8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): August 7, 2013

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization) 001-31239 (Commission File Number) 27-0005456 (I.R.S. Employer Identification Number)

1515 Arapahoe Street, Tower 1, Suite 1600, Denver CO 80202

(Address of principal executive offices)

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

Not Applicable.

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o    Written Communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-Commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-Commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

ITEM 2.02. Results of Operations and Financial Condition

On August 7, 2013, MarkWest Energy Partners, L.P. (the “Partnership”) announced its consolidated financial results for the three and six months ended June 30, 2013.  A copy of the Partnership’s earnings release is furnished as Exhibit 99.1 to this Current Report on Form 8-K.

This information shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

The earnings release furnished with this Current Report on Form 8-K utilizes the Non-GAAP financial measures of Distributable Cash Flow (“DCF”), Adjusted EBITDA, and Operating Income before Items Not Allocated to Segments.  In general, we define DCF as net income (loss) adjusted for (i) depreciation, amortization, impairment, and other non-cash expense; (ii) amortization of deferred financing costs and discount; (iii) loss on redemption of debt net of current tax benefit; (iv) non-cash (earnings) loss from unconsolidated affiliates; (v) distributions from (contributions to) unconsolidated affiliates (net of affiliate growth capital expenditures); (vi) non-cash compensation expense; (vii) non-cash derivative activity; (viii) losses (gains) on the disposal of property, plant, and equipment (PP&E) and unconsolidated affiliates; (ix) provision for deferred income taxes; (x) cash adjustments for non-controlling interest in consolidated subsidiaries; (xi) revenue deferral adjustment; (xii) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period; and (xiii) maintenance capital expenditures net of joint venture partner contributions. We define Adjusted EBITDA as net income (loss) adjusted for (i) depreciation, amortization, impairment, and other non-cash expense; (ii) interest expense; (iii) amortization of deferred financing costs; (iv) loss on redemption of debt; (v) losses (gains) on the disposal of PP&E and unconsolidated affiliates; (vi) non-cash derivative activity; (vii) non-cash compensation expense; (viii) provision for income taxes; (ix) adjustments for cash flow from unconsolidated affiliates; (x) adjustment related to non-guarantor, consolidated subsidiaries; and (xi) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period. We generally define Operating Income before Items Not Allocated to Segments as (i) revenue, excluding derivative gains and losses and adjusted for certain revenue deferral adjustments less; (ii) purchased product costs, excluding derivative gains and losses less; (iii) facility expenses, adjusted for certain non-cash items not allocated to segments and certain interest payments allocable to the segments less; ( iv) the portion allocable to non-controlling interests.

DCF is a financial performance measure used by management as a key component in the determination of cash distributions paid to unitholders.  We believe distributable cash flow is an important financial measure for unitholders as an indicator of cash return on investment and to evaluate whether the Partnership is generating sufficient cash flow to support quarterly distributions.  In addition, DCF is commonly used by the investment community because the market value of publicly traded partnerships is based, in part, on distributable cash flow and cash distributions paid to unitholders.

Adjusted EBITDA is a financial performance measure used by management, industry analysts, investors, lenders, and rating agencies to assess the financial performance and operating results of the Partnership’s ongoing business operations.  Additionally, we believe Adjusted EBITDA provides useful information to investors for trending, analyzing, and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures.

Operating Income before Items Not Allocable to Segments is a financial performance measure used by management to evaluate the performance of the operating segments in order to make decisions and allocate resources.

Cautionary Statements

This filing includes “forward-looking statements.”  All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements.  Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties.  Although we believe that the expectations reflected in the forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct.  The forward-looking statements involve risks and uncertainties that affect our operations, financial performance, and other factors as discussed in our filings with the Securities and Exchange Commission.  Among the factors that could cause results to differ materially are those risks discussed in the periodic reports we file with the SEC, including our Annual Report on Form 10-K for the year ended December

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31, 2012 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013.  You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading “Risk Factors.”  We do not undertake any duty to update any forward-looking statement except as required by law.

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ITEM 9.01.  Financial Statements and Exhibits.

(d)   Exhibits.

