MARKWEST ENERGY PARTNERS L P - FORM 10-Q

Attached files

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EX-32 - EX-32 - MARKWEST ENERGY PARTNERS L P	a15-11887_1ex32.htm
EX-4.1 - EX-4.1 - MARKWEST ENERGY PARTNERS L P	a15-11887_1ex4d1.htm
EX-31.1 - EX-31.1 - MARKWEST ENERGY PARTNERS L P	a15-11887_1ex31d1.htm
EX-31.2 - EX-31.2 - MARKWEST ENERGY PARTNERS L P	a15-11887_1ex31d2.htm
EX-12.1 - EX-12.1 - MARKWEST ENERGY PARTNERS L P	a15-11887_1ex12d1.htm

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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, 2015

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 29, 2015, the number of the registrant’s common units and Class B units outstanding were 191,379,512 and 7,981,756, respectively.

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PART I—FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
	Unaudited Condensed Consolidated Balance Sheets at June 30, 2015 and December 31, 2014	4
	Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014	5
	Unaudited Condensed Consolidated Statements of Changes in Equity for the six months ended June 30, 2015 and 2014	6
	Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	7
	Unaudited Notes to the Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 4.	Controls and Procedures	62
PART II—OTHER INFORMATION		63
Item 1.	Legal Proceedings	63
Item 1A.	Risk Factors	64
Item 6.	Exhibits	67
SIGNATURES		69

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

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Glossary of Terms

Bbl	Barrel
Bbl/d	Barrels per day
Bcf/d	Billion cubic feet per day
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
LIBOR	London Interbank Offered Rate
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, 2015			December 31, 2014
ASSETS
Current assets:
Cash and cash equivalents ($12,807 and $73,300, respectively)	$	45,162		$	108,887
Restricted cash	10,000			20,000
Receivables, net ($43,442 and $22,722, respectively)	273,634			302,259
Receivables from unconsolidated affiliates, net ($0 and $30, respectively)	5,348			7,097
Inventories ($3,211 and $2,434, respectively)	31,358			31,749
Fair value of derivative instruments	15,151			20,921
Deferred income taxes	10			9
Other current assets ($3,704 and $9,511, respectively)	26,622			46,731
Total current assets	407,285			537,653

Property, plant and equipment ($1,489,149 and $1,411,797, respectively)	10,626,393			9,923,524
Less: accumulated depreciation ($87,328 and $56,987, respectively)	(1,490,582		)	(1,270,624		)
Total property, plant and equipment, net	9,135,811			8,652,900

Other long-term assets:
Investment in unconsolidated affiliates ($765,482 and $696,784, respectively)	888,820			805,633
Intangibles, net of accumulated amortization of $371,310 and $350,327, respectively	760,936			809,277
Goodwill	79,729			82,411
Deferred financing costs, net of accumulated amortization of $26,245 and $31,298, respectively	55,592			52,919
Deferred contract cost, net of accumulated amortization of $3,250 and $3,198, respectively	20,000			20,052
Fair value of derivative instruments	7,976			16,507
Other long-term assets ($664 and $664, respectively)	3,410			3,426
Total assets	$	11,359,559		$	10,980,778

LIABILITIES AND EQUITY
Current liabilities:

Accounts payable ($17,383 and $28,021, respectively)	$	193,329		$	270,997
Accrued liabilities ($18,002 and $48,793, respectively)	277,147			360,006
Deferred income taxes	331			239
Fair value of derivative instruments	1,164			—
Payables to unconsolidated affiliates, net ($9,349 and $5,500, respectively)	12,009			8,621
Total current liabilities	483,980			639,863

Deferred income taxes	342,938			357,260
Fair value of derivative instruments	55			—
Long-term debt, net of discounts of $6,837 and $6,196, respectively	4,540,663			3,621,404
Other long-term liabilities	163,122			169,012

Commitments and contingencies (Note 11)

Equity:
Common units (187,389 and 186,553 common units issued and outstanding, respectively)	4,355,128			4,758,243
Class B units (11,973 units issued and outstanding)	451,519			451,519
Non-controlling interest in consolidated subsidiaries	1,022,154			983,477
Total equity	5,828,801			6,193,239
Total liabilities and equity	$	11,359,559		$	10,980,778

Asset and liability amounts in parentheses represent the portion of the condensed 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,
	2015			2014			2015			2014
Revenue:
Product sales	$	156,643		$	309,919		$	324,580		$	632,288
Service revenue	302,847			215,200			594,872			409,274
Derivative gain (loss)	138			(6,753		)	7,506			(10,720		)
Total revenue	459,628			518,366			926,958			1,030,842

Operating expenses:
Purchased product costs	123,292			215,824			246,776			427,388
Derivative loss related to purchased product costs	2,255			11,964			6,795			4,166
Facility expenses	88,550			83,545			180,366			167,250
Derivative loss related to facility expenses	91			2,045			91			1,777
Selling, general and administrative expenses	34,971			27,701			69,606			62,991
Depreciation	121,909			104,078			241,501			206,007
Amortization of intangible assets	15,596			15,965			31,422			31,943
Impairment expense	—			—			25,523			—
Loss on disposal of property, plant and equipment	2,417			1,450			1,606			1,357
Accretion of asset retirement obligations	194			168			387			336
Total operating expenses	389,275			462,740			804,073			903,215
Income from operations	70,353			55,626			122,885			127,627

Other income (expense):
Equity in earnings (loss) from unconsolidated affiliates	3,262			(721		)	3,774			(471		)
Interest expense	(52,087		)	(43,391		)	(102,144		)	(84,375		)
Amortization of deferred financing costs and debt discount (a component of interest expense)	(1,562		)	(1,449		)	(3,197		)	(4,273		)
Loss on redemption of debt	(117,860		)	—			(117,860		)	—
Miscellaneous income, net	46			43			94			62
(Loss) income before provision for income tax	(97,848		)	10,108			(96,448		)	38,570

Provision for income tax expense (benefit):
Current	125			(19		)	164			326
Deferred	(11,581		)	(2,921		)	(15,741		)	9,280
Total provision for income tax expense (benefit)	(11,456		)	(2,940		)	(15,577		)	9,606

Net (loss) income	(86,392		)	13,048			(80,871		)	28,964

Net income attributable to non-controlling interest	(15,094		)	(4,071		)	(29,698		)	(7,495		)
Net (loss) income attributable to the Partnership’s unitholders	$	(101,486	)	$	8,977		$	(110,569	)	$	21,469

Net (loss) income attributable to the Partnership’s common unitholders per common unit:
Basic	$	(0.55	)	$	0.05		$	(0.60	)	$	0.13
Diluted	$	(0.55	)	$	0.05		$	(0.60	)	$	0.12
Weighted average number of outstanding common units:
Basic	186,855			164,613			186,771			161,727
Diluted	186,855			181,237			186,771			178,378
Cash distribution declared per common unit	$	0.91		$	0.87		$	1.81		$	1.73

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
	Units	Amount			Units	Amount		Interest			Total Equity
December 31, 2014	186,553	$	4,758,243		11,973	$	451,519	$	983,477		$	6,193,239
Issuance of units in public offerings, net of offering costs	636	39,630			—	—		—			39,630
Distributions paid	—	(339,306		)	—	—		(24,659		)	(363,965		)
Contributions from non-controlling interest	—	—			—	—		26,689			26,689
Sale of equity interest in a joint venture	—	—			—	—		11,319			11,319
Transfer of interest due to sale of joint venture	—	4,370			—	—		(4,370		)	—
Share-based compensation activity	200	4,270			—	—		—			4,270
Deferred income tax impact from changes in equity	—	(1,510		)	—	—		—			(1,510		)
Net (loss) income	—	(110,569		)	—	—		29,698			(80,871		)
June 30, 2015	187,389	$	4,355,128		11,973	$	451,519	$	1,022,154		$	5,828,801

	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

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,
	2015			2014
Cash flows from operating activities:
Net (loss) income	$	(80,871	)	$	28,964
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation	241,501			206,007
Amortization of intangible assets	31,422			31,943
Impairment expense	25,523			—
Loss on redemption of debt	117,860			—
Amortization of deferred financing costs and debt discount	3,197			4,273
Accretion of asset retirement obligations	387			336
Amortization of deferred contract cost	52			1,025
Phantom unit compensation expense	10,387			9,955
Equity in (earnings) loss from unconsolidated affiliates	(3,774		)	471
Distributions from unconsolidated affiliates	28,747			3,910
Unrealized loss on derivative instruments	15,520			7,024
Loss on disposal of property, plant and equipment	1,606			1,357
Deferred income taxes	(15,741		)	9,280
Changes in operating assets and liabilities:
Receivables	28,625			(32,291		)
Receivables from unconsolidated affiliates	1,749			2,768
Inventories	837			(21,435		)
Other current assets	20,109			7,434
Accounts payable and accrued liabilities	(62,136		)	87,371
Payables to unconsolidated affiliates	3,388			—
Other long-term assets	16			761
Other long-term liabilities	(5,066		)	7,670
Net cash flows provided by operating activities	363,338			356,823

Cash flows from investing activities:
Restricted cash	10,000			—
Capital expenditures	(833,062		)	(1,275,323		)
Investment in unconsolidated affiliates	(107,894		)	(76,054		)
Proceeds from sale of equity interest in unconsolidated affiliate	—			324,657
Proceeds from disposal of property, plant and equipment	2,360			21,562
Net cash flows used in investing activities	(928,596		)	(1,005,158		)

Cash flows from financing activities:
Proceeds from public equity offerings, net	39,630			711,837
Proceeds from Credit Facility	1,260,600			1,923,500
Payments of Credit Facility	(910,700		)	(1,482,300		)
Proceeds from long-term debt	1,848,875			—
Payments of long-term debt	(1,280,000		)	—
Payments of premiums on redemption of long-term debt	(103,209		)	—
Payments for debt issuance costs, deferred financing costs and registration costs	(20,270		)	(2,045		)
Proceeds from sale of equity interest in joint venture	11,319			—
Contributions from non-controlling interest	26,689			—
Payments of SMR liability	(1,319		)	(1,201		)
Cash paid for taxes related to net settlement of share-based payment awards	(6,117		)	(8,943		)
Payment of distributions to common unitholders	(339,306		)	(278,316		)
Payment of distributions to non-controlling interest	(24,659		)	(90		)
Net cash flows provided by financing activities	501,533			862,442

Net (decrease) increase in cash and cash equivalents	(63,725		)	214,107
Cash and cash equivalents at beginning of period	108,887			85,305
Cash and cash equivalents at end of period	$	45,162		$	299,412

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 natural gas resource 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, 2014. 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, 2015 are not necessarily indicative of results for the full year 2015 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). Intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in which the Partnership exercises significant influence but does not control and does not have a controlling financial interest, are accounted for using the equity method. The Partnership’s investments in VIEs, in which the Partnership exercises significant influence but does not control and is not the primary beneficiary, are also accounted for using the equity method.

2. Recent Accounting Pronouncements

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, 2018 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. Early adoption as of January 1, 2017 is permitted. 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.

In August 2014, the FASB issued ASU 2014-15 — Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”), that provides guidance on management’s responsibility to perform interim and annual assessments of an entity’s ability to continue as a going concern and provides related disclosure requirements. ASU 2014-15 is effective for the Partnership as of January 1, 2017 and early adoption is permitted. The Partnership is in the early stages of evaluating ASU 2014-15 and has not yet determined the impact on the Partnership’s condensed consolidated financial statements.

In February 2015, the FASB issued ASU 2015-02 — Consolidation (Topic 810): Amendments to the Consolidation Analysis (“ASU 2015-02”) that will modify current consolidation guidance. ASU 2015-02 makes changes to both the variable interest model and the voting interest model, including modifying the evaluation of whether limited partnerships or similar legal entities are VIEs or voting interest entities and amending the guidance for assessing how relationships of related parties affect the consolidation analysis of VIEs. ASU 2015-02 is effective for the Partnership as of January 1, 2016 and early adoption is permitted. The Partnership is in the early stages of evaluating ASU 2015-02 and has not yet determined the impact on the Partnership’s condensed consolidated financial statements.

In April 2015, the FASB issued ASU 2015-03 — Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU 2015-03”) that will modify the presentation of debt issuance costs such that they are presented in the balance sheet as a direct deduction from the carrying amount of the debt liability. ASU 2015-03 is effective for the Partnership as of January 1, 2016 and early adoption is permitted. The Partnership evaluated ASU 2015-03 and has determined the impact is not material to the Partnership’s condensed consolidated financial statements.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

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. After EMG Utica funded the Minimum EMG Investment, the Partnership was required to fund, as needed, 100% of future capital for MarkWest Utica EMG until such time as the aggregate capital that had been contributed by the Members reached $2.0 billion, which occurred in November 2014. Until such time as the investment balances of the Partnership and EMG Utica are in the ratio of 70% and 30%, respectively (such time being referred to as the “Second Equalization Date”), EMG Utica has 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 their 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, 2015, EMG Utica has contributed approximately $989.9 million and the Partnership has contributed approximately $1,379.6 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 $10.9 million and approximately $21.2 million for the three and six months ended June 30, 2015, respectively. 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. The Preference Amount along with the cash contributions result in investment balances of the Partnership and EMG Utica as of June 30, 2015 in the ratio of 55% and 45%, respectively.

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 Members. After the earlier of those dates, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Members in proportion to their respective investment balances.

The Partnership has determined that MarkWest Utica EMG does not meet the business scope exception to be excluded as a VIE due to the unique investment structure, discussed above, which creates a de-facto agent relationship between the Members, as EMG Utica has funded portions of the Partnership’s ownership in MarkWest Utica EMG. MarkWest Utica EMG’s inability to fund its planned activities without additional subordinated financial support qualifies it to be a VIE. 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. Upon 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 Members, the de-facto agent relationship between the Members will no longer exist.

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. 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, 2015 and 2014.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

Ohio Gathering

Ohio Gathering Company L.L.C. (“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 $341.1 million that Ohio Gathering received in 2014. MarkWest Utica EMG received approximately $336.1 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 Gathering as an equity method investment. As of June 30, 2014, Ohio Gathering’s net assets are reported under the caption Investment in unconsolidated affiliates on the Condensed Consolidated Balance Sheets.

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 one month ended June 30, 2014 and for the three and six months ended June 30, 2015, the Partnership, through its consolidation of MarkWest Utica EMG, has reported its pro rata share of Ohio Gathering’s net income under the caption Equity in earnings (loss) from unconsolidated affiliates on the Condensed Consolidated Statements of Operations. Ohio Gathering is considered to be a related party. The Partnership receives engineering and construction and administrative management fee revenue and other direct personnel costs (“Operational Service” revenue) for operating Ohio Gathering. The amount of Operational Service revenue related to Ohio Gathering for the three and six months ended June 30, 2015 was approximately $4.2 million and $8.9 million, respectively, and is reported as Service revenue in the Condensed Consolidated Statements of Operations. The amount of Operational Service revenue related to Ohio Gathering for the three and six months ended June 30, 2014 was approximately $1.0 million and is reported as Service revenue in the Condensed Consolidated Statements of Operations.

4. Other Equity Interests

Utica 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. If Utica Condensate requires additional capital, each Condensate Member has the right, but not the obligation, to contribute capital in proportion to its ownership interest. As of June 30, 2015, the Partnership owned 55% of Utica Condensate.

Ohio Condensate

Utica Condensate’s business is 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 less than 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 40% through a cash investment of approximately $8.6 million.

As of June 30, 2015, Utica Condensate owned 60% of Ohio Condensate. The Partnership sold approximately $17 million of assets under construction to Utica Condensate in December 2013 and received the $17 million in the first quarter of 2014. The Partnership has recorded the proceeds in the Proceeds from disposal of property, plant and equipment in the accompanying Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014. Ohio Condensate is considered to be a related party. The amount of Operational Service revenue related to Ohio Condensate for the three and six months ended June 30, 2015 was approximately $0.9 million and $2.0 million, respectively, and is reported as Service revenue in the Condensed Consolidated Statements of Operations. The amount of Operational Service 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 Service revenue in the Condensed Consolidated Statements of Operations.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

5. Derivative Financial Instruments

Commodity Derivatives

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

To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership currently manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory.

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 2016. 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.

