PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents ($312 and $31,584, respectively)	$	328,153		$	345,756
Restricted cash ($0 and $500, respectively)	10,000			25,500
Receivables, net ($4,666 and $403, respectively)	235,630			197,977
Inventories ($235 and $0, respectively)	35,514			24,633
Fair value of derivative instruments	15,710			19,504
Deferred income taxes	15,455			5,281
Other current assets ($2,584 and $82, respectively)	39,834			34,871
Total current assets	680,296			653,522

Property, plant and equipment ($1,393,841 and $410,205, respectively)	7,848,221			5,542,316
Less: accumulated depreciation ($23,047 and $2,787, respectively)	(807,398		)	(602,698		)
Total property, plant and equipment, net	7,040,823			4,939,618

Other long-term assets:
Restricted cash	10,000			10,000
Investment in unconsolidated affiliates	68,193			63,054
Intangibles, net of accumulated amortization of $269,012 and $221,416, respectively	891,512			855,155
Goodwill	144,856			142,174
Deferred financing costs, net of accumulated amortization of $23,449 and $18,567, respectively	53,764			51,145
Deferred contract cost, net of accumulated amortization of $2,808 and $2,574, respectively	20,442			676
Fair value of derivative instruments	4,555			10,878
Other long-term assets ($609 and $0, respectively)	3,275			2,140
Total assets	$	8,917,716		$	6,728,362

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($87,209 and $73,865, respectively)	$	420,087		$	320,627
Accrued liabilities ($116,824 and $109,572, respectively)	494,626			390,178
Fair value of derivative instruments	29,479			27,229
Total current liabilities	944,192			738,034

Deferred income taxes	260,035			189,428
Fair value of derivative instruments	21,044			32,190
Long-term debt, net of discounts of $7,113 and $8,061, respectively	3,022,887			2,523,051
Other long-term liabilities	152,877			134,261

Commitments and contingencies (Note 12)
Redeemable non-controlling interest (Note 3)	366,238			—

Equity:
Common units (147,763 and 127,494 common units issued and outstanding, respectively)	2,968,451			2,097,404
Class B units (15,964 and 19,954 units issued and outstanding, respectively)	602,025			752,531
Non-controlling interest in consolidated subsidiaries	579,967			261,463
Total equity	4,150,443			3,111,398
Total liabilities and equity	$	8,917,716		$	6,728,362

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

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

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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,
	2013			2012			2013			2012
Revenue:
Revenue	$	450,834		$	316,976		$	1,219,713		$	1,019,709
Derivative (loss) gain	(30,318		)	(36,400		)	(10,804		)	50,952
Total revenue	420,516			280,576			1,208,909			1,070,661

Operating expenses:
Purchased product costs	191,672			119,369			499,588			386,655
Derivative loss (gain) related to purchased product costs	20,234			11,643			(10,902		)	(21,136		)
Facility expenses	77,542			52,883			199,849			149,438
Derivative loss related to facility expenses	2,332			4,028			2,800			1,136
Selling, general and administrative expenses	26,647			21,723			77,388			68,471
Depreciation	76,323			46,554			215,902			127,472
Amortization of intangible assets	16,003			14,988			47,925			38,280
Loss (gain) on disposal of property, plant and equipment	1,840			655			(35,758		)	2,983
Accretion of asset retirement obligations	160			140			669			536
Total operating expenses	412,753			271,983			997,461			753,835

Income from operations	7,763			8,593			211,448			316,826

Other income (expense):
Equity in earnings from unconsolidated affiliates	896			706			1,561			2,254
Interest income	27			64			238			295
Interest expense	(38,889		)	(30,621		)	(114,180		)	(86,855		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,584		)	(1,428		)	(5,198		)	(3,943		)
Loss on redemption of debt	—			—			(38,455		)	—
Miscellaneous income, net	1,504			1			1,510			63
(Loss) income before provision for income tax	(30,283		)	(22,685		)	56,924			228,640

Provision for income tax (benefit) expense:
Current	(2,344		)	(17,948		)	(10,503		)	2,202
Deferred	(7,912		)	10,528			23,087			39,396
Total provision for income tax	(10,256		)	(7,420		)	12,584			41,598

Net (loss) income	(20,027		)	(15,265		)	44,340			187,042

Net (income) loss attributable to non-controlling interest	(3,577		)	925			297			1,546
Net (loss) income attributable to the Partnership’s unitholders	$	(23,604	)	$	(14,340	)	$	44,637		$	188,588

Net (loss) income attributable to the Partnership’s common unitholders per common unit (Note 14):
Basic	$	(0.17	)	$	(0.13	)	$	0.32		$	1.77
Diluted	$	(0.17	)	$	(0.13	)	$	0.29		$	1.49

Weighted average number of outstanding common units:
Basic	142,352			113,994			134,115			105,916
Diluted	142,352			113,994			153,455			126,595

Cash distribution declared per common unit	$	0.84		$	0.80		$	2.49		$	2.35

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

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Changes in Equity

(unaudited, in thousands)

	Common Units				Class B Units					Non- controlling						Redeemable Non-controlling Interest (Temporary
	Units	Amount			Units		Amount			Interest			Total Equity			Equity)
December 31, 2012	127,494	$	2,097,404		19,954		$	752,531		$	261,463		$	3,111,398		$	—
Issuance of units in public offerings, net of offering costs	16,112	1,039,849			—		—			—			1,039,849			—
Conversion of Class B units to common units	3,990	150,506			(3,990	)	(150,506		)	—			—			—
Distributions paid	—	(333,946		)	—		—			(180		)	(334,126		)	—
Contributions from non-controlling interest	—	—			—		—			685,219			685,219			—
Redeemable non-controlling interest classified as temporary equity	—	—			—		—			(366,238		)	(366,238		)	366,238
Share-based compensation activity	167	6,697			—		—			—			6,697			—
Excess tax benefits related to share-based compensation	—	650			—		—			—			650			—
Deferred income tax impact from changes in equity	—	(37,346		)	—		—			—			(37,346		)	—
Net income (loss)	—	44,637			—		—			(297		)	44,340			—
September 30, 2013	147,763	$	2,968,451		15,964		$	602,025		$	579,967		$	4,150,443		$	366,238

	Common Units				Class B Units			Non- controlling
	Units	Amounts			Units	Amounts		Interest			Total Equity
December 31, 2011	94,940	$	642,522		19,954	$	752,531	$	189		$	1,395,242
Issuance of units in public offerings, net of offering costs	22,408	1,191,066			—	—		—			1,191,066
Distributions paid	—	(244,169		)	—	—		(71		)	(244,240		)
Contributions from non-controlling interest	—	—			—	—		56,101			56,101
Share-based compensation activity	246	3,517			—	—		—			3,517
Excess tax benefits related to share-based compensation	—	2,216			—	—		—			2,216
Deferred income tax impact from changes in equity	—	(75,248		)	—	—		—			(75,248		)
Net income (loss)	—	188,588			—	—		(1,546		)	187,042
September 30, 2012	117,594	$	1,708,492		19,954	$	752,531	$	54,673		$	2,515,696

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,
	2013			2012
Cash flows from operating activities:
Net income	$	44,340		$	187,042
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	215,902			127,472
Amortization of intangible assets	47,925			38,280
Loss on redemption of debt	38,455			—
Amortization of deferred financing costs and discount	5,198			3,943
Accretion of asset retirement obligations	669			536
Amortization of deferred contract cost	234			234
Phantom unit compensation expense	11,907			11,579
Equity in earnings from unconsolidated affiliate	(1,561		)	(2,254		)
Distributions from unconsolidated affiliate	4,952			6,624
Unrealized loss (gain) on derivative instruments	1,222			(101,815		)
(Gain) loss on disposal of property, plant and equipment	(35,758		)	2,983
Deferred income taxes	23,087			39,396

Changes in operating assets and liabilities, net of working capital acquired:
Receivables	(37,491		)	32,248
Inventories	(10,881		)	7,590
Other current assets	(4,963		)	(12,866		)
Accounts payable and accrued liabilities	29,664			36,837
Other long-term assets	(21,135		)	(676		)
Other long-term liabilities	18,893			8,631
Net cash provided by operating activities	330,659			385,784

Cash flows from investing activities:
Restricted cash	15,500			1,003
Capital expenditures	(2,176,719		)	(1,239,705		)
Investment in unconsolidated affiliates	(8,530		)	(839		)
Acquisition of business, net of cash acquired	(225,210		)	(506,797		)
Proceeds from disposal of property, plant and equipment	208,652			589
Net cash flows used in investing activities	(2,186,307		)	(1,745,749		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	1,039,849			1,191,066
Proceeds from Credit Facility	—			511,100
Payments of Credit Facility	—			(577,100		)
Proceeds from long-term debt	1,000,000			742,613
Payments of long-term debt	(501,112		)	—
Payments of premiums on redemption of long-term debt	(31,516		)	—
Payments for debt issuance costs, deferred financing costs and registration costs	(14,046		)	(14,184		)
Contributions from non-controlling interest	685,219			56,101
Payments of SMR liability	(1,661		)	(1,525		)
Cash paid for taxes related to net settlement of share-based payment awards	(5,212		)	(8,061		)
Excess tax benefits related to share-based compensation	650			2,216
Payment of distributions to common unitholders	(333,946		)	(244,169		)
Payment of distributions to non-controlling interest	(180		)	(71		)
Net cash flows provided by financing activities	1,838,045			1,657,986

Net (decrease) increase in cash and cash equivalents	(17,603		)	298,021
Cash and cash equivalents at beginning of year	345,756			114,332
Cash and cash equivalents at end of period	$	328,153		$	412,353

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

1. Organization and Basis of Presentation

MarkWest Energy Partners, L.P. was formed in 2002 as a Delaware limited partnership. The Partnership is engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the gathering and transportation of crude oil. The Partnership has a leading presence in many unconventional gas plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation.

These unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the SEC for interim financial reporting. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. These condensed consolidated financial statements should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. The Marcellus segment was formerly known as the Liberty segment. 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, 2013 are not necessarily indicative of results for the full year 2013 or any other future period.

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

2. Recent Accounting Pronouncements

In December 2011, the FASB amended the accounting guidance for balance sheet offsetting for financial assets and financial liabilities. The amended guidance is intended to help investors and other financial statement users to better assess the effect or potential effect of offsetting arrangements on a company’s financial position and provides for increased disclosures. The amended guidance became effective for the Partnership retrospectively as of January 1, 2013. Except for additional disclosures included in Note 6 related to our master netting arrangements, the adoption of the amended guidance did not have a material effect on the Partnership’s condensed consolidated financial statements.

3. Variable Interest Entity

Variable Interest Entity MarkWest Utica EMG

In February 2013, the Partnership and EMG Utica, LLC (“EMG Utica”) (together the “Members”) entered into the Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG (the “Amended Utica LLC Agreement”) which replaced the original agreement discussed in Note 4 to the Consolidated Financial Statements included in Item 8 of the Partnership’s Form 10-K for the year ended December 31, 2012. Pursuant to the Amended Utica LLC Agreement, the aggregate funding commitment of EMG Utica has increased from $500 million to $950 million (the “Minimum EMG Investment”). As part of this commitment, EMG Utica was required to fund, as needed, all capital required for MarkWest Utica EMG until such time as EMG Utica has contributed aggregate capital equal to $750 million (the “Tier 1 EMG Contributions”). Following the funding of the Tier 1 EMG Contributions, the Partnership had the one time right to elect to fund up to 60% of all capital required for MarkWest Utica EMG until such time as EMG Utica has contributed aggregate capital equal to the Minimum EMG Investment. The Partnership elected not to fund the 60% and therefore EMG Utica was required to fund all capital until the Minimum EMG Investment was satisfied which occurred in May 2013. As EMG Utica has funded the Minimum EMG Investment, the Partnership will be required to fund, as needed, 100% of future capital for MarkWest Utica EMG until such time as the aggregate capital that has been contributed by the Partnership and EMG Utica equals $2 billion. After such time, and until such time as the investment balances of the Partnership and EMG Utica are in the ratio of 70% and 30%, respectively (such time being referred to as the “Second Equalization Date”), EMG Utica will have the right, but not the obligation, to fund up to 10% of each capital call for MarkWest Utica EMG, and the Partnership will be required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization Date, the Partnership and EMG Utica will have the right, but not the obligation, to fund its pro rata portion (based on the respective investment balances) of any additional required capital and may also fund additional capital which the other party elects not to fund. As of September 30, 2013, the Partnership has contributed $279.9 million, net of distributions related to temporary contributions discussed below, to MarkWest Utica EMG.

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Under the Amended Utica LLC Agreement, after EMG Utica has contributed more than $500 million to MarkWest Utica EMG, and prior to December 31, 2016, EMG Utica’s investment balance will also be increased by a quarterly special non-cash allocation of income (“Preference Amount”) that is based upon the amount of capital contributed by EMG Utica in excess of $500 million. No Preference Amount will accrue to EMG Utica’s investment balance after December 31, 2016. EMG Utica received a special non-cash allocation of income of approximately $8.3 million and $14.7 million for the three and nine months ended September 30, 2013, respectively.