Exhibit No.	Description of Exhibit
99.1	Press release dated August 7, 2013, reporting 2013 2nd quarter financial results.

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SIGNATURE

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

	MARKWEST ENERGY PARTNERS, L.P.
	(Registrant)
	By:	MarkWest Energy GP, L.L.C.,
		Its General Partner
Date: August 7, 2013	By:	/s/ NANCY K. BUESE
		Nancy K. Buese Senior Vice President and Chief Financial Officer

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EX-99.1

Exhibit 99.1

MarkWest Energy Partners, L.P.	Contact:	Frank Semple, Chairman, President & CEO
1515 Arapahoe Street		Nancy Buese, Executive VP and CFO
Tower 1, Suite 1600		Josh Hallenbeck, VP of Finance & Treasurer
Denver, Colorado 80202	Phone:	(866) 858-0482
	E-mail:	investorrelations@markwest.com

MarkWest Energy Partners Reports Record Second Quarter Results and Announces Plans to form a Joint Venture with Kinder Morgan to Support Northern Ohio Rich-Gas Development and NGL Pipeline to Gulf Coast

·MarkWest Utica EMG announced plans to form a Joint Venture with Kinder Morgan to support northern Ohio rich-gas processing, an NGL pipeline to the Gulf Coast, and additional Gulf Coast fractionation facilities.

·Placed into service three processing facilities with combined capacity of 525 MMcf/d.

·Commenced operations of the first large-scale de-ethanization facility in the Northeast, which is producing purity ethane for delivery initially to Mariner West and ultimately to all planned ethane projects including ATEX and Mariner East.

·Announced expansion of Mobley processing complex by 200 MMcf/d to support EQT and other producers, bringing total expected capacity in the Marcellus Shale to nearly 3.6 billion cubic feet per day.

·Executed agreements with Antero Resources to expand the Seneca processing complex by 200 MMcf/d, bringing total capacity in the Utica Shale to over 900 MMcf/d by the third quarter of 2014.

·Announced four additional fractionation projects, which will increase total fractionation capacity in the Marcellus and Utica Shales by 96,000 to 332,000 barrels per day by the first quarter of 2015.

·The Partnership has 23 major processing and fractionation currently under construction.

·Fee-based net operating margin increased from 50 percent to 61 percent when compared to the second quarter of 2012.

DENVER—August 7, 2013—MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported record quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $128.4 million for the three months ended June 30, 2013, and $238.2 million for the six months ended June 30, 2013.  DCF for the three months ended June 30, 2013 represents 108 percent coverage of the second quarter distribution of $118.4 million or $0.84 per common unit, which will be paid to unitholders on August 14, 2013. The second quarter 2013 distribution represents an increase of $0.01 per common unit or 1.2 percent over the first quarter 2013 distribution and an increase of $0.04 per common unit or 5.0 percent compared to the second quarter 2012 distribution.  As a Master Limited Partnership, cash distributions to common unitholders are largely determined based on DCF.  A reconciliation of DCF to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported Adjusted EBITDA for the three and six months ended June 30, 2013, of $156.1 million and $296.5 million, respectively, as compared to $121.9 million and $275.0 million for the three and six months ended June 30, 2012.  The Partnership believes the presentation of Adjusted EBITDA provides useful information because it is commonly used by investors in Master

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Limited Partnerships to assess financial performance and operating results of ongoing business operations.  A reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported income before provision for income tax for the three and six months ended June 30, 2013, of $101.8 million and $87.2 million, respectively.  Income before provision for income tax includes non-cash gains associated with the change in fair value of derivative instruments of $37.3 million and $46.3 million for the three and six months ended June 30, 2013, a gain of $38.2 million related to the divestiture of gathering assets in the Marcellus Shale for the three months ended June 30, 2013 and a loss associated with the redemption of debt of $38.5 million for the six months ended June 30, 2013.  Excluding these items, income before provision for income tax for the three and six months ended June 30, 2013 would have been $26.3 million and $41.2 million, respectively.

“Our full-service midstream model and commitment to delivering exceptional customer service continues to deliver record volumes and financial performance,” said Frank Semple, Chairman, President and Chief Executive Officer. “We are excited to announce new strategic opportunities and growth projects throughout our core operating areas, which continue to support the ongoing success of our producer customers.”