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

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

As of June 30, 2015, 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	293,800
Natural Gas (MMBtu)	Long	1,311,126
NGLs (Gal)	Short	111,236,914

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

Embedded Derivatives in Commodity Contracts

The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content (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 related to purchased product costs in the Condensed Consolidated Statement of Operations. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022 with the producer’s option to extend the agreement for successive five-year terms through December 31, 2032. As of June 30, 2015, the estimated fair value of this contract was a liability of $39.1 million and the recorded value was an asset of $11.8 million. The recorded asset does not include the inception fair value of the commodity contract related to the remaining extension period of July 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. In the second quarter of 2015, approximately $2.6 million of the original inception value, related to April through June 2015, is no longer included in the inception value below as it is deemed to have settled. See the following table for a reconciliation of the liability recorded for the embedded derivative as of June 30, 2015 (in thousands):

Fair value of commodity contract	$	(39,101	)
Inception value for period from July 1, 2015 to December 31, 2022	(50,928		)
Derivative asset as of June 30, 2015	$	11,827

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 a plant location in the Southwest segment through the fourth quarter of 2017. The contract is currently fixed through the fourth quarter of 2015 with the ability to fix the commodity contract for its remaining years. Changes in the fair value of the derivative component of this contract are recognized as Derivative loss related to facility expenses in the Condensed Consolidated Statements of Operations. As of June 30, 2015, the estimated fair value of this contract was a liability of $0.1 million on the Condensed Consolidated Balance Sheet.

Financial Statement Impact of Derivative Contracts

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, 2014. 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, 2015		Fair Value at December 31, 2014		Fair Value at June 30, 2015			Fair Value at December 31, 2014
Commodity contracts(1)
Fair value of derivative contracts — current	$	15,151	$	20,921	$	(1,164	)	$	—
Fair value of derivative contracts — long-term	7,976		16,507		(55		)	—
Total	$	23,127	$	37,428	$	(1,219	)	$	—

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

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

	Assets							Liabilities
As of June 30, 2015	Gross Amounts of Assets in the Condensed Consolidated Balance Sheet		Gross Amounts Not Offset in the Condensed Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Condensed Consolidated Balance Sheet			Gross Amounts Not Offset in the Condensed Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	11,241	$	(1,026	)	$	10,215	$	(1,073	)	$	1,026	$	(47	)
Embedded derivatives in commodity contracts	3,910		—			3,910		(91		)	—		(91		)
Total current derivative instruments	15,151		(1,026		)	14,125		(1,164		)	1,026		(138		)

Non-current
Commodity contracts	59		—			59		(55		)	—		(55		)
Embedded derivatives in commodity contracts	7,917		—			7,917		—			—		—
Total non-current derivative instruments	7,976		—			7,976		(55		)	—		(55		)

Total derivative instruments	$	23,127	$	(1,026	)	$	22,101	$	(1,219	)	$	1,026	$	(193	)

	Assets						Liabilities
As of December 31, 2014	Gross Amounts of Assets in the Condensed Consolidated Balance Sheet		Gross Amounts Not Offset in the Condensed Consolidated Balance Sheet		Net Amount		Gross Amounts of Liabilities in the Condensed Consolidated Balance Sheet		Gross Amounts Not Offset in the Condensed Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	18,652	$	—	$	18,652	$	—	$	—	$	—
Embedded derivatives in commodity contracts	2,269		—		2,269		—		—		—
Total current derivative instruments	20,921		—		20,921		—		—		—

Non-current
Embedded derivatives in commodity contracts	16,507		—		16,507		—		—		—
Total non-current derivative instruments	16,507		—		16,507		—		—		—

Total derivative instruments	$	37,428	$	—	$	37,428	$	—	$	—	$	—

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 (continued)

(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 gain	Three months ended June 30,						Six months ended June 30,
or (loss) recognized in income	2015			2014			2015			2014
Revenue: Derivative gain (loss)
Realized gain (loss)	$	5,132		$	(1,774	)	$	16,120		$	(9,381	)
Unrealized loss	(4,994		)	(4,979		)	(8,614		)	(1,339		)
Total revenue: derivative gain (loss)	138			(6,753		)	7,506			(10,720		)

Derivative loss related to purchased product costs
Realized gain (loss)	20			(144		)	20			(258		)
Unrealized loss	(2,275		)	(11,820		)	(6,815		)	(3,908		)
Total derivative loss related to purchased product costs	(2,255		)	(11,964		)	(6,795		)	(4,166		)

Derivative loss related to facility expenses
Unrealized (loss)	(91		)	(2,045		)	(91		)	(1,777		)
Total (loss) gain	$	(2,208	)	$	(20,762	)	$	620		$	(16,663	)

6. Fair Value

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions discussed in Note 5. Money market funds, which are included in Cash and cash equivalents on the Condensed Consolidated Balance Sheets, 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, 2015 and December 31, 2014 (in thousands):

As of June 30, 2015	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	5,413	$	(19	)
Significant unobservable inputs (Level 3)
Commodity contracts	5,887		(1,109		)
Embedded derivatives in commodity contracts	11,827		(91		)
Total carrying value in Condensed Consolidated Balance Sheets	$	23,127	$	(1,219	)

As of December 31, 2014	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	14,812	$	—
Significant unobservable inputs (Level 3)
Commodity contracts	3,840		—
Embedded derivatives in commodity contracts	18,776		—
Total carrying value in Condensed Consolidated Balance Sheets	$	37,428	$	—

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of June 30, 2015. The market approach is used for valuation of all instruments.

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

Commodity contracts	Asset	Forward propane prices (per gallon) (1)	$0.44 - $0.54	Jul. 2015 - Mar. 2016

		Forward isobutane prices (per gallon) (1)	$0.59 - $0.72	Jul. 2015 - Mar. 2016

		Forward normal butane prices (per gallon) (1)	$0.58 - $0.69	Jul. 2015 - Mar. 2016

		Forward natural gasoline prices (per gallon) (1)	$1.22 - $1.24	Jul. 2015 - Dec. 2015

	Liability	Forward ethane prices (per gallon) (1)	$0.20 - $0.21	Jul. 2015 - Dec. 2015

		Forward isobutane prices (per gallon) (1)	$0.62 - $0.72	Aug. 2015 - Mar. 2016

		Forward normal butane prices (per gallon) (1)	$0.58 - $0.69	Jul. 2015 - Mar. 2016

		Forward natural gasoline prices (per gallon) (1)	$1.22 - $1.27	Jul. 2015 - Dec. 2016

Embedded derivatives in commodity contract	Asset	Forward propane prices (per gallon) (1)	$0.44 - $0.61	Jul. 2015 - Dec. 2022

		Forward isobutane prices (per gallon) (1)	$0.59 - $0.82	Jul. 2015 - Dec. 2022

		Forward normal butane prices (per gallon) (1)	$0.58 - $0.79	Jul. 2015 - Dec. 2022

		Forward natural gasoline prices (per gallon) (1)	$1.22 - $1.34	Jul. 2015 - Dec. 2022

		Forward natural gas prices (per MMBtu) (2)	$2.68 - $3.69	Jul. 2015 - Dec. 2022

		Probability of renewal (3)	0%

	Liability	ERCOT Pricing (per MegaWatt Hour) (4)	$26.55 - $35.56	Jul. 2015 - Dec. 2015

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

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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

(3) 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.

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

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 (asset) - The embedded derivative asset relates to the natural gas purchase agreement embedded in a keep-whole processing agreement as discussed further in Note 5. Increases (decreases) in forward NGL prices result in an increase (decrease) in the fair value of the embedded derivative. 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 (liability) - The embedded derivative liability relates to utilities costs discussed further in Note 5. Increases in the forward ERCOT prices result in a decrease in the fair value of the embedded derivative liability.

Level 3 Valuation Process

The Partnership’s Risk Management Department (the “Risk Department”) is responsible for the valuation of the Partnership’s commodity derivative contracts and embedded derivatives in commodity contracts. The Risk Department reports to the Chief Financial Officer for the oversight of the Partnership’s commodity risk management program. The members of the Risk Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The valuations of the Level 3 commodity derivative contracts are performed by a third-party pricing service and reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by at least one other independent third-party pricing service. The valuations for the embedded derivative in the commodity contract 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 5, 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, 2015, the Risk Department utilized internally developed price curves for the period of July 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.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

Changes in Level 3 Fair Value Measurements

The tables below include a roll forward of the balance sheet amounts for the three and six months ended June 30, 2015 and 2014 (including the change in fair value) for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

	Three months ended June 30, 2015
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	5,091		$	14,294
Total gain (loss) (realized and unrealized) included in earnings (1)	1,895			(4,416		)
Settlements	(2,208		)	1,858
Fair value at end of period	$	4,778		$	11,736

The amount of total gains (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)	$	872		$	(1,446	)

	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	)

	Six months ended June 30, 2015
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	3,840		$	18,776
Total gain (loss) (realized and unrealized) included in earnings (1)	6,923			(10,198		)
Settlements	(5,985		)	3,158
Fair value at end of period	$	4,778		$	11,736

The amount of total gains (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)	$	4,778		$	(6,916	)

	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 (continued)

(unaudited)

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

7. Inventories

Inventories consist of the following (in thousands):

	June 30, 2015		December 31, 2014
NGLs	$	5,228	$	9,687
Line fill	3,954		6,241
Spare parts, materials and supplies	22,176		15,821
Total inventories	$	31,358	$	31,749

8. Impairment of Long-Lived Assets and Goodwill

Long-Lived Assets. The Partnership’s policy is to evaluate whether there has been an impairment in the value of long-lived assets when certain events have taken place that indicate that the remaining balance may not be recoverable. The Partnership evaluates the carrying value of its long-lived assets and intangibles on at least a segment level and at lower levels when cash flows for specific assets can be identified.

An analysis completed during the first quarter of 2015 indicated a potential impairment of the Appleby asset grouping in the Southwest segment. Appleby is a gathering system in Nacogdoches County, Texas (“Appleby”). In the first quarter of 2015, Appleby’s expected future cash flows were adversely impacted by declines in the forward price strip of natural gas and condensate. The Partnership used a combination of the income and market approaches for determining the fair value of Appleby and recognized an impairment totaling approximately $22.8 million, of which approximately $16.8 million relates to intangibles and $6.0 million to property, plant and equipment for the six months ended June 30, 2015. This impairment is recorded as Impairment expense on the Condensed Consolidated Statements of Operations.

Goodwill. The Partnership annually evaluates goodwill for impairment as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.

Management considered the decline in commodity prices and resulting decline in projected operating income to be an indicator of impairment of goodwill of the Western Oklahoma assets in our Southwest segment (“Western Oklahoma Reporting Unit”). The Partnership performed the first step of our goodwill impairment analysis as of February 28, 2015 and determined that the carrying value of the Western Oklahoma Reporting Unit exceeded its fair value. The Partnership completed the second step of its goodwill impairment analysis comparing the implied fair value of that reporting unit’s goodwill to the carrying amount of that goodwill and determined goodwill related to the Western Oklahoma Reporting Unit was fully impaired and recorded an impairment charge of $2.7 million during the three months ended March 31, 2015.

In completing these evaluations, management’s best estimates of the expected future results are the primary driver in determining the fair value. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the goodwill impairment test will prove to be an accurate prediction of the future. Management estimated the fair value of the Partnership’s reporting units and asset grouping using a combination of the income and market approaches based on discounted future cash flows using significant unobservable inputs (Level 3).

There were no impairments recorded related to the Partnership’s other reporting units as a result of its analyses for the six months ended June 30, 2015.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

9. Long-Term Debt

Debt is summarized below (in thousands):

	June 30, 2015		December 31, 2014
Credit Facility
Credit Facility, variable interest, due March 2019 (1)	$	447,500	$	97,600

Senior Notes (2)
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020	—		500,000
2021 Senior Notes, 6.5% interest, net of discount of $— and $413, respectively, issued February and March 2011 and due August 2021	—		324,587
2022 Senior Notes, 6.25% interest, issued October 2011 and due September 2022	—		455,000
2023A Senior Notes, 5.5% interest, net of discount of $5,447 and $5,783, respectively, issued August 2012 and due February 2023	744,553		744,217
2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023	1,000,000		1,000,000
2024 Senior Notes, 4.875% interest, including premium of $10,204, issued November 2014 and March 2015 and due December 2024	1,160,204		500,000
2025 Senior Notes, 4.875% interest, including discount of $11,594, issued June 2015 and due June 2025	1,188,406		—
Total long-term debt (3)	$	4,540,663	$	3,621,404

(1) Applicable interest rate was 2.4% for $250.0 million and 4.5% for $197.5 million at June 30, 2015. The applicable interest rate was 4.5% at December 31, 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 $4,058 million and $3,563 million as of June 30, 2015 and December 31, 2014, respectively, based on recent actual prices for OTC secondary market transactions. The fair value of the Partnership’s Senior Notes is considered a Level 2 measurement.

(3) Accrued interest payable related to the long-term debt was approximately $47.6 million for the six months ended June 30, 2015.

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, 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 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 a margin. 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 margin is determined by 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 margin is determined by 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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

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 2.5 to 1.0 and the Total Leverage Ratio (as defined in the Credit Facility). Prior to the February 2015 amendment, the Total Leverage Ratio was required to be less than 5.5 to 1.0 prior to January 1, 2015, and thereafter until the Collateral Release Date the maximum permissible Total Leverage Ratio was 5.25 to 1.0. In February 2015, we entered into an amendment which permanently increases our maximum permissible leverage ratio to 5.5 to 1.0 until the Collateral Release Date. 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.

As of June 30, 2015, the Partnership was in compliance with these financial covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by and collateralized by substantially all assets of the Partnership’s wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries and MarkWest Panola Pipeline, L.L.C. As of June 30, 2015, the Partnership had approximately $447.5 million borrowings outstanding and approximately $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $841.2 million of unused capacity all of which was available for borrowing based on financial covenant requirements. Additionally, the full amount of unused capacity is available for borrowing on a short-term basis to provide financial flexibility within a given fiscal quarter.

Senior Notes

In March 2015, the Partnership completed a public offering for $650 million in additional aggregate principal amount of 4.875% unsecured notes due December 2024 (“new notes”), which are additional notes under an indenture pursuant to which the Partnership issued $500 million aggregate principal amount of 4.875% Senior Notes due 2024 on November 21, 2014 (“existing notes”). The new notes and the existing notes are treated as a single class of securities under the indenture (“2024 Senior Notes”). The 2024 Senior Notes mature December 1, 2024. Interest on the new notes will accrue from November 21, 2014, and the Partnership will pay interest on the notes twice a year, beginning on June 1, 2015. The Partnership received aggregate net proceeds of approximately $653.6 million from the new notes offering, after deducting underwriting fees and third-party expenses and excluding approximately $9.0 million for accrued interest.

In June 2015, the Partnership completed a public offering for $1.2 billion in additional aggregate principal amount of 4.875% unsecured notes due June 2025 (“2025 Senior Notes”). The 2025 Senior Notes mature June 1, 2025. Interest on the 2025 Senior Notes will accrue from June 2, 2015, and the Partnership will pay interest on the notes twice a year, beginning on December 1, 2015. The Partnership received aggregate net proceeds of approximately $1,174.9 million from the 2025 Senior Notes offering, after deducting discounts, underwriting fees and third-party expenses and excluding approximately $23.0 million for accrued interest. The proceeds from the issuance of the 2025 Senior Notes along with the Credit Facility were used to repurchase $500.0 million of our 6.754% Senior Notes due 2020 (the “2020 Senior Notes”), $325.0 million of our 6.5% Senior Notes due 2021 (the “2021 Senior Notes”) and $455.0 million of our 6.25% Senior Notes due 2022 (the “2022 Senior Notes”).

The Partnership recorded a total pre-tax loss during the six months ended June 30, 2015 of approximately $117.9 million related to the repurchases of the 2020 Senior Notes, 2021 Senior Notes and 2022 Senior Notes. The pre-tax loss recorded in the second quarter of 2015 consisted of approximately $14.7 million related to the non-cash write-off of the unamortized discount and deferred finance costs and approximately $103.2 million related to the payment of redemption premiums and third party expenses. The loss was recorded in Loss on redemption of debt in the accompanying Condensed Consolidated Statement of Operations.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

10. Equity

Equity Offerings

Our public equity offerings are summarized in the table below for the three and six months ended June 30, 2015 and 2014 (in millions):

	Three months ended June 30, 2015			Three months ended June 30, 2014			Six months ended June 30, 2015			Six months ended June 30, 2014
	Common units	Net Proceeds		Common units	Net Proceeds		Common units	Net Proceeds		Common units	Net Proceeds
September 2013 ATM (1)	—	$	—	—	$	—	—	$	—	4.2	$	272
March 2014 ATM (2)	—	—		7.0	440		—	—		7.0	440
November 2014 ATM (3)	0.6	40		—	—		0.6	40		—	—
Total	0.6	$	40	7.0	$	440	0.6	$	40	11.2	$	712

(1) In September 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 could have sold from time to time through the 2013 Manager, as its sales agent, common units having an aggregate offering price of up to $1 billion. During the six months ended June 30, 2014, the Partnership incurred approximately $4 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.

