Markwest Energy Partners L P 10-Q 2011 Q3 Quarterly report

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 September 30, 2011

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
(State or other jurisdiction of
incorporation or organization) 27-0005456
(IRS Employer
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

The number of the registrant’s common units outstanding as of October 28, 2011, was 84,939,558.

PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	2
	Unaudited Condensed Consolidated Balance Sheets at September 30, 2011 and December 31, 2010	2
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2011 and 2010	3
	Unaudited Condensed Consolidated Statements of Changes in Equity for the nine months ended September 30, 2011 and 2010	4
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010	5
	Unaudited Notes to the Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	49
Item 4.	Controls and Procedures	53
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	53
Item 1A.	Risk Factors	53
Item 6.	Exhibits	54
SIGNATURES		55

Throughout this document we make statements that are classified as “forward-looking.” Please refer to the “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 “General Partner” are intended to mean MarkWest Energy GP, L.L.C., the general partner of the Partnership.

Glossary of Terms

Bbl	Barrel
Bbl/d	Barrels per day
Credit Facility	Revolving credit facility as provided under the Amended and Restated Credit Agreement, dated July 1, 2010, among the Partnership, Wells Fargo Bank, National Association, as administrative agent, RBC Capital Markets, as syndication agent, BNP Paribas, Morgan Stanley Bank and U.S. Bank National Association, as documentation agents, and the lender parties thereto, as supplemented by the Joinder Agreement dated July 29, 2010 and the Joinder Agreement dated June 15, 2011 and as amended by that First Amendment thereto dated as of September 7, 2011.
Dth/d	Dekatherms per day
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
Gal	Gallon
Gal/d	Gallons per day
IFRS	International Financial Reporting Standards
Mcf/d	One thousand cubic feet of natural gas per day
MMBtu	One million British thermal units, an energy measurement
MMBtu/d	One million British thermal units per day
MMcf/d	One million cubic feet of natural gas per day
Net operating margin (a non-GAAP financial measure)	Segment revenue less purchased product costs, excluding any derivative gain (loss)
NGL	Natural gas liquids, such as ethane, propane, butanes and natural gasoline
N/A	Not applicable
OTC	Over-the-Counter
SEC	U.S. 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
TSR Performance Units	Phantom units containing performance vesting criteria related to the Partnership’s total shareholder return.
WTI	West Texas Intermediate
VIE	Variable interest entity

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PART I—FINANCIAL INFORMATION

Item 1.  Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	September 30, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents ($72,171 and $2,913, respectively)	$	159,177		$	67,450
Restricted cash ($25,143 and $0, respectively)	25,143			—
Receivables, net ($13,451 and $43,783, respectively)	192,271			179,209
Inventories ($21,919 and $8,431, respectively)	43,381			23,432
Fair value of derivative instruments ($280 and $0, respectively)	29,260			4,345
Deferred income taxes	16,090			16,090
Other current assets ($1,168 and $272, respectively)	8,745			8,020
Total current assets	474,067			298,546
Property, plant and equipment ($1,116,112 and $849,986, respectively)	3,121,547			2,613,027
Less: accumulated depreciation ($67,455 and $38,169, respectively)	(401,729		)	(294,003		)
Total property, plant and equipment, net	2,719,818			2,319,024
Other long-term assets:
Restricted cash ($3,007 and $28,001, respectively)	3,007			28,001
Investment in unconsolidated affiliate	27,126			28,688
Intangibles, net of accumulated amortization of $157,183 and $124,568, respectively	614,752			613,578
Goodwill	67,918			9,421
Deferred financing costs, net of accumulated amortization of $13,809 and $11,445, respectively	34,043			32,901
Deferred contract cost, net of accumulated amortization of $2,184 and $1,950, respectively	1,066			1,300
Fair value of derivative instruments	42,783			417
Other long-term assets ($361 and $383, respectively)	1,621			1,486
Total assets	$	3,986,201		$	3,333,362
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($35,724 and $5,945, respectively)	$	183,695		$	122,473
Accrued liabilities ($68,781 and $64,713, respectively)	168,168			153,869
Deferred income taxes	11			11
Fair value of derivative instruments	65,499			65,489
Total current liabilities	417,373			341,842
Deferred income taxes	28,765			10,427
Fair value of derivative instruments	34,161			66,290
Long-term debt, net of discounts of $1,499 and $1,566, respectively	1,477,963			1,273,434
Other long-term liabilities ($163 and $154, respectively)	118,835			105,349
Commitments and contingencies (Note 11)
Equity:
MarkWest Energy Partners, L.P. partners’ capital (79,190 and 71,440 common units issued and outstanding, respectively)	1,379,146			1,070,503
Non-controlling interest in consolidated subsidiaries	529,958			465,517
Total equity	1,909,104			1,536,020
Total liabilities and equity	$	3,986,201		$	3,333,362

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

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

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Operations

(unaudited, in thousands, except per unit amounts)

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Revenue:
Revenue	$	400,883		$	292,370		$	1,109,632		$	884,933
Derivative gain (loss)	106,943			(36,959		)	61,854			2,707
Total revenue	507,826			255,411			1,171,486			887,640
Operating expenses:
Purchased product costs	189,284			136,700			497,493			409,119
Derivative (gain) loss related to purchased product costs	(1,274		)	19,996			17,866			24,993
Facility expenses	44,236			37,934			124,358			113,266
Derivative gain related to facility expenses	(2,787		)	(564		)	(2,871		)	(436		)
Selling, general and administrative expenses	20,162			17,137			60,454			55,064
Depreciation	38,715			31,362			110,280			89,367
Amortization of intangible assets	10,985			10,193			32,632			30,579
Loss on disposal of property, plant and equipment	147			1,937			4,619			2,116
Accretion of asset retirement obligations	557			70			934			282
Total operating expenses	300,025			254,765			845,765			724,350
Income from operations	207,801			646			325,721			163,290
Other income (expense):
(Loss) earnings from unconsolidated affiliate	(507		)	—			(1,262		)	1,517
Interest income	62			422			214			1,185
Interest expense	(26,899		)	(26,433		)	(83,036		)	(75,970		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,002		)	(3,625		)	(3,873		)	(8,517		)
Derivative gain related to interest expense	—			—			—			1,871
Loss on redemption of debt	(133		)	—			(43,461		)	—
Miscellaneous (expense) income, net	(4		)	76			127			1,129
Income (loss) before provision for income tax	179,318			(28,914		)	194,430			84,505
Provision for income tax expense (benefit):
Current	3,959			3,533			8,104			10,254
Deferred	21,905			(13,771		)	18,338			(45		)
Total provision for income tax	25,864			(10,238		)	26,442			10,209
Net income (loss)	153,454			(18,676		)	167,988			74,296
Net income attributable to non-controlling interest	(13,142		)	(8,475		)	(33,208		)	(19,720		)
Net income (loss) attributable to the Partnership	$	140,312		$	(27,151	)	$	134,780		$	54,576
Net income (loss) attributable to the Partnership’s common unitholders per common unit (Note 14):
Basic	$	1.77		$	(0.39	)	$	1.75		$	0.77
Diluted	$	1.77		$	(0.39	)	$	1.75		$	0.77
Weighted average number of outstanding common units:
Basic	78,619			71,438			76,118			69,685
Diluted	78,760			71,438			76,276			69,831
Cash distribution declared per common unit	$	0.70		$	0.64		$	2.02		$	1.92

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

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Changes in Equity

(unaudited, in thousands)

	MarkWest Energy Partners, L.P. Unitholders
	Common Units	Partners’ Capital			Non-controlling Interest			Total
December 31, 2010	71,440	$	1,070,503		$	465,517		$	1,536,020
Share-based compensation activity	275	5,213			—			5,213
Excess tax benefits related to share-based compensation	—	1,089			—			1,089
Distributions paid	—	(155,931		)	(49,099		)	(205,030		)
Issuance of units in public offerings, net of offering costs	7,475	323,492			—			323,492
Contributions to MarkWest Liberty Midstream joint venture	—	—			80,332			80,332
Net income	—	134,780			33,208			167,988
September 30, 2011	79,190	$	1,379,146		$	529,958		$	1,909,104

	MarkWest Energy Partners, L.P. Unitholders
	Common Units	Partners’ Capital			Non-controlling Interest			Total
December 31, 2009	66,275	$	1,096,654		$	282,739		$	1,379,393
Share-based compensation activity	278	8,465			—			8,465
Excess tax benefits related to share-based compensation	—	97			—			97
Distributions paid	—	(134,949		)	(4,830		)	(139,779		)
Issuance of units in public offering, net of offering costs	4,887	142,255			—			142,255
Contributions to MarkWest Liberty Midstream joint venture	—	—			148,057			148,057
Net income	—	54,576			19,720			74,296
September 30, 2010	71,440	$	1,167,098		$	445,686		$	1,612,784

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

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Cash Flows

(unaudited, in thousands)

	Nine months ended September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	167,988		$	74,296
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	110,280			89,367
Amortization of intangible assets	32,632			30,579
Loss on redemption of debt	43,461			—
Amortization of deferred financing costs and discount	3,873			8,517
Accretion of asset retirement obligations	934			282
Amortization of deferred contract cost	234			234
Phantom unit compensation expense	10,611			11,430
Loss (earnings) of unconsolidated affiliate	1,262			(1,517		)
Distribution from unconsolidated affiliate	300			2,508
Unrealized gain on derivative instruments	(99,400		)	(11,885		)
Loss on disposal of property, plant and equipment	4,619			2,116
Deferred income taxes	18,338			(45		)
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	(12,776		)	(35,072		)
Inventories	(19,470		)	576
Other current assets	(725		)	2,026
Accounts payable and accrued liabilities	56,716			23,042
Other long-term assets	(284		)	(509		)
Other long-term liabilities	12,656			1,293
Net cash provided by operating activities	331,249			197,238
Cash flows from investing activities:
Capital expenditures	(359,926		)	(374,173		)
Acquisitions	(230,728		)	—
Proceeds from disposal of property, plant and equipment	2,968			524
Net cash used in investing activities	(587,686		)	(373,649		)
Cash flows from financing activities:
Proceeds from revolving credit facility	1,074,700			421,304
Payments of revolving credit facility	(929,600		)	(378,804		)
Proceeds from long-term debt	499,000			—
Payments of long-term debt	(440,638		)	—
Payments of premiums on redemption of long-term debt	(39,642		)	—
Payments for debt issuance costs, deferred financing costs and registration costs	(7,795		)	(11,230		)
Contributions to MarkWest Liberty Midstream joint venture	80,332			148,057
Payments of SMR liability	(1,390		)	(912		)
Proceeds from public offerings, net	323,492			142,255
Cash paid for taxes related to net settlement of share-based payment awards	(6,354		)	(3,834		)
Excess tax benefits related to share-based compensation	1,089			97
Payment of distributions to common unitholders	(155,931		)	(134,949		)
Payment of distributions to non-controlling interest	(49,099		)	(4,830		)
Net cash provided by financing activities	348,164			177,154
Net increase in cash	91,727			743
Cash and cash equivalents at beginning of year	67,450			97,752
Cash and cash equivalents at end of period	$	159,177		$	98,495

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

1. Organization and Basis of Presentation

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

These unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the SEC for interim financial reporting. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. These condensed consolidated financial statements should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010. In management’s opinion, the Partnership has made all adjustments necessary for a fair presentation of its results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. Finally, results for the three and nine months ended September 30, 2011 are not necessarily indicative of results for the full year 2011, or any other future period.

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

2. Recent Accounting Pronouncements

In September 2009, the FASB amended the accounting guidance for revenue recognition for multiple-deliverable arrangements. The amended guidance establishes a hierarchy for determining the selling price of each individual deliverable and eliminates the residual value method of allocating the selling price. The amended guidance was effective for the Partnership prospectively for all revenue arrangements entered into or materially modified on or after January 1, 2011. The amendment did not have a material effect on the Partnership’s condensed consolidated financial statements.

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

In September 2011, the FASB amended the accounting guidance for goodwill impairment testing.  The amended guidance provides an entity with an option to first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test.  The Partnership plans to early adopt the guidance for the period ended December 31, 2011.  The adoption of the amended guidance will not have a material effect on the Partnership’s condensed consolidated financial statements.

3. Business Combination

Langley Acquisition

On February 1, 2011, the Partnership acquired natural gas processing and NGL transportation assets from EQT Gathering, LLC, a subsidiary of EQT Corporation (together with all of its affiliates, “EQT”), for a cash purchase price of approximately $230.7 million.  The assets acquired include natural gas processing facilities located near Langley, Kentucky, consisting of a cryogenic natural gas processing plant with a capacity of approximately 100 MMcf/d and a refrigeration natural gas processing plant with a capacity of approximately 75 MMcf/d (together, the “Langley Processing Facilities”), a partially constructed NGL pipeline (the “Ranger Pipeline”) that will extend through parts of Kentucky and West Virginia, and certain other related assets. The acquired assets do not include certain residue gas compression and transportation facilities at the same location as the Langley Processing Facilities. This acquisition is referred to as the Langley Acquisition. In connection with the Langley Acquisition, the

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Partnership will complete the construction of the Ranger Pipeline to connect the Langley Processing Facilities to the Partnership’s existing pipeline that transports NGLs to its Siloam fractionation facility in South Shore, Kentucky.

