	January 22, 2014	February 6, 2014	February 14, 2014

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8. 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 that it believes are 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 injury 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 accompanying Condensed Consolidated Financial Statements and that 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 and gathering arrangements require the Partnership to construct new natural gas processing plants and NGL pipelines and contain certain fees and concessions if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure. As of March 31, 2014, management does not believe there are any indications that the Partnership will not be able to meet the construction milestones or that force majeure does not apply or that such fees or concessions will otherwise apply.

9. 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 three months ended March 31, 2014 and 2013 is as follows (in thousands):

	Three months ended March 31, 2014
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	18,459		$	15,106		$	(5,103	)	$	28,462
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	6,461			—			—			6,461
Permanent items	21			—			—			21
State income taxes net of federal benefit	463			156			—			619
Federal and state tax rate change	4,250			—			—			4,250
Provision on income from Class A units (1)	1,195			—			—			1,195
Provision for income tax	$	12,390		$	156		$	—		$	12,546

	Three months ended March 31, 2013
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	20,311		$	(33,447	)	$	(1,438	)	$	(14,574	)
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	7,109			—			—			7,109
Permanent items	16			—			—			16
State income taxes net of federal benefit	508			(133		)	—			375
Provision on income from Class A units (1)	(943		)	—			—			(943		)
Provision for income tax	$	6,690		$	(133	)	$	—		$	6,557

(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.

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10. Earnings (Loss) Per Common Unit

The following table shows the computation of basic and diluted net income per common unit for the three months ended March 31, 2014 and 2013, and the weighted-average units used to compute basic and diluted net income per common unit (in thousands, except per unit data):

	Three months ended March 31,
	2014		2013
Net income (loss) attributable to the Partnership’s unitholders	$	12,492	$	(15,458	)
Less: Income allocable to phantom units	545		546
Income (loss) available for common unitholders - basic	11,947		(16,004		)
Add: Income allocable to phantom units and DER expense	568		—
Income (loss) available for common unitholders - diluted	$	12,515	$	(16,004	)

Weighted average common units outstanding - basic	158,808		128,615
Potential common shares (Class B and phantom units) (1)	16,680		—
Weighted average common units outstanding - diluted	175,488		128,615

Net income (loss) attributable to the Partnership’s common unitholders per common unit (2)
Basic	$	0.08	$	(0.12	)
Diluted	$	0.07	$	(0.12	)

(1) For the three month period ending March 31, 2013, 20,664 units were excluded from the calculation of diluted units because the impact was anti-dilutive.

(2) 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.

11. Segment Information

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

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The tables below present the Partnership’s segment profit measure, Operating income before items not allocated to segments and capital expenditures for the three months ended March 31, 2014 and 2013 for the reported segments (in thousands):

Three months ended March 31, 2014:

	Marcellus				Utica				Northeast				Southwest					Elimination (1)			Total

Segment revenue	$		175,159		$		23,766		$		61,253		$		259,329			$	(1,571	)	$	517,936

Purchased product costs	34,290				4,135				20,455				152,684					—			211,564

Net operating margin	140,869				19,631				40,798				106,645					(1,571		)	306,372

Facility expenses	35,473				11,852				7,114				32,521					(1,571		)	85,389
Portion of operating (loss) income attributable to non-controlling interests	—				3,136				—				(1				)	—			3,135
Operating income (loss) before items not allocated to segments	$		105,396		$		4,643		$		33,684		$		74,125			$	—		$	217,848

Capital expenditures		$		360,598		$		181,332		$		463		$		40,132		$	—		$	582,525
Capital expenditures not allocated to segments																					4,595
Total capital expenditures																					$	587,120

Three months ended March 31, 2013:

	Marcellus		Utica			Northeast		Southwest (2)		Total
Segment revenue	$	108,497	$	623		$	57,336	$	208,366	$	374,822
Purchased product costs	18,793		—			19,662		114,102		152,557
Net operating margin	89,704		623			37,674		94,264		222,265
Facility expenses	22,636		3,962			6,524		28,689		61,811
Portion of operating (loss) income attributable to non-controlling interests	—		(1,339		)	—		64		(1,275		)
Operating income (loss) before items not allocated to segments	$	67,068	$	(2,000	)	$	31,150	$	65,511	$	161,729

Capital expenditures	$	319,827	$	280,320		$	1,779	$	26,687	$	628,613
Capital expenditures not allocated to segments										2,945
Total capital expenditures										$	631,558

(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment, which occurs when NGL volumes in the Marcellus exceed its fractionation capacity.

(2) Amounts have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 2 of these Condensed Consolidated Financial Statements.

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The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the three months ended March 31, 2014 and 2013 (in thousands):

	Three months ended March 31,
	2014			2013 (1)
Total segment revenue	$	517,936		$	374,822
Derivative loss not allocated to segments	(3,967		)	(185		)
Revenue deferral adjustment and other (2)	(1,493		)	(1,364		)
Total revenue	$	512,476		$	373,273

Operating income before items not allocated to segments	$	217,848		$	161,729
Portion of operating income (loss) attributable to non-controlling interests	3,135			(1,275		)
Derivative gain not allocated to segments	4,099			10,851
Revenue deferral adjustment and other (2)	(1,493		)	(1,364		)
Compensation expense included in facility expenses not allocated to segments	(1,004		)	(387		)
Facility expenses adjustments (3)	2,688			2,688
Selling, general and administrative expenses	(35,290		)	(25,242		)
Depreciation	(101,929		)	(68,017		)
Amortization of intangible assets	(15,978		)	(14,830		)
Gain (loss) on disposal of property, plant and equipment	93			(138		)
Accretion of asset retirement obligations	(168		)	(352		)
Income from operations	72,001			63,663
Earnings from unconsolidated affiliates	250			235
Interest income	9			149
Interest expense	(40,984		)	(38,336		)
Amortization of deferred financing costs and discount (a component of interest expense)	(2,824		)	(1,830		)
Loss on redemption of debt	—			(38,455		)
Miscellaneous income, net	10			—
Income (loss) before provision for income tax	$	28,462		$	(14,574	)

(1) Amounts have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 2 of these Condensed Consolidated Financial Statements.

(2) Revenue deferral amount relates primarily to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term. Therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnership’s chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended March 31, 2014, approximately $0.2 million and $1.9 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. In comparison, for the three months ended March 31, 2013, approximately $0.2 million and $1.6 million of the revenue deferral adjustment was 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. Other consists of management fee revenues from unconsolidated affiliates of $0.6 million for the three months ended March 31, 2014 compared to $0.4 million for three months ended March 31, 2013.

(3) Facility expenses adjustments consist of 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 segment.