(2) In March 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 incurred 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 March 2014 ATM in October 2014.

(3) In November 2014, the Partnership entered into an Equity Distribution Agreement with financial institutions (the “November 2014 Managers”) that established an At the Market offering program (the “November 2014 ATM”) pursuant to which the Partnership may sell from time to time through the November 2014 Managers, as its sales agents, common units having an aggregate offering price of up to $1.5 billion. As of June 30, 2015, the Partnership has issued 3.1 million units receiving net proceeds of approximately $214 million under the November 2014 ATM.

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. Approximately four million Class B units converted to common units on July 1, 2015. The remaining Class B units will convert to common units on a one-for-one basis in two equal installments on July 1, 2016 and 2017. After the units are converted to common units, M&R MWE Liberty, LLC may sell common units as part of the November 2014 ATM program. See the voting agreement section of Note 17 for further information regarding the voting of M&R MWE Liberty, LLC’s common units with respect to the Merger Agreement (as defined in Note 17). Class B units converted to common units prior to the applicable record date will participate in the distributions relating to such date.

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, 2015	$	69.50	$	56.20	$	0.92	July 20, 2015	August 6, 2015	August 14, 2015
March 31, 2015	$	69.16	$	54.04	$	0.91	April 22, 2015	May 7, 2015	May 15, 2015
December 31, 2014	$	77.31	$	58.67	$	0.90	January 21, 2015	February 5, 2015	February 13, 2015

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

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 coverage 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 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.

On July 6, 2015, officials from the United States Environmental Protection Agency (“EPA”) and the Department of Justice conducted an inspection at a MarkWest Liberty Midstream pipeline tool launcher/receiver site in Washington County, Pennsylvania pursuant to a search warrant issued by the United States District Court for the Western District of Pennsylvania. At the conclusion of the inspection, the EPA also presented MarkWest Liberty Midstream with a subpoena to provide documents related to the design, construction, operation, maintenance, modification, inspection, assessment, repair of, and/or emissions from MarkWest Liberty Midstream’s pipeline facilities located in Pennsylvania. MarkWest Liberty Midstream is providing information in response to the subpoena and is in discussions with the relevant agencies regarding any issues associated with the inspection and subpoena or its operations of or supplementary permitting obligations for its pipeline facilities. While it is possible that MarkWest Liberty Midstream will incur expenses and potential assessments or fines in connection with the inspection and subpoena, the amount of potential expenses or assessments cannot be reasonably estimated at this time.

As more fully described in Note 17 of the Notes to the Condensed Consolidated Financial Statements, on July 11, 2015, the Partnership entered into an Agreement and Plan of Merger (the “Merger Agreement”) with MPLX LP (“MPLX”), MPLX GP LLC, the general partner of MPLX (“MPLX GP”), Sapphire Holdco LLC, a wholly owned subsidiary of MPLX (“Merger Sub” and, together with MPLX and MPLX GP, the “MPLX Entities”), and, for certain limited purposes set forth in the Merger Agreement, Marathon Petroleum Corporation, the parent of MPLX GP (“MPC”). Pursuant to the Merger Agreement, Merger Sub will be merged with and into the Partnership (the “Merger”), with the Partnership surviving the Merger as a wholly owned subsidiary of MPLX. After the Merger, the Partnership’s common units will cease to be publicly traded.

On July 24, 2015, a putative unitholder class action complaint was filed by a single plaintiff who purports to be a unitholder of the Partnership in the Court of Chancery for the State of Delaware (Case No. 11332-VCG) against the individual members of the General Partner’s board of directors (the “Board”), the General Partner, MPLX, MPC and Merger Sub. The complaint, styled Katsman v. Frank M. Semple, et al., (the “Complaint”) alleges that the Board breached its duties in approving the Merger with MPLX. Generally, the Complaint alleges that the Board breached its duties to the Partnership’s common unitholders because the Merger does not provide the Partnership’s common unitholders with adequate consideration, the Board did not seek to maximize value for the benefit of the Partnership’s common unitholders, certain members of the Partnership’s management team will remain executive officers of MPLX after the consummation of the Merger and the Merger Agreement contains preclusive deal protective devices and does not provide for appraisal rights. The Complaint also alleges that MPC, MPLX and Merger Sub aided and abetted in such breaches. The Complaint seeks, among other relief, to enjoin the Merger, or in the event the Merger is consummated, rescission of the Merger or monetary damages.

The Partnership intends to vigorously defend this lawsuit. However, one of the conditions to the completion of the Merger is that no law, order, decree, judgment or injunction of any court, agency or other governmental authority shall be in effect that enjoins, prohibits or makes illegal consummation of any of the transactions contemplated by the Merger Agreement. A preliminary injunction could delay or jeopardize the completion of the Merger, and an adverse judgment granting permanent injunctive relief could indefinitely enjoin completion of the Merger. An adverse judgment for rescission or for monetary damages could have a material adverse effect on the Partnership and MPLX following the Merger.

Contract Contingencies

Certain natural gas processing and gathering arrangements require the Partnership to construct new natural gas processing plants, natural gas gathering pipelines and NGL pipelines and contain certain fees and charges if specified construction milestones are

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

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, 2015, management does not believe there are any indications that the Partnership will not be able to meet the construction milestones, that force majeure does not apply, or that such fees and charges will otherwise be triggered.

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, 2015 and 2014 is as follows (in thousands):

	Six months ended June 30, 2015
	Corporation			Partnership			Eliminations			Consolidated
Loss before provision for income tax	$	(26,183	)	$	(69,612	)	$	(653	)	$	(96,448	)
Federal statutory rate	35		%	0		%	0		%
Federal income tax at statutory rate	(9,164		)	—			—			(9,164		)
Permanent items	16			—			—			16
Change in state statutory rate	—			(1,517		)	—			(1,517		)
State income taxes net of federal benefit	(784		)	(2,059		)	—			(2,843		)
Provision on income from Class A units (1)	(2,069		)	—			—			(2,069		)
Provision for income tax	$	(12,001	)	$	(3,576	)	$	—		$	(15,577	)

	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

(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 (continued)

(unaudited)

13. Earnings Per Common Unit

The following table shows the computation of basic and diluted net income per common unit, and the weighted-average units used to compute basic and diluted net income per common unit for the three and six months ended June 30, 2015 and 2014 (in thousands, except per unit data):

	Three months ended June 30,					Six months ended June 30,
	2015			2014		2015			2014
Net (loss) income attributable to the Partnership’s unitholders	$	(101,486	)	$	8,977	$	(110,569	)	$	21,469
Less: Income allocable to phantom units	644			551		1,286			1,096
(Loss) income available for common unitholders - basic	(102,130		)	8,426		(111,855		)	20,373
Add: Income allocable to phantom units and DER expense (1)	—			574		—			1,141
(Loss) income available for common unitholders - diluted	$	(102,130	)	$	9,000	$	(111,855	)	$	21,514

Weighted average common units outstanding - basic	186,855			164,613		186,771			161,727
Potential common shares (Class B and phantom units) (1)	—			16,624		—			16,651
Weighted average common units outstanding - diluted	186,855			181,237		186,771			178,378

Net (loss) income attributable to the Partnership’s common unitholders per common unit (2)
Basic	$	(0.55	)	$	0.05	$	(0.60	)	$	0.13
Diluted	$	(0.55	)	$	0.05	$	(0.60	)	$	0.12

(1) For the three and six months ended June 30, 2015, approximately 12,717,000 and 12,726,000, respectively, potential common shares were excluded from the calculation because the impact was anti-dilutive.

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

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, 2015 and results of operations are reported under the equity method of accounting. However, the Partnership’s 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 it were consolidated. In addition, the Partnership’s Chief Executive Officer and chief operating decision maker views all Partnership operated, non-wholly owned subsidiaries as if they are consolidated, as these subsidiaries are operated by the Partnership.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

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, 2015 and 2014 for the reported segments (in thousands):

Three months ended June 30, 2015:

	Marcellus		Utica		Northeast		Southwest		Elimination (1)		Total

Segment revenue	$	199,311	$	63,942	$	22,595	$	200,210	$	—	$	486,058
Segment purchased product costs	4,568		679		9,743		108,302		—		123,292
Net operating margin	194,743		63,263		12,852		91,908		—		362,766
Segment facility expenses	39,938		15,952		7,584		33,993		—		97,467
Segment portion of operating income attributable to non-controlling interests	—		23,633		—		2,062		—		25,695
Operating income before items not allocated to segments	$	154,805	$	23,678	$	5,268	$	55,853	$	—	$	239,604

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

(1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(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, 2015 and 2014 (in thousands):

	Three months ended June 30,
	2015			2014
Total segment revenue	$	486,058		$	528,577
Derivative gain (loss) not allocated to segments	138			(6,753		)
Revenue adjustment for unconsolidated affiliates (1)	(33,016		)	(3,833		)
Revenue deferral adjustment and other (2) (3)	6,448			375
Total revenue	$	459,628		$	518,366

Operating income before items not allocated to segments	$	239,604		$	220,132
Portion of operating income attributable to non-controlling interests	11,495			4,184
Derivative loss not allocated to segments	(2,208		)	(20,762		)
Revenue adjustment for unconsolidated affiliates (1)	(33,016		)	(3,833		)
Revenue deferral adjustment (2)	1,076			375
Compensation expense included in facility expenses not allocated to segments	(942		)	(903		)
Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliates (4)	12,543			2,598
Portion of operating income attributable to non-controlling interests of unconsolidated affiliates (5)	14,200			509
Facility expense adjustments (6)	2,688			2,688
Selling, general and administrative expenses	(34,971		)	(27,701		)
Depreciation	(121,909		)	(104,078		)
Amortization of intangible assets	(15,596		)	(15,965		)
Loss on disposal of property, plant and equipment	(2,417		)	(1,450		)
Accretion of asset retirement obligations	(194		)	(168		)
Income from operations	70,353			55,626
Earnings (loss) from unconsolidated affiliates	3,262			(721		)
Interest expense	(52,087		)	(43,391		)
Amortization of deferred financing costs and debt discount (a component of interest expense)	(1,562		)	(1,449		)
Loss on redemption of debt	(117,860		)	—
Miscellaneous income, net	46			43
(Loss) income before provision for income tax	$	(97,848	)	$	10,108

(1) Revenue adjustment for unconsolidated affiliates relates to revenue of Partnership operated, non-wholly owned subsidiaries (See Note 3).

(2) Revenue deferral adjustment 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. In March 2015, the cash consideration received from the Southwest segment contract declined and the reported segment revenue was less than the revenue recognized for GAAP purposes. For the three months ended June 30, 2015, approximately $0.2 million of the revenue deferral adjustment is attributable to the Southwest segment. Beginning in the second quarter of 2015, the cash consideration received from the Northeast segment contract declined and the reported segment revenue is less than the revenue recognized for GAAP purposes. For the three months ended June 30, 2015, approximately $0.9 million of the revenue deferral adjustment is attributable to the Northeast segment. In comparison, for the three months ended June 30, 2014, approximately $0.2 million and $1.5 million of the revenue deferral adjustment was attributable to the Southwest segment and Northeast segment, respectively.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

(3) Other consists of Operational Service revenues from unconsolidated affiliates of $5.4 million for the three months ended June 30, 2015 compared to $2.1 million for three months ended June 30, 2014.

(4) Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliates consist of the facility expenses and purchased product costs related to Partnership operated, non-wholly owned subsidiaries (See note (1) above and Note 3).

(5) Portion of operating income attributable to non-controlling interests of unconsolidated affiliates amount relates to the Partnership’s joint venture partners’ proportionate share of operating income in Partnership operated, non-wholly owned subsidiaries, which is included in segment operating income calculation as if the Partnership operated, non-wholly owned subsidiaries are consolidated (See note (1) above and Note 3).

(6) 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 for the six months ended June 30, 2015 and 2014 for the reported segments (in thousands):

Six months ended June 30, 2015:

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

Segment revenue	$	396,487	$	122,853	$	52,616	$	396,477	$	(44	)	$	968,389
Segment purchased product costs	11,070		860		22,261		212,585		—			246,776
Net operating margin	385,417		121,993		30,355		183,892		(44		)	721,613
Segment facility expenses	83,320		32,590		14,462		67,910		(44		)	198,238
Segment portion of operating income attributable to non-controlling interests	—		43,740		—		3,609		—			47,349
Operating income before items not allocated to segments	$	302,097	$	45,663	$	15,893	$	112,373	$	—		$	476,026

Capital expenditures	$	584,067	$	290,106	$	1,854	$	122,081	$			$	998,108
Capital expenditures for Partnership operated, non-wholly owned subsidiaries (1)												(170,442		)
Capital expenditures not allocated to segments												5,396
Total capital expenditures												$	833,062

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

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
Segment 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
Segment facility expenses	69,228		24,026		15,623		66,876		(2,471	)	173,282
Segment 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

(1) The Utica segment for the six months ended June 30, 2015 includes $167.2 million of capital expenditures related to Partnership operated, non-wholly owned subsidiaries’ capital expenditures. The Southwest segment for the six months ended June 30, 2015 includes $3.2 million related to Partnership operated, non-wholly owned subsidiaries. The Utica segment for the six months ended June 30, 2014 includes $40.0 million related to Ohio Gathering capital expenditures after deconsolidation on June 1, 2014.

(2) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(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 six months ended June 30, 2015 and 2014 (in thousands):

	Six months ended June 30,
	2015			2014
Total segment revenue	$	968,389		$	1,046,514
Derivative gain (loss) not allocated to segments	7,506			(10,720		)
Revenue adjustment for unconsolidated affiliates (1)	(60,547		)	(3,833		)
Revenue deferral adjustment and other (2) (3)	11,610			(1,119		)
Total revenue	$	926,958		$	1,030,842

Operating income before items not allocated to segments	$	476,026		$	437,980
Portion of operating income attributable to non-controlling interests	22,909			7,319
Derivative gain (loss) not allocated to segments	620			(16,663		)
Revenue adjustment for unconsolidated affiliates (1)	(60,547		)	(3,833		)
Revenue deferral adjustment (2)	154			(1,119		)
Compensation expense included in facility expenses not allocated to segments	(2,049		)	(1,906		)
Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliates (4)	26,001			2,598
Portion of operating income attributable to non-controlling interests of unconsolidated affiliates (5)	24,440			509
Facility expense adjustments (6)	5,376			5,376
Selling, general and administrative expenses	(69,606		)	(62,991		)
Depreciation	(241,501		)	(206,007		)
Amortization of intangible assets	(31,422		)	(31,943		)
Impairment expense	(25,523		)	—
Loss on disposal of property, plant and equipment	(1,606		)	(1,357		)
Accretion of asset retirement obligations	(387		)	(336		)
Income from operations	122,885			127,627
Earnings (loss) from unconsolidated affiliates	3,774			(471		)
Interest expense	(102,144		)	(84,375		)
Amortization of deferred financing costs and debt discount (a component of interest expense)	(3,197		)	(4,273		)
Loss on redemption of debt	(117,860		)	—
Miscellaneous income, net	94			62
(Loss) income before provision for income tax	$	(96,448	)	$	38,570

(1) Revenue adjustment for unconsolidated affiliates relates to revenue of Partnership operated, non-wholly owned subsidiaries (See note (1) 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. In March 2015, the cash consideration received from the Southwest segment contract declined and the reported segment revenue was less than the revenue recognized for GAAP purposes. For the six months ended June 30, 2015, approximately $0.1 million of the revenue deferral adjustment is attributable to the Southwest segment. Beginning in the second quarter of 2015, the cash consideration received from the Northeast segment contract started to decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes. For the six months ended June 30, 2015, approximately $0.1 million of the revenue deferral adjustment is attributable to the Northeast segment. In comparison, for the six months ended June 30, 2014, approximately $0.4 million and $3.4 million of the revenue deferral adjustment was attributable to the Southwest segment and Northeast segment, respectively.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

(3) Other consists of Operational Service revenues from unconsolidated affiliates of $11.5 million for the six months ended June 30, 2015 compared to $2.7 million for six months ended June 30, 2014.

