MARKWEST ENERGY PARTNERS L P - FORM 10-Q

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2014

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

For the transition period from to

Commission File Number 001-31239

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices)

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

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

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

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

Large accelerated filer x		Accelerated filer o

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

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

As of July 30, 2014, the number of the registrant’s common units and Class B units outstanding were 177,021,464 and 11,972,634, respectively.

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PART I—FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
	Unaudited Condensed Consolidated Balance Sheets at June 30, 2014 and December 31, 2013	4
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014 and 2013	5
	Unaudited Condensed Consolidated Statements of Changes in Equity for the six months ended June 30, 2014 and 2013	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	7
	Unaudited Notes to the Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	55
Item 4.	Controls and Procedures	58
PART II—OTHER INFORMATION		59
Item 1.	Legal Proceedings	59
Item 1A.	Risk Factors	59
Item 6.	Exhibits	60
SIGNATURES		61

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

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Glossary of Terms

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

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Balance Sheets

(unaudited, in thousands)

	June 30, 2014			December 31, 2013
ASSETS
Current assets:
Cash and cash equivalents ($225,020 and $4,114, respectively)	$	299,412		$	85,305
Restricted cash	10,000			10,000
Receivables, net ($6,678 and $5,346, respectively)	306,101			299,107
Receivables from unconsolidated affiliates, net ($10,334 and $0, respectively)	13,977			—
Inventories ($6,838 and $2,553, respectively)	62,735			41,363
Fair value of derivative instruments	5,935			11,457
Deferred income taxes	13,575			23,200
Other current assets ($4,475 and $5,527, respectively)	34,700			44,068
Total current assets	746,435			514,500

Property, plant and equipment ($1,115,941 and $1,655,789, respectively)	8,798,039			8,583,767
Less: accumulated depreciation ($35,192 and $33,583, respectively)	(1,061,151		)	(890,598		)
Total property, plant and equipment, net	7,736,888			7,693,169

Other long-term assets:
Restricted cash	10,000			10,000
Investment in unconsolidated affiliates ($558,603 and $0, respectively)	629,927			75,627
Intangibles, net of accumulated amortization of $317,377 and $285,732, respectively	842,227			874,792
Goodwill	144,856			144,856
Deferred financing costs, net of accumulated amortization of $28,220 and $25,083, respectively	49,841			52,132
Deferred contract cost, ($0 and $6,591, respectively), net of accumulated amortization of $3,042 and $2,886 ($0), respectively	20,208			26,955
Fair value of derivative instruments	—			505
Other long-term assets ($5 and $658, respectively)	3,008			3,887
Total assets	$	10,183,390		$	9,396,423

LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($26,094 and $82,007, respectively)	$	381,953		$	401,088
Accrued liabilities ($33,482 and $112,029, respectively)	338,588			437,847
Fair value of derivative instruments	21,930			28,838
Total current liabilities	742,471			867,773

Deferred income taxes	305,525			287,566
Fair value of derivative instruments	35,668			27,763
Long-term debt, net of discounts of $6,563 and $6,929, respectively	3,464,637			3,023,071
Other long-term liabilities	162,828			156,500

Commitments and contingencies (Note 11)
Redeemable non-controlling interest (Note 3)	70,711			235,617

Equity:
Common units (169,261 and 157,766 common units issued and outstanding, respectively)	3,913,993			3,476,295
Class B units (15,964 units issued and outstanding)	602,025			602,025
Non-controlling interest in consolidated subsidiaries	885,532			719,813
Total equity	5,401,550			4,798,133
Total liabilities and equity	$	10,183,390		$	9,396,423

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

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

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Operations

(unaudited, in thousands, except per unit amounts)

	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Revenue:
Revenue	$	525,119		$	395,421		$	1,041,562		$	768,879
Derivative (loss) gain	(6,753		)	19,699			(10,720		)	19,514
Total revenue	518,366			415,120			1,030,842			788,393

Operating expenses:
Purchased product costs	215,824			155,359			427,388			307,916
Derivative loss (gain) related to purchased product costs	11,964			(20,432		)	4,166			(31,136		)
Facility expenses	83,545			62,797			167,250			122,307
Derivative loss related to facility expenses	2,045			800			1,777			468
Selling, general and administrative expenses	27,701			25,499			62,991			50,741
Depreciation	104,078			71,562			206,007			139,579
Amortization of intangible assets	15,965			17,092			31,943			31,922
Loss (gain) on disposal of property, plant and equipment	1,450			(37,736		)	1,357			(37,598		)
Accretion of asset retirement obligations	168			157			336			509
Total operating expenses	462,740			275,098			903,215			584,708

Income from operations	55,626			140,022			127,627			203,685

Other income (expense):
Equity in (loss) earnings from unconsolidated affiliates	(721		)	430			(471		)	665
Interest income	10			62			19			211
Interest expense	(43,391		)	(36,955		)	(84,375		)	(75,291		)
Amortization of deferred financing costs and debt discount (a component of interest expense)	(1,449		)	(1,784		)	(4,273		)	(3,614		)
Loss on redemption of debt	—			—			—			(38,455		)
Miscellaneous income, net	33			6			43			6
Income before provision for income tax	10,108			101,781			38,570			87,207

Provision for income tax expense (benefit):
Current	(19		)	(2,745		)	326			(8,159		)
Deferred	(2,921		)	19,028			9,280			30,999
Total provision for income tax	(2,940		)	16,283			9,606			22,840

Net income	13,048			85,498			28,964			64,367

Net (income) loss attributable to non-controlling interest	(4,071		)	(1,799		)	(7,495		)	3,874
Net income attributable to the Partnership’s unitholders	$	8,977		$	83,699		$	21,469		$	68,241

Net income attributable to the Partnership’s common unitholders per common unit:
Basic	$	0.05		$	0.63		$	0.13		$	0.52
Diluted	$	0.05		$	0.55		$	0.12		$	0.45

Weighted average number of outstanding common units:
Basic	164,613			131,227			161,727			129,928
Diluted	181,237			151,866			178,378			150,580

Cash distribution declared per common unit	$	0.87		$	0.83		$	1.73		$	1.65

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

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MARKWEST ENERGY PARTNERS, L.P.

Condensed Consolidated Statements of Changes in Equity

(unaudited, in thousands)

	Common Units				Class B Units			Non- controlling						Redeemable Non- controlling Interest (Temporary
	Units	Amount			Units	Amount		Interest			Total Equity			Equity)
December 31, 2013	157,766	$	3,476,295		15,964	$	602,025	$	719,813		$	4,798,133		$	235,617
Issuance of units in public offerings, net of offering costs	11,284	711,837			—	—		—			711,837			—
Distributions paid	—	(278,316		)	—	—		(90		)	(278,406		)	—
Redeemable non-controlling interest classified as temporary equity	—	—			—	—		164,906			164,906			(164,906		)
Elimination of non-controlling interest from deconsolidation of a subsidiary	—	—			—	—		(6,592		)	(6,592		)	—
Share-based compensation activity	211	1,012			—	—		—			1,012			—
Deferred income tax impact from changes in equity	—	(18,304		)	—	—		—			(18,304		)	—
Net income	—	21,469			—	—		7,495			28,964			—
June 30, 2014	169,261	$	3,913,993		15,964	$	602,025	$	885,532		$	5,401,550		$	70,711

	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	5,720	348,352			—	—		—			348,352			—
Distributions paid	—	(214,903		)	—	—		(112		)	(215,015		)	—
Contributions from non-controlling interest	—	—			—	—		685,219			685,219			—
Redeemable non-controlling interest classified as temporary equity	—	—			—	—		(486,670		)	(486,670		)	486,670
Share-based compensation activity	161	2,092			—	—		—			2,092			—
Excess tax benefits related to share-based compensation	—	650			—	—		—			650			—
Deferred income tax impact from changes in equity	—	(28,077		)	—	—		—			(28,077		)	—
Net income (loss)	—	68,241			—	—		(3,874		)	64,367			—
June 30, 2013	133,375	$	2,273,759		19,954	$	752,531	$	456,026		$	3,482,316		$	486,670

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)

	Six months ended June 30,
	2014			2013
Cash flows from operating activities:
Net income	$	28,964		$	64,367
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation	206,007			139,579
Amortization of intangible assets	31,943			31,922
Loss on redemption of debt	—			38,455
Amortization of deferred financing costs and debt discount	4,273			3,614
Accretion of asset retirement obligations	336			509
Amortization of deferred contract cost	1,025			156
Phantom unit compensation expense	9,955			7,298
Equity in loss (earnings) from unconsolidated affiliates	471			(665		)
Distributions from unconsolidated affiliates	3,910			2,728
Unrealized loss (gain) on derivative instruments	7,024			(46,320		)
Loss (gain) on disposal of property, plant and equipment	1,357			(37,598		)
Deferred income taxes	9,280			30,999
Changes in operating assets and liabilities, net of deconsolidation:
Receivables	(32,291		)	(34,529		)
Receivables from unconsolidated affiliate	2,768			—
Inventories	(21,435		)	(11,828		)
Other current assets	7,434			607
Accounts payable and accrued liabilities	87,371			(7,462		)
Other long-term assets	761			(21,751		)
Other long-term liabilities	7,670			17,515
Net cash provided by operating activities	356,823			177,596

Cash flows from investing activities:
Restricted cash	—			25,500
Capital expenditures	(1,275,323		)	(1,435,084		)
Investment in unconsolidated affiliates	(76,054		)	(8,336		)
Proceeds from sale of equity interest in unconsolidated affiliate	324,657			—
Acquisition of business, net of cash acquired	—			(225,210		)
Proceeds from disposal of property, plant and equipment	21,562			208,109
Net cash flows used in investing activities	(1,005,158		)	(1,435,021		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	711,837			348,352
Proceeds from Credit Facility	1,923,500			—
Payments of Credit Facility	(1,482,300		)	—
Proceeds from long-term debt	—			1,000,000
Payments of long-term debt	—			(501,112		)
Payments of premiums on redemption of long-term debt	—			(31,516		)
Payments for debt issuance costs, deferred financing costs and registration costs	(2,045		)	(14,046		)
Contributions from non-controlling interest	—			685,219
Payments of SMR liability	(1,201		)	(1,103		)
Cash paid for taxes related to net settlement of share-based payment awards	(8,943		)	(5,206		)
Excess tax benefits related to share-based compensation	—			650
Payment of distributions to common unitholders	(278,316		)	(214,903		)
Payment of distributions to non-controlling interest	(90		)	(112		)
Net cash flows provided by financing activities	862,442			1,266,223

Net increase in cash and cash equivalents	214,107			8,798
Cash and cash equivalents at beginning of year	85,305			345,756
Cash and cash equivalents at end of period	$	299,412		$	354,554

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

1. Organization and Basis of Presentation

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

These unaudited condensed consolidated financial statements have been prepared in accordance with the rules and regulations of the SEC for interim financial reporting. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. These condensed consolidated financial statements should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. In management’s opinion, the Partnership has made all adjustments necessary for a fair presentation of its results of operations, financial position and cash flows for the periods shown. These adjustments are of a normal recurring nature. Finally, results for the six months ended June 30, 2014 are not necessarily indicative of results for the full year 2014 or any other future period.

The Partnership’s unaudited condensed consolidated financial statements include all majority-owned or controlled subsidiaries. In addition, MarkWest Utica EMG, L.L.C. (“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”), Ohio Gathering Company L.L.C. (“Ohio Gathering”) 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 April 2014, the FASB issued ASU 2014-08 — Presentation Of Financial Statements (Topic 205) And Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations And Disclosures Of Disposals Of Components Of An Entity (“ASU 2014-08”) that will supersede previous GAAP for accounting for discontinued operations. ASU 2014-08 raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. ASU 2014-08 is effective for the Partnership prospectively as of January 1, 2015; however the Partnership has elected to early adopt the guidance as of April 1, 2014. The adoption of the guidance did not have a material effect on the Partnership’s condensed consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09 — Revenue from Contracts with Customers (“ASU 2014-09”) that will supersede current revenue recognition guidance. ASU 2014-09 is intended to provide companies with a single comprehensive model to use for all revenue arising from contracts with customers, which would include real estate sales transactions. ASU 2014-09 is effective for the Partnership as of January 1, 2017 and must be adopted using either a full retrospective approach for all periods presented in the period of adoption (with some limited relief provided) or a modified retrospective approach. The Partnership is in the early stages of evaluating ASU 2014-09 and has not yet determined the impact on the Partnership’s condensed consolidated financial statements.

3. Variable Interest Entity

MarkWest Utica EMG

Effective January 1, 2012, the Partnership and EMG Utica, LLC (“EMG Utica”) (together the “Members”), executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in eastern Ohio.

In February 2013, the Members entered into the Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG (“Amended Utica LLC Agreement”) which replaced the original agreement. Pursuant to the Amended Utica LLC Agreement, the aggregate funding commitment of EMG Utica increased to $950.0 million (the “Minimum EMG Investment”). EMG Utica was required to fund all capital until the Minimum EMG Investment was satisfied, which occurred in May 2013. As EMG Utica has funded the Minimum EMG Investment, the Partnership is required to fund, as needed, 100% of future capital for MarkWest Utica EMG until such time as the aggregate capital that has been contributed by the Members equals $2.0 billion. After such time, and until such time as the investment balances of the Partnership and EMG Utica are in the ratio of 70% and 30%, respectively (such time being

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

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 their pro rata portion (based on the respective investment balances) of any additional required capital and may also fund additional capital that the other party elects not to fund. As of June 30, 2014, EMG Utica has contributed $950.0 million and the Partnership has contributed approximately $944.1 million to MarkWest Utica EMG.

Under the Amended Utica LLC Agreement, after EMG Utica has contributed more than $500.0 million to MarkWest Utica EMG and prior to December 31, 2016, EMG Utica’s investment balance will also be increased by a quarterly special non-cash allocation of income (“Preference Amount”) that is based upon the amount of capital contributed by EMG Utica in excess of $500.0 million. No Preference Amount will accrue to EMG Utica’s investment balance after December 31, 2016. EMG Utica received a special non-cash allocation of income of approximately $9.1 million and approximately $17.9 million for the three and six months ended June 30, 2014, 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 the Partnership to purchase membership interests from EMG Utica so that, following the purchase, the Partnership’s investment balance equals 51% of the aggregate investment balances of the Members. The purchase price payable would equal the investment balance associated with the membership interests acquired from EMG Utica. If EMG Utica makes this election, the Partnership would be required to purchase the membership interests on or before March 1, 2017, but effective as of January 1, 2017. The amount of non-controlling interest subject to the redemption option as of June 30, 2014 is reported as Redeemable non-controlling interest in the mezzanine equity section of the Partnership’s 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 of those dates, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Partnership and EMG Utica in proportion to their respective investment balances.

