Markwest Energy Partners L P 10-Q 5 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 29, 2015
Entity Registrant Name	MARKWEST ENERGY PARTNERS L P
Entity Central Index Key	1,166,036
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Common Units
Entity Common Stock, Shares Outstanding		191,379,512
Class B Units
Entity Common Stock, Shares Outstanding		7,981,756

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
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
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:
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
Common Units
Equity:
Common units or Class B units	4,355,128	4,758,243
Total equity	4,355,128	4,758,243
Class B Units
Equity:
Common units or Class B units	451,519	451,519
Total equity	$ 451,519	$ 451,519

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Cash and cash equivalents	$ 45,162	$ 108,887
Receivables, net	273,634	302,259
Receivables from unconsolidated affiliates, net	5,348	7,097
Inventories	31,358	31,749
Other current assets	26,622	46,731
Property, plant and equipment	10,626,393	9,923,524
Less: accumulated depreciation	(1,490,582)	(1,270,624)
Investment in unconsolidated affiliates	888,820	805,633
Accumulated amortization, intangibles	371,310	350,327
Accumulated amortization, deferred financing costs	26,245	31,298
Accumulated amortization, deferred contract cost	3,250	3,198
Other long-term assets	3,410	3,426
Accounts payable	193,329	270,997
Accrued liabilities	277,147	360,006
Payables to unconsolidated affiliates	12,009	8,621
Long-term debt, discounts	$ 6,837	$ 6,196
Common Units
Common units issued (in units)	187,389	186,553
Common units outstanding (in units)	187,389	186,553
Class B Units
Common units issued (in units)	11,973	11,973
Common units outstanding (in units)	11,973	11,973
Total Variable Interest Entities
Cash and cash equivalents	$ 12,807	$ 73,300
Receivables, net	43,442	22,722
Receivables from unconsolidated affiliates, net	0	30
Inventories	3,211	2,434
Other current assets	3,704	9,511
Property, plant and equipment	1,489,149	1,411,797
Less: accumulated depreciation	(87,328)	(56,987)
Investment in unconsolidated affiliates	765,482	696,784
Other long-term assets	664	664
Accounts payable	17,383	28,021
Accrued liabilities	18,002	48,793
Payables to unconsolidated affiliates	$ 9,349	$ 5,500

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 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 (in dollars per unit)	$ (0.55)	$ 0.05	$ (0.60)	$ 0.13
Diluted (in dollars per unit)	$ (0.55)	$ 0.05	$ (0.60)	$ 0.12
Weighted average number of outstanding common units:
Basic (in units)	186,855	164,613	186,771	161,727
Diluted (in units)	186,855	181,237	186,771	178,378
Cash distribution declared per common unit (in dollars per unit)	$ 0.91	$ 0.87	$ 1.81	$ 1.73

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Changes in Equity - USD ($) shares in Thousands, $ in Thousands	Common Units	Class B Units	Non-controlling Interest	Total
Balance, Equity at Dec. 31, 2013	$ 3,476,295	$ 602,025	$ 719,813	$ 4,798,133
Balance, Equity (in units) at Dec. 31, 2013	157,766	15,964
Increase (Decrease) in Equity
Issuance of units in public offering, net of offering costs	$ 711,837			711,837
Issuance of units in public offering, net of offering costs (in units)	11,284
Distributions paid	$ (278,316)		(90)	(278,406)
Redeemable non-controlling interest classified as temporary equity			164,906	164,906
Elimination of non-controlling interest from deconsolidation of a subsidiary			(6,592)	(6,592)
Share-based compensation activity	$ 1,012			1,012
Share-based compensation activity (in units)	211
Deferred income tax impact from changes in equity	$ (18,304)			(18,304)
Net (loss) income	21,469		7,495	28,964
Balance, Equity at Jun. 30, 2014	$ 3,913,993	$ 602,025	885,532	5,401,550
Balance, Equity (in units) at Jun. 30, 2014	169,261	15,964
Balance, Temporary Equity at Dec. 31, 2013				235,617
Redeemable Non-controlling Interest (Temporary Equity)
Redeemable non-controlling interest classified as temporary equity				(164,906)
Balance, Temporary Equity at Jun. 30, 2014				70,711
Balance, Equity at Dec. 31, 2014	$ 4,758,243	$ 451,519	983,477	6,193,239
Balance, Equity (in units) at Dec. 31, 2014	186,553	11,973
Increase (Decrease) in Equity
Issuance of units in public offering, net of offering costs	$ 39,630			39,630
Issuance of units in public offering, net of offering costs (in units)	636
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	$ 4,270			4,270
Share-based compensation activity (in units)	200
Deferred income tax impact from changes in equity	$ (1,510)			(1,510)
Net (loss) income	(110,569)		29,698	(80,871)
Balance, Equity at Jun. 30, 2015	$ 4,355,128	$ 451,519	$ 1,022,154	$ 5,828,801
Balance, Equity (in units) at Jun. 30, 2015	187,389	11,973

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 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

Organization and Basis of Prese

Organization and Basis of Presentation	6 Months Ended
	Jun. 30, 2015
Organization and Basis of Presentation
Organization and Basis of Presentation	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.

Recent Accounting Pronouncement

Recent Accounting Pronouncements	6 Months Ended
	Jun. 30, 2015
Recent Accounting Pronouncements
Recent Accounting Pronouncements	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.

Variable Interest Entities

Variable Interest Entities	6 Months Ended
	Jun. 30, 2015
Variable Interest Entities
Variable Interest Entities	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. 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.

Other Equity Interests

Other Equity Interests	6 Months Ended
	Jun. 30, 2015
Other Equity Interests
Other Equity Interests	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.

Derivative Financial Instrument

Derivative Financial Instruments	6 Months Ended
	Jun. 30, 2015
Derivative Financial Instruments
Derivative Financial Instruments	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 Natural Gas (MMBtu) Long NGLs (Gal) Short 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 $ ) Inception value for period from July 1, 2015 to December 31, 2022 ) Derivative asset as of June 30, 2015 $ 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 $ $ $ ) $ — Fair value of derivative contracts — long-term ) — Total $ $ $ ) $ — (1) Includes Embedded Derivatives in Commodity Contracts as discussed above. Although certain derivative positions are subject to master netting agreements, the Partnership has elected not to offset any derivative assets and liabilities. The gross amounts in the table below equal the balances presented in the Condensed Consolidated Balance Sheets. The table below summarizes the impact if the Partnership had elected to net its derivative positions that are subject to master netting arrangements (in thousands): Assets Liabilities As of June 30, 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 $ $ ) $ $ ) $ $ ) Embedded derivatives in commodity contracts — ) — ) Total current derivative instruments ) ) ) Non-current Commodity contracts — ) — ) Embedded derivatives in commodity contracts — — — — Total non-current derivative instruments — ) — ) Total derivative instruments $ $ ) $ $ ) $ $ ) 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 $ $ — $ $ — $ — $ — Embedded derivatives in commodity contracts — — — — Total current derivative instruments — — — — Non-current Embedded derivatives in commodity contracts — — — — Total non-current derivative instruments — — — — Total derivative instruments $ $ — $ $ — $ — $ — 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. 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) $ $ ) $ $ ) Unrealized loss ) ) ) ) Total revenue: derivative gain (loss) ) ) Derivative loss related to purchased product costs Realized gain (loss) ) ) Unrealized loss ) ) ) ) Total derivative loss related to purchased product costs ) ) ) ) Derivative loss related to facility expenses Unrealized (loss) ) ) ) ) Total (loss) gain $ ) $ ) $ $ )

Fair Value

Fair Value	6 Months Ended
	Jun. 30, 2015
Fair Value
Fair Value	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 $ $ ) Significant unobservable inputs (Level 3) Commodity contracts ) Embedded derivatives in commodity contracts ) Total carrying value in Condensed Consolidated Balance Sheets $ $ ) As of December 31, 2014 Assets Liabilities Significant other observable inputs (Level 2) Commodity contracts $ $ — Significant unobservable inputs (Level 3) Commodity contracts — Embedded derivatives in commodity contracts — Total carrying value in Condensed Consolidated Balance Sheets $ $ — 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. (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. 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 $ $ Total gain (loss) (realized and unrealized) included in earnings (1) ) Settlements ) Fair value at end of period $ $ 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) $ $ ) Three months ended June 30, 2014 Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Fair value at beginning of period $ ) $ ) Total loss (realized and unrealized) included in earnings (1) ) ) Settlements Fair value at end of period $ ) $ ) 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) $ ) $ ) Six months ended June 30, 2015 Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Fair value at beginning of period $ $ Total gain (loss) (realized and unrealized) included in earnings (1) ) Settlements ) Fair value at end of period $ $ 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) $ $ ) Six months ended June 30, 2014 Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Fair value at beginning of period $ ) $ ) Total loss (realized and unrealized) included in earnings (1) ) ) Settlements Fair value at end of period $ ) $ ) 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) 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 .

Inventories

Inventories	6 Months Ended
	Jun. 30, 2015
Inventories
Inventories	7. Inventories Inventories consist of the following (in thousands): June 30, 2015 December 31, 2014 NGLs $ $ Line fill Spare parts, materials and supplies Total inventories $ $

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets and Goodwill	6 Months Ended
	Jun. 30, 2015
Impairment of Long-Lived Assets and Goodwill
Impairment of Long-Lived Assets and Goodwill	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.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2015
Long-Term Debt
Long-Term Debt	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) $ $ Senior Notes (2) 2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020 — 2021 Senior Notes, 6.5% interest, net of discount of $— and $413, respectively, issued February and March 2011 and due August 2021 — 2022 Senior Notes, 6.25% interest, issued October 2011 and due September 2022 — 2023A Senior Notes, 5.5% interest, net of discount of $5,447 and $5,783, respectively, issued August 2012 and due February 2023 2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023 2024 Senior Notes, 4.875% interest, including premium of $10,204, issued November 2014 and March 2015 and due December 2024 2025 Senior Notes, 4.875% interest, including discount of $11,594, issued June 2015 and due June 2025 — Total long-term debt (3) $ $ (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 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.

Equity

Equity	6 Months Ended
	Jun. 30, 2015
Equity
Equity	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) — $ — — $ — — $ — $ March 2014 ATM (2) — — — — November 2014 ATM (3) — — — — Total $ $ $ $ (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. D uring 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 $ $ $ July 20, 2015 August 6, 2015 August 14, 2015 March 31, 2015 $ $ $ April 22, 2015 May 7, 2015 May 15, 2015 December 31, 2014 $ $ $ January 21, 2015 February 5, 2015 February 13, 2015

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies
Commitments and Contingencies	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 t h e 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 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.

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2015
Income Taxes
Income Taxes	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 $ ) $ ) $ ) $ ) Federal statutory rate % % % Federal income tax at statutory rate ) — — ) Permanent items — — Change in state statutory rate — ) — ) State income taxes net of federal benefit ) ) — ) Provision on income from Class A units (1) ) — — ) Provision for income tax $ ) $ ) $ — $ ) Six months ended June 30, 2014 Corporation Partnership Eliminations Consolidated Income before provision for income tax $ $ $ ) $ Federal statutory rate % % % Federal income tax at statutory rate — — Permanent items — — State income taxes net of federal benefit — Federal and state tax rate change — — Provision on income from Class A units (1) — — Provision for income tax $ $ $ — $ (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.