BUSINESS HIGHLIGHTS

Liberty:

·In May 2013, the Partnership commenced operations of Majorsville III, a 200 million cubic feet per day (MMcf/d) processing facility in Marshall County, West Virginia.  Majorsville III is supported by long-term, fee-based agreements with Consol Energy, Inc. (NYSE: CNX) (CNX) and Noble Energy, Inc. (NYSE: NBL).  The facility will also provide additional processing capacity to Range Resources Corporation (NYSE: RRC) (Range), Chesapeake Energy Corporation (NYSE: CHK) (Chesapeake) and other producers prior to the completion of subsequent facilities.  The total processing capacity of the Majorsville complex has increased to 470 MMcf/d.

·In May 2013, the Partnership commenced operations of Sherwood II, a 200 MMcf/d processing facility in Doddridge County, West Virginia.  Sherwood II is supported by long-term, fee-based agreements with Antero Resources (Antero).  The total processing capacity at the Sherwood complex has increased to 400 MMcf/d.

·In June 2013, the Partnership closed on the sale of a non-strategic, high-pressure gas gathering system in Doddridge County, West Virginia to Summit Midstream Partners, LP (NYSE: SMLP) for $207.9 million in cash, net of fees.  Rich-gas gathered by this system is supported by a long-term, fee-based contract with an affiliate of Antero, and is dedicated to the Partnership for processing at the Sherwood complex.

·In July 2013, the Partnership commenced operations of the Houston De-ethanizer, a 38,000 barrel per day (Bbl/d) fractionator that is producing purity ethane from Marcellus rich-gas production. The Houston De-ethanizer will initially support Mariner West, a joint project with Sunoco Logistics Partners, L.P. (NYSE: SXL) and in the future will support all the planned ethane takeaway pipeline projects.

·Today, the Partnership is announcing an expansion of the Mobley Complex in Wetzel County, West Virginia to support EQT Corporation (EQT) and other producers’ rich-gas development.  EQT has requested 145 MMcf/d of additional priority capacity at the Mobley complex.  To

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support the increase in priority capacity, MarkWest will construct Mobley IV, a new 200 MMcf/d processing facility that is scheduled to begin operations by the first quarter of 2015.  Upon completion of this facility, Mobley’s processing capacity will be 720 MMcf/d.

·The Partnership is also announcing the development of additional fractionation facilities to support producers’ growing rich-gas production in the Marcellus Shale. By the first quarter of 2014, the Partnership will install de-ethanization and de-propanization units totaling 20,000 Bbl/d of capacity at the Keystone complex in Butler County, Pennsylvania. In addition, the Partnership will install a 38,000 Bbl/d de-ethanization facility at the Sherwood complex in Doddridge County, West Virginia, which is expected to be operational during the first quarter of 2015.

Utica:

·In May 2013, MarkWest Utica EMG executed definitive agreements with CNX and two additional producers to provide processing, fractionation, and marketing services in the Utica Shale.

·In May 2013, MarkWest Utica EMG commenced operations of Cadiz I, a 125 MMcf/d cryogenic processing facility in Harrison County, Ohio.  Cadiz I is supported by fee-based agreements with Gulfport Energy Corporation (NASDAQ: GPOR), Antero and other producers.

·In June 2013, MarkWest Utica EMG executed definitive agreements with Antero for the development of Seneca III, a 200 MMcf/d processing facility in Noble County, Ohio. Seneca III is scheduled to be operational during the second quarter of 2014 and will support rich-gas production from Antero and other producers in the southern core area of the Utica Shale.

·Today, MarkWest Utica EMG is announcing installation of a 38,000 Bbl/d de-ethanization facility at the Seneca complex, which is expected to be operational as soon as the fourth quarter of 2014.