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

The assets of MarkWest Utica EMG are the property of MarkWest Utica EMG and are not available to the Partnership for any other purpose, including as collateral for its secured debt (see Notes 9 and 15). MarkWest Utica EMG’s asset balances can only be used to settle its own obligations. The liabilities of MarkWest Utica EMG do not represent additional claims against the Partnership’s general assets and the creditors or beneficial interest holders of MarkWest Utica EMG do not have recourse to the general credit of the Partnership. The Partnership’s maximum exposure to loss as a result of its involvement with MarkWest Utica EMG includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. Other than temporary funding due to the timing of the administrative process associated with capital calls in the beginning of 2013, the Partnership did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the six months ended June 30, 2014 and 2013.

Ohio Gathering

Ohio Gathering is a subsidiary of MarkWest Utica EMG and is engaged in providing natural gas gathering services in the Utica Shale in eastern Ohio. Prior to June 1, 2014, MarkWest Utica EMG, as the primary beneficiary of a VIE, consolidated Ohio Gathering. Effective June 1, 2014 (“Summit Investment Date”), Summit Midstream Partners (“Summit”) exercised its option (“Ohio Gathering Option”) and increased its equity ownership (“Summit Equity Ownership”) from less than 1% to approximately 40% through a cash investment of approximately $324.7 million that Ohio Gathering received on May 30, 2014 and a true-up payment of approximately $16.5 million that was contributed in July 2014. MarkWest Utica EMG received $319.6 million as a distribution from Ohio Gathering as a result of the exercise of the Ohio Gathering Option. Summit purchased its initial 1% equity interest and the Ohio Gathering Option from Blackhawk Midstream LLC (“Blackhawk”) in January 2014. As of the Summit Investment Date, MarkWest Utica EMG was no longer deemed the primary beneficiary due to Summit’s voting rights on significant operating matters obtained as a result of its increased equity ownership in Ohio Gathering. As of the Summit Investment Date, the Partnership accounted for Ohio

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Gathering as an equity method investment as the Partnership exercises significant influence. As of June 30, 2014, Ohio Gathering’s net assets are reported under the caption Investment in unconsolidated affiliates on the Condensed Consolidated Balance Sheet.

The Partnership accounted for the increase in Summit’s Equity Ownership and the deconsolidation of Ohio Gathering as a partial sale of in-substance real estate. In conjunction with Summit exercising the Ohio Gathering Option, Summit reimbursed MarkWest Utica EMG $5.0 million and an additional $0.3 million in July 2014 related to a reimbursement of certain costs incurred on behalf of Ohio Gathering and payable to the Partnership. The Partnership accounted for the cash received of $5.3 million as a (Gain) loss on disposal of property, plant and equipment in the Partnership’s Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2014.

For the three and six months ended June 30, 2014, the Partnership’s condensed consolidated results of operations include the consolidated results of operations of Ohio Gathering through May 31, 2014. For the month of June 2014, MarkWest Utica EMG has reported its pro rata share of Ohio Gathering’s net loss under the caption Equity in (loss) earnings of unconsolidated affiliate on the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014. Ohio Gathering is considered to be a related party. The Partnership receives engineering and construction and administrative management fee revenues (“Management Fees”) for operating Ohio Gathering. The June 30, 2014 receivable balance related to Ohio Gathering’s management and operational fees was $14.0 million and is reported as Receivables from unconsolidated affiliates, net in the current asset section of the Partnership’s Condensed Consolidated Balance Sheets. The amount of Management Fees revenue related to Ohio Gathering for the three and six months ended June 30, 2014 was approximately $1.0 million and is reported as Revenue in the Condensed Consolidated Statement of Operations.

4. Other Equity Interests

MarkWest Utica EMG Condensate

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

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

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Ohio Condensate

Initially, Utica Condensate’s business will be conducted solely through its subsidiary, Ohio Condensate Company L.L.C. (“Ohio Condensate”), which was formed in December 2013 through an agreement executed between Utica Condensate and Blackhawk (“Ohio Condensate LLC Agreement”), in which Utica Condensate and Blackhawk contributed cash in exchange for equity ownership interests of 99% and 1%, respectively. In January 2014, Summit purchased Blackhawk’s 1% equity interest and its option to purchase up to an additional equity ownership interest of 40% in Ohio Condensate (“Ohio Condensate Option”). Effective as of the Summit Investment Date, Summit exercised the Ohio Condensate Option and increased its equity ownership from less than 1% to approximately 40% through a cash investment of approximately $7.3 million, subject to a true-up of approximately $1.3 million that was contributed by Summit in July 2014.

As of June 30, 2014, Utica Condensate owned 60% of Ohio Condensate. The Partnership sold approximately $17 million of assets under construction to Utica Condensate in December 2013 and recorded that amount in Receivables, net in the accompanying Condensed Consolidated Balance Sheets as of December 31, 2013. The Partnership received the $17 million in the first quarter of 2014 and has recorded the proceeds in the Proceeds from disposal of property, plant and equipment in the accompanying Condensed Consolidated Statement of Cash Flows for the six months ended June 30, 2014. The amount of Management Fees revenue related to Ohio Condensate for the three and six months ended June 30, 2014 was approximately $0.9 million and $1.3 million, respectively, and is reported as Revenue in the Condensed Consolidated Statement of Operations.

5. Business Combination

Buffalo Creek Acquisition

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. The acquired assets include a 200 MMcf/d cryogenic gas processing plant under construction (which commenced operation in February 2014), 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 acquired facilities. Chesapeake has dedicated 130,000 acres throughout the Anadarko Basin to the Partnership as part of this long-term agreement. As a result of the acquisition, the Partnership has expanded its presence in the Granite Wash and Hogshooter formations in Oklahoma.

Contemporaneously with the Buffalo Creek Acquisition, Chesapeake agreed to extend a keep-whole processing agreement for natural gas produced in the Appalachia Basin area of the Partnership’s Northeast segment for five additional years, to 2020. The Partnership paid an additional $20.0 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 Consolidated Balance Sheets. The deferred contract cost is being amortized over the extension term. This $20.0 million is not considered to be part of the purchase price of the Buffalo Creek Acquisition and is not included in the purchase price allocation table below.

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 following table summarizes the 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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

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 market outlets, 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 prices of NGLs and crude oil. The Partnership currently manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. A portion of the Partnership’s NGL price exposure is managed by using crude oil contracts that were primarily executed when there was a strong relationship between changes in NGL and crude oil prices. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the crude oil contracts create increased risk and additional gains or losses. The Partnership may settle its crude oil contracts prior to the contractual settlement date in order to take advantage of favorable terms and reduce the future exposure resulting from the less effective crude oil contracts.

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

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

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

Notes to the Condensed Consolidated Financial Statements

(unaudited)

As of June 30, 2014, the Partnership had the following outstanding commodity contracts that were entered into to manage cash flow risk associated with future sales of NGLs or future purchases of natural gas:

Derivative contracts not designated as hedging instruments	Financial Position	Notional Quantity (net)
Crude Oil (bbl)	Short	935,540
Natural Gas (MMBtu)	Long	1,581,160
NGLs (gal)	Short	83,399,447

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 June 30, 2015 to December 31, 2022 with the producer’s option to extend the agreement for successive five-year terms through December 31, 2032. As of June 30, 2014, the estimated fair value of this contract was a liability of $97.8 million and the recorded value was a liability of $44.3 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of June 30, 2014 (in thousands):

Fair value of commodity contract	$	97,838
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of June 30, 2014	$	44,331

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 June 30, 2014, the estimated fair value of this contract was an asset of $1.5 million.

Financial Statement Impact of Derivative Instruments

There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013. The impact of the Partnership’s derivative instruments on its Condensed Consolidated Balance Sheets is summarized below (in thousands):

	Assets				Liabilities
Derivative instruments not designated as hedging instruments and their balance sheet location	Fair Value at June 30, 2014		Fair Value at December 31, 2013		Fair Value at June 30, 2014			Fair Value at December 31, 2013
Commodity contracts(1)
Fair value of derivative instruments — current	$	5,935	$	11,457	$	(21,930	)	$	(28,838	)
Fair value of derivative instruments — long-term	—		505		(35,668		)	(27,763		)
Total	$	5,935	$	11,962	$	(57,598	)	$	(56,601	)

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

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

	Assets							Liabilities
As of June 30, 2014	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	4,435	$	(3,947	)	$	488	$	(12,045	)	$	3,947	$	(8,098	)
Embedded derivatives in commodity contracts	1,500		—			1,500		(9,885		)	—		(9,885		)
Total current derivative instruments	5,935		(3,947		)	1,988		(21,930		)	3,947		(17,983		)

Non-current

Commodity contracts	—		—			—		(1,222		)	—		(1,222		)
Embedded derivatives in commodity contracts	—		—			—		(34,446		)	—		(34,446		)
Total non-current derivative instruments	—		—			—		(35,668		)	—		(35,668		)

Total derivative instruments	$	5,935	$	(3,947	)	$	1,988	$	(57,598	)	$	3,947	$	(53,651	)

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

Non-current

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

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

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

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

Derivative contracts not designated as hedging instruments and the location of	Three months ended June 30,						Six months ended June 30,
gain or (loss) recognized in income	2014			2013			2014			2013
Revenue: Derivative (loss) gain
Realized (loss) gain	$	(1,774	)	$	3,089		$	(9,381	)	$	6,987
Unrealized (loss) gain	(4,979		)	16,610			(1,339		)	12,527
Total revenue: derivative (loss) gain	(6,753		)	19,699			(10,720		)	19,514

Derivative (loss) gain related to purchased product costs
Realized loss	(144		)	(1,045		)	(258		)	(3,125		)
Unrealized (loss) gain	(11,820		)	21,477			(3,908		)	34,261
Total derivative (loss) gain related to purchase product costs	(11,964		)	20,432			(4,166		)	31,136

Derivative loss related to facility expenses
Unrealized loss	(2,045		)	(800		)	(1,777		)	(468		)
Total (loss) gain	$	(20,762	)	$	39,331		$	(16,663	)	$	50,182

7. Fair Value

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 6. Money market funds, which are included in cash and cash equivalents, are measured at fair value and are included in Level 1 measurements of the valuation hierarchy. The following table presents the derivative instruments carried at fair value as of June 30, 2014 and December 31, 2013 (in thousands):

As of June 30, 2014	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	89	$	(6,829	)
Significant unobservable inputs (Level 3)
Commodity contracts	4,346		(6,438		)
Embedded derivatives in commodity contracts	1,500		(44,331		)
Total carrying value in Condensed Consolidated Balance Sheet	$	5,935	$	(57,598	)

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of June 30, 2014. The market approach is used for valuation of all instruments.

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

Commodity contracts	Assets	Forward propane prices (per gallon) (1)	$ 1.06 - $1.09	Jul. 2014 - Dec. 2014

		Forward isobutane prices (per gallon) (1)	$ 1.34 - $1.36	Jul. 2014 - Dec. 2014

		Forward normal butane prices (per gallon) (1)	$ 1.26 - $1.31	Jul. 2014 - Dec. 2014

		Forward natural gasoline prices (per gallon) (1)	$ 2.15 - $2.21	Jul. 2014 - Dec. 2014

		Crude option volatilities (%)	13.89% - 14.93%	Sep. 2014 - Dec. 2014

	Liabilities	Forward propane prices (per gallon) (1)	$ 1.06 - $1.09	Jul. 2014 - Dec. 2014

		Forward isobutane prices (per gallon) (1)	$ 1.34 - $1.36	Jul. 2014 - Dec. 2014

		Forward normal butane prices (per gallon) (1)	$ 1.26 - $1.31	Jul. 2014 - Dec. 2014

		Forward natural gasoline prices (per gallon) (1)	$ 2.15 - $2.21	Jul. 2014 - Dec. 2014

		Crude option volatilities (%)	8.24% - 17.99%	Jul. 2014 - Dec. 2014

Embedded derivatives in commodity contracts	Asset	ERCOT Pricing (per MegaWatt Hour) (2)	$ 36.16 - $52.42	Jul. 2014 - Dec. 2014

	Liabilities	Forward propane prices (per gallon) (1)	$ 1.02 - $1.10	Jul. 2014 - Dec. 2022

		Forward isobutane prices (per gallon) (1)	$ 1.27 - $1.38	Jul. 2014 - Dec. 2022

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Level 3 Instrument	Balance Sheet Classification	Unobservable Inputs	Value Range	Time Period
		Forward normal butane prices (per gallon) (1)	$ 1.19 - $1.32	Jul. 2014 - Dec. 2022

		Forward natural gasoline prices (per gallon) (1)	$ 1.80 - $2.21	Jul. 2014 - Dec. 2022

		Forward natural gas prices (per MMBtu) (3)	$ 3.46 - $5.14	Jul. 2014 - Dec. 2022

		Probability of renewal (4)	0%

(1) NGL prices decrease over the respective period.

(2) The forward ERCOT prices utilized in the valuations are generally increasing over time with a seasonal spike in pricing in the summer months.

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

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

Fair Value Sensitivity Related to Unobservable Inputs

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

Embedded derivative in commodity contracts (liability) - The embedded derivative liability relates to the natural gas purchase agreement embedded in a keep-whole processing agreement as discussed further in Note 6. Increases (decreases) in forward NGL prices result in an increase (decrease) in the fair value of the embedded derivative liability. An increase in the probability of renewal would result in an increase in the fair value of the related embedded derivative liability.

Embedded derivative in commodity contracts (asset) - The embedded derivative asset relates to utilities costs discussed further in Note 6. Increases in the forward ERCOT prices, relative to natural gas prices, result in an increase in the fair value of the embedded derivative asset.

Level 3 Valuation Process

The Partnership’s Risk Management Department (the “Risk Department”) reports to the Chief Financial Officer, is responsible for the valuation of the Partnership’s commodity derivative contracts and embedded derivatives in commodity contracts and is responsible for the oversight of the Partnership’s commodity risk management program. The members of the Risk Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The valuations of the Level 3 commodity derivative

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

contracts are performed by a third-party pricing service and reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by at least one other independent third-party pricing service. The valuations for the embedded derivatives in commodity contracts are completed by the Risk Department utilizing the market data and price curves provided by the third-party pricing service. For the embedded derivative in the keep-whole processing arrangement discussed in Note 6, the Risk Department must develop forward price curves for NGLs and natural gas for periods in which price curves are not available from third-party pricing services due to insufficient market data. As of June 30, 2014, the Risk Department utilized internally developed price curves for the period of January 2015 through December 2022 in the valuation of the embedded derivative in the keep-whole processing arrangement. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Risk Department’s estimated price curves.