Concurrently with the closing of the Langley Acquisition, the Partnership entered into a long-term agreement to process certain natural gas owned or controlled by EQT at the Langley Processing Facilities. The processing agreement requires the Partnership to install an additional cryogenic natural gas processing plant with a capacity of at least 60 MMcf/d in 2012. The Partnership exchanges the NGLs produced at the Langley Processing Facilities for fractionated products from its Siloam facility and markets the fractionated products on behalf of EQT in accordance with a long-term NGL exchange and marketing agreement. As a result of the acquisition, the Partnership has significantly expanded its midstream operations in the liquids-rich gas areas of the Appalachian Basin.

The Langley Acquisition is accounted for as a business combination. The total purchase price is allocated to the 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 Northeast segment.

The following table summarizes the purchase price allocation for the Langley Acquisition (in thousands):

Property, plant and equipment	$	136,525
Goodwill	58,497
Intangibles	33,900
Inventories	1,806
Total	$	230,728

The goodwill recognized from the Langley Acquisition results primarily from the Partnership’s ability to continue to grow its business in the liquids-rich gas areas of the Appalachian Basin and access additional markets in a competitive environment as a result of securing the processing rights for a large area of dedicated acreage and acquiring expanded midstream infrastructure in the acquisition. All of the goodwill is deductible for tax purposes.

Intangible assets consist of an identifiable customer contract and relationship. The acquired intangibles will be amortized on a straight-line basis over the estimated remaining useful life of approximately twelve years.

The results of operations from the Langley Acquisition are included in the condensed consolidated financial statements from the acquisition date. Revenue and net income related to the Langley Acquisition were approximately $6.2 million and $2.1 million, respectively, for the quarter ended September 30, 2011 and $16.3 million and $5.7 million, respectively, for the nine months ended September 30, 2011.

Pro forma financial results that give effect to the Langley Acquisition are not presented as it is impracticable to obtain the necessary information. EQT did not operate the acquired assets as a stand-alone business, and therefore historical financial information that is consistent with the operations under the current agreements is not available or meaningful.

4. Variable Interest Entities

MarkWest Liberty Midstream

MarkWest Liberty Midstream operates in the natural gas midstream business in and around the Marcellus Shale in western Pennsylvania and northern West Virginia. Effective January 1, 2011, equity interests in the entity are owned 51% by the Partnership and 49% by M&R MWE Liberty, LLC (“M&R”), an affiliate of The Energy & Minerals Group and its affiliated funds.

As of September 30, 2011, the cumulative capital contributed to MarkWest Liberty Midstream by each member is proportionate to its respective ownership interest (“Equalization”). However, until the third quarter of 2011, the cumulative capital contributed by M&R had exceeded its ownership interest. Under the terms of the joint venture agreement, M&R received a special $1.3 million allocation of net income from MarkWest Liberty Midstream during the nine months of 2011 due to its excess contributions. The allocation is recorded in Net income attributable to non-controlling interest.

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MarkWest Pioneer

MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline. Equity interests in the entity are shared equally by the Partnership and Arkoma Pipeline Partners, LLC.

Financial Statement Impact of VIEs

As the primary beneficiary of MarkWest Liberty Midstream and MarkWest Pioneer, the Partnership consolidates the entities and recognizes non-controlling interests. The following tables show the consolidated assets and liabilities attributable to VIEs, excluding intercompany balances, as of September 30, 2011 and December 31, 2010 (in thousands):

	As of September 30, 2011
	MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents	$	69,808	$	2,363	$	72,171
Restricted cash (current)	25,143		—		25,143
Receivables, net	12,116		1,335		13,451
Inventories	21,919		—		21,919
Fair value of derivative instruments (current)	280		—		280
Other current assets	1,168		—		1,168
Property, plant and equipment, net of accumulated depreciation of $53,468 and $13,987, respectively	906,199		142,458		1,048,657
Restricted cash (long-term)	3,007		—		3,007
Other long-term assets	259		102		361
Total assets	$	1,039,899	$	146,258	$	1,186,157
LIABILITIES
Accounts payable	$	35,644	$	80	$	35,724
Accrued liabilities	67,849		932		68,781
Other long-term liabilities	91		72		163
Total liabilities	$	103,584	$	1,084	$	104,668

	As of December 31, 2010
	MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents	$	—	$	2,913	$	2,913
Receivables, net	42,181		1,602		43,783
Inventories	8,431		—		8,431
Other current assets	271		1		272
Property, plant and equipment, net of accumulated depreciation of $28,869 and $9,300, respectively	664,778		147,039		811,817
Restricted cash (long-term)	28,001		—		28,001
Other long-term assets	281		102		383
Total assets	$	743,943	$	151,657	$	895,600
LIABILITIES
Accounts payable	$	5,945	$	—	$	5,945
Accrued liabilities	63,450		1,263		64,713
Other long-term liabilities	86		68		154
Total liabilities	$	69,481	$	1,331	$	70,812

The assets of the VIEs are the property of the respective entities and are not available to the Partnership for any other purpose, including as collateral for its secured debt (see Note 9 and Note 16). VIE asset balances can only be used to settle obligations of each respective VIE. The liabilities of the VIEs do not represent additional claims against the Partnership’s general assets, and the creditors or beneficial interest holders of the VIE do not have recourse to the general credit of the Partnership. The Partnership’s Liberty segment includes the results of operations of MarkWest Liberty Midstream and the Partnership’s Southwest segment includes

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the results of operations of MarkWest Pioneer (see Note 15). The cash flow information for MarkWest Liberty Midstream and MarkWest Pioneer comprise substantially all of the cash flow information of the Partnership’s non-guarantor subsidiaries (see Note 16). The Partnership’s maximum exposure to loss as a result of its involvement with the VIEs includes its equity investment, any additional capital contribution commitments and any operating expense incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to the VIEs that it was not contractually obligated to provide during the nine months ended September 30, 2011 and 2010.

5. Derivative Financial Instruments

Commodity Derivatives

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership’s control. The Partnership’s profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its own or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of natural gas drilling by our 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 hedging strategy governed by the risk management policy approved by the General Partner’s board of directors (the “Board”). The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps and options traded on the OTC market. The risk management policy does not allow for trading derivative contracts.

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

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

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

The Partnership enters into derivative contracts primarily with financial institutions that are participating members of the Credit Facility and collateral is not posted by the Partnership as the participating members have a collateral position in substantially all the wholly-owned assets of the Partnership. All of the Partnership’s financial derivative positions are currently with participating bank group members. Management conducts a standard credit review on counterparties and the Partnership has agreements containing collateral requirements. For all participating bank group members, collateral requirements do not exist when a derivative contract favors the Partnership. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).

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

9

As of September 30, 2011, 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	Notional Quantity (net)
Crude oil (bbl)	6,843,759
Natural gas (MMBtu)	14,857,174
NGLs (gal)	138,213,006

Embedded Derivatives in Commodity Contracts

The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative (gain) loss related to purchased product costs. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of September 30, 2011, the estimated fair value of this contract was a liability of $94.7 million and the recorded value was a liability of $41.1 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 September 30, 2011 (in thousands).

Fair value of commodity contract	$	94,652
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of September 30, 2011	$	41,145

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 one of its 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 September 30, 2011, the estimated fair value of this contract was an asset of $3.9 million.

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Financial Statement Impact of Derivative Instruments

There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010. The impact of the Partnership’s derivative instruments on its Condensed Consolidated Balance Sheets and its Condensed Consolidated Statements of Operations is summarized below (in thousands):

Derivative instruments not designated as hedging	Assets				Liabilities
instruments and their balance sheet location	September 30, 2011		December 31, 2010		September 30, 2011			December 31, 2010
Commodity contracts
Fair value of derivative instruments - current	$	29,260	$	4,345	$	(65,499	)	$	(65,489	)
Fair value of derivative instruments - long-term	42,783		417		(34,161		)	(66,290		)
Total	$	72,043	$	4,762	$	(99,660	)	$	(131,779	)

Derivative instruments not designated as hedging instruments and the location of gain or (loss)	Three months ended September 30,						Nine months ended September 30,
recognized in income	2011			2010			2011			2010
Revenue: Derivative gain (loss)
Realized loss	$	(9,809	)	$	(1,732	)	$	(36,386	)	$	(20,551	)
Unrealized gain (loss)	116,752			(35,227		)	98,240			23,258
Total revenue: derivative gain (loss)	106,943			(36,959		)	61,854			2,707
Derivative gain (loss) related to purchased product costs
Realized loss	(5,989		)	(3,946		)	(19,436		)	(15,117		)
Unrealized gain (loss)	7,263			(16,050		)	1,570			(9,876		)
Total derivative gain (loss) related to purchased product costs	1,274			(19,996		)	(17,866		)	(24,993		)
Derivative gain related to facility expenses
Unrealized gain	2,787			564			2,871			436
Derivative gain related to interest expense
Realized gain	—			—			—			2,380
Unrealized loss	—			—			—			(509		)
Total derivative gain related to interest expense	—			—			—			1,871
Miscellaneous (expense) income, net
Unrealized gain	—			103			—			162
Total gain (loss)	$	111,004		$	(56,288	)	$	46,859		$	(19,817	)

At September 30, 2011, the fair value of the Partnership’s commodity derivative contracts is inclusive of premium payments of $1.2 million, net of amortization. For the three months ended September 30, 2011 and 2010, the Realized loss—revenue includes amortization of premium payments of $1.2 million and $0.5 million, respectively. For the nine months ended September 30, 2011 and 2010, the Realized loss—revenue includes amortization of premium payments of $3.3 million and $1.6 million, respectively.

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6. Fair Value

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 5. The following table presents the derivative instruments carried at fair value as of September 30, 2011 and December 31, 2010 (in thousands):

As of September 30, 2011	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	34,678	$	(53,873	)
Significant unobservable inputs (Level 3)
Commodity contracts	33,458		(4,642		)
Embedded derivatives in commodity contracts	3,907		(41,145		)
Total carrying value in Condensed Consolidated Balance Sheet	$	72,043	$	(99,660	)

As of December 31, 2010	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	52	$	(77,776	)
Significant unobservable inputs (Level 3)
Commodity contracts	3,674		(18,031		)
Embedded derivatives in commodity contracts	1,036		(35,972		)
Total carrying value in Condensed Consolidated Balance Sheet	$	4,762	$	(131,779	)

Changes in Level 3 Fair Value Measurements

The table below includes a rollforward of the balance sheet amounts for the three and nine months ended September 30, 2011 and 2010 for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

	Three months ended September 30, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(22,290	)	$	(49,447	)
Total gain (realized and unrealized) included in earnings (1)	47,939			8,042
Settlements	3,167			4,167
Fair value at end of period	$	28,816		$	(37,238	)
The amount of total gain for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	48,544		$	8,337

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	Three months ended September 30, 2010
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Embedded Derivative in Debt Contract
Fair value at beginning of period	$	5,348		$	(23,636	)	$	(131	)
Total (loss) or gain (realized and unrealized) included in earnings (1)	(8,952		)	(11,977		)	103
Settlements (net)	65			2,298			—
Fair value at end of period	$	(3,539	)	$	(33,315	)	$	(28	)
The amount of total (loss) or gain 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)	$	(8,592	)	$	(11,345	)	$	103

	Nine months ended September 30, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(14,357	)	$	(34,936	)
Total gain or (loss) (realized and unrealized) included in earnings (1)	35,402			(14,063		)
Settlements	7,771			11,761
Fair value at end of period	$	28,816		$	(37,238	)
The amount of total gain or (loss) 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)	$	39,196		$	(10,813	)

	Nine months ended September 30, 2010
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Interest Rate Contracts			Embedded Derivative in Debt Contract
Fair value at beginning of period	$	(11,340	)	$	(34,199	)	$	509		$	(190	)
Total gain or (loss) (realized and unrealized) included in earnings (1)	1,319			(6,857		)	1,871			162
Settlements (net)	6,482			7,741			(2,380		)	—
Fair value at end of period	$	(3,539	)	$	(33,315	)	$	—		$	(28	)
The amount of total (loss) or gain 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)	$	(2,712	)	$	(4,703	)	$	—		$	162

(1)Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Derivative gain (loss) related to revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs, Derivative (gain) loss related to purchased product costs and Derivative gain related to facility expenses.  Gains on Embedded Derivatives in Debt Contract are recorded in Miscellaneous (expense) income, net.  Gains on Interest Rate Contracts are recorded in Derivative gain related to interest expense.

