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 June 30, 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 July 31, 2013, the number of the registrant’s common units and Class B units outstanding were 140,976,492 and 15,963,512, respectively.

PART I—FINANCIAL INFORMATION	4
Item 1. Financial Statements	4
Unaudited Condensed Consolidated Balance Sheets at June 30, 2013 and December 31, 2012	4
Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2013 and 2012	5
Unaudited Condensed Consolidated Statements of Changes in Equity for the six months ended Juned 30, 2013 and 2012	6
Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 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	37
Item 3. Quantitative and Qualitative Disclosures about Market Risk	57
Item 4. Controls and Procedures	60
Item 5. Other Information	60
PART II—OTHER INFORMATION	65
Item 1. Legal Proceedings	65
Item 1A. Risk Factors	65
Item 6. Exhibits	68
SIGNATURES	69

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)

	June 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents ($74,381 and $31,584, respectively)	$	354,554		$	345,756
Restricted cash ($0 and $500, respectively)	10,000			25,500
Receivables, net ($1,759 and $403, respectively)	232,668			197,977
Inventories ($230 and $0, respectively)	36,461			24,633
Fair value of derivative instruments	24,746			19,504
Deferred income taxes	1,199			5,281
Other current assets ($3,324 and $82, respectively)	34,264			34,871
Total current assets	693,892			653,522
Property, plant and equipment ($1,106,356 and $410,205, respectively)	7,025,344			5,542,316
Less: accumulated depreciation ($14,329 and $2,787, respectively)	(732,482		)	(602,698		)
Total property, plant and equipment, net	6,292,862			4,939,618
Other long-term assets:
Restricted cash	—			10,000
Investment in unconsolidated affiliates	69,327			63,054
Intangibles, net of accumulated amortization of $253,338 and $221,416, respectively	907,733			855,155
Goodwill	144,856			142,174
Deferred financing costs, net of accumulated amortization of $21,829 and $18,567, respectively	55,384			51,145
Deferred contract cost, net of accumulated amortization of $2,730 and $2,574, respectively	20,520			676
Fair value of derivative instruments	12,418			10,878
Other long-term assets ($953 and $0, respectively)	3,891			2,140
Total assets	$	8,200,883		$	6,728,362
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($74,008 and $73,865, respectively)	$	296,559		$	320,627
Accrued liabilities ($158,324 and $109,572, respectively)	496,384			390,178
Fair value of derivative instruments	17,871			27,229
Total current liabilities	810,814			738,034
Deferred income taxes	244,422			189,428
Fair value of derivative instruments	2,010			32,190
Long-term debt, net of discounts of $7,296 and $8,061, respectively	3,022,704			2,523,051
Other long-term liabilities	151,947			134,261
Commitments and contingencies (Note 12)
Redeemable non-controlling interest (Note 3)	486,670			—
Equity:
Common units (133,375 and 127,494 common units issued and outstanding, respectively)	2,273,759			2,097,404
Class B units (19,954 units issued and outstanding)	752,531			752,531
Non-controlling interest in consolidated subsidiaries	456,026			261,463
Total equity	3,482,316			3,111,398
Total liabilities and equity	$	8,200,883		$	6,728,362

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

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

4

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Operations

(unaudited, in thousands, except per unit amounts)

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Revenue:
Revenue	$	395,421		$	306,755		$	768,879		$	702,733
Derivative gain	19,699			136,067			19,514			87,352
Total revenue	415,120			442,822			788,393			790,085
Operating expenses:
Purchased product costs	155,359			112,731			307,916			267,286
Derivative gain related to purchased product costs	(20,432		)	(51,579		)	(31,136		)	(32,779		)
Facility expenses	62,797			48,230			122,307			96,555
Derivative loss (gain) related to facility expenses	800			(1,146		)	468			(2,892		)
Selling, general and administrative expenses	25,499			21,700			50,741			46,748
Depreciation	71,562			41,336			139,579			80,918
Amortization of intangible assets	17,092			12,307			31,922			23,292
(Gain) loss on disposal of property, plant and equipment	(37,736		)	1,342			(37,598		)	2,328
Accretion of asset retirement obligations	157			160			509			396
Total operating expenses	275,098			185,081			584,708			481,852
Income from operations	140,022			257,741			203,685			308,233
Other income (expense):
Equity in earnings from unconsolidated affiliates	430			1,109			665			1,548
Interest income	62			159			211			231
Interest expense	(36,955		)	(26,762		)	(75,291		)	(56,234		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,784		)	(1,245		)	(3,614		)	(2,515		)
Loss on redemption of debt	—			—			(38,455		)	—
Miscellaneous income, net	6			4			6			62
Income before provision for income tax	101,781			231,006			87,207			251,325
Provision for income tax (benefit) expense:
Current	(2,745		)	4,809			(8,159		)	20,150
Deferred	19,028			39,664			30,999			28,868
Total provision for income tax	16,283			44,473			22,840			49,018
Net income	85,498			186,533			64,367			202,307
Net (income) loss attributable to non-controlling interest	(1,799		)	375			3,874			621
Net income attributable to the Partnership’s unitholders	$	83,699		$	186,908		$	68,241		$	202,928
Net income attributable to the Partnership’s common unitholders per common unit (Note 14):
Basic	$	0.63		$	1.74		$	0.52		$	1.98
Diluted	$	0.55		$	1.47		$	0.45		$	1.66
Weighted average number of outstanding common units:
Basic	131,227			106,825			129,928			101,833
Diluted	151,866			127,468			150,580			122,531
Cash distribution declared per common unit	$	0.83		$	0.79		$	1.65		$	1.55

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 Noncontrolling Interest (Temporary
	Units	Amount			Units	Amount		Interest			Total Equity			Equity)
December 31, 2012	127,494	$	2,097,404		19,954	$	752,531	$	261,463		$	3,111,398		$	—
Issuance of units in public offerings, net of offering costs	5,720	348,352			—	—		—			348,352			—
Distributions paid	—	(214,903		)	—	—		(112		)	(215,015		)	—
Contributions from non-controlling interest	—	—			—	—		685,219			685,219			—
Redeemable non-controlling interest classified as temporary equity	—	—			—	—		(486,670		)	(486,670		)	486,670
Share-based compensation activity	161	2,092			—	—		—			2,092			—
Excess tax benefits related to share-based compensation	—	650			—	—		—			650			—
Deferred income tax impact from changes in equity	—	(28,077		)	—	—		—			(28,077		)	—
Net income (loss)	—	68,241			—	—		(3,874		)	64,367			—
June 30, 2013	133,375	$	2,273,759		19,954	$	752,531	$	456,026		$	3,482,316		$	486,670

	Common Units				Class B Units			Non- controlling
	Units	Amounts			Units	Amounts		Interest			Total Equity
December 31, 2011	94,940	$	642,522		19,954	$	752,531	$	189		$	1,395,242
Issuance of units in public offerings, net of offering costs	15,508	852,873			—	—		—			852,873
Distributions paid	—	(155,073		)	—	—		(71		)	(155,144		)
Contributions from non-controlling interest	—	—			—	—		1,101			1,101
Share-based compensation activity	246	537			—	—		—			537
Excess tax benefits related to share-based compensation	—	2,207			—	—		—			2,207
Deferred income tax impact from changes in equity	—	(42,854		)	—	—		—			(42,854		)
Net income	—	202,928			—	—		(621		)	202,307
June 30, 2012	110,694	$	1,503,140		19,954	$	752,531	$	598		$	2,256,269

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)

	Six months ended June 30,
	2013			2012
Cash flows from operating activities:
Net income	$	64,367		$	202,307
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	139,579			80,918
Amortization of intangible assets	31,922			23,292
Loss on redemption of debt	38,455			—
Amortization of deferred financing costs and discount	3,614			2,515
Accretion of asset retirement obligations	509			396
Amortization of deferred contract cost	156			156
Phantom unit compensation expense	7,298			8,585
Equity in earnings of unconsolidated affiliate	(665		)	(1,548		)
Distributions from unconsolidated affiliate	2,728			4,566
Unrealized gain on derivative instruments	(46,320		)	(145,527		)
(Gain) loss on disposal of property, plant and equipment	(37,598		)	2,328
Deferred income taxes	30,999			28,868
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	(34,529		)	90,337
Inventories	(11,828		)	18,895
Other current assets	607			2,638
Accounts payable and accrued liabilities	(7,462		)	(71,783		)
Other long-term assets	(21,751		)	85
Other long-term liabilities	17,515			6,593
Net cash provided by operating activities	177,596			253,621
Cash flows from investing activities:
Restricted cash	25,500			1,003
Capital expenditures	(1,435,084		)	(580,980		)
Investment in unconsolidated affiliate	(8,336		)	(839		)
Acquisition of business, net of cash acquired	(225,210		)	(506,797		)
Proceeds from disposal of property, plant and equipment	208,109			499
Net cash flows used in investing activities	(1,435,021		)	(1,087,114		)
Cash flows from financing activities:
Proceeds from public equity offerings, net	348,352			852,873
Proceeds from Credit Facility	—			238,065
Payments of Credit Facility	—			(86,200		)
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		)	(2,315		)
Contributions from non-controlling interest	685,219			1,101
Payments of SMR liability	(1,103		)	(1,005		)
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	650			2,207
Payment of distributions to common unitholders	(214,903		)	(155,073		)
Payment of distributions to non-controlling interest	(112		)	(71		)
Net cash flows provided by financing activities	1,266,223			841,534
Net increase in cash and cash equivalents	8,798			8,041
Cash and cash equivalents at beginning of year	345,756			114,332
Cash and cash equivalents at end of period	$	354,554		$	122,373

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 and six months ended June 30, 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”), a VIE for which the Partnership has been determined to be the primary beneficiary, is included in the condensed consolidated financial statements (see Note 3). All intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), in which the Partnership exercises significant influence but does not control and is not the primary beneficiary, and Centrahoma Processing, LLC (“Centrahoma”) are 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 retrospectively as of January 1, 2013. Except for additional disclosures included in Note 6 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 Entity and Equity Method Investment

Variable Interest Entity MarkWest Utica EMG

In February 2013, the Partnership and EMG Utica, LLC (“EMG Utica”) (together the “Members”) entered into the Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG (“Amended Utica LLC Agreement”) which replaces the original agreement discussed in Note 4 to the Consolidated Financial Statements included in Item 8 of the Partnership’s Form 10-K for the 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 was required to fund all capital until the Minimum EMG Investment was satisfied which occurred in May 2013. As EMG Utica has funded the Minimum EMG Investment, the Partnership will be required to fund, as needed, 100% of future capital for MarkWest Utica EMG until such time as the aggregate capital that has been contributed by the 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

8

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.

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 received a special non-cash allocation of income of approximately $6.4 million in the second quarter of 2013.

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 June 30, 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 is 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 MarkWest Utica EMG’s inability to fund its planned activities without additional subordinated financial support.  The Partnership has concluded that it is the primary beneficiary of MarkWest Utica EMG.  As the primary beneficiary of MarkWest Utica EMG, the Partnership consolidates the entity and recognizes non-controlling interest and redeemable non-controlling interest.

The assets of MarkWest Utica EMG are the property of the entity and are not available to the Partnership for any other purpose, including as collateral for its secured debt (see Notes 10 and 16). MarkWest Utica EMG’s asset balances can only be used to settle its own obligations. The liabilities of MarkWest Utica EMG do not represent additional claims against the Partnership’s general assets, and the creditors or beneficial interest holders of MarkWest Utica EMG do not have recourse to the general credit of the Partnership. The Partnership’s maximum exposure to loss as a result of its involvement with MarkWest Utica EMG includes its equity investment, any additional capital contribution commitments and any operating expense incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. Other than temporary funding due to the timing of the administrative process associated with capital calls in the beginning of 2013, the Partnership did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the six months ended June 30, 2013 and 2012. The Partnership was reimbursed for its temporary funding except for $15 million that was retained and treated as a capital contribution from the Partnership as discussed above.

The results of operations of MarkWest Utica EMG and its subsidiaries are shown separately as the Utica segment (see Note 15).

MarkWest Pioneer  — Restatement

MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline. The Partnership and Arkoma Pipeline Partners, LLC share the equity interests in MarkWest Pioneer equally (50% and 50%). As discussed in Note 4 to the Consolidated Financial Statements in Item 8 of the Partnership’s Form 10-K for the fiscal year ended December 31, 2012, the Partnership had determined that MarkWest Pioneer was a VIE and the Partnership was the primary beneficiary. Therefore, MarkWest Pioneer has historically been included as a consolidated subsidiary by the Partnership. Based on further consideration of the facts and circumstances, MarkWest Pioneer should not have been consolidated and should have been accounted for under the equity method

9

since the Partnership sold 50% of its interests to Arkoma Pipeline Partners, L.L.C. in 2009.   Under the equity method, the Partnership would have recognized an impairment of its investment in MarkWest Pioneer of approximately $39.2 million ($35.4 million, net of provision for income tax) in the year ended December 31, 2009.

The Partnership determined that the consolidation error and impairment were immaterial to the prior periods included in the accompanying Condensed Consolidated Financial Statements.  Correcting the cumulative effect of the error in the three months ended June 30, 2013, could have had a significant effect on the results of operations for the full year, therefore, the Partnership has restated the accompanying Condensed Consolidated Balance Sheet as of December 31, 2012 (including the parenthetical disclosure of VIE balances), the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2012, and the Condensed Consolidated Statement of Cash Flows and Condensed Consolidated Statement Changes in Equity for the six months ended June 30, 2012.  The impact of the misstatement is shown in the tables below (in thousands).