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The table below presents information about segment assets as of March 31, 2014 and December 31, 2013 (in thousands):

	March 31, 2014		December 31, 2013
Marcellus	$	4,805,804	$	4,529,028
Utica	1,881,958		1,646,995
Northeast	546,637		572,855
Southwest	2,403,404		2,389,057
Total segment assets	9,637,803		9,137,935
Assets not allocated to segments:
Certain cash and cash equivalents	111,234		63,086
Fair value of derivatives	10,937		11,962
Investment in unconsolidated affiliate	82,006		75,627
Other (1)	100,267		107,813
Total assets	$	9,942,247	$	9,396,423

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

12. Supplemental Condensed Consolidating Financial Information

MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of March 31, 2014, the Partnership’s obligations under the outstanding Senior Notes (see Note 6) were fully, jointly and severally guaranteed, by all of the subsidiaries that are owned 100% by the Partnership, 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 (see Note 16 to the Consolidated Financial Statements included in Item 8 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013 for discussion of these circumstances). Subsidiaries that are not 100% owned by the Partnership do not guarantee the Senior Notes. 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 co-issuer, MarkWest Energy Finance Corporation, has no independent assets or operations. Condensed consolidating financial information for MarkWest Energy Partners and its combined guarantor and combined non-guarantor subsidiaries as of March 31, 2014 and December 31, 2013 and for the three months ended March 31, 2014 and 2013 is as follows (in thousands):

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Condensed Consolidating Balance Sheets

	As of March 31, 2014
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	119,069	$	4,412	$	—		$	123,481
Restricted cash	—		—		10,000		—			10,000
Receivables and other current assets	2,574		258,523		129,169		—			390,266
Intercompany receivables	1,643,514		56,827		172,736		(1,873,077		)	—
Fair value of derivative instruments	—		9,144		1,762		—			10,906
Total current assets	1,646,088		443,563		318,079		(1,873,077		)	534,653

Total property, plant and equipment, net	7,728		2,160,925		6,144,553		(82,011		)	8,231,195

Other long-term assets:
Restricted cash	—		—		10,000		—			10,000
Investment in unconsolidated affiliate	—		82,005		1		—			82,006
Investment in consolidated affiliates	5,779,598		5,012,600		—		(10,792,198		)	—
Intangibles, net of accumulated amortization	—		583,983		274,832		—			858,815
Fair value of derivative instruments	—		31		—		—			31
Intercompany notes receivable	169,600		—		—		(169,600		)	—
Other long-term assets	51,314		92,171		82,062		—			225,547
Total assets	$	7,654,328	$	8,375,278	$	6,829,527	$	(12,916,886	)	$	9,942,247

LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	—	$	1,737,689	$	135,388	$	(1,873,077	)	$	—
Fair value of derivative instruments	—		21,080		1,215		—			22,295
Other current liabilities	47,153		200,721		616,657		(2,195		)	862,336
Total current liabilities	47,153		1,959,490		753,260		(1,875,272		)	884,631

Deferred income taxes	3,564		298,082		—		—			301,646
Long-term intercompany financing payable	—		169,600		96,887		(266,487		)	—
Fair value of derivative instruments	—		21,461		—		—			21,461
Long-term debt, net of discounts	3,400,554		—		—		—			3,400,554
Other long-term liabilities	4,596		147,047		8,016		—			159,659

Redeemable non-controlling interest	—		—		—		131,565			131,565

Equity:
Common units	3,596,436		5,779,598		5,971,364		(11,733,891		)	3,613,507
Class B units	602,025		—		—		—			602,025
Non-controlling interest in consolidated subsidiaries	—		—		—		827,199			827,199
Total equity	4,198,461		5,779,598		5,971,364		(10,906,692		)	5,042,731
Total liabilities and equity	$	7,654,328	$	8,375,278	$	6,829,527	$	(12,916,886	)	$	9,942,247

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	As of December 31, 2013
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	224	$	79,363	$	5,718	$	—		$	85,305
Restricted cash	—		—		10,000		—			10,000
Receivables and other current assets	6,248		266,610		134,880		—			407,738
Intercompany receivables	1,194,955		78,010		125,115		(1,398,080		)	—
Fair value of derivative instruments	—		10,444		1,013		—			11,457
Total current assets	1,201,427		434,427		276,726		(1,398,080		)	514,500
Total property, plant and equipment, net	5,379		2,149,845		5,622,602		(84,657		)	7,693,169
Other long-term assets:
Restricted cash	—		—		10,000		—			10,000
Investment in unconsolidated affiliates	—		75,627		—		—			75,627
Investment in consolidated affiliates	5,741,374		4,541,617		—		(10,282,991		)	—
Intangibles, net of accumulated amortization	—		595,995		278,797		—			874,792
Fair value of derivative instruments	—		505		—		—			505
Intercompany notes receivable	151,200		—		—		(151,200		)	—
Other long-term assets	52,338		92,276		83,216		—			227,830
Total assets	$	7,151,718	$	7,890,292	$	6,271,341	$	(11,916,928	)	$	9,396,423
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	—	$	1,315,707	$	82,373	$	(1,398,080	)	$	—
Fair value of derivative instruments	—		26,382		2,456		—			28,838
Other current liabilities	58,110		199,146		583,810		(2,131		)	838,935
Total current liabilities	58,110		1,541,235		668,639		(1,400,211		)	867,773
Deferred income taxes	3,407		284,159		—		—			287,566
Long-term intercompany financing payable	—		151,200		97,461		(248,661		)	—
Fair value of derivative instruments	—		27,763		—		—			27,763
Long-term debt, net of discounts	3,023,071		—		—		—			3,023,071
Other long-term liabilities	3,745		144,561		8,194		—			156,500
Redeemable non-controlling interest	—		—		—		235,617			235,617
Equity:
Common Units	3,461,360		5,741,374		5,497,047		(11,223,486		)	3,476,295
Class B Units	602,025		—		—		—			602,025
Non-controlling interest in consolidated subsidiaries	—		—		—		719,813			719,813
Total equity	4,063,385		5,741,374		5,497,047		(10,503,673		)	4,798,133
Total liabilities and equity	$	7,151,718	$	7,890,292	$	6,271,341	$	(11,916,928	)	$	9,396,423

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Condensed Consolidating Statements of Operations

	Three months ended March 31, 2014
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	325,501		$	199,118		$	(12,143	)	$	512,476
Operating expenses:
Purchased product costs	—			165,183			38,583			—			203,766
Facility expenses	—			37,033			48,371			(1,967		)	83,437
Selling, general and administrative expenses	13,655			10,516			13,349			(2,230		)	35,290
Depreciation and amortization	280			49,120			69,813			(1,306		)	117,907
Other operating expenses (income)	—			(159		)	234			—			75
Total operating expenses	13,935			261,693			170,350			(5,503		)	440,475

(Loss) income from operations	(13,935		)	63,808			28,768			(6,640		)	72,001

Earnings from consolidated affiliates	67,710			22,389			—			(90,099		)	—
Other expense, net	(43,162		)	(6,098		)	(2,956		)	8,677			(43,539		)
Income before provision for income tax	10,613			80,099			25,812			(88,062		)	28,462
Provision for income tax (benefit) expense	157			12,389			—			—			12,546
Net income	10,456			67,710			25,812			(88,062		)	15,916
Net income attributable to non-controlling interest	—			—			—			(3,424		)	(3,424		)
Net income attributable to the Partnership’s unitholders	$	10,456		$	67,710		$	25,812		$	(91,486	)	$	12,492