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7. Inventories

Inventories consist of the following (in thousands):

	September 30, 2011		December 31, 2010
NGLs	$	35,567	$	15,930
Spare parts, materials and supplies	7,814		7,502
Total inventories	$	43,381	$	23,432

The increase in NGL inventory primarily relates to the purchase of propane in the Liberty segment. The propane is expected to be sold during the fourth quarter of 2011 and first quarter of 2012.

8. Goodwill

Changes in goodwill are summarized as follows (in thousands):

	Southwest			Northeast		Gulf Coast			Total
Gross goodwill as of December 31, 2010	$	24,324		$	3,948	$	9,854		$	38,126
Acquisition(1)	—			58,497		—			58,497
Gross Goodwill as of September 30, 2011	24,324			62,445		9,854			96,623
Cumulative impairment (2)	(18,851		)	—		(9,854		)	(28,705		)
Balance as of September 30, 2011	$	5,473		$	62,445	$	—		$	67,918

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

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

9. Long-Term Debt

Debt is summarized below (in thousands):

	September 30, 2011		December 31, 2010
Credit Facility
Revolving credit facility, 4.25% interest due September 2016	$	145,100	$	—
Senior Notes (1)
Senior Notes, 8.5% interest, net of discount of $0 and $642, respectively, issued July 2006 and due July 2016	—		274,358
Senior Notes, 8.75% interest, net of discount of $555 and $924, respectively, issued April and May 2008 and due April 2018	333,807		499,076
Senior Notes, 6.75% interest, issued November 2010 and due November 2020	500,000		500,000
Senior Notes, 6.5% interest, net of discount of $944, issued February and March 2011 and due August 2021	499,056		—
Total long-term debt	$	1,477,963	$	1,273,434

(1)The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $1,350.2 million and $1,333.9 million as of September 30, 2011 and December 31, 2010, respectively, based on quoted market prices.

Credit Facility

On June 15, 2011, the Partnership executed a joinder agreement to the Credit Facility to include an additional member in the bank group and to exercise a portion of the accordion feature under the Credit Facility, thereby increasing the borrowing capacity of the Credit Facility to $745 million and reducing the uncommitted accordion feature to $155 million.

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On September 7, 2011, the Partnership amended the Credit Facility, increasing the borrowing capacity of the Credit Facility to $750 million, increasing the uncommitted accordion feature to $250 million, reducing the interest rate ranges by 75 basis points, and extending the maturity date to September 2016.

Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by the Partnership’s wholly-owned subsidiaries and collateralized by substantially all of the Partnership’s assets and those of its wholly-owned subsidiaries. As of September 30, 2011, the Partnership had $27.3 million of letters of credit outstanding under the Credit Facility and approximately $577.6 million available for borrowing.

Senior Notes

On February 24, 2011, the Partnership completed a public offering of $300 million in aggregate principal amount of 6.5% senior unsecured notes (“2021 Senior Notes”), which were issued at par. On March 10, 2011, the Partnership completed a follow-on public offering of an additional $200 million in aggregate principal amount of 2021 Senior Notes, which were issued at 99.5% of par and are treated as a single class of debt securities with the 2021 Senior Notes issued on February 24, 2011. The 2021 Senior Notes mature on August 15, 2021, and interest is payable semi-annually in arrears on February 15 and August 15, commencing August 15, 2011. The Partnership received aggregate net proceeds of approximately $492 million from the 2021 Senior Notes offerings after deducting the underwriting fees and other third-party expenses. The Partnership used the net proceeds from these offerings to fund the repurchase of approximately $272.2 million in aggregate principal amount of the Partnership’s 8.5% senior unsecured notes due 2016 (the “2016 Senior Notes”) and approximately $165.6 million in aggregate principal amount of the Partnership’s 8.75% senior unsecured notes due 2018 (the “2018 Senior Notes”). The remaining proceeds were used to repay borrowings under the Credit Facility. The Partnership recorded a pre-tax loss on redemption of debt of approximately $43.3 million in the first quarter of 2011 related to the repurchase of the 2016 Senior Notes and 2018 Senior Notes, which consisted of approximately $3.8 million for the non-cash write off of the unamortized discount and deferred finance costs and approximately $39.5 million for the payment of the related tender premiums and third-party expenses. On July 15, 2011, the Partnership repurchased the remaining 2016 Senior Notes. The Partnership recorded a pre-tax loss on redemption of debt of approximately $0.1 million in the third quarter of 2011 for the payment of tender premiums and third-party expenses related to the repurchase of the remaining 2016 Senior Notes.

10. Equity

Equity Offering

On January 14, 2011, the Partnership completed a public offering of approximately 3.45 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriter’s over-allotment option. Net proceeds after deducting the underwriting fees and third-party offering expenses were approximately $138 million and were used to partially fund the Partnership’s ongoing capital expenditure program, including a portion of the costs associated with the Langley Acquisition (see Note 3).

On July 13, 2011, the Partnership completed a public offering of approximately 4.0 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option.  Net proceeds after deducting underwriting fees and other third-party offering expenses were approximately $185 million and were used to repay borrowings under the Credit Facility and to partially fund the Partnership’s ongoing capital expenditure program.

Distributions of Available Cash

Quarter Ended	Distribution Per Common Unit		Declaration Date	Record Date	Payment Date
September 30, 2011	$	0.73	October 18, 2011	November 7, 2011	November 14, 2011
June 30, 2011	$	0.70	July 21, 2011	August 1, 2011	August 12, 2011
March 31, 2011	$	0.67	April 21, 2011	May 2, 2011	May 13, 2011
December 31, 2010	$	0.65	January 27, 2011	February 7, 2011	February 14, 2011

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11. Commitments and Contingencies

Legal

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

In June 2006, the Pipeline and Hazardous Materials Safety Administration issued a Notice of Probable Violation and Proposed Civil Penalty (“NOPV”) (CPF No. 2-2006-5001) to both MarkWest Hydrocarbon and Equitable Production Company (“Equitable”). The NOPV is associated with the pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 in Ivel, Kentucky on an NGL pipeline owned by Equitable and leased and operated by a subsidiary of the Partnership, MarkWest Energy Appalachia, L.L.C. The NOPV sets forth six counts of violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1.1 million. In March 2011, MarkWest received an order assessing a penalty solely against Equitable for count one of the NOPV in the amount of $0.5 million and assessing a penalty jointly and severally against MarkWest and Equitable for four of the other counts in the NOPV in the amount of $0.2 million. In March 2011, the parties filed separate petitions for reconsideration, which remain pending.

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

12. Incentive Compensation Plans

Compensation Expense

Total compensation expense recorded for share-based pay arrangements for the three and nine months ended September 30, 2011 and 2010 is as follows (in thousands):

	Three months ended September 30,				Nine months ended September 30,
	2011		2010		2011		2010
Phantom units	$	2,518	$	3,177	$	10,611	$	11,430
Distribution equivalent rights	115		548		327		1,169
Total compensation expense	$	2,633	$	3,725	$	10,938	$	12,599

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 nine months ended September 30, 2011 and 2010 is as follows (in thousands):

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

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	Nine months ended September 30, 2010
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	5,303		$	83,603		$	(4,401	)	$	84,505
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	$	1,856		$	—		$	—		$	1,856
Permanent items	6			—			—			6
State income taxes net of federal benefit	190			474			—			664
Provision on income from Class A units (1)	8,251			—			—			8,251
Other	(568		)	—			—			(568		)
Provision for income tax	$	9,735		$	474		$	—		$	10,209

(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. For further discussion of Class A units, see Item 1. Business in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010.

14. Earnings (Loss) Per Common Unit

The following table shows the computation of basic and diluted net income (loss) per common unit for the three and nine months ended September 30, 2011 and 2010, and the weighted-average units used to compute diluted net income (loss) per common unit (in thousands, except per unit data):

	Three months ended September 30,					Nine months ended September 30,
	2011		2010			2011		2010
Net income (loss) attributable to the Partnership	$	140,312	$	(27,151	)	$	134,780	$	54,576
Less: Income allocable to phantom units	1,287		370			1,288		921
Income (loss) available for common unitholders	$	139,025	$	(27,521	)	$	133,492	$	53,655
Weighted average common units outstanding - basic	78,619		71,438			76,118		69,685
Effect of dilutive instruments (1)	141		—			158		146
Weighted average common units outstanding - diluted (1)	78,760		71,438			76,276		69,831
Net income (loss) attributable to the Partnership’s common unitholders per common unit
Basic	$	1.77	$	(0.39	)	$	1.75	$	0.77
Diluted	$	1.77	$	(0.39	)	$	1.75	$	0.77

(1)Dilutive instruments include TSR Performance Units and are based on the number of units, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period. For the three months ended September 30, 2010, 247 units were excluded from the calculation of diluted units because the impact was anti-dilutive.

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.

The tables below present the Partnership’s segment profit measure, Operating income before items not allocated to segments, for the three and nine months ended September 30, 2011 and 2010 and capital expenditures for the nine months ended September 30, 2011 and 2010 for the reported segments (in thousands).

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Three months ended September 30, 2011:	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	241,998	$	55,920	$	78,586	$	26,868	$	403,372
Purchased product costs	141,067		15,947		32,270		—		189,284
Net operating margin	100,931		39,973		46,316		26,868		214,088
Facility expenses	21,043		6,879		9,108		9,798		46,828
Portion of operating income attributable to non-controlling interests	1,227		—		18,223		—		19,450
Operating income before items not allocated to segments	$	78,661	$	33,094	$	18,985	$	17,070	$	147,810

Three months ended September 30, 2010:	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	159,044	$	83,400	$	28,606	$	21,320	$	292,370
Purchased product costs	74,835		55,879		5,986		—		136,700
Net operating margin	84,209		27,521		22,620		21,320		155,670
Facility expenses	20,659		5,268		5,668		8,785		40,380
Portion of operating income attributable to non-controlling interests	1,906		—		6,772		—		8,678
Operating income before items not allocated to segments	$	61,644	$	22,253	$	10,180	$	12,535	$	106,612

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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 (loss) before provision for income tax for the three months ended September 30, 2011 and 2010 (in thousands).

	Three months ended September 30,
	2011			2010
Total segment revenue	$	403,372		$	292,370
Derivative gain (loss) not allocated to segments	106,943			(36,959		)
Revenue deferral adjustment (1)	(2,489		)	—
Total revenue	$	507,826		$	255,411
Operating income before items not allocated to segments	$	147,810		$	106,612
Portion of operating income attributable to non-controlling interests	19,450			8,678
Derivative gain (loss) not allocated to segments	111,004			(56,391		)
Revenue deferral adjustment (1)	(2,489		)	—
Compensation expense included in facility expenses not allocated to segments	(263		)	(404		)
Facility expenses adjustments	2,855			2,850
Selling, general and administrative expenses	(20,162		)	(17,137		)
Depreciation	(38,715		)	(31,362		)
Amortization of intangible assets	(10,985		)	(10,193		)
Loss on disposal of property, plant and equipment	(147		)	(1,937		)
Accretion of asset retirement obligations	(557		)	(70		)
Income from operations	207,801			646
Loss from unconsolidated affiliate	(507		)	—
Interest income	62			422
Interest expense	(26,899		)	(26,433		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,002		)	(3,625		)
Loss on redemption of debt	(133		)	—
Miscellaneous (expense) income, net	(4		)	76
Income (loss) before provision for income tax	$	179,318		$	(28,914	)

(1)Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended September 30, 2011, approximately $0.2 million and $2.3 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

19

Nine months ended September 30, 2011:	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	679,347	$	201,687	$	168,142	$	73,310	$	1,122,486
Purchased product costs	373,251		72,527		51,715		—		497,493
Net operating margin	306,096		129,160		116,427		73,310		624,993
Facility expenses	62,055		19,402		22,875		27,100		131,432
Portion of operating income attributable to non-controlling interests	3,745		—		45,782		—		49,527
Operating income before items not allocated to segments	$	240,296	$	109,758	$	47,770	$	46,210	$	444,034
Capital expenditures	$	80,069	$	17,768	$	256,877	$	1,282	$	355,996
Capital expenditures not allocated to segments									3,930
Total capital expenditures									$	359,926

Nine months ended September 30, 2010:	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	479,051	$	276,570	$	66,354	$	62,958	$	884,933
Purchased product costs	220,849		179,700		8,570		—		409,119
Net operating margin	258,202		96,870		57,784		62,958		475,814
Facility expenses	60,543		14,555		19,121		23,875		118,094
Portion of operating income attributable to non-controlling interests	4,962		—		15,617		—		20,579
Operating income before items not allocated to segments	$	192,697	$	82,315	$	23,046	$	39,083	$	337,141
Capital expenditures	$	89,949	$	1,918	$	275,620	$	3,418	$	370,905
Capital expenditures not allocated to segments									3,268
Total capital expenditures									$	374,173

20

The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the nine months ended September 30, 2011 and 2010 (in thousands).

