UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2013

OR

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

For the transition period from          to          

Commission File Number 001-31239

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes x No o

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

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

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

As of May 1, 2013, the number of the registrant’s common units and Class B units outstanding were 130,362,380 and 19,954,389, respectively.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	4
	Unaudited Condensed Consolidated Balance Sheets at March 31, 2013 and December 31, 2012	4
	Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2013 and 2012	5
	Unaudited Condensed Consolidated Statements of Changes in Equity for the three months ended March 31, 2013 and 2012	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2013 and 2012	7
	Unaudited Notes to the Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	43
Item 4.	Controls and Procedures	46
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 6.	Exhibits	48
SIGNATURES		50

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

2

Glossary of Terms

Bbl	Barrel
Bbl/d	Barrels per day
Bcf/d	Billion cubic feet per day
Btu	One British thermal unit, an energy measurement
Credit Facility	Amended and restated revolving credit agreement
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	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

3

PART I—FINANCIAL INFORMATION

Item 1.  Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	March 31, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents ($150,728 and $33,727, respectively)	$	654,170		$	347,899
Restricted cash ($500 and $500, respectively)	500			25,500
Receivables, net ($1,248 and $1,591, respectively)	212,957			198,769
Inventories	20,514			24,633
Fair value of derivative instruments	16,814			19,504
Deferred income taxes	2,993			5,281
Other current assets ($1,594 and $264, respectively)	24,070			35,053
Total current assets	932,018			656,639
Property, plant and equipment ($888,402 and $568,063, respectively)	6,380,671			5,700,176
Less: accumulated depreciation ($30,670 and $24,636, respectively)	(688,724		)	(624,548		)
Total property, plant and equipment, net	5,691,947			5,075,628
Other long-term assets:
Restricted cash	10,000			10,000
Investment in unconsolidated affiliate	34,106			31,179
Intangibles, net of accumulated amortization of $236,245 and $221,416, respectively	840,326			855,155
Goodwill	142,174			142,174
Deferred financing costs, net of accumulated amortization of $20,218 and $18,567, respectively	56,995			51,145
Deferred contract cost, net of accumulated amortization of $2,652 and $2,574, respectively	598			676
Fair value of derivative instruments	10,181			10,878
Other long-term assets ($102 and $102, respectively)	2,209			2,242
Total assets	$	7,720,554		$	6,835,716
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($81,992 and $73,883, respectively)	$	300,056		$	320,645
Accrued liabilities ($136,794 and $110,746, respectively)	435,483			391,352
Fair value of derivative instruments	23,060			27,229
Total current liabilities	758,599			739,226
Deferred income taxes	211,091			191,318
Fair value of derivative instruments	23,938			32,190
Long-term debt, net of discounts of $7,479 and $8,061, respectively	3,022,521			2,523,051
Other long-term liabilities ($80 and $79, respectively)	137,856			134,340
Commitments and contingencies (Note 9)
Redeemable non-controlling interest (Note 3)	326,249			—
Equity:
Common units (129,576 and 127,494 common units issued and outstanding, respectively)	2,106,605			2,134,714
Class B units (19,954 units issued and outstanding)	752,531			752,531
Non-controlling interest in consolidated subsidiaries	381,164			328,346
Total equity	3,240,300			3,215,591
Total liabilities and equity	$	7,720,554		$	6,835,716

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

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

4

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Operations

(unaudited, in thousands, except per unit amounts)

	Three months ended March 31,
	2013			2012
Revenue:
Revenue	$	376,137		$	399,181
Derivative loss	(185		)	(48,715		)
Total revenue	375,952			350,466
Operating expenses:
Purchased product costs	152,557			154,555
Derivative (gain) loss related to purchased product costs	(10,704		)	18,800
Facility expenses	59,755			48,840
Derivative gain related to facility expenses	(332		)	(1,746		)
Selling, general and administrative expenses	25,408			25,224
Depreciation	69,597			41,145
Amortization of intangible assets	14,830			10,985
Loss on disposal of property, plant and equipment	138			986
Accretion of asset retirement obligations	353			238
Total operating expenses	311,602			299,027
Income from operations	64,350			51,439
Other (expense) income:
Loss from unconsolidated affiliate	(85		)	(9		)
Interest income	149			72
Interest expense	(38,336		)	(29,472		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,830		)	(1,270		)
Loss on redemption of debt	(38,455		)	—
Miscellaneous income, net	—			58
(Loss) income before provision for income tax	(14,207		)	20,818
Provision for income tax (benefit) expense:
Current	(5,414		)	15,341
Deferred	11,971			(10,796		)
Total provision for income tax	6,557			4,545
Net (loss) income	(20,764		)	16,273
Net loss (income) attributable to non-controlling interest	5,304			(253		)
Net (loss) income attributable to the Partnership’s unitholders	$	(15,460	)	$	16,020
Net (loss) income attributable to the Partnership’s common unitholders per common unit (Note 11):
Basic	$	(0.12	)	$	0.16
Diluted	$	(0.12	)	$	0.14
Weighted average number of outstanding common units:
Basic	128,615			96,840
Diluted	128,615			117,593
Cash distribution declared per common unit	$	0.82		$	0.76

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

5

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, 2012	127,494	$	2,134,714		19,954	$	752,531	$	328,346		$	3,215,591		$	—
Issuance of units in public equity offerings, net of offering costs	1,921	103,937			—	—		—			103,937			—
Distributions paid	—	(105,945		)	—	—		(848		)	(106,793		)	—
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	—	(10,088		)	—	—		—			(10,088		)	—
Net loss	—	(15,460		)	—	—		(5,304		)	(20,764		)	—
March 31, 2013	129,576	$	2,106,605		19,954	$	752,531	$	381,164		$	3,240,300		$	326,249

	Common Units				Class B Units			Non- controlling
	Units	Amounts			Units	Amounts		Interest			Total Equity
December 31, 2011	94,940	$	679,309		19,954	$	752,531	$	70,227		$	1,502,067
Issuance of units in public equity offerings, net of offering costs	7,508	425,629			—	—		—			425,629
Distributions paid	—	(73,410		)	—	—		(1,962		)	(75,372		)
Contributions from non-controlling interest	—	—			—	—		755			755
Share-based compensation activity	246	(2,343		)	—	—		—			(2,343		)
Excess tax benefits related to share-based compensation	—	2,207			—	—		—			2,207
Deferred income tax impact from changes in equity	—	(16,915		)	—	—		—			(16,915		)
Net income	—	16,020			—	—		253			16,273
March 31, 2012	102,694	$	1,030,497		19,954	$	752,531	$	69,273		$	1,852,301

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

6

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Cash Flows

(unaudited, in thousands)

	Three months ended March 31,
	2013			2012
Cash flows from operating activities:
Net (loss) income	$	(20,764	)	$	16,273
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	69,597			41,145
Amortization of intangible assets	14,830			10,985
Loss on redemption of debt	38,455			—
Amortization of deferred financing costs and discount	1,830			1,270
Accretion of asset retirement obligations	353			238
Amortization of deferred contract cost	78			78
Phantom unit compensation expense	4,002			5,709
Equity in loss of unconsolidated affiliate	85			9
Distributions from unconsolidated affiliate	—			900
Unrealized (gain) loss on derivative instruments	(9,033		)	48,217
Loss on disposal of property, plant and equipment	138			986
Deferred income taxes	11,971			(10,796		)
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	(14,026		)	30,279
Inventories	4,119			23,812
Other current assets	10,983			3,503
Accounts payable and accrued liabilities	(30,561		)	32,556
Other long-term assets	33			61
Other long-term liabilities	2,953			2,688
Net cash provided by operating activities	85,043			207,913
Cash flows from investing activities:
Restricted cash	25,000			1,003
Capital expenditures	(631,558		)	(254,263		)
Investment in unconsolidated affiliate	(3,012		)	—
Proceeds from disposal of property, plant and equipment	209			291
Net cash flows used in investing activities	(609,361		)	(252,969		)
Cash flows from financing activities:
Proceeds from public equity offerings, net	103,937			425,629
Proceeds from Credit Facility	—			13,700
Payments of Credit Facility	—			(79,700		)
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	(14,046		)	—
Contributions from non-controlling interest	385,219			755
Payments of SMR liability	(545		)	(497		)
Cash paid for taxes related to net settlement of share-based payment awards	(5,206		)	(8,048		)
Excess tax benefits related to share-based compensation	651			2,207
Payment of distributions to common unitholders	(105,945		)	(73,410		)
Payment of distributions to non-controlling interest	(848		)	(1,962		)
Net cash flows provided by financing activities	830,589			278,674
Net increase in cash and cash equivalents	306,271			233,618
Cash and cash equivalents at beginning of year	347,899			117,016
Cash and cash equivalents at end of period	$	654,170		$	350,634

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

7

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 formation.

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, 2012. 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, 2013 are not necessarily indicative of results for the full year 2013 or any other future period.

The Partnership’s unaudited condensed consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Utica EMG, L.L.C. and its subsidiaries (“MarkWest Utica EMG”), and MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), VIEs for which the Partnership has been determined to be the primary beneficiary, are included in the condensed consolidated financial statements (see Note 3). All intercompany investments, accounts and transactions have been eliminated. The Partnership’s investment in Centrahoma Processing, LLC (“Centrahoma”), in which the Partnership exercises significant influence but does not control and is not the primary beneficiary, is accounted for using the equity method.

2. Recent Accounting Pronouncements

In December 2011, the FASB amended the accounting guidance for balance sheet offsetting for financial assets and financial liabilities. The amended guidance is intended to help investors and other financial statement users to better assess the effect or potential effect of offsetting arrangements on a company’s financial position and provides for increased disclosures. The amended guidance is effective for the Partnership prospectively as of January 1, 2013. Except for additional disclosures included in Note 4 related to our master netting arrangements, the adoption of the amended guidance did not have a material effect on the Partnership’s condensed consolidated financial statements.