If the Partnership’s investment balance does not equal at least 51% of the aggregate investment balances of both Members as of December 31, 2016, then EMG Utica may require that the Partnership purchase membership interests from EMG Utica so that, following the purchase, the Partnership’s investment balance equals 51% of the aggregate investment balances of the Members. The purchase price payable would equal the investment balance associated with the membership interests so acquired from EMG Utica. If EMG Utica makes this election, the Partnership would be required to purchase the membership interests on or prior to March 1, 2017, but effective as of January 1, 2017. The amount of non-controlling interest subject to the redemption option as of September 30, 2013 is reported as redeemable non-controlling interest in the mezzanine equity section of our Condensed Consolidated Balance Sheets.

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

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

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

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

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

MarkWest Pioneer — Restatement

MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline. The Partnership and Arkoma Pipeline Partners, LLC share the equity interests in MarkWest Pioneer equally (50% and 50%). As discussed in Note 4 to the Consolidated Financial Statements in Item 8 of the Partnership’s Form 10-K for the fiscal year ended December 31, 2012, the Partnership had determined that MarkWest Pioneer was a VIE and the Partnership was the primary beneficiary. Therefore, MarkWest Pioneer has historically been included as a consolidated subsidiary by the Partnership. Based on further consideration of the facts and circumstances, MarkWest Pioneer should not have been consolidated and should have been accounted for under the equity method since the Partnership sold 50% of its interests to Arkoma Pipeline Partners, L.L.C. in 2009. Under the equity method, the Partnership

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would have recognized an impairment of its investment in MarkWest Pioneer of approximately $39.2 million ($35.4 million, net of provision for income tax) in the year ended December 31, 2009.

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

	December 31, 2012
Balance Sheet	As previously reported			As restated
Cash and cash equivalents	$	347,899		$	345,756
Receivables, net	198,769			197,977
Other current assets	35,053			34,871
Total current assets	656,639			653,522

Property, plant and equipment	5,700,176			5,542,316
Less: accumulated depreciation	(624,548		)	(602,698		)
Total property, plant and equipment, net	5,075,628			4,939,618

Investment in unconsolidated affiliates	31,179			63,054
Other long-term assets	2,242			2,140
Total assets	6,835,716			6,728,362

Accounts payable	320,645			320,627
Accrued liabilities	391,352			390,178
Total current liabilities	739,226			738,034

Deferred income taxes	191,318			189,428
Other long-term liabilities	134,340			134,261

Common units	2,134,714			2,097,404
Non-controlling interest in consolidated subsidiaries	328,346			261,463

Total equity	3,215,591			3,111,398
Total liabilities and equity	6,835,716			6,728,362

	Three months ended September 30, 2012						Nine months ended September 30, 2012
Statement of Operations	As previously reported			As restated			As previously reported			As restated
Revenue	$	320,137		$	316,976		$	1,029,304		$	1,019,709
Total revenue	283,737			280,576			1,080,256			1,070,661

Facility expenses	53,293			52,883			150,671			149,438
Selling, general and administrative expenses	21,922			21,723			69,025			68,471
Depreciation	48,136			46,554			132,199			127,472
Accretion of asset retirement obligations	141			140			540			536
Total operating expenses	274,175			271,983			760,353			753,835

Income from operations	9,562			8,593			319,903			316,826
Equity in earnings from unconsolidated affiliates	246			706			788			2,254
(Loss) income before provision for income tax	(22,176		)	(22,685		)	230,251			228,640
Net (loss) income	(14,756		)	(15,265		)	188,653			187,042
Net loss (income) attributable to non-controlling interest	416			925			(65		)	1,546

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	Nine months ended September 30, 2012
Statement of Cash Flows	As previously reported			As restated
Cash flows from operating activities:
Net income	$	188,653		$	187,042
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	132,199			127,472
Accretion of asset retirement obligations	540			536
Equity in earnings from unconsolidated affiliate	(788		)	(2,254		)
Distributions from unconsolidated affiliate	2,200			6,624
Receivables	32,739			32,248
Other current assets	(12,707		)	(12,866		)
Accounts payable and accrued liabilities	36,737			36,837
Net cash provided by operating activities	389,718			385,784

Cash flows from investing activities:
Capital expenditures	(1,240,866		)	(1,239,705		)
Investment in unconsolidated affiliates	—			(839		)
Net cash flows used in investing activities	(1,746,071		)	(1,745,749		)

Cash flows from financing activities:
Contributions from non-controlling interest	56,940			56,101
Payment of distributions to non-controlling interest	(4,495		)	(71		)
Net cash flows provided by financing activities	1,654,401			1,657,986

Net increase in cash and cash equivalents	298,048			298,021
Cash and cash equivalents at beginning of year	117,016			114,332
Cash and cash equivalents at end of period	415,064			412,353

	Common Units						Non-controlling Interest						Total Equity
Statement of Changes in Equity	As previously reported			As restated			As previously reported			As restated			As previously reported			As restated
December 31, 2011	$	679,309		$	642,522		$	70,227		$	189		$	1,502,067		$	1,395,242
Distributions paid	(244,169		)	(244,169		)	(4,495		)	(71		)	(248,664		)	(244,240		)
Contributions from non-controlling interest	—			—			56,940			56,101			56,940			56,101
Deferred income tax impact from changes in equity	(74,855		)	(75,248		)	—			—			(74,855		)	(75,248		)
Net income (loss)	188,588			188,588			65			(1,546		)	188,653			187,042
September 30, 2012	1,745,672			1,708,492			122,737			54,673			2,620,940			2,515,696

4. Business Combination

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

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

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

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

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

Assets:
Property, plant and equipment	$	144,115
Goodwill	2,682
Intangible asset	84,500
Liabilities:
Accounts payable	6,087
Total	$	225,210

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

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

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

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

5. Divestiture

In June 2013, the Partnership completed the sale of certain gathering assets in Doddridge County, West Virginia (the “Sherwood Asset Sale”) to Summit Midstream Partners, LP (“Summit”) for approximately $207.9 million cash, net of third party transaction costs. In connection with the Sherwood Asset Sale, Summit assumed liabilities associated with the purchased assets other than certain identified liabilities that were retained by the Partnership. Liquids-rich gas gathered by these assets is dedicated to the Partnership for processing at the Marcellus segment’s Sherwood processing complex, also located in Doddridge County, West Virginia. The assets included in this transaction consist of over 40 miles of newly constructed high-pressure gas gathering pipelines, certain rights-of-way associated with the pipeline, and two compressor stations totaling over 21,000 horsepower of combined compression. The assets had a carrying value of approximately $169.0 million and were part of the Partnership’s Marcellus segment. The estimated gain of approximately $38.9 million on the Sherwood Asset Sale is included in Loss (gain) on disposal of property, plant, and equipment in the accompanying Condensed Consolidated Statements of Operations.

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6. Derivative Financial Instruments

Commodity Derivatives

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

To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership currently manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. A portion of the Partnership’s NGL price exposure is managed by using crude oil contracts that were primarily executed when there was a strong relationship between changes in NGL and crude oil prices. During 2012 and continuing into 2013, the price of NGLs as compared to crude oil weakened significantly and as a result, the crude oil contracts became less effective in offsetting the impact of NGL price fluctuations. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the crude oil contracts create increased risk and additional gains or losses. The Partnership may settle its crude oil contracts prior to the contractual settlement date in order to take advantage of favorable terms and reduce the future exposure resulting from the less effective crude oil contracts. Based on our current volume forecasts, approximately 80% of our derivative positions used to manage our future commodity price exposure are direct product NGL derivative contracts.

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

As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2015. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

Currently, all of the Partnership’s financial derivative positions are with financial institutions that are participating members of the Credit Facility (“participating bank group members”). Management conducts a standard credit review on counterparties to derivative contracts. There are no collateral requirements for derivative contracts among the Partnership and any participating bank group members. Specifically, the Partnership is not required to post collateral when it enters into derivative contracts with participating bank group members as the participating bank group members have a collateral position in substantially all the wholly-owned assets of the Partnership other than MarkWest Liberty Midstream and its subsidiaries. A separate agreement with certain participating bank group members allows MarkWest Liberty Midstream to enter into derivative positions without posting cash collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures (“master netting arrangements”) in the event of default or other terminating events, including bankruptcy.

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

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As of September 30, 2013, the Partnership had the following outstanding commodity contracts that were entered into to manage cash flow risk associated with future sales of NGLs or future purchases of natural gas:

Derivative contracts not designated as hedging instruments	Financial Position	Notional Quantity (net)
Crude Oil (bbl)	Short	1,409,056
Natural Gas (MMBtu)	Long	4,171,700
NGLs (gal)	Short	140,771,757

Embedded Derivatives in Commodity Contracts

The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative (loss) gain related to purchased product costs. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022 with the producer’s option to extend the agreement for successive five-year terms through December 31, 2032. As of September 30, 2013, the estimated fair value of this contract was a liability of $82.0 million and the recorded value was a liability of $28.5 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, 2013 (in thousands):

Fair value of commodity contract	$	81,957
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of September 30, 2013	$	28,450

The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at its plant location in the Southwest segment through the fourth quarter of 2014. Changes in the fair value of the derivative component of this contract are recorded in Derivative loss related to facility expenses. As of September 30, 2013, the estimated fair value of this contract was an asset of $3.3 million.

Financial Statement Impact of Derivative Instruments

There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012. The impact of the Partnership’s derivative instruments on its Condensed Consolidated Balance Sheets is summarized below (in thousands):

	Assets				Liabilities
Derivative instruments not designated as hedging instruments and their balance sheet location	September 30, 2013		December 31, 2012		September 30, 2013			December 31, 2012
Commodity contracts(1)
Fair value of derivative instruments — current	$	15,710	$	19,504	$	(29,479	)	$	(27,229	)
Fair value of derivative instruments - long-term	4,555		10,878		(21,044		)	(32,190		)
Total	$	20,265	$	30,382	$	(50,523	)	$	(59,419	)

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

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

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	Assets							Liabilities
As of September 30, 2013	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	12,630	$	(10,365	)	$	2,265	$	(19,372	)	$	10,365	$	(9,007	)
Embedded derivatives in commodity contracts	3,080		—			3,080		(10,107		)	—		(10,107		)
Total current derivative instruments	15,710		(10,365		)	5,345		(29,479		)	10,365		(19,114		)

Non-current

Commodity contracts	4,289		(1,792		)	2,497		(2,701		)	1,792		(909		)
Embedded derivatives in commodity contracts	266		—			266		(18,343		)	—		(18,343		)
Total non-current derivative instruments	4,555		(1,792		)	2,763		(21,044		)	1,792		(19,252		)

Total derivative instruments	$	20,265	$	(12,157	)	$	8,108	$	(50,523	)	$	12,157	$	(38,366	)

	Assets							Liabilities
As of December 31, 2012	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	16,438	$	(9,541	)	$	6,897	$	(16,679	)	$	9,541	$	(7,138	)
Embedded derivatives in commodity contracts	3,066		—			3,066		(10,550		)	—		(10,550		)
Total current derivative instruments	19,504		(9,541		)	9,963		(27,229		)	9,541		(17,688		)

Non-current

Commodity contracts	7,798		(2,637		)	5,161		(2,637		)	2,637		—
Embedded derivatives in commodity contracts	3,080		—			3,080		(29,553		)	—		(29,553		)
Total non-current derivative instruments	10,878		(2,637		)	8,241		(32,190		)	2,637		(29,553		)

Total derivative instruments	$	30,382	$	(12,178	)	$	18,204	$	(59,419	)	$	12,178	$	(47,241	)

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

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

Derivative contracts not designated as hedging instruments and the location of	Three months ended September 30,						Nine months ended September 30,
gain or (loss) recognized in income	2013			2012			2013			2012
Revenue: Derivative (loss) gain
Realized (loss) gain	$	(3,631	)	$	(2,025	)	$	3,356		$	(9,662	)
Unrealized (loss) gain	(26,687		)	(34,375		)	(14,160		)	60,614
Total revenue: derivative (loss) gain	(30,318		)	(36,400		)	(10,804		)	50,952

Derivative (loss) gain related to purchased product costs
Realized loss	(1,711		)	(6,334		)	(4,836		)	(21,201		)
Unrealized (loss) gain	(18,523		)	(5,309		)	15,738			42,337
Total derivative (loss) gain related to purchase product costs	(20,234		)	(11,643		)	10,902			21,136

Derivative loss related to facility expenses
Unrealized loss	(2,332		)	(4,028		)	(2,800		)	(1,136		)
Total (loss) gain	$	(52,884	)	$	(52,071	)	$	(2,702	)	$	70,952

7. Fair Value

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

As of September 30, 2013	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	3,518	$	(11,615	)
Significant unobservable inputs (Level 3)
Commodity contracts	13,401		(10,458		)
Embedded derivatives in commodity contracts	3,346		(28,450		)
Total carrying value in Condensed Consolidated Balance Sheet	$	20,265	$	(50,523	)

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

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The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of September 30, 2013. The market approach is used for valuation of all instruments.