	Nine months ended September 30,
	2011			2010
Total segment revenue	$	1,122,486		$	884,933
Derivative gain not allocated to segments	61,854			2,707
Revenue deferral adjustment (1)	(12,854		)	—
Total revenue	$	1,171,486		$	887,640
Operating income before items not allocated to segments	$	444,034		$	337,141
Portion of operating income attributable to non-controlling interests	49,527			20,579
Derivative gain (loss) not allocated to segments	46,859			(21,850		)
Revenue deferral adjustment (1)	(12,854		)	—
Compensation expense included in facility expenses not allocated to segments	(1,491		)	(1,412		)
Facility expenses adjustments	8,565			6,240
Selling, general and administrative expenses	(60,454		)	(55,064		)
Depreciation	(110,280		)	(89,367		)
Amortization of intangible assets	(32,632		)	(30,579		)
Loss on disposal of property, plant and equipment	(4,619		)	(2,116		)
Accretion of asset retirement obligations	(934		)	(282		)
Income from operations	325,721			163,290
(Loss) earnings from unconsolidated affiliate	(1,262		)	1,517
Interest income	214			1,185
Interest expense	(83,036		)	(75,970		)
Amortization of deferred financing costs and discount (a component of interest expense)	(3,873		)	(8,517		)
Derivative gain related to interest expense	—			1,871
Loss on redemption of debt	(43,461		)	—
Miscellaneous income, net	127			1,129
Income before provision for income tax	$	194,430		$	84,505

(1)Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the nine months ended September 30, 2011, approximately $6.9 million and $5.9 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

21

The tables below present information about segment assets as of September 30, 2011 and December 31, 2010 (in thousands):

SEGMENT ASSETS:

	September 30, 2011		December 31, 2010
Southwest	$	1,680,619	$	1,646,607
Northeast	479,576		244,219
Liberty	1,039,619		743,943
Gulf Coast	569,241		573,456
Total segment assets	3,769,055		3,208,225
Assets not allocated to segments:
Certain cash and cash equivalents	82,626		49,776
Fair value of derivatives	72,043		4,762
Investment in unconsolidated affiliate	27,126		28,688
Other (1)	35,351		41,911
Total assets	$	3,986,201	$	3,333,362

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

16. Supplemental Condensed Consolidating Financial Information

The Partnership has no operations independent of its subsidiaries. As of September 30, 2011, the Partnership’s obligations under the outstanding Senior Notes (see Note 9) were fully and unconditionally guaranteed, jointly and severally, by all of its wholly-owned subsidiaries. MarkWest Liberty Midstream and MarkWest Pioneer, together with certain of the Partnership’s other subsidiaries that do not guarantee the outstanding Senior Notes, have significant assets and operations in aggregate. For the purpose of the following financial information, the Partnership’s investments in its subsidiaries and the guarantor subsidiaries’ investments in their subsidiaries are presented in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. The operations, cash flows and financial position of the co-issuer of the Senior Notes, MarkWest Energy Finance Corporation, are minor and therefore have been included with the Parent’s financial information. Condensed consolidating financial information for the Partnership, its combined guarantor and combined non-guarantor subsidiaries as of September 30, 2011 and December 31, 2010 and for the three and nine months ended September 30, 2011 and 2010 is as follows (in thousands):

22

Condensed Consolidating Balance Sheets

	As of September 30, 2011
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	3	$	86,423	$	72,751	$	—		$	159,177
Restricted cash	—		—		25,143		—			25,143
Receivables and other current assets	846		222,835		36,806		—			260,487
Intercompany receivables	9,548		8,668		24,505		(42,721		)	—
Fair value of derivative instruments	—		28,980		280		—			29,260
Total current assets	10,397		346,906		159,485		(42,721		)	474,067
Total property, plant and equipment, net	4,191		1,681,413		1,049,629		(15,415		)	2,719,818
Other long-term assets:
Restricted cash	—		—		3,007		—			3,007
Investment in unconsolidated affiliate	—		27,126		—		—			27,126
Investment in consolidated affiliates	2,659,809		554,896		—		(3,214,705		)	—
Intangibles, net of accumulated amortization	—		614,201		551		—			614,752
Fair value of derivative instruments	—		42,783		—		—			42,783
Intercompany notes receivable	215,310		—		—		(215,310		)	—
Other long-term assets	33,733		70,554		361		—			104,648
Total assets	$	2,923,440	$	3,337,879	$	1,213,033	$	(3,488,151	)	$	3,986,201
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	8,568	$	33,807	$	346	$	(42,721	)	$	—
Fair value of derivative instruments	—		65,499		—		—			65,499
Other current liabilities	37,409		209,828		104,637		—			351,874
Total current liabilities	45,977		309,134		104,983		(42,721		)	417,373
Deferred income taxes	1,623		27,142		—		—			28,765
Intercompany notes payable	—		192,310		23,000		(215,310		)	—
Fair value of derivative instruments	—		34,161		—		—			34,161
Long-term debt, net of discounts	1,477,963		—		—		—			1,477,963
Other long-term liabilities	3,316		115,323		196		—			118,835
Equity:
MarkWest Energy Partners, L.P. partners’ capital	1,394,561		2,659,809		1,084,854		(3,760,078		)	1,379,146
Non-controlling interest in consolidated subsidiaries	—		—		—		529,958			529,958
Total equity	1,394,561		2,659,809		1,084,854		(3,230,120		)	1,909,104
Total liabilities and equity	$	2,923,440	$	3,337,879	$	1,213,033	$	(3,488,151	)	$	3,986,201

23

	As of December 31, 2010
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	63,850	$	3,600	$	—		$	67,450
Receivables and other current assets	1,708		172,209		52,834		—			226,751
Intercompany receivables	1,440,302		1,099		7,635		(1,449,036		)	—
Fair value of derivative instruments	—		4,345		—		—			4,345
Total current assets	1,442,010		241,503		64,069		(1,449,036		)	298,546
Total property, plant and equipment, net	4,623		1,512,763		812,898		(11,260		)	2,319,024
Other long-term assets:
Restricted cash	—		—		28,001		—			28,001
Investment in unconsolidated affiliate	—		28,688		—		—			28,688
Investment in consolidated affiliates	716,673		368,864		—		(1,085,537		)	—
Intangibles, net of accumulated amortization	—		613,000		578		—			613,578
Fair value of derivative instruments	—		417		—		—			417
Intercompany notes receivable	197,710		—		—		(197,710		)	—
Other long-term assets	32,587		12,139		382		—			45,108
Total assets	$	2,393,603	$	2,777,374	$	905,928	$	(2,743,543	)	$	3,333,362
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	672	$	1,447,799	$	565	$	(1,449,036	)	$	—
Fair value of derivative instruments	—		65,489		—		—			65,489
Other current liabilities	31,882		173,667		70,804		—			276,353
Total current liabilities	32,554		1,686,955		71,369		(1,449,036		)	341,842
Deferred income taxes	2,533		7,894		—		—			10,427
Intercompany notes payable	—		197,710		—		(197,710		)	—
Fair value of derivative instruments	—		66,290		—		—			66,290
Long-term debt, net of discounts	1,273,434		—		—		—			1,273,434
Other long-term liabilities	3,319		101,852		178		—			105,349
Equity:
MarkWest Energy Partners, L.P. partners’ capital	1,081,763		716,673		834,381		(1,562,314		)	1,070,503
Non-controlling interest in consolidated subsidiaries	—		—		—		465,517			465,517
Total equity	1,081,763		716,673		834,381		(1,096,797		)	1,536,020
Total liabilities and equity	$	2,393,603	$	2,777,374	$	905,928	$	(2,743,543	)	$	3,333,362

24

Condensed Consolidating Statements of Operations

	Three Months Ended September 30, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	425,142		$	82,684		$	—		$	507,826
Operating expenses:
Purchased product costs	—			155,612			32,398			—			188,010
Facility expenses	—			31,351			10,263			(165		)	41,449
Selling, general and administrative expenses	11,270			7,768			2,421			(1,297		)	20,162
Depreciation and amortization	182			38,391			11,314			(187		)	49,700
Other operating expenses	—			1,069			(365		)	—			704
Total operating expenses	11,452			234,191			56,031			(1,649		)	300,025
(Loss) income from operations	(11,452		)	190,951			26,653			1,649			207,801
Earnings from consolidated affiliates	174,458			13,479			—			(187,937		)	—
Loss on redemption of debt	(133		)	—			—			—			(133		)
Other expense, net	(20,609		)	(4,849		)	(32		)	(2,860		)	(28,350		)
Income before provision for income tax	142,264			199,581			26,621			(189,148		)	179,318
Provision for income tax expense	741			25,123			—			—			25,864
Net income	141,523			174,458			26,621			(189,148		)	153,454
Net income attributable to non-controlling interest	—			—			—			(13,142		)	(13,142		)
Net income attributable to the Partnership	$	141,523		$	174,458		$	26,621		$	(202,290	)	$	140,312

25

	Three Months Ended September 30, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Total revenue	$	—		$	222,004		$	33,407	$	—		$	255,411
Operating expenses:
Purchased product costs	—			150,689			6,007		—			156,696
Facility expenses	—			30,931			6,602		(163		)	37,370
Selling, general and administrative expenses	12,203			4,842			1,354		(1,262		)	17,137
Depreciation and amortization	147			34,400			7,117		(109		)	41,555
Other operating expenses	730			1,269			8		—			2,007
Total operating expenses	13,080			222,131			21,088		(1,534		)	254,765
(Loss) income from operations	(13,080		)	(127		)	12,319		1,534			646
Earnings from consolidated affiliates	9,249			4,256			—		(13,505		)	—
Other (expense) income, net	(21,539		)	(5,097		)	412		(3,336		)	(29,560		)
(Loss) income before provision for income tax	(25,370		)	(968		)	12,731		(15,307		)	(28,914		)
Provision for income tax benefit	(21		)	(10,217		)	—		—			(10,238		)
Net (loss) income	(25,349		)	9,249			12,731		(15,307		)	(18,676		)
Net income attributable to non-controlling interest	—			—			—		(8,475		)	(8,475		)
Net (loss) income attributable to the Partnership	$	(25,349	)	$	9,249		$	12,731	$	(23,782	)	$	(27,151	)

26

	Nine Months Ended September 30, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	991,993		$	179,493		$	—		$	1,171,486
Operating expenses:
Purchased product costs	—			463,459			51,900			—			515,359
Facility expenses	—			95,701			26,285			(499		)	121,487
Selling, general and administrative expenses	35,348			23,139			6,390			(4,423		)	60,454
Depreciation and amortization	538			112,868			30,010			(504		)	142,912
Other operating expenses	673			4,895			(15		)	—			5,553
Total operating expenses	36,559			700,062			114,570			(5,426		)	845,765
(Loss) income from operations	(36,559		)	291,931			64,923			5,426			325,721
Earnings from consolidated affiliates	287,377			31,623			—			(319,000		)	—
Loss on redemption of debt	(43,461		)	—			—			—			(43,461		)
Other expense, net	(67,574		)	(10,583		)	(92		)	(9,581		)	(87,830		)
Income before provision for income tax	139,783			312,971			64,831			(323,155		)	194,430
Provision for income tax expense	848			25,594			—			—			26,442
Net income	138,935			287,377			64,831			(323,155		)	167,988
Net income attributable to non-controlling interest	—			—			—			(33,208		)	(33,208		)
Net income attributable to the Partnership	$	138,935		$	287,377		$	64,831		$	(356,363	)	$	134,780

27

	Nine Months Ended September 30, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Total revenue	$	—		$	807,585		$	80,055	$	—		$	887,640
Operating expenses:
Purchased product costs	—			425,469			8,643		—			434,112
Facility expenses	—			91,074			22,245		(489		)	112,830
Selling, general and administrative expenses	35,243			19,370			4,141		(3,690		)	55,064
Depreciation and amortization	438			101,034			18,739		(265		)	119,946
Other operating expenses	730			1,364			304		—			2,398
Total operating expenses	36,411			638,311			54,072		(4,444		)	724,350
(Loss) income from operations	(36,411		)	169,274			25,983		4,444			163,290
Earnings from consolidated affiliates	156,634			7,521			—		(164,155		)	—
Other (expense) income, net	(60,675		)	(10,427		)	1,258		(8,941		)	(78,785		)
Income before provision for income tax	59,548			166,368			27,241		(168,652		)	84,505
Provision for income tax expense	475			9,734			—		—			10,209
Net income	59,073			156,634			27,241		(168,652		)	74,296
Net income attributable to non-controlling interest	—			—			—		(19,720		)	(19,720		)
Net income attributable to the Partnership	$	59,073		$	156,634		$	27,241	$	(188,372	)	$	54,576