·Today, MarkWest Utica EMG announced plans to form a Joint Venture (JV) with Kinder Morgan Energy Partners, LP (NYSE: KMP) (Kinder Morgan) to pursue three critical new projects to support producers in the Utica and Marcellus Shales:

·Under the first joint project, Kinder Morgan and MarkWest Utica EMG would develop a processing complex to be constructed on Kinder Morgan’s existing 220-acre site in Tuscarawas County, Ohio (JV processing complex) with an initial processing capacity of 200 MMcf/d, expandable to 400 MMcf/d of processing capacity. In addition, Kinder Morgan would convert a 65-mile segment of its existing 26-inch Tennessee Gas Pipeline into rich-gas gathering service.  MarkWest Utica EMG would also construct additional rich-gas and NGL pipelines to connect the complex with its large-scale full-service midstream infrastructure.  This project would serve new customers in Carroll, Columbiana, Mahoning and Trumbull counties in northern Ohio.  The JV would own the processing complex on a 50-50 basis.

·The second joint project with Kinder Morgan would involve the development of a 200,000 Bbl/d C2+ NGL pipeline originating at the JV processing complex to Gulf Coast fractionation facilities. This would be accomplished through the conversion of over 900 miles of existing Kinder Morgan pipeline assets and the construction of approximately 200 miles of additional pipeline to connect to Gulf Coast liquids and fractionation infrastructure.  The NGL pipeline would be expandable to 400,000 Bbl/d.

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Subject to sufficient shipper commitments, permitting and all related regulatory approvals, the pipeline would be operational during the fourth quarter of 2015.  The Partnership and MarkWest Utica EMG would utilize their extensive NGL pipeline network to deliver NGLs from the Marcellus and Utica to the new NGL pipeline.  By converting over 900 miles of existing pipeline and utilizing the Partnership and MarkWest Utica EMG’s existing NGL network, the JV’s NGL pipeline solution is best positioned to provide a cost effective outlet from the Utica and Marcellus Shale plays to Gulf Coast area markets.  Kinder Morgan would own at least 75 percent of the NGL pipeline and MarkWest Utica EMG would have the option to invest up to 25 percent.

·The third joint project with Kinder Morgan would involve the development of new fractionation facilities, as well as utilizing third-party fractionation facilities, throughout the Gulf Coast.

Southwest:

·In May 2013, the Partnership acquired midstream assets in the Texas Panhandle and Western Oklahoma from a wholly owned subsidiary of Chesapeake for consideration of $225.2 million in cash (Granite Wash Acquisition). In conjunction with the acquisition, the Partnership executed long-term, fee-based agreements with Chesapeake for gas gathering and processing services. As part of the fee-based gas processing agreement, Chesapeake has dedicated to the Partnership approximately 130,000 acres throughout the Anadarko Basin.

·In May 2013, the Partnership executed a long-term fee-based agreement with Newfield Exploration (NYSE: NFX) (Newfield) to develop rich-gas gathering facilities in the Eagle Ford Shale. The Partnership will construct gathering pipelines, field compression, and liquids storage to support production from Newfield’s West Asherton project in Dimmit County, Texas.

Capital Markets

·During the second quarter of 2013, the Partnership offered 3.8 million units and received net proceeds of approximately $244.5 million under the continuous offering program that was launched in the fourth quarter of 2012.  The Partnership completed the $600 million program in July 2013.

FINANCIAL RESULTS

Balance Sheet

·As of June 30, 2013, the Partnership had $278.9 million of cash and cash equivalents in wholly owned subsidiaries and $1.19 billion remaining capacity under its $1.2 billion revolving credit facility after consideration of $11.3 million of outstanding letters of credit.

Operating Results

·Operating income before items not allocated to segments for the three months ended June 30, 2013, was $177.5 million, an increase of $32.8 million when compared to segment operating income of $144.7 million over the same period in 2012.  This increase was primarily attributable to higher processing volumes, offset by lower commodity prices compared to the prior year quarter.  Processed volumes continued to remain strong, growing approximately 53 percent when compared to the second quarter of 2012, primarily due to the Partnership’s Liberty Segment and East Texas operations.

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A reconciliation of operating income before items not allocated to segments to income before provision for income tax, the most directly comparable GAAP financial measure, is provided within the financial tables of this press release.

·Operating income before items not allocated to segments does not include gains (losses) on commodity derivative instruments.  Realized gains (losses) on commodity derivative instruments were $2.0 million in the second quarter of 2013 and ($5.0) million in the second quarter of 2012.