	Three months ended March 31, 2013 (1)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	270,968		$	109,342		$	(7,037	)	$	373,273
Operating expenses:
Purchased product costs	—			122,950			18,903			—			141,853
Facility expenses	—			32,278			26,902			(2		)	59,178
Selling, general and administrative expenses	12,034			6,973			7,077			(842		)	25,242
Depreciation and amortization	277			44,053			40,003			(1,486		)	82,847
Other operating expenses (income)	—			765			(274		)	(1		)	490
Total operating expenses	12,311			207,019			92,611			(2,331		)	309,610

(Loss) income from operations	(12,311		)	63,949			16,731			(4,706		)	63,663

Earnings from consolidated affiliates	69,961			19,118			—			(89,079		)	—
Loss on redemption of debt	(38,455		)	—			—			—			(38,455		)
Other expense, net	(43,000		)	(6,416		)	(3,285		)	12,919			(39,782		)
(Loss) income before provision for income tax	(23,805		)	76,651			13,446			(80,866		)	(14,574		)
Provision for income tax (benefit) expense	(133		)	6,690			—			—			6,557
Net (loss) income	(23,672		)	69,961			13,446			(80,866		)	(21,131		)
Net loss attributable to non-controlling interest	—			—			—			5,673			5,673
Net (loss) income attributable to the Partnership’s unitholders	$	(23,672	)	$	69,961		$	13,446		$	(75,193	)	$	(15,458	)

(1) The condensed consolidating financial statements have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 2 of these Condensed Consolidated Financial Statements. The adjustments to the amounts previously reported were not material.

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Condensed Consolidating Statements of Cash Flows

	Three months ended March 31, 2014
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(56,688	)	$	103,777		$	64,456		$	828		$	112,373

Cash flows from investing activities:
Capital expenditures	(3,512		)	(51,417		)	(530,853		)	(1,338		)	(587,120		)
Equity investments in consolidated affiliates	(14,243		)	(522,200		)	—			536,443			—
Investment in unconsolidated affiliates	—			(7,498		)	—			—			(7,498		)
Distributions from consolidated affiliates	35,861			73,610			—			(109,471		)	—
Investment in intercompany notes, net	(18,400		)	—			—			18,400			—
Proceeds from disposal of property, plant and equipment	—			2,043			17,101			—			19,144
Net cash flows used in investing activities	(294		)	(505,462		)	(513,752		)	444,034			(575,474		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	271,880			—			—			—			271,880
Proceeds from Credit Facility	377,300			—			—			—			377,300
Payments related to intercompany financing, net	—			18,400			(510		)	(17,890		)	—
Payments for debt issuance costs, deferred financing costs and registration costs	(1,890		)	—			—			—			(1,890		)
Contributions from Parent and affiliates	—			14,243			522,200			(536,443		)	—
Share-based payment activity	(8,924		)	—			—			—			(8,924		)
Payments of distributions	(136,405		)	(35,861		)	(73,700		)	109,471			(136,495		)
Payments of SMR liability	—			(594		)	—			—			(594		)
Intercompany advances, net	(445,203		)	445,203			—			—			—
Net cash flows provided by financing activities	56,758			441,391			447,990			(444,862		)	501,277

Net (decrease) increase in cash and cash equivalents	(224		)	39,706			(1,306		)	—			38,176
Cash and cash equivalents at beginning of year	224			79,363			5,718			—			85,305
Cash and cash equivalents at end of period	$	—		$	119,069		$	4,412		$	—		$	123,481

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	Three months ended March 31, 2013 (1)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(44,484	)	$	72,477		$	49,040		$	6,725		$	83,758

Cash flows from investing activities:
Restricted cash	—			—			25,000			—			25,000
Capital expenditures	(340		)	(31,398		)	(592,643		)	(7,177		)	(631,558		)
Equity investments	(14,828		)	(407,300		)	—			422,128			—
Investment in unconsolidated affiliates	—			(3,012		)	—			—			(3,012		)
Distributions from consolidated affiliates	20,552			140,202			—			(160,754		)	—
Proceeds from disposal of property, plant and equipment	—			35			174			—			209
Net cash flows used in investing activities	5,384			(301,473		)	(567,469		)	254,197			(609,361		)

Cash flows from financing activities:
Proceeds from public equity offering, net	103,937			—			—			—			103,937
Proceeds from long-term debt	1,000,000			—			—			—			1,000,000
Payments of long-term debt	(501,112		)	—			—			—			(501,112		)
Payments of premiums on redemption of long-term debt	(31,516		)	—			—			—			(31,516		)
Payments for debt issue costs and deferred financing costs	(14,046		)	—			—			—			(14,046		)
Payments related to intercompany financing, net	—			—			(452		)	452			—
Contributions from parent and affiliates	—			14,828			407,300			(422,128		)	—
Contributions from non-controlling interest	—			—			385,219			—			385,219
Share-based payment activity	(5,206		)	651			—			—			(4,555		)
Payment of distributions	(105,945		)	(20,552		)	(140,283		)	160,754			(106,026		)
Payments of SMR liability	—			(545		)	—			—			(545		)
Intercompany advances, net	(310,892		)	310,892			—			—			—
Net cash flows provided by financing activities	135,220			305,274			651,784			(260,922		)	831,356

Net increase (decrease) in cash	96,120			76,278			133,355			—			305,753
Cash and cash equivalents at beginning of year	210,015			102,979			32,762			—			345,756
Cash and cash equivalents at end of period	$	306,135		$	179,257		$	166,117		$	—		$	651,509

13. Supplemental Cash Flow Information

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

	Three months ended March 31,
	2014			2013
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	51,622		$	35,196
Cash (received) paid for income taxes, net	(183		)	17,814

Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	553,370		$	500,301
Interest capitalized on construction in progress	5,936			10,158
Issuance of common units for vesting of share-based payment awards	7,720			4,495

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Non-GAAP Measures

In evaluating our financial performance, management utilizes the segment performance measures, segment revenues and operating income before items not allocated to segments. These financial measures are presented in Note 11 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 11 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 from operations, the most comparable GAAP financial measure to net operating margin (in thousands):

	Three months ended March 31,
	2014			2013
Segment revenue	$	517,936		$	374,822
Purchased product costs	(211,564		)	(152,557		)
Net operating margin	306,372			222,265
Facility expenses	(83,705		)	(59,510		)
Derivative gain	4,099			10,851
Revenue deferral adjustment	(1,493		)	(1,364		)
Selling, general and administrative expenses	(35,290		)	(25,242		)
Depreciation	(101,929		)	(68,017		)
Amortization of intangible assets	(15,978		)	(14,830		)
Gain (loss) on disposal of property, plant and equipment	93			(138		)
Accretion of asset retirement obligations	(168		)	(352		)
Income from operations	$	72,001		$	63,663

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 gathering, transportation, fractionation, exchange, 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, 2013 for further discussion of each of these types of arrangements.