3. Variable Interest Entities

MarkWest Utica EMG

In February 2013, the Partnership and EMG Utica, LLC (“EMG Utica”) entered into the Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG (“Amended Utica LLC Agreement”)  which replaces the original agreements discussed in Note 4 to the Consolidated Financial Statements included in Item 8 of the Partnership’s Form 10-K for year ended December 31, 2012. Pursuant to the Amended Utica LLC Agreement, the aggregate funding commitment of EMG Utica has increased from $500 million to $950 million (the “Minimum EMG Investment”). As part of this commitment, EMG Utica is required to fund, as needed, all capital required for MarkWest Utica EMG until such time as EMG Utica has contributed aggregate capital equal to $750 million (the “Tier 1 EMG Contributions”). Following the funding of the Tier 1 EMG Contributions, the Partnership had the one time right to elect to fund up to 60% of all capital required for MarkWest Utica EMG until such time as EMG Utica has contributed aggregate capital equal to the Minimum EMG Investment.  The Partnership elected not to fund the 60% and therefore EMG Utica will  be required to fund all capital until the Minimum EMG Investment has been satisfied. Once EMG Utica has funded the Minimum EMG Investment, the Partnership will be required to fund, as needed, 100% of all capital for MarkWest Utica EMG until such time as the aggregate capital that has been contributed by the Partnership and EMG Utica equals $2 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.

8

Under the Amended Utica LLC Agreement, after EMG Utica has contributed more than $500 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 million. No Preference Amount will accrue to EMG Utica’s investment balance after December 31, 2016. EMG Utica did not receive a special allocation of income during the three months ended March 31, 2013 because EMG Utica’s weighted average investment balance was less than $500 million.

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 so acquired from EMG Utica.  If EMG Utica makes this election, the Partnership would be required to purchase the membership interests on or prior to 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, 2013 is reported as redeemable non-controlling interest in the mezzanine equity section of our Condensed 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 to occur 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.

In contemplation of executing the Amended Utica LLC Agreement, the Partnership and EMG Utica had executed an amendment to the original agreement in January 2013 that obligated the Partnership to temporarily fund MarkWest Utica EMG while EMG Utica completed efforts to raise additional capital to fund its remaining $150 million capital commitment under the original agreement. In February 2013, the Partnership contributed approximately $76.2 million to MarkWest Utica EMG and subsequently received a distribution of $61.2 million as reimbursement for the temporary funding. The remaining $15 million has been retained by MarkWest Utica EMG and treated as a capital contribution from the Partnership under the terms of the Amended Utica LLC Agreement.

The Partnership has determined that MarkWest Utica EMG is a VIE primarily due to the Partnership’s disproportionate economic interests as compared to its stated ownership interests and voting interests. The Partnership’s 60% ownership interest in the entity is disproportionate to its economic interest due to the timing of the capital funding requirements described above. The Partnership has concluded that it is the primary beneficiary of MarkWest Utica EMG.

MarkWest Pioneer

MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline. The Partnership and Arkoma Pipeline Partners, LLC share the equity interests in MarkWest Pioneer equally (50% and 50%). As discussed in Note 4 to the Consolidated Financial Statements in Item 8 of the Partnership’s Form 10-K for year ended December 31, 2012, the Partnership determined that MarkWest Pioneer is a VIE and the Partnership is the primary beneficiary.

9

Financial Statement Impact of VIEs

As the primary beneficiary of MarkWest Pioneer and MarkWest Utica EMG, the Partnership consolidates the entities and recognizes non-controlling interests. The following tables show the consolidated assets and liabilities attributable to MarkWest Pioneer and MarkWest Utica EMG, excluding intercompany balances, as of March 31, 2013 and December 31, 2012, respectively (in thousands):

	As of March 31, 2013
	MarkWest Pioneer		MarkWest Utica EMG		Total
ASSETS
Cash and cash equivalents	$	2,661	$	148,067	$	150,728
Restricted cash	—		500		500
Receivables, net	1,088		160		1,248
Other current assets	131		1,463		1,594
Property, plant and equipment, net of accumulated depreciation of $23,429 and $7,241, respectively	134,429		723,303		857,732
Other long-term assets	102		—		102
Total assets	$	138,411	$	873,493	$	1,011,904
LIABILITIES
Accounts payable	$	14	$	81,978	$	81,992
Accrued liabilities	1,117		135,677		136,794
Other long-term liabilities	80		—		80
Total liabilities	$	1,211	$	217,655	$	218,866

	As of December 31, 2012
	MarkWest Pioneer		MarkWest Utica EMG		Total
ASSETS
Cash and cash equivalents	$	2,143	$	31,584	$	33,727
Restricted cash	—		500		500
Receivables, net	1,188		403		1,591
Other current assets	182		82		264
Property, plant and equipment, net of accumulated depreciation of $21,849 and $2,787, respectively	136,009		407,418		543,427
Other long-term assets	102		—		102
Total assets	$	139,624	$	439,987	$	579,611
LIABILITIES
Accounts payable	$	18	$	73,865	$	73,883
Accrued liabilities	1,174		109,572		110,746
Other long-term liabilities	79		—		79
Total liabilities	$	1,271	$	183,437	$	184,708

The assets of the VIEs are the property of the respective entities and are not available to the Partnership for any other purpose, including as collateral for its secured debt (see Note 7 and Note 13). VIE asset balances can only be used to settle obligations of each respective VIE. The liabilities of the VIEs do not represent additional claims against the Partnership’s general assets, and the creditors or beneficial interest holders of the VIE do not have recourse to the general credit of the Partnership. The Partnership’s maximum exposure to loss as a result of its involvement with the VIEs includes its equity investment, any additional capital contribution commitments and any operating expense incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership may temporarily fund MarkWest Utica EMG for certain projects due to the timing of the capital call process. The Partnership will receive distributions as reimbursement for any temporary funding. Other than temporary funding, the Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the three months ended March 31, 2013 and 2012.

10

The results of operations of MarkWest Utica EMG and its subsidiaries are shown separately as the Utica segment and MarkWest Pioneer results are included in the Partnership’s Southwest segments (see Note 12). The result of operations and cash flows for MarkWest Pioneer are not material to the Partnership.

4. Derivative Financial Instruments

Commodity Derivatives

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership’s control. The Partnership’s profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its own or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of natural gas drilling by the Partnership’s producer customers, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so that the Partnership can meet its cash distribution objectives, debt service and capital expenditures, the Partnership executes a strategy governed by the risk management policy approved by the General Partner’s board of directors (the “Board”). The Partnership has a committee comprised of senior management that oversees risk management activities (the “Hedge Committee”), continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps and options traded on the OTC market 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 manages a portion of its NGL price risk using crude oil contracts, referred to as “proxy contracts”, as the NGL financial markets are not as liquid and historically there has been a strong relationship between changes in NGL and crude oil prices. During 2012 and continuing into 2013, the price of NGLs as compared to crude oil weakened significantly and as a result, our derivative financial instruments have not been as effective in offsetting the impact of NGL price declines. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the Partnership incurs increased risk and additional gains or losses. The Partnership may settle its derivative positions prior to the contractual settlement date in order to take advantage of favorable terms at which the Partnership could settle these proxy contracts that are expected to be less effective. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory.  Currently, approximately 70% of our derivative positions used to manage our future commodity price exposure are direct product hedges.

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

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

The Partnership enters into derivative contracts primarily with financial institutions that are participating members of the Credit Facility (“participating bank group members”). Currently, all of the Partnership’s financial derivative positions are with participating bank group members. Management conducts a standard credit review on counterparties to derivative contracts. There are no collateral requirements for derivative contracts among the Partnership and any participating bank group members. Specifically, the Partnership is not required to post collateral when it enters into derivative contracts with participating bank group members as the participating bank group members have a collateral position in substantially all the wholly-owned assets of the Partnership other than MarkWest Liberty Midstream and its subsidiaries. A separate agreement with certain bank group members allows MarkWest Liberty Midstream to enter into derivative 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 on derivatives.

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As of March 31, 2013, 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	2,626,742
Natural Gas (MMBtu)	Long	4,570,733
NGLs (gal)	Short	101,249,566

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, 2013, the estimated fair value of this contract was a liability of $84.9 million and the recorded value was a liability of $31.4 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of March 31, 2013 (in thousands):

Fair value of commodity contract	$	84,866
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of March 31, 2013	$	31,359

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 gain related to facility expenses. As of March 31, 2013, the estimated fair value of this contract was an asset of $6.5 million.

Financial Statement Impact of Derivative Instruments

There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. 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	March 31, 2013		December 31, 2012		March 31, 2013			December 31, 2012
Commodity contracts(1)
Fair value of derivative instruments — current	$	16,814	$	19,504	$	(23,060	)	$	(27,229	)
Fair value of derivative instruments - long-term	10,181		10,878		(23,938		)	(32,190		)
Total	$	26,995	$	30,382	$	(46,998	)	$	(59,419	)

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

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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, 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	$	13,514	$	(8,039	)	$	5,475	$	(13,765	)	$	8,039	$	(5,726	)
Embedded derivatives in commodity contracts	3,300		—			3,300		(9,295		)	—		(9,295		)
Total current derivative instruments	16,814		(8,039		)	8,775		(23,060		)	8,039		(15,021		)
Non-current
Commodity contracts	7,003		(1,720		)	5,283		(1,874		)	1,720		(154		)
Embedded derivatives in commodity contracts	3,178		—			3,178		(22,064		)	—		(22,064		)
Total non-current derivative instruments	10,181		(1,720		)	8,461		(23,938		)	1,720		(22,218		)
Total derivative instruments	$	26,995	$	(9,759	)	$	17,236	$	(46,998	)	$	9,759	$	(37,239	)

	Assets							Liabilities
As of December 31, 2012	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	$	16,438	$	(9,541	)	$	6,897	$	(16,679	)	$	9,541	$	(7,138	)
Embedded derivatives in commodity contracts	3,066		—			3,066		(10,550		)	—		(10,550		)
Total current derivative instruments	19,504		(9,541		)	9,963		(27,229		)	9,541		(17,688		)
Non-current
Commodity contracts	7,798		(2,637		)	5,161		(2,637		)	2,637		—
Embedded derivatives in commodity contracts	3,080		—			3,080		(29,553		)	—		(29,553		)
Total non-current derivative instruments	10,878		(2,637		)	8,241		(32,190		)	2,637		(29,553		)
Total derivative instruments	$	30,382	$	(12,178	)	$	18,204	$	(59,419	)	$	12,178	$	(47,241	)

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.