28

Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(89,044	)	$	303,401		$	121,551		$	(4,659	)	$	331,249
Cash flows from investing activities:
Capital expenditures	(785		)	(100,155		)	(264,996		)	6,010			(359,926		)
Acquisitions	—			(230,728		)	—			—			(230,728		)
Equity investments	(34,246		)	(204,428		)	—			238,674			—
Distributions from consolidated affiliates	37,978			50,019			—			(87,997		)	—
Investment in intercompany notes, net	(17,600		)	—			—			17,600			—
Proceeds from disposal of property, plant and equipment	—			365			3,954			(1,351		)	2,968
Net cash used in investing activities	(14,653		)	(484,927		)	(261,042		)	172,936			(587,686		)
Cash flows from financing activities:
Proceeds from revolving credit facility	1,074,700			—			—			—			1,074,700
Payments of revolving credit facility	(929,600		)	—			—			—			(929,600		)
Proceeds from long-term debt	499,000			—			—			—			499,000
Payments of long-term debt	(440,638		)	—			—			—			(440,638		)
Payments of premiums on redemption of long-term debt	(39,642		)	—			—			—			(39,642		)
(Payments of) proceeds from intercompany notes, net	—			(5,400		)	23,000			(17,600		)	—
Payments for debt issuance costs, deferred financing costs and registration costs	(7,795		)	—			—			—			(7,795		)
Contributions to guarantor subsidiaries, net	—			34,246			—			(34,246		)	—
Contributions to joint ventures, net	—			—			284,760			(204,428		)	80,332
Payments of SMR liability	—			(1,390		)	—			—			(1,390		)
Proceeds from public equity offering, net	323,492			—			—			—			323,492
Share-based payment activity	(6,354		)	1,089			—			—			(5,265		)
Payment of distributions	(155,931		)	(37,978		)	(99,118		)	87,997			(205,030		)
Intercompany advances, net	(213,532		)	213,532
Net cash provided by financing activities	103,700			204,099			208,642			(168,277		)	348,164
Net increase in cash	3			22,573			69,151			—			91,727
Cash and cash equivalents at beginning of year	—			63,850			3,600			—			67,450
Cash and cash equivalents at end of period	$	3		$	86,423		$	72,751		$	—		$	159,177

29

	Nine Months Ended September 30, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(63,740	)	$	230,279		$	35,460		$	(4,761	)	$	197,238
Cash flows from investing activities:
Capital expenditures	(569		)	(97,039		)	(281,326		)	4,761			(374,173		)
Equity investments	(32,442		)	(130,074		)	—			162,516			—
Distributions from consolidated affiliates	33,237			14,512			—			(47,749		)	—
Payments for intercompany notes, net	(1,550		)	—			—			1,550			—
Proceeds from disposal of property, plant and equipment	—			524			—			—			524
Net cash used in investing activities	(1,324		)	(212,077		)	(281,326		)	121,078			(373,649		)
Cash flows from financing activities:
Proceeds from revolving credit facility	421,304			—			—			—			421,304
Payments of revolving credit facility	(378,804		)	—			—			—			(378,804		)
Proceeds from intercompany notes, net	—			1,550			—			(1,550		)	—
Payments for debt issuance costs, deferred financing costs and registration costs	(11,230		)	—			—			—			(11,230		)
Contributions from parent, net	—			32,442			—			(32,442		)	—
Contributions to joint ventures, net	—			—			278,131			(130,074		)	148,057
Payments of SMR liability	—			(912		)	—			—			(912		)
Proceeds from public offering, net	142,255			—			—			—			142,255
Share-based payment activity	(3,834		)	97			—			—			(3,737		)
Payment of distributions	(134,949		)	(33,237		)	(19,342		)	47,749			(139,779		)
Intercompany advances, net	30,322			(30,322		)	—			—			—
Net cash provided by (used in) financing activities	65,064			(30,382		)	258,789			(116,317		)	177,154
Net (decrease) increase in cash	—			(12,180		)	12,923			—			743
Cash and cash equivalents at beginning of year	—			74,448			23,304			—			97,752
Cash and cash equivalents at end of period	$	—		$	62,268		$	36,227		$	—		$	98,495

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17. Supplemental Cash Flow Information

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

	Nine months ended September 30,
	2011		2010
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	76,876	$	64,448
Cash paid for income taxes, net of refunds	5,051		8,760
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	85,666	$	53,381
Interest capitalized on construction in progress	571		2,719
Issuance of common units for vesting of share-based payment awards	5,412		7,238

18. Subsequent Events

Equity Offering

On October 13, 2011, the Partnership completed a public offering of approximately 5.75 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option.  Net proceeds after deducting underwriting fees and other third-party expenses were approximately $251 million and were used to repay borrowings under the Credit Facility and to provide working capital for general partnership purposes.

Senior Notes Offering and Tender Offer

On October 25, 2011, the Partnership commenced a public offering of $700 million in aggregate principal amount of 6.25% senior unsecured notes due June 2022 (“2022 Senior Notes”).  The offering is expected to close on November 3, 2011. Interest on the 2022 Notes is payable semi-annually in arrears on June 15 and December 15, commencing June 15, 2012. The Partnership intends to use the net proceeds from this offering to fund the repurchase of any and all of the $334.4 million outstanding 2018 Senior Notes that are tendered pursuant to a concurrent tender offer, and any remaining net proceeds will be used to provide additional working capital for general partnership purposes.  The Partnership has offered to repurchase the 2018 Senior Notes at 112.5% of their principal amounts for all notes tendered prior to November 9, 2011. Any 2018 Senior Notes tendered after November 9, 2011 but prior to November 25, 2011 will be repurchased at 109.5% of their principal amounts.

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

Forward-Looking Statements

Management’s Discussion and Analysis (“MD&A”) contains statements that are forward-looking and should be read in conjunction with our condensed consolidated financial statements and accompanying notes included elsewhere in this report and our Annual Report on Form 10-K for the year ended December 31, 2010. Statements that are not historical facts are forward- looking statements. We use words such as “could,” “may,” “predict,” “should,” “expect,” “hope,” “continue,” “potential,” “plan,” “intend,” “anticipate,” “project,” “believe,” “estimate,” and similar expressions to identify forward-looking statements. These statements are based on current expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. Forward-looking statements are not guarantees and actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors. We do not update publicly any forward-looking statement with new information or future events. Undue reliance should not be placed on forward-looking statements as many of these factors are beyond our ability to control or predict.

Overview

We are a master limited partnership engaged in the gathering, transportation and processing of natural gas; the transportation, fractionation, marketing and storage of NGLs; and the gathering and transportation of crude oil. We have extensive natural gas gathering, processing and transmission operations in the southwest, Gulf Coast and northeast regions of the United States, including the Marcellus Shale, and are the largest natural gas processor and fractionator in the Appalachian region.

Significant Financial and Other Highlights

Significant financial and other highlights for the three months ended September 30, 2011 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 $41.2 million, or 39%, for the three months ended September 30, 2011 compared to the same period in 2010. The increase is due primarily to higher commodity prices in 2011, expanding operations in our Liberty and Northeast segments and increased volumes from a large producer in our Southwest segment. The increase was partially offset by a $10.1 million increase in cash paid for the settlement of commodity derivative positions.

·In July 2011, we received net proceeds of approximately $185 million from a public offering of approximately 4.0 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option.

·In September 2011, we commenced operations of our fractionation facility in Houston, Pennsylvania. The new fractionation facility allows us to provide additional fully-integrated midstream services to our producer customers in the Marcellus Shale.

Non-GAAP Financial Measures

In evaluating the Partnership’s 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) which is defined as segment revenue, excluding any derivative gain (loss) and adjusted for the non-cash impact of revenue deferrals related to certain agreements, less purchased product costs, excluding any derivative gain (loss). These adjustments have been made for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting.

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

	Three months ended September 30,						Nine months ended September 30,
	2011			2010			2011			2010
Segment revenue	$	403,372		$	292,370		$	1,122,486		$	884,933
Purchased product costs	(189,284		)	(136,700		)	(497,493		)	(409,119		)
Net operating margin	214,088			155,670			624,993			475,814
Facility expenses	(44,236		)	(37,934		)	(124,358		)	(113,266		)
Derivative gain (loss)	111,004			(56,391		)	46,859			(21,850		)
Revenue deferral adjustment	(2,489		)	—			(12,854		)	—
Selling, general and administrative expenses	(20,162		)	(17,137		)	(60,454		)	(55,064		)
Depreciation	(38,715		)	(31,362		)	(110,280		)	(89,367		)
Amortization of intangible assets	(10,985		)	(10,193		)	(32,632		)	(30,579		)
Loss on disposal of property, plant and equipment	(147		)	(1,937		)	(4,619		)	(2,116		)
Accretion of asset retirement obligations	(557		)	(70		)	(934		)	(282		)
Income from operations	$	207,801		$	646		$	325,721		$	163,290

Segment revenues, operating income before items not allocated to segments and net operating margin (collectively the “Non-GAAP Measures”) do not have any standardized definition and therefore are unlikely to be comparable to similar measures presented by other reporting companies. Non-GAAP Measures should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Non-GAAP Measures and the underlying methodology in excluding certain revenues or charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, receive such revenue or incur such charges in future periods.

Our Contracts

We generate the majority of our revenue and net operating margin (a non-GAAP measure, see above for discussion and reconciliation of net operating margin) from natural gas gathering, transportation and processing; NGL transportation, fractionation, marketing and storage; and crude oil gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the following types of arrangements: fee-based, percent-of-proceeds, percent-of-index and keep-whole. See Item 1. Business—Our Contracts in our Annual Report on Form 10-K for the year ended December 31, 2010 for further discussion of each of these types of arrangements.

The following table does not give effect to our active commodity risk management program. For the nine months ended September 30, 2011, we calculated the following approximate percentages of our segment revenue and net operating margin from the following types of contracts:

	Fee-Based		Percent-of-Proceeds (1)		Percent-of-Index (2)		Keep-Whole (3)
Segment revenue	21	%	38	%	4	%	37	%
Net operating margin (4)	38	%	30	%	0	%	32	%

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

(2)Includes arrangements tied to natural gas prices.

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

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

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Seasonality

Our business is affected by seasonal fluctuations in commodity prices. Sales volumes also are affected by various other factors such as fluctuating and seasonal demands for products, changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast segment is particularly impacted by seasonality. In our Northeast segment operations, we store a portion of the propane that is produced in the summer to be sold in the winter months. As a result of our seasonality, we generally expect the sales volumes in our Northeast segment to be higher in the first quarter and fourth quarter. These seasonal factors also impact our Liberty segment; however, we anticipate that the expected growth and expansion in our Liberty segment in 2011 will counteract this seasonality impact.

Results of Operations

Segment Reporting

We classify our business in four reportable segments: Southwest, Northeast, Liberty and Gulf Coast. 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.

Southwest

·East Texas.  We own a system that consists of natural gas gathering pipelines, centralized compressor stations, natural gas processing facility and an NGL pipeline. The East Texas system is located in Panola, Harrison and Rusk Counties and services the Carthage Field. Producing formations in Panola County consist of the Cotton Valley, Pettit, Travis Peak and Haynesville formations. Our current cryogenic processing capacity in East Texas is 280 MMcf/d, and we are planning an additional 120 MMcf/d cryogenic processing plant that is expected to be complete in the fourth quarter of 2012.  For natural gas that is processed in this area, we purchase the NGLs from the producers under percent-of-proceeds arrangements, or we transport and process volumes for a fee.

·Oklahoma.  We own a natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. The liquids- rich natural gas gathered in the Woodford system is processed through Centrahoma Processing LLC (“Centrahoma”), our equity investment or another third-party processor. In addition, we own the Foss Lake natural gas gathering system and the Western Oklahoma natural gas processing complex, all located in Roger Mills, Beckham, Custer and Ellis Counties of western Oklahoma. The gathering portion consists of a pipeline system that is connected to natural gas wells and associated compression facilities. The majority of the gathered gas ultimately is compressed and delivered to the processing plants. We also own a gathering system in the Granite Wash formation in the Texas panhandle that is connected to our Western Oklahoma processing complex. We completed the expansion of the Western Oklahoma natural gas processing plant in October 2011, which increased our processing capacity at the Western Oklahoma complex by 75 MMcf/d to a total of 235 MMcf/d. The gathering and processing expansions are supported by long-term agreements with producer customers.

Through our joint venture, MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with the Midcontinent Express Pipeline and Gulf Crossing Pipeline at Bennington, Oklahoma and is designed to provide approximately 638,000 Dth/d of Woodford Shale takeaway capacity.

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

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Northeast

·Kentucky and southern West Virginia.  Our Northeast segment assets include the Kenova, Boldman, Cobb, Kermit and the Langley natural gas processing plants acquired in the first quarter of 2011, an NGL pipeline, and the Siloam NGL fractionation plant. In connection with the Langley Acquisition, we will complete the construction of the Ranger Pipeline to connect the Langley Processing Facilities to our existing NGL pipeline that transports NGLs to our Siloam fractionation facility. We have an obligation to install an additional cryogenic natural gas processing plant with a capacity of at least 60 MMcf/d in 2012. In addition, we have two caverns for storing propane at our Siloam facility and additional propane storage capacity under a long-term firm-capacity agreement with a third party. The Northeast segment operations include fractionation and marketing services on behalf of the Liberty segment.  Including our presence in the Marcellus shale, we are the largest processor and fractionator of natural gas in the Northeast, with fully integrated processing, fractionation, storage and marketing operations.