Earnings Per Common Unit

Earnings Per Common Unit	6 Months Ended
	Jun. 30, 2015
Earnings Per Common Unit
Earnings Per Common Unit	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 $ ) $ $ ) $ Less: Income allocable to phantom units (Loss) income available for common unitholders - basic ) ) Add: Income allocable to phantom units and DER expense (1) — — (Loss) income available for common unitholders - diluted $ ) $ $ ) $ Weighted average common units outstanding - basic Potential common shares (Class B and phantom units) (1) — — Weighted average common units outstanding - diluted Net (loss) income attributable to the Partnership’s common unitholders per common unit (2) Basic $ ) $ $ ) $ Diluted $ ) $ $ ) $ (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.

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2015
Segment Information
Segment Information	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. 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 $ $ $ $ $ — $ Segment purchased product costs — Net operating margin — Segment facility expenses — Segment portion of operating income attributable to non-controlling interests — — — Operating income before items not allocated to segments $ $ $ $ $ — $ Three months ended June 30, 2014: Marcellus Utica Northeast Southwest Elimination (1) Total Segment revenue $ $ $ $ ) $ Segment purchased product costs — Net operating margin ) Segment facility expenses ) Segment portion of operating income (loss) attributable to non-controlling interests — — — Operating income (loss) before items not allocated to segments $ $ $ $ — $ (1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus segment. 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 $ $ Derivative gain (loss) not allocated to segments ) Revenue adjustment for unconsolidated affiliates (1) ) ) Revenue deferral adjustment and other (2) (3) Total revenue $ $ Operating income before items not allocated to segments $ $ Portion of operating income attributable to non-controlling interests Derivative loss not allocated to segments ) ) Revenue adjustment for unconsolidated affiliates (1) ) ) Revenue deferral adjustment (2) Compensation expense included in facility expenses not allocated to segments ) ) Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliates (4) Portion of operating income attributable to non-controlling interests of unconsolidated affiliates (5) Facility expense adjustments (6) Selling, general and administrative expenses ) ) Depreciation ) ) Amortization of intangible assets ) ) Loss on disposal of property, plant and equipment ) ) Accretion of asset retirement obligations ) ) Income from operations Earnings (loss) from unconsolidated affiliates ) Interest expense ) ) Amortization of deferred financing costs and debt discount (a component of interest expense) ) ) Loss on redemption of debt ) — Miscellaneous income, net (Loss) income before provision for income tax $ ) $ (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. (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 $ $ $ $ $ ) $ Segment purchased product costs — Net operating margin ) Segment facility expenses ) Segment portion of operating income attributable to non-controlling interests — — — Operating income before items not allocated to segments $ $ $ $ $ — $ Capital expenditures $ $ $ $ $ $ Capital expenditures for Partnership operated, non-wholly owned subsidiaries (1) ) Capital expenditures not allocated to segments Total capital expenditures $ Six months ended June 30, 2014: Marcellus Utica(1) Northeast Southwest Elimination (2) Total Segment revenue $ $ $ $ ) $ Segment purchased product costs — Net operating margin ) Segment facility expenses ) Segment portion of operating income attributable to non-controlling interests — — — Operating income before items not allocated to segments $ $ $ $ — $ Capital expenditures $ $ $ $ — $ Capital expenditures for Ohio Gathering after deconsolidation (1) ) Capital expenditures not allocated to segments Total capital expenditures $ (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. 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 $ $ Derivative gain (loss) not allocated to segments ) Revenue adjustment for unconsolidated affiliates (1) ) ) Revenue deferral adjustment and other (2) (3) ) Total revenue $ $ Operating income before items not allocated to segments $ $ Portion of operating income attributable to non-controlling interests Derivative gain (loss) not allocated to segments ) Revenue adjustment for unconsolidated affiliates (1) ) ) Revenue deferral adjustment (2) ) Compensation expense included in facility expenses not allocated to segments ) ) Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliates (4) Portion of operating income attributable to non-controlling interests of unconsolidated affiliates (5) Facility expense adjustments (6) Selling, general and administrative expenses ) ) Depreciation ) ) Amortization of intangible assets ) ) Impairment expense ) — Loss on disposal of property, plant and equipment ) ) Accretion of asset retirement obligations ) ) Income from operations Earnings (loss) from unconsolidated affiliates ) Interest expense ) ) Amortization of deferred financing costs and debt discount (a component of interest expense) ) ) Loss on redemption of debt ) — Miscellaneous income, net (Loss) income before provision for income tax $ ) $ (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. (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. (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 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 $ $ Utica (1) Northeast Southwest (1) Total segment assets Assets not allocated to segments: Certain cash and cash equivalents — Fair value of derivatives Investment in unconsolidated affiliates Other (2) Total assets $ $ (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.

Supplemental Condensed Consolid

Supplemental Condensed Consolidating Financial Information	6 Months Ended
	Jun. 30, 2015
Supplemental Condensed Consolidating Financial Information
Supplemental Condensed Consolidating Financial Information	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): 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 $ — $ $ $ — $ Restricted cash — — — Receivables and other current assets — Receivables from unconsolidated affiliates, net — — Intercompany receivables ) — Fair value of derivative instruments — — Total current assets ) Total property, plant and equipment, net ) Other long-term assets: Investment in unconsolidated affiliates — ) Investment in consolidated affiliates — ) — Intangibles, net of accumulated amortization — — Fair value of derivative instruments — — — Intercompany notes receivable — — ) — Other long-term assets — Total assets $ $ $ $ ) $ LIABILITIES AND EQUITY Current liabilities: Intercompany payables $ $ $ $ ) $ — Fair value of derivative instruments — — Payables to unconsolidated affiliates — Other current liabilities ) Total current liabilities ) Deferred income taxes — — Fair value of derivative instruments — — — Long-term intercompany financing payable — ) — Long-term debt, net of discounts — — — Other long-term liabilities — Equity: Common Units ) Class B Units — — — Non-controlling interest in consolidated subsidiaries — — — Total equity ) Total liabilities and equity $ $ $ $ ) $ As of December 31, 2014 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ — $ $ — $ Restricted cash — — — Receivables and other current assets — Receivables from unconsolidated affiliates, net — Intercompany receivables ) — Fair value of derivative instruments — — Total current assets ) Total property, plant and equipment, net ) Other long-term assets: Investment in unconsolidated affiliates — ) Investment in consolidated affiliates — ) — Intangibles, net of accumulated amortization — — Fair value of derivative instruments — — — Intercompany notes receivable — — ) — Other long-term assets — Total assets $ $ $ $ ) $ LIABILITIES AND EQUITY Current liabilities: Intercompany payables $ $ $ $ ) $ — Payables to unconsolidated affiliates — — — Other current liabilities ) Total current liabilities ) Deferred income taxes — — Long-term intercompany financing payable — ) — Long-term debt, net of discounts — — — Other long-term liabilities — Equity: Common Units ) Class B Units — — — Non-controlling interest in consolidated subsidiaries — — — Total equity ) Total liabilities and equity $ $ $ $ ) $ Condensed Consolidating Statements of Operations Three months ended June 30, 2015 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Total revenue $ — $ $ $ ) $ Operating expenses: Purchased product costs — — Facility expenses — Selling, general and administrative expenses ) Depreciation and amortization ) Other operating expenses (income) — — Total operating expenses ) (Loss) income from operations ) ) Earnings from consolidated affiliates — ) — Loss on redemption of debt ) — — — ) Other expense, net ) ) ) ) (Loss) income before provision for income tax ) ) ) Provision for income tax expense (benefit) ) ) — — ) Net income ) ) ) Net income attributable to non-controlling interest — — — ) ) Net (loss) income attributable to the Partnership’s unitholders $ ) $ $ $ ) $ ) Three months ended June 30, 2014 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Total revenue $ — $ $ $ ) $ Operating expenses: Purchased product costs — — Facility expenses — ) Selling, general and administrative expenses ) Depreciation and amortization ) Other operating expenses (income) — ) Total operating expenses ) (Loss) income from operations ) Earnings from consolidated affiliates — ) — Other expense, net ) ) ) ) Income before provision for income tax ) ) Provision for income tax expense ) — — ) Net income ) ) Net income attributable to non-controlling interest — — — ) ) Net income attributable to the Partnership’s unitholders $ ) $ $ $ ) $ Six months ended June 30, 2015 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Total revenue $ — $ $ $ ) $ Operating expenses: Purchased product costs — — Facility expenses — Selling, general and administrative expenses ) Depreciation and amortization ) Other operating expenses (income) — — Impairment expense — — — Total operating expenses ) (Loss) income from operations ) ) ) Earnings from consolidated affiliates — ) — Loss on redemption of debt ) — — — ) Other expense, net ) ) ) ) (Loss) income before provision for income tax ) ) ) Provision for income tax expense (benefit) ) ) — — ) Net income ) ) ) Net income attributable to non-controlling interest — — — ) ) Net (loss) income attributable to the Partnership’s unitholders $ ) $ $ $ ) $ ) Six months ended June 30, 2014 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Total revenue $ — $ $ $ ) $ Operating expenses: Purchased product costs — — Facility expenses — ) Selling, general and administrative expenses ) Depreciation and amortization ) Other operating (income) expenses — ) Total operating expenses ) (Loss) income from operations ) ) Earnings from consolidated affiliates — ) — Other expense, net ) ) ) ) Income before provision for income tax ) Provision for income tax expense — — Net income ) Net income attributable to non-controlling interest — — — ) ) Net income attributable to the Partnership’s unitholders $ $ $ $ ) $ 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 $ ) $ $ $ Cash flows from investing activities: Restricted cash — — — Capital expenditures ) ) ) ) ) Equity investments in consolidated affiliates ) ) — — Intercompany advances, net ) — ) — Investment in unconsolidated affiliates — ) ) — ) Distributions from consolidated affiliates — ) — Investment in intercompany notes receivable, net ) — — — Proceeds from disposal of property, plant and equipment — — Net cash flows used in investing activities ) ) ) ) Cash flows from financing activities: Proceeds from public equity offerings, net — — — Proceeds from Credit Facility — — — Payments Credit Facility ) — — — ) Proceeds from long-term debt — — — Payments of long-term debt ) — — — ) Payments of premiums on redemption of long-term debt ) — — — ) Payments for debt issue costs and deferred financing costs ) — — — ) Payments related to intercompany financing, net — ) ) — Proceeds from sale of equity interest in consolidated subsidiary — — — Contributions from non-controlling interest — — — Contributions from parent and affiliates — ) — Payments of SMR liability — ) — — ) Share-based payment activity ) — — — ) Payment of distributions ) ) ) ) Intercompany advances, net — — ) — Net cash flows provided by financing activities ) Net increase (decrease) in cash — ) — ) Cash and cash equivalents at beginning of period — — — Cash and cash equivalents at end of period $ — $ $ $ — $ Six months ended June 30, 2014 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Net cash (used in) provided by operating activities $ ) $ $ $ $ Cash flows from investing activities: Capital expenditures ) ) ) ) ) Equity investments in consolidated affiliates ) ) — — Intercompany advances, net ) — — — Investment in unconsolidated affiliates — ) ) — ) Distributions from consolidated affiliates — ) — Investment in intercompany notes, net — — ) — Proceeds from disposal of property, plant and equipment — — Proceeds from sale of equity interest in unconsolidated affiliate — — — Net cash flows used in investing activities ) ) ) ) Cash flows from financing activities: Proceeds from public equity offerings, net — — — Proceeds from Credit Facility — — — Payments Credit Facility ) — — — ) Payments related to intercompany financing, net — ) ) — Payments for debt issuance costs, deferred financing costs and registration costs ) — — — ) Contributions from parent and affiliates — ) — Share-based payment activity ) — — — ) Payments of distributions ) ) ) ) Payments of SMR liability — ) — — ) Intercompany advances, net — — ) — Net cash flows provided by financing activities ) Net (decrease) increase in cash and cash equivalents ) ) — Cash and cash equivalents at beginning of period — Cash and cash equivalents at end of period $ $ $ $ — $

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	6 Months Ended
	Jun. 30, 2015
Supplemental Cash Flow Information
Supplemental Cash Flow Information	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 $ $ Cash received for income taxes, net Supplemental schedule of non-cash investing and financing activities: Amounts payable for property, plant and equipment (1) $ $ Interest capitalized on construction in progress Issuance of common units for vesting of share-based payment awards (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.