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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 gain or (loss)	Three months ended March 31,
recognized in income	2013			2012
Revenue: Derivative loss
Realized gain (loss)	$	3,898		$	(10,478	)
Unrealized loss	(4,083		)	(38,237		)
Total revenue: derivative loss	(185		)	(48,715		)
Derivative gain (loss) related to purchased product costs
Realized loss	(2,080		)	(7,074		)
Unrealized gain (loss)	12,784			(11,726		)
Total derivative gain (loss) related to purchase product costs	10,704			(18,800		)
Derivative gain related to facility expenses
Unrealized gain	332			1,746
Total gain (loss)	$	10,851		$	(65,769	)

5. Fair Value

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 4. The following table presents the derivative instruments carried at fair value as of March 31, 2013 and December 31, 2012 (in thousands):

As of March 31, 2013	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	5,548	$	(13,147	)
Significant unobservable inputs (Level 3)
Commodity contracts	14,969		(2,492		)
Embedded derivatives in commodity contracts	6,478		(31,359		)
Total carrying value in Condensed Consolidated Balance Sheet	$	26,995	$	(46,998	)

As of December 31, 2012	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	8,441	$	(15,970	)
Significant unobservable inputs (Level 3)
Commodity contracts	15,795		(3,346		)
Embedded derivatives in commodity contracts	6,146		(40,103		)
Total carrying value in Condensed Consolidated Balance Sheet	$	30,382	$	(59,419	)

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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, 2013. The market approach is used for valuation of all instruments.

Level 3 Instrument	Balance Sheet Classification	Unobservable Inputs	Value Range							Time Period
Commodity contracts	Assets	Forward propane prices (per gallon)	$	0.93		—	$	0.99		Oct. 2013 - Dec. 2014
		Forward isobutane prices (per gallon)	$	1.49		—	$	1.54		Apr. 2013 - Dec. 2014
		Forward normal butane prices (per gallon)	$	1.30		—	$	1.46		Apr. 2013 - Dec. 2014
		Forward natural gasoline prices (per gallon)	$	1.90		—	$	2.15		Apr. 2013 - Dec. 2014
		Crude option volatilities (%)	12.11		%	—	20.78		%	Apr. 2013 - Dec. 2014
	Liabilities	Forward propane prices (per gallon)	$	0.95		—	$	0.99		Apr. 2013 - Dec. 2013
		Forward natural gasoline prices (per gallon)	$	2.04		—	$	2.15		Apr. 2013 - Dec. 2013
		Propane option volatilities	10.56		%	—	22.69		%	Apr. 2013 - Dec. 2013
		Crude option volatilities (%)	10.24		%	—	22.34		%	Apr. 2013 - Jan. 2014
Embedded derivatives in commodity contracts	Asset	ERCOT Pricing (per MegaWatt Hour) (1)	$	31.33		—	$	72.19		Apr. 2013 - Dec. 2014
	Liability	Forward propane prices (per gallon)	$	0.92		—	$	0.99		Apr. 2013 - Dec. 2022
		Forward isobutane prices (per gallon)	$	1.39		—	$	1.54		Apr. 2013 - Dec. 2022
		Forward normal butane prices (per gallon)	$	1.28		—	$	1.46		Apr. 2013 - Dec. 2022
		Forward natural gasoline prices (per gallon)	$	1.71		—	$	2.15		Apr. 2013 - Dec. 2022
		Forward natural gas prices (per mmbtu)	$	4.04		—	$	5.87		Apr. 2013 - Dec. 2022
		Probability of renewal (2)				0%

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(1)The forward ERCOT prices utilized in the valuations are generally flat at the low end of the range with a seasonal spike in pricing in the summer months.

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

Fair Value Sensitivity Related to Unobservable Inputs

Commodity contracts (assets and liabilities) - For the Partnership’s commodity contracts, increases in forward NGL prices result in a decrease in the fair value of the derivative assets and an increase in the fair value of the derivative liabilities. The forward prices for the individual NGL products generally increase or decrease in a positive correlation with one another. An increase in crude option volatilities will generally result in an increase in the fair value of the Partnership’s derivative assets and derivative liabilities in commodity contracts.

Embedded derivative in commodity contracts (liability) - The embedded derivative liability relates to the natural gas purchase agreement embedded in a keep-whole processing agreement as discussed further in Note 4. Increases (decreases) in forward NGL prices result in an increase (decrease) in the fair value of the embedded derivative liability. An increase in the probability of renewal would result in an increase in the fair value of the related embedded derivative liability.

Embedded derivative in commodity contracts (asset) - The embedded derivative asset relates to utilities costs discussed further in Note 4. Increases in the forward ERCOT prices, relative to natural gas prices, result in an increase in the fair value of the embedded derivative asset.

Level 3 Valuation Process

The Partnership’s Risk Management Department (the “Risk Department”) is responsible for the valuation of the Partnership’s commodity derivative contracts and embedded derivatives in commodity contracts. The Risk Department reports to the Chief Financial Officer and is responsible for the oversight of the Partnership’s commodity risk management program. The members of the Risk Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The valuations of the Level 3 commodity derivative contracts are performed by a third-party pricing service and reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by at least one other independent third-party pricing service. The valuations for the embedded derivatives in commodity contracts are completed by the Risk Department utilizing the market data and price curves provided by the third-party pricing service. For the embedded derivative in the keep-whole processing arrangement discussed in Note 4, the Risk Department must develop forward price curves for NGLs and natural gas for periods in which price curves are not available from third-party pricing services due to insufficient market data. As of March 31, 2013, the Risk Department utilized internally developed price curves for the period of January 2015 through December 2022 in the valuation of the embedded derivative in the keep-whole processing arrangement. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between the forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Partnership’s estimated price curves.

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Changes in Level 3 Fair Value Measurements

The table below includes a rollforward of the balance sheet amounts for the three months ended March 31, 2013 and 2012 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

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

	Three months ended March 31, 2012
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(2,965	)	$	(53,904	)
Total loss (realized and unrealized) included in earnings (1)	(12,076		)	(10,438		)
Settlements	(2,409		)	3,538
Fair value at end of period	$	(17,450	)	$	(60,804	)
The amount of total net losses for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	(14,050	)	$	(10,620	)

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

6. Inventories

Inventories consist of the following (in thousands):

	March 31, 2013		December 31, 2012
NGLs	$	9,930	$	14,763
Spare parts, materials and supplies	10,584		9,870
Total inventories	$	20,514	$	24,633

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7. Long-Term Debt

Debt is summarized below (in thousands):

	March 31, 2013		December 31, 2012
Credit Facility
Credit Facility, variable interest, due September 2017 (1)	$	—	$	—
Senior Notes (2)
2018 Senior Notes, 8.75% interest, net of discount of zero and $109, respectively, issued April and May 2008	—		81,003
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 $521 and $826, respectively, issued February and March 2011 and due August 2021	324,479		499,174
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022	455,000		700,000
2023A Senior Notes, 5.5% interest, net of discount of $6,958 and $7,126, respectively, issued August 2012 and due February 2023	743,042		742,874
2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023	1,000,000		—
Total long-term debt	$	3,022,521	$	2,523,051

(1)Applicable interest rate was 4.75% at March 31, 2013.

(2)The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $3,180.1 million and $2,763.1 million as of March 31, 2013 and December 31, 2012, respectively, based on quoted prices in an inactive market. The fair value of the Partnership’s Senior Notes is considered a Level 3 measurement.

Credit Facility

Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by the Partnership’s 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, 2013, the Partnership had no borrowings outstanding and approximately $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $1,188.7 million of unused capacity of which approximately $145.3 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.

Senior Notes

In January 2013, the Partnership completed a public offering for $1 billion in aggregate principal amount of 4.5% senior unsecured notes due July 2023. The Partnership received net proceeds of approximately $986.0 million after deducting underwriters’ and third-party expenses. A portion of the proceeds, together with cash on hand, was used to repurchase $81.1 million aggregate principal amount of the Partnership’s 8.75% senior notes due April 2018, $175 million of the outstanding principal amount of the Partnership’s 6.5% senior notes due August 2021 and $245 million of the outstanding principal amount of the Partnership’s 6.25% senior notes due June 2022, with the remainder used to fund the Partnership’s capital expenditure program and for general partnership purposes. The Partnership recorded a total pre-tax loss of approximately $38.5 million related to repurchases. The pre-tax loss consisted of approximately $7.0 million related to the non-cash write-off of the unamortized discount and deferred finance costs and approximately $31.5 million related to the payment of redemption premiums.

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8. Equity

Equity Offerings

The Partnership has a Continuous Offering Program (the “COP”) in place with a financial institution (the “Manager”) which allows the Partnership from time to time, through the Manager as its sales agent, to offer and sell common units representing limited partner interests in the Partnership having an aggregate offering price of up to $600 million. Sales of such common units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed upon by the Manager and the Partnership. The Partnership may also sell common units to the Manager as principal for its own account at a price to be agreed upon at the time of the sale. For any such sales, the Partnership will enter into a separate agreement with the Manager.  During the three months ended March 31, 2013, the Partnership sold an aggregate of 1.9 million common units under the COP, receiving net proceeds of $103.9 million after deducting $1.8 million in manager fees and other third-party expenses.  The proceeds from sales were used to fund capital expenditures and for general partnership purposes.

Distributions of Available Cash and Range of Unit Prices

	Common Unit Price				Distribution Per Common
Quarter Ended	High		Low		Unit		Declaration Date	Record Date	Payment Date
March 31, 2013	$	61.97	$	51.77	$	0.83	April 25, 2013	May 7, 2013	May 15, 2013
December 31, 2012	$	55.95	$	46.03	$	0.82	January 23, 2013	February 6, 2013	February 14, 2013

9. Commitments and Contingencies

Legal

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

Contract Contingencies

Certain natural gas processing arrangements in the Partnership’s Liberty, Utica and Northeast segments 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, 2013, management does not believe there are any indications that the Partnership will incur any such fees or other material consequences for not meeting construction milestones.

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10. 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, 2013 and 2012 is as follows (in thousands):

	Three months ended March 31, 2013
	Corporation			Partnership			Eliminations			Consolidated
Income (loss) before provision for income tax	$	20,311		$	(33,080	)	$	(1,438	)	$	(14,207	)
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

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

(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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11. Earnings (Loss) Per Common Unit

The following table shows the computation of basic and diluted net income (loss) per common unit for the three months ended March 31, 2013 and 2012, and the weighted-average units used to compute basic and diluted net income (loss) per common unit (in thousands, except per unit data):

	Three months ended March 31,
	2013			2012
Net (loss) income attributable to the Partnership’s unitholders	$	(15,460	)	$	16,020
Less: Income allocable to phantom units	546			520
(Loss) Income available for common unitholders - basic	(16,006		)	15,500
Add: Income allocable to phantom units and DER expense	—			535
(Loss) Income available for common unitholders - diluted	$	(16,006	)	$	16,035
Weighted average common units outstanding - basic	128,615			96,840
Potential common units (Class B and phantom units) (2)	—			20,753
Weighted average common units outstanding - diluted	128,615			117,593
Net (loss) income attributable to the Partnership’s common unitholders per common unit (1)
Basic	$	(0.12	)	$	0.16
Diluted	$	(0.12	)	$	0.14

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

(2)For the three months ended March 31, 2013, 20,664 units were excluded from the calculation of potential common units because the impact was anti-dilutive.