Level 3 Instrument	Balance Sheet Classification	Unobservable Inputs	Value Range	Time Period

Commodity contracts	Assets	Forward propane prices (per gallon) (1)	$0.97 - $1.07	Oct. 2013 – Dec. 2014

		Forward isobutane prices (per gallon) (1)	$1.28 - $1.41	Oct. 2013 – Dec. 2014

		Forward normal butane prices (per gallon) (1)	$1.21 - $1.38	Oct. 2013 – Dec. 2014

		Forward natural gasoline prices (per gallon) (1)	$1.93 - $2.07	Oct. 2013 – Dec. 2014

		Crude option volatilities (%)	16.37% - 22.15%	Dec. 2013 – Dec. 2014

	Liabilities	Forward propane prices (per gallon) (1)	$0.97 - $1.07	Oct. 2013 – Dec. 2014

		Forward isobutane prices (per gallon) (1)	$1.28 - $1.40	Jan. 2014 – Dec. 2014

		Forward normal butane prices (per gallon) (1)	$1.21 - $1.37	Jan. 2014 – Dec. 2014

		Forward natural gasoline prices (per gallon) (1)	$2.03 - $2.07	Oct. 2013 – Mar. 2014

		Propane option volatilities (%)	14.01% - 26.14%	Oct. 2013 – Dec. 2013

		Crude option volatilities (%)	11.61% - 26.45%	Oct. 2013 – Jul. 2014

Embedded derivatives in commodity contracts	Asset	ERCOT Pricing (per MegaWatt Hour) (2)	$29.19 - $58.68	Oct. 2013 – Dec. 2014

	Liability	Forward propane prices (per gallon) (1)	$0.89 - $1.07	Oct. 2013 – Dec. 2022

		Forward isobutane prices (per gallon) (1)	$1.26 - $1.41	Oct. 2013 – Dec. 2022

		Forward normal butane prices (per gallon) (1)	$1.14 - $1.38	Oct. 2013 – Dec. 2022

		Forward natural gasoline prices (per gallon) (1)	$1.73 - $2.07	Oct. 2013 – Dec. 2022

		Forward natural gas prices (per MMBtu) (3)	$3.50 - $5.50	Oct. 2013 – Dec. 2022

		Probability of renewal(4)	0%

(1) NGL prices decrease over the respective periods with increases in the winter months due to seasonality.

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Changes in Level 3 Fair Value Measurements

The table below includes a roll forward of the balance sheet amounts for the three months ended September 30, 2013 and 2012 for net assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

	Three months ended September 30, 2013
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	26,378		$	(2,403	)
Total loss (realized and unrealized) included in earnings (1)	(24,269		)	(24,786		)
Settlements	834			2,085
Fair value at end of period	$	2,943		$	(25,104	)

The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	(20,250	)	$	(22,742	)

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

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

	Nine months ended September 30, 2013
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	12,449		$	(33,957	)
Total (loss) gain (realized and unrealized) included in earnings (1)	(4,050		)	2,206
Settlements	(5,456		)	6,647
Fair value at end of period	$	2,943		$	(25,104	)

The amount of total (losses) gains for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	(5,656	)	$	3,883

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

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

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

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8. Inventories

Inventories consist of the following (in thousands):

	September 30, 2013		December 31, 2012
NGLs	$	24,739	$	14,763
Spare parts, materials and supplies	10,775		9,870
Total inventories	$	35,514	$	24,633

9. Goodwill

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

	Marcellus		Northeast		Southwest			Total
Gross goodwill as of December 31, 2012	$	74,256	$	62,445	$	34,178		$	170,879
Acquisition (1)	—		—		2,682			2,682
Gross goodwill as of September 30, 2013	74,256		62,445		36,860			173,561

Cumulative impairment (2)	—		—		(28,705		)	(28,705		)
Balance as of September 30, 2013	$	74,256	$	62,445	$	8,155		$	144,856

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

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

10. Long-Term Debt

Debt is summarized below (in thousands):

	September 30, 2013		December 31, 2012
Credit Facility
Credit Facility, variable interest, due September 2017 (1)	$	—	$	—

Senior Notes (2)
2018 Senior Notes, 8.75% interest, net of discount of zero and $109, respectively, issued April and May 2008	—		81,003
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020	500,000		500,000
2021 Senior Notes, 6.5% interest, net of discount of $490 and $826, respectively, issued February and March 2011 and due August 2021	324,510		499,174
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022	455,000		700,000
2023A Senior Notes, 5.5% interest, net of discount of $6,623 and $7,126, respectively, issued August 2012 and due February 2023	743,377		742,874
2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023	1,000,000		—
Total long-term debt	$	3,022,887	$	2,523,051

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

(2) The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $3,065 million and $2,763 million as of September 30, 2013 and December 31, 2012, respectively, based on quoted prices in an inactive market. The fair value of the Partnership’s Senior Notes is considered a Level 3 measurement.

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Distributions of Available Cash and Range of Unit Prices

	Common Unit Price				Distribution Per Common
Quarter Ended	High		Low		Unit		Declaration Date	Record Date	Payment Date
September 30, 2013	$	72.35	$	65.27	$	0.85	October 23, 2013	November 7, 2013	November 14, 2013
June 30, 2013	$	71.20	$	56.90	$	0.84	July 24, 2013	August 6, 2013	August 14, 2013
March 31, 2013	$	61.97	$	51.77	$	0.83	April 25, 2013	May 7, 2013	May 15, 2013
December 31, 2012	$	55.95	$	46.03	$	0.82	January 23, 2013	February 6, 2013	February 14, 2013

12. Commitments and Contingencies

Legal

The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Partnership maintains insurance policies in amounts and with coverage and deductibles that it believes are reasonable and prudent. However, the Partnership cannot assure that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect the Partnership from all material expenses related to future claims for property loss or business interruption to the Partnership, or for third-party claims of personal injury and property damage, or that the coverages or levels of insurance it currently has will be available in the future at economical prices. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the accompanying Condensed Consolidated Financial Statements and that none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership’s financial condition, liquidity or results of operations.

Contract Contingencies

Certain natural gas processing arrangements in the Partnership’s Marcellus, Utica and Northeast segments require the Partnership to construct new natural gas processing plants and NGL pipelines and contain certain fees and concessions if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure. As of September 30, 2013, management does not believe there are any indications that the Partnership will incur any such fees or other material consequences for not meeting construction milestones.

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

	Nine months ended September 30, 2013
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	25,480		$	40,223		$	(8,779	)	$	56,924
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	8,918			—			—			8,918
Permanent items	25			—			—			25
State income taxes net of federal benefit	511			154			—			665
Provision on income from Class A units (1)	2,976			—			—			2,976
Provision for income tax	$	12,430		$	154		$	—		$	12,584

	Nine months ended September 30, 2012
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	74,679		$	151,752		$	2,209		$	228,640
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	26,138			—			—			26,138
Permanent items	21			—			—			21
State income taxes net of federal benefit	3,418			734			—			4,152
Provision on income from Class A units (1)	11,287			—			—			11,287
Provision for income tax	$	40,864		$	734		$	—		$	41,598

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(1) The Corporation and the General Partner of the Partnership own Class A units of the Partnership that were received in the merger of the Corporation and the Partnership completed in February 2008. The Class A units share, on a pro-rata basis, in the income or loss of the Partnership, except for items attributable to the Partnership’s ownership of or sale of shares of the Corporation’s common stock. The provision for income tax on income from Class A units includes intra period allocations to continued operations and excludes allocations to equity.

14. Earnings Per Common Unit

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

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013		2012
Net (loss) income attributable to the Partnership’s unitholders	$	(23,604	)	$	(14,340	)	$	44,637	$	188,588
Less: Income allocable to phantom units	618			541			1,718		1,595
(Loss) income available for common unitholders - basic	(24,222		)	(14,881		)	42,919		186,993
Add: Income allocable to phantom units and DER expense	—			—			1,774		1,627
(Loss) income available for common unitholders - diluted	$	(24,222	)	$	(14,881	)	$	44,693	$	188,620

Weighted average common units outstanding - basic	142,352			113,994			134,115		105,916
Potential common shares (Class B and phantom units) (1)	—			—			19,340		20,679
Weighted average common units outstanding - diluted	142,352			113,994			153,455		126,595

Net (loss) income attributable to the Partnership’s common unitholders per common unit (2)
Basic	$	(0.17	)	$	(0.13	)	$	0.32	$	1.77
Diluted	$	(0.17	)	$	(0.13	)	$	0.29	$	1.49

(1) For the three month periods ending September 30, 2013 and September 30, 2012, 16,760 and 20,641 units were excluded, respectively, from the calculation of diluted units because the impact was anti-dilutive.

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

15. Segment Information

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

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, 2013 and 2012 and capital expenditures for the nine months ended September 30, 2013 and 2012 for the reported segments (in thousands):

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Three months ended September 30, 2013:

	Marcellus		Utica			Northeast		Southwest		Total
Segment revenue	$	147,290	$	8,373		$	48,829	$	247,885	$	452,377
Purchased product costs	36,995		—			15,330		139,347		191,672
Net operating margin	110,295		8,373			33,499		108,538		260,705
Facility expenses	29,621		9,858			7,359		32,559		79,397
Portion of operating loss attributable to non-controlling interests	—		(599		)	—		40		(559		)
Operating income (loss) before items not allocated to segments	$	80,674	$	(886	)	$	26,140	$	75,939	$	181,867

Three months ended September 30, 2012:

	Marcellus		Utica			Northeast		Southwest (1)		Total
Segment revenue	$	78,707	$	145		$	39,987	$	199,394	$	318,233
Purchased product costs	16,203		—			11,054		92,112		119,369
Net operating margin	62,504		145			28,933		107,282		198,864
Facility expenses	18,933		1,308			6,267		28,870		55,378
Portion of operating (loss) income attributable to non-controlling interests	—		(627		)	—		67		(560		)
Operating income (loss) before items not allocated to segments	$	43,571	$	(536	)	$	22,666	$	78,345	$	144,046

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

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

	Three months ended September 30,
	2013			2012 (3)
Total segment revenue	$	452,377		$	318,233
Derivative loss not allocated to segments	(30,318		)	(36,400		)
Revenue deferral adjustment and other (1)	(1,543		)	(1,257		)
Total revenue	$	420,516		$	280,576

Operating income before items not allocated to segments	$	181,867		$	144,046
Portion of operating loss attributable to non-controlling interests	(559		)	(560		)
Derivative loss not allocated to segments	(52,884		)	(52,071		)
Revenue deferral adjustment and other (1)	(1,543		)	(1,257		)
Compensation expense included in facility expenses not allocated to segments	(833		)	(193		)
Facility expenses adjustments (2)	2,688			2,688
Selling, general and administrative expenses	(26,647		)	(21,723		)
Depreciation	(76,323		)	(46,554		)
Amortization of intangible assets	(16,003		)	(14,988		)
Loss on disposal of property, plant and equipment	(1,840		)	(655		)
Accretion of asset retirement obligations	(160		)	(140		)
Income from operations	7,763			8,593
Earnings from unconsolidated affiliates	896			706
Interest income	27			64
Interest expense	(38,889		)	(30,621		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,584		)	(1,428		)
Miscellaneous income, net	1,504			1
Loss before provision for income tax	$	(30,283	)	$	(22,685	)

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(1) Amount relates primarily to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term. Therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnership’s chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended September 30, 2013, approximately $0.2 million and $1.5 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. In comparison, for the three months ended September 30, 2012, approximately $0.2 million and $1.4 million of the revenue deferral adjustment was attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes. Other consists of management fee revenues from an unconsolidated affiliate of $0.2 million for the three months ended September 30, 2013 compared to $0.3 million for three months ended September 30, 2012.