Subsequent Event

Subsequent Event	6 Months Ended
	Jun. 30, 2015
Subsequent Event.
Subsequent Event	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. 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.

Derivative Financial Instrume24

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative Financial Instruments
Schedule of notional amounts of derivative contracts	Derivative contracts not designated as hedging instruments Financial Position Notional Quantity (net) Crude Oil (Bbl) Short Natural Gas (MMBtu) Long NGLs (Gal) Short
Reconciliation of liability recorded for embedded derivative	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 $ ) Inception value for period from July 1, 2015 to December 31, 2022 ) Derivative asset as of June 30, 2015 $
Schedule of the impact of derivative instruments on the balance sheet and statement of operations	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 $ $ $ ) $ — Fair value of derivative contracts — long-term ) — Total $ $ $ ) $ — (1) Includes Embedded Derivatives in Commodity Contracts as discussed above. The impact of the Partnership’s derivative instruments on its Condensed Consolidated Statements of Operations is summarized below (in thousands): Derivative contracts not designated as hedging instruments and the location of 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) $ $ ) $ $ ) Unrealized loss ) ) ) ) Total revenue: derivative gain (loss) ) ) Derivative loss related to purchased product costs Realized gain (loss) ) ) Unrealized loss ) ) ) ) Total derivative loss related to purchased product costs ) ) ) ) Derivative loss related to facility expenses Unrealized (loss) ) ) ) ) Total (loss) gain $ ) $ ) $ $ )
Schedule of impact on the balance sheet if Partnership had elected to net derivative positions subject to master netting arrangements	The table below summarizes the impact if the Partnership had elected to net its derivative positions that are subject to master netting arrangements (in thousands): Assets Liabilities As of June 30, 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 $ $ ) $ $ ) $ $ ) Embedded derivatives in commodity contracts — ) — ) Total current derivative instruments ) ) ) Non-current Commodity contracts — ) — ) Embedded derivatives in commodity contracts — — — — Total non-current derivative instruments — ) — ) Total derivative instruments $ $ ) $ $ ) $ $ ) 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 $ $ — $ $ — $ — $ — Embedded derivatives in commodity contracts — — — — Total current derivative instruments — — — — Non-current Embedded derivatives in commodity contracts — — — — Total non-current derivative instruments — — — — Total derivative instruments $ $ — $ $ — $ — $ —

Fair Value (Tables)

Fair Value (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value
Schedule of derivative instruments carried at fair value	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 $ $ ) Significant unobservable inputs (Level 3) Commodity contracts ) Embedded derivatives in commodity contracts ) Total carrying value in Condensed Consolidated Balance Sheets $ $ ) As of December 31, 2014 Assets Liabilities Significant other observable inputs (Level 2) Commodity contracts $ $ — Significant unobservable inputs (Level 3) Commodity contracts — Embedded derivatives in commodity contracts — Total carrying value in Condensed Consolidated Balance Sheets $ $ —
Schedule of information about significant unobservable inputs used in the valuation of Level 3 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. (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.
Schedule of 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 $ $ Total gain (loss) (realized and unrealized) included in earnings (1) ) Settlements ) Fair value at end of period $ $ 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) $ $ ) Three months ended June 30, 2014 Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Fair value at beginning of period $ ) $ ) Total loss (realized and unrealized) included in earnings (1) ) ) Settlements Fair value at end of period $ ) $ ) 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) $ ) $ ) Six months ended June 30, 2015 Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Fair value at beginning of period $ $ Total gain (loss) (realized and unrealized) included in earnings (1) ) Settlements ) Fair value at end of period $ $ 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) $ $ ) Six months ended June 30, 2014 Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Fair value at beginning of period $ ) $ ) Total loss (realized and unrealized) included in earnings (1) ) ) Settlements Fair value at end of period $ ) $ ) 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) 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 .

Inventories (Tables)

Inventories (Tables)	6 Months Ended
	Jun. 30, 2015
Inventories
Schedule of components of inventories	Inventories consist of the following (in thousands): June 30, 2015 December 31, 2014 NGLs $ $ Line fill Spare parts, materials and supplies Total inventories $ $

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Long-Term Debt
Summary of debt	Debt is summarized below (in thousands): June 30, 2015 December 31, 2014 Credit Facility Credit Facility, variable interest, due March 2019 (1) $ $ Senior Notes (2) 2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020 — 2021 Senior Notes, 6.5% interest, net of discount of $— and $413, respectively, issued February and March 2011 and due August 2021 — 2022 Senior Notes, 6.25% interest, issued October 2011 and due September 2022 — 2023A Senior Notes, 5.5% interest, net of discount of $5,447 and $5,783, respectively, issued August 2012 and due February 2023 2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023 2024 Senior Notes, 4.875% interest, including premium of $10,204, issued November 2014 and March 2015 and due December 2024 2025 Senior Notes, 4.875% interest, including discount of $11,594, issued June 2015 and due June 2025 — Total long-term debt (3) $ $ (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.

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 30, 2015
Equity
Schedule of public 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) — $ — — $ — — $ — $ March 2014 ATM (2) — — — — November 2014 ATM (3) — — — — Total $ $ $ $ (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. D uring 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.
Schedule of 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 $ $ $ July 20, 2015 August 6, 2015 August 14, 2015 March 31, 2015 $ $ $ April 22, 2015 May 7, 2015 May 15, 2015 December 31, 2014 $ $ $ January 21, 2015 February 5, 2015 February 13, 2015

Income Tax (Tables)

Income Tax (Tables)	6 Months Ended
	Jun. 30, 2015
Income Taxes
Schedule of income tax rate reconciliation	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 $ ) $ ) $ ) $ ) Federal statutory rate % % % Federal income tax at statutory rate ) — — ) Permanent items — — Change in state statutory rate — ) — ) State income taxes net of federal benefit ) ) — ) Provision on income from Class A units (1) ) — — ) Provision for income tax $ ) $ ) $ — $ ) Six months ended June 30, 2014 Corporation Partnership Eliminations Consolidated Income before provision for income tax $ $ $ ) $ Federal statutory rate % % % Federal income tax at statutory rate — — Permanent items — — State income taxes net of federal benefit — Federal and state tax rate change — — Provision on income from Class A units (1) — — Provision for income tax $ $ $ — $ (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.

Earnings Per Common Unit (Table

Earnings Per Common Unit (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings Per Common Unit
Schedule of computation of basic and diluted net income 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 $ ) $ $ ) $ Less: Income allocable to phantom units (Loss) income available for common unitholders - basic ) ) Add: Income allocable to phantom units and DER expense (1) — — (Loss) income available for common unitholders - diluted $ ) $ $ ) $ Weighted average common units outstanding - basic Potential common shares (Class B and phantom units) (1) — — Weighted average common units outstanding - diluted Net (loss) income attributable to the Partnership’s common unitholders per common unit (2) Basic $ ) $ $ ) $ Diluted $ ) $ $ ) $ (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.

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Information
Schedule of operating income and capital expenditures of reportable segments	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 $ $ $ $ $ — $ Segment purchased product costs — Net operating margin — Segment facility expenses — Segment portion of operating income attributable to non-controlling interests — — — Operating income before items not allocated to segments $ $ $ $ $ — $ Three months ended June 30, 2014: Marcellus Utica Northeast Southwest Elimination (1) Total Segment revenue $ $ $ $ ) $ Segment purchased product costs — Net operating margin ) Segment facility expenses ) Segment portion of operating income (loss) attributable to non-controlling interests — — — Operating income (loss) before items not allocated to segments $ $ $ $ — $ (1) Amounts represent revenues and expenses associated with the Northeast segment fractionation completed on behalf of the Marcellus 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 $ $ $ $ $ ) $ Segment purchased product costs — Net operating margin ) Segment facility expenses ) Segment portion of operating income attributable to non-controlling interests — — — Operating income before items not allocated to segments $ $ $ $ $ — $ Capital expenditures $ $ $ $ $ $ Capital expenditures for Partnership operated, non-wholly owned subsidiaries (1) ) Capital expenditures not allocated to segments Total capital expenditures $ Six months ended June 30, 2014: Marcellus Utica(1) Northeast Southwest Elimination (2) Total Segment revenue $ $ $ $ ) $ Segment purchased product costs — Net operating margin ) Segment facility expenses ) Segment portion of operating income attributable to non-controlling interests — — — Operating income before items not allocated to segments $ $ $ $ — $ Capital expenditures $ $ $ $ — $ Capital expenditures for Ohio Gathering after deconsolidation (1) ) Capital expenditures not allocated to segments Total capital expenditures $ (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.
Reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax	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 $ $ Derivative gain (loss) not allocated to segments ) Revenue adjustment for unconsolidated affiliates (1) ) ) Revenue deferral adjustment and other (2) (3) Total revenue $ $ Operating income before items not allocated to segments $ $ Portion of operating income attributable to non-controlling interests Derivative loss not allocated to segments ) ) Revenue adjustment for unconsolidated affiliates (1) ) ) Revenue deferral adjustment (2) Compensation expense included in facility expenses not allocated to segments ) ) Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliates (4) Portion of operating income attributable to non-controlling interests of unconsolidated affiliates (5) Facility expense adjustments (6) Selling, general and administrative expenses ) ) Depreciation ) ) Amortization of intangible assets ) ) Loss on disposal of property, plant and equipment ) ) Accretion of asset retirement obligations ) ) Income from operations Earnings (loss) from unconsolidated affiliates ) Interest expense ) ) Amortization of deferred financing costs and debt discount (a component of interest expense) ) ) Loss on redemption of debt ) — Miscellaneous income, net (Loss) income before provision for income tax $ ) $ (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. (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 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 $ $ Derivative gain (loss) not allocated to segments ) Revenue adjustment for unconsolidated affiliates (1) ) ) Revenue deferral adjustment and other (2) (3) ) Total revenue $ $ Operating income before items not allocated to segments $ $ Portion of operating income attributable to non-controlling interests Derivative gain (loss) not allocated to segments ) Revenue adjustment for unconsolidated affiliates (1) ) ) Revenue deferral adjustment (2) ) Compensation expense included in facility expenses not allocated to segments ) ) Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliates (4) Portion of operating income attributable to non-controlling interests of unconsolidated affiliates (5) Facility expense adjustments (6) Selling, general and administrative expenses ) ) Depreciation ) ) Amortization of intangible assets ) ) Impairment expense ) — Loss on disposal of property, plant and equipment ) ) Accretion of asset retirement obligations ) ) Income from operations Earnings (loss) from unconsolidated affiliates ) Interest expense ) ) Amortization of deferred financing costs and debt discount (a component of interest expense) ) ) Loss on redemption of debt ) — Miscellaneous income, net (Loss) income before provision for income tax $ ) $ (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. (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. (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.
Schedule of assets by segment	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 $ $ Utica (1) Northeast Southwest (1) Total segment assets Assets not allocated to segments: Certain cash and cash equivalents — Fair value of derivatives Investment in unconsolidated affiliates Other (2) Total assets $ $ (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.