12. Segment Information

The Partnership prepares segment information in accordance with GAAP. Certain items below Income from operations in the accompanying Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual segments. Management does not consider these items allocable to or controllable by any individual segment and therefore excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests.  For each period presented, the Southwest segment includes the operations of the Partnership’s processing facilities in Corpus Christi, Texas that were reported separately in the Gulf Coast segment in the prior year.  The Gulf Coast operations are no longer material to the Partnership’s operations and no longer meaningful presented separately.

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, 2013 and 2012 for the reported segments (in thousands).

21

Three months ended March 31, 2013:

	Southwest		Northeast		Liberty		Utica			Total
Segment revenue	$	211,446	$	57,336	$	108,497	$	623		$	377,902
Purchased product costs	114,102		19,662		18,793		—			152,557
Net operating margin	97,344		37,674		89,704		623			225,345
Facility expenses	29,123		6,524		22,636		3,962			62,245
Portion of operating income (loss) attributable to non-controlling interests	1,387		—		—		(1,339		)	48
Operating income (loss) before items not allocated to segments	$	66,834	$	31,150	$	67,068	$	(2,000	)	$	163,052
Capital expenditures	$	26,687	$	1,779	$	319,827	$	280,320		$	628,613
Capital expenditures not allocated to segments										2,945
Total capital expenditures										$	631,558

Three months ended March 31, 2012:

	Southwest		Northeast		Liberty		Total
Segment revenue	$	238,954	$	86,918	$	75,577	$	401,449
Purchased product costs	104,233		25,687		24,635		154,555
Net operating margin	134,721		61,231		50,942		246,894
Facility expenses	32,630		6,378		12,247		51,255
Portion of operating income attributable to non-controlling interests	1,446		—		—		1,446
Operating income before items not allocated to segments	$	100,645	$	54,853	$	38,695	$	194,193
Capital expenditures	$	50,583	$	23,302	$	178,689	$	252,574
Capital expenditures not allocated to segments							1,689
Total capital expenditures							$	254,263

22

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, 2013 and 2012 (in thousands):

	Three months ended March 31,
	2013			2012
Total segment revenue	$	377,902		$	401,449
Derivative loss not allocated to segments	(185		)	(48,715		)
Revenue deferral adjustment (1)	(1,765		)	(2,268		)
Total revenue	$	375,952		$	350,466
Operating income before items not allocated to segments	$	163,052		$	194,193
Portion of operating income attributable to non-controlling interests	48			1,446
Derivative gain (loss) not allocated to segments	10,851			(65,769		)
Revenue deferral adjustment (1)	(1,765		)	(2,268		)
Compensation expense included in facility expenses not allocated to segments	(387		)	(449		)
Facility expenses adjustments (2)	2,877			2,864
Selling, general and administrative expenses	(25,408		)	(25,224		)
Depreciation	(69,597		)	(41,145		)
Amortization of intangible assets	(14,830		)	(10,985		)
Loss on disposal of property, plant and equipment	(138		)	(986		)
Accretion of asset retirement obligations	(353		)	(238		)
Income from operations	64,350			51,439
Loss from unconsolidated affiliate	(85		)	(9		)
Interest income	149			72
Interest expense	(38,336		)	(29,472		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,830		)	(1,270		)
Loss on redemption of debt	(38,455		)	—
Miscellaneous income, net	—			58
(Loss) income before provision for income tax	$	(14,207	)	$	20,818

(1)Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term. Therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnership’s chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended March 31, 2013, approximately $0.2 million and $1.6 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, 2012, approximately $0.2 million and $2.1 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.

(2)Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR, which is included in facility expenses for the purposes of evaluating the performance of the Southwest segment.

23

The tables below present information about segment assets as of March 31, 2013 and December 31, 2012 (in thousands):

	March 31, 2013		December 31, 2012
Southwest	$	2,236,099	$	2,225,838
Northeast	573,199		578,122
Liberty	3,454,768		3,172,144
Utica	873,493		439,987
Total segment assets	7,137,559		6,416,091
Assets not allocated to segments:
Certain cash and cash equivalents	431,086		261,473
Fair value of derivatives	26,995		30,382
Investment in unconsolidated affiliate	34,106		31,179
Other (1)	90,808		96,591
Total assets	$	7,720,554	$	6,835,716

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

13. Supplemental Condensed Consolidating Financial Information

MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of March 31, 2013, the Partnership’s obligations under the outstanding Senior Notes (see Note 7) 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 15 to the Consolidated Financial Statements included in Item 8 of the Partnership’s December 31, 2012 Form 10-K 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 operations, cash flows and financial position of the co-issuer, MarkWest Energy Finance Corporation, are not material and, therefore, have been included with the Parent’s financial information. Condensed consolidating financial information for MarkWest Energy Partners and its combined guarantor and combined non-guarantor subsidiaries as of March 31, 2013 and December 31, 2012 and for the three months ended March 31, 2013 and 2012 is as follows (in thousands):

24

Condensed Consolidating Balance Sheets

	As of March 31, 2013
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	306,135	$	179,257	$	168,778	$	—		$	654,170
Restricted cash	—		—		500		—			500
Receivables and other current assets	7,047		187,358		66,129		—			260,534
Intercompany receivables	1,126,396		13,379		34,199		(1,173,974		)	—
Fair value of derivative instruments	—		16,425		389		—			16,814
Total current assets	1,439,578		396,419		269,995		(1,173,974		)	932,018
Total property, plant and equipment, net	3,627		1,997,885		3,777,288		(86,853		)	5,691,947
Other long-term assets:
Restricted cash	—		—		10,000		—			10,000
Investment in unconsolidated affiliate	—		34,106		—		—			34,106
Investment in consolidated affiliates	4,196,579		3,082,173		—		(7,278,752		)	—
Intangibles, net of accumulated amortization	—		548,345		291,981		—			840,326
Fair value of derivative instruments	—		9,729		452		—			10,181
Intercompany notes receivable	225,000		—		—		(225,000		)	—
Other long-term assets	56,721		69,906		75,349		—			201,976
Total assets	$	5,921,505	$	6,138,563	$	4,425,065	$	(8,764,579	)	$	7,720,554
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	1,281	$	1,157,146	$	15,547	$	(1,173,974	)	$	—
Fair value of derivative instruments	—		23,020		40		—			23,060
Other current liabilities	47,129		172,350		518,010		(1,950		)	735,539
Total current liabilities	48,410		1,352,516		533,597		(1,175,924		)	758,599
Deferred income taxes	2,749		208,342		—		—			211,091
Long-term intercompany financing payable	—		225,000		99,082		(324,082		)	—
Fair value of derivative instruments	—		23,862		76		—			23,938
Long-term debt, net of discounts	3,022,521		—		—		—			3,022,521
Other long-term liabilities	2,868		132,264		2,724		—			137,856
Redeemable non-controlling interest	—		—		—		326,249			326,249
Equity:
Common units	2,092,426		4,196,579		3,789,586		(7,971,986		)	2,106,605
Class B units	752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries	—		—		—		381,164			381,164
Total equity	2,844,957		4,196,579		3,789,586		(7,590,822		)	3,240,300
Total liabilities and equity	$	5,921,505	$	6,138,563	$	4,425,065	$	(8,764,579	)	$	7,720,554

25

	As of December 31, 2012
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	210,015	$	102,979	$	34,905	$	—		$	347,899
Restricted cash	—		—		25,500		—			25,500
Receivables and other current assets	9,191		178,517		76,028		—			263,736
Intercompany receivables	812,562		18,868		32,656		(864,086		)	—
Fair value of derivative instruments	—		18,389		1,115		—			19,504
Total current assets	1,031,768		318,753		170,204		(864,086		)	656,639
Total property, plant and equipment, net	3,542		1,999,474		3,168,131		(95,519		)	5,075,628
Other long-term assets:
Restricted cash	—		—		10,000		—			10,000
Investment in unconsolidated affiliate	—		31,179		—		—			31,179
Investment in consolidated affiliates	4,141,782		2,790,994		—		(6,932,776		)	—
Intangibles, net of accumulated amortization	—		559,320		295,835		—			855,155
Fair value of derivative instruments	—		10,878		—		—			10,878
Intercompany notes receivable	225,000		—		—		(225,000		)	—
Other long-term assets	50,866		70,009		75,362		—			196,237
Total assets	$	5,452,958	$	5,780,607	$	3,719,532	$	(8,117,381	)	$	6,835,716
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	461	$	839,543	$	24,082	$	(864,086	)	$	—
Fair value of derivative instruments	—		27,062		167		—			27,229
Other current liabilities	42,301		197,934		473,654		(1,892		)	711,997
Total current liabilities	42,762		1,064,539		497,903		(865,978		)	739,226
Deferred income taxes	2,906		188,412		—		—			191,318
Long-term intercompany financing payable	—		225,000		99,592		(324,592		)	—
Fair value of derivative instruments	—		32,190		—		—			32,190
Long-term debt, net of discounts	2,523,051		—		—		—			2,523,051
Other long-term liabilities	2,959		128,684		2,697		—			134,340
Equity:
Common Units	2,128,749		4,141,782		3,119,340		(7,255,157		)	2,134,714
Class B Units	752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries	—		—		—		328,346			328,346
Total equity	2,881,280		4,141,782		3,119,340		(6,926,811		)	3,215,591
Total liabilities and equity	$	5,452,958	$	5,780,607	$	3,719,532	$	(8,117,381	)	$	6,835,716

26

Condensed Consolidating Statements of Operations

	Three months ended March 31, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	270,968		$	112,422		$	(7,438	)	$	375,952
Operating expenses:
Purchased product costs	—			122,950			18,903			—			141,853
Facility expenses	—			32,278			27,336			(191		)	59,423
Selling, general and administrative expenses	12,034			6,973			7,454			(1,053		)	25,408
Depreciation and amortization	277			44,053			41,584			(1,487		)	84,427
Other operating expenses (income)	—			765			(274		)	—			491
Total operating expenses	12,311			207,019			95,003			(2,731		)	311,602
(Loss) income from operations	(12,311		)	63,949			17,419			(4,707		)	64,350
Earnings from consolidated affiliates	69,961			19,438			—			(89,399		)	—
Loss on redemption of debt	(38,455		)	—			—			—			(38,455		)
Other expense, net	(43,000		)	(6,736		)	(3,285		)	12,919			(40,102		)
(Loss) income before provision for income tax	(23,805		)	76,651			14,134			(81,187		)	(14,207		)
Provision for income tax (benefit) expense	(133		)	6,690			—			—			6,557
Net (loss) income	(23,672		)	69,961			14,134			(81,187		)	(20,764		)
Net income attributable to non-controlling interest	—			—			—			5,304			5,304
Net (loss) income attributable to the Partnership’s unitholders	$	(23,672	)	$	69,961		$	14,134		$	(75,883	)	$	(15,460	)