Changes in Level 3 Fair Value Measurements

The table below includes a roll forward of the balance sheet amounts for the three and six months ended June 30, 2014 and 2013 for net assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

	Three months ended June 30, 2014
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(751	)	$	(28,486	)
Total loss (realized and unrealized) included in earnings (1)	(1,961		)	(16,479		)
Settlements	620			2,134
Fair value at end of period	$	(2,092	)	$	(42,831	)

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)	$	(1,758	)	$	(15,959	)

	Three months ended June 30, 2013
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	12,477		$	(24,881	)
Total gain (realized and unrealized) included in earnings (1)	16,896			20,459
Settlements	(2,995		)	2,019
Fair value at end of period	$	26,378		$	(2,403	)

The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period (1)	$	14,755		$	20,766

	Six months ended June 30, 2014
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(5,460	)	$	(35,032	)
Total loss (realized and unrealized) included in earnings (1)	(4,238		)	(12,068		)
Settlements	7,606			4,269
Fair value at end of period	$	(2,092	)	$	(42,831	)

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)	$	(1,319	)	$	(12,204	)

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

	Six months ended June 30, 2013
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	12,449		$	(33,957	)
Total gain (realized and unrealized) included in earnings (1)	20,220			26,991
Settlements	(6,291		)	4,563
Fair value at end of period	$	26,378		$	(2,403	)

The amount of total 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)	$	17,854		$	27,229

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

8. Inventories

Inventories consist of the following (in thousands):

	June 30, 2014		December 31, 2013
NGLs	$	38,444	$	21,131
Line fill	10,466		7,960
Spare parts, materials and supplies	13,825		12,272
Total inventories	$	62,735	$	41,363

9. Long-Term Debt

Debt is summarized below (in thousands):

	June 30, 2014		December 31, 2013
Credit Facility
Credit Facility, variable interest, due March 2019 (1)	$	441,200	$	—

Senior Notes (2)
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020	500,000		500,000
2021 Senior Notes, 6.5% interest, net of discount of $444 and $474, respectively, issued February and March 2011 and due August 2021	324,556		324,526
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022	455,000		455,000
2023A Senior Notes, 5.5% interest, net of discount of $6,119 and $6,455, respectively, issued August 2012 and due February 2023	743,881		743,545
2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023	1,000,000		1,000,000
Total long-term debt	$	3,464,637	$	3,023,071

(1) Applicable interest rate was 4.5% for $166.2 million and 2.4% for $275.0 million at June 30, 2014. The carrying amount of the Credit Facility approximates fair value due to the short-term and variable nature of the borrowings. The fair value of the Partnership’s Credit Facility is considered a Level 2 measurement.

(2) The estimated aggregate fair value of the senior notes (collectively, the “Senior Notes”) was approximately $3,217 million and $3,079 million as of June 30, 2014 and December 31, 2013, respectively, based on quoted prices in an inactive market. The fair value of the Partnership’s Senior Notes is considered a Level 3 measurement.

Credit Facility

On March 20, 2014, the Partnership amended the Credit Facility to increase total borrowing capacity to $1.3 billion, extend the maturity by approximately 18 months to March 20, 2019, amend the pricing terms (as discussed below), expand the existing accordion option from $250 million to $500 million and provide the Partnership with the right to release the collateral securing the Credit Facility. The right to release collateral will occur once the Partnership’s long-term, senior unsecured debt (“Index Debt”) has received an investment grade rating from Standard & Poor’s equal to or more favorable than BBB- (stable) and from Moody’s equal to or more favorable than Baa3 (stable) and the Partnership’s Total Leverage Ratio (as defined in the Credit Facility) is not greater than 5.00 to

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

1.00 (“Collateral Release Date”). The Partnership incurred approximately $1.9 million of deferred financing costs associated with modifications of the Credit Facility during the six months ended June 30, 2014.

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

Under the provisions of the Credit Facility and indentures, the Partnership is subject to a number of restrictions and covenants. The Credit Facility and indentures place limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership’s restricted subsidiaries to pay dividends or distributions, make loans or transfer property to the Partnership; engage in transactions with the Partnership’s affiliates; sell assets, including equity interests of the Partnership’s subsidiaries; make any payment on or with respect to or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. The Credit Facility also limits the Partnership’s ability to enter into transactions with parties that require margin calls under certain derivative instruments. Under the Credit Facility, neither the Partnership nor the bank can require margin calls for outstanding derivative positions.

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

Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by the Partnership’s 100% owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries, and collateralized by substantially all of the Partnership’s assets and those of its 100% owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries. As of June 30, 2014, the Partnership had $441.2 million borrowings outstanding and approximately $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $847.5 million of unused capacity of which approximately $645 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.

10. Equity

Equity Offerings

On September 5, 2013, the Partnership entered into an Equity Distribution Agreement with a financial institution (the “2013 Manager”) that established an At the Market offering program (the “September 2013 ATM”) pursuant to which the Partnership may sell from time to time through the 2013 Manager as its sales agent, common units representing limited partner interests having an aggregate offering price of up to $1 billion. During the six months ended June 30, 2014, the Partnership sold an aggregate of 4.2 million common units under the September 2013 ATM Agreement, receiving net proceeds of approximately $272 million after deducting approximately $3.5 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general Partnership purposes. The Partnership completed the September 2013 ATM on March 31, 2014.

On March 11, 2014, the Partnership entered into an Equity Distribution Agreement with financial institutions (the “2014 Managers”) that established an At the Market offering program (the “March 2014 ATM”) pursuant to which the Partnership may sell from time to time through the 2014 Managers, as its sales agents, common units having an aggregate offering price of up to $1.2 billion. During the six months ended June 30, 2014, the Partnership sold an aggregate of approximately 7.0 million common units under the March 2014 ATM Agreement, receiving net proceeds of approximately $440 million after deducting approximately $3.5 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general Partnership purposes.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

All of the Partnership’s Class B units were issued to and are held by M&R MWE Liberty, LLC, an affiliate of EMG, as part of the Partnership’s December 31, 2011 acquisition of the non-controlling interest in MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”). Approximately four million Class B units converted to common units on July 1, 2014. The remaining Class B units will convert to common units on a one-for-one basis in three equal installments beginning on July 1, 2015 and each of the next two anniversaries of such date. After the units are converted to common units, M&R MWE Liberty, LLC may sell common units as part of the March 2014 ATM program. These converted units will participate in the distributions declared on July 24, 2014.

Distributions of Available Cash and Range of Unit Prices

	Common Unit Price				Distribution Per Common
Quarter Ended	High		Low		Unit		Declaration Date	Record Date	Payment Date
June 30, 2014	$	71.88	$	58.62	$	0.88	July 24, 2014	August 5, 2014	August 14, 2014
March 31, 2014	$	73.42	$	61.60	$	0.87	April 22, 2014	May 7, 2014	May 15, 2014
December 31, 2013	$	75.79	$	62.56	$	0.86	January 22, 2014	February 6, 2014	February 14, 2014

11. Commitments and Contingencies

Legal

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

Contract Contingencies

Certain natural gas processing and gathering arrangements require the Partnership to construct new natural gas processing plants and NGL pipelines and contain certain fees and concessions if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure. As of June 30, 2014, management does not believe there are any indications that the Partnership will not be able to meet the construction milestones or that force majeure does not apply or that such fees or concessions will otherwise apply.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

12. Income Taxes

A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate to income before provision for income tax for the six months ended June 30, 2014 and 2013 is as follows (in thousands):

	Six months ended June 30, 2014
	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax	$	6,641		$	32,297		$	(368	)	$	38,570
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	2,324			—			—			2,324
Permanent items	33			—			—			33
State income taxes net of federal benefit	168			409			—			577
Federal and state tax rate change	4,250			—			—			4,250
Provision on income from Class A units (1)	2,422			—			—			2,422
Provision for income tax	$	9,197		$	409		$	—		$	9,606

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

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

13. Earnings Per Common Unit

The following table shows the computation of basic and diluted net income per common unit for the three and six months ended June 30, 2014 and 2013, and the weighted-average units used to compute basic and diluted net income per common unit (in thousands, except per unit data):

	Three months ended June 30,				Six months ended June 30,
	2014		2013		2014		2013
Net income attributable to the Partnership’s unitholders	$	8,977	$	83,699	$	21,469	$	68,241
Less: Income allocable to phantom units	551		554		1,096		1,100
Income available for common unitholders - basic	8,426		83,145		20,373		67,141
Add: Income allocable to phantom units and DER expense	574		569		1,141		1,135
Income available for common unitholders - diluted	$	9,000	$	83,714	$	21,514	$	68,276

Weighted average common units outstanding - basic	164,613		131,227		161,727		129,928
Potential common shares (Class B and phantom units)	16,624		20,639		16,651		20,652
Weighted average common units outstanding - diluted	181,237		151,866		178,378		150,580

Net income attributable to the Partnership’s common unitholders per common unit (1)
Basic	$	0.05	$	0.63	$	0.13	$	0.52
Diluted	$	0.05	$	0.55	$	0.12	$	0.45

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

14. Segment Information

The Partnership prepares segment information in accordance with GAAP. However, 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. As disclosed in Note 3, Ohio Gathering was deconsolidated effective June 1, 2014 and its financial position as of June 30, 2014 and results of operations are reported under the equity method of accounting as of June 30, 2014 and for the month of June 2014, respectively. However, the Partnership’s Chief Executive Officer and “chief operating decision maker” continues to view the Utica Segment inclusive of Ohio Gathering, and review its financial information as if they are still consolidated.

The tables below present the Partnership’s segment profit measure, Operating income before items not allocated to segments for the three months ended June 30, 2014 and 2013 for the reported segments (in thousands):

Three months ended June 30, 2014:

	Marcellus		Utica		Northeast		Southwest		Elimination (1)			Total

Segment revenue	$	183,734	$	30,826	$	43,777	$	271,140	$	(900	)	$	528,577

Purchased product costs	39,710		7,353		15,169		153,628		—			215,860

Net operating margin	144,024		23,473		28,608		117,512		(900		)	312,717

Facility expenses	33,755		12,174		8,509		34,354		(900		)	87,892
Portion of operating income attributable to non-controlling interests	—		4,687		—		6		—			4,693
Operating income before items not allocated to segments	$	110,269	$	6,612	$	20,099	$	83,152	$	—		$	220,132

Three months ended June 30, 2013:

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

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the three months ended June 30, 2014 and 2013 (in thousands):

	Three months ended June 30,
	2014			2013
Total segment revenue	$	528,577		$	396,858
Derivative (loss) gain not allocated to segments	(6,753		)	19,699
Revenue adjustment for unconsolidated affiliate (1)	(3,833		)	—
Revenue deferral adjustment and other (2)	375			(1,437		)
Total revenue	$	518,366		$	415,120

Operating income before items not allocated to segments	$	220,132		$	177,472
Portion of operating income (loss) attributable to non-controlling interests	4,184			(1,090		)
Derivative (loss) gain not allocated to segments	(20,762		)	39,331
Revenue adjustment for unconsolidated affiliate (1)	(3,833		)	—
Revenue deferral adjustment and other (2)	375			(1,437		)
Compensation expense included in facility expenses not allocated to segments	(903		)	(368		)
Facility expense and purchase product cost adjustments for unconsolidated affiliate (3)	2,598			—
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate (4)	509			—
Facility expense adjustments (5)	2,688			2,688
Selling, general and administrative expenses	(27,701		)	(25,499		)
Depreciation	(104,078		)	(71,562		)
Amortization of intangible assets	(15,965		)	(17,092		)
(Loss) gain on disposal of property, plant and equipment	(1,450		)	37,736
Accretion of asset retirement obligations	(168		)	(157		)
Income from operations	55,626			140,022
Equity in (loss) earnings from unconsolidated affiliates	(721		)	430
Interest income	10			62
Interest expense	(43,391		)	(36,955		)
Amortization of deferred financing costs and debt discount (a component of interest expense)	(1,449		)	(1,784		)
Miscellaneous income, net	33			6
Income before provision for income tax	$	10,108		$	101,781

(1) Revenue adjustment for unconsolidated affiliate relates to Ohio Gathering revenue for the month of June 2014 (See note above and Note 3).

(2) Revenue deferral amount relates primarily to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term. Therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnership’s chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended June 30, 2014, 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 June 30, 2013, 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 unconsolidated affiliates of $2.1 million for the three months ended June 30, 2014 compared to $0.2 million for three months ended June 30, 2013.

(3) Facility expense and purchase product cost adjustments for unconsolidated affiliate consist of the facility expenses and purchase product costs related to Ohio Gathering for the month of June 2014 (See note above and Note 3).

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

(4) Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate amount relates to Summit’s portion of Ohio Gathering’s operating income, which is included in segment operating income calculation as if Ohio Gathering is consolidated (See note above and Note 3).

(5) 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.

The tables below present the Partnership’s segment profit measure, Operating income before items not allocated to segments, and capital expenditures for the six months ended June 30, 2014 and 2013 for the reported segments (in thousands):

Six months ended June 30, 2014:

	Marcellus		Utica (1)		Northeast		Southwest		Elimination (2)			Total

Segment revenue	$	358,893	$	54,592	$	105,030	$	530,470	$	(2,471	)	$	1,046,514

Purchased product costs	74,000		11,488		35,624		306,312		—			427,424

Net operating margin	284,893		43,104		69,406		224,158		(2,471		)	619,090

Facility expenses	69,228		24,026		15,623		66,876		(2,471		)	173,282
Portion of operating income attributable to non-controlling interests	—		7,823		—		5		—			7,828
Operating income before items not allocated to segments	$	215,665	$	11,255	$	53,783	$	157,277	$	—		$	437,980

Capital expenditures	$	792,927	$	433,615	$	1,300	$	78,588	$	—		$	1,306,430
Capital expenditures for Ohio Gathering after deconsolidation (1)												(40,013		)
Capital expenditures not allocated to segments												8,906
Total capital expenditures												$	1,275,323

Six months ended June 30, 2013:

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

Capital expenditures	$	729,040	$	640,819		$	2,509	$	57,816	$	1,430,184
Capital expenditures not allocated to segments										4,900
Total capital expenditures										$	1,435,084

(1) As disclosed in Note 3, Ohio Gathering was deconsolidated effective June 1, 2014, and its financial position as of June 30, 2014 and results of operations are reported under the equity method of accounting as of June 30, 2014 and for the month of June 2014, respectively. However, the Partnership’s Chief Executive Officer and “chief operating

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

decision maker” continues to view the Utica Segment inclusive of Ohio Gathering, and review its financial information as if they are still combined. The Utica segment includes $40.0 million related to Ohio Gathering capital expenditures after deconsolidation on June 1, 2014 (See Note 3).