	December 31, 2012
Balance Sheet	As previously reported			As restated
Cash and cash equivalents	$	347,899		$	345,756
Receivables, net	198,769			197,977
Other current assets	35,053			34,871
Total current assets	656,639			653,522
Property, plant and equipment	5,700,176			5,542,316
Less: accumulated depreciation	(624,548		)	(602,698		)
Total property, plant and equipment, net	5,075,628			4,939,618
Investment in unconsolidated affiliate	31,179			63,054
Other long-term assets	2,242			2,140
Total assets	6,835,716			6,728,362
Accounts payable	320,645			320,627
Accrued liabilities	391,352			390,178
Total current liabilities	739,226			738,034
Deferred income taxes	191,318			189,428
Other long-term liabilities	134,340			134,261
Common Units	2,134,714			2,097,404
Non-controlling interest in consolidated subsidiaries	328,346			261,463
Total equity	3,215,591			3,111,398
Total liabilities and equity	$	6,835,716		$	6,728,362

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	Three months ended June 30, 2012					Six months ended June 30, 2012
Statement of Operations	As previously reported			As restated		As previously reported			As restated
Revenue	$	309,986		$	306,755	$	709,167		$	702,733
Total revenue	446,053			442,822		796,519			790,085
Facility expenses	48,538			48,230		97,378			96,555
Selling, general and administrative expenses	21,879			21,700		47,103			46,748
Depreciation	42,918			41,336		84,063			80,918
Accretion of asset retirement obligations	161			160		399			396
Total operating expenses	187,151			185,081		486,178			481,852
Income from operations	258,902			257,741		310,341			308,233
Earnings from unconsolidated affiliates	551			1,109		542			1,548
Income before provision for income tax	231,609			231,006		252,427			251,325
Net income	187,136			186,533		203,409			202,307
Net (income) loss attributable to non-controlling interest	(228		)	375		(481		)	621

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	Six months ended June 30, 2012
Statement of Cash Flows	As previously reported			As restated
Net income	$	203,409		$	202,307
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	84,063			80,918
Accretion of asset retirement obligations	399			396
Equity in (earnings) loss of unconsolidated affiliate	(542		)	(1,548		)
Distributions from unconsolidated affiliate	1,700			4,566
Receivables	90,664			90,337
Other current assets	2,738			2,638
Accounts payable and accrued liabilities	(71,784		)	(71,783		)
Net cash provided by operating activities	256,437			253,621
Cash flows from investing activities:
Capital expenditures	(582,203		)	(580,980		)
Investment in unconsolidated affiliates	—			(839		)
Net cash flows used in investing activities	(1,087,498		)	(1,087,114		)
Cash flows from financing activities:
Contributions from non-controlling interest	1,940			1,101
Payment of distributions to non-controlling interest	(2,937		)	(71		)
Net cash flows provided by financing activities	839,507			841,534
Net increase in cash and cash equivalents	8,446			8,041
Cash and cash equivalents at beginning of year	117,016			114,332
Cash and cash equivalents at end of period	125,462			122,373

	Common Units						Non-controlling Interest						Total Equity
Statement of Changes in Equity	As previously reported			As restated			As previously reported			As restated			As previously reported			As restated
December 31, 2011 Balance	$	679,309		$	642,522		$	70,227		$	189		$	1,502,067		$	1,395,242
Distributions paid	(155,073		)	(155,073		)	(2,937		)	(71		)	(158,010		)	(155,144		)
Contributions from non-controlling interest	—			—			1,940			1,101			1,940			1,101
Deferred income tax impact from changes in equity.	(42,592		)	(42,854		)	—			—			(42,592		)	(42,854		)
Net income	202,928			202,928			481			(621		)	203,409			202,307
June 30, 2012 Balance	1,540,189			1,503,140			69,711			598			2,362,431			2,256,269

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4. Business Combination

On May 8, 2013, the Partnership acquired natural gas gathering and processing assets from Chesapeake Energy Corporation (“Chesapeake”) for a cash purchase price of approximately $225.2 million, subject to final purchase price adjustments.  The acquired assets include a 200 MMcf/d cryogenic gas processing plant (the “Buffalo Creek Plant”) currently under construction, 22 miles of gas gathering pipeline in Hemphill County, Texas, and approximately 30 miles of rights-of-way associated with the future construction of a high-pressure trunk line.  Additional assets acquired from Chesapeake consist of an amine treating facility and a five mile gas gathering pipeline in Washita County, Oklahoma.  This acquisition is referred to as the Buffalo Creek Acquisition.

Concurrently with the closing of the Buffalo Creek Acquisition, the Partnership entered into a long-term fee-based agreement to provide treating, processing and certain gathering and compression services for natural gas owned or controlled by Chesapeake at the facilities acquired.  Chesapeake has dedicated 130,000 acres throughout the Anadarko Basin to the Partnership as part of this long-term agreement.  As a result of the acquisition, the Partnership has expanded its presence in the Granite Wash and Hogshooter formations in Oklahoma.

Contemporaneously with the Buffalo Creek Acquisition, Chesapeake agreed to extend a keep-whole processing agreement for natural gas produced in the Appalachia Basin area of the Partnership’s Northeast segment for five additional years, to 2020.  The Partnership paid an additional $20 million of cash upon closing the Buffalo Creek Acquisition as consideration for the  extension and has recorded it as deferred contract cost in the accompanying Condensed Consolidated Balance Sheets.  The deferred contract costs will be amortized over the extension term.  This $20 million is not considered to be part of the purchase price of Buffalo Creek Acquisition and is not included in the purchase prices allocation table below.

The Buffalo Creek Acquisition is accounted for as a business combination.  The total purchase price is allocated to identifiable assets acquired and liabilities assumed based on the estimated fair values at the acquisition date.  The remaining purchase price in excess of the fair value of the identifiable assets and liabilities is recorded as goodwill.  The acquired assets and the related results of operations are included in the Partnership’s Southwest segment.

The following table summarizes the preliminary purchase price allocation for the Buffalo Creek Acquisition (in thousands):

Assets:
Property, plant and equipment	$	149,382
Goodwill	2,682
Intangible asset	84,500
Liabilities:
Accounts payable	11,354
Total	$	225,210

As of June 30, 2013, the purchase price for the Buffalo Creek Acquisition is $225.2 million subject to further working capital adjustments.  Due to the potential change in assumed liabilities due to estimates and the further working capital adjustments, the purchase price allocation is subject to further adjustment, which could impact depreciation and amortization expense.

The goodwill recognized from the Buffalo Creek Acquisition results primarily from the Partnership’s ability to grow its business in the liquids-rich gas areas of the Granite Wash and Hogshooter formations in Oklahoma and access additional markets in a competitive environment as a result of securing the gathering and processing rights for a large area of dedicated acreage. All of the goodwill is deductible for tax purposes.

The intangible asset consists of an identifiable customer contract with Chesapeake.  The asset results from the value obtained related to the dedicated acreage and significant fee-based revenues the Partnership will earn.  The acquired intangible will be amortized on a straight-line basis over the estimated remaining customer contract useful life of 20 years.

Pro forma financial results that give effect to the Buffalo Creek Acquisition are not presented as it is impractical to obtain the necessary information.  Chesapeake did not operate the acquired assets as a standalone business and, therefore, historical financial information that is consistent with the operations under the current agreements is not available.

5. Divestiture

In June 2013, the Partnership completed the sale of certain gathering assets in Doddridge County, West Virginia (“Sherwood Asset Sale”) to Summit Midstream Partners, LP (“Summit”) for approximately $207.9 million cash, net of third party transaction

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costs.  In connection with the transaction, Summit assumed liabilities associated with the purchased assets other than certain identified liabilities that were retained by the Partnership.  Liquids-rich gas gathered by these assets is dedicated to the Partnership for processing at the Liberty segment’s Sherwood processing complex, also located in Doddridge County, West Virginia. The assets included in this transaction consist of over 40 miles of newly constructed high-pressure gas gathering pipelines, certain rights-of-way associated with the pipeline, and two compressor stations totaling over 21,000 horsepower of combined compression.  The assets had a carrying value of approximately $169.7 million and were part of the Partnership’s Liberty segment.  The gain of approximately $38.2 million on the Sherwood Asset Sale is included in Gain (loss) on disposal of property, plant, and equipment in the accompanying Condensed Consolidated Statements of Operations.

6. 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 Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps and options traded on the OTC market and fixed price forward contracts. The risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.

To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership 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 73% of our derivative positions used to manage our future commodity price exposure are direct product positions.

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

14

for offset of certain positive and negative exposures (master netting arrangements) in the event of default or other terminating events, including bankruptcy.

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

As of June 30, 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	1,885,366
Natural Gas (MMBtu)	Long	5,173,965
NGLs (gal)	Short	133,196,994

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 June 30, 2013, the estimated fair value of this contract was a liability of $61.6 million and the recorded value was a liability of $8.1 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of June 30, 2013 (in thousands):

Fair value of commodity contract	$	61,587
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of June 30, 2013	$	8,080

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 June 30, 2013, the estimated fair value of this contract was an asset of $5.7 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	June 30, 2013		December 31, 2012		June 30, 2013			December 31, 2012
Commodity contracts(1)
Fair value of derivative instruments — current	$	24,746	$	19,504	$	(17,871	)	$	(27,229	)
Fair value of derivative instruments - long-term	12,418		10,878		(2,010		)	(32,190		)
Total	$	37,164	$	30,382	$	(19,881	)	$	(59,419	)

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

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

	Assets							Liabilities
As of June 30, 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	$	21,546	$	(8,219	)	$	13,327	$	(9,791	)	$	8,219	$	(1,572	)
Embedded derivatives in commodity contracts	3,200		—			3,200		(8,080		)	—		(8,080		)
Total current derivative instruments	24,746		(8,219		)	16,527		(17,871		)	8,219		(9,652		)
Non-current
Commodity contracts	9,941		(1,875		)	8,066		(2,010		)	1,875		(135		)
Embedded derivatives in commodity contracts	2,477		—			2,477		—			—		—
Total non-current derivative instruments	12,418		(1,875		)	10,543		(2,010		)	1,875		(135		)
Total derivative instruments	$	37,164	$	(10,094	)	$	27,070	$	(19,881	)	$	10,094	$	(9,787	)

	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

16

forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented above.

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

Derivative contracts not designated as hedging instruments and the location of	Three months ended June 30,						Six months ended June 30,
gain or (loss) recognized in income	2013			2012			2013			2012
Revenue: Derivative gain (loss)
Realized gain (loss)	$	3,089		$	2,841		$	6,987		$	(7,637	)
Unrealized gain	16,610			133,226			12,527			94,989
Total revenue: derivative gain	19,699			136,067			19,514			87,352
Derivative gain (loss) related to purchased product costs
Realized loss	(1,045		)	(7,793		)	(3,125		)	(14,867		)
Unrealized gain	21,477			59,372			34,261			47,646
Total derivative gain related to purchase product costs	20,432			51,579			31,136			32,779
Derivative (loss) gain related to facility expenses
Unrealized (loss) gain	(800		)	1,146			(468		)	2,892
Total gain	$	39,331		$	188,792		$	50,182		$	123,023

7. Fair Value

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 6. The following table presents the derivative instruments carried at fair value as of June 30, 2013 and December 31, 2012 (in thousands):

As of June 30, 2013	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	4,662	$	(11,354	)
Significant unobservable inputs (Level 3)
Commodity contracts	26,825		(447		)
Embedded derivatives in commodity contracts	5,677		(8,080		)
Total carrying value in Condensed Consolidated Balance Sheet	$	37,164	$	(19,881	)

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 June 30, 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) (1)	$0.82	-	$0.88	Jul. 2013 - Dec. 2014
		Forward isobutane prices (per gallon) (1)	$1.19	-	$1.24	Jul. 2013 - Dec. 2014
		Forward normal butane prices (per gallon) (1)	$1.08	-	$1.20	Jul. 2013 - Dec. 2014
		Forward natural gasoline prices (per gallon) (1)	$1.84	-	$1.98	Jul. 2013 - Dec. 2014
		Propane option volatilities (%)	13.33%	-	22.49%	Jul. 2013 - Dec. 2013
		Crude option volatilities (%)	12.49%	-	24.48%	Jul. 2013 - Dec. 2014
	Liabilities	Forward propane prices (per gallon) (1)	$0.82	-	$0.85	Apr. 2014 - Dec. 2014
		Forward isobutane prices (per gallon) (1)	$1.19	-	$1.22	Apr. 2014 - Sep. 2014
		Forward normal butane prices (per gallon) (1)	$1.08	-	$1.20	Jan. 2014 - Sep. 2014
		Forward natural gasoline prices (per gallon) (1)	$1.93	-	$1.98	Jul. 2013 - Mar. 2014
		Crude option volatilities (%)	11.75%	-	24.92%	Jul. 2013 - Dec. 2013
Embedded derivatives in commodity contracts	Asset	ERCOT Pricing (per MegaWatt Hour) (2)	$ 28.09	-	$ 67.91	Jul. 2013 - Dec. 2014
	Liability	Forward propane prices (per gallon) (1)	$ 0.78	-	$ 0.88	Jul. 2013 - Dec. 2022
		Forward isobutane prices (per gallon) (1)	$ 1.13	-	$ 1.24	Jul. 2013 - Dec. 2022
		Forward normal butane prices (per gallon) (1)	$ 1.03	-	$ 1.20	Jul. 2013 - Dec. 2022
		Forward natural gasoline prices (per gallon) (1)	$ 1.66	-	$ 1.98	Jul. 2013 - Dec. 2022
		Forward natural gas prices (per MMBtu) (3)	$ 3.38	-	$ 6.42	Jul. 2013 - Dec. 2022
		Probability of renewal(4)	0%

(1)NGL prices used in the valuations are generally at the higher end of the range in the early periods and decrease over time with seasonal increases in the winter months.