	Three months ended March 31, 2012
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	271,071		$	79,395		$	—		$	350,466
Operating expenses:
Purchased product costs	—			148,601			24,754			—			173,355
Facility expenses	—			33,936			13,334			(176		)	47,094
Selling, general and administrative expenses	14,417			9,048			3,131			(1,372		)	25,224
Depreciation and amortization	164			39,293			12,911			(238		)	52,130
Other operating expenses	—			1,111			113			—			1,224
Total operating expenses	14,581			231,989			54,243			(1,786		)	299,027
(Loss) income from operations	(14,581		)	39,082			25,152			1,786			51,439
Earnings from consolidated affiliates	56,431			24,234			—			(80,665		)	—
Other expense, net	(23,344		)	(2,406		)	(665		)	(4,206		)	(30,621		)
Income before provision for income tax	18,506			60,910			24,487			(83,085		)	20,818
Provision for income tax expense	66			4,479			—			—			4,545
Net (loss) income	18,440			56,431			24,487			(83,085		)	16,273
Net income attributable to non-controlling interest	—			—			—			(253		)	(253		)
Net income attributable to the Partnership’s unitholders	$	18,440		$	56,431		$	24,487		$	(83,338	)	$	16,020

27

Condensed Consolidating Statements of Cash Flows

	Three months ended March 31, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(44,484	)	$	71,711		$	51,091		$	6,725		$	85,043
Cash flows from investing activities:
Restricted cash	—			—			25,000			—			25,000
Capital expenditures	(340		)	(31,398		)	(592,643		)	(7,177		)	(631,558		)
Equity investments in consolidated affiliates	(14,828		)	(407,300		)	—			422,128			—
Investment in unconsolidated affiliate	—			(3,012		)	—			—			(3,012		)
Distributions from consolidated affiliates	20,552			140,968			—			(161,520		)	—
Proceeds from disposal of property, plant and equipment	—			35			174			—			209
Net cash flows provided by (used in) investing activities	5,384			(300,707		)	(567,469		)	253,431			(609,361		)
Cash flows from financing activities:
Proceeds from public equity offerings, 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		)	—
Contribution from non-controlling interest	—			—			385,219			—			385,219
Share-based payment activity	(5,206		)	651			—			—			(4,555		)
Payment of distributions	(105,945		)	(20,552		)	(141,816		)	161,520			(106,793		)
Payments of SMR liability	—			(545		)	—			—			(545		)
Intercompany advances, net	(310,892		)	310,892			—			—			—
Net cash flows provided by financing activities	135,220			305,274			650,251			(260,156		)	830,589
Net increase in cash	96,120			76,278			133,873			—			306,271
Cash and cash equivalents at beginning of year	210,015			102,979			34,905			—			347,899
Cash and cash equivalents at end of period	$	306,135		$	179,257		$	168,778		$	—		$	654,170

28

	Three months ended March 31, 2012
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(27,744	)	$	149,912		$	88,402		$	(2,657	)	$	207,913
Cash flows from investing activities:
Restricted cash	—			—			1,003			—			1,003
Capital expenditures	(68		)	(91,090		)	(166,976		)	3,871			(254,263		)
Equity investments	(13,230		)	(66,356		)	—			79,586			—
Distributions from consolidated affiliates	16,496			2,139			—			(18,635		)	—
Collections of  intercompany notes, net	51,400			—			—			(51,400		)	—
Proceeds from disposal of property, plant and equipment	—			1,505			—			(1,214		)	291
Net cash flows provided by (used in) investing activities	54,598			(153,802		)	(165,973		)	12,208			(252,969		)
Cash flows from financing activities:
Proceeds from public equity offering, net	425,629			—			—			—			425,629
Proceeds from Credit Facility	13,700			—			—			—			13,700
Payments of Credit Facility	(79,700		)	—			—			—			(79,700		)
Payments related to intercompany financing, net	—			(51,400		)	—			51,400			—
Contributions from parent and affiliates	—			13,230			66,356			(79,586		)	—
Contributions from non-controlling interest	—			—			755			—			755
Share-based payment activity	(8,048		)	2,207			—			—			(5,841		)
Payment of distributions	(73,410		)	(16,496		)	(4,101		)	18,635			(75,372		)
Payments of SMR liability	—			(497		)	—			—			(497		)
Intercompany advances, net	(35,025		)	35,025			—			—			—
Net cash flows provided by (used in) financing activities	243,146			(17,931		)	63,010			(9,551		)	278,674
Net increase (decrease) in cash	270,000			(21,821		)	(14,561		)	—			233,618
Cash and cash equivalents at beginning of year	22			99,580			17,414			—			117,016
Cash and cash equivalents at end of period	$	270,022		$	77,759		$	2,853		$	—		$	350,634

29

14. Supplemental Cash Flow Information

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

	Three months ended March 31,
	2013		2012
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	35,196	$	16,607
Cash received for income taxes, net	17,814		363
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	500,301	$	101,299
Interest capitalized on construction in progress	10,158		2,620
Issuance of common units for vesting of share-based payment awards	4,495		2,501

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

Forward-Looking Statements

Management’s Discussion and Analysis (“MD&A”) contains statements that are forward-looking and should be read in conjunction with our condensed consolidated financial statements and accompanying notes included elsewhere in this report and our Annual Report on Form 10-K for the year ended December 31, 2012. Statements that are not historical facts are forward-looking statements. We use words such as “could,” “may,” “predict,” “should,” “expect,” “hope,” “continue,” “potential,” “plan,” “intend,” “anticipate,” “project,” “believe,” “estimate,” and similar expressions to identify forward-looking statements. These statements are based on current expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. Forward-looking statements are not guarantees and actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors. We do not update publicly any forward-looking statement with new information or future events. Undue reliance should not be placed on forward-looking statements as many of these factors are beyond our ability to control or predict.

Overview

We are a master limited partnership engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the gathering and transportation of crude oil. We have a leading presence in many unconventional gas plays, including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation.

Significant Financial and Other Business Highlights

Significant financial and other highlights for the three months ended March 31, 2013 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

·Total segment operating income before items not allocated to segments (a non-GAAP financial measure, see below) decreased approximately $31 million, or 16%, for the three months ended March 31, 2013 compared to the same period in 2012. The decrease is due primarily to a decline in the Northeast and Southwest segments, offset by an increase in the Liberty segment.  Total processed volumes increased 38% and gathered volumes increased 19%.

·The decrease in the Northeast segment is due to lower NGL prices as well as a decline in volumes.

·The decrease in the Southwest segment is due to lower NGL prices and a change in contract mix, partially offset by a significant increase in volumes.

·The increase in Liberty segment is primarily due to increased volumes resulting from our ongoing expansion of the segment’s operations.

·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 will develop gathering pipelines, field compression and liquids storage to support production from Newfield’s West Asherton area in Dimmit County, Texas.  We plan to invest approximately $50 million to support Newfield’s development plans.

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·In the first quarter 2013, we commenced operations of a 120 MMcf/d cryogenic processing plant at our existing Mobley, West Virginia processing complex.  We also completed a 200 MMcf/d cryogenic processing plant at our existing Majorsville, West Virginia processing complex in the second quarter 2013 and a 200 MMcf/d cryogenic processing plant at our existing Sherwood, West Virginia processing complex in the second quarter 2013.

·In 2013, MarkWest Utica EMG announced the execution of definitive agreements with Rex Energy Corporation (“Rex”), PDC Energy Inc. (“PDC”) and CONSOL Energy Inc. (“CONSOL”) to provide midstream services in the Utica Shale.

·Realized gain from the settlement of our derivative instruments was $1.8 million for the three months ended March 31, 2013 compared to a $17.6 million realized loss for the same period in 2012.  Changes in the correlation between the price of NGLs and price of crude oil has reduced the effectiveness of our crude oil derivative positions that have historically been used as a proxy contract for managing NGL price risk.  Currently, approximately 70% of our derivative positions used to manage our future commodity price exposure are direct product hedges.

·In January 2013, we received net proceeds of approximately $986.0 million from a public offering of $1 billion in aggregate principal amount of our 4.5% senior unsecured notes due in 2023, which were issued at par.

·In February 2013, pursuant to the optional redemption provision contained in such notes, we repurchased $81.1 million aggregate principal amount of our 8.75% senior notes due April 2018, $175 million of outstanding principal amount of our 6.5% senior notes due August 2021 and $245 million of outstanding principal amount of our 6.25% senior notes due June 2022.

·In the first quarter of 2013, we received net proceeds of approximately $103.9 million from a public offering of approximately 1.9 million newly issued common units representing limited partner interests in the Partnership as part of the COP.

·In February 2013, we entered into the Amended Utica LLC Agreement where the aggregate funding commitment of EMG Utica increased from $500 million to $950 million.

Non-GAAP Measures

In evaluating our financial performance, management utilizes the segment performance measures, segment revenues and operating income before items not allocated to segments. These financial measures are presented in Note 12 to the accompanying condensed consolidated financial statements and are considered non-GAAP financial measures when presented outside of the notes to the condensed consolidated financial statements. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Note 12 to the accompanying condensed consolidated financial statements for the reconciliations of segment revenue and operating income before items not allocated to segments to the respective most comparable GAAP measure.

Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure). 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,
	2013			2012
Segment revenue	$	377,902		$	401,449
Purchased product costs	(152,557		)	(154,555		)
Net operating margin	225,345			246,894
Facility expenses	(59,755		)	(48,840		)
Derivative gain (loss)	10,851			(65,769		)
Revenue deferral adjustment	(1,765		)	(2,268		)
Selling, general and administrative expenses	(25,408		)	(25,224		)
Depreciation	(69,597		)	(41,145		)
Amortization of intangible assets	(14,830		)	(10,985		)
Loss on disposal of property, plant and equipment	(138		)	(986		)
Accretion of asset retirement obligations	(353		)	(238		)
Income from operations	$	64,350		$	51,439

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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, 2012 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 table below. For the three months ended March 31, 2013, we calculated the following approximate percentages of our segment revenue and net operating margin from the following types of contracts:

	Fee- Based		Percent-of- Proceeds(1)		Keep- Whole(2)
Southwest	56	%	32	%	12	%
Northeast	19	%	15	%	66	%
Liberty	76	%	24	%	0	%
Utica	100	%	0	%	0	%
Total	58	%	26	%	16	%

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

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

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 approximately 50 million gallons of propane storage capacity in the northeast region provided by our own storage facilities and a firm capacity 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 12 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal management reporting. We conduct our operations in the following operating segments: Southwest, Northeast, Liberty and Utica. Our assets and operations in each of these segments are described below.

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Southwest Segment

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

·Oklahoma.  We own gas gathering systems in the Granite Wash formation of Western Oklahoma and the Texas panhandle, which are both connected to a natural gas processing complex in Western Oklahoma. The gathering system includes compression facilities. The majority of the gathered gas is ultimately compressed and delivered to the processing complex.  In addition, we own an extensive natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. The liquids-rich natural gas gathered in the Woodford system is processed through Centrahoma, our equity investment, or other third-party processors.  We have agreed to fund our share of a 120 MMcf/d processing plant expansion at Centrahoma in order to support the drilling programs in the Woodford Shale.  The expansion is expected to be operational in the first quarter of 2014.

Through our joint venture, MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with the Midcontinent Express Pipeline, the Gulf Crossing Pipeline, and the NGPL Pipeline in Bennington, Oklahoma and is designed to provide approximately 638,000 Dth/d of Woodford Shale takeaway capacity. For a complete discussion of the formation of, and accounting treatment for, MarkWest Pioneer, see Note 4 of Item 8. Financial Statement and Supplementary Data, of our Annual Report on Form 10-K for the year ended December 31, 2012.

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

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

Northeast Segment

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

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

Liberty Segment

·Marcellus Shale.  We provide extensive natural gas midstream services in southwest Pennsylvania and northern West Virginia through MarkWest Liberty Midstream. With gathering capacity of approximately 855 MMcf/d and current processing capacity of 1.6 Bcf/d, we are the largest processor of natural gas in the Marcellus Shale, with fully integrated gathering, processing, fractionation, storage and marketing operations that are critical to the liquids-rich gas development in the northeast United States.

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

Natural Gas Gathering

·Existing gathering system delivering to our Houston, Pennsylvania processing complex (“Houston Complex”).

·Existing gathering lines acquired in the acquisition of Keystone Midstream Services, LLC completed in the second quarter of 2013 (the “Keystone Acquisition”).

·Existing gathering system delivering to our Sherwood, West Virginia processing complex, (“Sherwood Complex”).

Natural Gas Processing

·355 MMcf/d of current cryogenic processing capacity at our Houston Complex.

·470 MMcf/d of current cryogenic processing capacity at our Majorsville, West Virginia processing complex (“Majorsville Complex”) of which 200 MMcf/d was completed in the second quarter of 2013.

·320 MMcf/d of current cryogenic processing capacity at our Mobley, West Virginia processing complex (“Mobley Complex”) of which 120 MMcf/d facility was completed in the first quarter of 2013.

·90 MMcf/d of cryogenic processing capacity at our Butler County, Pennsylvania processing plants (“Keystone Complex”), which we acquired in the Keystone Acquisition.

·400 MMcf/d of current cryogenic processing capacity at our Sherwood Complex.

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

·200 MMcf/d cryogenic processing capacity expansion under construction at our Mobley Complex. The additional 200 MMcf/d of capacity is expected to be operational during the fourth quarter of 2013 and is supported by long-term fee-based agreements with EQT Corporation and Magnum Hunter Resources Corporation.

·400 MMcf/d cryogenic processing capacity expansion under construction at our Sherwood Complex. The Sherwood expansion includes two, 200 MMcf/d processing plants that are expected to commence operation in the fourth quarter of 2013 and the second quarter of 2014, respectively.  The expansion plans are based, in part, on Antero Resources’ decision to support the additional capacity under a long-term processing agreement.

·120 MMcf/d cryogenic processing capacity expansion under construction in Butler County, Pennsylvania, which is expected to commence operation in the second quarter of 2014. Based on producer production, we may expand our Keystone Complex by an additional 200 MMcf/d as soon as 2014.

By the end of 2014, MarkWest Liberty Midstream is expected to have up to approximately 3.4 Bcf/d of cryogenic processing capacity that is supported primarily by long-term fee-based agreements with our producer customers.

NGL Gathering, Fractionation and Market Outlets

·NGLs produced at the Majorsville Complex are delivered through an NGL pipeline (“Majorsville Pipeline”) to the Houston Complex for exchange for fractionated products. We also operate an NGL pipeline from our Mobley Complex to the Majorsville Complex and an NGL pipeline connecting the

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Sherwood Complex to the Mobley Complex is under construction and is expected to be completed in the second quarter of 2013.

·Existing propane-plus fractionation facility at our Houston Complex with a design capacity of 60,000 Bbl/d.

·Existing interconnect with a key interstate pipeline providing a market outlet for the propane produced from this region.

·Existing agreements to access international markets.  Propane is currently being transported by truck to a third-party terminal near Philadelphia, Pennsylvania where it is loaded onto marine vessels and delivered to international markets.  We added rail deliveries to the terminal as rail unloading capabilities were expanded.  As discussed below, we will also have the ability to deliver propane to Sunoco Logistics L.P.’s (“Sunoco”) terminal in Philadelphia via pipeline once the Mariner East, a Sunoco pipeline and marine project that is expected to originate at our Houston Complex (“Mariner East”), pipeline is placed into service.

·Existing extensions of our NGL gathering system to receive NGLs produced at a third-party’s Fort Beeler processing plant which allows certain producers at the third party’s plant to benefit from our integrated NGL fractionation and marketing operations.

·Existing twelve bay truck loading and unloading facility at our Houston Complex. The unloading facility allows for regional marketing of purity NGLs and the unloading facility allows for the receipt of raw NGLs for fractionation and marketing.

·Existing 200 railcar loading facility at our Houston Complex that expands our market access and allows for long-haul, cost effective transportation of purity NGLs.

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

Ethane Recovery and Associated Market Outlets

Due to increased natural gas production from the liquids-rich area of the Marcellus Shale, natural gas processors must begin to recover a significant amount of ethane from the gas stream to meet the pipeline gas quality specifications for residue gas and to provide producers with the ability to benefit from a potential price uplift received from the sale of ethane. We are developing solutions that will have the capability to recover and fractionate ethane, and provide access to ethane markets in North America and internationally. The primary components of our ethane recovery, fractionation and marketing solutions consist of the following:

·Two de-ethanization facilities of 38,000 Bbl/d each are under construction at our Houston Complex and Majorsville Complex and are expected to be completed by the third quarter of 2013 and the fourth quarter of 2013, respectively.

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

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

·Mariner East is intended to deliver Marcellus purity ethane and purity propane to the Gulf Coast and international markets. Mariner East, for which we have made a 5,000 bbl/d commitment, is expected to begin delivering propane in the second half of 2014 and ethane in the first half of 2015.

·Connection to Enterprise Products Partners L.P.’s NGL pipeline from Appalachia to Texas (“ATEX Pipeline”). We expect to begin delivering ethane to the ATEX Pipeline in the first quarter of 2014.

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Utica Segment

We formed MarkWest Utica EMG, a joint venture with EMG focused on the development of fully integrated midstream services in the Utica Shale in eastern Ohio. The current Utica development plan includes:

Natural Gas Processing

·The Utica segment began the first phase of operations in the fourth quarter of 2012 with interim mechanical refrigeration processing capacity of 60 MMcf/d.

·125 MMcf/d cryogenic processing capacity at our Cadiz Complex beginning initial start up phase in May 2013.

·200 MMcf/d processing in our Cadiz Complex under construction and expected to be complete in 2014.

·400 MMcf/d processing in our Seneca Complex, which is expected to begin the first phase of operations in the fourth quarter of 2013 with processing capacity of 400 MMcf/d.

NGL Gathering, Fractionation and Market Outlets

·60,000 Bbl/d of NGL fractionation, storage, and marketing capabilities in Harrison County for propane and heavier components (the “Hopedale Fractionation Facility”). The Hopedale Fractionation Facility will be jointly owned by MarkWest Utica EMG and MarkWest Liberty Midstream and is expected to begin operations in the first quarter of 2014.

·Both the Cadiz and Seneca processing complexes are expected to be connected via an NGL gathering pipeline system to the Hopedale Fractionation Facility that is expected to be operational by the first quarter of 2014.

·From the Hopedale Fractionation Facility we plan to market NGLs by truck, rail and pipeline. A rail car loading facility that can accommodate 200 rail cars and a twelve bay truck loading and unloading facility are under construction at the Hopedale Fractionation Facility and are expected to be complete by first quarter of 2014. Additionally, the Hopedale Fractionation Facility is expected to be connected to our extensive processing and NGL pipeline network in our Liberty segment and provide for the integrated operation of the two largest fractionation complexes in the northeast United States by the first quarter of 2014.

Ethane Recovery and Associated Market Outlets

·At our Cadiz Complex we are also constructing de-ethanization capacity of 40,000 Bbl/d and a connection to the ATEX Pipeline. We expect to begin delivering ethane to the ATEX Pipeline in the first quarter of 2014.

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, 2013:

	Southwest		Northeast		Liberty		Utica
Segment revenue	56	%	15	%	29	%	<1	%
Net operating margin	43	%	17	%	40	%	<1	%

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, 2013 and 2012. For each period presented, the Southwest segment includes the operations of our processing facilities in Corpus Christi, TX that were reported separately in the Gulf Coast segment in the prior year.  The Gulf Coast operations are no longer material to the Partnership’s operations and no longer meaningful separately.

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The information includes net operating margin, a non-GAAP financial measure. See above for a reconciliation of net operating margin to Income (loss) from operations, the most comparable GAAP financial measure.