Supplemental Condensed Consol32

Supplemental Condensed Consolidating Financial Information (Tables)	6 Months Ended
	Jun. 30, 2015
Supplemental Condensed Consolidating Financial Information
Schedule of condensed consolidating balance sheets	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): 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 $ — $ $ $ — $ Restricted cash — — — Receivables and other current assets — Receivables from unconsolidated affiliates, net — — Intercompany receivables ) — Fair value of derivative instruments — — Total current assets ) Total property, plant and equipment, net ) Other long-term assets: Investment in unconsolidated affiliates — ) Investment in consolidated affiliates — ) — Intangibles, net of accumulated amortization — — Fair value of derivative instruments — — — Intercompany notes receivable — — ) — Other long-term assets — Total assets $ $ $ $ ) $ LIABILITIES AND EQUITY Current liabilities: Intercompany payables $ $ $ $ ) $ — Fair value of derivative instruments — — Payables to unconsolidated affiliates — Other current liabilities ) Total current liabilities ) Deferred income taxes — — Fair value of derivative instruments — — — Long-term intercompany financing payable — ) — Long-term debt, net of discounts — — — Other long-term liabilities — Equity: Common Units ) Class B Units — — — Non-controlling interest in consolidated subsidiaries — — — Total equity ) Total liabilities and equity $ $ $ $ ) $ As of December 31, 2014 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated ASSETS Current assets: Cash and cash equivalents $ — $ — $ $ — $ Restricted cash — — — Receivables and other current assets — Receivables from unconsolidated affiliates, net — Intercompany receivables ) — Fair value of derivative instruments — — Total current assets ) Total property, plant and equipment, net ) Other long-term assets: Investment in unconsolidated affiliates — ) Investment in consolidated affiliates — ) — Intangibles, net of accumulated amortization — — Fair value of derivative instruments — — — Intercompany notes receivable — — ) — Other long-term assets — Total assets $ $ $ $ ) $ LIABILITIES AND EQUITY Current liabilities: Intercompany payables $ $ $ $ ) $ — Payables to unconsolidated affiliates — — — Other current liabilities ) Total current liabilities ) Deferred income taxes — — Long-term intercompany financing payable — ) — Long-term debt, net of discounts — — — Other long-term liabilities — Equity: Common Units ) Class B Units — — — Non-controlling interest in consolidated subsidiaries — — — Total equity ) Total liabilities and equity $ $ $ $ ) $
Schedule of condensed consolidating statements of operations	Condensed Consolidating Statements of Operations Three months ended June 30, 2015 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Total revenue $ — $ $ $ ) $ Operating expenses: Purchased product costs — — Facility expenses — Selling, general and administrative expenses ) Depreciation and amortization ) Other operating expenses (income) — — Total operating expenses ) (Loss) income from operations ) ) Earnings from consolidated affiliates — ) — Loss on redemption of debt ) — — — ) Other expense, net ) ) ) ) (Loss) income before provision for income tax ) ) ) Provision for income tax expense (benefit) ) ) — — ) Net income ) ) ) Net income attributable to non-controlling interest — — — ) ) Net (loss) income attributable to the Partnership’s unitholders $ ) $ $ $ ) $ ) Three months ended June 30, 2014 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Total revenue $ — $ $ $ ) $ Operating expenses: Purchased product costs — — Facility expenses — ) Selling, general and administrative expenses ) Depreciation and amortization ) Other operating expenses (income) — ) Total operating expenses ) (Loss) income from operations ) Earnings from consolidated affiliates — ) — Other expense, net ) ) ) ) Income before provision for income tax ) ) Provision for income tax expense ) — — ) Net income ) ) Net income attributable to non-controlling interest — — — ) ) Net income attributable to the Partnership’s unitholders $ ) $ $ $ ) $ Six months ended June 30, 2015 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Total revenue $ — $ $ $ ) $ Operating expenses: Purchased product costs — — Facility expenses — Selling, general and administrative expenses ) Depreciation and amortization ) Other operating expenses (income) — — Impairment expense — — — Total operating expenses ) (Loss) income from operations ) ) ) Earnings from consolidated affiliates — ) — Loss on redemption of debt ) — — — ) Other expense, net ) ) ) ) (Loss) income before provision for income tax ) ) ) Provision for income tax expense (benefit) ) ) — — ) Net income ) ) ) Net income attributable to non-controlling interest — — — ) ) Net (loss) income attributable to the Partnership’s unitholders $ ) $ $ $ ) $ ) Six months ended June 30, 2014 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Total revenue $ — $ $ $ ) $ Operating expenses: Purchased product costs — — Facility expenses — ) Selling, general and administrative expenses ) Depreciation and amortization ) Other operating (income) expenses — ) Total operating expenses ) (Loss) income from operations ) ) Earnings from consolidated affiliates — ) — Other expense, net ) ) ) ) Income before provision for income tax ) Provision for income tax expense — — Net income ) Net income attributable to non-controlling interest — — — ) ) Net income attributable to the Partnership’s unitholders $ $ $ $ ) $
Schedule of condensed consolidating statements of cash flows	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 $ ) $ $ $ Cash flows from investing activities: Restricted cash — — — Capital expenditures ) ) ) ) ) Equity investments in consolidated affiliates ) ) — — Intercompany advances, net ) — ) — Investment in unconsolidated affiliates — ) ) — ) Distributions from consolidated affiliates — ) — Investment in intercompany notes receivable, net ) — — — Proceeds from disposal of property, plant and equipment — — Net cash flows used in investing activities ) ) ) ) Cash flows from financing activities: Proceeds from public equity offerings, net — — — Proceeds from Credit Facility — — — Payments Credit Facility ) — — — ) Proceeds from long-term debt — — — Payments of long-term debt ) — — — ) Payments of premiums on redemption of long-term debt ) — — — ) Payments for debt issue costs and deferred financing costs ) — — — ) Payments related to intercompany financing, net — ) ) — Proceeds from sale of equity interest in consolidated subsidiary — — — Contributions from non-controlling interest — — — Contributions from parent and affiliates — ) — Payments of SMR liability — ) — — ) Share-based payment activity ) — — — ) Payment of distributions ) ) ) ) Intercompany advances, net — — ) — Net cash flows provided by financing activities ) Net increase (decrease) in cash — ) — ) Cash and cash equivalents at beginning of period — — — Cash and cash equivalents at end of period $ — $ $ $ — $ Six months ended June 30, 2014 Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Consolidating Adjustments Consolidated Net cash (used in) provided by operating activities $ ) $ $ $ $ Cash flows from investing activities: Capital expenditures ) ) ) ) ) Equity investments in consolidated affiliates ) ) — — Intercompany advances, net ) — — — Investment in unconsolidated affiliates — ) ) — ) Distributions from consolidated affiliates — ) — Investment in intercompany notes, net — — ) — Proceeds from disposal of property, plant and equipment — — Proceeds from sale of equity interest in unconsolidated affiliate — — — Net cash flows used in investing activities ) ) ) ) Cash flows from financing activities: Proceeds from public equity offerings, net — — — Proceeds from Credit Facility — — — Payments Credit Facility ) — — — ) Payments related to intercompany financing, net — ) ) — Payments for debt issuance costs, deferred financing costs and registration costs ) — — — ) Contributions from parent and affiliates — ) — Share-based payment activity ) — — — ) Payments of distributions ) ) ) ) Payments of SMR liability — ) — — ) Intercompany advances, net — — ) — Net cash flows provided by financing activities ) Net (decrease) increase in cash and cash equivalents ) ) — Cash and cash equivalents at beginning of period — Cash and cash equivalents at end of period $ $ $ $ — $

Supplemental Cash Flow Inform33

Supplemental Cash Flow Information (Tables)	6 Months Ended
	Jun. 30, 2015
Supplemental Cash Flow Information
Schedule of 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 $ $ Cash received for income taxes, net Supplemental schedule of non-cash investing and financing activities: Amounts payable for property, plant and equipment (1) $ $ Interest capitalized on construction in progress Issuance of common units for vesting of share-based payment awards (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.

Variable Interest Entity (Detai

Variable Interest Entity (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014	Nov. 30, 2014	Jan. 31, 2014	Feb. 28, 2013
MarkWest Utica EMG
Variable Interest Entities
Distributions received from Ohio Gathering			$ 336.1
Ohio Gathering
Variable Interest Entities
Operational service revenue	$ 4.2	$ 1	$ 8.9	$ 1
Ohio Gathering | Summit
Variable Interest Entities
Percentage of ownership interest held by non-controlling interest	40.00%		40.00%				1.00%
Total Variable Interest Entities | MarkWest Utica EMG
Variable Interest Entities
Noncontrolling interest owners total funding commitment								$ 950
Percentage of capital required by reporting entity after non-controlling interest minimum contribution								100.00%
Aggregate contributions to VIE threshold								$ 2,000
Aggregate capital contributed by all members						$ 2,000
Maximum percentage of ownership interest in joint venture	70.00%		70.00%
Threshold percentage for non-controlling owners to make pro rata contributions	30.00%		30.00%
Maximum non-controlling percentage of capital contributions until pro rata ownership threshold is reached			10.00%
Noncontrolling interest owners actual contribution	$ 989.9		$ 989.9
Contribution by the Partnership	$ 1,379.6		$ 1,379.6
Percentage of ownership interest held by non-controlling interest	45.00%		45.00%
Noncontrolling interest owners capital contribution preference threshold								$ 500
Accrual of preference amount to EMG Utica's investment balance during the period	$ 10.9	$ 9.1	$ 21.2	$ 17.9
Investment balance as a percent of aggregate investment balances			55.00%
Percentage of available cash to be received by the Partnership	60.00%		60.00%
Percentage of aggregate investment balances for proportionate distribution of cash	60.00%		60.00%
Percentage of aggregate investment balances for end of de facto agent relationship			60.00%
Ohio Gathering | Summit
Variable Interest Entities
Cash investment received					$ 341.1

Other Equity Interests (Details

Other Equity Interests (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended			6 Months Ended		12 Months Ended
	Dec. 31, 2013	Jun. 30, 2015	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Other Equity Interests
Proceeds from sale of assets under construction					$ 2,360	$ 21,562
Utica Condensate
Other Equity Interests
Ownership percentage in equity method investment		55.00%			55.00%
Utica Condensate | Sale of assets to investee | Assets under construction
Other Equity Interests
Amount of assets sold	$ 17,000
Proceeds from sale of assets under construction				$ 17,000
Ohio Condensate
Other Equity Interests
Operational service revenue		$ 900	$ 900		$ 2,000	$ 1,300
Ohio Condensate | Blackhawk | Maximum
Other Equity Interests
Percentage of ownership interest held by non-controlling interest	1.00%
Ohio Condensate | Summit
Other Equity Interests
Percentage of ownership interest held by non-controlling interest		40.00%			40.00%
Utica Condensate | Ohio Condensate
Other Equity Interests
Ownership percentage in subsidiary	99.00%	60.00%			60.00%
Ohio Condensate | Summit
Other Equity Interests
Cash investment received							$ 8,600