18

(2)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.

(3)Natural gas prices used in the valuations are generally at the lower end of the range in the early years and increase over time.

(4)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 6. 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 6. 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 6, 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 June 30, 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 June 30, 2013 and 2012 for net assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

	Three months ended June 30, 2013
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	12,477		$	(24,881	)
Total gain (realized and unrealized) included in earnings (1)	16,896			20,459
Settlements	(2,995		)	2,019
Fair value at end of period	$	26,378		$	(2,403	)
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	14,755		$	20,766

	Three months ended June 30, 2012
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(17,450	)	$	(60,804	)
Total gain (realized and unrealized) included in earnings (1)	46,290			48,109
Settlements	716			2,300
Fair value at end of period	$	29,556		$	(10,395	)
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	43,894		$	47,300

	Six months ended June 30, 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)	20,220			26,991
Settlements	(6,291		)	4,563
Fair value at end of period	$	26,378		$	(2,403	)
The amount of total gains for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	17,854		$	27,229

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	Six months ended June 30, 2012
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(2,965	)	$	(53,904	)
Total gain (realized and unrealized) included in earnings (1)	34,214			37,671
Settlements	(1,693		)	5,838
Fair value at end of period	$	29,556		$	(10,395	)
The amount of total 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)	$	30,304		$	36,698

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

8. Inventories

Inventories consist of the following (in thousands):

	June 30, 2013		December 31, 2012
NGLs	$	25,097	$	14,763
Spare parts, materials and supplies	11,364		9,870
Total inventories	$	36,461	$	24,633

9. Goodwill

Changes in goodwill for the six months ended June 30, 2013 are summarized as follows (in thousands):

	Liberty		Northeast		Southwest			Total
Gross goodwill as of December 31, 2012	$	74,256	$	62,445	$	34,178		$	170,879
Acquisition (1)	—		—		2,682			2,682
Gross goodwill as of June 30, 2013	74,256		62,445		36,860			173,561
Cumulative impairment (2)	—		—		(28,705		)	(28,705		)
Balance as of June 30, 2013	$	74,256	$	62,445	$	8,155		$	144,856

(1)Represents goodwill associated with the Buffalo Creek Acquisition (see Note 4).

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

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10. Long-Term Debt

Debt is summarized below (in thousands):

	June 30, 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 $505 and $826, respectively, issued February and March 2011 and due August 2021	324,495		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 $6,791 and $7,126, respectively, issued August 2012 and due February 2023	743,209		742,874
2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023	1,000,000		—
Total long-term debt	$	3,022,704	$	2,523,051

(1)Applicable interest rate was 5.00% at June 30, 2013.

(2)The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $2,989.9 million and $2,763 million as of June 30, 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 June 30, 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 $271.5  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, $175.0 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 the 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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11. Equity

Equity Offerings

The Partnership has an At the Market offering program (the “ATM”) 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. 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 six months ended June 30, 2013, the Partnership sold an aggregate of 5.7 million common units under the ATM, receiving net proceeds of approximately $348.4 million after deducting approximately $5.2 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
June 30, 2013	$	71.20	$	56.90	$	0.84	July 24, 2013	August 6, 2013	August 14, 2013
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

12. 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 accompanying Condensed Consolidated Financial Statements and that none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition, liquidity or results of operations.

Contract Contingencies

Certain natural gas processing 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 June 30, 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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13. 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 six months ended June 30, 2013 and 2012 is as follows (in thousands):

	Six months ended June 30, 2013
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	52,839		$	40,023		$	(5,655	)	$	87,207
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	18,494			—			—			18,494
Permanent items	29			—			—			29
State income taxes net of federal benefit	1,321			161			—			1,482
Provision on income from Class A units (1)	2,835			—			—			2,835
Provision for income tax	$	22,679		$	161		$	—		$	22,840

	Six months ended June 30, 2012
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	94,600		$	154,519		$	2,206		$	251,325
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	33,110			—			—			33,110
Permanent items	16			—			—			16
State income taxes net of federal benefit	4,259			765			—			5,024
Provision on income from Class A units (1)	10,868			—			—			10,868
Provision for income tax	$	48,253		$	765		$	—		$	49,018

(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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14. Earnings Per Common Unit

The following table shows the computation of basic and diluted net income per common unit for the three and six months ended June 30, 2013 and 2012, and the weighted-average units used to compute basic and diluted net income per common unit (in thousands, except per unit data):

	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Net income attributable to the Partnership’s unitholders	$	83,699	$	186,908	$	68,241	$	202,928
Less: Income allocable to phantom units	554		1,209		1,100		1,391
Income available for common unitholders - basic	83,145		185,699		67,141		201,537
Add: Income allocable to phantom units and DER expense	569		1,218		1,135		1,414
Income available for common unitholders - diluted	$	83,714	$	186,917	$	68,276	$	202,951
Weighted average common units outstanding - basic	131,227		106,825		129,928		101,833
Potential common shares (Class B and phantom units)	20,639		20,643		20,652		20,698
Weighted average common units outstanding - diluted	151,866		127,468		150,580		122,531
Net income attributable to the Partnership’s common unitholders per common unit (1)
Basic	$	0.63	$	1.74	$	0.52	$	1.98
Diluted	$	0.55	$	1.47	$	0.45	$	1.66

(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.

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15. 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 June 30, 2013 and 2012 for the reported segments (in thousands).

Three months ended June 30, 2013:

	Liberty		Utica			Northeast		Southwest		Total
Segment revenue	$	120,057	$	3,594		$	45,365	$	227,842	$	396,858
Purchased product costs	16,993		—			15,126		123,240		155,359
Net operating margin	103,064		3,594			30,239		104,602		241,499
Facility expenses	22,272		6,412			6,655		29,778		65,117
Portion of operating loss attributable to non-controlling interests	—		(1,143		)	—		53		(1,090		)
Operating income (loss) before items not allocated to segments	$	80,792	$	(1,675	)	$	23,584	$	74,771	$	177,472

Three months ended June 30, 2012:

	Liberty		Utica			Northeast		Southwest (1)		Total
Segment revenue	$	59,477	$	—		$	42,051	$	206,551	$	308,079
Purchased product costs	8,018		—			12,921		91,792		112,731
Net operating margin	51,459		—			29,130		114,759		195,348
Facility expenses	13,364		283			4,932		32,156		50,735
Portion of operating (loss) income attributable to non-controlling interests	—		(113		)	—		28		(85		)
Operating income before items not allocated to segments	$	38,095	$	(170	)	$	24,198	$	82,575	$	144,698

(1)Amounts have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 3 of these Condensed Consolidated Financial Statements.

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The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the three months ended June 30, 2013 and 2012 (in thousands):

	Three months ended June 30,
	2013			2012 (3)
Total segment revenue	$	396,858		$	308,079
Derivative gain not allocated to segments	19,699			136,067
Revenue deferral adjustment and other (1)	(1,437		)	(1,324		)
Total revenue	$	415,120		$	442,822
Operating income before items not allocated to segments	$	177,472		$	144,698
Portion of operating income attributable to non-controlling interests	(1,090		)	(85		)
Derivative gain not allocated to segments	39,331			188,792
Revenue deferral adjustment and other (1)	(1,437		)	(1,324		)
Compensation expense included in facility expenses not allocated to segments	(368		)	(183		)
Facility expenses adjustments (2)	2,688			2,688
Selling, general and administrative expenses	(25,499		)	(21,700		)
Depreciation	(71,562		)	(41,336		)
Amortization of intangible assets	(17,092		)	(12,307		)
Gain (loss) on disposal of property, plant and equipment	37,736			(1,342		)
Accretion of asset retirement obligations	(157		)	(160		)
Income from operations	140,022			257,741
Earnings from unconsolidated affiliate	430			1,109
Interest income	62			159
Interest expense	(36,955		)	(26,762		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,784		)	(1,245		)
Miscellaneous income, net	6			4
Income before provision for income tax	$	101,781		$	231,006

(1)Amount relates primarily to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term. Therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnership’s chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended June 30, 2013, approximately $0.2 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. In comparison, for the three months ended June 30, 2012, approximately $0.2 million and $1.5 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

27

contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.  Other consists of management fee revenues from an unconsolidated affiliate of $0.2 million for the three months ended June 30, 2013 compared to $0.4 million for three months ended June 30, 2012.

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

(3)Amounts have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 3 of these Condensed Consolidated Financial Statements.

Six months ended June 30, 2013:

	Liberty		Utica			Northeast		Southwest		Total
Segment revenue	$	228,554	$	4,217		$	102,701	$	436,208	$	771,680
Purchased product costs	35,786		—			34,788		237,342		307,916
Net operating margin	192,768		4,217			67,913		198,866		463,764
Facility expenses	44,908		10,374			13,179		58,468		126,929
Portion of operating (loss) income attributable to non-controlling interests	—		(2,482		)	—		117		(2,365		)
Operating income before items not allocated to segments	$	147,860	$	(3,675	)	$	54,734	$	140,281	$	339,200
Capital expenditures	$	729,040	$	640,819		$	2,509	$	57,816	$	1,430,184
Capital expenditures not allocated to segments										4,900
Total capital expenditures										$	1,435,084

Six months ended June 30, 2012:

	Liberty		Utica			Northeast		Southwest (1)		Total
Segment revenue	$	135,054	$	—		$	128,969	$	441,927	$	705,950
Purchased product costs	32,653		—			38,608		196,025		267,286
Net operating margin	102,401		—			90,361		245,902		438,664
Facility expenses	25,611		283			11,310		64,094		101,298
Portion of operating (loss) income attributable to non-controlling interests	—		(113		)	—		31		(82		)
Operating income (loss) before items not allocated to segments	$	76,790	$	(170	)	$	79,051	$	181,777	$	337,448
Capital expenditures	$	415,506	$	16,786		$	43,475	$	101,481	$	577,248
Capital expenditures not allocated to segments										3,732
Total capital expenditures										$	580,980

(1)Amounts have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 3 of these Condensed Consolidated Financial Statements.

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The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the six months ended June 30, 2013 and 2012 (in thousands):

	Six months ended June 30,
	2013			2012 (3)
Total segment revenue	$	771,680		$	705,950
Derivative gain not allocated to segments	19,514			87,352
Revenue deferral adjustment and other (1)	(2,801		)	(3,217		)
Total revenue	$	788,393		$	790,085
Operating income before items not allocated to segments	$	339,200		$	337,448
Portion of operating (loss) income attributable to non-controlling interests	(2,365		)	(82		)
Derivative gain not allocated to segments	50,182			123,023
Revenue deferral adjustment and other(1)	(2,801		)	(3,217		)
Compensation expense included in facility expenses not allocated to segments	(754		)	(633		)
Facility expenses adjustments (2)	5,376			5,376
Selling, general and administrative expenses	(50,741		)	(46,748		)
Depreciation	(139,579		)	(80,918		)
Amortization of intangible assets	(31,922		)	(23,292		)
Gain (loss) on disposal of property, plant and equipment	37,598			(2,328		)
Accretion of asset retirement obligations	(509		)	(396		)
Income from operations	203,685			308,233
Earnings from unconsolidated affiliate	665			1,548
Interest income	211			231
Interest expense	(75,291		)	(56,234		)
Amortization of deferred financing costs and discount (a component of interest expense)	(3,614		)	(2,515		)
Loss on redemption of debt	(38,455		)	—
Miscellaneous income, net	6			62
Income before provision for income tax	$	87,207		$	251,325

(1)Amount relates primarily to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term. Therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnership’s chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the six months ended June 30, 2013, approximately $0.4 million and $3.0 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. In comparison, for the six months ended June 30, 2012, approximately $0.4 million and $3.6 million of the revenue deferral adjustment was attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.  The other consists of

29

management fee revenues from an unconsolidated affiliate of $0.6 million for the six months ended June 30, 2013 compared to $0.8 million for the six months ended June 30, 2012.

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

(3)Amounts have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 3 of these Condensed Consolidated Financial Statements.

The table below presents information about segment assets as of June 30, 2013 and December 31, 2012 (in thousands):

	June 30, 2013		December 31, 2012 (2)
Liberty	$	3,677,016	$	3,172,144
Utica	1,172,675		439,987
Northeast	572,110		578,122
Southwest	2,365,670		2,086,215
Total segment assets	7,787,471		6,276,468
Assets not allocated to segments:
Certain cash and cash equivalents	215,469		261,473
Fair value of derivatives	37,164		30,382
Investment in unconsolidated affiliate	69,327		63,054
Other (1)	91,452		96,985
Total assets	$	8,200,883	$	6,728,362

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

(2)Amounts have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 3 of these Condensed Consolidated Financial Statements.