Three months ended March 31, 2013 compared to three months ended March 31, 2012

Southwest

	Three months ended March 31,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	211,446	$	238,954	$	(27,508	)	(12	)%
Purchased product costs	114,102		104,233		9,869			9	%
Net operating margin	97,344		134,721		(37,377		)	(28	)%
Facility expenses	29,123		32,630		(3,507		)	(11	)%
Portion of operating income attributable to non-controlling interests	1,387		1,446		(59		)	(4	)%
Operating income before items not allocated to segments	$	66,834	$	100,645	$	(33,811	)	(34	)%

Segment Revenue.  Revenues decreased due to lower NGL revenues, partially offset by higher fee based revenue and higher gas sales.  Approximately $8 million of the decline in NGL sales was caused by a planned shutdown of one customer’s refinery operations from mid-January through mid-March in our Javelina area.  At the end of March 2013, this refinery customer had returned to normal operations.  The remaining decline in NGL revenues was primarily caused by lower prices and a change in contract mix, partially offset by increased processed volumes.  Fee based revenue increased as a result of an increase in gathering volumes and an increase in processing capacity in our East Texas area.  Higher gas sales revenue is mainly caused by higher prices.

Purchased Product Costs. Purchase product costs increased due to increases in gas purchases of $4.8 million primarily due to higher gas prices.  The remainder of the increase is due to higher NGL purchases.  NGL purchases increased despite a decrease in NGL sales due to a shift in contract mix, which resulted in less volumes processed under keep-whole contracts and more volumes processed under fee based or other arrangements in which NGLs are purchased from producer customers and resold.

Facility Expenses.  Facility expenses decreased due primarily to a lower compressor expenses use in Oklahoma due to lower gathered volumes, as well as a decrease due to timing of facility maintenance and repairs.

Northeast

	Three months ended March 31,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	57,336	$	86,918	$	(29,582	)	(34	)%
Purchased product costs	19,662		25,687		(6,025		)	(23	)%
Net operating margin	37,674		61,231		(23,557		)	(38	)%
Facility expenses	6,524		6,378		146			2	%
Operating income before items not allocated to segments	$	31,150	$	54,853	$	(23,703	)	(43	)%

Segment Revenue.  Revenue decreased due to lower NGL prices and a decrease in NGL sales volumes. The decrease in NGL sales volumes is primarily due to lower plant inlet volumes, as well as, lower sales from inventory.

Purchased Product Costs.  Purchased product costs decreased due to a decrease in NGL sales volumes related to keep-whole agreements, partially offset by higher gas prices.  The overall frac spread margins declined by approximately 33% as compared to the first quarter 2012.

Liberty

	Three months ended March 31,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	108,497	$	75,577	$	32,920		44	%
Purchased product costs	18,793		24,635		(5,842		)	(24	)%
Net operating margin	89,704		50,942		38,762			76	%
Facility expenses	22,636		12,247		10,389			85	%
Operating income before items not allocated to segments	$	67,068	$	38,695	$	28,373		73	%

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Segment Revenue.  Revenue increased due to ongoing expansion of the Liberty segment operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $28.1 million related to gathering, processing and fractionation fees and by approximately $4.0 million related to NGL sales under percent of proceeds arrangements, partially offset by lower sales of purchased product.

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

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

Utica

	Three months ended March 31,
	2013			2012		$ Change			% Change
	(in thousands)
Segment revenue	$	623		$	—	$	623		N/A
Purchased product costs	—			—		—			N/A
Net operating margin	623			—		623			N/A
Facility expenses	3,962			—		3,962			N/A
Portion of operating loss attributable to non-controlling interests	(1,339		)	—		(1,339		)	N/A
Operating loss before items not allocated to segments	$	(2,000	)	$	—	$	(2,000	)	N/A

The results of operations for the quarter ended March 31, 2013 include our operations in Utica Shale areas of eastern Ohio. The first phase of operations began in the third quarter of 2012. The total planned cryogenic processing capacity is expected to be in operation in 2014. Facility expenses include start-up costs and other costs that cannot be capitalized.

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, 2013 and 2012, 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,
	2013			2012			$ Change			% Change
	(in thousands)
Total segment revenue	$	377,902		$	401,449		$	(23,547	)	(6	)%
Derivative loss not allocated to segments	(185		)	(48,715		)	48,530			(100	)%
Revenue deferral adjustment	(1,765		)	(2,268		)	503			(22	)%
Total revenue	$	375,952		$	350,466		$	25,486		7	%
Operating income before items not allocated to segments	$	163,052		$	194,193		$	(31,141	)	(16	)%
Portion of operating income attributable to non-controlling interests	48			1,446			(1,398		)	(97	)%
Derivative gain (loss) not allocated to segments	10,851			(65,769		)	76,620			(116	)%
Revenue deferral adjustment	(1,765		)	(2,268		)	503			(22	)%
Compensation expense included in facility expenses not allocated to segments	(387		)	(449		)	62			(14	)%
Facility expenses adjustments	2,877			2,864			13			0	%
Selling, general and administrative expenses	(25,408		)	(25,224		)	(184		)	1	%
Depreciation	(69,597		)	(41,145		)	(28,452		)	69	%
Amortization of intangible assets	(14,830		)	(10,985		)	(3,845		)	35	%
Loss on disposal of property, plant and equipment	(138		)	(986		)	848			(86	)%
Accretion of asset retirement obligations	(353		)	(238		)	(115		)	48	%
Income from operations	64,350			51,439			12,911			25	%
Loss from unconsolidated affiliates	(85		)	(9		)	(76		)	844	%
Interest income	149			72			77			107	%
Interest expense	(38,336		)	(29,472		)	(8,864		)	30	%
Amortization of deferred financing costs and discount (a component of interest expense)	(1,830		)	(1,270		)	(560		)	44	%
Loss on redemption of debt	(38,455		)	—			(38,455		)	N/A
Miscellaneous income, net	—			58			(58		)	(100	)%
(Loss) income before provision for income tax	$	(14,207	)	$	20,818		$	(35,025	)	(168	)%

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Derivative (Loss) Gain Not Allocated to Segments.  Unrealized gain from the change in fair value of our derivative instruments was $9.0 million for the three months ended March 31, 2013 compared to an unrealized loss of $48.2 million for the same period in 2012. Realized gain from the settlement of our derivative instruments was $1.8 million for the three months ended March 31, 2013 compared to an unrealized loss of $17.6 million for the same period in 2012. The total change of $76.6 million is due mainly to volatility in commodity prices. Due to the weakened relationship between the price of NGLs and crude oil, our crude oil derivative positions used as a proxy to manage NGL price risk have been less effective.  We are not able to predict the future effectiveness of our crude oil positions in managing NGL price risk, but ineffectiveness may continue for the near-term.

Revenue Deferral Adjustment.  Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended March 31, 2013, approximately $0.2 million and $1.6 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the three months ended March 31, 2012, approximately $0.2 million and $2.1 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Based on current commodity prices, management expects the deferred revenue in subsequent periods to approximate the first quarter 2013 amount until the beginning of 2015 when the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

Depreciation.  Depreciation increased due to additional projects completed during 2012 through the first quarter of 2013, shorter lives on certain interim Utica assets, and the Keystone Acquisition.

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

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

Loss on Redemption of Debt.  The increase in loss on redemption of debt was related to the redemption of the 2018 Senior notes, a portion of the 2021 Senior Notes and a portion of the 2022 Senior Notes which occurred in the first quarter of 2013, while no such redemptions of debt occurred during the first quarter of 2012.

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Operating Data

	Three months ended March 31,		%
	2013	2012	Change
Southwest
East Texas gathering systems throughput (Mcf/d)	500,300	410,000	22	%
East Texas natural gas processed (Mcf/d)	339,500	242,500	40	%
East Texas NGL sales (gallons, in thousands)	80,600	63,400	27	%
Western Oklahoma gathering system throughput (Mcf/d)(1)	202,600	262,000	(23	)%
Western Oklahoma natural gas processed (Mcf/d)	186,300	203,800	(9	)%
Western Oklahoma NGL sales (gallons, in thousands)	54,800	57,300	(4	)%
Southeast Oklahoma gathering systems throughput (Mcf/d)	461,300	501,200	(8	)%
Southeast Oklahoma natural gas processed (Mcf/d)(2)	151,200	101,700	49	%
Southeast Oklahoma NGL sales (gallons, in thousands)	39,300	33,000	19	%
Arkoma Connector Pipeline throughput (Mcf/d)	273,800	328,700	(17	)%
Other Southwest gathering system throughput (Mcf/d)(3)	20,600	25,000	(18	)%
Gulf Coast refinery off-gas processed (Mcf/d)	95,300	120,300	(21	)%
Gulf Coast liquids fractionated (Bbl/d)	17,200	23,400	(26	)%
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands)	65,100	89,300	(27	)%
Northeast
Natural gas processed (Mcf/d)	302,600	321,700	(6	)%
NGLs fractionated (Bbl/d)	17,100	16,700	2	%
Keep-whole sales (gallons, in thousands)	37,400	49,500	(24	)%
Percent-of-proceeds sales (gallons, in thousands)	34,900	33,000	6	%
Total NGL sales (gallons, in thousands)	72,300	82,500	(12	)%
Crude oil transported for a fee (Bbl/d)	10,300	10,400	(1	)%
Liberty
Gathering system throughput (Mcf/d)	605,400	308,100	96	%
Natural gas processed (Mcf/d)	828,100	392,100	111	%
NGLs fractionated (Bbl/d)	37,000	20,000	85	%
NGL sales (gallons, in thousands)(4)	145,900	97,500	50	%
Utica(5)
Gathering system throughput (Mcf/d)	9,000	—	N/A
Natural gas processed (Mcf/d)	7,900	—	N/A

(1)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.

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

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

(4)Includes sale of all purity products fractionated at the Liberty facilities and the sale of all unfractionated NGLs.

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(5)Utica operations began in August 2012.

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 2013 capital plan is summarized in the table below (in millions):

	2013 Full Year Plan						Actual
	Low			High			Three months ended March 31, 2013
Consolidated growth capital(1)	$	2,217		$	2,517		$	630
Utica joint venture partner’s estimated share of growth capital	(717		)	(717		)	(265		)
Partnership share of growth capital	$	1,500		$	1,800		$	365

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

Management believes that the cash requirements to meet operating expenses and pay distributions to our unitholders, including the distributions for approximately 4 million Class B units that will convert to common units on July 1, 2013, will be funded by cash generated from our operations.