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

Liberty

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

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

Processing

·355 MMcf/d of current cryogenic processing capacity at our Houston, Pennsylvania processing complex (“Houston Complex”), which includes a 200 MMcf/d cryogenic plant that began operations in the second quarter of 2011.

·270 MMcf/d of current cryogenic processing capacity at our Majorsville, West Virginia processing complex “(Majorsville Complex”), which includes a 135 MMcf/d cryogenic plant that began operations in the second quarter of 2011.

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

·200 MMcf/d cryogenic processing capacity under construction in Sherwood, West Virginia that is expected to be completed in the second half of 2012.

By the end of 2012, MarkWest Liberty Midstream is expected to have more than 1Bcf/d of cryogenic processing capacity that is supported by long-term agreements with our producer customers.  NGLs produced at the Majorsville Complex are transported through an NGL pipeline to the Houston Complex (“Majorsville Pipeline”) for fractionation.  We also plan to complete an NGL pipeline connecting each of the planned processing facilities to the Majorsville Pipeline allowing for fractionation at the Houston Complex. By the end of 2012, MarkWest Liberty Midstream will have approximately 100 miles of NGL transportation pipeline.

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Fractionation and Market Outlets

·Existing fractionation facility at our Houston Complex with a design capacity of 60,000 Bbl/d that was placed into service in the third quarter of 2011. Prior to the completion of the Houston fractionation facility, only propane was  recovered at our Houston Complex and further fractionation of the remaining portion of the NGL stream produced at the Liberty processing plants was performed at the Siloam NGL fractionation plant in our Northeast segment.

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

·Extension of our Majorsville NGL pipeline under construction to receive NGLs produced at a third-party’s Fort Beeler processing plant.  This project is expected to be completed in the fourth quarter of 2011 and will allow certain producers to benefit from our integrated NGL fractionation and marketing operations.

·Railcar loading facility under construction at our Houston Complex that is expected to be completed in the first half of 2012.

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

Ethane Recovery and associated Market Outlets

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

·75,000 Bbl/d de-ethanization facilities under construction at our Houston Complex and Majorsville Complex that are expected to be completed by mid- 2013.

·A joint pipeline project with Sunoco Logistics, L.P. (“Sunoco”) that is currently under construction and will 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 by mid-2013 with the ability to expand to support higher volumes as needed. Sunoco completed an open season for Mariner West and received binding commitments from shippers that would enable the project to proceed as designed.

·Mariner East, an additional joint project with Sunoco, is a pipeline and marine project under consideration that is intended to deliver Marcellus purity ethane to the Gulf Coast and international markets. Mariner East is anticipated to have initial capacity to transport up to 50,000 Bbl/d of ethane by mid-2013.

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

Gulf Coast

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

The following summarizes the percentage of our segment revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by segment, for the nine months ended September 30, 2011:

	Southwest		Northeast		Liberty		Gulf Coast
Segment revenue	61	%	18	%	15	%	6	%
Net operating margin	49	%	21	%	18	%	12	%

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 September 30, 2011 and 2010 and for the nine months ended September 30, 2011 and 2010. The information includes net operating margin, a non-GAAP financial measure. See above for a reconciliation of net operating margin to Income from operations, the most comparable GAAP financial measure.

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Three months ended September 30, 2011 compared to three months ended September 30, 2010

Southwest

	Three months ended September 30,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	241,998	$	159,044	$	82,954		52	%
Purchased product costs	141,067		74,835		66,232			89	%
Net operating margin	100,931		84,209		16,722			20	%
Facility expenses	21,043		20,659		384			2	%
Portion of operating income attributable to non-controlling interests	1,227		1,906		(679		)	(36	)%
Operating income before items not allocated to segments	$	78,661	$	61,644	$	17,017		28	%

Segment Revenue.  Revenue increased primarily due to higher commodity prices for all areas of the segment, higher condensate revenue, and an overall increase in the volume of natural gas processed and NGLs produced in Oklahoma.

Purchased Product Costs.  Purchased product costs increased primarily due to higher commodity prices and an increase in the volume of natural gas processed and NGLs produced in Oklahoma.

Northeast

	Three months ended September 30,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	55,920	$	83,400	$	(27,480	)	(33	)%
Purchased product costs	15,947		55,879		(39,932		)	(71	)%
Net operating margin	39,973		27,521		12,452			45	%
Facility expenses	6,879		5,268		1,611			31	%
Operating income before items not allocated to segments	$	33,094	$	22,253	$	10,841		49	%

Segment Revenue.  Revenue decreased primarily due to a contract change related to the Langley Acquisition. Subsequent to the Langley Acquisition, we continue to market the NGLs related to natural gas processed at the Langley plant; however, we are acting as an agent and therefore record revenue net of purchase product costs. Prior to the contract change we were acting as the principal. Revenue also decreased due to a decline in volumes processed under keep-whole terms primarily due to the required repairs of a significant third-party transmission pipeline feeding our Kenova plant. The repairs of the transmission pipeline are scheduled to be completed in the fourth quarter of 2011, after which we expect volumes to return to normal levels.

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

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

Liberty

	Three months ended September 30,
	2011		2010		$ Change		% Change
	(in thousands)
Segment revenue	$	78,586	$	28,606	$	49,980	175	%
Purchased product costs	32,270		5,986		26,284		439	%
Net operating margin	46,316		22,620		23,696		105	%
Facility expenses	9,108		5,668		3,440		61	%
Portion of operating income attributable to non-controlling interests	18,223		6,772		11,451		169	%
Operating income before items not allocated to segments	$	18,985	$	10,180	$	8,805	86	%

37

Segment Revenue.  Revenue increased due to ongoing expansion of the Liberty operations and higher NGL prices. Revenue increased approximately $13.4 million related to gathering and processing fees and approximately $34.4 million related to NGL product sales.

Purchased Product Costs.  Purchased product costs increased primarily due to the purchase of propane from certain producers at market prices less a discount, which began in the second half of 2010.

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

Portion of Operating Income Attributable to Non-controlling Interests.  Portion of operating income attributable to non-controlling interests represents M&R’s interest in net operating income of MarkWest Liberty Midstream. The increase is the result of ongoing expansion of the Liberty operations, as well as M&R’s interest increasing from 40% to 49% effective January 1, 2011.

Gulf Coast

	Three months ended September 30,
	2011		2010		$ Change		% Change
	(in thousands)
Segment revenue	$	26,868	$	21,320	$	5,548	26	%
Purchased product costs	—		—		—		N/A
Net operating margin	26,868		21,320		5,548		26	%
Facility expenses	9,798		8,785		1,013		12	%
Operating income before items not allocated to segments	$	17,070	$	12,535	$	4,535	36	%

Segment Revenue.  Revenue increased primarily due to higher pricing on NGL products.

Facility Expenses.  Facility expenses increased primarily due to the timing of facility maintenance and repairs.

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

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income (loss) before provision for income tax for the three months ended September 30, 2011 and 2010. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Three months ended September 30,
	2011			2010			$ Change			% Change
	(in thousands)
Total segment revenue	$	403,372		$	292,370		$	111,002		38	%
Derivative gain (loss) not allocated to segments	106,943			(36,959		)	143,902			(389	)%
Revenue deferral adjustment	(2,489		)	—			(2,489		)	N/A
Total revenue	$	507,826		$	255,411		$	252,415		99	%
Operating income before items not allocated to segments	$	147,810		$	106,612		$	41,198		39	%
Portion of operating income attributable to non-controlling interests	19,450			8,678			10,772			124	%
Derivative gain (loss) not allocated to segments	111,004			(56,391		)	167,395			(297	)%
Revenue deferral adjustment	(2,489		)	—			(2,489		)	N/A
Compensation expense included in facility expenses not allocated to segments	(263		)	(404		)	141			(35	)%
Facility expenses adjustments	2,855			2,850			5			0	%
Selling, general and administrative expenses	(20,162		)	(17,137		)	(3,025		)	18	%
Depreciation	(38,715		)	(31,362		)	(7,353		)	23	%
Amortization of intangible assets	(10,985		)	(10,193		)	(792		)	8	%
Loss on disposal of property, plant and equipment	(147		)	(1,937		)	1,790			(92	)%
Accretion of asset retirement obligations	(557		)	(70		)	(487		)	696	%
Income from operations	207,801			646			207,155			32,067	%
Loss from unconsolidated affiliate	(507		)	—			(507		)	N/A
Interest income	62			422			(360		)	(85	)%
Interest expense	(26,899		)	(26,433		)	(466		)	2	%
Amortization of deferred financing costs and discount (a component of interest expense)	(1,002		)	(3,625		)	2,623			(72	)%
Loss on redemption of debt	(133		)	—						N/A
Miscellaneous (expense) income, net	(4		)	76			(80		)	(105	)%
Income (loss) before provision for income tax	$	179,318		$	(28,914	)	$	208,232		(720	)%

Derivative Gain (Loss) Not Allocated to Segments.  Unrealized gain from the mark-to-market of our derivative instruments was $126.8 million for the three months ended September 30, 2011 compared to an unrealized loss of $50.7 million for the same period in 2010. Realized loss from the settlement of our derivative instruments was $15.8 million for the three months ended September 30, 2011 compared to $5.7 million for the same period in 2010. The total change of $167.4 million is due mainly to volatility in commodity prices.

Revenue Deferral Adjustment.  Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended September 30, 2011, approximately $0.2 million and $2.3 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Based on current commodity prices, management expects the deferred revenue in subsequent periods to approximate the current quarter’s amount until the beginning of 2015 when the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

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Selling, General and Administrative.  Selling, general and administrative expenses increased primarily due to higher labor, benefits, office expense and professional services necessary to support the overall growth of our operations.

Depreciation.  Depreciation increased due to additional projects completed during 2010 through the third quarter of 2011, as well as the Langley Acquisition.

Amortization of Deferred Financing Costs and Discount.  Amortization of deferred financing costs and discount decreased primarily due to the write off of the unamortized discount associated with our 6.875% senior unsecured notes due 2014 (the “2014 Senior Notes”), which were redeemed in the fourth quarter of 2010.

Nine months ended September 30, 2011 compared to nine months ended September 30, 2010

Southwest

	Nine months ended September 30,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	679,347	$	479,051	$	200,296		42	%
Purchased product costs	373,251		220,849		152,402			69	%
Net operating margin	306,096		258,202		47,894			19	%
Facility expenses	62,055		60,543		1,512			2	%
Portion of operating income attributable to non-controlling interests	3,745		4,962		(1,217		)	(25	)%
Operating income before items not allocated to segments	$	240,296	$	192,697	$	47,599		25	%

Segment Revenue.  Revenue increased primarily due to higher commodity prices for all areas of the segment, higher condensate revenue, and an overall increase in the volume of natural gas processed and NGLs produced in Oklahoma.

Purchased Product Costs.  Purchased product costs increased primarily due to higher commodity prices and an increase in the volume of natural gas processed and NGLs produced in Oklahoma.

Northeast

	Nine months ended September 30,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	201,687	$	276,570	$	(74,883	)	(27	)%
Purchased product costs	72,527		179,700		(107,173		)	(60	)%
Net operating margin	129,160		96,870		32,290			33	%
Facility expenses	19,402		14,555		4,847			33	%
Operating income before items not allocated to segments	$	109,758	$	82,315	$	27,443		33	%

Segment Revenue.  Revenue decreased primarily due to a contract change related to the Langley Acquisition. Subsequent to the Langley Acquisition, we continue to market the NGLs related to natural gas processed at the Langley plant; however we are acting as an agent and therefore record revenue net of purchase product costs. Prior to the contract change we were acting as the principal. Revenue also decreased due to a decrease in volumes processed under keep-whole terms primarily due to the required repairs of a significant third-party transmission pipeline feeding our Kenova plant. The repairs of the transmission pipeline are scheduled to be completed in the fourth quarter of 2011, after which we expect volumes to return to normal levels.

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

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

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Liberty

	Nine months ended September 30,
	2011		2010		$ Change		% Change
	(in thousands)
Segment revenue	$	168,142	$	66,354	$	101,788	153	%
Purchased product costs	51,715		8,570		43,145		503	%
Net operating margin	116,427		57,784		58,643		101	%
Facility expenses	22,875		19,121		3,754		20	%
Portion of operating income attributable to non-controlling interests	45,782		15,617		30,165		193	%
Operating income before items not allocated to segments	$	47,770	$	23,046	$	24,724	107	%

Segment Revenue.  Revenue increased due to ongoing expansion of the Liberty operations and higher NGL prices. Revenue increased approximately $36.3 million related to gathering and processing fees and approximately $60.9 million related to NGL product sales.

Purchased Product Costs.  Purchased product costs increased primarily due to the purchase of propane from certain producers at  market prices less a discount, which began in the second half of 2010.