The table below presents information about segment assets as of June 30, 2015 and December 31, 2014 (in thousands):

	June 30, 2015		December 31, 2014
Marcellus	$	6,106,353	$	5,749,932
Utica (1)	2,270,379		2,163,025
Northeast	398,221		445,911
Southwest (1)	2,409,091		2,362,113
Total segment assets	11,184,044		10,720,981
Assets not allocated to segments:
Certain cash and cash equivalents	1		—
Fair value of derivatives	23,127		37,428
Investment in unconsolidated affiliates	57,777		108,849
Other (2)	94,610		113,520
Total assets	$	11,359,559	$	10,980,778

(1) The June 30, 2015 and December 31, 2014 amounts exclude assets related to the Partnership’s unconsolidated joint ventures. The amounts include the investments in unconsolidated affiliates.

(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, 2015, 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 and MarkWest Panola Pipeline, L.L.C. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures (See Note 17 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, 2014 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 the Partnership and its combined guarantor and combined non-guarantor subsidiaries as of June 30, 2015 and December 31, 2014 and for the three and six months ended June 30, 2015 and 2014 is as follows (in thousands):

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

Condensed Consolidating Balance Sheets

	As of June 30, 2015
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	2	$	45,160	$	—		$	45,162
Restricted cash	—		—		10,000		—			10,000
Receivables and other current assets	4,515		146,887		180,222		—			331,624
Receivables from unconsolidated affiliates, net	—		2,687		2,661		—			5,348
Intercompany receivables	934,388		18,214		47,131		(999,733		)	—
Fair value of derivative instruments	—		12,723		2,428		—			15,151
Total current assets	938,903		180,513		287,602		(999,733		)	407,285
Total property, plant and equipment, net	10,268		2,175,626		6,984,817		(34,900		)	9,135,811
Other long-term assets:
Investment in unconsolidated affiliates	—		85,091		813,672		(9,943		)	888,820
Investment in consolidated affiliates	8,117,920		7,005,652		—		(15,123,572		)	—
Intangibles, net of accumulated amortization	—		506,353		254,583		—			760,936
Fair value of derivative instruments	—		7,976		—		—			7,976
Intercompany notes receivable	231,400		—		—		(231,400		)	—
Other long-term assets	55,376		26,670		76,685		—			158,731
Total assets	$	9,353,867	$	9,987,881	$	8,417,359	$	(16,399,548	)	$	11,359,559
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	1,948	$	976,097	$	21,688	$	(999,733	)	$	—
Fair value of derivative instruments	—		554		610		—			1,164
Payables to unconsolidated affiliates	12		40		11,957		—			12,009
Other current liabilities	51,194		174,805		247,355		(2,547		)	470,807
Total current liabilities	53,154		1,151,496		281,610		(1,002,280		)	483,980
Deferred income taxes	2,588		340,350		—		—			342,938
Fair value of derivative instruments	—		—		55		—			55
Long-term intercompany financing payable	—		231,400		93,750		(325,150		)	—
Long-term debt, net of discounts	4,540,663		—		—		—			4,540,663
Other long-term liabilities	8,453		146,715		7,954		—			163,122
Equity:
Common Units	4,297,490		8,117,920		8,033,990		(16,094,272		)	4,355,128
Class B Units	451,519		—		—		—			451,519
Non-controlling interest in consolidated subsidiaries	—		—		—		1,022,154			1,022,154
Total equity	4,749,009		8,117,920		8,033,990		(15,072,118		)	5,828,801
Total liabilities and equity	$	9,353,867	$	9,987,881	$	8,417,359	$	(16,399,548	)	$	11,359,559

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

	As of December 31, 2014
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—	$	108,887	$	—		$	108,887
Restricted cash	—		—		20,000		—			20,000
Receivables and other current assets	1,219		225,695		153,834		—			380,748
Receivables from unconsolidated affiliates, net	247		3,001		3,849		—			7,097
Intercompany receivables	633,994		24,683		178,109		(836,786		)	—
Fair value of derivative instruments	—		17,386		3,535		—			20,921
Total current assets	635,460		270,765		468,214		(836,786		)	537,653
Total property, plant and equipment, net	9,992		2,140,565		6,550,040		(47,697		)	8,652,900
Other long-term assets:
Investment in unconsolidated affiliates	—		82,616		733,226		(10,209		)	805,633
Investment in consolidated affiliates	7,990,532		6,500,008		—		(14,490,540		)	—
Intangibles, net of accumulated amortization	—		546,637		262,640		—			809,277
Fair value of derivative instruments	—		16,507		—		—			16,507
Intercompany notes receivable	186,100		—		—		(186,100		)	—
Other long-term assets	52,825		29,412		76,571		—			158,808
Total assets	$	8,874,909	$	9,586,510	$	8,090,691	$	(15,571,332	)	$	10,980,778
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	3,287	$	729,714	$	103,787	$	(836,788	)	$	—
Payables to unconsolidated affiliates	—		—		8,621		—			8,621
Other current liabilities	69,552		177,269		386,821		(2,400		)	631,242
Total current liabilities	72,839		906,983		499,229		(839,188		)	639,863
Deferred income taxes	6,162		351,098		—		—			357,260
Long-term intercompany financing payable	—		186,100		95,061		(281,161		)	—
Long-term debt, net of discounts	3,621,404		—		—		—			3,621,404
Other long-term liabilities	8,794		151,797		8,421		—			169,012
Equity:
Common Units	4,714,191		7,990,532		7,487,980		(15,434,460		)	4,758,243
Class B Units	451,519		—		—		—			451,519
Non-controlling interest in consolidated subsidiaries	—		—		—		983,477			983,477
Total equity	5,165,710		7,990,532		7,487,980		(14,450,983		)	6,193,239
Total liabilities and equity	$	8,874,909	$	9,586,510	$	8,090,691	$	(15,571,332	)	$	10,980,778

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

Condensed Consolidating Statements of Operations

	Three months ended June 30, 2015
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	232,588		$	231,920		$	(4,880	)	$	459,628
Operating expenses:
Purchased product costs	—			120,299			5,248			—			125,547
Facility expenses	—			38,920			47,291			2,430			88,641
Selling, general and administrative expenses	14,013			13,715			10,860			(3,617		)	34,971
Depreciation and amortization	393			51,470			86,712			(1,070		)	137,505
Other operating expenses (income)	—			935			1,676			—			2,611
Total operating expenses	14,406			225,339			151,787			(2,257		)	389,275

(Loss) income from operations	(14,406		)	7,249			80,133			(2,623		)	70,353

Earnings from consolidated affiliates	73,192			63,113			—			(136,305		)	—
Loss on redemption of debt	(117,860		)	—			—			—			(117,860		)
Other expense, net	(53,898		)	(4,887		)	(1,926		)	10,370			(50,341		)
(Loss) income before provision for income tax	(112,972		)	65,475			78,207			(128,558		)	(97,848		)
Provision for income tax expense (benefit)	(3,740		)	(7,716		)	—			—			(11,456		)
Net income	(109,232		)	73,191			78,207			(128,558		)	(86,392		)
Net income attributable to non-controlling interest	—			—			—			(15,094		)	(15,094		)
Net (loss) income attributable to the Partnership’s unitholders	$	(109,232	)	$	73,191		$	78,207		$	(143,652	)	$	(101,486	)

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

	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 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

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

	Six months ended June 30, 2015
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	473,913		$	463,847		$	(10,802	)	$	926,958
Operating expenses:
Purchased product costs	—			241,630			11,941			—			253,571
Facility expenses	—			76,920			98,176			5,361			180,457
Selling, general and administrative expenses	27,545			29,499			20,605			(8,043		)	69,606
Depreciation and amortization	717			102,414			171,934			(2,142		)	272,923
Other operating expenses (income)	—			1,564			429			—			1,993
Impairment expense	—			25,523			—			—			25,523
Total operating expenses	28,262			477,550			303,085			(4,824		)	804,073

(Loss) income from operations	(28,262		)	(3,637		)	160,762			(5,978		)	122,885

Earnings from consolidated affiliates	123,460			125,581			—			(249,041		)	—
Loss on redemption of debt	(117,860		)	—			—			—			(117,860		)
Other expense, net	(104,209		)	(10,486		)	(5,483		)	18,705			(101,473		)
(Loss) income before provision for income tax	(126,871		)	111,458			155,279			(236,314		)	(96,448		)
Provision for income tax expense (benefit)	(3,575		)	(12,002		)	—			—			(15,577		)
Net income	(123,296		)	123,460			155,279			(236,314		)	(80,871		)
Net income attributable to non-controlling interest	—			—			—			(29,698		)	(29,698		)
Net (loss) income attributable to the Partnership’s unitholders	$	(123,296	)	$	123,460		$	155,279		$	(266,012	)	$	(110,569	)

	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 (income) expenses	—			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 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 income attributable to the Partnership’s unitholders	$	8,705		$	121,784		$	48,812		$	(157,832	)	$	21,469

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

Condensed Consolidating Statements of Cash Flows

	Six months ended June 30, 2015
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(145,787	)	$	147,039		$	351,362		$	10,724		363,338

Cash flows from investing activities:
Restricted cash	—			—			10,000			—			10,000
Capital expenditures	(1,010		)	(121,624		)	(699,473		)	(10,955		)	(833,062		)
Equity investments in consolidated affiliates	(36,540		)	(674,134		)	—			710,674			—
Intercompany advances, net	(295,602		)	—			(12,426		)	308,028			—
Investment in unconsolidated affiliates	—			(7,071		)	(100,823		)	—			(107,894		)
Distributions from consolidated affiliates	34,736			301,130			—			(335,866		)	—
Investment in intercompany notes receivable, net	(45,300		)	—			—			45,300			—
Proceeds from disposal of property, plant and equipment	—			22			2,338			—			2,360
Net cash flows used in investing activities	(343,716		)	(501,677		)	(800,384		)	717,181			(928,596		)

Cash flows from financing activities:

Proceeds from public equity offerings, net	39,630			—			—			—			39,630
Proceeds from Credit Facility	1,260,600			—			—			—			1,260,600
Payments Credit Facility	(910,700		)	—			—			—			(910,700		)
Proceeds from long-term debt	1,848,875			—			—			—			1,848,875
Payments of long-term debt	(1,280,000		)	—			—			—			(1,280,000		)
Payments of premiums on redemption of long-term debt	(103,209		)	—			—			—			(103,209		)
Payments for debt issue costs and deferred financing costs	(20,270		)	—			—			—			(20,270		)
Payments related to intercompany financing, net	—			45,300			(1,164		)	(44,136		)	—
Proceeds from sale of equity interest in consolidated subsidiary	—			—			11,319			—			11,319
Contributions from non-controlling interest	—			—			26,689			—			26,689
Contributions from parent and affiliates	—			36,540			674,134			(710,674		)	—
Payments of SMR liability	—			(1,319		)	—			—			(1,319		)
Share-based payment activity	(6,117		)	—			—			—			(6,117		)
Payment of distributions	(339,306		)	(34,736		)	(325,683		)	335,760			(363,965		)
Intercompany advances, net	—			308,855			—			(308,855		)	—
Net cash flows provided by financing activities	489,503			354,640			385,295			(727,905		)	501,533

Net increase (decrease) in cash	—			2			(63,727		)	—			(63,725		)
Cash and cash equivalents at beginning of period	—			—			108,887			—			108,887
Cash and cash equivalents at end of period	$	—		$	2		$	45,160		$	—		$	45,162

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

	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			—
Intercompany advances, net	(808,923		)	—			—			808,923			—
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 used in investing activities	(766,719		)	(1,051,469		)	(882,805		)	1,695,835			(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 issuance costs, deferred financing costs and registration 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		)
Payments 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 provided by financing activities	863,733			760,402			937,766			(1,699,459		)	862,442

Net (decrease) increase in cash and cash equivalents	(209		)	(27,783		)	242,099			—			214,107
Cash and cash equivalents at beginning of period	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 (continued)

(unaudited)

16. Supplemental Cash Flow Information

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

	Six months ended June 30,
	2015		2014
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	109,985	$	81,031
Cash received for income taxes, net	5,308		321

Supplemental schedule of non-cash investing and financing activities:
Amounts payable for property, plant and equipment (1)	$	253,892	$	312,519
Interest capitalized on construction in progress	13,352		12,679
Issuance of common units for vesting of share-based payment awards	12,131		7,754

(1)	The June 30, 2015 total amounts payable for property, plant and equipment includes approximately $166.9 million recorded in accrued liabilities in the accompanying Condensed Consolidated Balance Sheets.

17. Subsequent Event

Merger Agreement

On July 11, 2015, the Partnership entered into the Merger Agreement with MPLX, MPLX GP, Merger Sub, and, for certain limited purposes set forth in the Merger Agreement, MPC.

Pursuant to the Merger Agreement, Merger Sub will be merged with and into the Partnership (the “Merger”), with the Partnership surviving the Merger as a wholly owned subsidiary of MPLX. After the Merger, the Partnership’s common units will cease to be publicly traded.

Under the Merger Agreement, MPC will contribute $675 million to MPLX, without receiving any new equity in exchange, and, at the effective time of the Merger (the “Effective Time”), (a) each outstanding Partnership common unit (the “Common Units”) will be converted into the right to receive 1.09 MPLX common units (the “MPLX Common Units” and, such consideration, the “Common Equity Consideration”) and an amount in cash obtained by dividing (i) $675 million by (ii) the number of Common Units plus the number of Canceled Awards (as defined below) plus the number of Partnership Class B units (the “Class B Units”), in each case outstanding as of immediately prior to the Effective Time (together with the Common Equity Consideration, the “Common Merger Consideration”) and (b) each outstanding Class B Unit will be converted into the right to receive one MPLX Class B unit (the “MPLX Class B Units”). Under the Merger Agreement, at the Effective Time, the Partnership Class A units, all of which are owned by wholly owned subsidiaries of the Partnership, will be converted into a specified number of MPLX Class A units, as more fully described in the Merger Agreement.

As a result of the Merger, each phantom unit under the Partnership’s equity plans outstanding immediately prior to the Effective Time will become fully vested and converted into an equivalent number of Common Units, which will be canceled and converted into the right to receive the Common Merger Consideration (the “Canceled Awards”). As of the Effective Time, each DER award will be canceled and the holder thereof will cease to have any rights with respect thereto, other than the right to receive distributions declared or made (but not yet paid) by the Partnership prior to the Effective Time. The payments pursuant to this paragraph are subject to any applicable withholding taxes.

The completion of the Merger is subject to certain customary conditions, including (a) the approval of the Merger Agreement by the Partnership’s unitholders entitled to vote thereon, (b) the expiration or termination of the waiting period under the Hart-Scott Rodino Antitrust Improvement Act of 1976, as amended, (c) the effectiveness of the registration statement filed by MPLX with respect to the Merger and the Common Equity Consideration and (d) the approval of the MPLX Common Units comprising the Common Equity Consideration for listing on the New York Stock Exchange. Each of the Partnership’s and MPLX’s obligation to complete the Merger is also subject to certain additional customary conditions, including (i) subject to specified standards, the accuracy of the representations and warranties of the other party and (ii) performance in all material respects by the other party of its obligations under the Merger Agreement.

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MARKWEST ENERGY PARTNERS, L.P.

Notes to the Condensed Consolidated Financial Statements (continued)

(unaudited)

The Merger Agreement contains customary representations and warranties from both the Partnership and MPLX, and also contains customary pre-closing covenants, including covenants requiring each of them to use their respective reasonable best efforts to cause the Merger to be consummated, and covenants requiring the Partnership and MPLX, subject to certain exceptions, to carry on their respective businesses in the ordinary course of business consistent with past practice during the period between the execution of the Merger Agreement and the closing of the Merger. The Merger Agreement generally requires the Partnership and the MPLX Entities to use their reasonable best efforts to resolve objections under any antitrust law.

The Merger Agreement also contains a “no shop” provision that, in general, restricts the Partnership’s ability to solicit third-party acquisition proposals or provide information to or engage in discussions or negotiations with third parties that have made or that might make an acquisition proposal. The no shop provision is subject to certain limited exceptions that allow the Partnership, under certain circumstances and in compliance with certain obligations, to provide information and participate in discussions and negotiations with respect to unsolicited third-party acquisition proposals that would reasonably be expected to lead to a Superior Proposal (as defined in the Merger Agreement).

The Merger Agreement contains certain termination rights and provides that, upon termination of the Merger Agreement under specified circumstances, including, but not limited to, a change in the recommendation of the General Partner of the Partnership, the Partnership will pay MPLX a cash termination fee of $625 million.