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

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

Nine months ended September 30, 2013:

	Marcellus		Utica			Northeast		Southwest		Total
Segment revenue	$	375,844	$	12,590		$	151,530	$	684,093	$	1,224,057
Purchased product costs	72,781		—			50,118		376,689		499,588
Net operating margin	303,063		12,590			101,412		307,404		724,469
Facility expenses	74,529		20,232			20,538		91,027		206,326
Portion of operating (loss) income attributable to non-controlling interests	—		(3,081		)	—		157		(2,924		)
Operating income (loss) before items not allocated to segments	$	228,534	$	(4,561	)	$	80,874	$	216,220	$	521,067

Capital expenditures	$	1,097,440	$	961,538		$	3,418	$	108,440	$	2,170,836
Capital expenditures not allocated to segments										5,883
Total capital expenditures										$	2,176,719

Nine months ended September 30, 2012:

	Marcellus		Utica			Northeast		Southwest (1)		Total
Segment revenue	$	213,761	$	145		$	168,956	$	641,321	$	1,024,183
Purchased product costs	48,856		—			49,662		288,137		386,655
Net operating margin	164,905		145			119,294		353,184		637,528
Facility expenses	44,544		1,591			17,577		92,964		156,676
Portion of operating (loss) income attributable to non-controlling interests	—		(740		)	—		98		(642		)
Operating income (loss) before items not allocated to segments	$	120,361	$	(706	)	$	101,717	$	260,122	$	481,494

Capital expenditures	$	937,008	$	82,366		$	70,206	$	145,213	$	1,234,793
Capital expenditures not allocated to segments										4,912
Total capital expenditures										$	1,239,705

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

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

	Nine months ended September 30,
	2013			2012 (3)

Total segment revenue	$	1,224,057		$	1,024,183
Derivative gain not allocated to segments	(10,804		)	50,952
Revenue deferral adjustment and other (1)	(4,344		)	(4,474		)
Total revenue	$	1,208,909		$	1,070,661

Operating income before items not allocated to segments	$	521,067		$	481,494
Portion of loss income attributable to non-controlling interests	(2,924		)	(642		)
Derivative (loss) gain not allocated to segments	(2,702		)	70,952
Revenue deferral adjustment and other(1)	(4,344		)	(4,474		)
Compensation expense included in facility expenses not allocated to segments	(1,587		)	(826		)
Facility expenses adjustments (2)	8,064			8,064
Selling, general and administrative expenses	(77,388		)	(68,471		)
Depreciation	(215,902		)	(127,472		)
Amortization of intangible assets	(47,925		)	(38,280		)
Gain (loss) on disposal of property, plant and equipment	35,758			(2,983		)
Accretion of asset retirement obligations	(669		)	(536		)
Income from operations	211,448			316,826
Earnings from unconsolidated affiliates	1,561			2,254
Interest income	238			295
Interest expense	(114,180		)	(86,855		)
Amortization of deferred financing costs and discount (a component of interest expense)	(5,198		)	(3,943		)
Loss on redemption of debt	(38,455		)	—
Miscellaneous income, net	1,510			63
Income before provision for income tax	$	56,924		$	228,640

(1) Amount relates primarily to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term. Therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnership’s chief operating decision maker and management evaluate the segment performance based on the cash consideration received and, therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the nine months ended September 30, 2013, approximately $0.6 million and $4.5 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. In comparison, for the nine months ended September 30, 2012, approximately $0.6 million and $5.0 million of the revenue deferral adjustment was attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes. The other consists of management fee revenues from an unconsolidated affiliate of $0.8 million for the nine months ended September 30, 2013 compared to $1.1 million for the nine months ended September 30, 2012.

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

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

	September 30, 2013		December 31, 2012 (2)
Marcellus	$	4,143,180	$	3,172,144
Utica	1,379,200		439,987
Northeast	580,788		578,122
Southwest	2,371,539		2,086,215
Total segment assets	8,474,707		6,276,468
Assets not allocated to segments:
Certain cash and cash equivalents	250,133		261,473
Fair value of derivatives	20,265		30,382
Investment in unconsolidated affiliate	68,193		63,054
Other (1)	104,418		96,985
Total assets	$	8,917,716	$	6,728,362

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

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

16. Supplemental Condensed Consolidating Financial Information

MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of September 30, 2013, the Partnership’s obligations under the outstanding Senior Notes (see Note 10) were fully, jointly and severally guaranteed, by all of the subsidiaries that are owned 100% by the Partnership, other than MarkWest Liberty Midstream and its subsidiaries. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures (see Note 15 to the Consolidated Financial Statements included in Item 8 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012 for discussion of these circumstances). Subsidiaries that are not 100% owned by the Partnership do not guarantee the Senior Notes. For the purpose of the following financial information, the Partnership’s investments in its subsidiaries and the guarantor subsidiaries’ investments in their subsidiaries are presented in accordance with the equity method of accounting. The operations, cash flows and financial position of the co-issuer, MarkWest Energy Finance Corporation, are not material and, therefore, have been included with the Parent’s financial information. Condensed consolidating financial information for MarkWest Energy Partners and its combined guarantor and combined non-guarantor subsidiaries as of September 30, 2013 and December 31, 2012 and for the three and nine months ended September 30, 2013 and 2012 is as follows (in thousands):

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Condensed Consolidating Balance Sheets

	As of September 30, 2013
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	181,213	$	119,886	$	27,054	$	—		$	328,153
Restricted cash	—		—		10,000		—			10,000
Receivables and other current assets	3,146		233,522		89,765		—			326,433
Intercompany receivables	440,839		6,659		49,494		(496,992		)	—
Fair value of derivative instruments	—		14,872		838		—			15,710
Total current assets	625,198		374,939		177,151		(496,992		)	680,296

Total property, plant and equipment, net	3,598		2,174,893		4,940,452		(78,120		)	7,040,823

Other long-term assets:
Restricted Cash	—		—		10,000		—			10,000
Investment in unconsolidated affiliate	—		68,193		—		—			68,193
Investment in consolidated affiliates	5,716,977		3,766,735		—		(9,483,712		)	—
Intangibles, net of accumulated amortization	—		608,748		282,764		—			891,512
Fair value of derivative instruments	—		4,214		341		—			4,555
Intercompany notes receivable	225,000		—		—		(225,000		)	—
Other long-term assets	54,046		92,380		75,911		—			222,337
Total assets	$	6,624,819	$	7,090,102	$	5,486,619	$	(10,283,824	)	$	8,917,716

LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	1	$	486,870	$	10,121	$	(496,992	)	$	—
Fair value of derivative instruments	—		27,460		2,019		—			29,479
Other current liabilities	47,522		214,180		655,079		(2,068		)	914,713
Total current liabilities	47,523		728,510		667,219		(499,060		)	944,192

Deferred income taxes	3,061		256,974		—		—			260,035
Long-term intercompany financing payable	—		225,000		98,018		(323,018		)	—
Fair value of derivative instruments	—		20,996		48		—			21,044
Long-term debt, net of discounts	3,022,887		—		—		—			3,022,887
Other long-term liabilities	2,838		141,645		8,394		—			152,877

Redeemable non-controlling interest	—		—		—		366,238			366,238

Equity:
Common units	2,946,485		5,716,977		4,712,940		(10,407,951		)	2,968,451
Class B units	602,025		—		—		—			602,025
Non-controlling interest in consolidated subsidiaries	—		—		—		579,967			579,967
Total equity	3,548,510		5,716,977		4,712,940		(9,827,984		)	4,150,443
Total liabilities and equity	$	6,624,819	$	7,090,102	$	5,486,619	$	(10,283,824	)	$	8,917,716

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	As of December 31, 2012 (1)
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	210,015	$	102,979	$	32,762	$	—		$	345,756
Restricted cash	—		—		25,500		—			25,500
Receivables and other current assets	9,191		178,913		74,658		—			262,762
Intercompany receivables	812,562		18,472		32,656		(863,690		)	—
Fair value of derivative instruments	—		18,389		1,115		—			19,504
Total current assets	1,031,768		318,753		166,691		(863,690		)	653,522
Total property, plant and equipment, net	3,542		1,999,474		3,032,121		(95,519		)	4,939,618
Other long-term assets:
Restricted cash	—		—		10,000		—			10,000
Investment in unconsolidated affiliate	—		63,054		—		—			63,054
Investment in consolidated affiliates	4,104,473		2,719,920		—		(6,824,393		)	—
Intangibles, net of accumulated amortization	—		559,320		295,835		—			855,155
Fair value of derivative instruments	—		10,878		—		—			10,878
Intercompany notes receivable	225,000		—		—		(225,000		)	—
Other long-term assets	50,866		70,009		75,260		—			196,135
Total assets	$	5,415,649	$	5,741,408	$	3,579,907	$	(8,008,602	)	$	6,728,362
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	461	$	839,543	$	23,686	$	(863,690	)	$	—
Fair value of derivative instruments	—		27,062		167		—			27,229
Other current liabilities	42,301		197,934		472,462		(1,892		)	710,805
Total current liabilities	42,762		1,064,539		496,315		(865,582		)	738,034
Deferred income taxes	2,906		186,522		—		—			189,428
Long-term intercompany financing payable	—		225,000		99,592		(324,592		)	—
Fair value of derivative instruments	—		32,190		—		—			32,190
Long-term debt, net of discounts	2,523,051		—		—		—			2,523,051
Other long-term liabilities	2,959		128,684		2,618		—			134,261
Equity:
Common Units	2,091,440		4,104,473		2,981,382		(7,079,891		)	2,097,404
Class B Units	752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries	—		—		—		261,463			261,463
Total equity	2,843,971		4,104,473		2,981,382		(6,818,428		)	3,111,398
Total liabilities and equity	$	5,415,649	$	5,741,408	$	3,579,907	$	(8,008,602	)	$	6,728,362

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

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Condensed Consolidating Statements of Operations

	Three months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	277,120		$	152,225		$	(8,829	)	$	420,516
Operating expenses:
Purchased product costs	—			174,754			37,152			—			211,906
Facility expenses	—			39,781			40,598			(505		)	79,874
Selling, general and administrative expenses	12,297			7,900			8,077			(1,627		)	26,647
Depreciation and amortization	155			45,898			47,570			(1,297		)	92,326
Other operating expenses (income)	—			1,970			30			—			2,000
Total operating expenses	12,452			270,303			133,427			(3,429		)	412,753

(Loss) income from operations	(12,452		)	6,817			18,798			(5,400		)	7,763

Earnings from consolidated affiliates	22,899			12,229			—			(35,128		)	—
Other expense, net	(38,339		)	(6,396		)	(2,992		)	9,681			(38,046		)
Income before provision for income tax	(27,892		)	12,650			15,806			(30,847		)	(30,283		)
Provision for income tax (benefit) expense	(7		)	(10,249		)	—			—			(10,256		)
Net income	(27,885		)	22,899			15,806			(30,847		)	(20,027		)
Net income attributable to non-controlling interest	—			—			—			(3,577		)	(3,577		)
Net income attributable to the Partnership’s unitholders	$	(27,885	)	$	22,899		$	15,806		$	(34,424	)	$	(23,604	)

	Three months ended September 30, 2012 (1)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	205,629		$	78,047		$	(3,100	)	$	280,576
Operating expenses:
Purchased product costs	—			114,685			16,327			—			131,012
Facility expenses	—			36,437			20,475			(1		)	56,911
Selling, general and administrative expenses	10,241			5,633			6,943			(1,094		)	21,723
Depreciation and amortization	146			41,593			21,381			(1,578		)	61,542
Other operating expenses	—			488			307			—			795
Total operating expenses	10,387			198,836			65,433			(2,673		)	271,983

(Loss) income from operations	(10,387		)	6,793			12,614			(427		)	8,593

Earnings from consolidated affiliates	20,122			10,387			—			(30,509		)	—
Other (expense) income, net	(24,637		)	(4,447		)	(3,152		)	958			(31,278		)
(Loss) income before provision for income tax	(14,902		)	12,733			9,462			(29,978		)	(22,685		)
Provision for income tax expense	(31		)	(7,389		)	—			—			(7,420		)
Net (loss) income	(14,871		)	20,122			9,462			(29,978		)	(15,265		)
Net income attributable to non-controlling interest	—			—			—			925			925
Net (loss) income attributable to the Partnership’s unitholders	$	(14,871	)	$	20,122		$	9,462		$	(29,053	)	$	(14,340	)

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	Nine months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	846,185		$	388,082		$	(25,358	)	$	1,208,909
Operating expenses:
Purchased product costs	—			415,517			73,169			—			488,686
Facility expenses	—			106,556			96,985			(892		)	202,649
Selling, general and administrative expenses	36,405			21,519			23,605			(4,141		)	77,388
Depreciation and amortization	674			135,408			131,865			(4,120		)	263,827
Other operating expenses (income)	—			3,308			(40,477		)	2,080			(35,089		)
Total operating expenses	37,079			682,308			285,147			(7,073		)	997,461

(Loss) income from operations	(37,079		)	163,877			102,935			(18,285		)	211,448

Earnings from consolidated affiliates	225,773			93,958			—			(319,731		)	—
Loss on redemption of debt	(38,455		)	—			—			—			(38,455		)
Other expense, net	(121,441		)	(19,632		)	(9,274		)	34,278			(116,069		)
Income before provision for income tax	28,798			238,203			93,661			(303,738		)	56,924
Provision for income tax (benefit) expense	154			12,430			—			—			12,584
Net income	28,644			225,773			93,661			(303,738		)	44,340
Net income attributable to non-controlling interest	—			—			—			297			297
Net (loss) income attributable to the Partnership’s unitholders	$	28,644		$	225,773		$	93,661		$	(303,441	)	$	44,637

	Nine months ended September 30, 2012 (1)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	858,227		$	217,257		$	(4,823	)	$	1,070,661
Operating expenses:
Purchased product costs	—			316,327			49,192			—			365,519
Facility expenses	—			103,484			47,248			(158		)	150,574
Selling, general and administrative expenses	37,197			13,333			20,697			(2,756		)	68,471
Depreciation and amortization	458			121,520			46,719			(2,945		)	165,752
Other operating expenses	—			2,227			1,292			—			3,519
Total operating expenses	37,655			556,891			165,148			(5,859		)	753,835

(Loss) income from operations	(37,655		)	301,336			52,109			1,036			316,826

Earnings from consolidated affiliates	294,036			48,134			—			(342,170		)	—
Other expense, net	(68,681		)	(14,570		)	(5,521		)	586			(88,186		)
Income before provision for income tax	187,700			334,900			46,588			(340,548		)	228,640
Provision for income tax expense	734			40,864			—			—			41,598
Net income (loss)	186,966			294,036			46,588			(340,548		)	187,042
Net income attributable to non-controlling interest	—			—			—			1,546			1,546
Net income attributable to the Partnership’s unitholders	$	186,966		$	294,036		$	46,588		$	(339,002	)	$	188,588