The following table does not give effect to our active commodity risk management program. We manage our business by taking into account the partial offset of short natural gas positions primarily in our Southwest segment. The calculated percentages for net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial offset of our natural gas positions. The calculated percentages are less than one percent for percent-of-index due to the offset of our natural gas positions and, therefore, not meaningful to the tables below.

For the three months ended March 31, 2014, we calculated the following approximate percentages of our segment revenue and net operating margin from the following types of contracts:

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	Fee-Based		Percent-of- Proceeds (1)		Keep-Whole (2)
Marcellus	81	%	19	%	0	%
Utica	100	%	0	%	0	%
Northeast	17	%	15	%	68	%
Southwest	57	%	38	%	5	%
Total	65	%	24	%	11	%

(1) Includes condensate sales and other types of arrangements with NGL commodity exposure.

(2) Includes condensate sales and other types of arrangements with both NGL and natural gas commodity exposures.

Seasonality

Our business can be affected by seasonal fluctuations in the demand for natural gas and NGLs and the related fluctuations in commodity prices caused by various factors such as changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast segment could be particularly impacted by seasonality as the majority of its revenues are generated by NGL sales. However, we manage the seasonality impact through the execution of our marketing strategy. We have access to up to 50 million gallons of propane storage capacity in the northeast region of the United States provided by our own storage facilities and an arrangement with a third-party which provides us with flexibility to manage the seasonality impact. Overall, our exposure to the seasonal fluctuations in the commodity markets is declining due to our growth in fee-based business.

Results of Operations

Segment Reporting

We present information in this MD&A by segment. The segment information appearing in Note 11 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: Marcellus, Utica, Northeast and Southwest. Our assets and operations in each of these segments are described below.

Marcellus Segment

In our Marcellus segment, we provide fully integrated natural gas midstream services in southwestern Pennsylvania and northern West Virginia through our wholly owned subsidiary, MarkWest Liberty Midstream. With a total current processing capacity of over 2.2 Bcf/d, we are the largest processor of natural gas in the Marcellus Shale, and have fully integrated gathering, processing, fractionation, storage and marketing operations that support the growing liquids-rich natural gas production in the northeast United States.

Natural Gas Gathering and Processing

We currently operate five processing complexes in our Marcellus segment that include the Houston Complex located in Washington County, Pennsylvania: the Majorsville Complex located in Marshall County, West Virginia; the Mobley Complex located in Wetzel County, West Virginia; the Sherwood Complex located in Doddridge County, West Virginia; and the Keystone Complex located in Butler County, Pennsylvania. In addition, we operate two gathering systems: one currently delivering over 510 MMcf/d of natural gas to our Houston and Majorsville Complexes and the other delivering over 90 MMcf/d of natural gas to our Keystone complex. The gathering and processing capacity at these facilities are supported by long-term fee-based agreements with ten major producer customers.

We currently have over 2.2 Bcf/d processing capacity operational in our Marcellus segment and have approximately 1.9 Bcf/d under development.

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· Eagle Ford Shale. In April 2013, we announced the execution of long-term fee-based agreements with Newfield Exploration Co. (“Newfield”) for the development of a gathering system and associated storage services in the Eagle Ford Shale of south Texas. We operate natural gas gathering pipelines and field compression to support production from Newfield’s West Asherton area in Dimmit County, Texas (“West Asherton facilities”).

The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by segment, for the three months ended March 31, 2014:

	Marcellus		Utica		Northeast		Southwest
Segment revenue	34	%	4	%	12	%	50	%
Net operating margin	46	%	6	%	13	%	35	%

Segment Operating Results

Items below Income from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual business segments. Management does not consider these items allocable to or controllable by any individual business segment and therefore excludes these items when evaluating segment performance. The segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests. The tables below present financial information, as evaluated by management, for the reported segments for the three months ended March 31, 2014 and 2013.

The information includes net operating margin, a non-GAAP financial measure. See above for a reconciliation of net operating margin to Income from operations, the most comparable GAAP financial measure. This section should be read in conjunction with the Operating Data table later in this Item 2 and the contract mix table included above in the section titled Our Contracts.

Three months ended March 31, 2014 compared to three months ended March 31, 2013

Marcellus

	Three months ended March 31,
	2014		2013		$ Change		% Change
	(in thousands)
Segment revenue	$	175,159	$	108,497	$	66,662	61	%
Purchased product costs	34,290		18,793		15,497		82	%
Net operating margin	140,869		89,704		51,165		57	%
Facility expenses	35,473		22,636		12,837		57	%

Operating income before items not allocated to segments	$	105,396	$	67,068	$	38,328	57	%

Segment Revenue. Revenue increased due to the ongoing expansion of the Marcellus segment operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $44.8 million due to an increase in gathering, processing and fractionation fees, of which approximately $14.8 million is due to the opening of the Sherwood and Mobley Complexes. Additionally, approximately $8.1 million of the revenue increase occurred at our Majorsville Complex and the remaining increase was in fees related to increased volumes at our Houston facility. Revenue also increased approximately $20.4 million primarily due to increased inventory available for sale as well as a 16% increase in weighted average NGL sales prices.

Purchased Product Costs. Purchased product costs increased primarily due to an increase in inventory sold.

Net Operating Margin. Net operating margin increased as the volume of natural gas gathered, processed, and fractionated increased by 18%, 98% and 215%, respectively. Approximately 81% of the net operating margin is earned under fee-based contracts.

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

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Utica

	Three months ended March 31,
	2014		2013			$ Change		% Change
	(in thousands)
Segment revenue	$	23,766	$	623		$	23,143	3,715	%
Purchased product costs	4,135		—			4,135		N/A
Net operating margin	19,631		623			19,008		3,051	%
Facility expenses	11,852		3,962			7,890		199	%
Portion of operating income (loss) attributable to non-controlling interests	3,136		(1,339		)	4,475		(334	)%
Operating income (loss) before items not allocated to segments	$	4,643	$	(2,000	)	$	6,643	(332	)%

The results of operations for the quarter ended March 31, 2014 include our operations in the Utica Shale areas of eastern Ohio. The first phase of operations began in the third quarter of 2012 and remained in the early stages of development at March 31, 2013. Operations will continue to grow as we add 400 MMcf/d cryogenic capacity through the end of 2014.

Segment Revenue. Revenue increased $23.1 million, $7.5 million of which was due to processing fee revenue increases due to the fact that we were processing for eight producer customers during the first quarter 2014 as compared to one in the first quarter 2013. Approximately $7.3 million of the increase is due to an increase in gathering fees revenue as we were gathering for seven producers in the first quarter 2014 as compared to one in the first quarter 2013. Approximately $2.9 million of the increase was due to NGL sales of local inventory, $2.7 million of the increase was due to an increase in fractionation fees resulting from the increase in fractionation volumes and $2.4 million of the increase was due to increases in compression fees resulting from the increase in gathered volumes.