Under the Merger Agreement, the Partnership, MPC and the MPLX Entities have agreed that, prior to the closing of the Merger, (a) MPLX GP will increase the size of its board of directors and two directors identified by the Partnership will be appointed to such board of directors and (b) one director identified by the Partnership will be appointed to the board of directors of MPC, in each case effective immediately following the closing of the Merger. In addition, certain of the Partnership’s executive officers will retain their titles and become executive officers of MPLX GP and MPC, as the case may be.

Voting Agreement

On July 11, 2015, and in connection with the execution of the Merger Agreement, M&R MWE Liberty, LLC, which holds 7,352,691 Common Units (representing approximately 3.84% of the outstanding Common Units as of July 29, 2015), entered into a Voting Agreement with the MPLX Entities (the “Voting Agreement”), pursuant to which such holder has agreed, among other things, to vote (or cause to be voted) all Common Units owned by such holder in favor of approving the Merger Agreement. The Voting Agreement shall terminate upon termination of the Merger Agreement, and certain other specified events.

Lock-Up Agreement

On July 11, 2015, and in connection with the execution of the Merger Agreement, EMG Utica, Utica Condensate, the MPLX Entities, the Partnership and M&R MWE Liberty, L.L.C. entered into a Lock-Up Agreement (the “Lock-Up Agreement”), pursuant to which the parties thereto have agreed, among other things, not to convert any Class B Units into Common Units in connection with the Merger and that certain transfer restrictions will apply, during the six-month period following consummation of the Merger, to the MPLX Common Units that the holders of Class B Units will receive as Common Merger Consideration for its Common Units. The MPLX Class B Units will have substantially similar rights and obligations, including registration rights, as those applicable to the Class B Units, other than there will be no restrictions on the MPLX Common Units into which such MPLX Class B Units are convertible. The MPLX Class B Units will be convertible into the Common Merger Consideration on July 1, 2016 and July 1, 2017.

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

Forward-Looking Statements

Management’s Discussion and Analysis (“MD&A”) contains statements that are forward-looking and should be read in conjunction with our Condensed Consolidated Financial Statements and accompanying notes included elsewhere in this report and our Annual Report on Form 10-K for the year ended December 31, 2014. 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 that owns and operates midstream services businesses. We have a leading presence in many natural gas resource 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, 2015 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 increased approximately $19.5 million, or 9%, for the three months ended June 30, 2015 compared to the same period in 2014. The increase was comprised of the following:

· An increase of $44.5 million in our Marcellus segment with a 43% increase in gathered volumes, 59% increase in processed volumes and a 50% increase in total NGLs fractionated volumes.

· An increase of approximately $17.1 million in our Utica segment due to the significant increase in volumes at our Cadiz and Seneca complexes (as defined below) and an increase in the utilization of the Hopedale Complex (as defined below).

· A decrease of approximately $27.3 million in our Southwest segment due to a decrease in both NGL and gas prices, partially offset by higher fee-based revenue from a 7% increase in processed volumes and a 6% increase in gathered volumes.

· A decrease of approximately $14.8 million in our Northeast segment due to a decline in frac spread pricing quarter-over-quarter and a 2% decline in keep-whole NGL sales volumes.

· Realized gain from the settlement of our derivative instruments was $5.2 million for the three months ended June 30, 2015 compared to a $1.9 million realized loss for the same period in 2014.

· In June 2015, we completed a public offering for $1.2 billion in aggregate principal amount of 4.875% unsecured notes due June 2025. The proceeds from the issuance along with our Credit Facility were used to repurchase our 2020 Senior Notes, 2021 Senior Notes and 2022 Senior Notes. We recorded a total pre-tax loss during the six months ended June 30, 2015 of approximately $117.9 million related to the repurchases of the 2020 Senior Notes, 2021 Senior Notes and 2022 Senior Notes.

· During the three months ended June 30, 2015, we received net proceeds of approximately $40 million from the public offering of approximately 0.6 million newly issued Partnership common units as part of our November 2014 ATM.

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· On July 11, 2015, we entered into a Merger Agreement with MPLX pursuant to which the Partnership will become a wholly owned subsidiary of MPLX. See Note 17 of the Notes to the Condensed Consolidated Financial Statements for more information.

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,
	2015			2014			2015			2014
Segment revenue	$	486,058		$	528,577		$	968,389		$	1,046,514
Segment purchased product costs	(123,292		)	(215,860		)	(246,776		)	(427,424		)
Net operating margin	362,766			312,717			721,613			619,090
Facility expenses	(88,550		)	(83,545		)	(180,366		)	(167,250		)
Derivative gain	(2,208		)	(20,762		)	620			(16,663		)
Revenue deferral adjustment and other	6,448			375			11,610			(1,119		)
Revenue adjustment for unconsolidated affiliates (1)	(33,016		)	(3,833		)	(60,547		)	(3,833		)
Purchased product costs from unconsolidated affiliates (1)	—			36			—			36
Selling, general and administrative expenses	(34,971		)	(27,701		)	(69,606		)	(62,991		)
Depreciation	(121,909		)	(104,078		)	(241,501		)	(206,007		)
Amortization of intangible assets	(15,596		)	(15,965		)	(31,422		)	(31,943		)
Impairment expense	—			—			(25,523		)	—
Gain on disposal of property, plant and equipment	(2,417		)	(1,450		)	(1,606		)	(1,357		)
Accretion of asset retirement obligations	(194		)	(168		)	(387		)	(336		)
Income from operations	$	70,353		$	55,626		$	122,885		$	127,627

(1) These amounts relate to revenue of Partnership operated, non-wholly owned subsidiaries (See Note 3 of the Notes to the Condensed Consolidated Financial Statements). The chief operating decision maker and management include these unconsolidated affiliates to evaluate the segment performance as we operate and manage their operations. Therefore, the impact of the revenue and purchased product costs is included for segment reporting purposes, but removed for GAAP purposes.

Segment revenue, 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 revenue 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.

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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, 2014 for further discussion of each of these types of arrangements.

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

For the three months ended June 30, 2015, we calculated the following approximate percentages of our segment net operating margin from the following types of contracts:

	Fee-Based		Percent-of- Proceeds (1)		Keep- Whole (2)
Marcellus	95	%	5	%	0	%
Utica (3)	100	%	0	%	0	%
Northeast	51	%	13	%	36	%
Southwest (3)	79	%	21	%	0	%
Total (3)	90	%	9	%	1	%

For the six months ended June 30, 2015, we calculated the following approximate percentages of our segment net operating margin from the following types of contracts:

	Fee-Based		Percent-of- Proceeds (1)		Keep- Whole (2)
Marcellus	94	%	6	%	0	%
Utica (3)	100	%	0	%	0	%
Northeast	42	%	17	%	41	%
Southwest (3)	77	%	23	%	0	%
Total (3)	89	%	9	%	2	%

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

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

(3) Includes all Partnership operated, non-wholly owned subsidiaries (See Notes 3 and 14 of the Notes to the Condensed Consolidated Financial Statements).

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 availability and variations in weather patterns from year to year. Our Northeast segment could be particularly impacted by seasonality as the majority of its revenue is 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.

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Results of Operations

Segment Reporting

We present information in this MD&A by segment. The segment information appearing in Note 14 of the 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 approximately 3.8 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. We have approximately 1.2 Bcf/d of processing capacity under development.

We currently operate 192,000 Bbl/d of combined propane and heavier fractionation capacity at the Houston Fractionation Complex (the “Houston Complex”) in Washington County, Pennsylvania, the Hopedale Fractionation Complex (the “Hopedale Complex”) in Harrison County, Ohio and the Keystone Fractionation Complex in Butler County, Pennsylvania (the “Keystone Complex”). We have announced the development of an additional 31,000 Bbl/d of propane and heavier NGL fractionation at the Keystone Complex and we are currently developing an additional 60,000 Bbl/d of propane and heavier NGL fractionation capacity at our Hopedale Complex, which is shared by the Marcellus and Utica segments.

We currently have large scale de-ethanization facilities totaling 94,000 Bbl/d of capacity operational in our Marcellus segment and plan to expand our purity ethane production capacity with approximately 110,000 Bbl/d of additional capacity.

Utica Segment

MarkWest Utica EMG, a joint venture with EMG (See Note 3 of the Notes to the Condensed Consolidated Financial Statements), provides gathering, processing, fractionation and marketing services in the liquids-rich areas of the Utica Shale in eastern Ohio. Utica Condensate, an equity method investment, was formed in December 2013 and began providing condensate stabilization and terminalling services in February 2015 at our 23,000 Bbl/d facility. Ohio Gathering, an equity method investment and a subsidiary of MarkWest Utica EMG, of which we indirectly own 36%, continues to expand its gathering system in the core acreage of the Utica Shale and, during the second quarter of 2015 began gathering dry gas in eastern Ohio. In addition, Ohio Gathering operates a natural gas gathering system that currently spans more than 350 miles and provides low- and high-pressure gathering and compression services throughout a five county area in eastern Ohio. As disclosed in Notes 3 and 14 of the Notes to the Condensed Consolidated Financial Statements, we consolidate all Partnership operated, non-wholly owned subsidiaries for segment purposes.

MarkWest Utica EMG operates two processing complexes in the Utica Shale with a total capacity of 1.3 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 200 MMcf/d of additional capacity currently under development.

We currently have a de-ethanization facility totaling 40,000 Bbl/d of capacity operational in our Utica segment that is connected to ATEX. Both the Cadiz Complex and Seneca Complex are connected via a NGL gathering pipeline that extends to the Hopedale Complex. As discussed above, the Hopedale Complex consists of a 120,000 Bbl/d facility that provides fractionation services for NGLs produced in the Utica and the Marcellus segments and will be expanded by an additional 60,000 Bbl/d.

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Northeast Segment

Our Northeast segment has processing capacity of approximately 620 MMcf/d and fractionation capacity of 24,000 Bbl/d. The Siloam fractionation facility can also be used to provide fractionation services to customers of MarkWest Liberty Midstream and MarkWest Utica EMG. 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 utilized by the Siloam facility as well as MarkWest Liberty Midstream and MarkWest Utica EMG producer customers. 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. In December 2014, we commenced operations of an additional 120 MMcf/d processing plant in our East Texas area, bringing our total capacity in East Texas to 520 MMcf/d. Furthermore, in May 2015 we announced an 80 MMcf/d gas processing facility expansion in the Haynesville Shale that, upon completion, will increase processing capacity in East Texas to 600 MMcf/d.

· Oklahoma. We own gas gathering systems in the Granite Wash formation of Western Oklahoma and the Texas panhandle, both of which are connected to natural gas processing complexes in Western Oklahoma. Our 200 MMcf/d Buffalo Creek plant and high-pressure gathering trunkline commenced operations in February 2014. The addition of the Buffalo Creek plant brought our total natural gas processing capacity in Western Oklahoma to 435 MMcf/d.

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. Centrahoma commenced operations of an additional 120 MMcf/d processing capacity at its Stonewall plant in the second quarter of 2014. We agreed to fund the construction of an additional 80 MMcf/d processing capacity at Centrahoma’s Stonewall plant, of which 40 MMcf/d became operational in December 2014. The remaining 40 MMcf/d of additional capacity will commence operations in mid-2015. Through another equity method investment, MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with the Midcontinent Express Pipeline and Gulf Crossing Pipeline at Bennington, Oklahoma, and is designed to provide approximately 638,000 Dth/d of Woodford Shale takeaway capacity.

· Javelina. We own and operate the 142 MMcf/d Javelina processing and 29,000 Bbl/d fractionation facility in Corpus Christi, Texas, which treats, processes and fractionates off-gas from six refineries operated by three different refinery customers.

· 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 also operate natural gas gathering pipelines and field compression to support production from Newfield Exploration Co.’s West Asherton area of the Eagle Ford Shale in Dimmit County, Texas.

· West Texas Development. In June 2015, we announced long-term, fee-based agreements to support producer development in the Delaware Basin of West Texas. Pursuant to these agreements, we will install a 200 MMcf/d cryogenic gas processing plant in Culberson County, Texas. The new facility is scheduled to commence operations during the second quarter of 2016.

The following summarizes the percentage of our segment revenue and net operating margin (both non-GAAP financial measures, see above) generated by our assets, by segment, for the six months ended June 30, 2015:

	Marcellus		Utica		Northeast		Southwest
Segment revenue	41	%	13	%	5	%	41	%
Net operating margin	53	%	17	%	4	%	26	%

Segment Operating Results

Items below Income from operations in our Condensed Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual business segments. Management does not consider these items allocable to or controllable by any individual business segment and therefore

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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 of the Notes to the Condensed Consolidated Financial Statements, Ohio Gathering was deconsolidated effective June 1, 2014 and its financial position as of June 1, 2014 and results of operations are reported under the equity method of accounting as of June 1, 2014 and for the six months ended June 30, 2015, 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. In addition, the Partnership’s Chief Executive Officer views all Partnership operated, non-wholly owned subsidiaries as if they were consolidated. The tables below present financial information, as evaluated by management, for the reported segments for the six months ended June 30, 2015 and 2014.

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, 2015 compared to three months ended June 30, 2014

Marcellus

	Three months ended June 30,
	2015		2014		$ Change			% Change
			(in thousands)
Segment revenue	$	199,311	$	183,734	$	15,577		8	%
Segment purchased product costs	4,568		39,710		(35,142		)	(88	)%
Net operating margin	194,743		144,024		50,719			35	%
Segment facility expenses	39,938		33,755		6,183			18	%

Operating income before items not allocated to segments	$	154,805	$	110,269	$	44,536		40	%

Segment Revenue. Revenue increased $15.6 million due to the ongoing expansion of the Marcellus segment operations that resulted in increased gathered, processed and fractionated volumes. Approximately $60.3 million of the increase is due to increased processing capacities and corresponding volumes offset by approximately $33.8 million related to a decrease in NGL inventory sold. Due to changes in contractual terms, we expect NGL inventory sold to continue to be at lower levels in 2015 as compared to 2014. Revenue also decreased approximately $11.0 million due to lower NGL prices received partially offset by higher volumes for our percent of proceeds contract compared to the same period in 2014.

Segment Purchased Product Costs. Purchased product costs decreased primarily due to a decrease in inventory sold.

Net Operating Margin. Net operating margin mainly increased as the volume of natural gas gathered, natural gas processed, and NGL products fractionated increased by 43%, 59% and 50%, respectively. Approximately 95% of the net operating margin was earned under fee-based contracts.

Segment Facility Expenses. Facility expenses increased due to the ongoing expansion of the Marcellus segment operations, offset by reductions in discretionary spending.

Utica

	Three months ended June 30,
	2015		2014		$ Change			% Change
			(in thousands)
Segment revenue	$	63,942	$	30,826	$	33,116		107	%
Segment purchased product costs	679		7,353		(6,674		)	(91	)%
Net operating margin	63,263		23,473		39,790			170	%
Segment facility expenses	15,952		12,174		3,778			31	%
Segment portion of operating income attributable to non-controlling interests	23,633		4,687		18,946			404	%
Operating income before items not allocated to segments	$	23,678	$	6,612	$	17,066		258	%

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Segment Revenue. Revenue increased $33.1 million, of which approximately $14.4 million was due to processing fee revenue increases primarily from a 159% increase in volumes. Approximately $19.8 million of the increase was due to an increase in gathering and compression fees revenue from a 209% increase in volumes. Approximately $5.6 million of the increase was due to an increase in fractionation, marketing and transportation fees resulting from a 151% increase in fractionated volumes. These increases were partially offset by a decrease of approximately $6.8 million in NGL sales primarily due to decreases of sales of inventory over the same period in 2014.

Segment Purchased Product Costs. Purchased product costs decreased due to a decrease in inventory sold compared to the same period in 2014.

Net Operating Margin. Net operating margin increased due to an overall increase in operations in the second quarter of 2015 compared to the same period in 2014. All of our gathering, processing and fractionation 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 and NGLs fractionated increasing by 209%, 159% and 151%, respectively.

Segment Facility Expenses. Facility expenses increased due to the significant increase in operations as compared to 2014.

Segment portion of operating income attributable to non-controlling interests. The segment portion of operating income attributable to non-controlling interests change is primarily due to Ohio Gathering, which was a jointly owned entity effective June 1, 2014.

Northeast

	Three months ended June 30,
	2015		2014		$ Change			% Change
			(in thousands)
Segment revenue	$	22,595	$	43,777	$	(21,182	)	(48	)%
Segment purchased product costs	9,743		15,169		(5,426		)	(36	)%
Net operating margin	12,852		28,608		(15,756		)	(55	)%
Segment facility expenses	7,584		8,509		(925		)	(11	)%
Operating income before items not allocated to segments	$	5,268	$	20,099	$	(14,831	)	(74	)%

Segment Revenue. Revenue decreased primarily due to a decrease in NGL sale prices.