Facility Expenses.  Facility expenses increased due to costs related to the expansion of Liberty operations. The increase in costs related to expansion were partially offset by a reduction in compressor rental expense as compressors were purchased in the first quarter of 2010 and by environmental and remediation costs incurred in 2010 that did not recur in 2011.

Portion of Operating Income Attributable to Non-controlling Interests.  Portion of operating income attributable to non-controlling interests represents M&R’s interest in net operating income of MarkWest Liberty Midstream. The increase is the result of ongoing expansion of the Liberty operations, as well as M&R’s interest increasing from 40% to 49% effective January 1, 2011.

Gulf Coast

	Nine months ended September 30,
	2011		2010		$ Change		% Change
	(in thousands)
Segment revenue	$	73,310	$	62,958	$	10,352	16	%
Purchased product costs	—		—		—		N/A
Net operating margin	73,310		62,958		10,352		16	%
Facility expenses	27,100		23,875		3,225		14	%
Operating income before items not allocated to segments	$	46,210	$	39,083	$	7,127	18	%

Segment Revenue.  Revenue increased primarily due to increases in commodity prices and the revenues earned from the SMR which did not begin until March 2010. The increases were partially offset by a decrease in volumes due to increased maintenance activities.

Facility Expenses.  Facility expenses increased primarily due to operating expenses of the SMR which began in March 2010.

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Reconciliation of Segment Operating Income to Consolidated Income 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 before provision for income tax for the nine months ended September 30, 2011 and 2010. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Nine months ended September 30,
	2011			2010			$ Change			% Change
	(in thousands)
Total segment revenue	$	1,122,486		$	884,933		$	237,553		27	%
Derivative gain not allocated to segments	61,854			2,707			59,147			2,185	%
Revenue deferral adjustment	(12,854		)	—			(12,854		)	N/A
Total revenue	$	1,171,486		$	887,640		$	283,846		32	%
Operating income before items not allocated to segments	$	444,034		$	337,141		$	106,893		32	%
Portion of operating income attributable to non-controlling interests	49,527			20,579			28,948			141	%
Derivative gain (loss) not allocated to segments	46,859			(21,850		)	68,709			(314	)%
Revenue deferral adjustment	(12,854		)	—			(12,854		)	N/A
Compensation expense included in facility expenses not allocated to segments	(1,491		)	(1,412		)	(79		)	6	%
Facility expenses adjustments	8,565			6,240			2,325			37	%
Selling, general and administrative expenses	(60,454		)	(55,064		)	(5,390		)	10	%
Depreciation	(110,280		)	(89,367		)	(20,913		)	23	%
Amortization of intangible assets	(32,632		)	(30,579		)	(2,053		)	7	%
Loss on disposal of property, plant and equipment	(4,619		)	(2,116		)	(2,503		)	118	%
Accretion of asset retirement obligations	(934		)	(282		)	(652		)	231	%
Income from operations	325,721			163,290			162,431			99	%
(Loss) earnings from unconsolidated affiliate	(1,262		)	1,517			(2,779		)	(183	)%
Interest income	214			1,185			(971		)	(82	)%
Interest expense	(83,036		)	(75,970		)	(7,066		)	9	%
Amortization of deferred financing costs and discount (a component of interest expense)	(3,873		)	(8,517		)	4,644			(55	)%
Derivative gain related to interest expense	—			1,871			(1,871		)	(100	)%
Loss on redemption of debt	(43,461		)	—			(43,461		)	N/A
Miscellaneous income, net	127			1,129			(1,002		)	(89	)%
Income before provision for income tax	$	194,430		$	84,505		$	109,925		130	%

Derivative Gain (Loss) Not Allocated to Segments.  Unrealized gain from the mark-to-market of our derivative instruments was $102.7 million for the nine months ended September 30, 2011 compared to $13.8 million for the same period in 2010. Realized loss from the settlement of our derivative instruments was $55.8 million for the nine months ended September 30, 2011 compared to $35.7 million for the same period in 2010. The total change of $68.7 million is due mainly to volatility in commodity prices.

Revenue Deferral Adjustment.  Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the nine months ended September 30, 2011, approximately $6.9 million and $5.9 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

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Facility Expenses Adjustments.  Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR, which is included in facility expenses for the purposes of evaluating the performance of the Gulf Coast segment. The increase is due to a full nine months of interest expense related to the SMR in 2011 compared to approximately six months of SMR interest expense in 2010.

Selling, General and Administrative.  Selling, general and administrative expenses increased primarily due to higher labor, benefits, and professional services necessary to support the overall growth of our operations.

Depreciation.  Depreciation increased due to additional projects completed during 2010 through the third quarter of 2011, as well as the Langley Acquisition.

Loss on Disposal of Property, Plant and Equipment. Loss relates to non-recurring disposals of miscellaneous equipment, primarily in the Northeast segment.

Interest Expense.  Interest expense increased primarily due to increased borrowings under our Credit Facility and a net increase in our borrowings resulting from our Senior Notes offerings and related redemptions in order to fund our capital plan. Interest expense also increased approximately $1.8 million related to payments of the SMR liability that began in March 2010.

Amortization of Deferred Financing Costs and Discount.  Amortization of deferred financing costs and discount decreased primarily due to the write off of the unamortized discount associated with our 2014 Senior Notes, which were redeemed in the fourth quarter of 2010. The decrease was partially offset by the amortization of deferred financing costs related to notes issued in the fourth quarter of 2010 and the first quarter of 2011.

Loss on Redemption of Debt.  Loss on redemption of debt relates to the redemption of $275.0 million of our 2016 Senior Notes and $165.6 million of our 2018 Senior Notes occurring primarily in the first quarter of 2011. Approximately $3.8 million relates to the non-cash write off of the unamortized discount and deferred finance costs and approximately $39.6 million relates to the payment of the related tender premiums and third-party expenses. See Note 9 of the accompanying Notes to the Condensed Consolidated Financial Statements.

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Operating Data

	Three months ended September 30,		%		Nine months endedSeptember 30,
	2011	2010	Change		2011	2010	% Change
Southwest
East Texas gathering systems throughput (Mcf/d)	417,400	433,000	(4	)%	423,800	433,600	(2	)%
East Texas natural gas processed (Mcf/d)	229,700	221,900	4	%	226,000	236,900	(5	)%
East Texas NGL sales (gallons, in thousands)	59,000	60,200	(2	)%	175,200	186,300	(6	)%
Western Oklahoma gathering system throughput (Mcf/d) (1)	241,300	183,600	31	%	224,400	189,300	19	%
Western Oklahoma natural gas processed (Mcf/d)	153,200	143,300	7	%	156,600	129,600	21	%
Western Oklahoma NGL sales (gallons, in thousands)	37,000	33,800	9	%	111,100	93,400	19	%
Southeast Oklahoma gathering system throughput (Mcf/d)	512,600	535,800	(4	)%	507,500	524,100	(3	)%
Southeast Oklahoma natural gas processed (Mcf/d) (2)	105,400	94,500	12	%	103,100	79,000	31	%
Southeast Oklahoma NGL sales (gallons, in thousands)	30,600	29,900	2	%	92,100	72,300	27	%
Arkoma Connector Pipeline throughput (Mcf/d)	298,600	396,800	(25	)%	294,300	378,900	(22	)%
Other Southwest gathering system throughput (Mcf/d) (3)	29,900	37,000	(19	)%	31,500	40,200	(22	)%
Northeast (4)
Natural gas processed (Mcf/d)	277,400	190,300	46	%	300,700	194,400	55	%
NGLs fractionated (Bbl/d) (5)	19,300	21,200	(9	)%	21,400	20,500	4	%
Keep-whole sales (gallons, in thousands)	21,700	28,700	(24	)%	82,600	105,300	(22	)%
Percent-of-proceeds sales (gallons, in thousands)	31,600	30,800	3	%	95,600	87,900	9	%
Total NGL sales (gallons, in thousands) (6)	53,300	59,500	(10	)%	178,200	193,200	(8	)%
Crude oil transported for a fee (Bbl/d)	9,900	12,100	(18	)%	10,500	12,400	(15	)%
Liberty
Natural gas processed (Mcf/d)	366,200	156,300	134	%	306,700	122,300	151	%
Gathering system throughput (Mcf/d)	258,300	153,300	68	%	228,900	127,700	79	%
NGLs fractionated (Bbl/d) (7)	12,400	4,200	195	%	9,300	3,500	166	%
NGL sales (gallons, in thousands) (8)	61,100	32,400	89	%	163,500	77,400	111	%
Gulf Coast
Refinery off-gas processed (Mcf/d)	122,000	123,000	(1	)%	113,200	118,400	(4	)%
Liquids fractionated (Bbl/d)	23,100	23,100	0	%	21,400	22,800	(6	)%
NGL sales (gallons excluding hydrogen, in thousands)	89,200	89,300	(0	)%	245,500	261,700	(6	)%

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

(2)The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or a third-party processor.

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

(4)Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported are the average daily rates for the days of operation.

(5)Amount includes 4,400 barrels per day and 4,300 barrels per day fractionated on behalf of Liberty for the three months ended September 30, 2011 and 2010, respectively, and includes 5,100 barrels per day and 3,500 barrels per day fractionated on behalf of Liberty for the nine months ended September 30, 2011 and 2010, respectively.  Beginning in the fourth quarter of 2011, Siloam will no longer fractionate NGLs on behalf of Liberty due to the operation of Liberty’s  fractionation facility that began in September 2011.

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(6)Represents sales at the Siloam fractionator. The total sales exclude approximately 17,100,000 gallons and 16,700,000 gallons sold by the Northeast on behalf of Liberty for the three months ended September 30, 2011 and 2010, respectively, and approximately 58,600,000 gallons and 40,000,000 gallons sold for the nine months ended September 30, 2011 and 2010, respectively.  These volumes are included as part of NGLs sold at Liberty.

(7)Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility. Through August 2011, only propane was recovered at our Liberty facilities.  In September 2011, Liberty’s fractionation facility commenced operations and Liberty now has full fractionation capabilities.

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

Liquidity and Capital Resources

Our primary strategy is to expand our asset base through organic growth projects and selective third-party acquisitions that are accretive to our cash available for distribution per common unit. In 2010, we spent approximately $458.7 million primarily on organic expansion opportunities, of which approximately $184 million was funded by our MarkWest Liberty Midstream joint venture partner.

Our 2011 capital plan is summarized in the table below (in millions):

							Actual
							Nine months
	Full Year Plan						ended September
	Low			High			30, 2011
Consolidated growth capital	$	575		$	620		$	351
Liberty joint venture partner’s estimated share of growth capital	(130		)	(150		)	(69		)
Partnership share of growth capital	445			470			282
Langley Acquisition	230			230			231
Partnership share of growth capital and acquisitions	$	675		$	700		$	513
Consolidated maintenance capital	$	15		$	15		$	9

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.

Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations, contributions from our MarkWest Liberty Midstream joint venture partner, our Credit Facility and access to debt and equity markets, both public and private. We will also consider the use of alternative financing strategies such as entering into additional joint venture arrangements and the sale of non-strategic assets.

In July 2011, we reached Equalization related to the capital contributed to MarkWest Liberty Midstream (see Note 4 in the accompanying condensed consolidated financial statements).  As a result, MarkWest Liberty Midstream will be funded by us and our joint venture partner in proportion to our ownership percentages for future capital requirements, which will decrease our proportionate share of the capital funding from 73% during the nine months ended September 30, 2011 to 51%.   Based on agreed-to levels of capital contributions that are expected to be reached in 2012, we will have the option to increase our portion of the capital contributions to 55% of each future capital call, which if elected by us, will increase our ownership percentage in MarkWest Liberty Midstream.

Management believes that expenditures for our currently planned capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partner for capital projects encompassed by the Liberty joint venture, our current borrowing capacity under the Credit Facility, additional long-term borrowings, and proceeds from equity offerings.  Our access to capital markets can be impacted by factors outside our control, including economic conditions; however, we believe that our strong cash flows and balance sheet, our Credit Facility and our credit rating will provide us with adequate access to funding given our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings

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assigned by independent rating agencies. As of October 28, 2011, our credit ratings were Ba2 with a Stable outlook by Moody’s Investors Service, BB with a Stable outlook by Standard & Poor’s, which both reflect upgrades during 2011, and BB with a Stable outlook by Fitch Ratings. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

Debt Financing Activities

On June 15, 2011, we executed a joinder agreement to include an additional member in the bank group and to exercise a portion of the accordion feature under the Credit Facility, thereby increasing the borrowing capacity of the Credit Facility to $745 million and reducing the accordion feature to $155 million of uncommitted funds.  On September 7, 2011, we amended the Credit Facility, increasing the borrowing capacity of the Credit Facility to $750 million, increasing the uncommitted accordion feature to $250 million, reducing the interest rate ranges by 75 basis points, and extending the maturity date to September 2016.  Under the provisions of the Credit Facility we are subject to a number of restrictions and covenants. As of September 30, 2011, we were in compliance with all of our debt covenants and we expect to remain in compliance for at least the next twelve months. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of October 28, 2011, we had no borrowings outstanding and $27.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $722.7 million available for borrowing.