Purchased Product Costs. Purchased product costs increased due to an increase in inventory sold, a decline in the value of line fill and $0.8 million amortization of deferred contract costs.

Net Operating Margin. Net operating margin increased due to an overall increase in operations in the first quarter 2014 compared to the same period in 2013. All of our gathering and processing contracts in the Utica segment are fee based and the increase in net operating margin was due to the volume of natural gas gathered and processed increasing by 1,907% and 3,081%, respectively.

Facility Expenses. Facility expenses increases in 2014 are due to the significant increase in operations as compared to 2013 related to start-up and other costs that cannot be capitalized.

Northeast

	Three months ended March 31,
	2014		2013		$ Change		% Change
	(in thousands)
Segment revenue	$	61,253	$	57,336	$	3,917	7	%
Purchased product costs	20,455		19,662		793		4	%
Net operating margin	40,798		37,674		3,124		8	%
Facility expenses	7,114		6,524		590		9	%
Operating income before items not allocated to segments	$	33,684	$	31,150	$	2,534	8	%

Segment Revenue. Revenue increased due to higher NGL and natural gas sales prices, partially offset by an approximately 20% decrease in NGL sales volumes over the same period in 2013.

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Purchased Product Costs. Purchased product costs increased slightly due to an increase in NGL prices and natural gas purchased prices, offset by lower volumes.

Net Operating Margin. Net operating margin increased due to overall frac spread margins, which increased by approximately 33% as compared to the first quarter 2013, partially offset by a decline of NGL sales volumes. Approximately 68% of the net operating margin was derived from commodity sensitive keep-whole contracts.

Facility Expenses. Facility expenses increased due primarily to an increase in plant operating expenses attributable to the timing of normal facility maintenance and repairs.

Southwest

	Three months ended March 31,
	2014			2013		$ Change			% Change
	(in thousands)
Segment revenue	$	259,329		$	208,366	$	50,963		24	%
Purchased product costs	152,684			114,102		38,582			34	%
Net operating margin	106,645			94,264		12,381			13	%
Facility expenses	32,521			28,689		3,832			13	%
Portion of operating (loss) income attributable to non-controlling interests	(1		)	64		(65		)	(102	)%
Operating income before items not allocated to segments	$	74,125		$	65,511	$	8,614		13	%

Segment Revenue. Revenue increased due to higher NGL sales, gas sales and higher fee-based revenue. NGL sales increased approximately $32.7 million due to increased volumes in our East Texas and Gulf Coast areas of 30% and 12%, respectively. Gas sales increased approximately $10.2 million in the Western Oklahoma area where we are operating in higher percentage of ethane rejection than the same period in 2013, whereby ethane was sold in the gas stream due to the higher gas prices. Processing fee revenue increased by approximately $4.6 million due to an increase in volumes in Western Oklahoma and East Texas of 34% and 8%, respectively. The 34% increase in the Western Oklahoma area primarily relates to the new Buffalo Creek processing plant that began processing in February 2014.

Purchased Product Costs. Purchased product costs increased due to higher NGL purchases of approximately $15.8 million related to the East Texas area increasing volumes processed, change in contract terms and higher pricing. Approximately $17.2 million increased in our Western Oklahoma area due to approximately 41% higher prices in the Western Oklahoma area for three months ended March 31, 2014 compared to the same period in 2013. Gas purchases increased by approximately $8.0 million in our Western Oklahoma area primarily related to approximately a 65% increase in gas prices for the three months ended March 31, 2014 compared to the same period in 2013. These increases were partially offset by lower processing expense of $1.4 million in our Western Oklahoma area.

Net Operating Margin. Net operating margin increased mainly due to margins earned from acquisitions that occurred after March 31, 2013, an increase of 8% in natural gas processed in East Texas, increased volumes in Gulf Coast due to a reduction in customer outages from the prior year and increased propane prices, partially offset by, the increased purchase price of natural gas and reductions in volumes in Southeast Oklahoma.

Facility Expenses. Facility expenses increased primarily due to $2.4 million of expenses relating to the Buffalo Creek and West Asherton facilities acquired in 2013.

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

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income (loss) before provision for income tax for the three months ended March 31, 2014 and 2013, 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 March 31,
	2014			2013			$ Change			% Change
	(in thousands)
Total segment revenue	$	517,936		$	374,822		$	143,114		38	%
Derivative loss not allocated to segments	(3,967		)	(185		)	(3,782		)	(2,044	)%
Revenue deferral adjustment and other	(1,493		)	(1,364		)	(129		)	(9	)%
Total revenue	$	512,476		$	373,273		$	139,203		37	%

Operating income before items not allocated to segments	$	217,848		$	161,729		$	56,119		35	%
Portion of operating income (loss) attributable to non-controlling interests	3,135			(1,275		)	4,410			346	%
Derivative gain not allocated to segments	4,099			10,851			(6,752		)	(62	)%
Revenue deferral adjustment and other	(1,493		)	(1,364		)	(129		)	(9	)%
Compensation expense included in facility expenses not allocated to segments	(1,004		)	(387		)	(617		)	(159	)%
Facility expenses adjustments	2,688			2,688			—			0	%
Selling, general and administrative expenses	(35,290		)	(25,242		)	(10,048		)	(40	)%
Depreciation	(101,929		)	(68,017		)	(33,912		)	(50	)%
Amortization of intangible assets	(15,978		)	(14,830		)	(1,148		)	(8	)%
Gain (loss) on disposal of property, plant and equipment	93			(138		)	231			167	%
Accretion of asset retirement obligations	(168		)	(352		)	184			52	%
Income from operations	72,001			63,663			8,338			13	%
Earnings from unconsolidated affiliates	250			235			15			6	%
Interest income	9			149			(140		)	(94	)%
Interest expense	(40,984		)	(38,336		)	(2,648		)	(7	)%
Amortization of deferred financing costs and discount (a component of interest expense)	(2,824		)	(1,830		)	(994		)	(54	)%
Loss on redemption of debt	—			(38,455		)	38,455			100	%
Miscellaneous income, net	10			—			10			N/A
Income (loss) before provision for income tax	$	28,462		$	(14,574	)	$	43,036		295	%

Derivative Gain Not Allocated to Segments. Unrealized gain from the change in fair value of our derivative instruments was $11.8 million for the three months ended March 31, 2014 compared to an unrealized gain of $9.0 million for the same period in 2013. Realized loss from the settlement of our derivative instruments was $7.7 million for the three months ended March 31, 2014 compared to a realized gain of $1.8 million for the same period in 2013. The total change of $6.8 million is due primarily to volatility in commodity prices.