Segment Purchased Product Costs. Purchased product costs decreased due to decreases in natural gas purchase prices and lower keep-whole contract volumes.

Net Operating Margin. Net operating margin decreased due to a decrease in the frac spread margins of 72% compared to the same period in 2014. Approximately 36% of the net operating margin was derived from keep-whole contracts for the three months ended June 30, 2015 compared to 55% for the same period in 2014. In 2015, we expect frac spread margins to continue to be lower than 2014 assuming the current low NGL pricing continues.

Segment Facility Expenses. Facility expenses decreased slightly due primarily to a decrease in plant operating expenses attributable to the timing of normal facility maintenance and repairs as well as by reductions in discretionary spending.

Southwest

	Three months ended June 30,
	2015		2014		$ Change			% Change
			(in thousands)
Segment revenue	$	200,210	$	271,140	$	(70,930	)	(26	)%
Segment purchased product costs	108,302		153,628		(45,326		)	(30	)%
Net operating margin	91,908		117,512		(25,604		)	(22	)%
Segment facility expenses	33,993		34,354		(361		)	(1	)%
Segment portion of operating income attributable to non-controlling interests	2,062		6		2,056			34,267	%
Operating income before items not allocated to segments	$	55,853	$	83,152	$	(27,299	)	(33	)%

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Segment Revenue. Revenue decreased $70.9 million due to lower NGL sales, partially offset by higher gas sales and higher fee-based revenue. The decrease in NGL sales volumes of 13% is primarily due to operating at lower levels of ethane recovery. NGL sales decreases of approximately $34.8 million, $28.4 million and $15.9 million in our East Texas, Western Oklahoma and Southeast Oklahoma areas due to decreases in NGL sales volumes of approximately 5% and 33% in our East Texas and Western Oklahoma areas, respectively, and decreases in average C3+ NGL prices of 52%, 61% and 57%, respectively. Hydrogen fees decreased approximately $8.1 million due to a 16% decrease in volumes and 42% decrease in prices for the three months ended June 30, 2015 compared to the same period in 2014. Processing fee revenue increased by approximately $3.7 million due to an increase in processed volumes of 7% and gathering fee revenue increased by approximately $6.1 million due to a 6% increase of gathered volumes. Gas sales increased approximately $7.5 million mainly due to operating in an environment of higher ethane rejection during the three months ended June 30, 2015 compared to the same period in 2014.

Segment Purchased Product Costs. Purchased product costs decreased by approximately $45.3 million mainly due to lower NGL sales volumes and a 55% decrease in C3+ NGL prices. Purchased product costs decreased as a percent of sales by 2% due a 15% increase in fee revenue.

Net Operating Margin. Net operating margin decreased mainly due to a 55% decrease in C3+ NGL prices, partially offset by higher fee-based revenue due to an increase of 7% in natural gas processed and a 6% increase in gathered volumes.

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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, 2015 and 2014, 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,
	2015			2014			$ Change			% Change
				(in thousands)
Total segment revenue	$	486,058		$	528,577		$	(42,519	)	(8	)%
Derivative gain (loss) not allocated to segments	138			(6,753		)	6,891			(102	)%
Revenue adjustment for unconsolidated affiliates	(33,016		)	(3,833		)	(29,183		)	761	%
Revenue deferral adjustment and other	6,448			375			6,073			1,619	%
Total revenue	$	459,628		$	518,366		$	(58,738	)	(11	)%

Operating income before items not allocated to segments	$	239,604		$	220,132		$	19,472		9	%
Portion of operating income attributable to non-controlling interests	11,495			4,184			7,311			175	%
Derivative loss not allocated to segments	(2,208		)	(20,762		)	18,554			(89	)%
Revenue adjustment for unconsolidated affiliates	(33,016		)	(3,833		)	(29,183		)	761	%
Revenue deferral adjustment	1,076			375			701			187	%
Compensation expense included in facility expenses not allocated to segments	(942		)	(903		)	(39		)	4	%
Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliates	12,543			2,598			9,945			383	%
Portion of operating income attributable to non-controlling interests of unconsolidated affiliates	14,200			509			13,691			2,690	%
Facility expense adjustments	2,688			2,688			—			0	%
Selling, general and administrative expenses	(34,971		)	(27,701		)	(7,270		)	26	%
Depreciation	(121,909		)	(104,078		)	(17,831		)	17	%
Amortization of intangible assets	(15,596		)	(15,965		)	369			(2	)%
Loss on disposal of property, plant and equipment	(2,417		)	(1,450		)	(967		)	67	%
Accretion of asset retirement obligations	(194		)	(168		)	(26		)	15	%
Income from operations	70,353			55,626			14,727			26	%
Earnings (loss) from unconsolidated affiliates	3,262			(721		)	3,983			(552	)%
Interest expense	(52,087		)	(43,391		)	(8,696		)	20	%
Amortization of deferred financing costs and debt discount (a component of interest expense)	(1,562		)	(1,449		)	(113		)	8	%
Loss on redemption of debt	(117,860		)	—			(117,860		)	N/A
Miscellaneous income, net	46			43			3			7	%
Income before provision for income tax	$	(97,848	)	$	10,108		(107,956		)	(1,068	)%

Derivative Loss Not Allocated to Segments. Unrealized loss from the change in fair value of our derivative instruments was $7.4 million for the three months ended June 30, 2015 compared to an unrealized loss of $18.8 million for the same period in 2014. Realized gain from the settlement of our derivative instruments was $5.2 million for the three months ended June 30, 2015 compared to a realized loss of $1.9 million for the same period in 2014. The total change of $18.6 million is due primarily to volatility in commodity prices.

Revenue Adjustment for Unconsolidated Affiliates. Revenue adjustment for unconsolidated affiliates relates to revenue of Partnership operated, non-wholly owned subsidiaries. The chief operating decision maker and management include these to evaluate the segment performance as we operate these unconsolidated affiliates, therefore, the impact of the revenue is included for segment reporting purposes, but removed to reconcile to GAAP revenue (See Notes 3 and 14 of the Notes to the Condensed Consolidated Financial Statements).

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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. Beginning in March 2015, the cash consideration received from the Southwest segment contract declined and the reported segment revenue was less than the revenue recognized for GAAP purposes. For the three months ended June 30, 2015, approximately $0.2 million of the revenue deferral adjustment is attributable to the Southwest segment. Beginning in the second quarter of 2015, the cash consideration received from the Northeast segment contract declined and the reported segment revenue was less than the revenue recognized for GAAP purposes. For the three months ended June 30, 2015, approximately $0.9 million of the revenue deferral adjustment is attributable to the Northeast segment. For the three months ended June 30, 2014, approximately $0.2 million and $1.5 million of the revenue deferral adjustment was attributable to the Southwest segment and Northeast segment, respectively. Other consists of management fee revenues from unconsolidated affiliates of $5.4 million for the three months ended June 30, 2015 compared to $2.1 million for the three months ended June 30, 2014. Operational Service fees have increased from 2014 due to the Ohio Gathering deconsolidation, as well as the formation of Ohio Condensate and Utica Condensate.

Facility Expense, Operational Service Fees and Purchased Product Cost Adjustments for Unconsolidated Affiliates. Facility expense and purchased product cost adjustments for unconsolidated affiliates relates to Ohio Gathering (See discussion above in Revenue Adjustment for Unconsolidated Affiliates and Notes 3 and 14 of the Notes to the Condensed Consolidated Financial Statements).

Portion of Operating Income Attributable to Non-controlling Interests of Unconsolidated Affiliates. Portion of operating income attributable to non-controlling interests of unconsolidated affiliate relates to joint venture partners’ portion of operating income, which occurs because segment operating income is reported as if Partnership operated unconsolidated affiliates were consolidated (see discussion above in Revenue Adjustment for Unconsolidated Affiliates and Notes 3 and 14 of the Notes to the Condensed Consolidated Financial Statements).

Facility Expenses Adjustments. 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.

Selling, General and Administrative Expenses. Selling, general and administrative expenses have increased to support the continued growth in our operations and approximately $2.5 million for consulting fees related to the Merger Agreement, offset by reductions in discretionary spending.

Depreciation. Depreciation increased due to additional projects completed during late 2014 and throughout 2015 mainly in the Utica and Marcellus segments, partially offset by a $6.0 million decrease from the deconsolidation of Ohio Gathering.

Interest Expense. Interest expense increased due to the greater average balance in 2015 outstanding borrowings related to our 2024 Senior Notes issued in November 2014 and March 2015.

Loss on Redemption of Debt. We recorded a total pre-tax loss during the six months ended June 30, 2015 related to repurchases of $500.0 million of the 2020 Senior Notes, $325.0 million of the 2021 Senior Notes and $455.0 million of the 2022 Senior Notes. The pre-tax loss recorded in the second quarter of 2015 consisted of approximately $14.7 million related to the non-cash write-off of the unamortized discount and deferred finance costs and approximately $103.2 million related to the payment of redemption premiums and third party expenses. See Note 9 of the Notes to the Condensed Consolidated Financial Statements.

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Six months ended June 30, 2015 compared to six months ended June 30, 2014

Marcellus

	Six months ended June 30,
	2015		2014		$ Change			% Change
			(in thousands)
Segment revenue	$	396,487	$	358,893	$	37,594		10	%
Segment purchased product costs	11,070		74,000		(62,930		)	(85	)%
Net operating margin	385,417		284,893		100,524			35	%
Segment facility expenses	83,320		69,228		14,092			20	%

Operating income before items not allocated to segments	$	302,097	$	215,665	$	86,432		40	%

Segment Revenue. Revenue increased $37.6 million due to the ongoing expansion of the Marcellus segment operations that resulted in increased gathered, processed and fractionated volumes. Revenue increased approximately $124.0 million due to increased processing capacities and corresponding volumes. Revenue decreased approximately $64.9 million primarily due to a decrease in NGL inventory sold. Due to changes in contractual terms, we expect NGLs inventory sold to be at lower levels in 2015 as compared to 2014. Revenue also decreased approximately $21.8 million due to lower NGL prices received for our percent of proceeds contract compared to the same period in 2014.

Segment Purchased Product Costs. Purchased product costs decreased primarily due to a decrease in inventory sold.

Net Operating Margin. Net operating margin mainly increased due to increased fee revenue, as the volume of natural gas gathered, natural gas processed, and NGL products fractionated increased by 39%, 66% and 51%, respectively. The increase was partially offset by the impact of lower NGL prices on our percent of proceeds contract of $21.8 million. Approximately 94% of the net operating margin was earned under fee-based contracts.

Segment Facility Expenses. Facility expenses increased due to the ongoing expansion of the Marcellus segment operations, offset by reductions in discretionary spending.

Utica

	Six months ended June 30,
	2015		2014		$ Change			% Change
			(in thousands)
Segment revenue	$	122,853	$	54,592	$	68,261		125	%
Segment purchased product costs	860		11,488		(10,628		)	(93	)%
Net operating margin	121,993		43,104		78,889			183	%
Segment facility expenses	32,590		24,026		8,564			36	%
Segment portion of operating income attributable to non-controlling interests	43,740		7,823		35,917			459	%
Operating income before items not allocated to segments	$	45,663	$	11,255	$	34,408		306	%

Segment Revenue. Revenue increased $68.3 million, of which approximately $29.1 million was due to processing fee revenue increases primarily from a 178% increase in volumes. Approximately $34.2 million of the increase was due to an increase in gathering and compression fees revenue from a 194% increase in volumes. Approximately $14.4 million of the increase was due to an increase in fractionation, marketing and transportation fees resulting from a 164% increase in fractionated volumes. These increases were partially offset by a decrease of approximately $9.7 million in NGL sales primarily due to decreases of sales of inventory over the same period in 2014.

Segment Purchased Product Costs. Purchased product costs decreased due to a decrease in inventory sold compared to the same period in 2014.

Net Operating Margin. Net operating margin increased due to an overall increase in operations in the first half of 2015 compared to the same period in 2014. All of our gathering, processing and fractionation 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 and NGLs fractionated increasing by 194%, 178% and 164%, respectively.

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Segment Facility Expenses. Facility expenses increased due to the significant increase in operations as compared to 2014.

Northeast

	Six months ended June 30,
	2015		2014		$ Change			% Change
			(in thousands)
Segment revenue	$	52,616	$	105,030	$	(52,414	)	(50	)%
Segment purchased product costs	22,261		35,624		(13,363		)	(38	)%
Net operating margin	30,355		69,406		(39,051		)	(56	)%
Segment facility expenses	14,462		15,623		(1,161		)	(7	)%
Operating income before items not allocated to segments	$	15,893	$	53,783	$	(37,890	)	(70	)%

Segment Revenue. Revenue decreased due to a decrease in NGL sale prices.

Segment Purchased Product Costs. Purchased product costs decreased due to decreases in natural gas purchase prices and lower keep-whole contract volumes.

Net Operating Margin. Net operating margin decreased due to a decrease in the frac spread margins of 69% and decreases in NGL pricing for the percent-of-proceeds business compared to the same period in 2014. Approximately 41% of the net operating margin was derived from keep-whole contracts in 2015 compared to 63% in 2014. In 2015, we expect frac spread margins to continue to be lower than 2014 assuming the current low NGL pricing continues.

Southwest

	Six months ended June 30,
	2015		2014		$ Change			% Change
			(in thousands)
Segment revenue	$	396,477	$	530,470	$	(133,993	)	(25	)%
Segment purchased product costs	212,585		306,312		(93,727		)	(31	)%
Net operating margin	183,892		224,158		(40,266		)	(18	)%
Segment facility expenses	67,910		66,876		1,034			2	%
Segment portion of operating income attributable to non-controlling interests	3,609		5		3,604			72,080	%
Operating income before items not allocated to segments	$	112,373	$	157,277	$	(44,904	)	(29	)%

Segment Revenue. Revenue decreased $134.0 million due to lower NGL sales, partially offset by higher gas sales and higher fee-based revenue. NGL sales decreased approximately $163.8 million due to an overall decrease of NGL prices and total NGL sales volumes of 9% partially due to higher ethane rejection during the six months ended June 30, 2015 compared to the same period in 2014. NGL sales decreased approximately $69.5 million in our Western Oklahoma area due to a 35% decrease in NGL sales volumes and a 65% decrease in C3+ NGL prices. NGL sales decreased in our East Texas, Southeast Oklahoma and Javelina areas for the six months ended June 30, 2015 over the same period in 2014 by approximately $61.8 million, $25.1 million and $5.5 million due to C3+ NGL price decreases of approximately 53%, 54%, and 48%, respectively. Hydrogen fees decreased approximately $10.1 million due to an 11% decrease in volumes and 41% decrease in prices for the six months ended June 30, 2015 compared to the same period in 2014. Processing fee revenue increased by approximately $11.3 million due to an increase in processed volumes of 14%, higher average rates and fees charged on volumes going off system excluded from processed volumes. Gathering fee revenue increased by approximately $8.5 million due to a 10% increase of gathered volumes. Gas sales increased approximately $14.9 million mainly due to operating in an environment of higher ethane rejection during the six months ended June 30, 2015 compared to the same period in 2014.

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Segment Purchased Product Costs. Purchased product costs decreased by approximately $93.7 million mainly due to lower NGL sales volumes and a 56% decrease in C3+ NGL prices. Purchased product costs decreased as a percent of sales by 4% due to a 20% increase in fee revenue.

Net Operating Margin. Net operating margin decreased mainly due to a 56% decrease in C3+ NGL prices, partially offset by higher fee-based revenue due to an increase of 14% in natural gas processed and a 10% increase in gathered volumes.

Segment Facility Expenses. Facility expenses increased by approximately $1.0 million, primarily due to repairs and maintenance in our East Texas area. Additional chemical and amine reclamation projects offset prior year compressor repairs of $2.2 million in our Javelina area. These increases were offset by reductions in discretionary spending.