Derivative Financial Instrume36

Derivative Financial Instruments (Details) - Jun. 30, 2015 $ in Thousands	USD ($)MMBTUgalbbl	USD ($)MMBTUgalbbl
Commodity contracts | Derivative instruments not designated as hedging instruments
Derivative financial instruments
Notional quantity of Crude Oil contracts (in Bbl) | bbl	293,800	293,800
Notional quantity of Natural Gas contracts (in MMBtu) | MMBTU	1,311,126	1,311,126
Notional quantity of NGL contracts (in Gal) | gal	111,236,914	111,236,914
Embedded derivatives in commodity contracts | Embedded derivative in gas processing and purchase contract
Derivative financial instruments
Notional amount for embedded derivative in commodity contract (in Dth per day)	9,000	9,000
Term of producer's option to renew gas purchase agreement		5 years
Inception value deemed to have settled	$ 2,600
Fair value of commodity contract	(39,101)	$ (39,101)
Inception value for period from July 1, 2015 to December 31, 2022	(50,928)	(50,928)
Derivative asset (liability) as of June 30, 2015	11,827	11,827
Embedded derivatives in commodity contracts | Embedded derivative in electricity purchase contract
Derivative financial instruments
Derivative asset (liability) as of June 30, 2015	$ (100)	$ (100)

Derivative Financial Instrume37

Derivative Financial Instruments (Details 2) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	$ 23,127	$ 37,428
Gross Amounts Not Offset in the Consolidated Balance Sheet	(1,026)
Net Amount	22,101	37,428
Liabilities
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(1,219)
Gross Amounts Not Offset in the Consolidated Balance Sheet	1,026
Net Amount	(193)
Current Assets
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	15,151	20,921
Gross Amounts Not Offset in the Consolidated Balance Sheet	(1,026)
Net Amount	14,125	20,921
Non-current Assets
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	7,976	16,507
Net Amount	7,976	16,507
Current Liabilities
Liabilities
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(1,164)
Gross Amounts Not Offset in the Consolidated Balance Sheet	1,026
Net Amount	(138)
Non-current Liabilities
Liabilities
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(55)
Net Amount	(55)
Commodity contracts, including embedded derivatives | Derivative instruments not designated as hedging instruments
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	23,127	37,428
Liabilities
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(1,219)
Commodity contracts, including embedded derivatives | Derivative instruments not designated as hedging instruments | Current Assets
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	15,151	20,921
Commodity contracts, including embedded derivatives | Derivative instruments not designated as hedging instruments | Non-current Assets
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	7,976	16,507
Commodity contracts, including embedded derivatives | Derivative instruments not designated as hedging instruments | Current Liabilities
Liabilities
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(1,164)
Commodity contracts, including embedded derivatives | Derivative instruments not designated as hedging instruments | Non-current Liabilities
Liabilities
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(55)
Commodity contracts | Current Assets
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	11,241	18,652
Gross Amounts Not Offset in the Consolidated Balance Sheet	(1,026)
Net Amount	10,215	18,652
Commodity contracts | Non-current Assets
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	59
Net Amount	59
Commodity contracts | Current Liabilities
Liabilities
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(1,073)
Gross Amounts Not Offset in the Consolidated Balance Sheet	1,026
Net Amount	(47)
Commodity contracts | Non-current Liabilities
Liabilities
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(55)
Net Amount	(55)
Embedded derivatives in commodity contracts | Current Assets
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	3,910	2,269
Net Amount	3,910	2,269
Embedded derivatives in commodity contracts | Non-current Assets
Assets
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	7,917	16,507
Net Amount	7,917	$ 16,507
Embedded derivatives in commodity contracts | Current Liabilities
Liabilities
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(91)
Net Amount	$ (91)

Derivative Financial Instrume38

Derivative Financial Instruments (Details 3) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Impact of the Partnership's derivative instruments on Condensed Consolidated Statements of Operations
Unrealized loss			$ (15,520)	$ (7,024)
Derivative instruments not designated as hedging instruments
Impact of the Partnership's derivative instruments on Condensed Consolidated Statements of Operations
Total gain (loss)	$ (2,208)	$ (20,762)	620	(16,663)
Derivative instruments not designated as hedging instruments | Revenue: Derivative gain (loss)
Impact of the Partnership's derivative instruments on Condensed Consolidated Statements of Operations
Realized gain (loss)	5,132	(1,774)	16,120	(9,381)
Unrealized loss	(4,994)	(4,979)	(8,614)	(1,339)
Total gain (loss)	138	(6,753)	7,506	(10,720)
Derivative instruments not designated as hedging instruments | Derivative loss related to purchased product costs
Impact of the Partnership's derivative instruments on Condensed Consolidated Statements of Operations
Realized gain (loss)	20	(144)	20	(258)
Unrealized loss	(2,275)	(11,820)	(6,815)	(3,908)
Total gain (loss)	(2,255)	(11,964)	(6,795)	(4,166)
Derivative instruments not designated as hedging instruments | Derivative loss related to facility expenses
Impact of the Partnership's derivative instruments on Condensed Consolidated Statements of Operations
Unrealized loss	$ (91)	$ (2,045)	$ (91)	$ (1,777)

Fair Value (Details)

Fair Value (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Derivative instruments carried at fair value in Condensed Consolidated Balance Sheet
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	$ 23,127	$ 37,428
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(1,219)
Recurring | Significant other observable inputs (Level 2) | Commodity contracts
Derivative instruments carried at fair value in Condensed Consolidated Balance Sheet
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	5,413	14,812
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(19)
Recurring | Significant unobservable inputs (Level 3) | Commodity contracts
Derivative instruments carried at fair value in Condensed Consolidated Balance Sheet
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	5,887	3,840
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	(1,109)
Recurring | Significant unobservable inputs (Level 3) | Embedded derivatives in commodity contracts
Derivative instruments carried at fair value in Condensed Consolidated Balance Sheet
Total carrying value of derivative assets in Condensed Consolidated Balance Sheets	11,827	$ 18,776
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheets	$ (91)

Fair Value (Details 2)

Fair Value (Details 2) - Commodity contracts - Significant unobservable inputs (Level 3)	Jun. 30, 2015$ / item
Asset | Propane prices | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.44
Asset | Propane prices | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.54
Asset | Isobutane prices | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.59
Asset | Isobutane prices | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.72
Asset | Normal butane prices | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.58
Asset | Normal butane prices | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.69
Asset | Natural gasoline prices | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	1.22
Asset | Natural gasoline prices | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	1.24
Liability | Ethane prices | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.20
Liability | Ethane prices | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.21
Liability | Isobutane prices | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.62
Liability | Isobutane prices | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.72
Liability | Normal butane prices | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.58
Liability | Normal butane prices | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.69
Liability | Natural gasoline prices | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	1.22
Liability | Natural gasoline prices | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	1.27

Fair Value (Details 3)

Fair Value (Details 3) - Jun. 30, 2015 - Embedded derivatives in commodity contracts	item$ / MWh$ / MMBTU$ / item
Propane prices | Asset | Significant unobservable inputs (Level 3) | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.44
Propane prices | Asset | Significant unobservable inputs (Level 3) | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.61
Isobutane prices | Asset | Significant unobservable inputs (Level 3) | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.59
Isobutane prices | Asset | Significant unobservable inputs (Level 3) | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.82
Normal butane prices | Asset | Significant unobservable inputs (Level 3) | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.58
Normal butane prices | Asset | Significant unobservable inputs (Level 3) | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	0.79
Natural gasoline prices | Asset | Significant unobservable inputs (Level 3) | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	1.22
Natural gasoline prices | Asset | Significant unobservable inputs (Level 3) | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit)	1.34
Natural gas prices | Asset | Significant unobservable inputs (Level 3) | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit) | $ / MMBTU	2.68
Natural gas prices | Asset | Significant unobservable inputs (Level 3) | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward price (in dollars per unit) | $ / MMBTU	3.69
Embedded derivative in gas processing and purchase contract
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Number of renewal periods | item	2
Term of producer's option to renew gas purchase agreement	5 years
Embedded derivative in gas processing and purchase contract | Asset | Significant unobservable inputs (Level 3)
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Probability of renewal (as a percent)	0.00%
Embedded derivative in electricity purchase contract | Liability | Significant unobservable inputs (Level 3) | Minimum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward ERCOT Pricing (in dollars per unit) | $ / MWh	26.55
Embedded derivative in electricity purchase contract | Liability | Significant unobservable inputs (Level 3) | Maximum
Unobservable inputs used in the valuation of Level 3 instruments of Assets and Liabilities
Forward ERCOT Pricing (in dollars per unit) | $ / MWh	35.56

Fair Value (Details 4)

Fair Value (Details 4) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Commodity contracts
Derivative assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy
Fair value at beginning of period	$ 5,091	$ (751)	$ 3,840	$ (5,460)
Total gain (loss) (realized and unrealized) included in earnings	1,895	(1,961)	6,923	(4,238)
Settlements	(2,208)	620	(5,985)	7,606
Fair value at end of period	4,778	(2,092)	4,778	(2,092)
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	872	(1,758)	4,778	(1,319)
Embedded derivatives in commodity contracts
Derivative assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy
Fair value at beginning of period	14,294	(28,486)	18,776	(35,032)
Total gain (loss) (realized and unrealized) included in earnings	(4,416)	(16,479)	(10,198)	(12,068)
Settlements	1,858	2,134	3,158	4,269
Fair value at end of period	11,736	(42,831)	11,736	(42,831)
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	$ (1,446)	$ (15,959)	$ (6,916)	$ (12,204)

Inventories (Details)

Inventories (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Inventories
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

Impairment of Long-Lived Asse44

Impairment of Long-Lived Assets and Goodwill (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Mar. 31, 2015	Jun. 30, 2015
Impairment expense		$ 25,523
Southwest Segment | Appleby
Impairment expense		22,800
Impairment related to intangibles		16,800
Impairment related to property, plant and equipment		6,000
Western Oklahoma Reporting Unit | Southwest Segment
Goodwill impairment charge	$ 2,700
Other reporting units
Goodwill impairment charge		$ 0