16. Supplemental Condensed Consolidating Financial Information

MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of June 30, 2013, the Partnership’s obligations under the outstanding Senior Notes (see Note 10) 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 Annual Report on Form 10-K for the year ended December 31, 2012 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 June 30, 2013 and December 31, 2012 and for the three and six months ended June 30, 2013 and 2012 is as follows (in thousands):

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Condensed Consolidating Balance Sheets

	As of June 30, 2013
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	135,188	$	127,186	$	92,180	$	—		$	354,554
Restricted cash	—		—		10,000		—			10,000
Receivables and other current assets	5,114		211,511		87,967		—			304,592
Intercompany receivables	1,411,736		17,423		37,392		(1,466,551		)	—
Fair value of derivative instruments	—		23,140		1,606		—			24,746
Total current assets	1,552,038		379,260		229,145		(1,466,551		)	693,892
Total property, plant and equipment, net	3,521		2,156,435		4,215,787		(82,881		)	6,292,862
Other long-term assets:
Investment in unconsolidated affiliate	—		69,327		—		—			69,327
Investment in consolidated affiliates	4,260,881		3,200,111		—		(7,460,992		)	—
Intangibles, net of accumulated amortization	—		621,003		286,730		—			907,733
Fair value of derivative instruments	—		11,410		1,008		—			12,418
Intercompany notes receivable	225,000		—		—		(225,000		)	—
Other long-term assets	55,768		92,484		76,399		—			224,651
Total assets	$	6,097,208	$	6,530,030	$	4,809,069	$	(9,235,424	)	$	8,200,883
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	—	$	1,445,187	$	21,364	$	(1,466,551	)	$	—
Fair value of derivative instruments	—		17,871		—		—			17,871
Other current liabilities	59,937		197,247		537,767		(2,008		)	792,943
Total current liabilities	59,937		1,660,305		559,131		(1,468,559		)	810,814
Deferred income taxes	3,068		241,354		—		—			244,422
Long-term intercompany financing payable	—		225,000		98,558		(323,558		)	—
Fair value of derivative instruments	—		2,010		—		—			2,010
Long-term debt, net of discounts	3,022,704		—		—		—			3,022,704
Other long-term liabilities	2,894		140,480		8,573		—			151,947
Redeemable non-controlling interest	—		—		—		486,670			486,670
Equity:
Common units	2,256,074		4,260,881		4,142,807		(8,386,003		)	2,273,759
Class B units	752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries	—		—		—		456,026			456,026
Total equity	3,008,605		4,260,881		4,142,807		(7,929,977		)	3,482,316
Total liabilities and equity	$	6,097,208	$	6,530,030	$	4,809,069	$	(9,235,424	)	$	8,200,883

31

	As of December 31, 2012 (1)
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	210,015	$	102,979	$	32,762	$	—		$	345,756
Restricted cash	—		—		25,500		—			25,500
Receivables and other current assets	9,191		178,913		74,658		—			262,762
Intercompany receivables	812,562		18,472		32,656		(863,690		)	—
Fair value of derivative instruments	—		18,389		1,115		—			19,504
Total current assets	1,031,768		318,753		166,691		(863,690		)	653,522
Total property, plant and equipment, net	3,542		1,999,474		3,032,121		(95,519		)	4,939,618
Other long-term assets:
Restricted cash	—		—		10,000		—			10,000
Investment in unconsolidated affiliate	—		63,054		—		—			63,054
Investment in consolidated affiliates	4,104,473		2,719,920		—		(6,824,393		)	—
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		75,260		—			196,135
Total assets	$	5,415,649	$	5,741,408	$	3,579,907	$	(8,008,602	)	$	6,728,362
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	461	$	839,543	$	23,686	$	(863,690	)	$	—
Fair value of derivative instruments	—		27,062		167		—			27,229
Other current liabilities	42,301		197,934		472,462		(1,892		)	710,805
Total current liabilities	42,762		1,064,539		496,315		(865,582		)	738,034
Deferred income taxes	2,906		186,522		—		—			189,428
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		2,618		—			134,261
Equity:
Common Units	2,091,440		4,104,473		2,981,382		(7,079,891		)	2,097,404
Class B Units	752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries	—		—		—		261,463			261,463
Total equity	2,843,971		4,104,473		2,981,382		(6,818,428		)	3,111,398
Total liabilities and equity	$	5,415,649	$	5,741,408	$	3,579,907	$	(8,008,602	)	$	6,728,362

(1)The condensed consolidating financial statements have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 3 of these Condensed Consolidated Financial Statements.  The adjustments to the amounts previously reported were not material.

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Condensed Consolidating Statements of Operations

	Three months ended June 30, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	298,097		$	126,515		$	(9,492	)	$	415,120
Operating expenses:
Purchased product costs	—			117,813			17,114			—			134,927
Facility expenses	—			34,497			29,485			(385		)	63,597
Selling, general and administrative expenses	12,074			6,646			8,451			(1,672		)	25,499
Depreciation and amortization	242			45,457			44,292			(1,337		)	88,654
Other operating expenses (income)	—			573			(40,233		)	2,081			(37,579		)
Total operating expenses	12,316			204,986			59,109			(1,313		)	275,098
(Loss) income from operations	(12,316		)	93,111			67,406			(8,179		)	140,022
Earnings from consolidated affiliates	132,913			62,611			—			(195,524		)	—
Other expense, net	(40,102		)	(6,820		)	(2,997		)	11,678			(38,241		)
Income before provision for income tax	80,495			148,902			64,409			(192,025		)	101,781
Provision for income tax (benefit) expense	294			15,989			—			—			16,283
Net income	80,201			132,913			64,409			(192,025		)	85,498
Net income attributable to non-controlling interest	—			—			—			(1,799		)	(1,799		)
Net income attributable to the Partnership’s unitholders	$	80,201		$	132,913		$	64,409		$	(193,824	)	$	83,699

	Three months ended June 30, 2012 (1)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	381,527		$	63,394		$	(2,099	)	$	442,822
Operating expenses:
Purchased product costs	—			53,041			8,111			—			61,152
Facility expenses	—			33,111			14,129			(156		)	47,084
Selling, general and administrative expenses	12,539			2,205			10,999			(4,043		)	21,700
Depreciation and amortization	148			40,634			13,990			(1,129		)	53,643
Other operating expenses	—			628			874			—			1,502
Total operating expenses	12,687			129,619			48,103			(5,328		)	185,081
(Loss) income from operations	(12,687		)	251,908			15,291			3,229			257,741
Earnings from consolidated affiliates	217,483			13,960			—			(231,443		)	—
Other expense, net	(20,700		)	(4,611		)	(1,705		)	281			(26,735		)
Income before provision for income tax	184,096			261,257			13,586			(227,933		)	231,006
Provision for income tax expense	699			43,774			—			—			44,473
Net income	183,397			217,483			13,586			(227,933		)	186,533
Net income attributable to non-controlling interest	—			—			—			375			375
Net income attributable to the Partnership’s unitholders	$	183,397		$	217,483		$	13,586		$	(227,558	)	$	186,908

33

(1)The condensed consolidating financial statements have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 3 of these Condensed Consolidated Financial Statements.  The adjustments to the amounts previously reported were not material.

	Six months ended June 30, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	569,065		$	235,857		$	(16,529	)	$	788,393
Operating expenses:
Purchased product costs	—			240,763			36,017			—			276,780
Facility expenses	—			66,775			56,387			(387		)	122,775
Selling, general and administrative expenses	24,108			13,619			15,528			(2,514		)	50,741
Depreciation and amortization	519			89,510			84,295			(2,823		)	171,501
Other operating expenses (income)	—			1,338			(40,507		)	2,080			(37,089		)
Total operating expenses	24,627			412,005			151,720			(3,644		)	584,708
(Loss) income from operations	(24,627		)	157,060			84,137			(12,885		)	203,685
Earnings from consolidated affiliates	202,874			81,729			—			(284,603		)	—
Loss on redemption of debt	(38,455		)	—			—			—			(38,455		)
Other expense, net	(83,102		)	(13,236		)	(6,282		)	24,597			(78,023		)
Income before provision for income tax	56,690			225,553			77,855			(272,891		)	87,207
Provision for income tax (benefit) expense	161			22,679			—			—			22,840
Net income	56,529			202,874			77,855			(272,891		)	64,367
Net income attributable to non-controlling interest	—			—			—			3,874			3,874
Net (loss) income attributable to the Partnership’s unitholders	$	56,529		$	202,874		$	77,855		$	(269,017	)	$	68,241

	Six months ended June 30, 2012 (1)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	652,598		$	139,209		$	(1,722	)	$	790,085
Operating expenses:
Purchased product costs	—			201,642			32,865			—			234,507
Facility expenses	—			67,047			26,772			(156		)	93,663
Selling, general and administrative expenses	26,956			7,700			13,754			(1,662		)	46,748
Depreciation and amortization	312			79,927			25,338			(1,367		)	104,210
Other operating expenses	—			1,739			985			—			2,724
Total operating expenses	27,268			358,055			99,714			(3,185		)	481,852
(Loss) income from operations	(27,268		)	294,543			39,495			1,463			308,233
Earnings from consolidated affiliates	273,914			37,746			—			(311,660		)	—
Other expense, net	(44,044		)	(10,122		)	(2,370		)	(372		)	(56,908		)
Income before provision for income tax	202,602			322,167			37,125			(310,569		)	251,325
Provision for income tax expense	765			48,253			—			—			49,018
Net income (loss)	201,837			273,914			37,125			(310,569		)	202,307
Net income attributable to non-controlling interest	—			—			—			621			621
Net income attributable to the Partnership’s unitholders	$	201,837		$	273,914		$	37,125		$	(309,948	)	$	202,928

(1)The condensed consolidating financial statements have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 3 of these Condensed Consolidated Financial Statements.  The adjustments to the amounts previously reported were not material.

34

Condensed Consolidating Statements of Cash Flows

	Six months ended June 30, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(79,362	)	$	129,228		$	116,760		$	10,970		$	177,596
Cash flows from investing activities:
Restricted cash	—			—			25,500			—			25,500
Capital expenditures	(480		)	(53,319		)	(1,369,397		)	(11,888		)	(1,435,084		)
Equity investments in consolidated affiliates	(28,823		)	(783,600		)	—			812,423			—
Investment in unconsolidated affiliate	—			(8,336		)	—			—			(8,336		)
Distributions from consolidated affiliates	47,860			389,300			—			(437,160		)	—
Acquisition of business, net of cash acquired	—			(225,210		)	—			—			(225,210		)
Proceeds from disposal of property, plant and equipment	—			43			208,066			—			208,109
Net cash flows provided by (used in) investing activities	18,557			(681,122		)	(1,135,831		)	363,375			(1,435,021		)
Cash flows from financing activities:
Proceeds from public equity offerings, net	348,352			—			—			—			348,352
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	—			—			(918		)	918			—
Contributions from parent and affiliates	—			28,823			783,600			(812,423		)	—
Contribution from non-controlling interest	—			—			685,219			—			685,219
Share-based payment activity	(5,206		)	650			—			—			(4,556		)
Payment of distributions	(214,903		)	(47,860		)	(389,412		)	437,160			(215,015		)
Payments of SMR liability	—			(1,103		)	—			—			(1,103		)
Intercompany advances, net	(595,591		)	595,591			—			—			—
Net cash flows (used in) provided by financing activities	(14,022		)	576,101			1,078,489			(374,345		)	1,266,223
Net (decrease) increase in cash	(74,827		)	24,207			59,418			—			8,798
Cash and cash equivalents at beginning of year	210,015			102,979			32,762			—			345,756
Cash and cash equivalents at end of period	$	135,188		$	127,186		$	92,180		$	—		$	354,554

35

	Six months ended June 30, 2012 (1)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(77,181	)	$	214,781		$	116,298		$	(277	)	$	253,621
Cash flows from investing activities:
Restricted cash	—			—			1,003			—			1,003
Capital expenditures	(114		)	(166,926		)	(415,154		)	1,214			(580,980		)
Equity investments	(26,640		)	(843,960		)	—			869,761			(839		)
Acquisition of business, net of cash acquired	—			—			(506,797		)	—			(506,797		)
Distributions from consolidated affiliates	36,575			50,489			—			(87,064		)	—
Collection of intercompany notes, net	16,700			—			—			(16,700		)	—
Proceeds from disposal of property, plant and equipment	—			1,713			—			(1,214		)	499
Net cash flows provided by (used in) investing activities	26,521			(958,684		)	(920,948		)	765,997			(1,087,114		)
Cash flows from financing activities:
Proceeds from public equity offering, net	852,873			—			—			—			852,873
Proceeds from Credit Facility	238,065			—			—			—			238,065
Payments of Credit Facility	(86,200		)	—			—			—			(86,200		)
Payments related to intercompany financing, net	—			(16,700		)	(277		)	16,977			—
Payments for deferred financing costs	(2,315		)	—			—			—			(2,315		)
Contributions from parent and affiliates	—			26,640			843,121			(869,761		)	—
Contributions from non-controlling interest	—			—			1,101			—			1,101
Share-based payment activity	(8,048		)	2,207			—			—			(5,841		)
Payment of distributions	(155,073		)	(36,575		)	(50,560		)	87,064			(155,144		)
Payments of SMR liability	—			(1,005		)	—			—			(1,005		)
Intercompany advances, net	(788,664		)	788,664			—			—			—
Net cash flows provided by financing activities	50,638			763,231			793,385			(765,720		)	841,534
Net increase (decrease) in cash	(22		)	19,328			(11,265		)	—			8,041
Cash and cash equivalents at beginning of year	22			99,580			14,730			—			114,332
Cash and cash equivalents at end of period	$	—		$	118,908		$	3,465		$	—		$	122,373

(1)The condensed consolidating financial statements have been restated to reflect the deconsolidation of MarkWest Pioneer as discussed in Note 3 of these Condensed Consolidated Financial Statements.  The adjustments to the amounts previously reported were not material.