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Condensed Consolidating Statements of Cash Flows

	Nine months ended September 30, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(136,817	)	$	265,484		$	188,042		$	13,950		$	330,659

Cash flows from investing activities:
Restricted cash	—			—			15,500			—			15,500
Capital expenditures	(655		)	(110,921		)	(2,049,794		)	(15,349		)	(2,176,719		)
Equity investments in consolidated affiliates	(43,763		)	(1,404,800		)	—			1,448,563			—
Investment in unconsolidated affiliates	—			(8,530		)	—			—			(8,530		)
Distributions from consolidated affiliates	72,673			455,966			—			(528,639		)	—
Acquisition of business, net of cash acquired	—			(225,210		)	—			—			(225,210		)
Proceeds from disposal of property, plant and equipment	—			582			208,070			—			208,652
Net cash flows provided by (used in) investing activities	28,255			(1,292,913		)	(1,826,224		)	904,575			(2,186,307		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	1,039,849			—			—			—			1,039,849
Proceeds from long-term debt	1,000,000			—			—			—			1,000,000
Payments of long-term debt	(501,112		)	—			—			—			(501,112		)
Payments of premiums on redemption of long-term debt	(31,516		)	—			—			—			(31,516		)
Payments for debt issuance costs, deferred financing costs and registration costs	(14,046		)	—			—			—			(14,046		)
Payments related to intercompany financing, net	—			—			(1,399		)	1,399			—
Contributions from parent and affiliates	—			43,763			1,404,800			(1,448,563		)	—
Contributions from non-controlling interest	—			—			685,219			—			685,219
Share-based payment activity	(5,212		)	650			—			—			(4,562		)
Payments of distributions	(333,946		)	(72,673		)	(456,146		)	528,639			(334,126		)
Payments of SMR liability	—			(1,661		)	—			—			(1,661		)
Intercompany advances, net	(1,074,257		)	1,074,257			—			—			—
Net cash flows (used in) provided by financing activities	79,760			1,044,336			1,632,474			(918,525		)	1,838,045

Net (decrease) increase in cash and cash equivalents	(28,802		)	16,907			(5,708		)	—			(17,603		)
Cash and cash equivalents at beginning of year	210,015			102,979			32,762			—			345,756
Cash and cash equivalents at end of period	$	181,213		$	119,886		$	27,054		$	—		$	328,153

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	Nine months ended September 30, 2012 (1)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(89,558	)	$	305,694		$	170,976		$	(1,328	)	$	385,784

Cash flows from investing activities:
Restricted cash	—			—			1,003			—			1,003
Capital expenditures	(120		)	(236,153		)	(1,005,270		)	1,838			(1,239,705		)
Equity investments	(42,120		)	(1,367,484		)	—			1,408,765			(839		)
Acquisition of business, net of cash acquired	—			—			(506,797		)	—			(506,797		)
Distributions from consolidated affiliates	48,973			95,814			—			(144,787		)	—
Collection of intercompany notes, net	(12,300		)	—			—			12,300			—
Proceeds from disposal of property, plant and equipment	—			1,718			84			(1,213		)	589
Net cash flows used in investing activities	(5,567		)	(1,506,105		)	(1,510,980		)	1,276,903			(1,745,749		)

Cash flows from financing activities:
Proceeds from public equity offering, net	1,191,066			—			—			—			1,191,066
Proceeds from Credit Facility	511,100			—			—			—			511,100
Payments of Credit Facility	(577,100		)	—			—			—			(577,100		)
Proceeds from long-term debt	742,613			—			—			—			742,613
Payments related to intercompany financing, net	—			12,300			(703		)	(11,597		)	—
Payments for deferred financing costs	(14,184		)	—			—			—			(14,184		)
Contributions from parent and affiliates	—			42,120			1,366,645			(1,408,765		)	—
Contributions from non-controlling interest	—			—			56,101			—			56,101
Share-based payment activity	(8,061		)	2,216			—			—			(5,845		)
Payment of distributions	(244,169		)	(48,973		)	(95,885		)	144,787			(244,240		)
Payments of SMR liability	—			(1,525		)	—			—			(1,525		)
Intercompany advances, net	(1,206,149		)	1,206,149			—			—			—
Net cash flows provided by financing activities	395,116			1,212,287			1,326,158			(1,275,575		)	1,657,986

Net increase (decrease) in cash	299,991			11,876			(13,846		)	—			298,021
Cash and cash equivalents at beginning of year	22			99,580			14,730			—			114,332
Cash and cash equivalents at end of period	$	300,013		$	111,456		$	884		$	—		$	412,353

17. Supplemental Cash Flow Information

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

	Nine months ended September 30,
	2013			2012
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	111,626		$	73,624
Cash (received) paid for income taxes, net	(16,414		)	18,925

Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	614,355		$	389,599
Interest capitalized on construction in progress	26,232			16,353
Issuance of common units for vesting of share-based payment awards	4,861			2,506

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	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Segment revenue	$	452,377		$	318,233		$	1,224,057		$	1,024,183
Purchased product costs	(191,672		)	(119,369		)	(499,588		)	(386,655		)
Net operating margin	260,705			198,864			724,469			637,528
Facility expenses	(77,542		)	(52,883		)	(199,849		)	(149,438		)
Derivative (loss) gain	(52,884		)	(52,071		)	(2,702		)	70,952
Revenue deferral adjustment	(1,543		)	(1,257		)	(4,344		)	(4,474		)
Selling, general and administrative expenses	(26,647		)	(21,723		)	(77,388		)	(68,471		)
Depreciation	(76,323		)	(46,554		)	(215,902		)	(127,472		)
Amortization of intangible assets	(16,003		)	(14,988		)	(47,925		)	(38,280		)
(Loss) gain on disposal of property, plant and equipment	(1,840		)	(655		)	35,758			(2,983		)
Accretion of asset retirement obligations	(160		)	(140		)	(669		)	(536		)
Income from operations	$	7,763		$	8,593		$	211,448		$	316,826

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

Our Contracts

We generate the majority of our revenue and net operating margin (a non-GAAP measure, see above for discussion and reconciliation of net operating margin) from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the following types of arrangements: fee-based, percent-of-proceeds, percent-of-index and keep-whole. See Item 1. Business—Our Contracts in our Annual Report on Form 10-K for the year ended December 31, 2012 for further discussion of each of these types of arrangements.

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

For the three months ended September 30, 2013, we calculated the following approximate percentages of our segment revenue and net operating margin from the following types of contracts:

	Fee-Based		Percent-of- Proceeds (1)		Keep-Whole (2)
Marcellus	80	%	20	%	0	%
Utica	100	%	0	%	0	%
Northeast	25	%	16	%	59	%
Southwest	51	%	41	%	8	%
Total	62	%	27	%	11	%

For the nine months ended September 30, 2013, we calculated the following approximate percentages of our segment revenue and net operating margin from the following types of contracts:

	Fee-Based		Percent-of-Proceeds (1)		Keep-Whole (2)
Marcellus	80	%	20	%	0	%
Utica	100	%	0	%	0	%
Northeast	23	%	16	%	61	%
Southwest	52	%	38	%	10	%
Total	60	%	27	%	13	%

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

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

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· From the Hopedale Fractionation Facility, we plan to market NGLs by truck, rail and pipeline. A large-scale rail car loading facility and truck loading and unloading facility are under construction at the Hopedale Fractionation Facility and are expected to be complete by first quarter of 2014. Additionally, the Hopedale Fractionation Facility is expected to be connected to our extensive processing and NGL pipeline network in our Marcellus segment and provide for the integrated operation of the two largest fractionation complexes in the northeast United States by the first half of 2014.

Ethane Recovery and Associated Market Outlets

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

· In August 2013, we announced plans to install a 38,000 Bbl/d de-ethanization facility at the Seneca Complex.

In August 2013, we executed a non-binding letter of intent with Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”) to form a midstream joint venture to pursue three critical new projects that would support producers in the Utica and Marcellus Shales in Ohio, Pennsylvania and West Virginia. If we reach a definitive agreement, the first project would consist of the development of a cryogenic processing complex in Tuscarawas County, Ohio with initial capacity of 200 MMcf/d, expandable to a capacity of 400 MMcf/d (“Tuscarawas Complex”). We expect that the second project would consist of the development of a NGL pipeline with initial capacity of 150,000 Bbl/d that originates at the planned Tuscarawas Complex in Ohio and transports NGLs to fractionation facilities in the Gulf Coast region. In November 2013, we and Kinder Morgan announced a binding open season to solicit commitments for the NGL pipeline project. The third joint project would involve the development of new fractionation facilities as well as the utilization of third-party fractionation facilities throughout the Gulf Coast region. The formation of the joint venture and the pursuit of the related projects is dependent upon the execution of definitive agreements. In addition to this anticipated joint venture, we continue to evaluate projects to expand our gathering, processing, fractionation, and marketing operations in the Utica Shale.

Northeast Segment

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

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

Southwest Segment

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

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

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

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compression services for natural gas produced by Chesapeake from 130,000 dedicated acres throughout the Anadarko Basin.

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

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

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

The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by segment, for the nine months ended September 30, 2013:

	Marcellus		Utica		Northeast		Southwest
Segment revenue	31	%	1	%	12	%	56	%
Net operating margin	42	%	2	%	14	%	42	%

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, 2013 and 2012 and for the nine months ended September 30, 2013 and 2012. For each period presented, the Southwest segment includes the operations of our processing facilities in Corpus Christi, Texas that were reported separately in the Gulf Coast segment in the prior year. The Gulf Coast operations are no longer material to the Partnership’s operations and no longer meaningful separately.

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

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

Marcellus

	Three months ended September 30,
	2013		2012		$ Change		% Change
	(in thousands)
Segment revenue	$	147,290	$	78,707	$	68,583	87	%
Purchased product costs	36,995		16,203		20,792		128	%
Net operating margin	110,295		62,504		47,791		76	%
Facility expenses	29,621		18,933		10,688		56	%

Operating income before items not allocated to segments	$	80,674	$	43,571	$	37,103	85	%

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Segment Revenue. Revenue increased due to ongoing expansion of the Marcellus segment operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $38.9 million related to gathering, processing and fractionation fees, of which approximately $14.6 million is due to our Keystone Acquisition and the opening of the Sherwood and Mobley Complexes and the remaining increase in fees relates to increased volumes at our Houston and Majorsville facilities. Revenue also increased approximately $27.1 million related to NGL sales under percent of proceeds arrangements due to increased volumes. These revenue increases were partially offset by several operational constraints discussed further in the Net Operating Margin section below.

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

Net Operating Margin. Net operating margin increased as the volume of natural gas gathered, processed, and fractionated increased by 27%, 137% and 116%, respectively. Approximately 80% of the net operating margin is earned under fee-based contracts and was not significantly impacted by the lower commodity prices in the third quarter of 2013 compared to the same period in 2012. Certain temporary operational constraints during the third quarter prevented us from realizing the full economic benefit of the significant growth in our producer customers’ volumes. Due to these constraints that are outlined below, our net operating margin was approximately $9.4 million lower than expected.

· The NGL production resulting from the increased volumes has exceeded our current fractionation capacity. Additional fractionation capacity is expected to be placed into service in the first quarter 2014. In response to this capacity constraint, we have made arrangements for the excess NGLs to be fractionated by third-party facilities. As part of these arrangements, until the end of the year we will incur additional transportation costs and realize lower fractionation income.

· We also experienced a temporary shutdown of the Mobley processing facilities and partial curtailment of operations of the Sherwood processing facilities beginning in the middle of August 2013. The constraints on the processing operations were due to damage to a portion of the Marcellus NGL pipeline in Wetzel County, West Virginia resulting from landslides that originated from significant run-off and saturation from persistent rainfall (“Wetzel County Landslides”). The pipeline and processing facilities impacted by the Wetzel County Landslides safely resumed normal operations in mid-October 2013.

· The delay in the completion of Sunoco’s Mariner West Pipeline project resulted in lower than expected income during this period. The Mariner West Pipeline is expected to become fully operational in November and together with the completion of the ATEX pipeline and Mariner East, we anticipate steady utilization growth of its new ethane fractionation facility as the full delivery of ethane begins.

Facility Expenses. Facility expenses increased due to the ongoing expansion of the Marcellus segment operations, additional expenses of approximately $2.0 million, net of insurance recoveries, related to the Wetzel County Landslides and additional expenses caused by the limitations in fractionation capacity discussed above under net operating margin.

Utica

	Three months ended September 30,
	2013			2012			$ Change			% Change
	(in thousands)
Segment revenue	$	8,373		$	145		$	8,228		5,674	%
Purchased product costs	—			—			—			N/A
Net operating margin	8,373			145			8,228			5,674	%
Facility expenses	9,858			1,308			8,550			654	%
Portion of operating loss attributable to non-controlling interests	(599		)	(627		)	28			(4	)%
Operating loss before items not allocated to segments	$	(886	)	$	(536	)	$	(350	)	65	%

The results of operations for the quarter ended September 30, 2013 include our operations in the Utica Shale areas of eastern Ohio. The first phase of operations began in the third quarter of 2012 and remains in the early stages of development. Operations will continue to grow significantly as we add 800 MMcf/d cryogenic capacity through the end of 2014. Facility expenses in 2013 include start-up costs and other costs that cannot be capitalized, including approximately $1.3 million of amortization of costs to install temporary compression and treating facilities. During the third quarter of 2013, the Utica segment net operating margin was similarly affected by the limitations of fractionation capacity discussed above for the Marcellus segment. The Utica segment net operating margin during the three months ended September 30, 2013 was approximately $1.2 million lower than it would have been if all NGLs produced could have been fractionated.