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	Mar. 20, 2014USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Nov. 30, 2014USD ($)	Mar. 19, 2014USD ($)
Long-Term Debt
Long-term debt, net of discounts		$ 4,540,663		$ 4,540,663	$ 4,540,663	$ 4,540,663		$ 3,621,404
Accrued interest payable		47,600		47,600	47,600	47,600
Deferred financing costs						20,270	$ 2,045
Pre-tax loss related to repurchase of Senior Notes				(117,860)		(117,860)
Non-cash write-off of the unamortized discount and deferred finance costs				14,700
Payment of redemption premiums and third-party expenses				103,200
Revolving credit facility
Long-Term Debt
Long-term debt, net of discounts		447,500		447,500	447,500	447,500		$ 97,600
Applicable interest rate (as a percent)								4.50%
Credit facility current lending capacity	$ 1,300,000
Extension of maturity	18 months
Accordion option to increase borrowing capacity under the Credit Facility	$ 500,000									$ 250,000
Deferred financing costs							$ 1,900
Letters of credit maximum borrowing capacity		150,000		150,000	150,000	150,000
Short-term swingline loan maximum borrowing capacity		10,000		10,000	$ 10,000	$ 10,000
Minimum Interest Coverage Ratio						2.5
Maximum leverage ratio prior to Collateral Release Date					5.5	5.25		5.5
Maximum leverage ratio after Collateral Release Date						5
Borrowings outstanding		447,500		447,500	$ 447,500	$ 447,500
Letters of credit outstanding amount		11,300		11,300	11,300	11,300
Unused borrowing capacity		841,200		841,200	841,200	$ 841,200
Revolving credit facility | Alternate Base Rate Loans | Minimum
Long-Term Debt
Margin prior to Collateral Release Date (as a percent)						0.50%
Margin after Collateral Release Date (as a percent)						0.125%
Revolving credit facility | Alternate Base Rate Loans | Maximum
Long-Term Debt
Margin prior to Collateral Release Date (as a percent)						1.50%
Margin after Collateral Release Date (as a percent)						1.00%
Revolving credit facility | Alternate Base Rate Loans | Prime rate
Long-Term Debt
Basis of variable interest rate						prime rate
Revolving credit facility | Alternate Base Rate Loans | Federal funds effective swap rate
Long-Term Debt
Basis of variable interest rate						Federal Funds Rate
Spread on variable rate basis (as a percent)						0.50%
Revolving credit facility | Alternate Base Rate Loans | One month LIBOR
Long-Term Debt
Basis of variable interest rate						One month LIBOR
Spread on variable rate basis (as a percent)						1.00%
Revolving credit facility | LIBO Rate Loans | Minimum
Long-Term Debt
Margin prior to Collateral Release Date (as a percent)						1.50%
Margin after Collateral Release Date (as a percent)						1.125%
Revolving credit facility | LIBO Rate Loans | Maximum
Long-Term Debt
Margin prior to Collateral Release Date (as a percent)						2.50%
Margin after Collateral Release Date (as a percent)						2.00%
Revolving credit facility | LIBO Rate Loans | One month LIBOR
Long-Term Debt
Basis of variable interest rate						LIBOR
Revolving credit facility | Credit facility bearing interest of 2.4 percent
Long-Term Debt
Long-term debt, net of discounts		$ 250,000		$ 250,000	$ 250,000	$ 250,000
Applicable interest rate (as a percent)		2.40%		2.40%	2.40%	2.40%
Revolving credit facility | Credit facility bearing interest of 4.5 percent
Long-Term Debt
Long-term debt, net of discounts		$ 197,500		$ 197,500	$ 197,500	$ 197,500
Applicable interest rate (as a percent)		4.50%		4.50%	4.50%	4.50%
Senior Notes
Long-Term Debt
Estimated aggregate fair value of debt		$ 4,058,000		$ 4,058,000	$ 4,058,000	$ 4,058,000		$ 3,563,000
Senior Notes | 2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020
Long-Term Debt
Long-term debt, net of discounts								$ 500,000
Debt instrument, stated interest rate percentage								6.75%
Amount of debt repurchased		500,000
Senior Notes | 2021 Senior Notes, 6.5% interest, issued February and March 2011 and due August 2021
Long-Term Debt
Long-term debt, net of discounts								$ 324,587
Debt instrument, stated interest rate percentage								6.50%
Long-term debt, discounts								$ 413
Amount of debt repurchased		325,000
Senior Notes | 2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022
Long-Term Debt
Long-term debt, net of discounts								$ 455,000
Debt instrument, stated interest rate percentage								6.25%
Amount of debt repurchased		455,000
Senior Notes | 2023A Senior Notes, 5.5% interest, issued August 2012 and due February 2023
Long-Term Debt
Long-term debt, net of discounts		$ 744,553		$ 744,553	$ 744,553	$ 744,553		$ 744,217
Debt instrument, stated interest rate percentage		5.50%		5.50%	5.50%	5.50%		5.50%
Long-term debt, discounts		$ 5,447		$ 5,447	$ 5,447	$ 5,447		$ 5,783
Senior Notes | 2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023
Long-Term Debt
Long-term debt, net of discounts		$ 1,000,000		$ 1,000,000	$ 1,000,000	$ 1,000,000		$ 1,000,000
Debt instrument, stated interest rate percentage		4.50%		4.50%	4.50%	4.50%		4.50%
Senior Notes | 2024 Senior Notes, 4.875% interest, issued November 2014 and March 2015, due December 2024
Long-Term Debt
Long-term debt, net of discounts		$ 1,160,204		$ 1,160,204	$ 1,160,204	$ 1,160,204		$ 500,000
Debt instrument, stated interest rate percentage		4.875%		4.875%	4.875%	4.875%		4.875%
Long-term debt, premium		$ 10,204		$ 10,204	$ 10,204	$ 10,204
Senior Notes | 2024 Senior Notes, 4.875% interest, issued March 2015 and due December 2024
Long-Term Debt
Debt instrument, stated interest rate percentage			4.875%
Aggregate principal amount			$ 650,000
Proceeds from issuance of senior notes, net of underwriting fees and the other expenses of the offering			653,600
Accrued interest on notes issued			$ 9,000
Senior Notes | 2024 Senior Notes, 4.875% interest, issued November 2014 and due December 2024
Long-Term Debt
Debt instrument, stated interest rate percentage									4.875%
Aggregate principal amount									$ 500,000
Senior Notes | 2025 Senior Notes, 4.875% interest, issued June 2015 and due June 2025
Long-Term Debt
Long-term debt, net of discounts		$ 1,188,406		$ 1,188,406	$ 1,188,406	$ 1,188,406
Debt instrument, stated interest rate percentage		4.875%		4.875%	4.875%	4.875%
Long-term debt, premium		$ 11,594		$ 11,594	$ 11,594	$ 11,594
Aggregate principal amount		1,200,000		$ 1,200,000	$ 1,200,000	$ 1,200,000
Proceeds from issuance of senior notes, net of underwriting fees and the other expenses of the offering		1,174,900
Accrued interest on notes issued		$ 23,000

Equity (Details)

Equity (Details) $ / shares in Units, shares in Thousands, $ in Thousands	1 Months Ended			3 Months Ended			6 Months Ended		8 Months Ended	12 Months Ended
	Nov. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Sep. 30, 2013USD ($)	Jun. 30, 2015USD ($)$ / sharesshares	Mar. 31, 2015$ / shares	Jun. 30, 2014USD ($)shares	Jun. 30, 2015USD ($)iteminstallment$ / sharesshares	Jun. 30, 2014USD ($)shares	Jun. 30, 2015USD ($)$ / sharesshares	Dec. 31, 2014$ / shares
Equity Offerings
Proceeds from public equity offerings, net							$ 39,630	$ 711,837
Common Units
Equity Offerings
Aggregate common units sold (in units) | shares							636	11,284
Distributions of Available Cash
Distribution per common unit (in dollars per unit) | $ / shares					$ 0.91		$ 0.92			$ 0.90
Common Units | ATM
Equity Offerings
Aggregate common units sold (in units) | shares				600		7,000	600	11,200
Proceeds from public equity offerings, net				$ 40,000		$ 440,000	$ 40,000	$ 712,000
Common Units | September 2013 ATM
Equity Offerings
Aggregate common units sold (in units) | shares								4,200
Proceeds from public equity offerings, net								$ 272,000
Offering under program			$ 1,000,000
Manager fees								$ 4,000
Common Units | March 2014 ATM
Equity Offerings
Aggregate common units sold (in units) | shares						7,000		7,000
Proceeds from public equity offerings, net						$ 440,000		$ 440,000
Offering under program		$ 1,200,000
Manager fees								$ 3,500
Common Units | November 2014 ATM
Equity Offerings
Aggregate common units sold (in units) | shares				600			600		3,100
Proceeds from public equity offerings, net				$ 40,000			$ 40,000		$ 214,000
Offering under program	$ 1,500,000
Class B Units | M & R
Equity Offerings
Conversion ratio | item							1
Number of installments | installment							2
Maximum | Common Units
Distributions of Available Cash
Common Unit Price (in dollars per share) | $ / shares				$ 69.50	69.16		$ 69.50		$ 69.50	77.31
Minimum | Common Units
Distributions of Available Cash
Common Unit Price (in dollars per share) | $ / shares				$ 56.20	$ 54.04		$ 56.20		$ 56.20	$ 58.67

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income tax
(Loss) income before provision for income tax	$ (97,848)	$ 10,108	$ (96,448)	$ 38,570
Federal income tax at statutory rate			(9,164)	2,324
Permanent items			16	33
State income taxes, net of federal benefit			(2,843)	577
Tax rate changes			(1,517)	4,250
Provision on income from Class A units			(2,069)	2,422
Total provision for income tax expense (benefit)	$ (11,456)	$ (2,940)	(15,577)	9,606
Eliminations
Income tax
(Loss) income before provision for income tax			$ (653)	$ (368)
Federal statutory rate (as a percent)			0.00%	0.00%
Corporation | Reportable legal entities
Income tax
(Loss) income before provision for income tax			$ (26,183)	$ 6,641
Federal statutory rate (as a percent)			35.00%	35.00%
Federal income tax at statutory rate			$ (9,164)	$ 2,324
Permanent items			16	33
State income taxes, net of federal benefit			(784)	168
Tax rate changes				4,250
Provision on income from Class A units			(2,069)	2,422
Total provision for income tax expense (benefit)			(12,001)	9,197
Partnership | Reportable legal entities
Income tax
(Loss) income before provision for income tax			$ (69,612)	$ 32,297
Federal statutory rate (as a percent)			0.00%	0.00%
State income taxes, net of federal benefit			$ (2,059)	$ 409
Tax rate changes			(1,517)
Total provision for income tax expense (benefit)			$ (3,576)	$ 409

Earnings Per Common Unit (Detai

Earnings Per Common Unit (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Earnings (Loss) Per Common Unit
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		574		1,141
(Loss) income available for common unitholders - diluted	$ (102,130)	$ 9,000	$ (111,855)	$ 21,514
Weighted average common units outstanding-basic (in units)	186,855,000	164,613,000	186,771,000	161,727,000
Potential common shares (Class B and phantom units)		16,624,000		16,651,000
Weighted average common units outstanding-diluted (in units)	186,855,000	181,237,000	186,771,000	178,378,000
Net (loss) income attributable to the Partnership's common unitholders per common unit:
Basic (in dollars per unit)	$ (0.55)	$ 0.05	$ (0.60)	$ 0.13
Diluted (in dollars per unit)	$ (0.55)	$ 0.05	$ (0.60)	$ 0.12
Potential common shares excluded from calculation as anti-dilutive (in units)	12,717,000		12,726,000
Class B Units
Earnings (Loss) Per Common Unit
Net (loss) income attributable to the Partnership's unitholders	$ 0	$ 0	$ 0	$ 0
Net (loss) income attributable to the Partnership's common unitholders per common unit:
Basic (in dollars per unit)	$ 0	$ 0	$ 0	$ 0
Diluted (in dollars per unit)	$ 0	$ 0	$ 0	$ 0