36

17. Supplemental Cash Flow Information

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

	Six months ended June 30,
	2013			2012
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	60,835		$	61,543
Cash (received) paid for income taxes, net	(16,591		)	18,425
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	524,445		$	236,495
Interest capitalized on construction in progress	19,090			8,048
Issuance of common units for vesting of share-based payment awards	4,495			2,501

18. Subsequent Events

Approximately four million Class B units converted to common units on July 1, 2013.  These converted units will participate in the distributions declared on July 24, 2013.  All of the Partnership’s Class B units were issued to and are held by M&R MWE Liberty, LLC, an affiliate of The Energy and Minerals Group (“EMG”), as part of the Company’s December 31, 2011 acquisition of the non-controlling interest in MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”). The remaining Class B units will convert to common units on a one-for-one basis in four equal installments beginning on July 1, 2014 and each of the next three anniversaries of such date.

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 June 30, 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) increased approximately $32.8 million, or 23%, for the three months ended June 30, 2013 compared to the same period in 2012. The increase is due primarily to an increase in the Liberty segment, offset by a decline in the Southwest segment.  On a consolidated basis, total processed volumes increased 53% and total gathered volumes increased 25%.

·The decrease in the Southwest segment is due to lower NGL prices, offset by an increase in volumes.

37

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

·Realized gain from the settlement of our derivative instruments was $2.0 million for the three months ended June 30, 2013 compared to a $5.0 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.

·In May 2013, we completed the Buffalo Creek Acquisition for total consideration of approximately $225 million, subject to final working capital adjustments.  The acquired assets included a 200 MMcf/d cryogenic gas processing plant currently under construction (“Buffalo Creek Processing Facility”), 22 miles of gas gathering pipeline in Hemphill County, Texas, and approximately 30 miles of rights-of-way associated with the future construction of a high-pressure trunk line.  We entered into a long-term fee-based agreement to provide treating, processing and certain gathering and compression services for natural gas owned or controlled by Chesapeake at the facilities acquired.  Chesapeake has dedicated 130,000 acres throughout the Anadarko Basin to us as part of this long-term agreement.  The Buffalo Creek Processing Facility is expected to commence operation in the fourth quarter of 2014.

·In the second quarter 2013, we completed construction of a 200 MMcf/d cryogenic processing plant at our existing Majorsville, West Virginia processing complex and a 200 MMcf/d cryogenic processing plant at our existing Sherwood, West Virginia processing complex.

·In the second quarter 2013, we commenced operation of a 125 MMcf/d cryogenic processing plant in Cadiz Township in Ohio (“Cadiz Complex”) facility in the Utica segment.

·In June 2013, we completed the Sherwood Asset Sale.  Under the terms of the agreement, the Partnership received proceeds of approximately $207.9 million, net of third party transaction costs.

·In the second quarter of 2013, we received net proceeds of approximately $244.5 million from a public offering of approximately 3.8 million newly issued common units representing limited partner interests in the Partnership as part of the ATM.  In July 2013, we completed the $600 million program that was initiated in November 2012.

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 15 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 15 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):

38

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Segment revenue	$	396,858		$	308,079		$	771,680		$	705,950
Purchased product costs	(155,359		)	(112,731		)	(307,916		)	(267,286		)
Net operating margin	241,499			195,348			463,764			438,664
Facility expenses	(62,797		)	(48,230		)	(122,307		)	(96,555		)
Derivative gain	39,331			188,792			50,182			123,023
Revenue deferral adjustment	(1,437		)	(1,324		)	(2,801		)	(3,217		)
Selling, general and administrative expenses	(25,499		)	(21,700		)	(50,741		)	(46,748		)
Depreciation	(71,562		)	(41,336		)	(139,579		)	(80,918		)
Amortization of intangible assets	(17,092		)	(12,307		)	(31,922		)	(23,292		)
Gain (loss) on disposal of property, plant and equipment	37,736			(1,342		)	37,598			(2,328		)
Accretion of asset retirement obligations	(157		)	(160		)	(509		)	(396		)
Income from operations	$	140,022		$	257,741		$	203,685		$	308,233

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 tables below.

For the three months ended June 30, 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)
Liberty	83	%	17	%	0	%
Utica	100	%	0	%	0	%
Northeast	24	%	18	%	58	%
Southwest	47	%	41	%	12	%
Total	61	%	27	%	12	%

For the six months ended June 30, 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)
Liberty	79	%	21	%	0	%
Utica	100	%	0	%	0	%
Northeast	21	%	16	%	63	%
Southwest	52	%	36	%	12	%
Total	59	%	27	%	14	%

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

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

Seasonality

Our business can be affected by seasonal fluctuations in the demand for natural gas and NGLs and the related fluctuations in commodity prices caused by various factors such as changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast segment could be particularly impacted by seasonality as the majority of its revenues are generated by NGL sales. However, we manage the seasonality impact through the execution of our marketing strategy. We have access to approximately 50 million gallons of propane storage capacity in the northeast region of the United States 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 15 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: Liberty, Utica, Northeast and Southwest. Our assets and operations in each of these segments are described below.

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 615 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.

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 2012 (the “Keystone Acquisition”).

Natural Gas Processing

·355 MMcf/d of current cryogenic processing capacity at our Houston Complex.  An additional 200 MMcf/d of cryogenic processing capacity is scheduled to be complete in 2015 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.

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

·600 MMcf/d expansion of our Majorsville Complex under construction that is supported by long-term agreements with Chesapeake, Statoil ASA and Range Resources Corporation. The Majorsville expansion includes three, 200 MMcf/d processing plants that are expected to commence operation in 2013, 2014 and 2016 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, Magnum Hunter Resources Corporation and others.  An additional 200 MMcf/d is scheduled to be complete by the first quarter of 2015.

·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 Corporation’s 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 the commencement date is based on our producer drilling activities.

Based on the currently planned facilities, MarkWest Liberty Midstream is expected to have up to approximately 3.6 Bcf/d of cryogenic processing capacity 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 Sherwood Complex to the Mobley Complex was completed in May 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 or train to a third-party terminal near Philadelphia, Pennsylvania where it is loaded onto marine vessels and delivered to international markets.  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 Sunoco’s Mariner East project, a pipeline and marine project that is expected to originate at our Houston Complex (“Mariner East”), 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 significant 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 large-scale railcar loading facility at our Houston Complex that expands our market access and allows for long-haul, cost effective transportation of purity NGLs.

·At our Keystone Complex we are also constructing additional fractionation capacity of 10,000 Bbl/d.  We expect to begin operations in first quarter of 2014.

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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 the United States and internationally. The primary components of our ethane recovery, fractionation and marketing solutions consist of the following:

·A de-ethanization facility of 38,000 Bbl/d at our Houston Complex was completed in the third quarter of 2013.  A second de-ethanization facility of 38,000 Bbl/d at our Majorsville Complex is expected to be completed by 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.

·A de-ethanization facility of 38,000 Bbl/d at our Sherwood Complex is expected to be completed in first quarter of 2015.

·At our Keystone Complex we are also constructing de-ethanization capacity of 10,000 Bbl/d.  We expect to begin operations in first quarter of 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 late 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 for propane, 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.

Utica Segment

We formed MarkWest Utica EMG, a joint venture with EMG to provide gathering, processing, fractionation and marketing services in the liquids-rich corridor of 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 processing facility in Cadiz Township in Ohio (“Cadiz Complex”) commenced operations in May 2013.

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

·600 MMcf/d processing in our processing facility in Seneca Township, Ohio (“Seneca Complex”).  The first two processing plants are expected to begin the first phase of operations in the fourth quarter of 2013, with processing capacity of 400 MMcf/d, and the third processing plant is expected to be operational in the second quarter 2014 with an additional processing capacity of 200 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.

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·Both the Cadiz Complex and the Seneca Complex 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 large-scale rail car loading facility and 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 half 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.

·At our Seneca Complex we are also constructing de-ethanization capacity of 38,000 Bbl/d.  We expect to begin operations in fourth quarter of 2014.

In August 2013, we executed a non-binding letter of intent with Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”) to form a midstream joint venture to pursue three critical new projects that would support producers in the Utica and Marcellus Shales in Ohio, Pennsylvania and West Virginia.  The first project would consist of the development of a cryogenic processing complex in Tuscarawas County, Ohio with initial capacity of 200 MMcf/d, expandable to a capacity of 400 MMcf/d (“Tuscarawas Complex”).  The second project would consist of the development of an NGL pipeline with initial capacity of 200,000 Bbl/d that originates at the planned Tuscarawas Complex in Ohio and transports NGLs to fractionation facilities in the Gulf Coast region.  The third joint project would involve the development of new fractionation facilities as well as the utilization of third-party fractionation facilities throughout the Gulf Coast region. The formation of the joint venture and the pursuit of the related projects is dependent upon the execution of definitive agreements.  In addition to this anticipated joint venture, we continue to evaluate projects to expand our gathering, processing, fractionation, and marketing operations in the Utica Shale.

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 above), 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.

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.

In May 2013, we completed the Buffalo Creek Acquisition.  The acquired assets include a 200 MMcf/d cryogenic gas processing plant currently under construction, 22 miles of gas gathering pipeline in Hemphill County, Texas, and approximately 30 miles of rights-of-way associated with the future construction of a high-pressure trunk line.  Additional assets consist of an amine treating facility and a five mile gas gathering pipeline in Washita County, Oklahoma.  We entered into a long-term fee-based agreement to provide treating and processing and certain gathering and compression services for natural gas produced by Chesapeake from 130,000 dedicated acres throughout the Anadarko Basin.

·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

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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.

·Eagle Ford Shale.  In April 2013, we announced the execution of long-term fee-based agreements with Newfield Exploration Co. (“Newfield”) for the development of a gathering system and associated storage services in the Eagle Ford Shale of south Texas.  We 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.

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 six months ended June 30, 2013:

	Liberty		Utica		Northeast		Southwest
Segment revenue	30	%	<1	%	13	%	57	%
Net operating margin	42	%	<1	%	15	%	43	%

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 June 30, 2013 and 2012 and for the six months ended June 30, 2013 and 2012. For each period presented, the Southwest segment includes the operations of our 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 separately.

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.  This section should be read in conjunction with the Operating Data table later in this Item 2 and the contract mix table included above in the section titled Our Contracts.

Three months ended June 30, 2013 compared to three months ended June 30, 2012

Liberty

	Three months ended June 30,
	2013		2012		$ Change		% Change
	(in thousands)
Segment revenue	$	120,057	$	59,477	$	60,580	102	%
Purchased product costs	16,993		8,018		8,975		112	%
Net operating margin	103,064		51,459		51,605		100	%
Facility expenses	22,272		13,364		8,908		67	%
Operating income before items not allocated to segments	$	80,792	$	38,095	$	42,697	112	%

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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 $43.0 million related to gathering, processing and fractionation fees, of which approximately $21.0 million is due to our Keystone Acquisition and the opening of the Sherwood Complex and the Mobley Complex, and by approximately $16.1 million related to NGL sales under percent of proceeds arrangements.

Purchased Product Costs.  Purchased product costs increased due to an increase in inventory sold, offset by a decrease in NGL prices.

Net Operating Margin.  Net operating margin increased as the volume of natural gas gathered, processed, and fractionated increased by 86%, 158% and 147%, respectively.  Approximately 83% of the net operating margin is earned under fee-based contracts and was not significantly impacted by the decline in commodity prices.  The Liberty segment net operating margin in the three months ended June 30, 2013 was reduced by less than $1 million due to limitations in storage and fractionation capacity, unexpected increases in the natural gas and NGL production, reduced demand or limited markets for certain NGL products, minor plant outages and the high ethane content in natural gas being delivered to us for processing.  The reductions in our margins will continue while we complete the construction of additional fractionation capacity and, depending on factors such as those listed above, may increase in the future.

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

Utica

	Three months ended June 30,
	2013			2012			$ Change			% Change
	(in thousands)
Segment revenue	$	3,594		$	—		$	3,594		N/A
Purchased product costs	—			—			—			N/A
Net operating margin	3,594			—			3,594			N/A
Facility expenses	6,412			283			6,129			2,166	%
Portion of operating loss attributable to non-controlling interests	(1,143		)	(113		)	(1,030		)	912	%
Operating loss before items not allocated to segments	$	(1,675	)	$	(170	)	$	(1,505	)	885	%

The results of operations for the quarter ended June 30, 2013 include our operations in Utica Shale areas of eastern Ohio. The first phase of operations began in the third quarter of 2012. The planned cryogenic processing capacity is expected to be in operation in 2014. Facility expenses in 2013 include start-up costs and other costs that cannot be capitalized, including approximately $2 million of amortization of costs to install temporary compression and treating facilities.  As the scale of our operations in the Utica segment continue to  grow in the second half of 2013 and into 2014,  the Utica segment net operating margin may be similarly affected by the capacity constraints and market limitations discussed above for the Liberty segment.

Northeast

	Three months ended June 30,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	45,365	$	42,051	$	3,314		8	%
Purchased product costs	15,126		12,921		2,205			17	%
Net operating margin	30,239		29,130		1,109			4	%
Facility expenses	6,655		4,932		1,723			35	%
Operating income before items not allocated to segments	$	23,584	$	24,198	$	(614	)	(3	)%

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Segment Revenue.  Revenue increased due to an increase in keep-whole NGLs sold and higher percent-of-proceed contract prices, partially offset by lower NGL prices.