Northeast

	Three months ended September 30,
	2013		2012		$ Change		% Change
	(in thousands)
Segment revenue	$	48,829	$	39,987	$	8,842	22	%
Purchased product costs	15,330		11,054		4,276		39	%
Net operating margin	33,499		28,933		4,566		16	%
Facility expenses	7,359		6,267		1,092		17	%
Operating income before items not allocated to segments	$	26,140	$	22,666	$	3,474	15	%

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Segment Revenue. Revenue increased due to an increase in keep-whole NGLs sold from inventory and NGLs sold under percent-of-proceed contracts.

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

Net Operating Margin. Net operating margin increased due to a 22% increase in keep-whole volumes of NGLs sold, partially offset by the decline in NGL prices and narrowing of the spread between NGL and natural gas prices as approximately 59% of the net operating margin was derived from commodity sensitive keep-whole contracts. The overall frac spread margins declined by approximately 11% as compared to the third quarter 2012.

Facility Expenses. Facility expenses increased due primarily to $0.5 million for a repair, as well as the timing of normal facility maintenance and repairs.

Southwest

	Three months ended September 30,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	247,885	$	199,394	$	48,491		24	%
Purchased product costs	139,347		92,112		47,235			51	%
Net operating margin	108,538		107,282		1,256			1	%
Facility expenses	32,559		28,870		3,689			13	%
Portion of operating income attributable to non-controlling interests	40		67		(27		)	(40	)%
Operating income before items not allocated to segments	$	75,939	$	78,345	$	(2,406	)	(3	)%

Segment Revenue. Revenues increased due to higher NGL sales, gas sales, hydrogen revenue and higher fee-based revenue. NGL sales increased approximately $30.2 million due to increased volumes in our Western Oklahoma and East Texas areas of 27% and 16%, respectively. Gas sales increased approximately $10.0 million in areas where we are operating in varying degrees of ethane rejection, whereby ethane was sold in the gas stream due to the higher gas prices. Processing fee revenue increased by approximately $5.6 million due to an increase in volumes in Western Oklahoma, East Texas, and Southeast Oklahoma. Hydrogen revenue increased in our Javelina facility by $2.0 million due to a 24.9% price increase.

Purchased Product Costs. Purchased product costs increased due to higher NGL purchases of approximately $24.4 million related to the East Texas area increasing volumes processed, and approximately $23.0 million in Western Oklahoma and Southeast Oklahoma areas due to changes in contract mix from keep-whole contracts to fee-based contracts or other arrangements in which NGLs are purchased from producer customers and are sold.

Net Operating Margin. Net operating margin as a percentage of sales decreased significantly due to the change in contract mix noted above, partially offset by slightly higher NGL prices. Approximately 49% of the net operating margin is derived from commodity sensitive percent-of-proceeds and keep-whole arrangements.

Facility Expenses. Facility expenses increased due primarily to approximately $2.4 million for rebuilding three inlet compressors at our Javelina facilities and the additional expenses related to the operation of the Carthage East plant that began in November of 2012, partially offset by a lower number of compressor units in Western Oklahoma and Southeast Oklahoma.

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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, 2013 and 2012, respectively. The ensuing items listed below the Total segment revenue and Operating income before items not allocated to segments lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Three months ended September 30,
	2013			2012			$ Change			% Change
	(in thousands)
Total segment revenue	$	452,377		$	318,233		$	134,144		42	%
Derivative loss not allocated to segments	(30,318		)	(36,400		)	6,082			(17	)%
Revenue deferral adjustment and other	(1,543		)	(1,257		)	(286		)	23	%
Total revenue	$	420,516		$	280,576		$	139,940		50	%

Operating income before items not allocated to segments	$	181,867		$	144,046		$	37,821		26	%
Portion of operating loss attributable to non-controlling interests	(559		)	(560		)	1			(0	)%
Derivative loss not allocated to segments	(52,884		)	(52,071		)	(813		)	2	%
Revenue deferral adjustment and other	(1,543		)	(1,257		)	(286		)	23	%
Compensation expense included in facility expenses not allocated to segments	(833		)	(193		)	(640		)	332	%
Facility expenses adjustments	2,688			2,688			—			0	%
Selling, general and administrative expenses	(26,647		)	(21,723		)	(4,924		)	23	%
Depreciation	(76,323		)	(46,554		)	(29,769		)	64	%
Amortization of intangible assets	(16,003		)	(14,988		)	(1,015		)	7	%
Loss on disposal of property, plant and equipment	(1,840		)	(655		)	(1,185		)	181	%
Accretion of asset retirement obligations	(160		)	(140		)	(20		)	14	%
Income from operations	7,763			8,593			(830		)	(10	)%
Earnings from unconsolidated affiliates	896			706			190			27	%
Interest income	27			64			(37		)	(58	)%
Interest expense	(38,889		)	(30,621		)	(8,268		)	27	%
Amortization of deferred financing costs and discount (a component of interest expense)	(1,584		)	(1,428		)	(156		)	11	%
Miscellaneous income, net	1,504			1			1,503			>100	%
Loss before provision for income tax	$	(30,283	)	$	(22,685	)	$	(7,598	)	33	%

Derivative (Loss) Gain Not Allocated to Segments. Unrealized loss from the change in fair value of our derivative instruments was $47.5 million for the three months ended September 30, 2013 compared to an unrealized loss of $43.7 million for the same period in 2012. Realized loss from the settlement of our derivative instruments was $5.3 million for the three months ended September 30, 2013 compared to a realized loss of $8.4 million for the same period in 2012. The total change of $0.8 million is due primarily to volatility in commodity prices.

Revenue Deferral Adjustment and Other. Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended September 30, 2013, approximately $0.2 million and $1.5 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the three months ended September 30, 2012, approximately $0.2 million and $1.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Based on current commodity prices, management expects the deferred revenue in subsequent periods to approximate the first quarter 2013 amount until the beginning of 2015 when the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes. Other consists of management fee revenues from an unconsolidated affiliate of $0.2 million for the three months ended September 30, 2013 compared to $0.3 million for the three months ended September 30, 2012.

Selling, general and administration expenses. Selling, general and administration expense has increased to support the continued growth in our operations.

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

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

(Loss) on Disposal of Property, Plant and Equipment. Loss on disposal of property, plant and equipment relates primarily to the disposal of a portion of the Marcellus NGL pipeline that was damaged in connection with the Wetzel County Landslides.

Interest Expense. Interest expense increased due to the increased amount of outstanding debt, offset by the decrease in average interest rate from our new debt.

Nine months ended September 30, 2013 compared to nine months ended September 30, 2012

Marcellus

	Nine months ended September 30,
	2013		2012		$ Change		% Change
	(in thousands)
Segment revenue	$	375,844	$	213,761	$	162,083	76	%
Purchased product costs	72,781		48,856		23,925		49	%
Net operating margin	303,063		164,905		138,158		84	%
Facility expenses	74,529		44,544		29,985		67	%
Operating income before items not allocated to segments	$	228,534	$	120,361	$	108,173	90	%

Segment Revenue. Revenue increased due to ongoing expansion of the Marcellus segment operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $110.0 million related to gathering, processing and fractionation fees, of which approximately $50.0 million is due to our Keystone Acquisition and the opening of the Sherwood and Mobley Complexes and the remaining increase in fees relates to increased volumes at our Houston and Majorsville facilities. Revenue also increased approximately $47.2 million related to NGL sales under percent of proceeds arrangements due to increased volumes or inventory sales. These revenue increases were partially offset by several operational constraints discussed further in the Net Operating Margin section below. Also, approximately $4.8 million of revenues for the nine months ended September 30, 2013 relate to Sherwood gathering, which will not reoccur as the Sherwood Asset Sale was completed in the second quarter of 2013.

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

Net Operating Margin. Net operating margin increased as the volume of natural gas gathered, processed, and fractionated increased by 65%, 136% and 115%, respectively. Approximately 80% of the net operating margin is earned under fee-based contracts and was not significantly impacted by the lower commodity prices for the nine months ended September 30, 2013 compared to the same period in 2012. Certain temporary operational constraints during the third quarter 2013 prevented us from realizing the full economic benefit of the significant growth in our producer customers’ volumes. Due to these constraints that are outlined below, our net operating margin was approximately $9.4 million lower than expected.

Facility Expenses. Facility expenses increased due to the ongoing expansion of the Marcellus segment operations, additional expenses of approximately $2.0 million, net of insurance recoveries, related to the Wetzel County Landslides and additional expenses caused by the limitations in fractionation capacity discussed above under net operating margin.

Utica

	Nine months ended September 30,
	2013			2012			$ Change			% Change
	(in thousands)
Segment revenue	$	12,590		$	145		$	12,445		8,583	%
Purchased product costs	—			—			—			N/A
Net operating margin	12,590			145			12,445			8,583	%
Facility expenses	20,232			1,591			18,641			1,172	%
Portion of operating loss attributable to non-controlling interests	(3,081		)	(740		)	(2,341		)	316	%
Operating loss before items not allocated to segments	$	(4,561	)	$	(706	)	$	(3,855	)	546	%

The results of operations for the nine months ended September 30, 2013 include our operations in Utica Shale areas of eastern Ohio. Facility expenses include start-up costs and other costs that cannot be capitalized including approximately $4.6 million of amortization of costs to install temporary compression and treating facilities. Operations are expected to continue to grow

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significantly as we add 800 MMcf/d cryogenic capacity through the end of 2014. During the third quarter of 2013, the Utica segment net operating margin was similarly affected by the limitations of fractionation capacity discussed above for the Marcellus segment. The Utica segment net operating margin during the nine months ended September 30, 2013 was approximately $1.2 million lower than it would have been if all NGLs produced could have been fractionated.

Northeast

	Nine months ended September 30,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	151,530	$	168,956	$	(17,426	)	(10	)%
Purchased product costs	50,118		49,662		456			1	%
Net operating margin	101,412		119,294		(17,882		)	(15	)%
Facility expenses	20,538		17,577		2,961			17	%
Operating income before items not allocated to segments	$	80,874	$	101,717	$	(20,843	)	(20	)%

Segment Revenue. Revenue decreased primarily due to lower NGL prices and a 3% decrease in NGL sales volumes. The decrease in NGL sales volumes is primarily due to lower sales from inventory.

Purchased Product Costs. Purchased product costs increased due to higher prices for natural gas that is purchased to satisfy the keep-whole arrangements, partially offset by 4% lower keep-whole sales volumes.

Net Operating Margin. Net operating margin decreased due to the decline in NGL prices and narrowing of the spread between NGL and natural gas prices as approximately 61% of the net operating margin is derived from commodity sensitive keep-whole contracts. The overall frac spread margins declined by approximately 25% as compared to the nine months ended September 30, 2012, partially offset by improvement in margins in percent of proceeds contracts due to a contractual increase in the percentage retained beginning November 2012.

Facility Expenses. Facility expenses increased due primarily to a prior year adjustment of approximately $1.0 million related to a reduction in property taxes resulting from a favorable rate determination related to one of our facilities. The remaining increase was for a repair, as well as the timing of normal facility maintenance and repairs.

Southwest

	Nine months ended September 30,
	2013		2012		$ Change			% Change
	(in thousands)
Segment revenue	$	684,093	$	641,321	$	42,772		7	%
Purchased product costs	376,689		288,137		88,552			31	%
Net operating margin	307,404		353,184		(45,780		)	(13	)%
Facility expenses	91,027		92,964		(1,937		)	(2	)%
Portion of operating income attributable to non-controlling interests	157		98		59			60	%
Operating income before items not allocated to segments	$	216,220	$	260,122	$	(43,902	)	(17	)%

Segment Revenue. Revenues increased due to approximately $34.4 million higher gas sales and approximately $7.9 million higher hydrogen revenue. The increase in gas sales revenue is primarily caused by higher prices and operating in ethane rejection in certain areas. Hydrogen revenue increased in our Javelina facility due to a 43.1% price increase. Processing fees increased approximately $15.5 million related to increases in East Texas related to the new Carthage east plant and change in contract mix, which resulted in more volumes processed under fee-based arrangements. NGL sales revenue decreased by approximately $7.2 million related to lower prices, operating in ethane rejection whereby ethane was sold in the gas stream, reduced volumes of condensate sales, and a change in contract mix. Approximately $8 million of the decline in NGL sales was caused by a planned shutdown of one customer’s refinery operations from mid-January through mid-March in our Javelina area. At the end of March 2013, this refinery customer had returned to normal operations. This decline in NGL revenues was partially offset by an increase in NGL sales in East Texas due to the start-up of Carthage east plant in November 2012.