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, 2015 and 2014, 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,
	2015			2014			$ Change			% Change
				(in thousands)
Total segment revenue	$	968,389		$	1,046,514		$	(78,125	)	(7	)%
Derivative gain (loss) not allocated to segments	7,506			(10,720		)	18,226			(170	)%
Revenue adjustment for unconsolidated affiliates	(60,547		)	(3,833		)	(56,714		)	1,480	%
Revenue deferral adjustment and other	11,610			(1,119		)	12,729			(1,138	)%
Total revenue	$	926,958		$	1,030,842		$	(103,884	)	(10	)%

Operating income before items not allocated to segments	$	476,026		$	437,980		$	38,046		9	%
Portion of operating income attributable to non-controlling interests	22,909			7,319			15,590			213	%
Derivative gain (loss) not allocated to segments	620			(16,663		)	17,283			(104	)%
Revenue adjustment for unconsolidated affiliates	(60,547		)	(3,833		)	(56,714		)	1,480	%
Revenue deferral adjustment	154			(1,119		)	1,273			(114	)%
Compensation expense included in facility expenses not allocated to segments	(2,049		)	(1,906		)	(143		)	8	%
Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliates	26,001			2,598			23,403			901	%
Portion of operating income attributable to non-controlling interests of unconsolidated affiliates	24,440			509			23,931			4,702	%
Facility expenses adjustments	5,376			5,376			—			0	%
Selling, general and administrative expenses	(69,606		)	(62,991		)	(6,615		)	11	%
Depreciation	(241,501		)	(206,007		)	(35,494		)	17	%
Amortization of intangible assets	(31,422		)	(31,943		)	521			(2	)%
Impairment expense	(25,523		)	—			(25,523		)	N/A
Loss on disposal of property, plant and equipment	(1,606		)	(1,357		)	(249		)	18	%
Accretion of asset retirement obligations	(387		)	(336		)	(51		)	15	%
Income from operations	122,885			127,627			(4,742		)	(4	)%
Earnings (loss) from unconsolidated affiliates	3,774			(471		)	4,245			(901	)%
Interest expense	(102,144		)	(84,375		)	(17,769		)	21	%
Amortization of deferred financing costs and debt discount (a component of interest expense)	(3,197		)	(4,273		)	1,076			(25	)%
Loss on redemption of debt	(117,860		)	—			(117,860		)	N/A
Miscellaneous income, net	94			62			32			52	%
Income before provision for income tax	$	(96,448	)	$	38,570		(135,018		)	(350	)%

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Derivative Gain (Loss) Not Allocated to Segments. Unrealized loss from the change in fair value of our derivative instruments was $15.5 million for the six months ended June 30, 2015 compared to an unrealized loss of $7.0 million for the same period in 2014. Realized gain from the settlement of our derivative instruments was $16.1 million for the six months ended June 30, 2015 compared to a realized loss of $9.6 million for the same period in 2014. The total change of $17.3 million is due primarily to volatility in commodity prices.

Revenue Deferral Adjustment and Other. Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. In March 2015, the cash consideration received from the Southwest segment contract declined and the reported segment revenue was less than the revenue recognized for GAAP purposes. For the six months ended June 30, 2015, approximately $0.1 million of the revenue deferral adjustment is attributable to the Southwest segment. Beginning in the second quarter of 2015, the cash consideration received from the Northeast segment contract declined and the reported segment revenue will be less than the revenue recognized for GAAP purposes. For the six months ended June 30, 2015, approximately $0.1 million of the revenue deferral adjustment is attributable to the Northeast segment. For the six months ended June 30, 2014, approximately $0.4 million and $3.4 million of the revenue deferral adjustment was attributable to the Southwest segment and Northeast segment, respectively. Other consists of management fee revenues from unconsolidated affiliates of $11.5 million for the six months ended June 30, 2015 compared to $2.7 million for the six months ended June 30, 2014. Operational Service fees have increased from 2014 due to the Ohio Gathering deconsolidation, as well as the formation of Ohio Condensate and Utica Condensate.

Portion of Operating Income Attributable to Non-controlling Interests of Unconsolidated Affiliates. Portion of operating income attributable to non-controlling interests of unconsolidated affiliate relates to joint venture partners’ portion of operating income, which occurs because segment operating income is reported as if Partnership operated unconsolidated affiliates were being consolidated (see discussion above in Revenue Adjustment for Unconsolidated Affiliates, Note 3 and Note 14 of the Notes to the Condensed Consolidated Financial Statements). The increase year over year is due to the continued growth of Ohio Gathering.

Selling, General and Administrative Expenses. Selling, general and administrative expenses have increased to support the continued growth in our operations, offset by reductions in discretionary spending.

Depreciation. Depreciation increased due to additional projects completed during late 2014 and throughout 2015 mainly in the Utica and Marcellus segments, partially offset by $14.6 million decrease from the deconsolidation of Ohio Gathering.

Impairment Expense. We recorded a total impairment expense of $25.5 million, of which approximately $16.8 million relates to intangibles and $6.0 million to property, plant and equipment for the six months ended June 30, 2015. See Note 8 of the Notes to the Condensed Consolidated Financial Statements for further information.

Interest Expense. Interest expense increased due to the greater average balance in 2015 outstanding borrowings related to our 2024 Senior Notes issued in November 2014 and March 2015.

Loss on redemption of debt. We recorded a total pre-tax loss during the six months ended June 30, 2015 related to repurchases of $500.0 million of the 2020 Senior Notes, $325.0 million of the 2021 Senior Notes and $455.0 million of the 2022 Senior Notes. See Note 9 of the Notes to the Condensed Consolidated Financial Statements.

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Operating Data

	Three months ended June 30,				Six months ended June 30,
	2015	2014	% Change		2015	2014	% Change
Marcellus
Gathering system throughput (Mcf/d)	857,100	599,500	43	%	835,900	600,500	39	%
Natural gas processed (Mcf/d)	2,894,500	1,823,200	59	%	2,869,700	1,732,500	66	%

C2 produced (Bbl/d)	61,400	45,900	34	%	58,100	47,400	23	%
C3+ NGLs fractionated (Bbl/d) (1)	131,100	82,200	59	%	128,800	76,200	69	%
Total NGLs fractionated (Bbl/d)	192,500	128,100	50	%	186,900	123,600	51	%

Utica
Gathering system throughput (Mcf/d)	582,700	188,700	209	%	542,500	184,700	194	%
Natural gas processed (Mcf/d)	761,600	293,800	159	%	758,500	272,700	178	%

C2 produced (Bbl/d)	4,100	—	N/A		4,000	—	N/A
C3+ NGLs fractionated (Bbl/d) (1)	29,800	13,500	121	%	30,000	12,900	133	%
Total NGLs fractionated (Bbl/d)	33,900	13,500	151	%	34,000	12,900	164	%

Condensate stabilized (Bbl/d) (2)	8,900	—	N/A		6,100	—	N/A

Northeast
Natural gas processed (Mcf/d)	278,500	281,500	(1	)%	272,300	268,600	1	%
NGLs fractionated (Bbl/d) (3)	15,400	17,500	(12	)%	15,200	17,500	(13	)%

Keep-whole NGL sales (gallons, in thousands)	24,400	24,800	(2	)%	55,600	57,000	(2	)%
Percent-of-proceeds NGL sales (gallons, in thousands)	30,700	29,900	3	%	60,900	56,000	9	%
Total NGL sales (gallons, in thousands) (4)	55,100	54,700	1	%	116,500	113,000	3	%

Crude oil transported for a fee (Bbl/d)	10,000	10,600	(6	)%	10,200	10,200	0	%

Southwest
East Texas gathering systems throughput (Mcf/d)	615,400	549,500	12	%	615,600	522,800	18	%
East Texas natural gas processed (Mcf/d)	490,000	398,500	23	%	493,500	383,400	29	%
East Texas NGL sales (gallons, in thousands) (5)	103,600	109,500	(5	)%	210,800	203,400	4	%

Western Oklahoma gathering systems throughput (Mcf/d) (6)	345,900	348,200	(1	)%	344,200	322,700	7	%
Western Oklahoma natural gas processed (Mcf/d) (7)	287,500	296,300	(3	)%	289,300	269,800	7	%
Western Oklahoma NGL sales (gallons, in thousands) (5)	38,400	56,900	(33	)%	72,900	111,300	(35	)%

Southeast Oklahoma gathering systems throughput (Mcf/d)	427,800	414,500	3	%	410,200	398,200	3	%
Southeast Oklahoma natural gas processed (Mcf/d) (8)	184,500	186,600	(1	)%	181,600	167,000	9	%
Southeast Oklahoma NGL sales (gallons, in thousands)	30,900	29,200	6	%	59,500	50,200	19	%
Arkoma Connector Pipeline throughput (Mcf/d) (9)	237,300	229,600	3	%	223,700	227,400	(2	)%

Other Southwest gathering systems throughput (Mcf/d) (10)	56,200	48,900	15	%	51,200	47,900	7	%

Javelina refinery off-gas processed (Mcf/d)	101,800	112,000	(9	)%	101,000	111,300	(9	)%
Javelina liquids fractionated (Bbl/d) (11)	17,300	21,000	(18	)%	16,600	20,200	(18	)%
Javelina NGL sales (gallons, in thousands) (11)	66,200	80,300	(18	)%	126,200	153,300	(18	)%

Total Southwest gathering system throughput (Mcf/d)	1,445,300	1,361,100	6	%	1,421,200	1,291,600	10	%
Total Southwest natural gas and refinery off-gas processed (Mcf/d)	1,063,800	993,400	7	%	1,065,400	931,500	14	%
Total Southwest NGL sales (gallons, in thousands)	239,100	275,900	(13	)%	469,400	518,200	(9	)%

(1) The Hopedale Complex is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG. Each segment includes its respective portion of the capacity utilized of the jointly owned Hopedale Complex. Operations began in January 2014, and a second fractionation facility began operations in December 2014. The volumes reported for 2014 are the average daily rate for the days of operation.

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(2) Utica Condensate operations began in February 2015. The volumes reported are the average daily rate for the days of operation. Utica Condensate is consolidated for segment purposes only.

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

(4) Represents sales at the Siloam fractionator. The total sales exclude approximately zero gallons and 8,757,000 gallons sold by the Northeast on behalf of Marcellus and Utica for the three months ended June 30, 2015 and 2014, respectively. The total sales exclude approximately 499,000 gallons and 22,010,000 gallons sold by the Northeast on behalf of Marcellus and Utica for the six months ended June 30, 2015 and 2014, respectively. These volumes are included as part of NGLs sold at Marcellus and Utica.

(5) Excludes gallons processed in conjunction with take in kind contracts for the six months ended June 30, 2015 and June 30, 2014, respectively, as shown below.

Gallons processed in conjunction with take	Three months ended June 30,		Six months ended June 30,
in kind contracts	2015	2014	2015	2014
East Texas	—	—	—	318,000
Western Oklahoma	30,033,000	41,969,000	60,565,000	53,685,000

(6) 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. The three and six months ended June 30, 2015 includes approximately 18,900 Mcf/d and 13,000 Mcf/d, respectively, related to new gathering in the Cana-Woodford Shale of Western Oklahoma.

(7) The Buffalo Creek plant began operations in February 2014.

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

(9) The Arkoma connector pipeline is consolidated for segment purposes only.

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

(11) Excludes Hydrogen volumes.

Liquidity and Capital Resources

There have not been any material changes during the six months ended June 30, 2015 to what was previously disclosed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources in our Annual Report on Form 10-K for the year ended December 31, 2014, except as noted below.

· Credit Facility. In February 2015, we entered into an amendment to our Credit Facility, which permanently increases our maximum possible leverage ratio to 5.5 to 1.0 until the Collateral Release Date. As of July 29, 2015, we had $510.4 million of borrowings outstanding and $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $778.3 million of unused capacity, all of which was available for borrowing based on financial covenant requirements. For further discussion of the Senior Notes and the accounting impacts, see Note 9 of the Notes to the Condensed Consolidated Financial Statements.

· Senior Notes. In March 2015, we completed a public offering of $650.0 million aggregate principal amount of 4.875% of unsecured notes due 2024. In June 2015, we completed a public offering of $1.2 billion aggregate principal amount of 4.875% unsecured notes due 2025. The proceeds from the issuance of the 2025 Senior Notes issued in June 2015 along with our borrowings under the Credit Facility were used to repurchase $500.0 million of the 2020 Senior Notes, $325.0 million of the 2021 Senior Notes and $455.0 million of the 2022 Senior Notes. For further discussion of the Senior Notes, see Note 9 of the Notes to the Condensed Consolidated Financial Statements.

· Credit Ratings. As of July 29, 2015, 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.

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· Joint Venture Partners. We have contributed approximately $1,379.6 million as of June 30, 2015 to MarkWest Utica EMG. For further discussion see Note 3 of the Notes to these Condensed Consolidated Financial Statements.

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 2015 capital plan is summarized in the table below (in millions):

	2015 Full Year Plan						Actual
							Six months ended
	Low			High			June 30, 2015
Total growth capital (1)	$	1,675		$	2,100		$	996
Joint venture partner’s estimated share of growth capital	(175		)	(200		)	(116		)
Partnership share of growth capital	$	1,500		$	1,900		$	880

(1) Growth capital includes expenditures made to expand the existing operating capacity to increase volumes gathered, processed, transported or fractionated, or to decrease operating expenses, within our facilities. Growth capital also includes costs associated with new well connections. In general, growth capital includes costs that are expected to generate additional or new cash flow for the Partnership. Growth capital excludes expenditures for third-party acquisitions and equity investment. Growth capital actual includes capital of approximately $170.4 million related to Partnership operated, unconsolidated affiliates. Maintenance capital was approximately $7.8 million for the six months ended June 30, 2015. Maintenance capital includes capital expenditures made to maintain our operating capacity and asset base.

Continuous Equity Offering Program

Our public equity offerings for the six months ended June 30, 2015 are summarized in the table below (in millions).

	Three months ended June 30, 2015			Three months ended June 30, 2014			Six months ended June 30, 2015			Six months ended June 30, 2014
	Common units	Net Proceeds		Common units	Net Proceeds		Common units	Net Proceeds		Common units	Net Proceeds
September 2013 ATM (1)	—	$	—	—	$	—	—	$	—	4.2	$	272
March 2014 ATM (2)	—	—		7.0	440		—	—		7.0	440
November 2014 ATM (3)	0.6	40		—	—		0.6	40		—	—
Total	0.6	$	40	7.0	$	440	0.6	$	40	11.2	$	712

(1) On September 5, 2013, we and M&R MWE Liberty L.L.C. (the “Selling Unitholder”) entered into an Equity Distribution Agreement with the 2013 Manager that established the September 2013 ATM pursuant to which we could have sold from time to time through the 2013 Manager, as our sales agent, common units representing limited partner interests having an aggregate offering price of up to $1 billion. In addition, the Selling Unitholder could sell from time to time through the 2013 Manager up to 794,761 common units. During the six months ended June 30, 2014, we incurred approximately $4 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, 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.

(2) On March 11, 2014, we and the Selling Unitholder entered into an Equity Distribution Agreement with financial institutions (the “March 2014 Managers”) that established an At the Market offering program (the “March 2014 ATM”) pursuant to which the Partnership sold from time to time through the March 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, we incurred 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.

(3) On November 19, 2014, we and the Selling Unitholder entered into an Equity Distribution Agreement with financial institutions (the “November 2014 Managers”) that established an At the Market offering program (the “November 2014

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ATM”) pursuant to which we may sell from time to time through the November 2014 Managers, as our sales agents, common units having an aggregate offering price of up to $1.5 billion. In addition, the Selling Unitholder may sell from time to time through the November 2014 Managers up to 3,990,878 common units. During the six months ended June 30, 2015, we sold 0.6 million common units for net proceeds of approximately $40 million, and we incurred approximately $2.8 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general partnership purposes.

Cash Flow

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

	Six months ended June 30,
	2015			2014			Change
Net cash provided by operating activities	$	363,338		$	356,823		$	6,515
Net cash used in investing activities	(928,596		)	(1,005,158		)	76,562
Net cash provided by financing activities	501,533			862,442			(360,909		)

Net cash provided by operating activities increased primarily due to a decrease in working capital of approximately $51.3 million caused by timing, a decrease in accounts receivable compared to the same period in 2014 due to declining revenues, and an increase in accrued interest expense of $11.2 million due to the new notes issued in June 2015. Also contributing to the change was a $25.8 million change in realized gains (losses) and improvements in cash flows generated from operating income before items not allocated to segments. In addition, other long term liabilities decreased approximately $12.7 million primarily due to timing of deferred revenue.

Net cash used in investing activities decreased primarily due to a $442.3 million decrease in capital expenditures, which primarily relates to a slowdown in capital expenditures due to producer customer drilling slowdowns as well as Ohio Gathering being an unconsolidated affiliate in 2015 and consolidated for the first five months of 2014. This decrease was partially offset by a decrease of $324.7 million in proceeds related to the exercise of the Ohio Gathering Option by Summit in 2014. The increase was also offset by an increase in cash contributions to our equity method investments of approximately $31.8 million, which primarily relates to Ohio Gathering being an unconsolidated affiliate in 2015 and consolidated for the first five months of 2014. The increase was also offset by an $19.2 million decrease in proceeds from the sale of property, plant and equipment from the cash received in first quarter 2014 related to $17 million sale of assets to Utica Condensate.