Purchased Product Costs.  Purchased product costs increased due to an increase in keep-whole volumes and higher prices for natural gas that is purchased to satisfy the keep-whole arrangements in the Appalachia area.

Net Operating Margin. Net operating margin increased due to improved margins in our Michigan business and a 14% increase in keep-whole volumes of NGLs sold, partially offset by the decline in NGL prices and narrowing of the spread between NGL and natural gas prices as approximately 60% of the net operating margin is derived from commodity sensitive keep-whole contracts. The overall frac spread margins declined by approximately 16% as compared to the second quarter 2012.

Facility Expenses.  Facility expenses increased due primarily to the adjustment of approximately $1 million in second quarter 2012 related to a reduction in property taxes resulting from a favorable rate determination related to one of our facilities.

Southwest

	Three months ended June 30,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	227,842	$	206,551	$	21,291		10	%
Purchased product costs	123,240		91,792		31,448			34	%
Net operating margin	104,602		114,759		(10,157		)	(9	)%
Facility expenses	29,778		32,156		(2,378		)	(7	)%
Portion of operating (loss) income attributable to non-controlling interests	53		28		25			89	%
Operating income before items not allocated to segments	$	74,771	$	82,575	$	(7,804	)	(9	)%

Segment Revenue.  Revenues increased due to higher gas sales, hydrogen revenue and higher fee-based revenue.  Gas sales increased approximately $16.9 million in areas where we are operating in varying degrees of ethane rejection, whereby ethane was sold in the gas stream due to the higher gas prices. Hydrogen revenue increased in our Javelina facility by $5.0 million due to a 90% price increase.  The revenue increases were offset by lower NGL sales of $2.0 million due to lower pricing.

Purchased Product Costs. Purchase product costs increased due to increases in gas purchases of approximately $12.1 million primarily due to higher gas prices.  The remainder of the increase is due to higher NGL purchases of approximately $13.8 million related to the East Texas area increasing volumes processed and $9.3 million in Southeast Oklahoma due to a change in contract mix from keep-whole to percent of proceeds.  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.

Net Operating Margin.  Net operating margin decreased due to lower NGL prices as approximately 50% of the net operating margin is derived from commodity sensitive percent-of-proceeds and keep-whole arrangements.  The decreases in NGL prices were partially offset by an approximately 17% increase in the volume of natural gas processed primarily due to producers increased production in the rich gas areas of the Haynesville Shale, Woodford Shale and Cotton Valley formations.

Facility Expenses.  Facility expenses decreased due primarily to lower compressor expenses, lower number of compressor units, timing of facility maintenance and repairs.

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

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

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	Three months ended June 30,
	2013			2012			$ Change			% Change
	(in thousands)
Total segment revenue	$	396,858		$	308,079		$	88,779		29	%
Derivative gain not allocated to segments	19,699			136,067			(116,368		)	(86	)%
Revenue deferral adjustment and other	(1,437		)	(1,324		)	(113		)	9	%
Total revenue	$	415,120		$	442,822		$	(27,702	)	(6	)%
Operating income before items not allocated to segments	$	177,472		$	144,698		$	32,774		23	%
Portion of operating (loss) income attributable to non-controlling interests	(1,090		)	(85		)	(1,005		)	1,182	%
Derivative gain not allocated to segments	39,331			188,792			(149,461		)	(79	)%
Revenue deferral adjustment and other	(1,437		)	(1,324		)	(113		)	9	%
Compensation expense included in facility expenses not allocated to segments	(368		)	(183		)	(185		)	101	%
Facility expenses adjustments	2,688			2,688			—			0	%
Selling, general and administrative expenses	(25,499		)	(21,700		)	(3,799		)	18	%
Depreciation	(71,562		)	(41,336		)	(30,226		)	73	%
Amortization of intangible assets	(17,092		)	(12,307		)	(4,785		)	39	%
Gain (loss) on disposal of property, plant and equipment	37,736			(1,342		)	39,078			(2,912	)%
Accretion of asset retirement obligations	(157		)	(160		)	3			(2	)%
Income from operations	140,022			257,741			(117,719		)	(46	)%
Earnings from unconsolidated affiliates	430			1,109			(679		)	(61	)%
Interest income	62			159			(97		)	(61	)%
Interest expense	(36,955		)	(26,762		)	(10,193		)	38	%
Amortization of deferred financing costs and discount (a component of interest expense)	(1,784		)	(1,245		)	(539		)	43	%
Miscellaneous income, net	6			4			2			50	%
Income before provision for income tax	$	101,781		$	231,006		$	(129,225	)	(56	)%

Derivative (Loss) Gain Not Allocated to Segments.  Unrealized gain from the change in fair value of our derivative instruments was $37.3 million for the three months ended June 30, 2013 compared to an unrealized gain of $193.7 million for the same period in 2012. Realized gain from the settlement of our derivative instruments was $2.0 million for the three months ended June 30, 2013 compared to a realized loss of $4.9 million for the same period in 2012. The total change of $149.5 million is due mainly to volatility in commodity prices.

Revenue Deferral Adjustment and Other.  Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended June 30, 2013, approximately $0.2 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the three months ended June 30, 2012, approximately $0.2 million and $1.5 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. 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.  Other consists of management fee revenues from an unconsolidated affiliate of $0.2 million for the three months ended June 30, 2013 compared to $0.4 million for the three months ended June 30, 2012.

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 and the Buffalo Creek Acquisition.

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Gain (loss) on Disposal of Property, Plant and Equipment.  Gain on disposal of property, plant and equipment relates primarily to a gain on our Sherwood Asset sale in June 2013 of approximately $38.2 million.

Interest Expense.  Interest expense increased due to the increased amount of outstanding debt. The increase was partially offset by an increase in capitalized interest of $11.3 million.

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.

Six months ended June 30, 2013 compared to six months ended June 30, 2012

Liberty

	Six months ended June 30,
	2013		2012		$ Change		% Change
	(in thousands)
Segment revenue	$	228,554	$	135,054	$	93,500	69	%
Purchased product costs	35,786		32,653		3,133		10	%
Net operating margin	192,768		102,401		90,367		88	%
Facility expenses	44,908		25,611		19,297		75	%
Portion of operating loss attributable to non-controlling interests	—		—		—		N/A
Operating income before items not allocated to segments	$	147,860	$	76,790	$	71,070	93	%

Segment Revenue.  Revenue increased due to ongoing expansion of the Liberty segment operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $71.1 million related to gathering, processing and fractionation fees, of which approximately $35.4 million is due to our Keystone Acquisition and the opening of the Sherwood Complex and the Mobley Complex, and by approximately $20.1 million related to NGL sales under percent of proceeds arrangements or inventory sales.

Purchased Product Costs.  Purchased product costs increased due to an increase of inventory sold, offset by a decrease in NGL prices.

Net Operating Margin.  Net operating margin increased as the volume of natural gas gathered, processed, and fractionated increased by 91%, 135% and 116%, respectively.  Approximately 79% of the net operating margin is earned under fee-based contracts and was not significantly impacted by the decline in commodity prices.

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

Utica

	Six months ended June 30,
	2013			2012			$ Change			% Change
	(in thousands)
Segment revenue	$	4,217		$	—		$	4,217		N/A
Purchased product costs	—			—			—			N/A
Net operating margin	4,217			—			4,217			N/A
Facility expenses	10,374			283			10,091			3,566	%
Portion of operating loss attributable to non-controlling interests	(2,482		)	(113		)	(2,369		)	2,096	%
Operating loss before items not allocated to segments	$	(3,675	)	$	(170	)	$	(3,505	)	2,062	%

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The results of operations for the six months ended June 30, 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 including approximately $3 million of amortization of costs to install temporary compression and treating facilities.

Northeast

	Six months ended June 30,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	102,701	$	128,969	$	(26,268	)	(20	)%
Purchased product costs	34,788		38,608		(3,820		)	(10	)%
Net operating margin	67,913		90,361		(22,448		)	(25	)%
Facility expenses	13,179		11,310		1,869			17	%
Operating income before items not allocated to segments	$	54,734	$	79,051	$	(24,317	)	(31	)%

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 partially offset by higher gas prices.  The overall frac spread margins declined by approximately 29% as compared to the second quarter 2012.

Net Operating Margin. Net operating margin decreased due to the decline in NGL prices and narrowing of the spread between NGL and natural gas prices as approximately 63% of the net operating margin is derived from commodity sensitive keep-whole contracts.  The overall frac spread margins declined by approximately 29% as compared to the second quarter 2012.

Facility Expenses.  Facility expenses increased due primarily to the adjustment of approximately $1.0 million in second quarter 2012 related to a reduction in property taxes resulting from a favorable rate determination related to one of our facilities.

Southwest

	Six months ended June 30,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	436,208	$	441,927	$	(5,719	)	(1	)%
Purchased product costs	237,342		196,025		41,317			21	%
Net operating margin	198,866		245,902		(47,036		)	(19	)%
Facility expenses	58,468		64,094		(5,626		)	(9	)%
Portion of operating income attributable to non-controlling interests	117		31		86			277	%
Operating income before items not allocated to segments	$	140,281	$	181,777	$	(41,496	)	(23	)%

Segment Revenue.  Revenues decreased due to approximately $46 million lower NGL revenues, partially offset by approximately $9 million of higher fee-based revenue and approximately $24 million 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, operating in ethane rejection whereby ethane was sold in the gas stream and in condensate sales, and a change in contract mix, partially offset by increased processed volumes in our East Texas area.  Fee-based revenue increased as a result of a 20% increase in gathering volumes and a 40% increase in processing capacity in our East Texas area.  The increase in gas sales revenue is primarily caused by higher prices and operating in ethane rejection in certain areas.

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Purchased Product Costs. Purchased product costs increased due to increases in gas purchases of approximately $16.0 million primarily due to higher gas prices.  The remainder of the increase is due to higher NGL purchases, approximately $20.9 million in Southeast Oklahoma.  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.

Net Operating Margin.  Net operating margin decreased due to lower NGL prices as approximately 50% of the net operating margin is derived from commodity sensitive percent-of-proceeds and keep-whole arrangements.  The decreases in NGL prices were partially offset by an approximately 16% increase in the volume of natural gas processed primarily due to producers increased production in the rich gas areas of the Haynesville Shale, Woodford Shale, and Cotton Valley formations.

Facility Expenses.  Facility expenses decreased due primarily to lower compressor expenses, lower number of compressor units, timing of facility maintenance and repairs.

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

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

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	Six months ended June 30,
	2013			2012			$ Change			% Change
	(in thousands)
Total segment revenue	$	771,680		$	705,950		$	65,730		9	%
Derivative gain not allocated to segments	19,514			87,352			(67,838		)	(78	)%
Revenue deferral adjustment and other	(2,801		)	(3,217		)	416			(13	)%
Total revenue	$	788,393		$	790,085		$	(1,692	)	(0	)%
Operating income before items not allocated to segments	$	339,200		$	337,448		$	1,752		1	%
Portion of operating (loss) income attributable to non-controlling interests	(2,365		)	(82		)	(2,283		)	2,784	%
Derivative gain not allocated to segments	50,182			123,023			(72,841		)	(59	)%
Revenue deferral adjustment and other	(2,801		)	(3,217		)	416			(13	)%
Compensation expense included in facility expenses not allocated to segments	(754		)	(633		)	(121		)	19	%
Facility expenses adjustments	5,376			5,376			—			0	%
Selling, general and administrative expenses	(50,741		)	(46,748		)	(3,993		)	9	%
Depreciation	(139,579		)	(80,918		)	(58,661		)	72	%
Amortization of intangible assets	(31,922		)	(23,292		)	(8,630		)	37	%
Gain (loss) on disposal of property, plant and equipment	37,598			(2,328		)	39,926			(1,715	)%
Accretion of asset retirement obligations	(509		)	(396		)	(113		)	29	%
Income from operations	203,685			308,233			(104,548		)	(34	)%
Gain from unconsolidated affiliates	665			1,548			(883		)	(57	)%
Interest income	211			231			(20		)	(9	)%
Interest expense	(75,291		)	(56,234		)	(19,057		)	34	%
Amortization of deferred financing costs and discount (a component of interest expense)	(3,614		)	(2,515		)	(1,099		)	44	%
Loss on redemption of debt	(38,455		)	—			(38,455		)	N/A
Miscellaneous income, net	6			62			(56		)	(90	)%
Income before provision for income tax	$	87,207		$	251,325		$	(164,118	)	(65	)%

Derivative (Loss) Gain Not Allocated to Segments.  Unrealized gain from the change in fair value of our derivative instruments was $46.3 million for the six months ended June 30, 2013 compared to an unrealized gain of $145.5 million for the same period in 2012. Realized gain from the settlement of our derivative instruments was $3.9 million for the six months ended June 30, 2013 compared to a realized loss of $22.5 million for the same period in 2012. The total change of $72.8 million is due primarily to volatility in commodity prices.

Revenue Deferral Adjustment and Other.  Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the six months ended June 30, 2013, approximately $0.4 million and $3.0 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the six months ended June 30, 2012, approximately $0.4 million and $3.6 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. 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.  Other consists of management fee revenues from an unconsolidated affiliate of $0.6 million for the six months ended June 30, 2013 compared to $0.8 million for the six months ended June 30, 2012.

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.