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

The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the six months ended June 30, 2014 and 2013 (in thousands):

	Six months ended June 30,
	2014			2013
Total segment revenue	$	1,046,514		$	771,680
Derivative (loss) gain not allocated to segments	(10,720		)	19,514
Revenue adjustment for unconsolidated affiliate (1)	(3,833		)	—
Revenue deferral adjustment and other (2)	(1,119		)	(2,801		)
Total revenue	$	1,030,842		$	788,393

Operating income before items not allocated to segments	$	437,980		$	339,200
Portion of operating income (loss) attributable to non-controlling interests	7,319			(2,365		)
Derivative (loss) gain not allocated to segments	(16,663		)	50,182
Revenue adjustment for unconsolidated affiliate (1)	(3,833		)	—
Revenue deferral adjustment and other (2)	(1,119		)	(2,801		)
Compensation expense included in facility expenses not allocated to segments	(1,906		)	(754		)
Facility expense and purchase product cost adjustments for unconsolidated affiliate (3)	2,598			—
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate (4)	509			—
Facility expense adjustments (5)	5,376			5,376
Selling, general and administrative expenses	(62,991		)	(50,741		)
Depreciation	(206,007		)	(139,579		)
Amortization of intangible assets	(31,943		)	(31,922		)
(Loss) gain on disposal of property, plant and equipment	(1,357		)	37,598
Accretion of asset retirement obligations	(336		)	(509		)
Income from operations	127,627			203,685
Equity in (loss) earnings from unconsolidated affiliates	(471		)	665
Interest income	19			211
Interest expense	(84,375		)	(75,291		)
Amortization of deferred financing costs and debt discount (a component of interest expense)	(4,273		)	(3,614		)
Loss on redemption of debt	—			(38,455		)
Miscellaneous income, net	43			6
Income before provision for income tax	$	38,570		$	87,207

(1) Revenue adjustment for unconsolidated affiliate relates to Ohio Gathering revenue for the month of June 2014 (See note above and Note 3).

(2) Revenue deferral amount relates primarily to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership will perform a similar level of service for the entire term. Therefore, the revenue recognized in the current reporting period is less than the cash received. However, the Partnership’s chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the six months ended June 30, 2014, approximately $0.4 million and $3.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. In comparison, for the six months ended June 30, 2013, approximately $0.4 million and $3.0 million of the revenue deferral adjustment was

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes. Other consists of management fee revenues from unconsolidated affiliates of $2.7 million for the six months ended June 30, 2014 compared to $0.6 million for six months ended June 30, 2013.

(4) Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate amount relates to Summit’s proportionate share of Ohio Gathering’s operating income, which is included in segment operating income calculation as if Ohio Gathering is consolidated (See note above and Note 3).

(5) 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.

The table below presents information about segment assets as of June 30, 2014 and December 31, 2013 (in thousands):

	June 30, 2014		December 31, 2013
Marcellus	$	5,108,339	$	4,529,028
Utica (1)	1,882,369		1,646,995
Northeast	525,743		572,855
Southwest	2,424,174		2,389,057
Total segment assets	9,940,625		9,137,935
Assets not allocated to segments:
Certain cash and cash equivalents	51,592		63,086
Fair value of derivatives	5,935		11,962
Investment in unconsolidated affiliates	71,324		75,627
Receivables from unconsolidated affiliate	13,977		—
Other (2)	99,937		107,813
Total assets	$	10,183,390	$	9,396,423

(1) The June 30, 2014 amount excludes assets related to Ohio Gathering, which was deconsolidated on June 1, 2014 and reported as an equity investment as of June 30, 2014 (See note above and Note 3). This amount includes Utica’s investment in Ohio Gathering.

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

15. Supplemental Condensed Consolidating Financial Information

MarkWest Energy Partners L.P. has no significant operations independent of its subsidiaries. As of June 30, 2014, the Partnership’s obligations under the outstanding Senior Notes (see Note 9) were fully, jointly and severally guaranteed, by all of the subsidiaries that are owned 100% by the Partnership, other than MarkWest Liberty Midstream and its subsidiaries. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures (see Note 16 to the Consolidated Financial Statements included in Item 8 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013 for discussion of these circumstances). Subsidiaries that are not 100% owned by the Partnership do not guarantee the Senior Notes. For the purpose of the following financial information, the Partnership’s investments in its subsidiaries and the guarantor subsidiaries’ investments in their subsidiaries are presented in accordance with the equity method of accounting. The co-issuer, MarkWest Energy Finance Corporation, has no independent assets or operations. Condensed consolidating financial information for MarkWest Energy Partners L.P. and its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2014 and December 31, 2013 and for the three and six months ended June 30, 2014 and 2013 is as follows (in thousands):

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Condensed Consolidating Balance Sheets

	As of June 30, 2014
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	15	$	51,580	$	247,817	$	—		$	299,412
Restricted cash	—		—		10,000		—			10,000
Receivables and other current assets	5,094		273,520		138,497		—			417,111
Intercompany receivables	2,012,956		76,174		67,906		(2,157,036		)	—
Fair value of derivative instruments	—		4,828		1,107		—			5,935
Receivables from unconsolidated affiliates	—		1,546		12,431		—			13,977
Total current assets	2,018,065		407,648		477,758		(2,157,036		)	746,435
Total property, plant and equipment, net	8,340		2,139,094		5,650,985		(61,531		)	7,736,888
Other long-term assets:
Restricted cash	—		—		10,000		—			10,000
Investment in unconsolidated affiliates	—		81,843		558,603		(10,519		)	629,927
Investment in consolidated affiliates	5,813,027		5,523,135		—		(11,336,162		)	—
Intangibles, net of accumulated amortization	—		571,361		270,866		—			842,227
Intercompany notes receivable	137,000		—		—		(137,000		)	—
Other long-term assets	49,898		92,065		75,950		—			217,913
Total assets	$	8,026,330	$	8,815,146	$	7,044,162	$	(13,702,248	)	$	10,183,390
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	3,109	$	2,074,930	$	78,997	$	(2,157,036	)	$	—
Fair value of derivative instruments	—		20,288		1,642		—			21,930
Other current liabilities	58,602		284,191		380,010		(2,262		)	720,541
Total current liabilities	61,711		2,379,409		460,649		(2,159,298		)	742,471
Deferred income taxes	3,815		301,710		—		—			305,525
Long-term intercompany financing payable	—		137,000		96,296		(233,296		)	—
Fair value of derivative instruments	—		35,668		—		—			35,668
Long-term debt, net of discounts	3,464,637		—		—		—			3,464,637
Other long-term liabilities	6,657		148,332		7,839		—			162,828
Redeemable non-controlling interest	—		—		—		70,711			70,711
Equity:
Common Units	3,887,485		5,813,027		6,479,378		(12,265,897		)	3,913,993
Class B Units	602,025		—		—		—			602,025
Non-controlling interest in consolidated subsidiaries	—		—		—		885,532			885,532
Total equity	4,489,510		5,813,027		6,479,378		(11,380,365		)	5,401,550
Total liabilities and equity	$	8,026,330	$	8,815,146	$	7,044,162	$	(13,702,248	)	$	10,183,390

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Condensed Consolidating Statements of Operations

	Three months ended June 30, 2014
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	318,408		$	209,800		$	(9,842	)	$	518,366
Operating expenses:
Purchased product costs	—			180,638			47,150			—			227,788
Facility expenses	—			42,567			44,311			(1,288		)	85,590
Selling, general and administrative expenses	10,760			7,795			12,416			(3,270		)	27,701
Depreciation and amortization	288			49,719			71,409			(1,373		)	120,043
Other operating expenses (income)	—			352			6,536			(5,270		)	1,618
Total operating expenses	11,048			281,071			181,822			(11,201		)	462,740

(Loss) income from operations	(11,048		)	37,337			27,978			1,359			55,626

Earnings from consolidated affiliates	54,074			18,928			—			(73,002		)	—
Other expense, net	(44,526		)	(5,382		)	(4,978		)	9,368			(45,518		)
Income before provision for income tax	(1,500		)	50,883			23,000			(62,275		)	10,108
Provision for income tax (benefit) expense	251			(3,191		)	—			—			(2,940		)
Net income	(1,751		)	54,074			23,000			(62,275		)	13,048
Net income attributable to non-controlling interest	—			—			—			(4,071		)	(4,071		)
Net income attributable to the Partnership’s unitholders	$	(1,751	)	$	54,074		$	23,000		$	(66,346	)	$	8,977

	Three months ended June 30, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	298,097		$	126,515		$	(9,492	)	$	415,120
Operating expenses:
Purchased product costs	—			117,813			17,114			—			134,927
Facility expenses	—			34,497			29,485			(385		)	63,597
Selling, general and administrative expenses	12,074			6,646			8,451			(1,672		)	25,499
Depreciation and amortization	242			45,457			44,292			(1,337		)	88,654
Other operating expenses (income)	—			573			(40,233		)	2,081			(37,579		)
Total operating expenses	12,316			204,986			59,109			(1,313		)	275,098

(Loss) income from operations	(12,316		)	93,111			67,406			(8,179		)	140,022

Earnings from consolidated affiliates	132,913			62,611			—			(195,524		)	—
Other expense, net	(40,102		)	(6,820		)	(2,997		)	11,678			(38,241		)
Income before provision for income tax	80,495			148,902			64,409			(192,025		)	101,781
Provision for income tax (benefit) expense	294			15,989			—			—			16,283
Net income	80,201			132,913			64,409			(192,025		)	85,498
Net income attributable to non-controlling interest	—			—			—			(1,799		)	(1,799		)
Net income attributable to the Partnership’s unitholders	$	80,201		$	132,913		$	64,409		$	(193,824	)	$	83,699

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

	Six months ended June 30, 2014
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	643,909		$	408,918		$	(21,985	)	$	1,030,842
Operating expenses:
Purchased product costs	—			345,821			85,733			—			431,554
Facility expenses	—			79,600			92,682			(3,255		)	169,027
Selling, general and administrative expenses	24,415			18,311			25,765			(5,500		)	62,991
Depreciation and amortization	568			98,839			141,222			(2,679		)	237,950
Other operating expenses (income)	—			193			6,770			(5,270		)	1,693
Total operating expenses	24,983			542,764			352,172			(16,704		)	903,215

(Loss) income from operations	(24,983		)	101,145			56,746			(5,281		)	127,627

Earnings from consolidated affiliates	121,784			41,317			—			(163,101		)	—
Other expense, net	(87,688		)	(11,480		)	(7,934		)	18,045			(89,057		)
Income before provision for income tax	9,113			130,982			48,812			(150,337		)	38,570
Provision for income tax (benefit) expense	408			9,198			—			—			9,606
Net income	8,705			121,784			48,812			(150,337		)	28,964
Net income attributable to non-controlling interest	—			—			—			(7,495		)	(7,495		)
Net (loss) income attributable to the Partnership’s unitholders	$	8,705		$	121,784		$	48,812		$	(157,832	)	$	21,469

	Six months ended June 30, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	569,065		$	235,857		$	(16,529	)	$	788,393
Operating expenses:
Purchased product costs	—			240,763			36,017			—			276,780
Facility expenses	—			66,775			56,387			(387		)	122,775
Selling, general and administrative expenses	24,108			13,619			15,528			(2,514		)	50,741
Depreciation and amortization	519			89,510			84,295			(2,823		)	171,501
Other operating expenses (income)	—			1,338			(40,507		)	2,080			(37,089		)
Total operating expenses	24,627			412,005			151,720			(3,644		)	584,708

(Loss) income from operations	(24,627		)	157,060			84,137			(12,885		)	203,685

Earnings from consolidated affiliates	202,874			81,729			—			(284,603		)	—
Loss on redemption of debt	(38,455		)	—			—			—			(38,455		)
Other expense, net	(83,102		)	(13,236		)	(6,282		)	24,597			(78,023		)
Income before provision for income tax	56,690			225,553			77,855			(272,891		)	87,207
Provision for income tax (benefit) expense	161			22,679			—			—			22,840
Net income	56,529			202,874			77,855			(272,891		)	64,367
Net income attributable to non-controlling interest	—			—			—			3,874			3,874
Net (loss) income attributable to the Partnership’s unitholders	$	56,529		$	202,874		$	77,855		$	(269,017	)	$	68,241

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

Condensed Consolidating Statements of Cash Flows

	Six months ended June 30, 2014
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(97,223	)	$	263,284		$	187,138		$	3,624		$	356,823

Cash flows from investing activities:
Capital expenditures	(5,116		)	(108,203		)	(1,157,346		)	(4,658		)	(1,275,323		)
Equity investments in consolidated affiliates	(30,038		)	(1,090,000		)	—			1,120,038			—
Investment in unconsolidated affiliates	—			(8,540		)	(67,514		)	—			(76,054		)
Distributions from consolidated affiliates	63,158			151,110			—			(214,268		)	—
Investment in intercompany notes, net	14,200			—			—			(14,200		)	—
Proceeds from disposal of property, plant and equipment	—			4,164			17,398			—			21,562
Proceeds from sale of equity interest in unconsolidated affiliate	—			—			324,657			—			324,657
Net cash flows provided by (used in) investing activities	42,204			(1,051,469		)	(882,805		)	886,912			(1,005,158		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	711,837			—			—			—			711,837
Proceeds from Credit Facility	1,923,500			—			—			—			1,923,500
Payments Credit Facility	(1,482,300		)	—			—			—			(1,482,300		)
Payments related to intercompany financing, net	—			(14,200		)	(1,034		)	15,234			—
Payments for debt issue costs and deferred financing costs	(2,045		)	—			—			—			(2,045		)
Contributions from parent and affiliates	—			30,038			1,090,000			(1,120,038		)	—
Share-based payment activity	(8,943		)	—			—			—			(8,943		)
Payment of distributions	(278,316		)	(63,158		)	(151,200		)	214,268			(278,406		)
Payments of SMR liability	—			(1,201		)	—			—			(1,201		)
Intercompany advances, net	(808,923		)	808,923			—			—			—
Net cash flows (used in) provided by financing activities	54,810			760,402			937,766			(890,536		)	862,442

Net (decrease) increase in cash	(209		)	(27,783		)	242,099			—			214,107
Cash and cash equivalents at beginning of year	224			79,363			5,718			—			85,305
Cash and cash equivalents at end of period	$	15		$	51,580		$	247,817		$	—		$	299,412

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements

(unaudited)

	Six months ended June 30, 2013
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(79,362	)	$	129,228		$	116,760		$	10,970		$	177,596

Cash flows from investing activities:
Restricted cash	—			—			25,500			—			25,500
Capital expenditures	(480		)	(53,319		)	(1,369,397		)	(11,888		)	(1,435,084		)
Equity investments in consolidated affiliates	(28,823		)	(783,600		)	—			812,423			—
Investment in unconsolidated affiliates	—			(8,336		)	—			—			(8,336		)
Distributions from consolidated affiliates	47,860			389,300			—			(437,160		)	—
Acquisition of business, net of cash acquired	—			(225,210		)	—			—			(225,210		)
Proceeds from disposal of property, plant and equipment	—			43			208,066			—			208,109
Net cash flows provided by (used in) investing activities	18,557			(681,122		)	(1,135,831		)	363,375			(1,435,021		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	348,352			—			—			—			348,352
Proceeds from long-term debt	1,000,000			—			—			—			1,000,000
Payments of long-term debt	(501,112		)	—			—			—			(501,112		)
Payments of premiums on redemption of long-term debt	(31,516		)	—			—			—			(31,516		)
Payments for debt issue costs and deferred financing costs	(14,046		)	—			—			—			(14,046		)
Payments related to intercompany financing, net	—			—			(918		)	918			—
Contributions from parent and affiliates	—			28,823			783,600			(812,423		)	—
Contribution from non-controlling interest	—			—			685,219			—			685,219
Share-based payment activity	(5,206		)	650			—			—			(4,556		)
Payment of distributions	(214,903		)	(47,860		)	(389,412		)	437,160			(215,015		)
Payments of SMR liability	—			(1,103		)	—			—			(1,103		)
Intercompany advances, net	(595,591		)	595,591			—			—			—
Net cash flows (used in) provided by financing activities	(14,022		)	576,101			1,078,489			(374,345		)	1,266,223

Net (decrease) increase in cash	(74,827		)	24,207			59,418			—			8,798
Cash and cash equivalents at beginning of year	210,015			102,979			32,762			—			345,756
Cash and cash equivalents at end of period	$	135,188		$	127,186		$	92,180		$	—		$	354,554

16. Supplemental Cash Flow Information

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

	Six months ended June 30,
	2014		2013
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	81,031	$	60,835
Cash received for income taxes, net	321		16,591

Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	312,519	$	524,445
Interest capitalized on construction in progress	12,679		19,090
Issuance of common units for vesting of share-based payment awards	7,754		4,495

Table of Contents

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

Forward-Looking Statements

Management’s Discussion and Analysis (“MD&A”) contains statements that are forward-looking and should be read in conjunction with our Condensed Consolidated Financial Statements and accompanying notes included elsewhere in this report and our Annual Report on Form 10-K for the year ended December 31, 2013. Statements that are not historical facts are forward-looking statements. We use words such as “could,” “may,” “predict,” “should,” “expect,” “hope,” “continue,” “potential,” “plan,” “intend,” “anticipate,” “project,” “believe,” “estimate,” and similar expressions to identify forward-looking statements. These statements are based on current expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. Forward-looking statements are not guarantees and actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors. We do not update publicly any forward-looking statement with new information or future events. Undue reliance should not be placed on forward-looking statements as many of these factors are beyond our ability to control or predict.