Revenue Deferral Adjustment and Other. 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

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Operating Data

	Three months ended March 31,
	2014	2013	% Change
Marcellus
Gathering system throughput(Mcf/d) (1)	601,500	509,200	18	%
Natural gas processed (Mcf/d)	1,640,800	828,100	98	%

C2 (purity ethane) produced (Bbl/d)	46,200	—	N/A
C3+ fractionated (Bbl/d) (2)	70,300	37,000	90	%
Total NGLs fractionated (Bbl/d)	116,500	37,000	215	%

Utica
Gathering system throughput (Mcf/d)	180,600	9,000	1,907	%
Natural gas processed (Mcf/d) (3)	251,300	7,900	3,081	%
C3+ NGLs fractionated (Bbl/d) (2)	12,100	—	N/A

Northeast
Natural gas processed (Mcf/d)	255,600	302,600	(16	)%
NGLs fractionated (Bbl/d) (4)	17,400	17,100	2	%

Keep-whole NGL sales (gallons, in thousands)	32,200	37,400	(14	)%
Percent-of-proceeds NGL sales (gallons, in thousands)	26,000	34,900	(26	)%
Total NGL sales (gallons, in thousands) (5)	58,200	72,300	(20	)%

Crude oil transported for a fee (Bbl/d)	9,900	10,300	(4	)%

Southwest
East Texas gathering systems throughput (Mcf/d)	495,800	500,300	(1	)%
East Texas natural gas processed (Mcf/d)	368,100	339,500	8	%
East Texas NGL sales (gallons, in thousands) (6)	93,900	72,200	30	%

Western Oklahoma gathering system throughput (Mcf/d) (7)	296,900	202,600	47	%
Western Oklahoma natural gas processed (Mcf/d)	250,100	186,300	34	%
Western Oklahoma NGL sales (gallons, in thousands) (8)	53,900	54,800	(2	)%

Southeast Oklahoma gathering systems throughput (Mcf/d)	381,800	461,300	(17	)%
Southeast Oklahoma natural gas processed (Mcf/d) (9)	147,300	151,200	(3	)%
Southeast Oklahoma NGL sales (gallons, in thousands)	21,000	39,300	(47	)%

Other Southwest gathering system throughput (Mcf/d) (10)	46,900	20,600	128	%

Gulf Coast refinery off-gas processed (Mcf/d)	110,500	95,300	16	%
Gulf Coast liquids fractionated (Bbl/d) (11)	19,300	17,200	12	%
Gulf Coast NGL sales (gallons, in thousands) (11)	73,000	65,100	12	%

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(1) The 2013 volumes exclude Sherwood gathering for comparability as this system was sold to Summit in June 2013.

(2) The Marcellus segment includes both the Houston Fractionation and Marcellus’ portion utilized of the jointly owned Hopedale Fractionation. Hopedale is currently jointly owned 60% and 40% by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. The Utica segment includes only the portion it utilized of the jointly owned Hopedale Fractionation. Operations began in January 2014. The volumes reported for 2014 are the average daily rate for the days of operation.

(3) Utica operations began in August 2013.

(4) Includes NGLs fractionated for Utica and Marcellus segments.

(5) Represents sales at the Siloam fractionator. The total sales exclude approximately 13,254,000 gallons and 207,000 gallons sold by the Northeast on behalf of Marcellus for the three months ended March 31, 2014 and 2013, respectively.

(6) Excludes approximately 317,500 gallons and 8,362,300 gallons processed in conjunction with take in kind contracts for the three months ended March 31, 2014 and March 31, 2013, respectively.

(7) Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as management considers this one integrated area of operations.

(8) Excludes approximately 11,716,200 gallons processed in conjunction with take in kind contracts for the three months ended March 31, 2014.

(9) The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma or other third-party processors.

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

(11) Excludes Hydrogen volumes.

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 2014 capital plan is summarized in the table below (in millions):

	2014 Full Year Plan						Actual
							Three months ended
	Low			High			March 31, 2014
Consolidated growth capital (1)	$	2,400		$	3,000		$	584
Joint venture partner’s estimated share of growth capital	(600		)	(700		)	(0		)
Partnership share of growth capital	$	1,800		$	2,300		$	584

(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 was approximately $2.7 million for the three months ended March 31, 2014. It includes capital expenditures made to maintain our operating capacity and asset base.

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.

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Management believes that expenditures for our capital projects can be funded with current cash balances, proceeds from equity or debt offerings, contributions from joint venture partners, cash flows from operations and our current borrowing capacity under the Credit Facility. 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 any future equity offerings we may commence after July 1, 2014; 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 the capital markets to fund our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings assigned by independent rating agencies. As of April 30, 2014, our credit ratings for our Senior Notes were Ba2 with a Stable outlook by Moody’s Investors Service and BB with a Stable outlook by Standard & Poor’s. Our investment grade Credit Facility is rated BBB- by Standard & Poor’s. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

Debt Financing Activities

On March 20, 2014, we amended the Credit Facility to increase total borrowing capacity to $1.3 billion, extend the maturity by approximately 18 months to March 20, 2019, amend the pricing terms, expand the existing accordion option from $250 million to $500 million and provide us with a the right to release collateral securing the Credit Facility once our Index Debt has received an investment grade rating from Standard & Poor’s equal to or more favorable than BBB- (stable) and from Moody’s equal to or more favorable than Baa3 (stable) and our Total Leverage Ratio is not greater than 5.00 to 1.00. We incurred approximately $1.9 million of deferred financing costs associated with modifications of the Credit Facility during the quarter ended March 31, 2014.

The borrowings under the Credit Facility bear interest at a variable interest rate, plus basis points. The variable interest rate is based either on the London interbank market rate (“LIBO Rate Loans”) or the higher of (a) the prime rate set by the Credit Facility’s administrative agent, (b) the Federal Funds Rate plus 0.50% and (c) the rate for LIBO Rate Loans for a one month interest period plus 1% (“Alternate Base Rate Loans”). Prior to the Collateral Release Date, the basis points correspond to our Total Leverage Ratio (as defined in the Credit Facility), ranging from 0.5% to 1.5% for Alternate Base Rate Loans and from 1.5% to 2.5% for LIBO Rate Loans. After the Collateral Release Date, the basis points correspond to the credit rating for our Index Debt issued by Moody’s and Standard & Poor’s, ranging from 0.125% to 1% for Alternate Base Rate Loans and from 1.125% to 2% for LIBO Rate Loans. We may utilize up to $150.0 million of the Credit Facility for the issuance of letters of credit and $10.0 million for shorter-term swingline loans.

Under the provisions of the Credit Facility, we are subject to a number of restrictions and covenants. As of March 31, 2014, we were in compliance with all of our debt covenants and we expect to remain in compliance for at least the next twelve months. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of April 30, 2014, we had approximately $482.8 million borrowings outstanding and approximately $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $805.9 million of unused capacity, of which approximately $439 million was available for borrowing based on financial covenant requirements. Additionally, the full amount of unused capacity is available for borrowing on a short term basis to provide financial flexibility within a given fiscal quarter.