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

Gain (loss) on Disposal of Property, Plant and Equipment.  Gain on disposal of property, plant and equipment relates primarily to a gain on our Sherwood Asset sale in June 2013 of approximately $38.2 million.

Interest Expense.  Interest expense increased due to the increased amount of outstanding debt. The increase was partially offset by an increase in capitalized interest of $14.5 million.

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 June 30,				Six months ended June 30,
	2013	2012	% Change		2013	2012	% Change
Liberty
Gathering system throughput(Mcf/d)	683,600	367,400	86	%	644,700	337,800	91	%
Natural gas processed (Mcf/d)	1,033,700	400,600	158	%	931,400	396,400	135	%
NGLs fractionated (Bbl/d)	48,900	19,800	147	%	43,000	19,900	116	%
NGL sales (gallons, in thousands) (1)	160,300	75,900	111	%	306,200	173,400	77	%
Utica (2)
Gathering system throughput (Mcf/d)	46,300	—	N/A		27,800	—	N/A
Natural gas processed (Mcf/d)	46,300	—	N/A		27,200	—	N/A
Northeast
Natural gas processed (Mcf/d)	296,400	328,200	(10	)%	299,500	324,900	(8	)%
NGLs fractionated (Bbl/d)	18,100	17,200	5	%	17,600	16,900	4	%
Keep-whole sales (gallons, in thousands)	27,100	23,700	14	%	60,000	73,300	(18	)%
Percent-of-proceeds sales (gallons, in thousands)	32,200	36,800	(13	)%	67,100	69,800	(4	)%
Total NGL sales (gallons, in thousands)	59,300	60,500	(2	)%	127,100	143,100	(11	)%
Crude oil transported for a fee (Bbl/d)	9,700	8,300	17	%	10,000	9,400	6	%
Southwest
East Texas gathering systems throughput (Mcf/d)	521,700	440,400	18	%	510,500	425,200	20	%
East Texas natural gas processed (Mcf/d)	377,600	268,300	41	%	358,600	255,400	40	%
East Texas NGL sales (gallons, in thousands)	90,200	68,000	33	%	170,700	131,400	30	%
Western Oklahoma gathering system throughput (Mcf/d) (3)	220,000	252,200	(13	)%	211,400	257,100	(18	)%
Western Oklahoma natural gas processed (Mcf/d)	189,900	218,900	(13	)%	188,100	211,400	(11	)%
Western Oklahoma NGL sales (gallons, in thousands)	42,900	61,700	(30	)%	97,700	119,000	(18	)%
Southeast Oklahoma gathering systems throughput (Mcf/d)	473,300	503,300	(6	)%	467,300	502,200	(7	)%
Southeast Oklahoma natural gas processed (Mcf/d)(4)	160,400	119,600	34	%	155,800	110,700	41	%
Southeast Oklahoma NGL sales (gallons, in thousands)	54,000	41,300	31	%	93,300	74,300	26	%
Other Southwest gathering system throughput (Mcf/d) (5)	39,900	26,700	49	%	30,300	25,600	18	%
Gulf Coast refinery off-gas processed (Mcf/d)	117,700	115,800	2	%	106,600	118,000	(10	)%
Gulf Coast liquids fractionated (Bbl/d)	22,100	21,700	2	%	19,700	22,500	(12	)%
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands)	84,600	83,000	2	%	149,700	172,300	(13	)%

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

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(2)Utica operations began in August 2012.

(3)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.

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

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

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			Six months ended June 30, 2013
Consolidated growth capital(1)	$	2,217		$	2,517		$	1,429
Utica joint venture partner’s estimated share of growth capital	(717		)	(717		)	(626		)
Partnership share of growth capital	$	1,500		$	1,800		$	803

(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 will be funded by cash generated from our operations.

Management believes that expenditures for our capital projects can be funded with current cash balances, proceeds from equity or debt offerings, contributions from joint venture partners, cash flows from operations and our current borrowing capacity under the Credit Facility. Our access to capital markets can be impacted by factors outside our control, which include but are not limited to general economic conditions and the rights of our Class B unitholders to participate in any future equity offerings we may commence after July 1, 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 the capital markets given our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings assigned by independent rating agencies. As of July 31, 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 negative 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.

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Under the provisions of the Credit Facility, we are subject to a number of restrictions and covenants. As of June 30, 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 July 31, 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 $271.5 million was available for borrowing based on financial covenant requirements.  Additionally, the full amount of unused capacity is available for borrowing on a short term basis to provide financial flexibility within a given fiscal quarter.

The Credit Facility and indentures governing the Senior Notes limit our and our restricted subsidiaries’ 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 July 31, 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.

Equity Financing Activities

In November 2012, we announced the ATM which allowed 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 were 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 could 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 would enter into a separate agreement with the Manager.  In the six months ended June 30, 2013, we sold an aggregate of 5.7 million common units under the Agreement, receiving net proceeds of approximately $348.4 million after deducting $5.2 million in manager fees and other third-party expenses. The proceeds from sales were used for general partnership purposes. We completed this $600 million program in July 2013.

Approximately four million Class B units converted to common units on July 1, 2013.  All of our Class B units were issued to and are held by M&R MWE Liberty, LLC (“M&R”), an affiliate of EMG, as part of our December 31, 2011 acquisition of the non-controlling interest in MarkWest Liberty Midstream. The remaining Class B units will convert to common units on a one-for-one basis in four equal installments beginning on July 1, 2014 and each of the next three anniversaries of such date.   M&R has the right to participate in any of our future equity offerings using the converted common units.

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. Pursuant to the Amended Utica LLC Agreement, the aggregate funding commitment of EMG Utica has increased from $500 million to $950 million.  EMG Utica completed its funding commitment in May 2013 and we began funding MarkWest Utica EMG in July 2013.

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.

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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.

Cash Flow

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

	Six months ended June 30,
	2013			2012			Change
Net cash provided by operating activities	$	177,596		$	253,621		$	(76,025	)
Net cash used in investing activities	(1,435,021		)	(1,087,114		)	(347,907		)
Net cash provided by financing activities	1,266,223			841,534			424,689

Net cash provided by operating activities decreased primarily due to approximately $93.3 million change in working capital, primarily due to $124.9 million decrease related to the timing of collections of receivables compared to 2012 and $30.7 million due to increase in inventories in 2013 compared to a decrease in 2012 due to timing of inventory sales, offset by $64.3 million increase related to the timing of payments of accounts payable and accrued liabilities.

Net cash used in investing activities decreased due to an $854 million increase in capital expenditures, primarily related to our expansion of our Liberty and Utica segments as discussed in our Segment Reporting section above, offset by proceeds of $207.9 million, net of cash paid for third party transaction fees, from our Sherwood Asset Sale and a decrease in business acquisition purchases of $281.6 million compared to the same period last year.

Net cash provided by financing activities increased primarily due to a $684.1 million increase in contributions from non-controlling interest holders and a $303.8 million increase in net borrowings, partially offset by a $504.5 million decrease in proceeds from public equity offerings and by a $59.8 million increase in distributions to unit holders.

Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of June 30, 2013, our purchase obligations for the remainder of 2013 were $696.1 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.  A portion of the proceeds, together with cash on hand, was used to repurchase $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 June 30, 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.

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Recent Accounting Pronouncements

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

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

The information about commodity price risk for the three months ended June 30, 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 June 30, 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	1,920	$	83.42	$	103.15	$	(79	)
2014	1,418	90.36		108.73		3,104

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2013	2,468	$	92.89	$	(1,020	)
2014	697	92.39		646

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2013	1,069	$	5.07	$	(326	)

Propane Collars	Volumes (Gal/d)	WAVG Floor (Per Gal)		WAVG Cap (Per Gal)		Fair Value (in thousands)
2013	120,848	$	0.80	$	0.97	$	199

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	6,098	$	0.93	$	79
2014	30,178	0.86		109

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	20,383	$	1.66	$	1,598
2014	7,517	1.57		956

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	23,580	$	1.53	$	1,555
2014	9,891	1.50		1,296

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	13,379	$	1.98	$	6
2014 (Jan – Mar)	7,249	1.91		(22		)

The following tables provide information on the volume of our taxable subsidiary’s commodity derivative activity for positions related to keep-whole price risk at June 30, 2013, including the WAVG:

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WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2013(1)	—	NA		$	884
2014	154	$	90.05	3

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2013	9,726	$	5.36	$	(3,269	)
2014	8,733	4.93		(3,852		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	89,068	$	1.02	$	2,578
2014	74,189	1.10		6,464

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	8,769	$	1.66	$	695
2014	7,516	1.45		653

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	24,071	$	1.53	$	1,564
2014	20,411	1.39		1,867

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	16,227	$	2.07	$	279
2014	7,106	2.32		1,106

The following tables provide information on the volume of MarkWest Liberty Midstream’s commodity derivative activity for positions related to long liquids price risk at June 30, 2013, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2013	647	$	87.57	$	105.49	$	110

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2014	358	$	91.85	$	242

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	50,024	$	0.92	$	500
2014 (Jan – Mar)	26,637	0.92		91

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	3,565	$	1.63	$	540

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	8,440	$	1.50	$	1,130

(1)During the second quarter of 2013, we effectively converted our swap hedges related to our 2013 NGL exposure from crude proxy hedges to direct NGL product hedges. We purchased crude swaps to offset the existing crude swap positions, effectively eliminating the price risk and locking in the value of the outstanding crude positions. At the same time, we executed direct NGL product positions to manage the NGL price risk.

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 June 30, 2013, including the WAVG:

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2014	36,822	$	0.88

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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 June 30, 2013, including the WAVG:

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2013 (Oct – Dec)	3,158	$	0.86
2014 (Jan – Mar)	9,643		0.87

Embedded Derivatives in Commodity Contracts

We have a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative (gain) loss related to purchased product costs. In February 2011, we executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of June 30, 2013, the estimated fair value of this contract was a liability of $61.6 million and the recorded value was a liability of $8.1 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception on February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of June 30, 2013 (in thousands):

Fair value of commodity contract	$	61,587
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of June 30, 2013	$	8,080

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 June 30, 2013, the estimated fair value of this contract was an asset of $5.7 million.

Interest Rate Risk

The information about interest rate risk for the six months ended June 30, 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.

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Credit Risk

The information about our credit risk for the six months ended June 30, 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 June 30, 2013. Based on this evaluation, the Partnership’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of June 30, 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.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2013 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 5. Other Information

Restatement of Prior Period Financial Statements

As discussed in Note 3 to the Condensed Consolidated Financial Statements included in Item 1 of this Form 10-Q, we determined that MarkWest Pioneer, a non-wholly owned subsidiary, was incorrectly consolidated as a variable interest entity in which we were the primary beneficiary. Our investment in MarkWest Pioneer should have been deconsolidated and accounted for using the equity method when we sold 50% of our investment in MarkWest Pioneer in 2009. Under the equity method, we would have recognized an impairment of our investment in MarkWest Pioneer of approximately $39.2 million ($35.4 million, net of provision for income tax) in the year ended December 31, 2009.  The effect of the deconsolidation and impairment was immaterial to the Consolidated Balance Sheets, Consolidated Statements of Operations, Consolidated Statements of Changes in Equity, Consolidated Statements of Cash Flows and Notes to the Consolidated Financial Statements for all periods presented in the Consolidated Financial Statements included in Item 8 of the Partnership’s Form 10-K for the year ended December 31, 2012. Correcting the cumulative effect of the error in the second quarter of 2013 could have had a significant effect on the results of operations for the full year, therefore we plan to restate comparative prior period Consolidated Financial Statements that will be included in our Form 10-K for the year ended December 31, 2013 to give effect to the deconsolidation and related impairment of MarkWest Pioneer in 2009.  Due to our assessment of materiality, however, we do not plan to amend previous filings.  Accordingly, the impact of the restatement on periods previously included in our Form 10-K for the year ended December 31, 2012 is shown in the tables below (in thousands).