Overview

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

Significant Financial and Other Business Highlights

Significant financial and other highlights for the three months ended June 30, 2014 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

· Total segment operating income before items not allocated to segments (a non-GAAP financial measure, see below) increased approximately $42.7 million, or 24%, for the three months ended June 30, 2014 compared to the same period in 2013. The increase was comprised of the following:

· An increase of $29.5 million in our Marcellus segment with a 76% increase in processed volumes and a 162% increase in total NGLs fractionated volumes.

· An increase of approximately $8.3 million in our Utica segment due to the significant increase in volumes from an increase in capacity at our Cadiz and Seneca complexes.

· An increase of approximately $8.4 million in our Southwest segment with a 17% increase in processed volumes and an 8% increase in gathered volumes.

· Realized loss from the settlement of our derivative instruments was $1.9 million for the three months ended June 30, 2014 compared to a $2.0 million realized gain for the same period in 2013.

· In the second quarter of 2014, we commenced operations of a 120 MMcf/d cryogenic processing facility and a 20,000 Bbl/d fractionation facility in Butler County, Pennsylvania along with a 32 mile purity ethane pipeline connecting to Sunoco’s purity ethane pipeline running from our Houston Fractionation Facility to Sarnia, Ontario, Canada markets (“Mariner West”).

· Summit exercised the Ohio Gathering Option and increased its equity ownership from less than 1% to approximately 40% through a cash investment of approximately $324.7 million that was received on May 30, 2014 and a true-up payment of approximately $16.5 million that was contributed in July 2014. MarkWest Utica EMG’s equity ownership in Ohio Gathering decreased to 60%. Summit also exercised the Ohio Condensate Option and increased its equity ownership from less than 1% to approximately 40% through a cash investment of approximately $7.3 million, subject to a true-up of approximately $1.3 million that was contributed in July 2014.

· In the second quarter of 2014, we received net proceeds of approximately $440 million from the public offering of approximately 7.0 million newly issued common units representing limited partner interests in the Partnership as part of our At the Market (“ATM”) programs.

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Non-GAAP Measures

In evaluating our financial performance, management utilizes the segment performance measures, segment revenues and operating income before items not allocated to segments. These financial measures are presented in Note 14 to the accompanying Condensed Consolidated Financial Statements and are considered non-GAAP financial measures when presented outside of the notes to the Condensed Consolidated Financial Statements. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Note 14 to the accompanying Condensed Consolidated Financial Statements for the reconciliations of segment revenue and segment operating income before items not allocated to segments to the respective most comparable GAAP measure.

Management evaluates contract performance on the basis of net operating margin (a non-GAAP financial measure). These adjustments have been made for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting.

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

	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Segment revenue	$	528,577		$	396,858		$	1,046,514		$	771,680
Purchased product costs	(215,824		)	(155,359		)	(427,388		)	(307,916		)
Net operating margin	312,753			241,499			619,126			463,764
Facility expenses	(83,545		)	(62,797		)	(167,250		)	(122,307		)
Derivative (loss) gain	(20,762		)	39,331			(16,663		)	50,182
Revenue deferral adjustment and other	375			(1,437		)	(1,119		)	(2,801		)
Revenue from unconsolidated affiliate	(3,833		)	—			(3,833		)	—
Selling, general and administrative expenses	(27,701		)	(25,499		)	(62,991		)	(50,741		)
Depreciation	(104,078		)	(71,562		)	(206,007		)	(139,579		)
Amortization of intangible assets	(15,965		)	(17,092		)	(31,943		)	(31,922		)
Gain on disposal of property, plant and equipment	(1,450		)	37,736			(1,357		)	37,598
Accretion of asset retirement obligations	(168		)	(157		)	(336		)	(509		)
Income from operations	$	55,626		$	140,022		$	127,627		$	203,685

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

Our Contracts

We generate the majority of our revenue and net operating margin (a non-GAAP measure, see above for discussion and reconciliation of net operating margin) from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the following types of arrangements: fee-based, percent-of-proceeds, percent-of-index and keep-whole. See Item 1 Business—Our Contracts in our Annual Report on Form 10-K for the year ended December 31, 2013 for further discussion of each of these types of arrangements.

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

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For the three months ended June 30, 2014, 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	87	%	13	%	0	%
Utica (3)	100	%	0	%	0	%
Northeast	25	%	20	%	55	%
Southwest	57	%	39	%	4	%
Total (3)	71	%	22	%	7	%

For the six months ended June 30, 2014, 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	84	%	16	%	0	%
Utica (3)	100	%	0	%	0	%
Northeast	20	%	17	%	63	%
Southwest	57	%	38	%	5	%
Total (3)	68	%	23	%	9	%

(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.

(3) Includes Ohio Gathering, an unconsolidated affiliate (See Note 3).

Seasonality

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

Results of Operations

Segment Reporting

We present information in this MD&A by segment. The segment information appearing in Note 14 of the accompanying Notes to the Condensed Consolidated Financial Statements is presented on a basis consistent with our internal management reporting. We conduct our operations in the following operating segments: Marcellus, Utica, Northeast and Southwest. Our assets and operations in each of these segments are described below.

Marcellus Segment

In our Marcellus segment, we provide fully integrated natural gas midstream services in southwestern Pennsylvania and northern West Virginia through our wholly owned subsidiary, MarkWest Liberty Midstream. With a total current processing capacity of over 2.5 Bcf/d, we are the largest processor of natural gas in the Marcellus Shale, and have fully integrated gathering, processing, fractionation, storage and marketing operations that support the growing liquids-rich natural gas production in the northeast United States.

Natural Gas Gathering and Processing

We currently operate five processing complexes in our Marcellus segment that include the Houston Complex located in Washington County, Pennsylvania; the Majorsville Complex located in Marshall County, West Virginia; the Mobley Complex located in Wetzel County, West Virginia; the Sherwood Complex located

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in Doddridge County, West Virginia; and the Keystone Complex located in Butler County, Pennsylvania. In addition, we operate two gathering systems: one currently delivering over 520 MMcf/d of natural gas to our Houston and Majorsville Complexes and the other delivering over 110 MMcf/d of natural gas to our Keystone Complex. The gathering and processing capacity at these facilities are supported by long-term fee-based agreements with ten major producer customers.

We currently have over 2.5 Bcf/d processing capacity operational in our Marcellus segment and have approximately 2.0 Bcf/d under development.

NGL Gathering and Fractionation Facilities and Market Outlets

We currently operate 132,000 Bbl/d of combined propane and heavier fractionation capacity at the Houston Complex, the Hopedale Fractionation Facility in Harrison County, Ohio and the Keystone Complex.

The NGLs produced at our Majorsville Complex, Mobley Complex, Sherwood Complex and a third-party’s Fort Beeler processing facility are gathered to the Houston Fractionation Facility or to the Hopedale Fractionation Facility through a system of NGL pipelines to allow for fractionation into purity NGL products. We also operate a truck loading facility that allows for the receipt and fractionation of NGLs from other facilities. Our Houston Complex also has the following infrastructure to provide our customers with marketing and storage services:

· An interconnect with a key interstate pipeline providing a market outlet and storage for the propane produced from this region;

· A large-scale railcar loading facility that expands our market access and allows for long-haul, cost-effective transportation of purity NGLs;

· Significant truck loading facilities that allow for regional marketing of purity NGLs; and

· Additional outlets provided by our access to international markets. Propane is currently being transported by truck or rail to Sunoco Logistics Partners L.P.’s (“Sunoco”) terminal near Philadelphia, Pennsylvania (“Marcus Hook Facility”) where it is loaded onto marine vessels and delivered to international markets. We expect to have the ability to deliver propane to Sunoco’s terminal in Philadelphia via pipeline once Sunoco’s Mariner East project (“Mariner East”), a pipeline and marine project that is expected to originate at our Houston Complex, is placed into service. We expect to begin delivering propane to the Marcus Hook Facility via pipeline in the second half of 2014.

In January 2014, we commenced operation of our Hopedale Fractionation Facility, a 60,000 Bbl/d facility in Harrison County, Ohio. The Hopedale Fractionation Facility is currently owned 60% by MarkWest Liberty Midstream in the Marcellus segment and 40% by the MarkWest Utica EMG in the Utica segment (see our discussion below in the Utica segment). Our Hopedale Fractionation Facility has the following infrastructure to provide to our customers:

· An interconnect with a key interstate pipeline providing a market outlet and storage for the propane produced from this region;

· A large-scale railcar loading facility that expands our market access and allows for long-haul, cost-effective transportation of purity NGLs;

· Significant truck loading facilities that allow for regional marketing of purity NGLs; and

· Connection to our extensive processing system via a NGL gathering pipeline utilized to gather NGLs produced in both our Marcellus and Utica segments for fractionation.

We commenced operation of additional fractionation capacity at our Keystone Complex for propane, truck and rail facilities that will transport heavier NGL products for further fractionation at our other fractionation facilities in the third quarter 2014. We have an additional 60,000 Bbl/d fractionation capacity under development as part of our Hopedale Fractionation Facility.

Our fractionation facilities are supported by long-term, fee-based agreements with our key producer customers.

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Ethane Recovery and Associated Market Outlets

Due to increased natural gas production from the liquids-rich area of the Marcellus Shale, natural gas processors must begin to recover a significant amount of ethane from the gas stream to meet the pipeline gas quality specifications for residue gas and to allow for the ability of producers to benefit from the potential price uplift received from the sale of ethane.

We currently have large scale de-ethanization facilities totaling 94,000 Bbl/d of capacity operational in our Marcellus segment and plan to continue to expand our purity ethane production capacity with approximately 60,000 Bbl/d of capacity under development. We own a purity ethane pipeline from our Majorsville Complex to Houston Complex. We also own a purity ethane pipeline connecting our Keystone Complex to Sunoco’s purity ethane pipeline traveling from our Houston Complex to Sarnia, Ontario, Canada.

Market Outlets

· We began delivering ethane to the Mariner West pipeline from the Houston Complex in the fourth quarter of 2013.

· We began delivering purity ethane to Enterprise Products Partners L.P.’s NGL pipeline from Appalachia to Texas Express Pipeline (“ATEX Pipeline”) in the fourth quarter of 2013.

· Sunoco’s Mariner East project discussed above is also intended to deliver Marcellus purity ethane to the East Coast for further delivery to the various domestic and international markets beginning in mid-2015.

Utica Segment

We formed MarkWest Utica EMG, a joint venture with EMG (see Note 3), to provide gathering, processing, fractionation and marketing services in the liquids-rich corridor of the Utica Shale in eastern Ohio. MarkWest Utica EMG Condensate was formed in December 2013 and is expected to begin providing condensate stabilization and terminalling services in the third quarter of 2014 and is accounted for using the equity method. As disclosed in Note 3, Ohio Gathering was deconsolidated effective June 1, 2014 and is accounted for using the equity method; however, it is consolidated for segment reporting purposes.

Natural Gas Gathering and Processing

MarkWest Utica EMG operates two processing complexes in the Utica Shale with a total capacity of approximately 725 MMcf/d; the Cadiz Complex in Harrison County, Ohio and the Seneca Complex in Noble County, Ohio. We continue to expand our processing infrastructure and have 600 MMcf/d of additional capacity currently under development. In addition, Ohio Gathering operates a natural gas gathering system that currently spans more than 230 miles and provides low- and high-pressure gathering and compression services throughout a five county area in eastern Ohio. Our gathering system and processing facilities are supported by long-term, fee-based agreements with several key producers in the Utica Shale.

Fractionation Facility

Both the Cadiz Complex and Seneca Complex are connected via a NGL gathering pipeline system to the Hopedale Fractionation Facility. As discussed above, Hopedale Fractionation Facility is a 60,000 Bbl/d facility that provides fractionation services for NGLs produced in the Utica and the Marcellus segments.

Ethane Recovery and Associated Market Outlets

We completed a 40,000 Bbl/d de-ethanization facility at our Cadiz Complex in the second quarter of 2014. Ethane produced at our Cadiz Complex will be delivered to the ATEX Pipeline.

Northeast Segment

· Kentucky and southern West Virginia. Our Northeast segment assets include the Kenova, Boldman, Cobb, Kermit and Langley natural gas processing complexes, a NGL pipeline and the Siloam fractionation facility. The Siloam fractionation facility can also be used to provide fractionation services to customers in

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the Marcellus and Utica Shales. In addition, we have two caverns for storing propane at our Siloam facility and we have additional propane storage capacity under a firm-capacity agreement with a third-party.