The Credit Facility and indentures governing the Senior Notes limit our and our restricted subsidiaries’ 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 limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. Under the Credit Facility, neither we nor the bank can require margin calls for outstanding derivative positions. As of April 30, 2014, all of our financial derivative positions are with members of the syndicated bank group and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to

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enter into derivative instruments without utilizing cash for margin calls or requiring the use of letters of credit. We believe the recent Dodd-Frank legislation will not change our ability to enter into derivatives without utilizing margin calls.

Equity Financing Activities

On September 5, 2013, we and M&R MWE Liberty, LLC (the “Selling Unitholder”) entered into an Equity Distribution Agreement with the Manager that established the September 2013 ATM pursuant to which we may sell from time to time through the 2013 Manager, as our sales agent, common units having an aggregate offering price of up to $1 billion. In addition, the Selling Unitholder may sell from time to time through the 2013 Manager up to 794,761 common units. During the three months ended March 31, 2014, we sold an aggregate of 4.2 million common units under the September 2013 ATM, receiving net proceeds of approximately $272 million after deducting approximately $3.5 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general Partnership purposes. During the three months ended March 31, 2014, the Selling Unitholder sold an aggregate of 222,897 of their common units under the September 2013 ATM Agreement, receiving net proceeds of approximately $14.3 million after deducting approximately $0.1 million in manager fees. We completed the September 2013 ATM on March 31, 2014.

On March 11, 2014, we and the Selling Unitholder entered into an Equity Distribution Agreement with the 2014 Managers that established the March 2014 ATM pursuant to which we may sell from time to time through the 2014 Managers, as our sales agents, common units having an aggregate offering price of up to $1.2 billion. In addition, the Selling Unitholder may sell from time to time through the 2014 Managers up to 4,031,075 common units (including 3,990,878 common units into which an equal number of the Selling Unitholder’s Class B Units will convert on July 1, 2014, such units being the “Class B Units” common units). During the three months ended March 31, 2014, no units were sold under the March 2014 ATM.

Class B Common Units

The remaining Class B units will convert to common units on a one-for-one basis in four equal installments beginning on July 1, 2014 and each of the next three anniversaries of such date. Class B units share in our income and losses and are not entitled to participate in any distributions of available cash prior to their conversion.

Joint Venture Partners

Pursuant to the Amended Utica LLC Agreement, EMG was obligated to fund the first $950.0 million of capital required by MarkWest Utica EMG and they completed this funding commitment in May 2013. We began funding MarkWest Utica EMG in July 2013 and have contributed approximately $799.4 million as of March 31, 2014. We are required to contribute 100% of the additional capital required by MarkWest Utica EMG until the aggregate contributions from us and EMG equal $2.0 billion. For further discussion of the funding requirements after $2.0 billion has been contributed to MarkWest Utica EMG, see Note 2 of the Notes to these Condensed Consolidated Financial Statements. In December 2013, we and EMG formed Utica Condensate. EMG is obligated to provide the first $100 million of the initial funding to Utica Condensate and is expected to provide 45% of the total capital required during 2014. See Note 2 of the Notes to these Condensed Consolidated Financial Statements for further discussion of the funding obligations for Utica Condensate. We anticipate additional funding in 2014 from joint venture partners due to the anticipated exercise by Summit of its options to acquire up to a 40% interest in both Ohio Gathering and Ohio Condensate.

Liquidity Risks and Uncertainties

Our ability to pay distributions to our unitholders, 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 our significant growth strategy and the length of the construction period for our assets, we spend a significant amount of capital prior to the realization of the revenues from our expansion projects. Many factors could impact our ability to generate the expected revenues and the timing of those revenues from our expansion projects including:

· unexpected changes in the production from our producer customers’ wells or changes in our producer customers’ drilling schedules except where we have minimum volume commitments;

· unexpected outages or downtime at our facilities or at upstream or downstream third party facilities;

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· market and capacity constraints affecting downstream natural gas and NGL facilities, including limited gas and NGL capacity downstream of our facilities, limited railcar and NGL pipeline facilities and reduced demand or limited markets for certain NGL products, which could reduce the volumes of gas and NGLs that we receive and adversely affect the pricing received for NGLs; and

· restrictions on the ability of our joint ventures to distribute cash to the Partnership.

If we are unable to generate the expected revenues from our expansion projects, our liquidity would be adversely impacted, which may also impact our ability to meet our financial and other covenants under our Credit Facility and indentures governing the Senior Notes.

Cash Flow

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

	Three months ended March 31,
	2014			2013			Change
Net cash provided by operating activities	$	112,373		$	83,758		$	28,615
Net cash used in investing activities	(575,474		)	(609,361		)	33,887
Net cash provided by financing activities	501,277			831,356			(330,079		)

Net cash provided by operating activities increased primarily due to an improvement in cash flows generated from expanded operations primarily due to an increase in segment operating income before items not allocated to segments, offset by a decrease of approximately $8.0 million change in working capital, primarily due to approximately a $10.4 million decrease in inventory.

Net cash used in investing activities decreased primarily due to a $44.4 million decrease in capital expenditures, primarily related to our expansion of our Marcellus and Utica segments as discussed in our Segment Reporting section above, and by proceeds of approximately $17.0 million from sale to an unconsolidated subsidiary, partially offset by a release of $25 million of restricted cash.

Net cash provided by financing activities decreased primarily due to a $385.2 million decrease in contributions from non-controlling interest holders, a $121.6 million decrease in net borrowings, a $30.5 million increase in distributions to unit holders, partially offset by a $167.9 million increase in proceeds from public equity offerings and an increase of $31.5 million related to the first quarter 2013 payment of premiums on redemption of long term debt.

Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of March 31, 2014, our purchase obligations were $628.8 million compared to our obligations of $681.8 million as of December 31, 2013. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

Critical Accounting Policies

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

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Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	118,198	$	0.92	$	(4,975	)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	15,325	$	1.46	$	694

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	41,546	$	1.36	$	954

The following tables provide information on the volume of our taxable subsidiary’s commodity derivative activity for positions related to keep-whole price risk at March 31, 2014, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)	Fair Value (in thousands)
2014	152	89.58	$	(341	)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2014	8,663	$	4.89	$	(1,476	)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	64,439	$	1.06	$	(428	)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	7,465	$	1.44	$	308

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	20,267	$	1.37	$	744

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	7,107	$	2.31	$	430

The following tables provide information on the volume of MarkWest Liberty Midstream’s commodity derivative activity for positions related to long liquids price risk at March 31, 2014, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2014	357	$	91.42	$	(615	)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	60,316	$	1.10	$	341

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	8,126	$	1.47	$	386

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	19,646	$	1.37	$	681

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Natural Gasoline	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	8,400	$	1.98	$	(245	)

The following table provides information on the derivative positions related to long liquids and keep-whole price risk that we have entered into subsequent to March 31, 2014, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)
2015 (Jan — Mar)	833	$	93.02

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 March 31, 2014, the estimated fair value of this contract was a liability of $85.5 million and the recorded value was a liability of $32.0 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception on February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of March 31, 2014 (in thousands):

Fair value of commodity contract	$	85,537
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of March 31, 2014	$	32,030

We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at one of our plant locations through the fourth quarter of 2014. The value of the derivative component of this contract is marked to market through Derivative gain related to facility expenses. As of March 31, 2014, the estimated fair value of this contract was an asset of $3.5 million.