Purchased Product Costs. Purchased product costs increased due to increases of approximately $82.0 million in higher NGL purchases, which consisted of approximately $26.0 million in Southeast Oklahoma, approximately $35.1 million in East Texas, and approximately $20.9 million in Western Oklahoma. NGL purchases increased despite a decrease in NGL sales due to a shift in contract mix, which resulted in less volumes processed under keep-whole contracts and more volumes processed under fee-based or

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other arrangements in which NGLs are purchased from producer customers and resold. The remainder of the increase is due to gas purchases of approximately $17.5 million primarily due to higher gas prices.

Net Operating Margin. Net operating margin decreased as a percentage of revenue due to the change in contract mix discussed above. The decrease in net operating margin was partially offset by an approximately 16% increase in the volume of natural gas processed primarily due to producers increased production in the rich gas areas of the Haynesville Shale, Woodford Shale, and Cotton Valley formations.

Facility Expenses. Facility expenses decreased by approximately $4.4 million due to a lower number of leased compressor units and approximately $1.1 million of overall timing of normal facility maintenance and repairs, offset by approximately $2.4 million increase for rebuilding three inlet compressors at our Javelina facilities and approximately $1.5 million of expense for the Carthage East plant which opened in November 2012.

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

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income (loss) before provision for income tax for the nine months ended September 30, 2013 and 2012, respectively. The ensuing items listed below the Total segment revenue and Operating income before items not allocated to segments lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Nine months ended September 30,
	2013			2012			$ Change			% Change
	(in thousands)
Total segment revenue	$	1,224,057		$	1,024,183		$	199,874		20	%
Derivative (loss) gain not allocated to segments	(10,804		)	50,952			(61,756		)	(121	)%
Revenue deferral adjustment and other	(4,344		)	(4,474		)	130			(3	)%
Total revenue	$	1,208,909		$	1,070,661		$	138,248		13	%

Operating income before items not allocated to segments	$	521,067		$	481,494		$	39,573		8	%
Portion of operating loss attributable to non-controlling interests	(2,924		)	(642		)	(2,282		)	355	%
Derivative (loss) gain not allocated to segments	(2,702		)	70,952			(73,654		)	(104	)%
Revenue deferral adjustment and other	(4,344		)	(4,474		)	130			(3	)%
Compensation expense included in facility expenses not allocated to segments	(1,587		)	(826		)	(761		)	92	%
Facility expenses adjustments	8,064			8,064			—			0	%
Selling, general and administrative expenses	(77,388		)	(68,471		)	(8,917		)	13	%
Depreciation	(215,902		)	(127,472		)	(88,430		)	69	%
Amortization of intangible assets	(47,925		)	(38,280		)	(9,645		)	25	%
Gain (loss) on disposal of property, plant and equipment	35,758			(2,983		)	38,741			(1,299	)%
Accretion of asset retirement obligations	(669		)	(536		)	(133		)	25	%
Income from operations	211,448			316,826			(105,378		)	(33	)%
Gain from unconsolidated affiliates	1,561			2,254			(693		)	(31	)%
Interest income	238			295			(57		)	(19	)%
Interest expense	(114,180		)	(86,855		)	(27,325		)	31	%
Amortization of deferred financing costs and discount (a component of interest expense)	(5,198		)	(3,943		)	(1,255		)	32	%
Loss on redemption of debt	(38,455		)	—			(38,455		)	N/A
Miscellaneous income, net	1,510			63			1,447			2,297	%
Income before provision for income tax	$	56,924		$	228,640		$	(171,716	)	(75	)%

Derivative (Loss) Gain Not Allocated to Segments. Unrealized loss from the change in fair value of our derivative instruments was $1.2 million for the nine months ended September 30, 2013 compared to an unrealized gain of $101.8 million for the same period in 2012. Realized loss from the settlement of our derivative instruments was $1.5 million for the nine months ended September 30, 2013 compared to a realized loss of $30.9 million for the same period in 2012. The total change of $73.7 million is due primarily to volatility in commodity prices.

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Operating Data

	Three months ended September 30,				Nine months ended September 30,
	2013	2012	% Change		2013	2012	% Change
Marcellus
Gathering system throughput(Mcf/d)	563,200	444,700	27	%	617,200	373,700	65	%
Natural gas processed (Mcf/d)	1,137,400	479,400	137	%	1,000,900	424,300	136	%
NGLs fractionated (Bbl/d)	48,200	22,300	116	%	44,500	20,700	115	%
NGL sales (gallons, in thousands) (1)	229,900	90,800	153	%	536,100	264,200	103	%

Utica (2)
Gathering system throughput (Mcf/d)	85,100	—	N/A		47,100	—	N/A
Natural gas processed (Mcf/d)	131,100	—	N/A		62,200	—	N/A

Northeast
Natural gas processed (Mcf/d)	297,800	318,500	(6	)%	298,900	322,800	(7	)%
NGLs fractionated (Bbl/d)	21,500	16,500	30	%	18,900	16,800	13	%

Keep-whole sales (gallons, in thousands)	28,200	23,200	22	%	92,600	96,500	(4	)%
Percent-of-proceeds sales (gallons, in thousands)	34,700	33,700	3	%	101,800	103,500	(2	)%
Total NGL sales (gallons, in thousands)(3)	62,900	56,900	11	%	194,400	200,000	(3	)%

Crude oil transported for a fee (Bbl/d)	9,400	8,700	8	%	9,800	9,100	8	%

Southwest
East Texas gathering systems throughput (Mcf/d)	494,300	471,200	5	%	505,000	440,700	15	%
East Texas natural gas processed (Mcf/d)	345,400	270,200	28	%	354,200	260,400	36	%
East Texas NGL sales (gallons, in thousands)(4)	78,500	67,800	16	%	249,300	199,300	25	%

Western Oklahoma gathering system throughput (Mcf/d) (5)	262,000	227,900	15	%	228,400	247,300	(8	)%
Western Oklahoma natural gas processed (Mcf/d)	218,500	209,600	4	%	198,400	210,800	(6	)%
Western Oklahoma NGL sales (gallons, in thousands)	64,400	50,900	27	%	162,200	169,900	(5	)%

Southeast Oklahoma gathering systems throughput (Mcf/d)	444,200	484,400	(8	)%	459,500	496,200	(7	)%
Southeast Oklahoma natural gas processed (Mcf/d)(6)	156,700	128,600	22	%	156,100	116,700	34	%
Southeast Oklahoma NGL sales (gallons, in thousands)	44,000	46,700	(6	)%	137,300	121,000	13	%

Other Southwest gathering system throughput (Mcf/d) (7)	33,000	23,600	40	%	31,200	25,000	25	%

Gulf Coast refinery off-gas processed (Mcf/d)	117,100	123,800	(5	)%	110,100	120,000	(8	)%
Gulf Coast liquids fractionated (Bbl/d)	21,400	23,800	(10	)%	20,300	23,000	(12	)%
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands)	82,800	92,100	(10	)%	232,500	264,400	(12	)%

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

(2) Utica operations began in August 2012.

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(3) Represents sales at the Siloam fractionator. The total sales exclude approximately 21,000,000 gallons, 595,000 gallons, 27,900,000 gallons, and 975,000 gallons sold by the Northeast on behalf of Marcellus for the three months and nine months ended September 30, 2013 and 2012, respectively. These volumes are included as part of NGLs sold at Marcellus.

(4) Includes approximately 1,390,000 gallons and 13,700,000 gallons processed in conjunction with take in kind contracts for the three and nine months ended September 30, 2013, respectively.

(5) 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.

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

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

Liquidity and Capital Resources

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

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

	2013 Full Year Plan						Actual
	Low			High			Nine months ended September 30, 2013
Consolidated growth capital(1)	$	2,717		$	3,017		$	2,164
Utica joint venture partner’s estimated share of growth capital	(717		)	(717		)	(717		)
Partnership share of growth capital	$	2,000		$	2,300		$	1,447

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

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

Management believes that expenditures for our capital projects can be funded with current cash balances, proceeds from equity or debt offerings, contributions from joint venture partners, cash flows from operations and our current borrowing capacity under the Credit Facility. Our access to capital markets can be impacted by factors outside our control, which include but are not limited to general economic conditions and the rights of our Class B unitholders to participate in any future equity offerings we may commence after July 1, 2013; however, we believe that our strong cash flows and balance sheet, our Credit Facility and our credit rating will provide us with adequate access to the capital markets to fund our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings assigned by independent rating agencies. As of November 5, 2013, our credit ratings were Ba2 with a Stable outlook by Moody’s Investors Service, BB with a Stable outlook by Standard & Poor’s, and BB with a negative outlook by Fitch Ratings. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

Debt Financing Activities

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

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Under the provisions of the Credit Facility, we are subject to a number of restrictions and covenants. As of September 30, 2013, we were in compliance with all of our debt covenants and we expect to remain in compliance for at least the next twelve months. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of November 5, 2013, we had no borrowings outstanding and approximately $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $1,188.7 million of unused capacity, of which approximately $530 million was available for borrowing based on financial covenant requirements. Additionally, the full amount of unused capacity is available for borrowing on a short term basis to provide financial flexibility within a given fiscal quarter.

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

The Credit Facility limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. Under the Credit Facility, neither we nor the bank can require margin calls for outstanding derivative positions. As of November 5, 2013, all of our financial derivative positions are with members of the participating bank group and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to enter into derivative instruments without utilizing cash for margin calls or requiring the use of letters of credit. We believe the recent Dodd-Frank legislation will not change our ability to enter into derivatives without utilizing margin calls.

Equity Financing Activities

In November 2012, we announced the November 2012 ATM which allowed us from time to time, through the Manager, as our sales agent, to offer and sell common units representing limited partner interests in the Partnership having an aggregate offering price of up to $600 million. Sales of such common units were made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed upon by us and the Manager. We could also sell common units to the Manager as principal for its own account at a price to be agreed upon at the time of such sale. For any such sales, we would enter into a separate agreement with the Manager. In the nine months ended September 30, 2013, we sold an aggregate of 9.3 million common units under the November 2012 ATM, receiving net proceeds of approximately $584.3 million after deducting $9.4 million in manager fees and other third-party expenses. The proceeds from sales were used for general partnership purposes. We completed this $600 million program in July 2013.

On August 7, 2013, we and M&R MWE Liberty, LLC (the “Selling Unitholder”) entered into an Equity Distribution Agreement with the Manager that established a $400 million At the Market offering program (the “August 2013 ATM”). In addition, the Selling Unitholder was permitted to sell from time to time through the Manager up to 1,452,415 common units. During the nine months ended September 30, 2013, the Partnership sold an aggregate of 5.9 million common units under the August 2013 ATM, receiving net proceeds of approximately $396.0 million after deducting approximately $4.0 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general partnership purposes. During the nine months ended September 30, 2013, the Selling Unitholder sold an aggregate of 657,654 of their common units under the August 2013 ATM program, receiving net proceeds of approximately $44.0 million after deducting approximately $0.4 million in manager fees. We completed this $400 million program in August 2013.

On September 5, 2013, we and the Selling Unitholder entered into an Equity Distribution Agreement with the Manager that established an At the Market offering program (the “September 2013 ATM”) pursuant to which we may sell from time to time through the Manager as its sales agent, Common Units having an aggregate offering price of up to $1 billion. In addition, the Selling Unitholder may sell from time to time through the Manager up to 794,761 common units. During the nine months ended September 30, 2013, we sold an aggregate of 0.9 million common units under the September 2013 ATM, receiving net proceeds of approximately $59.5 million after deducting approximately $0.6 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general partnership purposes. During the nine months ended September 30, 2013, the Selling Unitholder sold an aggregate of 45,400 of their common units under the September 2013 ATM Agreement, receiving net proceeds of approximately $3.1 million after deducting less than $0.1 million in manager fees. At September 30, 2013, the Selling Unitholder has 749,361 vested and unsold units.

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Utica Shale Joint Venture

As discussed in Note 3 of these Condensed Consolidated Financial Statements, we and EMG Utica entered into the Amended Utica LLC Agreement for MarkWest Utica EMG which replaced the original agreement discussed in Note 4 in the Notes to the Consolidated Financial Statements included in Item 8 of our Annual Report on Form 10-K. Pursuant to the Amended Utica LLC Agreement, the aggregate funding commitment of EMG Utica has increased from $500 million to $950 million. EMG Utica completed its funding commitment in May 2013 and we began funding MarkWest Utica EMG in July 2013.

Liquidity Risks and Uncertainties

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

We execute a risk management strategy to mitigate our exposure to downward fluctuations in commodity prices. We use derivative financial instruments relating to the future price of NGLs and crude oil to mitigate our exposure to NGL price risk.

Cash Flow

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

	Nine months ended September 30,
	2013			2012			Change
Net cash provided by operating activities	$	330,659		$	385,784		$	(55,125	)
Net cash used in investing activities	(2,186,307		)	(1,745,749		)	(440,558		)
Net cash provided by financing activities	1,838,045			1,657,986			180,059

Net cash provided by operating activities decreased primarily due to an approximately $87.5 million change in working capital, primarily due to a $69.7 million decrease related to the timing of collections of receivables compared to 2012 and $18.5 million due to an increase in inventories in 2013 compared to a decrease in 2012 due to timing of inventory sales.