· 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 complexes 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 natural gas processing complexes in Western Oklahoma. The gathering system includes compression facilities. The majority of the gathered gas is ultimately compressed and delivered to the processing complexes. 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, an equity method investment, or other third-party processors. We agreed to fund our share of a 120 MMcf/d processing plant expansion at Centrahoma’s Stonewall plant in order to support the drilling programs in the Woodford Shale. This expansion commenced operations in the second quarter of 2014. Through another equity method investment, MarkWest Pioneer L.L.C., we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with the Midcontinent Express Pipeline and Gulf Crossing Pipeline at Bennington, Oklahoma, and is designed to provide approximately 638,000 Dth/d of Woodford Shale takeaway capacity. In May 2013, we completed the Buffalo Creek acquisition, which included a 200 MMcf/d cryogenic gas processing plant and approximately 30 miles of rights-of-way for the construction of a high pressure gathering trunk line. The Buffalo Creek processing facility and high pressure gathering trunk line commenced operation in February 2014.

· Javelina. We own and operate the Javelina processing and fractionation facility in Corpus Christi, Texas, which 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, which 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 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. We also operate natural gas gathering pipelines and field compression to support production from Newfield Exploration Co.’s (“Newfield”) West Asherton area of the Eagle Ford Shale in Dimmit County, Texas (“West Asherton facilities”).

The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see above) generated by our assets, by segment, for the six months ended June 30, 2014:

	Marcellus		Utica		Northeast		Southwest
Segment revenue	34	%	5	%	10	%	51	%
Net operating margin	46	%	7	%	11	%	36	%

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

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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. As disclosed in Note 3, Ohio Gathering was deconsolidated effective June 1, 2014 and its financial position as of June 30, 2014 and results of operations are reported under the equity method of accounting as of June 30, 2014 and for the month of June 2014, respectively. However, our Chief Executive Officer and “chief operating decision maker” continues to view the Utica Segment inclusive of Ohio Gathering, and reviews its financial information as if they are still consolidated. The tables below present financial information, as evaluated by management, for the reported segments for the three and six months ended June 30, 2014 and 2013.

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

Three months ended June 30, 2014 compared to three months ended June 30, 2013

Marcellus

	Three months ended June 30,
	2014		2013		$ Change		% Change
			(in thousands)
Segment revenue	$	183,734	$	120,057	$	63,677	53	%
Purchased product costs	39,710		16,993		22,717		134	%
Net operating margin	144,024		103,064		40,960		40	%
Facility expenses	33,755		22,272		11,483		52	%

Operating income before items not allocated to segments	$	110,269	$	80,792	$	29,477	36	%

Segment Revenue. Revenue increased due to the ongoing expansion of the Marcellus segment operations that resulted in increased gathered, processed and fractionated volumes. Revenue increased approximately $36.3 million due to the increased capacities at the Sherwood, Mobley, Keystone and Majorsville Complexes. Revenue also increased approximately $24.0 million related to a 68% increase in NGLs fractionated.

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

Net Operating Margin. Net operating margin mainly increased as the volume of natural gas gathered, processed, and heavier NGL products fractionated increased by 10%, 76% and 68%, respectively. Approximately 87% of the net operating margin was earned under fee-based contracts.

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

Utica

	Three months ended June 30,
	2014		2013			$ Change		% Change
			(in thousands)
Segment revenue	$	30,826	$	3,594		$	27,232	758	%
Purchased product costs	7,353		—			7,353		N/A
Net operating margin	23,473		3,594			19,879		553	%
Facility expenses	12,174		6,412			5,762		90	%
Portion of operating income (loss) attributable to non-controlling interests	4,687		(1,143		)	5,830		510	%
Operating income (loss) before items not allocated to segments	$	6,612	$	(1,675	)	$	8,287	495	%

The results of operations for the quarter ended June 30, 2014 include our operations in the Utica Shale areas of eastern Ohio, including gas gathering revenues of Ohio Gathering, which was an unconsolidated subsidiary effective June 1, 2014 (see Note 3). The first phase of operations began in the third quarter of 2012 and remained in the early stages of development at June 30, 2013. Operations will continue to grow as we add 200 MMcf/d cryogenic processing capacity through the end of 2014.

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Segment Revenue. Revenue increased $27.2 million, of which $7.8 million was due to processing fee revenue increases primarily from a 535% increase in volumes. Approximately $6.1 million of the increase was due to an increase in gathering and compression fees revenue from a 308% increase in volumes. Approximately $6.8 million of the increase was due to NGL sales of local inventory and $3.5 million of the increase was due to an increase in fractionation fees resulting from the increase in fractionation volumes.

Purchased Product Costs. Purchased product costs increased due to an increase in inventory sold and a decline in the value of line fill.

Net Operating Margin. Net operating margin increased due to an overall increase in operations in the first quarter of 2014 compared to the same period in 2013. All of our gathering, processing and fractionating contracts in the Utica segment are fee based and the increase in net operating margin was due to the volume of natural gas gathered and processed increasing by 308% and 535%, respectively. Fractionated volumes increased due to the Hopedale fractionation plant commencing operations in January 2014.

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

Northeast

	Three months ended June 30,
	2014		2013		$ Change			% Change
	(in thousands)
Segment revenue	$	43,777	$	45,365	$	(1,588	)	(4	)%
Purchased product costs	15,169		15,126		43			0	%
Net operating margin	28,608		30,239		(1,631		)	(5	)%
Facility expenses	8,509		6,655		1,854			28	%
Operating income before items not allocated to segments	$	20,099	$	23,584	$	(3,485	)	(15	)%

Segment Revenue. Revenue decreased due to an 8% decrease in NGL sales volumes over the same period in 2013, partially offset by an increase in NGL sales prices of approximately 3% compared to the same period in 2013.

Purchased Product Costs. Purchased product costs increased slightly due to an increase in weighted average cost of goods sold due to increased natural gas purchased prices, offset by lower sales volumes.

Net Operating Margin. Net operating margin decreased due to an 8% decline of NGL sales volumes and overall frac spread margins, which decreased by approximately 2% as natural gas prices increased. Approximately 55% of the net operating margin was derived from keep-whole contracts.

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

Southwest

	Three months ended June 30,
	2014		2013		$ Change			% Change
			(in thousands)
Segment revenue	$	271,140	$	227,842	$	43,298		19	%
Purchased product costs	153,628		123,240		30,388			25	%
Net operating margin	117,512		104,602		12,910			12	%
Facility expenses	34,354		29,778		4,576			15	%
Portion of operating income attributable to non-controlling interests	6		53		(47		)	(89	)%
Operating income before items not allocated to segments	$	83,152	$	74,771	$	8,381		11	%

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Segment Revenue. Revenue increased due to higher NGL sales, gas sales and higher fee-based revenue. NGL sales increased approximately $20.1 million due to increased volumes in our East Texas and Western Oklahoma areas of 27% and 33%, respectively. Processing fee revenue increased by approximately $8.1 million due to an increase in volumes in Western Oklahoma and East Texas of 56% and 6%, respectively. The 56% increase in the Western Oklahoma area primarily relates to the new Buffalo Creek processing plant that began processing in February 2014. Gas sales increased approximately $4.3 million mainly due to a combination of price and volume increases in the Southeast Oklahoma area and operating in higher percentage of ethane rejection than the same period in 2013. Gathering fee revenue increased by approximately $5.3 million due to an 8% increase of gathered volumes.

Purchased Product Costs. Purchased product costs increased due to higher NGL purchases of approximately $10.9 million related to an increase in volumes processed and pricing in the East Texas area. Approximately $8.5 million increased due to higher NGL purchases in our Western Oklahoma area due to higher volumes in the Western Oklahoma area for three months ended June 30, 2014 compared to the same period in 2013. Approximately $8.1 million increased due to increases in price in Southeast Oklahoma and impacts of certain recovery elections by producer customers for the three months ended June 30, 2014 compared to the same period in 2013.

Net Operating Margin. Net operating margin increased mainly due an increase of 17% in natural gas processed and an 8% increase in gathered volumes. The Buffalo Creek plant contributed to the increased volumes.

Facility Expenses. Facility expenses increased primarily due to $1.8 million of expenses related to the Buffalo Creek and West Asherton facilities becoming operational in 2013, as well as an increase of approximately $2.0 million related to compressor repairs and maintenance in Javelina.

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Reconciliation of Segment Operating Income to Consolidated Income Before Provision for Income Tax

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income before provision for income tax for the three months ended June 30, 2014 and 2013, respectively. The ensuing items listed below the Total segment revenue and Operating income before items not allocated to segments lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Three months ended June 30,
	2014			2013			$ Change			% Change
				(in thousands)
Total segment revenue	$	528,577		$	396,858		$	131,719		33	%
Derivative(loss) gain not allocated to segments	(6,753		)	19,699			(26,452		)	(134	)%
Revenue adjustment for unconsolidated affiliate	(3,833		)	—			(3,833		)	N/A
Revenue deferral adjustment and other	375			(1,437		)	1,812			126	%
Total revenue	$	518,366		$	415,120		$	103,246		25	%

Operating income before items not allocated to segments	$	220,132		$	177,472		$	42,660		24	%
Portion of operating income (loss) attributable to non-controlling interests	4,184			(1,090		)	5,274			484	%
Derivative (loss) gain not allocated to segments	(20,762		)	39,331			(60,093		)	(153	)%
Revenue adjustment for unconsolidated affiliate	(3,833		)	—			(3,833		)	N/A
Revenue deferral adjustment and other	375			(1,437		)	1,812			126	%
Compensation expense included in facility expenses not allocated to segments	(903		)	(368		)	(535		)	145	%
Facility expense and purchase product cost adjustments for unconsolidated affiliate	2,598			—			2,598			N/A
Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate	509			—			509			N/A
Facility expenses adjustments	2,688			2,688			—			0	%
Selling, general and administrative expenses	(27,701		)	(25,499		)	(2,202		)	9	%
Depreciation	(104,078		)	(71,562		)	(32,516		)	45	%
Amortization of intangible assets	(15,965		)	(17,092		)	1,127			(7	)%
(Loss) gain on disposal of property, plant and equipment	(1,450		)	37,736			(39,186		)	(104	)%
Accretion of asset retirement obligations	(168		)	(157		)	(11		)	7	%
Income from operations	55,626			140,022			(84,396		)	(60	)%
Equity in (loss) earnings from unconsolidated affiliates	(721		)	430			(1,151		)	(268	)%
Interest income	10			62			(52		)	(84	)%
Interest expense	(43,391		)	(36,955		)	(6,436		)	17	%
Amortization of deferred financing costs and debt discount (a component of interest expense)	(1,449		)	(1,784		)	335			(19	)%
Miscellaneous income, net	33			6			27			450	%
Income before provision for income tax	$	10,108		$	101,781		(91,673		)	(90	)%

Derivative (Loss) Gain Not Allocated to Segments. Unrealized loss from the change in fair value of our derivative instruments was $18.8 million for the three months ended June 30, 2014 compared to an unrealized gain of $37.3 million for the same period in 2013. Realized loss from the settlement of our derivative instruments was $1.9 million for the three months ended June 30, 2014 compared to a realized gain of $2.0 million for the same period in 2013. The total change of $60.1 million is due primarily to volatility in commodity prices.

Revenue adjustment for unconsolidated affiliate. Revenue adjustment for unconsolidated affiliate relates to Ohio Gathering revenues. The chief operating decision maker and management includes these to evaluate the segment performance as we continue to operate and manage Ohio Gathering operations, therefore, the impact of the revenue is included for segment reporting purposes, but removed to reconcile to GAAP (See Notes 3 and 14).

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Revenue Deferral Adjustment and Other. Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the “chief operating decision maker” and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the three months ended June 30, 2014, 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 June 30, 2013, approximately $0.2 million and $1.4 million of the revenue deferral adjustment was 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 unconsolidated affiliates of $2.1 million for the three months ended June 30, 2014 compared to $0.2 million for the three months ended June 30, 2013.

Facility expense and purchase product cost adjustments for unconsolidated affiliate. Facility expense and purchase product cost adjustments for unconsolidated affiliate relates to Ohio Gathering (see discussion above in Revenue adjustment for unconsolidated affiliate, Note 3 and Note 14).

Portion of operating loss attributable to non-controlling interests of unconsolidated affiliate. Portion of operating loss attributable to non-controlling interests of unconsolidated affiliate relates to Summit’s portion of Ohio Gathering’s operating loss, which occurs because segment operating income is reported as if Ohio Gathering was being consolidated (see discussion above in Revenue adjustment for unconsolidated affiliate, Note 3 and Note 14).

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

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

Depreciation. Depreciation increased due to additional projects completed during late 2013 through the first quarter of 2014 in the Utica and Marcellus segments.

Interest Expense. Interest expense increased due to the greater amount in the 2014 ending balance of approximately $441.2 million in outstanding borrowings related to our Credit Facility in 2014, offset by decreases in our capitalized interest of approximately $2.2 million.

Six months ended June 30, 2014 compared to six months ended June 30, 2013

Marcellus

	Six months ended June 30,
	2014		2013		$ Change		% Change
			(in thousands)
Segment revenue	$	358,893	$	228,554	$	130,339	57	%
Purchased product costs	74,000		35,786		38,214		107	%
Net operating margin	284,893		192,768		92,125		48	%
Facility expenses	69,228		44,908		24,320		54	%

Operating income before items not allocated to segments	$	215,665	$	147,860	$	67,805	46	%

Segment Revenue. Revenue increased due to the ongoing expansion of the Marcellus segment operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $81.3 million due to an increase in gathering, processing and fractionation fees due to the increased capacities at the Sherwood, Mobley, Keystone and Majorsville Complexes. Revenue also increased approximately $42.5 million primarily due to a 135% increase in NGLs local inventory sold.

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

Net Operating Margin. Net operating margin increased as the volume of natural gas gathered, processed and fractionated increased by 14%, 86% and 187%, respectively. Approximately 84% of the net operating margin is earned under fee-based contracts.

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

Utica

	Six months ended June 30,
	2014		2013			$ Change		% Change
			(in thousands)
Segment revenue	$	54,592	$	4,217		$	50,375	1,195	%
Purchased product costs	11,488		—			11,488		N/A
Net operating margin	43,104		4,217			38,887		922	%
Facility expenses	24,026		10,374			13,652		132	%
Portion of operating income (loss) attributable to non-controlling interests	7,823		(2,482		)	10,305		415	%
Operating income (loss) before items not allocated to segments	$	11,255	$	(3,675	)	$	14,930	406	%

The results of operations for the six months ended June 30, 2014 include our operations in the Utica Shale areas of eastern Ohio, including gas gathering revenues of Ohio Gathering, which was our unconsolidated subsidiary effective June 1, 2014 (see Note 3). The first phase of operations began in the third quarter of 2012 and remained in the early stages of development at June 30, 2013. Operations will continue to grow as we add 200 MMcf/d cryogenic capacity through the end of 2014.