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment information
Segment purchased product costs	$ 123,292	$ 215,824	$ 246,776	$ 427,388
Segment facility expenses	88,550	83,545	180,366	167,250
Income from operations	70,353	55,626	122,885	127,627
Capital expenditures			833,062	1,275,323
Total segments
Segment information
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
Segment facility expenses	97,467	87,892	198,238	173,282
Segment portion of operating income (loss) attributable to non-controlling interests	25,695	4,693	47,349	7,828
Income from operations	239,604	220,132	476,026	437,980
Capital expenditures			998,108	1,306,430
Intersegment Eliminations
Segment information
Segment revenue		(900)	(44)	(2,471)
Net operating margin		(900)	(44)	(2,471)
Segment facility expenses		(900)	(44)	(2,471)
Adjustments for unconsolidated affiliates
Segment information
Segment portion of operating income (loss) attributable to non-controlling interests	(14,200)	(509)	(24,440)	(509)
Capital expenditures			(170,442)	(40,013)
Not allocated to segments
Segment information
Capital expenditures			5,396	8,906
Marcellus | Total segments
Segment information
Segment revenue	199,311	183,734	396,487	358,893
Segment purchased product costs	4,568	39,710	11,070	74,000
Net operating margin	194,743	144,024	385,417	284,893
Segment facility expenses	39,938	33,755	83,320	69,228
Income from operations	154,805	110,269	302,097	215,665
Capital expenditures			584,067	792,927
Utica Segment | Total segments
Segment information
Segment revenue	63,942	30,826	122,853	54,592
Segment purchased product costs	679	7,353	860	11,488
Net operating margin	63,263	23,473	121,993	43,104
Segment facility expenses	15,952	12,174	32,590	24,026
Segment portion of operating income (loss) attributable to non-controlling interests	23,633	4,687	43,740	7,823
Income from operations	23,678	6,612	45,663	11,255
Capital expenditures			290,106	433,615
Utica Segment | Adjustments for unconsolidated affiliates
Segment information
Capital expenditures			167,200	40,000
Northeast Segment | Total segments
Segment information
Segment revenue	22,595	43,777	52,616	105,030
Segment purchased product costs	9,743	15,169	22,261	35,624
Net operating margin	12,852	28,608	30,355	69,406
Segment facility expenses	7,584	8,509	14,462	15,623
Income from operations	5,268	20,099	15,893	53,783
Capital expenditures			1,854	1,300
Southwest Segment | Total segments
Segment information
Segment revenue	200,210	271,140	396,477	530,470
Segment purchased product costs	108,302	153,628	212,585	306,312
Net operating margin	91,908	117,512	183,892	224,158
Segment facility expenses	33,993	34,354	67,910	66,876
Segment portion of operating income (loss) attributable to non-controlling interests	2,062	6	3,609	5
Income from operations	$ 55,853	$ 83,152	112,373	157,277
Capital expenditures			122,081	$ 78,588
Southwest Segment | Adjustments for unconsolidated affiliates
Segment information
Capital expenditures			$ 3,200

Segment Information (Details 2)

Segment Information (Details 2) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment information
Derivative gain (loss)	$ 138	$ (6,753)	$ 7,506	$ (10,720)
Total revenue	459,628	518,366	926,958	1,030,842
Total segments
Segment information
Total segment revenue	486,058	528,577	968,389	1,046,514
Not allocated to segments
Segment information
Derivative gain (loss)	138	(6,753)	7,506	(10,720)
Adjustments for unconsolidated affiliates
Segment information
Total revenue	(33,016)	(3,833)	(60,547)	(3,833)
Reconciling adjustments
Segment information
Revenue deferral adjustment and other	$ 6,448	$ 375	$ 11,610	$ (1,119)

Segment Information (Details 3)

Segment Information (Details 3) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment information
Revenue	$ 459,628	$ 518,366	$ 926,958	$ 1,030,842
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)
Income from operations	70,353	55,626	122,885	127,627
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
Total segments
Segment information
Portion of operating income attributable to non-controlling interests	(25,695)	(4,693)	(47,349)	(7,828)
Income from operations	239,604	220,132	476,026	437,980
Reconciling adjustments
Segment information
Portion of operating income attributable to non-controlling interests	11,495	4,184	22,909	7,319
Revenue deferral adjustment	1,076	375	154	(1,119)
Facility expenses adjustments	2,688	2,688	5,376	5,376
Adjustments for unconsolidated affiliates
Segment information
Portion of operating income attributable to non-controlling interests	14,200	509	24,440	509
Revenue	(33,016)	(3,833)	(60,547)	(3,833)
Facility expense, operational service fees and purchased product cost adjustments	12,543	2,598	26,001	2,598
Not allocated to segments
Segment information
Derivative gain (loss) not allocated to segments	(2,208)	(20,762)	620	(16,663)
Compensation expense included in facility expenses not allocated to segments	(942)	(903)	(2,049)	(1,906)
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)

Segment Information (Details 4)

Segment Information (Details 4) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Segment information
Management fee revenues unconsolidated affiliate	$ 5.4	$ 2.1	$ 11.5	$ 2.7
Southwest Segment
Segment information
Revenue deferral adjustment	0.2	0.2	0.1	0.4
Northeast Segment
Segment information
Revenue deferral adjustment	$ 0.9	$ 1.5	$ 0.1	$ 3.4

Segment Information (Details 5)

Segment Information (Details 5) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Segment Assets
Certain cash and cash equivalents	$ 45,162	$ 108,887	$ 299,412	$ 85,305
Fair value of derivatives	23,127	37,428
Investment in unconsolidated affiliates	888,820	805,633
Total assets	11,359,559	10,980,778
Total segments
Segment Assets
Total assets	11,184,044	10,720,981
Not allocated to segments
Segment Assets
Certain cash and cash equivalents	1
Fair value of derivatives	23,127	37,428
Investment in unconsolidated affiliates	57,777	108,849
Other	94,610	113,520
Marcellus | Total segments
Segment Assets
Total assets	6,106,353	5,749,932
Utica Segment | Total segments
Segment Assets
Total assets	2,270,379	2,163,025
Northeast Segment | Total segments
Segment Assets
Total assets	398,221	445,911
Southwest Segment | Total segments
Segment Assets
Total assets	$ 2,409,091	$ 2,362,113

Supplemental Condensed Consol54

Supplemental Condensed Consolidating Financial Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 45,162	$ 108,887	$ 299,412	$ 85,305
Restricted cash	10,000	20,000
Receivables and other current assets	331,624	380,748
Receivables from unconsolidated affiliates, net	5,348	7,097
Fair value of derivative instruments	15,151	20,921
Total current assets	407,285	537,653
Total property, plant and equipment, net	9,135,811	8,652,900
Other long-term assets:
Investment in unconsolidated affiliates	888,820	805,633
Intangibles, net of accumulated amortization	760,936	809,277
Fair value of derivative instruments	7,976	16,507
Other long-term assets	158,731	158,808
Total assets	11,359,559	10,980,778
Current liabilities:
Fair value of derivative instruments	1,164
Payables to unconsolidated affiliates	12,009	8,621
Other current liabilities	470,807	631,242
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	4,540,663	3,621,404
Other long-term liabilities	163,122	169,012
Equity:
Non-controlling interest in consolidated subsidiaries	1,022,154	983,477
Total equity	5,828,801	6,193,239	5,401,550	4,798,133
Total liabilities and equity	11,359,559	10,980,778
Common Units
Equity:
Common units or Class B units	4,355,128	4,758,243
Total equity	4,355,128	4,758,243	3,913,993	3,476,295
Class B Units
Equity:
Common units or Class B units	451,519	451,519
Total equity	$ 451,519	451,519	602,025	602,025
Guarantor Subsidiaries
Condensed Consolidating Balance Sheets
Percentage of Partnership interest in subsidiaries guaranteeing the Senior Notes	100.00%
Reportable legal entities | Parent
Current assets:
Cash and cash equivalents			15	224
Receivables and other current assets	$ 4,515	1,219
Receivables from unconsolidated affiliates, net		247
Intercompany receivables	934,388	633,994
Total current assets	938,903	635,460
Total property, plant and equipment, net	10,268	9,992
Other long-term assets:
Investment in consolidated affiliates	8,117,920	7,990,532
Intercompany notes receivable	231,400	186,100
Other long-term assets	55,376	52,825
Total assets	9,353,867	8,874,909
Current liabilities:
Intercompany payables	1,948	3,287
Payables to unconsolidated affiliates	12
Other current liabilities	51,194	69,552
Total current liabilities	53,154	72,839
Deferred income taxes	2,588	6,162
Long-term debt, net of discounts	4,540,663	3,621,404
Other long-term liabilities	8,453	8,794
Equity:
Total equity	4,749,009	5,165,710
Total liabilities and equity	9,353,867	8,874,909
Reportable legal entities | Parent | Common Units
Equity:
Common units or Class B units	4,297,490	4,714,191
Reportable legal entities | Parent | Class B Units
Equity:
Common units or Class B units	451,519	451,519
Reportable legal entities | Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	2		51,580	79,363
Receivables and other current assets	146,887	225,695
Receivables from unconsolidated affiliates, net	2,687	3,001
Intercompany receivables	18,214	24,683
Fair value of derivative instruments	12,723	17,386
Total current assets	180,513	270,765
Total property, plant and equipment, net	2,175,626	2,140,565
Other long-term assets:
Investment in unconsolidated affiliates	85,091	82,616
Investment in consolidated affiliates	7,005,652	6,500,008
Intangibles, net of accumulated amortization	506,353	546,637
Fair value of derivative instruments	7,976	16,507
Other long-term assets	26,670	29,412
Total assets	9,987,881	9,586,510
Current liabilities:
Intercompany payables	976,097	729,714
Fair value of derivative instruments	554
Payables to unconsolidated affiliates	40
Other current liabilities	174,805	177,269
Total current liabilities	1,151,496	906,983
Deferred income taxes	340,350	351,098
Long-term intercompany financing payable	231,400	186,100
Other long-term liabilities	146,715	151,797
Equity:
Total equity	8,117,920	7,990,532
Total liabilities and equity	9,987,881	9,586,510
Reportable legal entities | Guarantor Subsidiaries | Common Units
Equity:
Common units or Class B units	8,117,920	7,990,532
Reportable legal entities | Non-Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	45,160	108,887	$ 247,817	$ 5,718
Restricted cash	10,000	20,000
Receivables and other current assets	180,222	153,834
Receivables from unconsolidated affiliates, net	2,661	3,849
Intercompany receivables	47,131	178,109
Fair value of derivative instruments	2,428	3,535
Total current assets	287,602	468,214
Total property, plant and equipment, net	6,984,817	6,550,040
Other long-term assets:
Investment in unconsolidated affiliates	813,672	733,226
Intangibles, net of accumulated amortization	254,583	262,640
Other long-term assets	76,685	76,571
Total assets	8,417,359	8,090,691
Current liabilities:
Intercompany payables	21,688	103,787
Fair value of derivative instruments	610
Payables to unconsolidated affiliates	11,957	8,621
Other current liabilities	247,355	386,821
Total current liabilities	281,610	499,229
Fair value of derivative instruments	55
Long-term intercompany financing payable	93,750	95,061
Other long-term liabilities	7,954	8,421
Equity:
Total equity	8,033,990	7,487,980
Total liabilities and equity	8,417,359	8,090,691
Reportable legal entities | Non-Guarantor Subsidiaries | Common Units
Equity:
Common units or Class B units	8,033,990	7,487,980
Eliminations
Current assets:
Intercompany receivables	(999,733)	(836,786)
Total current assets	(999,733)	(836,786)
Total property, plant and equipment, net	(34,900)	(47,697)
Other long-term assets:
Investment in unconsolidated affiliates	(9,943)	(10,209)
Investment in consolidated affiliates	(15,123,572)	(14,490,540)
Intercompany notes receivable	(231,400)	(186,100)
Total assets	(16,399,548)	(15,571,332)
Current liabilities:
Intercompany payables	(999,733)	(836,788)
Other current liabilities	(2,547)	(2,400)
Total current liabilities	(1,002,280)	(839,188)
Long-term intercompany financing payable	(325,150)	(281,161)
Equity:
Non-controlling interest in consolidated subsidiaries	1,022,154	983,477
Total equity	(15,072,118)	(14,450,983)
Total liabilities and equity	(16,399,548)	(15,571,332)
Eliminations | Common Units
Equity:
Common units or Class B units	$ (16,094,272)	$ (15,434,460)