Net cash used in investing activities decreased due to a $937.0 million increase in capital expenditures, primarily related to our expansion of our Marcellus and Utica segments as discussed in our Segment Reporting section above, offset by proceeds of $208.1 million, net of cash paid for third party transaction fees primarily from our Sherwood Asset Sale and a decrease in business acquisition purchases of $281.6 million compared to the same period in 2012.

Net cash provided by financing activities increased primarily due to a $629.1 million increase in contributions from non-controlling interest holders, partially offset by a $209.1 million decrease in net borrowings, a $151.2 million decrease in proceeds from public equity offerings and by an $89.8 million increase in distributions to unit holders.

Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of September 30, 2013, our purchase obligations were $906.0 million compared to our obligations of $664.8 million as of December 31, 2012. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

In the first quarter of 2013, we completed a public debt offering of $1 billion in aggregate principal amount of 4.5% senior unsecured notes due in 2023. A portion of the proceeds, together with cash on hand, was used to repurchase $81.1 million aggregate principal amount of our 8.75% senior notes due April 2018, $175 million of outstanding principal amount of our 6.5% senior notes due August 2021 and $245 million of outstanding principal amount of our 6.25% senior notes due September 2022.

Critical Accounting Policies

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

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

There have not been any material changes during the three months ended September 30, 2013 to the methodology applied by management for critical accounting policies previously disclosed in Item 7. Management’s Discussion and Analysis of Financial

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Condition and Results of Operations—Critical Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2012.

Recent Accounting Pronouncements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

The information about commodity price risk for the three months ended September 30, 2013 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2012.

Outstanding Derivative Contracts

The following table provides information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at September 30, 2013, including the weighted average prices (“WAVG”):

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2013	1,837	$	83.07	$	102.82	$	(425	)
2014	1,418	90.36		108.73		1,335

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2013	2,407	$	92.82	$	(1,924	)
2014	697	92.39		(675		)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2013	1,010	$	5.26	$	(174	)

Propane Collars	Volumes (Gal/d)	WAVG Floor (Per Gal)		WAVG Cap (Per Gal)		Fair Value (in thousands)
2013	120,473	$	0.80	$	0.97	$	(1,113	)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	5,322	$	0.93	$	(67	)
2014	103,309	0.91		(3,244		)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	21,185	$	1.66	$	498
2014	12,211	1.47		734

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	24,425	$	1.54	$	359
2014	15,265	1.43		909

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	13,712	$	1.98	$	(124	)
2014 (Jan – Mar)	7,249	1.91		(89		)

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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, 2013, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2013(1)	—	NA		$	840
2014	154	$	90.05	(294		)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2013	9,687	$	5.44	$	(1,656	)
2014	8,733	4.93		(3,771		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	165,048	$	1.03	$	(560	)
2014	74,189	1.10		2,339

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	8,739	$	1.67	$	210
2014	7,516	1.45		413

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	23,985	$	1.54	$	351
2014	20,411	1.39		952

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	16,189	$	2.07	$	(9	)
2014	7,106	2.32		864

Propane Fixed Physical	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	6,793	$	1.09	$	15
2014 (Jan-Mar)	9,222	1.10		41

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, 2013, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2013	649	$	87.56	$	105.48	$	(52	)

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2014	358	$	91.85	$	(445	)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2013	72,826	$	0.91	$	(1,034	)
2014 (Jan – Mar)	36,280	0.90		(536		)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	3,565	$	1.63	$	427

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	8,440	$	1.50	$	751

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

The following table provides information on the derivative positions related to long liquids and keep-whole price risk that we have entered into subsequent to September 30, 2013, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)
2015	1,000	$	89.49

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2014	11,633	$	1.03

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2014	4,790	$	1.39

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2014	19,737	$	1.34

The following tables provide information on the derivative positions of MarkWest Liberty Midstream related to long liquids price risk that we have entered into subsequent to September 30, 2013, including the WAVG:

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)

2014	21,000	$	1.03

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)

2014	882	$	1.29

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)

2014	2,058	$	1.25

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)

2014	8,400	$	2.00

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, 2013, the estimated fair value of this contract was a liability of $82.0 million and the recorded value was a liability of $28.5 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception on February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of September 30, 2013 (in thousands):

Fair value of commodity contract	$	81,957
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of September 30, 2013	$	28,450

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, 2013, the estimated fair value of this contract was an asset of $3.3 million.

Interest Rate Risk

The information about interest rate risk for the nine months ended September 30, 2013 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2012.

Credit Risk

The information about our credit risk for the nine months ended September 30, 2013 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2012.

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	December 31, 2012						December 31, 2011
Balance Sheets	As previously reported			As restated			As previously reported			As restated
Cash and cash equivalents	$	347,899		$	345,756		$	117,016		$	114,332
Receivables, net	198,769			197,977			226,561			225,001
Other current assets	35,053			34,871			11,748			11,578
Total current assets	656,639			653,522			446,107			441,693

Property, plant and equipment	5,700,176			5,542,316			3,302,369			3,145,561
Less: accumulated depreciation	(624,548		)	(602,698		)	(438,062		)	(422,512		)
Total property, plant and equipment, net	5,075,628			4,939,618			2,864,307			2,723,049

Investment in unconsolidated affiliate	31,179			63,054			27,853			63,076
Other long-term assets	2,242			2,140			1,595			1,493
Total assets	6,835,716			6,728,362			4,070,425			3,959,874

Accounts payable	320,645			320,627			179,871			179,775
Accrued liabilities	391,352			390,178			171,451			170,307
Total current liabilities	739,226			738,034			441,873			440,633

Deferred income taxes	191,318			189,428			93,664			91,250
Other long-term liabilities	134,340			134,261			121,356			121,283

Common Units	2,134,714			2,097,404			679,309			642,522
Non-controlling interest in consolidated subsidiaries	328,346			261,463			70,227			189

Total equity	3,215,591			3,111,398			1,502,067			1,395,242
Total liabilities and equity	$	6,835,716		$	6,728,362		$	4,070,425		$	3,959,874

	Year Ended December 31, 2012				Year Ended December 31, 2011						Year Ended December 31, 2010
Statement of Operations	As previously reported		As restated		As previously reported			As restated			As previously reported			As restated
Revenue	$	1,395,231	$	1,383,279	$	1,534,434		$	1,522,592		$	1,241,563		$	1,226,789
Total revenue	1,451,766		1,439,814		1,505,399			1,493,557			1,187,631			1,172,857

Facility expenses	208,385		206,861		173,598			171,497			151,449			148,416
Selling, general and administrative expenses	94,116		93,444		81,229			80,441			75,258			74,558
Depreciation	189,549		183,250		149,954			143,704			123,198			116,949
Accretion of asset retirement obligations	677		672		1,190			1,185			237			240
Total operating expenses	1,070,038		1,061,538		1,187,235			1,178,091			999,169			989,190

Income (loss) from operations	381,728		378,276		318,164			315,466			188,462			183,667
Earnings (loss) from unconsolidated affiliates	699		2,328		(1,095		)	158			1,562			3,823
Income (loss) before provision for income tax	257,116		255,293		119,894			118,449			34,291			31,757

Net income (loss)	218,788		216,965		106,245			104,800			31,102			28,568
Net loss (income) attributable to non-controlling interest	1,614		3,437		(45,550		)	(44,105		)	(30,635		)	(28,101		)

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	Year Ended December 31, 2012						Year Ended December 31, 2011						Year Ended December 31, 2010
	As previously reported			As restated			As previously reported			As restated			As previously reported			As restated
Cash flows from operating activities:
Net income	$	218,788		$	216,965		$	106,245		$	104,800		$	31,102		$	28,568
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	189,549			183,250			149,954			143,704			123,198			116,949
Accretion of asset retirement obligations	677			672			1,190			1,185			237			237
Equity in (earnings) loss of unconsolidated affiliate	(699		)	(2,328		)	1,095			(158		)	(1,562		)	(3,823		)
Distributions from unconsolidated affiliate	2,600			8,416			300			4,382			2,508			8,448
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	32,588			31,993			(45,463		)	(45,107		)	(37,090		)	(36,924		)
Other current assets	(23,115		)	(23,285		)	(3,728		)	(3,557		)	2,654			2,654
Accounts payable and accrued liabilities	28,412			28,417			54,745			54,795			45,361			44,088
Other long-term assets	(647		)	(647		)	(307		)	(308		)	174			174
Net cash provided by operating activities	496,713			492,013			414,698			410,403			312,328			306,117

Cash flows from investing activities:
Capital expenditures	(1,951,427		)	(1,950,324		)	(551,281		)	(550,839		)	(458,668		)	(457,468		)
Investment in unconsolidated affiliate	(5,227		)	(6,066		)	—			—			—			—
Proceeds from disposal of property, plant and equipment	596			596			3,450			3,450			733			665
Net cash flows used in investing activities	(2,472,352		)	(2,472,088		)	(776,553		)	(776,111		)	(485,936		)	(484,804		)

Cash flows from financing activities:
Contributions from non-controlling interest	265,620			264,781			126,392			126,392			158,293			158,293
Payment of distributions to non-controlling interest	(5,887		)	(71		)	(66,887		)	(62,805		)	(6,150		)	(210		)
Net cash flows provided by financing activities	2,206,522			2,211,499			411,421			415,503			143,306			149,246

Net increase in cash and cash equivalents	230,883			231,424			49,566			49,795			(30,302		)	(29,441		)
Cash and cash equivalents at beginning of year	117,016			114,332			67,450			64,537			97,752			93,978
Cash and cash equivalents at end of period	347,899			345,756			117,016			114,332			67,450			64,537

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	Common Units						Non-controlling Interest						Total Equity
Statement of Changes in Equity	As previously reported			As restated			As previously reported			As restated			As previously reported			As restated

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

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

The unaudited interim financial information presented in our Condensed Consolidated Financial Statements included in Item 1 of our Form 10-Q for the quarter-ended March 31, 2013 will not be amended due to our assessment of materiality. The unaudited interim financial information presented in our Condensed Consolidated Financial Statements included in Item 1 of our Form 10-Q for the quarters-ended June 30, 2013 and September 30, 2013 reflect these changes.

Retrospective Accounting Change

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

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

	Assets							Liabilities
As of December 31, 2011	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount

Current
Commodity contracts	$	5,183	$	(4,073	)	$	1,110	$	(75,264	)	$	4,073	$	(71,191	)
Embedded derivatives in commodity contracts	3,515		—			3,515		(15,287		)	—		(15,287		)
Total current derivative instruments	8,698		(4,073		)	4,625		(90,551		)	4,073		(86,478		)

Non-current
Commodity contracts	12,090		(6,315		)	5,775		(19,269		)	6,315		(12,954		)
Embedded derivatives in commodity contracts	4,002		—			4,002		(46,134		)	—		(46,134		)
Total non-current derivative instruments	16,092		(6,315		)	9,777		(65,403		)	6,315		(59,088		)

Total derivative instruments	$	24,790	$	(10,388	)	$	14,402	$	(155,954	)	$	10,388	$	(145,566	)

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

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Refer to Note 12 of the accompanying Notes to the Condensed Consolidated Financial Statements for all other information regarding legal proceedings.

Table of Contents

Item 1A. Risk Factors

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

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

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

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

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

· more stringent permitting and other regulatory requirements;

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

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

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

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

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

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

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

· availability of sufficient terminaling facilities in the United States;

· availability of sufficient rail car and tanker capacity;

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

Large accelerated filer x		Accelerated filer o

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

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

PART I—FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
	Unaudited Condensed Consolidated Balance Sheets at September 30, 2013 and December 31, 2012	4
	Unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2013 and 2012	5
	Unaudited Condensed Consolidated Statements of Changes in Equity for the nine months ended September 30, 2013 and 2012	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2013 and 2012	7
	Unaudited Notes to the Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 4.	Controls and Procedures	55
Item 5.	Other Information	55
PART II—OTHER INFORMATION		59
Item 1.	Legal Proceedings	59
Item 1A.	Risk Factors	60
Item 6.	Exhibits	62
SIGNATURES		63

10.1		Equity Distribution Agreement dated August 7, 2013 among MarkWest Energy Partners, L.P., MarkWest Energy Operating Company, L.L.C., M&R MWE Liberty, LLC and Citigroup Global Markets Inc. (incorporated by reference to the Form 8-K Current Report filed August 7, 2013).

10.2		Equity Distribution Agreement dated September 5, 2013 among MarkWest Energy Partners, L.P., MarkWest Energy Operating Company, L.L.C., M&R MWE Liberty, LLC and Citigroup Global Markets Inc. (incorporated by reference to the Form 8-K Current Report filed September 5, 2013).

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, 2013, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Statements of Changes in Equity, and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

	MarkWest Energy Partners, L.P.
	(Registrant)

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

Date: November 12, 2013		/s/ FRANK M. SEMPLE
		Frank M. Semple
		Chairman, President & Chief Executive Officer
		(Principal Executive Officer)


Date: November 12, 2013		/s/ NANCY K. BUESE
		Nancy K. Buese
		Executive Vice President & Chief Financial Officer
		(Principal Financial Officer)


Date: November 12, 2013		/s/ PAULA L. ROSSON
		Paula L. Rosson
		Vice President & Chief Accounting Officer
		(Principal Accounting Officer)