Segment Revenue. Revenue increased $50.4 million, $15.3 million of which was due to processing fee revenue increases due to the fact that we were processing for eight producer customers during the first six months of 2014 as compared to three in the first half of 2013. Approximately $11.5 million of the increase was due to an increase in gathering fees revenue as we were gathering for seven producers in the first six months of 2014 as compared to three in the first six months of 2013. Approximately $9.7 million of the increase was due to NGL sales of local inventory, $6.2 million of the increase was due to an increase in fractionation fees resulting from the increase in fractionation volumes and $4.3 million of the increase was due to increases in compression fees resulting from the increase in gathered volumes. Approximately $3.3 million of the increase related to the increase in marketing and transportation fees.

Purchased Product Costs. Purchased product costs increased due to an increase in inventory sold, a decline in the value of line fill and amortization of approximately $0.9 million in deferred contract costs.

Net Operating Margin. Net operating margin increased due to an overall increase in operations in the first half of 2014 compared to the same period in 2013. All of our gathering and processing contracts in the Utica segment are fee based and the increase in net operating margin was due to the volume of natural gas gathered, processed and fractionated increasing by 564%, 903% and 100%, respectively.

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

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Northeast

	Six months ended June 30,
	2014		2013		$ Change			% Change
	(in thousands)
Segment revenue	$	105,030	$	102,701	$	2,329		2	%
Purchased product costs	35,624		34,788		836			2	%
Net operating margin	69,406		67,913		1,493			2	%
Facility expenses	15,623		13,179		2,444			19	%
Operating income before items not allocated to segments	$	53,783	$	54,734	$	(951	)	(2	)%

Segment Revenue. Revenue increased due to higher NGL sales prices, partially offset by approximately a 14% decrease in NGL sales volumes over the same period in 2013.

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

Net Operating Margin. Net operating margin increased due to overall frac spread margins, which increased by approximately 17.5% as compared to the six months ended June 30, 2013, partially offset by a decline of NGL sales volumes. Approximately 63% of the net operating margin was derived from keep-whole contracts.

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

Southwest

	Six months ended June 30,
	2014		2013		$ Change			% Change
			(in thousands)
Segment revenue	$	530,470	$	436,208	$	94,262		22	%
Purchased product costs	306,312		237,342		68,970			29	%
Net operating margin	224,158		198,866		25,292			13	%
Facility expenses	66,876		58,468		8,408			14	%
Portion of operating income attributable to non-controlling interests	5		117		(112		)	(96	)%
Operating income before items not allocated to segments	$	157,277	$	140,281	$	16,996		12	%

Segment Revenue. Revenue increased due to higher NGL sales, gas sales and higher fee-based revenue. NGL sales increased approximately $52.9 million primarily due to increased volumes in our East Texas and Western Oklahoma areas of 28% and 14%, respectively. Gas sales increased approximately $7.4 million and approximately $7.2 million in the Western Oklahoma and Southeast Oklahoma areas, respectively, due to higher gas prices and operating in higher percentage of ethane rejection than the same period in 2013. Processing fee revenue increased by approximately $12.7 million due to an increase in volumes in Western Oklahoma, Southeast Oklahoma and East Texas of 43%, 7% and 7%, respectively. The 43% increase in the Western Oklahoma area primarily relates to the new Buffalo Creek processing plant that began processing in February 2014. Gathering fee revenue increased by approximately $5.5 million due to Western Oklahoma and East Texas, where gathered volumes increased 53% and 2%, respectively.

Purchased Product Costs. Purchased product costs increased due to higher NGL purchases of approximately $26.6 million related to the East Texas area because of increasing volumes processed, changing contractual terms and increasing pricing. Western Oklahoma NGL purchases increased approximately $25.7 million due to higher volumes and approximately 18% higher prices in the Western Oklahoma area for the six months ended June 30, 2014 compared to the same period in 2013. Approximately $9.7 million increase is due to NGL purchases in Southeast Oklahoma due to 88% higher prices compared to the same period in 2013. Gas purchases increased by approximately $9.2 million in our Western Oklahoma area primarily related to approximately a 37% increase in gas prices for the six months ended June 30, 2014 compared to the same period in 2013. These increases were partially offset by lower processing expense of $1.9 million in our Western Oklahoma area.

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Net Operating Margin. Net operating margin increased mainly due to increases of 43%, 7% and 7% in natural gas processed in Western Oklahoma, East Texas and Southeast Oklahoma, respectively. The Buffalo Creek plant began operations in February of 2014 contributed to the higher processed volumes in Western Oklahoma.

Facility Expenses. Facility expenses increased primarily due to $4.1 million of expenses related to the Buffalo Creek and West Asherton facilities becoming operational in the second half of 2013, as well as an increase of approximately $2.2 million related to long-term compressor repairs and maintenance in Javelina.

Reconciliation of Segment Operating Income to Consolidated Income Before Provision for Income Tax

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income before provision for income tax for the six months ended June 30, 2014 and 2013, respectively. The ensuing items listed below the Total segment revenue and Operating income before items not allocated to segments lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Six months ended June 30,
	2014			2013			$ Change			% Change
				(in thousands)
Total segment revenue	$	1,046,514		$	771,680		$	274,834		36	%
Derivative (loss) gain not allocated to segments	(10,720		)	19,514			(30,234		)	(155	)%
Revenue adjustment for unconsolidated affiliate	(3,833		)	—			(3,833		)	N/A
Revenue deferral adjustment and other	(1,119		)	(2,801		)	1,682			(60	)%
Total revenue	$	1,030,842		$	788,393		$	242,449		31	%

Operating income before items not allocated to segments	$	437,980		$	339,200		$	98,780		29	%
Portion of operating income (loss) attributable to non-controlling interests	7,319			(2,365		)	9,684			409	%
Derivative (loss) gain not allocated to segments	(16,663		)	50,182			(66,845		)	(133	)%
Revenue adjustment for unconsolidated affiliate	(3,833		)	—			(3,833		)	N/A
Revenue deferral adjustment and other	(1,119		)	(2,801		)	1,682			(60	)%
Compensation expense included in facility expenses not allocated to segments	(1,906		)	(754		)	(1,152		)	153	%
Facility expense and purchase product cost adjustments for unconsolidated affiliate	2,598			—			2,598			N/A
Portion of operating loss attributable to non-controlling interests of unconsolidated affiliate	509			—			509			N/A
Facility expenses adjustments	5,376			5,376			—			0	%
Selling, general and administrative expenses	(62,991		)	(50,741		)	(12,250		)	24	%
Depreciation	(206,007		)	(139,579		)	(66,428		)	48	%
Amortization of intangible assets	(31,943		)	(31,922		)	(21		)	0	%
(Loss) gain on disposal of property, plant and equipment	(1,357		)	37,598			(38,955		)	(104	)%
Accretion of asset retirement obligations	(336		)	(509		)	173			(34	)%
Income from operations	127,627			203,685			(76,058		)	(37	)%
Equity in loss from unconsolidated affiliates	(471		)	665			(1,136		)	(171	)%
Interest income	19			211			(192		)	(91	)%
Interest expense	(84,375		)	(75,291		)	(9,084		)	12	%
Amortization of deferred financing costs and debt discount (a component of interest expense)	(4,273		)	(3,614		)	(659		)	18	%
Loss on redemption of debt	—			(38,455		)	38,455			(100	)%
Miscellaneous income, net	43			6			37			617	%
Income before provision for income tax	$	38,570		$	87,207		$	(48,637	)	(56	)%

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Derivative (Loss) Gain Not Allocated to Segments. Unrealized loss from the change in fair value of our derivative instruments was $7.0 million for the six months ended June 30, 2014 compared to an unrealized gain of $46.3 million for the same period in 2013. Realized loss from the settlement of our derivative instruments was $9.6 million for the six months ended June 30, 2014 compared to a realized gain of $3.9 million for the same period in 2013. The total change of $66.8 million is due primarily to volatility in commodity prices.

Revenue adjustment for unconsolidated affiliate. Revenue adjustment for unconsolidated affiliate relates to Ohio Gathering revenues that the chief operating decision maker and management evaluate the segment performance based on Ohio Gathering being consolidated as we continue to operate and manage operations, therefore, the impact of the revenue is included for segment reporting purposes, but removed to reconcile to GAAP (See Notes 3 and 14).

Revenue Deferral Adjustment and Other. Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the six months ended June 30, 2014, approximately $0.4 million and $3.4 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. For the six months ended June 30, 2013, approximately $0.4 million and $3.0 million of the revenue deferral adjustment was 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 unconsolidated affiliates of $2.7 million for the six months ended June 30, 2014 compared to $0.6 million for the six months ended June 30, 2013.

Facility expense and purchase product cost adjustments for unconsolidated affiliate. Facility expense and purchase product cost adjustments for unconsolidated affiliate relate to Ohio Gathering (see discussion above in Revenue adjustment for unconsolidated affiliate, Note 3 and Note 14).

Portion of operating loss income attributable to non-controlling interests of unconsolidated affiliate. Portion of operating loss attributable to non-controlling interests of unconsolidated affiliate relates to Summit’s portion of Ohio Gathering’s operating loss, which occurs because segment operating income is reported as if Ohio Gathering was being consolidated (see discussion above in Revenue adjustment for unconsolidated affiliate, Note 3 and Note 14).

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

Depreciation. Depreciation increased due to additional projects completed during late 2013 through the first quarter of 2014 in the Utica and Marcellus segments.

Interest Expense. Interest expense increased due to the greater amount in the 2014 ending balance of approximately $441.2 million in outstanding borrowings, which fluctuated throughout 2014 related to our Credit Facility, offset by decreases in our capitalized interest of approximately $6.4 million and a decrease in interest rates on our long-term debt year over year due to the pay down of debt in January 2013.

Loss on Redemption of Debt. The decrease in loss on redemption of debt was related to the redemption of the 2018 Senior Notes, a portion of the 2021 Senior Notes and a portion of the 2022 Senior Notes that occurred in the first quarter of 2013, while no such redemptions of debt occurred during the first half of 2014.

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Operating Data

	Three months ended June 30,				Six months ended June 30,
	2014	2013	% Change		2014	2013	% Change
Marcellus
Gathering system throughput(Mcf/d) (1)	599,500	544,000	10	%	600,500	526,700	14	%
Natural gas processed (Mcf/d)	1,823,200	1,033,700	76	%	1,732,500	931,400	86	%

C2 (purity ethane) produced (Bbl/d)	45,900	—	N/A		47,400	—	N/A
C3+ NGLs fractionated (Bbl/d) (2)	82,200	48,900	68	%	76,200	43,000	77	%
Total NGLs fractionated (Bbl/d)	128,100	48,900	162	%	123,600	43,000	187	%

Utica
Gathering system throughput (Mcf/d)	188,700	46,300	308	%	184,700	27,800	564	%
Natural gas processed (Mcf/d) (3)	293,800	46,300	535	%	272,700	27,200	903	%
C3+ NGLs fractionated (Bbl/d) (2)	13,500	—	N/A		12,900	—	N/A

Northeast
Natural gas processed (Mcf/d)	281,500	296,400	(5	)%	268,600	299,500	(10	)%
NGLs fractionated (Bbl/d) (4)	17,500	18,100	(3	)%	17,500	17,600	(1	)%

Keep-whole NGL sales (gallons, in thousands)	24,800	27,100	(8	)%	57,000	64,500	(12	)%
Percent-of-proceeds NGL sales (gallons, in thousands)	29,900	32,200	(7	)%	56,000	67,100	(17	)%
Total NGL sales (gallons, in thousands) (5)	54,700	59,300	(8	)%	113,000	131,600	(14	)%
Crude oil transported for a fee (Bbl/d)	10,600	9,700	9	%	10,200	10,000	2	%

Southwest
East Texas gathering systems throughput (Mcf/d)	549,500	521,700	5	%	522,800	510,500	2	%
East Texas natural gas processed (Mcf/d)	398,500	377,600	6	%	383,400	358,600	7	%
East Texas NGL sales (gallons, in thousands) (6)	109,500	86,200	27	%	203,400	158,400	28	%

Western Oklahoma gathering system throughput (Mcf/d) (7)	348,200	220,000	58	%	322,700	211,400	53	%
Western Oklahoma natural gas processed (Mcf/d)	296,300	189,900	56	%	269,800	188,100	43	%
Western Oklahoma NGL sales (gallons, in thousands) (6)	56,900	42,900	33	%	111,300	97,700	14	%

Southeast Oklahoma gathering systems throughput (Mcf/d)	414,500	473,300	(12	)%	398,200	467,300	(15	)%
Southeast Oklahoma natural gas processed (Mcf/d) (8)	186,600	160,400	16	%	167,000	155,800	7	%
Southeast Oklahoma NGL sales (gallons, in thousands)	29,200	54,000	(46	)%	50,200	93,300	(46	)%

Other Southwest gathering system throughput (Mcf/d) (9)	48,900	39,900	23	%	47,900	30,300	58	%

Gulf Coast refinery off-gas processed (Mcf/d)	112,000	117,700	(5	)%	111,300	106,600	4	%
Gulf Coast liquids fractionated (Bbl/d) (10)	21,000	22,100	(5	)%	20,200	19,700	3	%
Gulf Coast NGL sales (gallons, in thousands) (10)	80,300	84,600	(5	)%	153,300	149,700	2	%

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

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

(3) Utica operations began in August 2013.

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

(5) Represents sales at the Siloam fractionator. The total sales exclude approximately 8,757,000 gallons and 6,611,000 gallons sold by the Northeast on behalf of Marcellus for the three months ended June 30, 2014 and 2013, respectively. The total sales exclude approximately 22,010,000 gallons and 6,818,000 gallons sold by the Northeast on behalf of Marcellus for the six months ended June 30, 2014 and 2013, respectively.

(6) Excludes gallons processed in conjunction with take in kind contracts for the three and six months ended June 30, 2014 and June 30, 2013, respectively, as shown below.

Gallons processed in conjunction with take	Three months ended June 30,		Six months ended June 30,
in kind contracts	2014	2013	2014	2013
East Texas	—	3,989,000	318,000	12,351,000
Western Oklahoma	41,969,000	—	53,685,000	—

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

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

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

(10) Excludes Hydrogen volumes.

Liquidity and Capital Resources

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

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

	2014 Full Year Plan						Actual
							Six months ended
	Low			High			June 30, 2014
Total growth capital (1)	$	2,550		$	2,900		$	1,306
Joint venture partner’s estimated share of growth capital	(550		)	(600		)	(120		)
Partnership share of growth capital	$	2,000		$	2,300		$	1,186

(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 actual includes one month capital of approximately $40 million related to Ohio Gathering, our unconsolidated affiliate effective June 1, 2014. Growth capital excludes expenditures for third-party acquisitions and equity

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investments. Maintenance capital was approximately $9.8 million for the six months ended June 30, 2014. 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 upon the conversion of the Class B units into common units; 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 July 30, 2014, our credit ratings for our Senior Notes were Ba2 with a Stable outlook by Moody’s Investors Service and BB with a Stable outlook by Standard & Poor’s. Our Credit Facility is investment grade rated BBB- by Standard & Poor’s. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

Debt Financing Activities

On March 20, 2014, we amended the Credit Facility to increase the total borrowing capacity to $1.3 billion, extend the maturity by approximately 18 months to March 20, 2019, amend the pricing terms, expand the existing accordion option from $250 million to $500 million and provide us with the right to release collateral securing the Credit Facility once our Index Debt has received an investment grade rating from Standard & Poor’s equal to or more favorable than BBB- (stable) and from Moody’s equal to or more favorable than Baa3 (stable) and our Total Leverage Ratio is not greater than 5.00 to 1.00. We incurred approximately $1.9 million of deferred financing costs associated with modifications of the Credit Facility during the six months ended June 30, 2014.