Management believes that expenditures for our currently planned capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partner for capital projects encompassed by MarkWest Utica EMG, our current borrowing capacity under the Credit Facility and proceeds from equity or debt offerings. Our access to capital markets can be impacted by factors outside our control, which include but are not limited to general economic conditions and the rights of our Class B unitholders to participate in any future equity offerings we may commence after July 1, 2013; however, we believe that our strong cash flows and balance sheet, our Credit Facility and our credit rating will provide us with adequate access to funding given our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings assigned by independent rating agencies. As of May 1, 2013, our credit ratings were Ba2 with a Stable outlook by Moody’s Investors Service, BB with a Stable outlook by Standard & Poor’s, and BB with a Stable outlook by Fitch Ratings. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

Debt Financing Activities

In January 2013, we completed a public offering for $1 billion in aggregate principal amount of 4.5% senior unsecured 2023B Senior Notes, which were issued at par. We received net proceeds of approximately $986.0 million, after deducting underwriters’ fees and third-party expenses. A portion of the proceeds, together with cash on hand, was used to repurchase, pursuant to the optional redemption provision contained in such notes, $81.1 million aggregate principal amount of our 8.75% senior notes due April 2018, $175 million of the outstanding principal amount of our 6.5% senior notes due August 2021 and $245 million of the outstanding principal amount of our 6.25% senior notes due June 2022, with the remainder used to fund our capital expenditure program and for general partnership purposes.

Under the provisions of the Credit Facility, we are subject to a number of restrictions and covenants. As of March 31, 2013, 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 May 1, 2013, we had no borrowings outstanding and approximately $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $1,188.7 million of unused capacity, of which approximately $145.3 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.

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

The Credit Facility 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 May 1, 2013, all of our financial derivative positions are with members of the participating bank group and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to enter into derivative instruments without utilizing cash for margin calls or requiring the use of letters of credit.  We believe the recent Dodd-Frank legislation will not change our ability to enter into derivatives without utilizing margin calls.

Continuous Offering Program

In November 2012, we announced the COP which allows us from time to time, through the Manager, as our sales agent, to offer and sell common units representing limited partner interests in the Partnership having an aggregate offering price of up to $600 million. Sales of such common units will be made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed upon by us and the Manager. We may also sell common units to the Manager as principal for its own account at a price to be agreed upon at the time of such sale. For any such sales, we will enter into a separate agreement with the Manager.

In the quarter ended March 31, 2013, we sold an aggregate of 1.9 million common units under the Agreement, receiving net proceeds of approximately $103.9 million after deducting $1.8 million in manager fees and other third-party expenses. The proceeds from sales were used for general partnership purposes. We plan to continue issuing common units under this plan throughout 2013.

Utica Shale Joint Venture

As discussed in Note 3 of these Condensed Consolidated Financial Statements, we and EMG Utica entered into the Amended Utica LLC Agreement for MarkWest Utica EMG which replaced the original agreement discussed in Note 4 in the Notes to the Consolidated Financial Statements included in Item 8 of our Annual Report on Form 10-K for details of the original agreement. Pursuant to the Amended Utica LLC Agreement, the aggregate funding commitment of EMG Utica has increased from $500 million to $950 million.

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 various supply and demand factors, NGL prices have declined significantly beginning in early 2012 and have remained at low levels, which has adversely impacted our liquidity and operating results and will continue to have an adverse impact if price declines are sustained.

Additionally, we execute a risk management strategy to mitigate our exposure to downward fluctuations in commodity prices. We use derivative financial instruments relating to the future price of NGLs and crude oil to mitigate our exposure to NGL price risk. During 2012 and continuing into 2013, the price of NGLs as compared to crude oil weakened significantly and as a result, our derivative financial instruments have not been as effective in offsetting the impact of NGL price declines. If the pricing relationship between crude oil and NGLs does not return to the historical correlation or continues to weaken, our derivative financial instruments will continue to be less effective.

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Cash Flow

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

	Three months ended March 31,
	2013			2012			Change
Net cash provided by operating activities	$	85,043		$	207,913		$	(122,870	)
Net cash flows used in investing activities	(609,361		)	(252,969		)	(356,392		)
Net cash flows provided by financing activities	830,589			278,674			551,915

Net cash provided by operating activities decreased primarily due to a $31 million decrease in operating income before items not allocated to segments (see Segment Operating Results section above for further discussion of this measure). The decrease in cash provided by operating activities was also due to changes in working capital.

Net cash used in investing activities increased due to a $377 million increase in capital expenditures, primarily related to our expansion of our Liberty and Utica segments as discussed in our Segment Reporting section above.

Net cash provided by financing activities increased primarily due to a $384.5 million increase in contributions from non-controlling interest holders and a $519.3 million increase in net borrowings, partially offset by a $321.7 million decrease in proceeds from public equity offerings and by a $32.5 million increase in distributions to unit holders.

Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of March 31, 2013, our purchase obligations for the remainder of 2013 were $653.6 million compared to our 2013 obligations of $664.8 million as of December 31, 2012. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

In the first quarter of 2013, we completed a public debt offering of $1 billion in aggregate principal amount of 4.5% senior unsecured notes due in 2023.  We repurchased $81.1 million aggregate principal amount of our 8.75% senior notes due April 2018, $175 million of outstanding principal amount of our 6.5% senior notes due August 2021 and $245 million of outstanding principal amount of our 6.25% senior notes due June 2022.

Critical Accounting Policies

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

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

There have not been any material changes during the three months ended March 31, 2013 to the methodology applied by management for critical accounting policies previously disclosed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2012.

Recent Accounting Pronouncements

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

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

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

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Commodity Price Risk

The information about commodity price risk for the three months ended March 31, 2013 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, 2012.

Outstanding Derivative Contracts

The following table provides information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at March 31, 2013, including the weighted average prices (“WAVG”):

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2013	2,119	$	84.05	$	103.80	$	(382	)
2014	1,418	90.36		108.73		2,290

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2013	2,456	$	93.46	$	(2,211	)
2014	697	92.39		(60		)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2013	1,216	$	4.79	$	(281	)

Propane Collars	Volumes (Gal/d)	WAVG Floor (Per Gal)		WAVG Cap (Per Gal)		Fair Value (in thousands)
2013	121,225	$	0.80	$	0.97	$	(1,118	)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	20,613	$	1.65	$	785
2014	6,221	1.64		285

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	24,783	$	1.52	$	995
2014	8,141	1.56		563

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	15,045	$	1.99	$	(422	)

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, 2013, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2013	640	$	98.43	$	431

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2013	9,766	$	5.31	$	(3,126	)
2014	4,249	5.69		(2,238		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013 (Oct-Dec)	45,910	$	1.27	$	1,182
2014 (Jan-Mar, Oct-Dec)	87,837	1.25		4,174

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	8,799	$	1.66	$	349
2014	3,885	1.67		225

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Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	24,158	$	1.51	$	890
2014	10,711	1.61		916

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	16,265	$	2.07	$	(29	)
2014	7,106	2.32		934

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, 2013, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2013	1,055	$	89.29	$	106.75	$	264

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2014	358	$	91.85	$	(114	)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	3,565	$	1.63	$	162

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	8,440	$	1.50	$	414

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, 2013, including the WAVG:

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2013	5,427	$	0.93

The following tables provide information on the derivative positions of our taxable subsidiary related to keep-whole price risk that we have entered into subsequent to March 31, 2013, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)
2013(1)	620	$	92.90

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2013	47,161	$	0.94

The following tables provide information on the derivative positions of MarkWest Liberty Midstream related to long liquids price risk that we have entered into subsequent to March 31, 2013, including the WAVG:

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2013	27,310	$	0.92

(1)During April of 2013, we purchased crude swaps to offset our existing crude positions and contemporaneously entered into direct NGL product positions to continue to manage our 2013 NGL price risk exposure.

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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, 2013, the estimated fair value of this contract was a liability of $84.9 million and the recorded value was a liability of $31.4 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception on February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of March 31, 2013 (in thousands):

Fair value of commodity contract	$	84,866
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of March 31, 2013	$	31,359

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, 2013, the estimated fair value of this contract was an asset of $6.5 million.

Interest Rate Risk

The information about interest rate risk for the three months ended March 31, 2013 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, 2012.

Credit Risk

The information about our credit risk for the three months ended March 31, 2013 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, 2012.

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, 2013. Based on this evaluation, the Partnership’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of March 31, 2013, 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.

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Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2013 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.  Legal Proceedings

On February 11, 2013 MarkWest Liberty Midstream entered into a Consent Order with the West Virginia Department of Environmental Protection (“WVDEP”) relating to alleged violations of West Virginia’s stormwater and erosion and sediment control regulations in connection with slips and landsides encountered during the construction of MarkWest Liberty Midstream’s Mobley processing complex near Mobley, West Virginia. Under the Consent Order, MarkWest Liberty Midstream agreed to pay a civil administrative penalty in the amount of $306,210 and to submit corrective action and stream restoration plans. Pursuant to WVDEP’s rules and regulations, the Consent Order was subject to a thirty day public notice period, which ended on March 22, 2013.  As a result, the Consent Order is final.  MarkWest Liberty Midstream has paid the administrative penalty and will be submitting to the WVDEP the plans required by the Consent Order.

In connection with construction activities in eastern Ohio, MarkWest Utica EMG has experienced 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 the impacts from these bentonite releases. 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.

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

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no significant changes to our risk factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2012.

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Item 6. Exhibits

4.1*	Eleventh Supplemental Indenture dated as of April 17, 2013, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein, and Wells Fargo Bank, National Association, as trustee.
10.1*+	Amendment No. 1 to Limited Liability Company Agreement of MarkWest Utica EMG, L.L.C. dated as of January 30, 2013, among MarkWest Utica EMG, L.L.C., MarkWest Utica Operating Company, L.L.C., and EMG Utica, LLC.
10.2*+	Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG, L.L.C. dated as of February 18, 2013, by and between MarkWest Utica Operating Company, L.L.C. and EMG Utica, LLC.
31.1*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	The following financial information from the quarterly report on Form 10-Q of MarkWest Energy Partners, L.P. for the quarter ended March 31, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Statements of Changes in Equity, and (v) Notes to the

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Condensed Consolidated Financial Statements, tagged as blocks of text.

*Filed herewith

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

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SIGNATURES

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

	MarkWest Energy Partners, L.P.
	(Registrant)
	By:	MarkWest Energy GP, L.L.C.,
		Its General Partner
Date: May 8, 2013	/s/ FRANK M. SEMPLE
	Frank M. Semple
	Chairman, President & Chief Executive Officer
	(Principal Executive Officer)
Date: May 8, 2013	/s/ NANCY K. BUESE
	Nancy K. Buese
	Senior Vice President & Chief Financial Officer
	(Principal Financial Officer)
Date: May 8, 2013	/s/ PAULA L. ROSSON
	Paula L. Rosson
	Vice President & Chief Accounting Officer
	(Principal Accounting Officer)

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