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	December 31, 2012						December 31, 2011
Balance Sheets	As previously reported			As restated			As previously reported			As restated
Cash and cash equivalents	$	347,899		$	345,756		$	117,016		$	114,332
Receivables, net	198,769			197,977			226,561			225,001
Other current assets	35,053			34,871			11,748			11,578
Total current assets	656,639			653,522			446,107			441,693
Property, plant and equipment	5,700,176			5,542,316			3,302,369			3,145,561
Less: accumulated depreciation	(624,548		)	(602,698		)	(438,062		)	(422,512		)
Total property, plant and equipment, net	5,075,628			4,939,618			2,864,307			2,723,049
Investment in unconsolidated affiliate	31,179			63,054			27,853			63,076
Other long-term assets	2,242			2,140			1,595			1,493
Total assets	6,835,716			6,728,362			4,070,425			3,959,874
Accounts payable	320,645			320,627			179,871			179,775
Accrued liabilities	391,352			390,178			171,451			170,307
Total current liabilities	739,226			738,034			441,873			440,633
Deferred income taxes	191,318			189,428			93,664			91,250
Other long-term liabilities	134,340			134,261			121,356			121,283
Common Units	2,134,714			2,097,404			679,309			642,522
Non-controlling interest in consolidated subsidiaries	328,346			261,463			70,227			189
Total equity	3,215,591			3,111,398			1,502,067			1,395,242
Total liabilities and equity	$	6,835,716		$	6,728,362		$	4,070,425		$	3,959,874

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	Year Ended December 31, 2012				Year Ended December 31, 2011						Year Ended December 31, 2010
Statement of Operations	As previously reported		As restated		As previously reported			As restated			As previously reported			As restated
Revenue	$	1,395,231	$	1,383,279	$	1,534,434		$	1,522,592		$	1,241,563		$	1,226,789
Total revenue	1,451,766		1,439,814		1,505,399			1,493,557			1,187,631			1,172,857
Facility expenses	208,385		206,861		173,598			171,497			151,449			148,416
Selling, general and administrative expenses	94,116		93,444		81,229			80,441			75,258			74,558
Depreciation	189,549		183,250		149,954			143,704			123,198			116,949
Accretion of asset retirement obligations	677		672		1,190			1,185			237			240
Total operating expenses	1,070,038		1,061,538		1,187,235			1,178,091			999,169			989,190
Income (loss) from operations	381,728		378,276		318,164			315,466			188,462			183,667
Earnings (loss) from unconsolidated affiliates	699		2,328		(1,095		)	158			1,562			3,823
Income (loss) before provision for income tax	257,116		255,293		119,894			118,449			34,291			31,757
Net income (loss)	218,788		216,965		106,245			104,800			31,102			28,568
Net loss (income) attributable to non-controlling interest	1,614		3,437		(45,550		)	(44,105		)	(30,635		)	(28,101		)

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	Year Ended December 31, 2012						Year Ended December 31, 2011						Year Ended December 31, 2010
	As previously reported			As restated			As previously reported			As restated			As previously reported			As restated
Cash flows from operating activities:
Net income	$	218,788		$	216,965		$	106,245		$	104,800		$	31,102		$	28,568
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	189,549			183,250			149,954			143,704			123,198			116,949
Accretion of asset retirement obligations	677			672			1,190			1,185			237			237
Equity in (earnings) loss of unconsolidated affiliate	(699		)	(2,328		)	1,095			(158		)	(1,562		)	(3,823		)
Distributions from unconsolidated affiliate	2,600			8,416			300			4,382			2,508			8,448
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	32,588			31,993			(45,463		)	(45,107		)	(37,090		)	(36,924		)
Other current assets	(23,115		)	(23,285		)	(3,728		)	(3,557		)	2,654			2,654
Accounts payable and accrued liabilities	28,412			28,417			54,745			54,795			45,361			44,088
Other long-term assets	(647		)	(647		)	(307		)	(308		)	174			174
Net cash provided by operating activities	496,713			492,013			414,698			410,403			312,328			306,117
Cash flows from investing activities:
Capital expenditures	(1,951,427		)	(1,950,324		)	(551,281		)	(550,839		)	(458,668		)	(457,468		)
Investment in unconsolidated affiliate	(5,227		)	(6,066		)	—			—			—			—
Proceeds from disposal of property, plant and equipment	596			596			3,450			3,450			733			665
Net cash flows used in investing activities	(2,472,352		)	(2,472,088		)	(776,553		)	(776,111		)	(485,936		)	(484,804		)
Cash flows from financing activities:
Contributions from non-controlling interest	265,620			264,781			126,392			126,392			158,293			158,293
Payment of distributions to non-controlling interest	(5,887		)	(71		)	(66,887		)	(62,805		)	(6,150		)	(210		)
Net cash flows provided by financing activities	2,206,522			2,211,499			411,421			415,503			143,306			149,246
Net increase in cash and cash equivalents	230,883			231,424			49,566			49,795			(30,302		)	(29,441		)
Cash and cash equivalents at beginning of year	117,016			114,332			67,450			64,537			97,752			93,978
Cash and cash equivalents at end of period	347,899			345,756			117,016			114,332			67,450			64,537

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	Common Units						Non-controlling Interest						Total Equity
Statement of Changes in Equity	As previously reported			As restated			As previously reported			As restated			As previously reported			As restated
December 31, 2009 Balance	$	1,026,814		$	991,461		$	282,739		$	206,658		$	1,309,553		$	1,198,119
Distributions paid	(181,058		)	(181,058		)	(6,150		)	(210		)	(187,208		)	(181,268		)
Deferred income tax impact from changes in equity	(7,614		)	(7,858		)	—			—			(7,614		)	(7,858		)
Net income	467			467			30,635			28,101			31,102			28,568
December 31, 2010 Balance	993,049			957,452			465,517			392,842			1,458,566			1,350,294
Distributions paid	(218,398		)	(218,398		)	(66,887		)	(62,805		)	(285,285		)	(281,203		)
Deferred income tax impact from changes in equity	(62,227		)	(63,417		)	—			—			(62,227		)	(63,417		)
Net income	60,695			60,695			45,550			44,105			106,245			104,800
December 31, 2011 Balance	679,309			642,522			70,227			189			1,502,067			1,395,242
Distributions paid	(339,967		)	(339,967		)	(5,887		)	(71		)	(345,854		)	(340,038		)
Contributions from non-controlling interest	—			—			265,620			264,782			265,620			264,782
Deferred income tax impact from changes in equity	(66,566		)	(67,089		)	—			—			(66,566		)	(67,089		)
Net income	220,402			220,402			(1,614		)	(3,437		)	218,788			216,965
December 31, 2012 Balance	2,134,714			2,097,404			328,346			261,463			3,215,591			3,111,398

Supplemental Condensed Consolidating Financial Information as disclosed in Note 24 in the Notes to the Consolidated Financial Statements included in Item 8 of our Annual Report on Form 10-K for the year-ended December 31, 2012 and 2011 will also be corrected.  MarkWest Pioneer was a non-guarantor subsidiary and therefore, adjustments similar to those presented above will be made to that column in all condensed consolidating financial statements when presented.  Other minor adjustments to reflect the results and cash flows as an investment in unconsolidated affiliate versus an investment in consolidated affiliate will also be made.  Such information is not presented here due to our assessment of materiality but will be restated for the periods above in our Annual Report on Form 10-K for the year-ended December 31, 2013.

The unaudited interim financial information presented in our Condensed Consolidated Financial Statements included in Item 1 of our Form 10-Q for the quarter-ended March 31, 2013 will not be amended due to our assessment of materiality.  Our Form 10-Q for the quarter-ended September 30, 2013 will be restated to incorporate these prior period adjustments when filed.

Retrospective Accounting Change

On January 1, 2013, we adopted Accounting Standards Update (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities (ASU 2011-11), which enhances disclosures by requiring an entity to disclose information about netting arrangements, including rights of offset, to enable users of our financial statements to understand the effect of those arrangements on its financial position.  We also adopted ASU No. 2013-01, Balance Sheet (Topic 210) — Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU 2013-01), which provides clarification of the specific instruments that should be considered in these disclosures. These pronouncements were issued to facilitate comparison between financial statements prepared on the basis of GAAP and International Financial Reporting Standards. These updates were effective for annual and interim reporting periods beginning on or after January 1, 2013 and are to be applied retroactively for all comparative periods presented. The impact of retrospectively adjusting for the adoption of these pronouncements was immaterial to our historical consolidated financial statements.

The following presents the unaudited retrospective application of ASU 2011-11 and ASU 2013-01 by providing reconciliation between the gross derivative assets and liabilities reflected on the Consolidated Balance Sheets and the potential effects of master netting arrangements on the fair value of our derivative contracts at December 31, 2011.  The impact for December 31, 2012 can be found in Note 6 of these Condensed Consolidated Financial Statements.  Although certain derivative positions are subject to master netting agreements, we elected not to offset any derivative assets and liabilities. The gross amounts in the table below equal the balances presented in the Consolidated Balance Sheets as filed in our Annual Report on Form 10-K for the year ended December 31,

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2012.  The table below summarizes the impact if we had elected to net its derivative positions that are subject to master netting arrangements (in thousands):

	Assets							Liabilities
As of December 31, 2011	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	$	5,183	$	(4,073	)	$	1,110	$	(75,264	)	$	4,073	$	(71,191	)
Embedded derivatives in commodity contracts	3,515		—			3,515		(15,287		)	—		(15,287		)
Total current derivative instruments	8,698		(4,073		)	4,625		(90,551		)	4,073		(86,478		)
Non-current
Commodity contracts	12,090		(6,315		)	5,775		(19,269		)	6,315		(12,954		)
Embedded derivatives in commodity contracts	4,002		—			4,002		(46,134		)	—		(46,134		)
Total non-current derivative instruments	16,092		(6,315		)	9,777		(65,403		)	6,315		(59,088		)
Total derivative instruments	$	24,790	$	(10,388	)	$	14,402	$	(155,954	)	$	10,388	$	(145,566	)

In the table above, we do not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although our 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, our 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 table presented above.

PART II—OTHER INFORMATION

Item 1.  Legal Proceedings

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 12 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, except for the additional or updated risk factors set forth below:

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New climate change initiatives and increased focus on the regulation of greenhouse gas emissions could result in restrictions or delays in construction and installation of our facilities, increased operating costs, reduced demand for our services, and may adversely affect the cash flows available for distribution to our unitholders.

In June 2013, utilizing his executive authority, President Obama announced a climate change plan for the United States Environmental Protection Agency (“EPA”) to regulate carbon emissions under the Clean Air Act.  President Obama’s plan is initially focused on emissions standards for existing power plants and instructs the EPA to issue a proposal by June 1, 2014 and a final rule by June 1, 2015.  Under the plan, states will submit their implementation plans by June 30, 2016.  It is unclear if, and to what extent, the EPA may expand the scope of the plan to existing facilities in other industries, including the oil and natural gas industry.  Such an expansion, taken together with the EPA’s prior administrative conclusion that greenhouse gases (GHGs) present an endangerment to public health and the environment and the rules previously adopted by the EPA regulating the monitoring and reporting of GHG emissions from specified large GHG emission sources, could have a material adverse effect on our ability to operate our existing gathering, compression, processing and fractionation facilities as well as to construct and install new facilities of this nature.  We may experience delays in the construction and installation of new facilities due to more stringent permitting requirements, incur additional costs to reduce emissions of GHGs associated with our operations, or be required to aggregate the emissions from separate facilities for permitting purposes or to relocate one or more of our facilities due to more stringent emissions standards.  To the extent that we incur additional costs or delays, our cash available for distribution may be adversely affected.  Our producer customers may also experience similar issues, which may adversely impact their drilling schedules and production volumes and reduce the volumes of natural gas that we receive for gathering and processing.

Due to capacity, market and other constraints relating to the growth of our business, we may experience difficulties in the execution of our business plan, which may increase our costs and reduce our revenues and our cash available for distribution.

The successful execution of our business strategy is impacted by a variety of factors, including our ability to grow our business and satisfy our producer customers’ requirements for gathering, processing, fractionation and marketing services.  Our ability to grow our business and satisfy our customers’ requirements may be adversely affected by a variety of factors, including the following:

·more stringent permitting and other regulatory requirements;

·a limited supply of qualified fabrication and construction contractors, which could delay or increase the cost of the construction and installation of our facilities or increase the cost of operating our existing facilities;

·unexpected increases in the volume of natural gas and NGLs being delivered to our facilities, which could adversely affect our ability to expand our facilities in a manner that is consistent with our customers’ production schedules;

·unexpected outages or downtime at our facilities or at upstream or downstream third party facilities, which could reduce the volumes of gas and NGLs that we receive; and

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

If we are unable to successfully execute our business strategy, then our operating and capital expenditures may materially increase, and our revenues and our cash available for distribution to our common unitholders may be adversely affected.

Due to an increased domestic supply of NGLs, we may be required to rely more heavily on the export of NGLs to foreign countries, which may increase our operating costs or reduce the price received for NGLs, and thereby reduce our cash available for distribution.

Due to the increased production of natural gas in the United States, particularly in shale plays, there is an increased supply of NGLs, which is currently outpacing, and could continue to outpace, demand for NGLs domestically.  As a result, we and our producer customers may need to continue to rely more heavily on the export of NGLs to foreign countries.  Our ability to export NGLs to foreign countries on a competitive basis is impacted by various factors, including:

·availability of sufficient terminaling facilities in the United States;

·availability of sufficient rail car and tanker capacity;

·currency fluctuations, which may impact the effectiveness of our hedging program and which may be exacerbated to the extent sales are denominated in foreign currencies as we do not currently hedge against currency fluctuations;

·compliance with additional governmental regulations and maritime requirements, including U.S. export controls, sanctions regulations and the Foreign Corrupt Practices Act;

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·risks of loss resulting from nonpayment or nonperformance by international purchasers; and

·political and economic disturbances in the countries to which NGLs are being exported.

The above factors could increase our operating costs or adversely affect the price that we and our producer customers receive for NGLs, which in turn may have a material adverse effect on our volumes, revenues, income and cash available for distribution to our common unitholders.

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Item 6. Exhibits

4.1*	Twelfth Supplemental Indenture dated as of June 19, 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.
31.1*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	The following financial information from the quarterly report on Form 10-Q of MarkWest Energy Partners, L.P. for the quarter ended June 30, 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 Condensed Consolidated Financial Statements, tagged as blocks of text.

*Filed herewith

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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: August 7, 2013	/s/ FRANK M. SEMPLE
	Frank M. Semple
	Chairman, President & Chief Executive Officer
	(Principal Executive Officer)
Date: August 7, 2013	/s/ NANCY K. BUESE
	Nancy K. Buese
	Executive Vice President & Chief Financial Officer
	(Principal Financial Officer)
Date: August 7, 2013	/s/ PAULA L. ROSSON
	Paula L. Rosson
	Vice President & Chief Accounting Officer
	(Principal Accounting Officer)

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