On February 24, 2011, we completed a public offering of $300 million in aggregate principal amount of 2021 Senior Notes, which were issued at par. On March 10, 2011, we completed a follow-on public offering of an additional $200 million in aggregate principal amount of 2021 Senior Notes, which were issued at 99.5% of par and are treated as a single class of debt securities with the 2021 Senior Notes issued on February 24, 2011. The 2021 Senior Notes mature on August 15, 2021, and interest is payable semi-annually in arrears on February 15 and August 15, commencing August 15, 2011. We received aggregate net proceeds of approximately $492 million from the 2021 Senior Notes offerings after deducting the underwriting fees and other third-party expenses and used the net proceeds to fund the repurchase of approximately $272.2 million in aggregate principal amount of 2016 Senior Notes and approximately $165.6 million in aggregate principal amount of 2018 Senior Notes. The remaining proceeds were used to repay borrowings under the Credit Facility. On July 15, 2011, we repurchased the remaining 2016 Senior Notes.  As a result of these refinancing activities, we have significantly reduced the interest rates and extended the terms of our long-term financing.

On October 25, 2011, we commenced a public offering of $700 million in aggregate principal amount of 6.25% senior unsecured notes due June 2022 (“2022 Senior Notes”).  The offering is expected to close on November 3, 2011. Interest on the 2022 Notes is payable semi-annually in arrears on June 15 and December 15, commencing June 15, 2012. We intend to use the net proceeds from this offering to fund the repurchase of any and all of the $334.4 million outstanding 2018 Senior Notes that are tendered pursuant to a concurrent tender offer and any remaining net proceeds will be used to provide additional working capital for general partnership purposes.  We have offered to repurchase the 2018 Senior Notes at 112.5% of their principal amounts for all notes tendered prior to November 9, 2011. Any 2018 Senior Notes tendered after November 9, 2011 but prior to November 25, 2011 would be repurchased at 109.5% of their principal amounts.  Assuming that all of the 2018 Senior Notes are tendered by November 9, 2011, we would record a pre-tax loss on redemption of debt of approximately $47 million, which would consist of $42 million for the payment of the related tender premiums and third-party expenses and $5 million for the non-cash write off of the unamortized discount and deferred finance costs.

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

The Credit Facility also limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Credit Facility prevents members of the participating bank group from requiring margin calls. As of October 28, 2011, all of our 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.

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Equity Offerings

On January 14, 2011, we completed a public offering of approximately 3.45 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriter’s over-allotment option. Net proceeds of approximately $138 million were used to partially fund our ongoing capital expenditure program, including a portion of the costs associated with the Langley Acquisition.

On July 13, 2011, we completed a public offering of approximately 4.0 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option.  Net proceeds of approximately $185 million and were used to repay borrowings under the Credit Facility and to partially fund our ongoing capital expenditure program.

On October 13, 2011, we completed a public offering of approximately 5.75 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters’ over-allotment option.  Net proceeds of approximately $251 million were used to repay borrowings under the Credit Facility and to provide working capital for general partnership purposes.

Cash Flow

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

	Nine months ended September 30,
	2011			2010			Change
Net cash provided by operating activities	$	331,249		$	197,238		$	134,011
Net cash used in investing activities	(587,686		)	(373,649		)	(214,037		)
Net cash provided by financing activities	348,164			177,154			171,010

Net cash provided by operating activities increased primarily due to a $106.9 million increase in operating income, excluding derivative gains and losses, in our operating segments, which was partially offset by a $20.1 million increase in net cash payments related to the settlement of commodity derivative positions. The increase in operating income was also due to increases in operating cash flow resulting from changes in working capital.

Net cash used in investing activities increased primarily due to the $230.7 million Langley Acquisition.

Net cash provided by financing activities increased primarily due to:

·$181.2 million increase in proceeds from public offerings, and

·$161.0 million increase in net borrowings.

These increases were partially offset by:

·$67.7 million decrease in cash contributions received from our joint venture partner,

·$44.3 million increase in distributions to non-controlling interest holders due to the increased cash flow from MarkWest Liberty Midstream, and

·$39.6 million increase in premiums paid for the redemption of our 2016 and 2018 Senior Notes,

·$21.0 million increase in distributions to common unitholders due to additional units outstanding and the growth in the per unit distribution,

·$3.4 million decrease in payments for debt issuance costs, deferred financing costs and registration costs.

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Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of September 30, 2011, our purchase obligations for the remainder of 2011 were $119.1 million compared to our 2011 obligations of $56.0 million as of December 31, 2010. The increase is due primarily to obligations related to the ongoing expansion in our Liberty and Northeast segments. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

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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; share-based compensation; risk management activities and derivative financial instruments; and VIEs.

There have not been any material changes during the nine months ended September 30, 2011 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, 2010, except as noted below.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Acquisitions—Purchase Price Allocation
We allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities is recorded as goodwill. For significant acquisitions, we engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as agent networks, customer relationships, trade names and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, after the acquisition closing date through the end of the measurement period of one year or less as we finalize valuations for the assets acquired and liabilities assumed.	Purchase price allocation methodology requires management to make assumptions and apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities primarily using a market approach, income approach, or replacement cost analysis, as appropriate. Key inputs into the fair value determinations include estimates and assumptions related to future volumes, commodity prices, operating costs and construction costs, as well as an estimate of the expected term of the related customer contract or contracts.	If estimates or assumptions used to complete the purchase price allocation and estimate the fair value of acquired assets and liabilities significantly differed from assumptions made, the allocation of purchase price between goodwill, intangibles, and property plant and equipment could significantly differ. Such a difference would impact future earnings through depreciation and amortization expense. In addition, if forecasts supporting the valuation of the intangibles or goodwill are not achieved, impairments could arise.

Recent Accounting Pronouncements

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

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

The information about commodity price risk for the nine months ended September 30, 2011 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, 2010.

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Outstanding Derivative Contracts

The following table provides information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at September 30, 2011, including the weighted average prices (“WAVG”):

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2011	1,592	$	67.25	$	85.40	$	(129	)
2012	2,634	75.65		97.22		3,614
2013	3,714	88.08		107.45		13,773
2014	734	95.36		114.81		3,811

WTI Crude Puts	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		Fair Value (in thousands)
2011	1,812	$	80.00	$	876

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2011 (1)	868	$	89.25	$	(4,981	)
2012	3,983	85.27		(945		)
2013	2,474	90.68		6,142
2014	601	101.50		3,263

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2011	8,310	$	4.21	$	(399	)
2012	4,650	5.62		(2,562		)
2013	980	5.13		(181		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	125,179	$	1.47	$	(153	)
2012 (Jan-Mar)	140,047	1.42		(62		)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	23,380	$	1.88	$	(224	)
2012 (Jan-Mar)	25,051	1.85		(12		)

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	35,108	$	1.82	$	135
2012 (Jan-Mar)	40,083	1.79		241

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	89,723	$	2.28	$	1,037
2012 (Jan-Mar)	92,847	2.29		1,350

(1)During the second quarter of 2011 we effectively converted our swap hedges related to our remaining 2011 NGL exposure from crude proxy hedges to direct refined product hedges by purchasing crude swaps to offset the existing crude swap positions.  The volume of offsetting crude swaps outstanding as of September 30, 2011 was 352,835 barrels.  The outstanding positions were being used to hedge refined products.  To continue the hedge of the refined products we sold refined product swaps through the remainder of 2011.

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The following tables provide information on the volume of our taxable subsidiary’s commodity derivative activity for positions related to keep-whole price risk at September 30, 2011, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012	1,122	$	78.49	$	101.71	$	2,381

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2011 (1)	—	N/A		$	(3,765	)
2012	1,083	$	87.11	(1,489		)
2013	1,304	94.32		4,859

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2011	17,728	$	8.28	$	(7,260	)
2012	14,419	6.02		(9,104		)
2013	9,793	5.34		(1,918		)
2014	4,249	5.69		(856		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	205,971	$	1.48	$	(377	)
2012 (Jan-Mar)	152,569	1.46		(196		)
2013 (Jan-Mar, Oct-Dec)	36,885	1.29		384
2014 (Jan-Mar, Oct-Dec)	87,837	1.25		418

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	13,800	$	1.71	$	(386	)
2012 (Jan-Mar)	8,282	1.82		(49		)
2013	3,081	1.70		87
2014	3,885	1.67		71

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	37,852	$	1.73	$	(325	)
2012 (Jan-Mar)	22,944	1.75		(51		)
2013	8,512	1.61		230
2014	10,711	1.61		275

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2011	25,037	$	2.31	$	298
2012 (Jan-Mar)	14,969	2.28		166
2013	5,600	2.26		549
2014	7,106	2.32		805

(1)During the second quarter of 2011 we effectively converted our swap hedges related to our remaining 2011 and first quarter 2012 NGL exposure from crude proxy hedges to direct refined product hedges by purchasing crude swaps to offset the existing crude swap positions.  The volume of offsetting crude swaps outstanding as of September 30, 2011 was 403,502 barrels for 2011 and 277,000 barrels for Q1 2012.  The outstanding positions were being used to hedge refined products.  To continue the hedge of the refined products we sold refined product swaps through the remainder 2011 and the first quarter of 2012.

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The following tables provide information on the volume of MarkWest Liberty Midstream’s commodity derivative activity for positions related to long liquids price risk at September 30, 2011, including the WAVG:

Propane Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2011	10,948	$	1.56	$	55
2012 (Jan-Mar)	43,353	1.56		225

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 September 30, 2011, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)
2011 (Dec)	676	$	91.20
2012	2,000	88.11

Nat Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMbtu)
2011 (Dec)	3,063	$	3.72
2012	6,871	3.90

Ethane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2011 (Nov-Dec)	85,139	$	0.87

The following table provides information on the derivative positions related to long liquids and keep-whole price risk that MarkWest Liberty Midstream entered into subsequent to September 30, 2011, including the WAVG:

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2011 (Dec)	7,580	$	1.43
2012 (Feb)	17,750	1.41

Embedded Derivatives in Commodity Contracts

We have a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative (gain) loss related to purchased product costs. In February 2011, we executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of September 30, 2011, the estimated fair value of this contract was a liability of $94.7 million and the recorded value was a liability of $41.1 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 September 30, 2011 (in thousands).

Fair value of commodity contract	$	94,652
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of September 30, 2011	$	41,145

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 September 30, 2011, the estimated fair value of this contract was an asset of $3.9 million.

Interest Rate Risk

The information about interest rate risk for the nine months ended September 30, 2011 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, 2010.

Credit Risk

The information about credit risk for the nine months ended September 30, 2011 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, 2010.

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Item 4.  Controls and Procedures

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the 1934 Act, as of September 30, 2011. Based on this evaluation, the Partnership’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of September 30, 2011, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

Limitations on Controls

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2011 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.  Legal Proceedings

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

Item 1A. Risk Factors

There were no material changes to our risk factors as disclosed in Item1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2010, except as set forth below.

New federal pipeline safety regulations relating to liquid pipelines could increase our cost of operations.

On May 5, 2011, the Pipeline and Hazardous Materials Safety Administration issued a final rule to extend safety regulations to certain rural low-stress hazardous liquid pipelines that were not previously regulated in such manner.  These regulations impose additional reporting obligations as well as integrity management requirements.  While we do not believe that compliance with these new regulations will have a material adverse effect on our operations, we are in the process of evaluating the application and impact of the new regulations on our facilities.  It is possible that compliance with these new requirements may increase our operating costs and reduce our cash flows available for distribution to our common unitholders.

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Item 6.  Exhibits

4.1*	Fifth Supplemental Indenture dated as of October 21, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
4.2*	Fourth Supplemental Indenture dated as of October 21, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
10.1(1)	First Amendment to Amended and Restated Credit Agreement dated as of September 7, 2011 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, the other agents and lenders party thereto, and Wells Fargo Securities, LLC and RBC Capital Markets, as joint lead arrangers and joint bookrunners.
31.1*	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101*	The following financial information from the quarterly report on Form 10-Q of MarkWest Energy Partners, L.P. for the quarter ended September 30, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Changes in Equity, (iv) Condensed Consolidated Statements of Cash Flows, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

(1)Incorporated by reference to the Current Report on Form 8-K filed September 13, 2011.

*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: November 7, 2011	/s/ FRANK M. SEMPLE
	Frank M. Semple
	Chairman, President & Chief Executive Officer
	(Principal Executive Officer)
Date: November 7, 2011	/s/ NANCY K. BUESE
	Nancy K. Buese
	Senior Vice President & Chief Financial Officer
	(Principal Financial Officer)
Date: November 7, 2011	/s/ PAULA L. ROSSON
	Paula L. Rosson
	Vice President & Chief Accounting Officer
	(Principal Accounting Officer)

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