Supplemental Condensed Consol55

Supplemental Condensed Consolidating Financial Information (Details 2) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Condensed Consolidating Statements of Operations
Total revenue	$ 459,628	$ 518,366	$ 926,958	$ 1,030,842
Operating expenses:
Purchased product costs	125,547	227,788	253,571	431,554
Facility expenses	88,641	85,590	180,457	169,027
Selling, general and administrative expenses	34,971	27,701	69,606	62,991
Depreciation and amortization	137,505	120,043	272,923	237,950
Other operating expenses (income)	2,611	1,618	1,993	1,693
Impairment expense			25,523
Total operating expenses	389,275	462,740	804,073	903,215
Income from operations	70,353	55,626	122,885	127,627
Loss on redemption of debt	(117,860)		(117,860)
Other expense, net	(50,341)	(45,518)	(101,473)	(89,057)
(Loss) income before provision for income tax	(97,848)	10,108	(96,448)	38,570
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 loss 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
Reportable legal entities | Parent
Operating expenses:
Selling, general and administrative expenses	14,013	10,760	27,545	24,415
Depreciation and amortization	393	288	717	568
Total operating expenses	14,406	11,048	28,262	24,983
Income from operations	(14,406)	(11,048)	(28,262)	(24,983)
Earnings from consolidated affiliates	73,192	54,074	123,460	121,784
Loss on redemption of debt	(117,860)		(117,860)
Other expense, net	(53,898)	(44,526)	(104,209)	(87,688)
(Loss) income before provision for income tax	(112,972)	(1,500)	(126,871)	9,113
Provision for income tax expense (benefit)	(3,740)	251	(3,575)	408
Net (loss) income	(109,232)	(1,751)	(123,296)	8,705
Net (loss) income attributable to the Partnership's unitholders	(109,232)	(1,751)	(123,296)	8,705
Reportable legal entities | Guarantor Subsidiaries
Condensed Consolidating Statements of Operations
Total revenue	232,588	318,408	473,913	643,909
Operating expenses:
Purchased product costs	120,299	180,638	241,630	345,821
Facility expenses	38,920	42,567	76,920	79,600
Selling, general and administrative expenses	13,715	7,795	29,499	18,311
Depreciation and amortization	51,470	49,719	102,414	98,839
Other operating expenses (income)	935	352	1,564	193
Impairment expense			25,523
Total operating expenses	225,339	281,071	477,550	542,764
Income from operations	7,249	37,337	(3,637)	101,145
Earnings from consolidated affiliates	63,113	18,928	125,581	41,317
Other expense, net	(4,887)	(5,382)	(10,486)	(11,480)
(Loss) income before provision for income tax	65,475	50,883	111,458	130,982
Provision for income tax expense (benefit)	(7,716)	(3,191)	(12,002)	9,198
Net (loss) income	73,191	54,074	123,460	121,784
Net (loss) income attributable to the Partnership's unitholders	73,191	54,074	123,460	121,784
Reportable legal entities | Non-Guarantor Subsidiaries
Condensed Consolidating Statements of Operations
Total revenue	231,920	209,800	463,847	408,918
Operating expenses:
Purchased product costs	5,248	47,150	11,941	85,733
Facility expenses	47,291	44,311	98,176	92,682
Selling, general and administrative expenses	10,860	12,416	20,605	25,765
Depreciation and amortization	86,712	71,409	171,934	141,222
Other operating expenses (income)	1,676	6,536	429	6,770
Total operating expenses	151,787	181,822	303,085	352,172
Income from operations	80,133	27,978	160,762	56,746
Other expense, net	(1,926)	(4,978)	(5,483)	(7,934)
(Loss) income before provision for income tax	78,207	23,000	155,279	48,812
Net (loss) income	78,207	23,000	155,279	48,812
Net (loss) income attributable to the Partnership's unitholders	78,207	23,000	155,279	48,812
Eliminations
Condensed Consolidating Statements of Operations
Total revenue	(4,880)	(9,842)	(10,802)	(21,985)
Operating expenses:
Facility expenses	2,430	(1,288)	5,361	(3,255)
Selling, general and administrative expenses	(3,617)	(3,270)	(8,043)	(5,500)
Depreciation and amortization	(1,070)	(1,373)	(2,142)	(2,679)
Other operating expenses (income)		(5,270)		(5,270)
Total operating expenses	(2,257)	(11,201)	(4,824)	(16,704)
Income from operations	(2,623)	1,359	(5,978)	(5,281)
Earnings from consolidated affiliates	(136,305)	(73,002)	(249,041)	(163,101)
Other expense, net	10,370	9,368	18,705	18,045
(Loss) income before provision for income tax	(128,558)	(62,275)	(236,314)	(150,337)
Net (loss) income	(128,558)	(62,275)	(236,314)	(150,337)
Net loss attributable to non-controlling interest	(15,094)	(4,071)	(29,698)	(7,495)
Net (loss) income attributable to the Partnership's unitholders	$ (143,652)	$ (66,346)	$ (266,012)	$ (157,832)

Supplemental Condensed Consol56

Supplemental Condensed Consolidating Financial Information (Details 3) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Condensed Consolidating Statements of Cash Flows
Net cash (used in) 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 disposal of property, plant and equipment	2,360	21,562
Proceeds from sale of equity interest in unconsolidated affiliate		324,657
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 consolidated subsidiary	11,319
Contributions from non-controlling interest	26,689
Payments of SMR liability	(1,319)	(1,201)
Share-based payment activity	(6,117)	(8,943)
Payment of distributions	(363,965)	(278,406)
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
Reportable legal entities | Parent
Condensed Consolidating Statements of Cash Flows
Net cash (used in) provided by operating activities	(145,787)	(97,223)
Cash flows from investing activities:
Capital expenditures	(1,010)	(5,116)
Equity investments in consolidated affiliates	(36,540)	(30,038)
Intercompany advances, net	(295,602)	(808,923)
Distributions from consolidated affiliates	34,736	63,158
Investment in intercompany notes receivable, net	(45,300)	14,200
Net cash flows used in investing activities	(343,716)	(766,719)
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)
Share-based payment activity	(6,117)	(8,943)
Payment of distributions	(339,306)	(278,316)
Net cash flows provided by financing activities	489,503	863,733
Net (decrease) increase in cash and cash equivalents		(209)
Cash and cash equivalents at beginning of period		224
Cash and cash equivalents at end of period		15
Reportable legal entities | Guarantor Subsidiaries
Condensed Consolidating Statements of Cash Flows
Net cash (used in) provided by operating activities	147,039	263,284
Cash flows from investing activities:
Capital expenditures	(121,624)	(108,203)
Equity investments in consolidated affiliates	(674,134)	(1,090,000)
Investment in unconsolidated affiliates	(7,071)	(8,540)
Distributions from consolidated affiliates	301,130	151,110
Proceeds from disposal of property, plant and equipment	22	4,164
Net cash flows used in investing activities	(501,677)	(1,051,469)
Cash flows from financing activities:
Payments related to intercompany financing, net	45,300	(14,200)
Contributions from Parent and affiliates	36,540	30,038
Payments of SMR liability	(1,319)	(1,201)
Payment of distributions	(34,736)	(63,158)
Intercompany advances, net	308,855	808,923
Net cash flows provided by financing activities	354,640	760,402
Net (decrease) increase in cash and cash equivalents	2	(27,783)
Cash and cash equivalents at beginning of period		79,363
Cash and cash equivalents at end of period	2	51,580
Reportable legal entities | Non-Guarantor Subsidiaries
Condensed Consolidating Statements of Cash Flows
Net cash (used in) provided by operating activities	351,362	187,138
Cash flows from investing activities:
Restricted cash	10,000
Capital expenditures	(699,473)	(1,157,346)
Intercompany advances, net	(12,426)
Investment in unconsolidated affiliates	(100,823)	(67,514)
Proceeds from disposal of property, plant and equipment	2,338	17,398
Proceeds from sale of equity interest in unconsolidated affiliate		324,657
Net cash flows used in investing activities	(800,384)	(882,805)
Cash flows from financing activities:
Payments related to intercompany financing, net	(1,164)	(1,034)
Proceeds from sale of equity interest in consolidated subsidiary	11,319
Contributions from non-controlling interest	26,689
Contributions from Parent and affiliates	674,134	1,090,000
Payment of distributions	(325,683)	(151,200)
Net cash flows provided by financing activities	385,295	937,766
Net (decrease) increase in cash and cash equivalents	(63,727)	242,099
Cash and cash equivalents at beginning of period	108,887	5,718
Cash and cash equivalents at end of period	45,160	247,817
Eliminations
Condensed Consolidating Statements of Cash Flows
Net cash (used in) provided by operating activities	10,724	3,624
Cash flows from investing activities:
Capital expenditures	(10,955)	(4,658)
Equity investments in consolidated affiliates	710,674	1,120,038
Intercompany advances, net	308,028	808,923
Distributions from consolidated affiliates	(335,866)	(214,268)
Investment in intercompany notes receivable, net	45,300	(14,200)
Net cash flows used in investing activities	717,181	1,695,835
Cash flows from financing activities:
Payments related to intercompany financing, net	(44,136)	15,234
Contributions from Parent and affiliates	(710,674)	(1,120,038)
Payment of distributions	335,760	214,268
Intercompany advances, net	(308,855)	(808,923)
Net cash flows provided by financing activities	$ (727,905)	$ (1,699,459)

Supplemental Cash Flow Inform57

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Supplemental 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
Accrued property, plant and equipment	$ 166,900

Subsequent Event (Details)

Subsequent Event (Details) - Jul. 11, 2015 - MPLX - Partnership - Subsequent Event $ in Millions	USD ($)directorshares
Common Units | M & R
Subsequent Event
Partnership interest held by counterparty and subject to Voting Agreement (in units) | shares	7,352,691
Partnership interest held by VIE and subject to Voting Agreement (as a percent)	3.84%
Forecast
Subsequent Event
Contribution to be made by MPC to MPLX	$ 675
Common equity cash consideration	675
Cash termination fee	$ 625
Number of directors the Partnership is to identify for MPLX GP's board | director	2
Number of directors the Partnership is to identify for MPC's board | director	1
Period of Lock-Up Agreement	6 months
Forecast | Common Units
Subsequent Event
Unit conversion ratio	1.09
Forecast | Class B Units
Subsequent Event
Unit conversion ratio	1