Interest Rate Risk

Our primary interest rate risk exposure results from our Credit Facility which has a borrowing capacity of $1.3 billion. The applicable interest rate for our Credit Facility was 4.5% at March 31, 2014. As of April 30, 2014, we have $482.8 million borrowings outstanding on our Credit Facility. The debt under the Credit Facility bears interest at variable rates that are tied to either the U.S. prime rate or LIBOR at the time of borrowing.

We may make use of interest rate swap agreements in the future to adjust the ratio of fixed and floating rates in our debt portfolio, however we had no interest rate swaps outstanding as of March 31, 2014. Our debt portfolio as of March 31, 2014 is shown in the following table.

Long-Term Debt	Interest Rate	Lending Limit	Due Date	Outstanding at March 31, 2014
Credit Facility	Variable	$ 1.3 billion	March 2019	$ 377.3 million
2020 Senior Notes	Fixed	$ 500.0 million	November 2020	$ 500.0 million
2021 Senior Notes	Fixed	$ 325.0 million	August 2021	$ 325.0 million
2022 Senior Notes	Fixed	$ 455.0 million	June 2022	$ 455.0 million
2023A Senior Notes	Fixed	$ 750.0 million	February 2023	$ 750.0 million
2023B Senior Notes	Fixed	$ 1.0 billion	July 2023	$ 1.0 billion

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Based on our overall interest rate exposure at March 31, 2014, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our Credit Facility would change pre-tax earnings by approximately $3.8 million over a twelve-month period. Based on our overall interest rate exposure at April 30, 2014, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our Credit Facility would change pre-tax earnings by approximately $4.8 million over a twelve-month period.

Credit Risk

The information about our credit risk for the three months ended March 31, 2014 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, 2013.

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 Securities and Exchange Act of 1934, as amended (the “1934 Act”), as of March 31, 2014. Based on this evaluation, the Partnership’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of March 31, 2014, 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 March 31, 2014 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

In connection with construction activities in eastern Ohio, MarkWest Utica EMG has experienced, and continues to experience, incidents of inadvertent returns of a bentonite clay solution used during construction of borings under areas primarily involving reclaimed strip coal mine lands. MarkWest Utica EMG self-reported these incidents to the Ohio Environmental Protection Agency (“OEPA”) and has remediated any impacts from these bentonite-clay inadvertent returns. There was no adverse impact on human health from these incidents and the impact to the receiving areas was a temporary physical sedimentation impact, without any chemicals or additives involved. OEPA has initiated an administrative enforcement action, although the amount of penalties or other administrative remedies has not yet been determined.

On March 21, 2014, MarkWest Liberty Midstream received a Draft Consent Order from the West Virginia Department of Environmental Protection (“WVDEP”) incorporating 16 separate inspections in 2013 of various operations and construction sites with claimed regulatory violations relating to erosion and sediment control measures, the August 2013 NGL pipeline break in Wetzel County and associated issues, pipeline borings, and other disparate matters. The Draft Consent Order aggregates those matters and proposes a total aggregate administrative penalty of $115,120 for all of the

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Item 6. Exhibits

3.1		Certificate of Limited Partnership of MarkWest Energy Partners, L.P. (incorporated by reference to the Registration Statement (No. 33-81780) on Form S-1 filed January 31, 2002).

3.2		Certificate of Formation of MarkWest Energy GP, L.L.C. (incorporated by reference to the Registration Statement (No. 33-81780) on Form S-1 filed January 31, 2002).

3.3		Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated as of February 21, 2008 (incorporated by reference to the Current Report on Form 8-K filed February 21, 2008).

3.4		Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of May 24, 2002 (incorporated by reference to the Current Report on Form 8-K filed June 7, 2002).

3.5		Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of December 31, 2004 (incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009).

3.6		Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of January 19, 2005 (incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009).

3.7		Amendment No. 3 to Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of February 21, 2008 (incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009).

3.8		Amendment No. 4 to Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of March 31, 2008 (incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009).

3.9		Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated December 29, 2011 (incorporated by reference to the Current Report on Form 8-K filed December 30, 2011).

4.1*		Acknowledgment of Release of Subsidiary Guarantor dated March 20, 2014 issued by Wells Fargo Bank, National Association.

10.1		New Lender Agreement and Sixth Amendment to Amended and Restated Credit Agreement dated as of March 20, 2014, among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto (incorporated by reference to the Form 8-K Current Report filed March 20, 2014).

10.2		Equity Distribution Agreement dated as of March 11, 2014, among MarkWest Energy Partners, L.P., MarkWest Energy Operating Company, L.L.C., M&R MWE Liberty, LLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and UBS Securities LLC (incorporated by reference to the Form 8-K Current Report filed March 11, 2014).

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.

Delaware		27-0005456
(State or other jurisdiction of		(IRS Employer
incorporation or organization)		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
Condensate		A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
Credit Facility		Amended and restated revolving credit agreement, as amended from time to time
DER		Distribution equivalent right
Dth/d		Dekatherms per day
ERCOT		Electric Reliability Council of Texas
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, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss)
NGL		Natural gas liquids, such as ethane, propane, butanes and natural gasoline
N/A		Not applicable
OTC		Over-the-Counter
SEC		United States Securities and Exchange Commission
SMR		Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation facility in Corpus Christi, Texas
VIE		Variable interest entity
WTI		West Texas Intermediate

PART I—FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
	Unaudited Condensed Consolidated Balance Sheets at March 31, 2014 and December 31, 2013	4
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2014 and 2013	5
	Unaudited Condensed Consolidated Statements of Changes in Equity for the three months ended March 31, 2014 and 2013	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2014 and 2013	7
	Unaudited Notes to the Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	48
Item 4.	Controls and Procedures	51
PART II—OTHER INFORMATION		51
Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	52
Item 6.	Exhibits	53
SIGNATURES		55

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2014	1,418	$	90.25	$	108.65	$	359

	MarkWest Energy Partners, L.P.
	(Registrant)

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

Date: May 7, 2014		/s/ FRANK M. SEMPLE
		Frank M. Semple
		Chairman, President & Chief Executive Officer
		(Principal Executive Officer)


Date: May 7, 2014		/s/ NANCY K. BUESE
		Nancy K. Buese
		Executive Vice President & Chief Financial Officer
		(Principal Financial Officer)


Date: May 7, 2014		/s/ PAULA L. ROSSON
		Paula L. Rosson
		Senior Vice President & Chief Accounting Officer
		(Principal Accounting Officer)