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

Under the provisions of the Credit Facility, we are subject to a number of restrictions and covenants. As of June 30, 2014, we were in compliance with all of our debt covenants and we expect to remain in compliance for at least the next twelve months. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of July 30, 2014, we had approximately $150.0 million borrowings outstanding and approximately $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $1,138.7 million of unused capacity, of which approximately $645 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,

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defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.

The Credit Facility limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. Under the Credit Facility, neither we nor the bank can require margin calls for outstanding derivative positions. As of July 30, 2014, all of our financial derivative positions are with members of the syndicated bank group and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to enter into derivative instruments without utilizing cash for margin calls or requiring the use of letters of credit. We believe the recent Dodd-Frank legislation will not change our ability to enter into derivatives without utilizing margin calls.

Equity Financing Activities

On September 5, 2013, we and M&R MWE Liberty, LLC (the “Selling Unitholder”) entered into an Equity Distribution Agreement with the 2013 Manager that established the September 2013 ATM pursuant to which we may sell from time to time through the 2013 Manager, as our sales agent, common units having an aggregate offering price of up to $1 billion. In addition, the Selling Unitholder may sell from time to time through the 2013 Manager up to 794,761 common units. During the six months ended June 30, 2014, we sold an aggregate of 4.2 million common units under the September 2013 ATM, receiving net proceeds of approximately $272 million after deducting approximately $3.5 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general Partnership purposes. During the six months ended June 30, 2014, the Selling Unitholder sold an aggregate of 222,897 of their common units under the September 2013 ATM Agreement, receiving net proceeds of approximately $14.3 million after deducting approximately $0.1 million in manager fees. We completed the September 2013 ATM on March 31, 2014.

On March 11, 2014, we and the Selling Unitholder entered into an Equity Distribution Agreement with the 2014 Managers that established the March 2014 ATM pursuant to which we may sell from time to time through the 2014 Managers, as our sales agents, common units having an aggregate offering price of up to $1.2 billion. In addition, the Selling Unitholder may sell from time to time through the 2014 Managers up to 4,031,075 common units (including 3,990,878 common units that were issued on July 1, 2014 upon conversion of an equal number of the Selling Unitholder’s Class B Units, such units being the “Class B Units”). During the six months ended June 30, 2014, we sold an aggregate of approximately 7.0 million common units under the March 2014 ATM Agreement, receiving net proceeds of approximately $440 million after deducting approximately $3.5 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general Partnership purposes.

For the first six months 2014, we sold an aggregate of approximately 11.3 million units and received net proceeds of approximately $712 million under both ATM programs.

Class B Common Units

Approximately four million Class B Units converted on July 1, 2014. All of our Class B Units were issued to and are held by M&R MWE Liberty, LLC, an affiliate of EMG, as part of our December 31, 2011 acquisition of the non-controlling interest in MarkWest Liberty Midstream. The remaining Class B Units will convert to common units on a one-for-one basis in three equal installments beginning on July 1, 2015 and each of the next two anniversaries of such date. Class B Units share in our income and losses and are not entitled to participate in any distributions of available cash prior to their conversion.

Joint Venture Arrangements

Pursuant to the Amended Utica LLC Agreement, EMG was obligated to fund the first $950.0 million of capital required by MarkWest Utica EMG and they completed this funding commitment in May 2013. We began funding MarkWest Utica EMG in July 2013 and have contributed approximately $944.1 million as of June 30, 2014. We are required to contribute 100% of the additional capital required by MarkWest Utica EMG until the aggregate contributions from us and EMG equal $2.0 billion. For further discussion of the funding requirements after $2.0 billion has been contributed to MarkWest Utica EMG, see Note 3 of the Notes to these Condensed Consolidated Financial Statements. In December 2013, we and EMG formed Utica Condensate. EMG is obligated to provide up to the first $100 million of the initial funding to Utica Condensate and is expected to provide 45% of the total capital required during 2014. See Note 3 of the Notes to these Condensed Consolidated Financial Statements for further discussion of the funding obligations for Utica Condensate. Effective June 1, 2014, Summit exercised the Ohio Gathering Option and increased its equity ownership from less than 1% to approximately 40% through a cash investment of approximately $324.7 million that was received on May 30, 2014 and a true-up payment of approximately $16.5 million that was contributed in July 2014.

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Liquidity Risks and Uncertainties

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

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

· unexpected changes in the production from our producer customers’ wells or in our producer customers’ drilling schedules, although this impact may be mitigated where we have minimum volume commitments;

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

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

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

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

In order to access alternative NGL market outlets for the increasing supply of NGLs produced in the United States, we may be required to make significant minimum volume commitments for transportation or terminalling capacity, with take or pay payments or deficiency fees if the minimum volume is not delivered. In many cases, we market NGLs on behalf of our producer customers, and as a result, we may make such commitments on behalf of our producer customers, and we expect to be able to pass such commitments through to our producer customers. However, if we were unable to do so, our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions may also be adversely impacted.

Cash Flow

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

	Six months ended June 30,
	2014			2013			Change
Net cash provided by operating activities	$	356,823		$	177,596		$	179,227
Net cash used in investing activities	(1,005,158		)	(1,435,021		)	429,863
Net cash provided by financing activities	862,442			1,266,223			(403,781		)

Net cash provided by operating activities increased primarily due to a $98.8 million increase in segment operating income before items not allocated to segments as a result of our expanded operations in all segments and an increase of approximately $97.1 million change in working capital primarily due to approximately a $94.8 million increase in accounts payable and accrued liabilities as a result of the timing on payments of certain expenditures outstanding as of June 30, 2014.

Net cash used in investing activities decreased primarily due to $324.7 million in proceeds related to the exercise of the Ohio Gathering Option by Summit, a decrease in capital expenditures of $159.8 million and by proceeds of approximately $17 million from the 2013 asset sale to an unconsolidated subsidiary, partially offset by a release of $25.5 million of restricted cash.

Net cash provided by financing activities decreased primarily due to a $685.2 million decrease in contributions from non-controlling interest holders, a $63.4 million increase in distributions to unit holders, a $14.2 million decrease in net borrowings, partially offset by a $363.5 million increase in proceeds from public equity offerings.

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Contractual Obligations

We periodically make other commitments and become subject to other contractual obligations that we believe to be routine in nature and incidental to the operation of the business. Management believes that such routine commitments and contractual obligations do not have a material impact on our business, financial condition or results of operations. As of June 30, 2014, our purchase obligations were $497.2 million compared to our obligations of $681.8 million as of December 31, 2013. Purchase obligations represent purchase orders and contracts related to property, plant and equipment. We have executed transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which will range from three to ten years. We expect to be able to pass any minimum payment commitments through to producer customers. Estimates of our obligations for minimum payment commitments related to these agreements are as follows (in thousands):

Total Obligation (1)		Due in 2014		Due in 2015-2016		Due in 2017-2018		Thereafter

$	601,614	$	3,062	$	87,322	$	122,423	$	388,807

(1) Minimum fees due under transportation agreements do not include potential future fee increases as required by FERC.

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; acquisitions and income taxes.

There have not been any material changes during the three or six months ended June 30, 2014 to the methodology applied by management for critical accounting policies previously disclosed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies in our Annual Report on Form 10-K for the year ended December 31, 2013.

Recent Accounting Pronouncements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

The information about commodity price risk for the three months ended June 30, 2014 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2013.

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Outstanding Derivative Contracts

The following table provides information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at June 30, 2014, including the weighted average prices (“WAVG”):

WTI Crude Collars	Volumes (Bbl/d)	WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2014	1,415	$	90.14	$	108.56	$	(359	)

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2014	772	$	92.56	$	(1,499	)
2015	1,205	90.09		(3,068		)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	115,021	$	0.92	$	(3,235	)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	15,312	$	1.46	$	317

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	40,055	$	1.37	$	406

The following tables provide information on the volume of our taxable subsidiary’s commodity derivative activity for positions related to keep-whole price risk at June 30, 2014, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)	Fair Value (in thousands)
2014	151	89.09	$	(390	)

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2014	8,593	$	4.95	$	(995	)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	91,416	$	1.07	$	(138	)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	7,414	$	1.45	$	140

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	20,125	$	1.38	$	351

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	7,085	$	2.32	$	173

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The following tables provide information on the volume of MarkWest Liberty Midstream’s commodity derivative activity for positions related to long liquids price risk at June 30, 2014, including the WAVG:

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2014	354	$	91.00	$	(788	)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	91,719	$	1.08	$	82

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	8,634	$	1.47	$	185

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	24,896	$	1.35	$	293

Natural Gasoline	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2014	31,581	$	2.13	$	(307	)

The following table provides information on the derivative positions related to long liquids and keep-whole price risk that we have entered into subsequent to June 30, 2014, including the WAVG:

Propane Collars	Volumes (Gal/d)	WAVG Floor (Per Gal)		WAVG Cap (Per Gal)
2015 (Jan-Mar)	7,464	$	0.95	$	1.18

The following tables provide information on the derivative positions of MarkWest Liberty Midstream related to long liquids price risk that we have entered into subsequent to June 30, 2014, including the WAVG:

Propane Collars	Volumes (Gal/d)	WAVG Floor (Per Gal)		WAVG Cap (Per Gal)
2015 (Jan-Mar)	21,863	$	0.95	$	1.18

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2014 (Oct-Dec)	42,165	$	1.07
2015 (Jan-Mar)	49,913	$	1.08

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 June 30, 2015 to December 31, 2022. As of June 30, 2014, the estimated fair value of this contract was a liability of $97.8 million and the recorded value was a liability of $44.3 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception on February 1, 2011 is deemed to be allocable to the host processing contract and therefore not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of June 30, 2014 (in thousands):

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Fair value of commodity contract	$	97,838
Inception value for period from April 1, 2015 to December 31, 2022	(53,507		)
Derivative liability as of June 30, 2014	$	44,331

We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at one of our plant locations through the fourth quarter of 2014. The value of the derivative component of this contract is marked to market through Derivative gain related to facility expenses. As of June 30, 2014, the estimated fair value of this contract was an asset of $1.5 million.

Interest Rate Risk

Our primary interest rate risk exposure results from our Credit Facility, which has a borrowing capacity of $1.3 billion. The applicable interest rate for our Credit Facility was a variable rate of 4.5% for $166.2 million and a variable rate of 2.4% for $275.0 million at June 30, 2014. As of July 30, 2014, we had $150.0 million in borrowings outstanding on our Credit Facility. The debt under the Credit Facility bears interest at variable rates that are tied to either the U.S. prime rate or LIBOR at the time of borrowing.

We may make use of interest rate swap agreements in the future to adjust the ratio of fixed and floating rates in our debt portfolio; however, we had no interest rate swaps outstanding as of June 30, 2014. Our debt portfolio as of June 30, 2014 is shown in the following table.

Long-Term Debt	Interest Rate	Lending Limit		Due Date	Outstanding at June 30, 2014
Credit Facility	Variable	$	1.3 billion	March 2019	$	441.2 million
2020 Senior Notes	Fixed	$	500.0 million	November 2020	$	500.0 million
2021 Senior Notes	Fixed	$	325.0 million	August 2021	$	325.0 million
2022 Senior Notes	Fixed	$	455.0 million	June 2022	$	455.0 million
2023A Senior Notes	Fixed	$	750.0 million	February 2023	$	750.0 million
2023B Senior Notes	Fixed	$	1.0 billion	July 2023	$	1.0 billion

Based on our overall interest rate exposure at June 30, 2014, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our Credit Facility would change pre-tax earnings by approximately $4.4 million over a twelve-month period. Based on our overall interest rate exposure at July 30, 2014, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our Credit Facility would change pre-tax earnings by approximately $1.5 million over a twelve-month period.

Credit Risk

The information about our credit risk for the three and six months ended June 30, 2014 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2013.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the Securities and Exchange Act of 1934, as amended (the “1934 Act”), as of June 30, 2014. Based on this evaluation, the Partnership’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of June 30, 2014, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

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Limitations on Controls

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2014 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

On March 21, 2014, MarkWest Liberty Midstream received a Draft Consent Order from the West Virginia Department of Environmental Protection (“WVDEP”) incorporating 16 separate inspections in 2013 of various operations and construction sites with claimed regulatory violations relating to erosion and sediment control measures, the August 2013 NGL pipeline break in Wetzel County and associated issues, pipeline borings and other disparate matters. The Draft Consent Order aggregates those matters and proposes a total aggregate administrative penalty of $115,120 for all of the various alleged claims, as well as the development of an approved remediation plan and certain provisions for approval of pipeline boring plans and other construction related activities in West Virginia going forward. The Partnership believes there are substantial defenses and disputable issues regarding the alleged claims, remedial action plans and the proposed penalty as set forth in the Draft Consent Order and MarkWest Liberty Midstream will be asserting those defenses and issues in discussions with WVDEP.

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

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013, 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, 2013.

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Item 6. Exhibits

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

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

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

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

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

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

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

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

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

31.1*		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) of the Securities Exchange Act, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2*		Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101*		The following financial information from the quarterly report on Form 10-Q of MarkWest Energy Partners, L.P. for the quarter ended June 30, 2014, formatted in XBRL (eXtensible Business Reporting Language): (i) Condensed Consolidated Statements of Operations, (ii) Condensed Consolidated Balance Sheets, (iii) Condensed Consolidated Statements of Cash Flows, (iv) Condensed Consolidated Statements of Changes in Equity and (v) Notes to the Condensed Consolidated Financial Statements, tagged as blocks of text.

* Filed herewith

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SIGNATURES

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

	MarkWest Energy Partners, L.P.
	(Registrant)

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

Date: August 6, 2014		/s/ FRANK M. SEMPLE
		Frank M. Semple
		Chairman, President & Chief Executive Officer
		(Principal Executive Officer)


Date: August 6, 2014		/s/ NANCY K. BUESE
		Nancy K. Buese
		Executive Vice President & Chief Financial Officer
		(Principal Financial Officer)


Date: August 6, 2014		/s/ PAULA L. ROSSON
		Paula L. Rosson
		Senior Vice President & Chief Accounting Officer
		(Principal Accounting Officer)

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