Net cash provided by financing activities decreased primarily due to a $672.2 million decrease in proceeds from equity offerings and $24.6 million due to distributions to non-controlling interest holders, as well as higher distribution amounts paid of $61.0 million due to increased distributions per unit and common units issued throughout 2014 and 2015 and the conversion of Class B units in July 2014, partially offset by a $356.1 million increase in net borrowings, which includes approximately $103.2 million of premiums paid for the redemption of our debt in June 2015, and $26.7 million in contributions from non-controlling interest holders due to Summit’s buy in of Ohio Gathering on June 1, 2014.

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, 2015, our purchase obligations were $445.8 million compared to our obligations of $643.9 million as of December 31, 2014. Purchase obligations represent purchase orders and contracts related to property, plant and equipment.

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; accounting for significant embedded derivatives; VIEs; acquisitions and income taxes.

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There have not been any material changes during the six months ended June 30, 2015 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, 2014, except as noted below.

Description

Judgments and Uncertainties

Effect if Actual Results Differ from
Estimates and Assumptions

Impairment of Long-Lived Assets

Management evaluates our long-lived assets, including intangibles, for impairment when certain events have taken place that indicate that the carrying value may not be recoverable from the expected undiscounted future cash flows. Qualitative and quantitative information is reviewed in order to determine if a triggering event has occurred or an impairment indicator exists. If we determine that a triggering event has occurred we would complete a full impairment analysis. If we determine that the carrying value of an asset group is not recoverable, a loss is recorded for the difference between the fair value and the carrying value. We evaluate our property, plant and equipment and intangibles on at least a segment level and at lower levels where cash flows for specific assets can be identified.

Management considers the volume of reserves dedicated to be processed by the asset and future NGL product and natural gas prices to estimate cash flows for each asset group. The amount of additional reserves developed by future drilling activity depends, in part, on expected commodity prices. Projections of reserves, drilling activity, ability to renew contracts of significant customers, and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Management considered the recent reductions in commodity prices in forecasted cash flows.

As of March 31, 2015, there were quantitative indicators of impairment related to our Appleby asset group. A full impairment analysis was completed, which demonstrated the fair value did not exceed the carrying value of the asset group and an impairment charge of $22.8 million was recorded as of March 31, 2015.

As of June 30, 2015, there were no indicators of impairment for any of our other asset groups. A significant variance in any of the assumptions or factors used to estimate future cash flows could result in the impairment of an asset. For certain asset groups that comprise approximately 0.25% of total long-lived assets, a decrease in the estimated future cash flows used in our impairment analysis of 10% would indicate that the net book value of the asset groups may not be fully recoverable and further evaluation would be required to estimate a potential impairment.

Recent Accounting Pronouncements

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

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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 six months ended June 30, 2015 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, 2014.

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, 2015, including the weighted average prices (“WAVG”):

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2015	1,000	$	88.15	$	5,100
2016	300	63.56		159

Ethane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	21,000	$	0.19	$	(33	)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	91,603	$	0.58	$	1,552
2016 (Jan. — Mar.)	75,298	0.60		435

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	17,341	$	0.71	$	206
2016 (Jan. — Mar.)	14,008	0.72		17

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	39,256	$	0.70	$	472
2016 (Jan. — Mar.)	31,383	0.72		70

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	20,296	$	1.19	$	(186	)
2016 (Jan. — Mar.)	14,089	1.22		(37		)

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The following tables provide information on the volume of our taxable subsidiary’s commodity derivative activity for positions related to keep-whole price risk at June 30, 2015, including the WAVG:

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2015	7,126	$	2.63	$	134

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	46,495	$	0.55	$	599

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	5,337	$	0.66	$	20

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	14,987	$	0.61	$	(21	)

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	10,655	$	1.20	$	(77	)

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, 2015, including the WAVG:

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	91,521	$	0.58	$	1,683
2016 (Jan. — Mar.)	78,346	0.59		417

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	10,181	$	0.71	$	120
2016 (Jan. — Mar.)	7,608	0.71		1

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	23,122	$	0.66	$	144
2016 (Jan. — Mar.)	17,911	0.67		(15		)

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2015	61,321	$	1.20	$	(399	)
2016	16,796	1.22		(189		)

The following table provides information on the derivative positions related to long liquids price risk that we have entered into subsequent to June 30, 2015, including the WAVG:

Ethane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2015	13,970	$	0.19
2016	16,800	$	0.21

Embedded Derivatives in Commodity Contracts

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

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with the producer’s option to extend the agreement for successive five-year terms through December 31, 2032. As of June 30, 2015, the estimated fair value of this contract was a liability of $39.1 million and the recorded value was an asset of $11.8 million. The recorded asset does not include the inception fair value of the commodity contract related to the extended period from July 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, 2015 (in thousands):

Fair value of commodity contract	$	(39,101	)
Inception value for period from July 1, 2015 to December 31, 2022	(50,928		)
Derivative liability as of June 30, 2015	$	11,827

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 $197.5 million and 2.4% for $250.0 million at June 30, 2015. As of July 29, 2015, we had $510.4 million of 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, 2015. Our debt portfolio as of June 30, 2015 is shown in the following table.

Long-Term Debt	Interest Rate	Lending Limit		Due Date	Outstanding at June 30, 2015
Credit Facility	Variable	$	1.3 billion	March 2019	$	447.5 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
2024 Senior Notes	Fixed	$	1.15 billion	December 2024	$	1.15 billion
2025 Senior Notes	Fixed	$	1.2 billion	June 2025	$	1.2 billion

Based on our overall interest rate exposure at June 30, 2015, a hypothetical increase or decrease of one percentage point in interest rates would change pre-tax earnings by approximately $4.5 million over a twelve-month period. Based on our overall interest rate exposure at July 29, 2015, 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 $5.1 million over a twelve-month period.

Credit Risk

The information about our credit risk for the six months ended June 30, 2015 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, 2014.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

An evaluation was performed under the supervision and with the participation of the Partnership’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the Securities and Exchange Act of 1934, as amended (the “1934 Act”), as of June 30, 2015. Based on this evaluation, the Partnership’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of June 30, 2015, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

Limitations on Controls

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

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended June 30, 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Environmental Litigation

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, damage in 2013 to a portion of the Marcellus NGL pipeline in Wetzel County, West Virginia which resulted from landslides (“Wetzel County Landslides”) and associated issues, pipeline borings and other disparate matters. The Draft Consent Order aggregated those matters and proposed 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. MarkWest Liberty Midstream 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 has and will continue to assert those defenses and issues in discussions with WVDEP.

On May 27, 2015, MarkWest Liberty Midstream received a revised Draft Consent Order consolidating certain of the claimed violations from the initial Draft Consent Order with certain additional claimed violations from inspections that occurred since the date of the initial Draft Consent Order through April 2015. The revised Draft Consent Order proposed a total aggregate administrative penalty of $100,510 as well as the development of an approved remediation plan and certain other ongoing compliance obligations. MarkWest Liberty Midstream continues to dispute the claimed violations, administrative penalty and additional compliance obligations in ongoing discussions with WVDEP.

On July 6, 2015, officials from the United States Environmental Protection Agency and the Department of Justice conducted an inspection at a MarkWest Liberty Midstream pipeline tool launcher/receiver site in Washington County, Pennsylvania pursuant to a search warrant issued by the United States District Court for the Western District of Pennsylvania. At the conclusion of the inspection, the EPA also presented MarkWest Liberty Midstream with a subpoena to provide documents related to the design, construction, operation, maintenance, modification, inspection, assessment, repair of, and/or emissions from MarkWest Liberty Midstream’s pipeline facilities located in Pennsylvania. MarkWest Liberty Midstream is providing information in response to the subpoena and is in discussions with the relevant agencies regarding any issues associated with the inspection and subpoena or its operations of or supplementary permitting obligations for its pipeline facilities. While it is possible that MarkWest Liberty Midstream will incur expenses and potential assessments or fines in connection with the inspection and subpoena, the amount of potential expenses or assessments cannot be reasonably estimated at this time.

Litigation Related to the Merger

As more fully described in Note 17 of the Notes to the Condensed Consolidated Financial Statements, on July 11, 2015, the Partnership entered into the Merger Agreement with MPLX, MPLX GP, Merger Sub, and, for certain limited purposes set forth in the Merger Agreement, MPC. Pursuant to the Merger Agreement, Merger Sub will be merged with and into the Partnership (the “Merger”), with the Partnership surviving the Merger as a wholly owned subsidiary of MPLX. After the Merger, the Partnership’s common units will cease to be publicly traded.

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indefinitely enjoin completion of the Merger. An adverse judgment for rescission or for monetary damages could have a material adverse effect on the Partnership and MPLX following the Merger.

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, 2014, 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. Prior to the date of this report, additional risk factors related to the Merger with MPLX and tax risks related to owning our common units arose in addition to those previously set forth in our Annual report on Form 10-K for the year ended December 31, 2014. The additional risk factors are presented below.

Risks Related to the Merger

There can be no assurance that the Merger will be completed in the anticipated time frame, or at all, or that the anticipated benefits of the Merger will be realized.

The completion of the Merger is subject to the satisfaction of customary closing conditions, including Partnership unitholder approval, SEC approval of the registration statement that MPLX must file in connection with the Merger, and the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Failure to satisfy any of these conditions, if not waived, would prevent us from consummating the Merger. As a result, we can provide no assurance that the Merger will be completed within the anticipated time frame, or at all.

In addition, even if we are able to complete the Merger, we may be unable to realize the anticipated benefits of the disposition. For example, a portion of the consideration for the Merger is in the form of MPLX Common Units, the holding of which exposes us to the risks disclosed by MPLX as “risk factors” in their Annual Reports on Form 10-K and subsequent Quarterly Reports on Form 10-Q. Any delay in our ability to consummate the Merger could make it more difficult to realize the benefits of the Merger.

The failure to complete the Merger could adversely affect the price of our Common Units and otherwise have an adverse effect on us.

There can be no assurance that the conditions to the completion of the Merger, many of which are out of our control, will be satisfied. Among other things, we cannot be certain that (i) holders of a majority of our Common Units will vote in favor of the Merger or (ii) the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 will occur within the required timeframe. Further, there are restrictions on the conduct of our business prior to the consummation of the Merger, requiring us to conduct our business in all material respects only in the ordinary course, subject to specific limitations.

Further, a failed transaction may result in negative publicity or a negative impression of us in the investment community and may affect our relationship with employees, vendors, creditors and other business partners. Accordingly, if the Merger is not completed, the price of our Common Units may be adversely affected.

In the event of a failed transaction, the Partnership will still have to pay certain costs associated with the Merger, which will be significant and will primarily consist of advisors’ fees, accounting fees, financial printing and other related costs. These costs could adversely affect our operations and cash flows available for distributions to our unitholders, while not being offset by consideration for the Merger.

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The market price of MPLX Common Units after the Merger will continue to fluctuate and may be affected by factors different from those affecting our Common Units currently.

Upon completion of the Merger, holders of our Common Units will become holders of MPLX Common Units. The market price of MPLX Common Units may fluctuate significantly following consummation of the Merger and current holders of our Common Units could lose some or all of the value of their investment in MPLX Common Units. In addition, the stock market has experienced significant price and volume fluctuations in recent times, which could have a material adverse effect on the market for, or liquidity of, the MPLX Common Units, regardless of MPLX’s actual operating performance. In addition, MPLX’s business differs in important respects from ours, and accordingly, the results of operations of the combined company and the market price of MPLX Common Units after the completion of the Merger may be affected by factors different from those currently affecting the independent results of our operations and MPLX’s operations.

The General Partner and the members of its board are included as defendants in litigation related to the Merger.

On July 24, 2015, a putative unitholder class action complaint was filed by a single plaintiff who purports to be a unitholder of the Partnership in the Court of Chancery for the State of Delaware (Case No. 11332-VCG) against the Board, the General Partner, MPLX, MPC and Merger Sub. The plaintiff alleges a variety of causes of action challenging the Merger. It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiff, members of the putative unitholder class he purports to represent or by others in an effort to enjoin the Merger or seek monetary relief. We cannot predict the outcome of any such lawsuit, nor can we predict the amount of time and expense that will be required to resolve such lawsuits. An unfavorable resolution of any such litigation surrounding the Merger could delay or prevent its consummation. In addition, the costs of defending the litigation, even if resolved in our favor, could be substantial and such litigation could distract MPLX and us from pursuing the consummation of the Merger and other potentially beneficial business opportunities. For additional information regarding this litigation, see Part II, Item 1.—Legal Proceedings.

The Merger Agreement contains provisions that limit our ability to pursue alternatives to the Merger, could discourage a potential competing acquiror of the Partnership from making a favorable alternative transaction proposal and, in specified circumstances, could require us to pay a termination fee to the other party.

The Merger Agreement contains a “no shop” provision that, in general, restricts the Partnership’s ability to solicit third-party acquisition proposals or provide information to or engage in discussions or negotiations with third parties that have made or that might make an acquisition proposal. The no shop provision is subject to certain limited exceptions that allow the Partnership, under certain circumstances and in compliance with certain obligations, to provide information and participate in discussions and negotiations with respect to unsolicited third-party acquisition proposals that would reasonably be expected to lead to a Superior Proposal (as defined in the Merger Agreement).

These provisions could discourage a potential third-party acquiror that might have an interest in acquiring all or a significant portion of the Partnership from considering or proposing that acquisition, even if it were prepared to pay consideration with a higher per unit cash or market value than the market value proposed to be received or realized in the Merger or might result in a potential third-party acquiror proposing to pay a lower price to the stockholders than it might otherwise have proposed to pay because of the added expense of the termination fee, described below, that may become payable in certain circumstances.

If the Merger Agreement is terminated and we determine to seek another business combination, we may not be able to negotiate a transaction with another party on terms comparable to, or better than, the terms of the Merger. In addition, pursuant to the Merger Agreement, under specified circumstances, including, but not limited to, a change in the recommendation of the General Partner of the Partnership, the Partnership may be required to pay MPLX a termination fee, which would adversely affect our operations and cash flows available for distributions to our unitholders.

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Tax Risks Related to Owning our Common Units

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Fiscal Year 2016 Budget proposed by the President recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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Item 6. Exhibits

2.1		Agreement and Plan of Merger, dated as of July 11, 2015, among MarkWest Energy Partners, L.P., MPLX LP, MPLX GP LLC, Marathon Petroleum Corporation and Sapphire Holdco LLC (incorporated by reference to the Current Report on 8-K filed July 13, 2015).

3.1		Certificate of Limited Partnership of MarkWest Energy Partners, L.P. (incorporated by reference to the Registration Statement (No. 333-81780) 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. 333-81780) 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).

4.1*		Fourteenth Supplemental Indenture, dated as of June 3, 2015, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.

4.2		Fifteenth Supplemental Indenture, dated as of June 2, 2015, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Current Report on Form 8-K filed June 2, 2015).

4.3		Form of 4.875% Senior Notes due 2025 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.2 hereto, which is incorporated by reference to the Current Report on Form 8-K filed June 2, 2015).

10.1		Eighth Amendment to Amended and Restated Credit Agreement dated as of May 28, 2015, among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto (incorporated by reference to the Current Report on Form 8-K filed May 28, 2015).

12.1*		Computation of Ratio of Earnings to Fixed Charges.

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*		Certification of the Chief Executive Officer and 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.

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99.1		Voting Agreement dated as of July 11, 2015, among MPLX LP, MPLX GP LLC, Sapphire Holdco LLC and M&R MWE Liberty, LLC (incorporated by reference to the Current Report on Form 8-K filed on July 13, 2015).

101.INS*		XBRL Taxonomy Extension Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

* 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 5, 2015		/s/ FRANK M. SEMPLE
		Frank M. Semple
		Chairman, President & Chief Executive Officer
		(Principal Executive Officer)


Date: August 5, 2015		/s/ NANCY K. BUESE
		Nancy K. Buese
		Executive Vice President & Chief Financial Officer
		(Principal Financial Officer)


Date: August 5, 2015		/s/ PAULA L. ROSSON
		Paula L. Rosson
		Senior Vice President & Chief Accounting Officer
		(Principal Accounting Officer)

MARKWEST ENERGY PARTNERS L P - FORM 10-Q - August 5, 2015

Attached files

MARKWEST ENERGY PARTNERS L P Reports