Capital Expenditures

·For the three months ended June 30, 2013, the Partnership’s portion of capital expenditures was $443.0 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership’s DCF forecast remains in a range of $500 million to $540 million based on its current forecast of operational volumes and prices for crude oil, natural gas and natural gas liquids; and derivative instruments currently outstanding.  A commodity price sensitivity analysis for forecasted 2013 DCF is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2013 is unchanged and remains in a range of $1.5 billion to $1.8 billion.  These expenditures do not include the Granite Wash Acquisition or the divestiture of the high-pressure gathering system in the Marcellus Shale.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, August 8, 2013, at 12:00 p.m. Eastern Time to review its second quarter 2013 financial results. Interested parties can participate in the call by dialing (800) 475-0218 (passcode “MarkWest”) approximately ten minutes prior to the scheduled start time.  To access the webcast, please visit the Investor Relations section of the Partnership’s website at www.markwest.com. A replay of the conference call will be available on the MarkWest website or by dialing (866) 454-1418 (no passcode required).

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

This press release includes “forward-looking statements.”  All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. Although MarkWest believes that the expectations reflected in the forward-looking statements are reasonable, MarkWest can give no assurance that such expectations will prove to be correct. The forward-looking statements involve risks and uncertainties that affect operations, financial performance, and other factors as discussed in filings with the Securities and Exchange Commission (SEC).  Among the factors that could cause results to differ materially are those risks discussed in the periodic reports filed with the SEC, including MarkWest’s Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013. You are urged to carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading “Risk Factors.”  MarkWest does not undertake any duty to update any forward-looking statement except as required by law.

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MarkWest Energy Partners, L.P.

Distributable Cash Flow Sensitivity Analysis

(unaudited, in millions)

MarkWest periodically estimates the effect on DCF resulting from its commodity risk management program, changes in crude oil and natural gas prices, and the ratio of NGL prices to crude oil.  The table below reflects MarkWest’s estimate of the range of DCF for 2013 and forecasted crude oil and natural gas prices for 2013.  The analysis assumes various combinations of crude oil and natural gas prices as well as three NGL-to-crude oil ratio scenarios, including:

a.NGL-to-crude oil ratio at 50% for 2013.

b.NGL-to-crude oil ratio at 40% for 2013.

c.NGL-to-crude oil ratio at 30% for 2013.

The analysis further assumes derivative instruments outstanding as of August 7, 2013, and production volumes estimated through December 31, 2013.  The range of stated hypothetical changes in commodity prices considers current and historic market performance.

Estimated Range of 2013 DCF

Crude Oil Price		NGL-to-Crude	Natural Gas Price (Henry Hub)
(WTI)		Oil ratio (1)	$3.00		$3.50		$4.00		$4.50		$5.00
$	120	50% of WTI	$	548	$	546	$	543	$	541	$	539
		40% of WTI	$	518	$	516	$	514	$	512	$	509
		30% of WTI	$	490	$	488	$	486	$	483	$	481
$	110	50% of WTI	$	540	$	538	$	535	$	533	$	531
		40% of WTI	$	513	$	511	$	508	$	506	$	504
		30% of WTI	$	486	$	484	$	482	$	479	$	477
$	100	50% of WTI	$	530	$	528	$	526	$	524	$	521
		40% of WTI	$	506	$	504	$	502	$	499	$	497
		30% of WTI	$	481	$	478	$	476	$	474	$	472
$	90	50% of WTI	$	519	$	517	$	515	$	512	$	510
		40% of WTI	$	497	$	495	$	493	$	491	$	488
		30% of WTI	$	474	$	472	$	470	$	468	$	465
$	80	50% of WTI	$	509	$	507	$	505	$	503	$	500
		40% of WTI	$	489	$	486	$	484	$	482	$	480
		30% of WTI	$	470	$	467	$	465	$	462	$	459

(1)The composition is based on MarkWest’s average projected barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%.

The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions MarkWest management may take to mitigate exposure to changes.  Nor does the table consider the effects that such hypothetical adverse changes may have on overall economic activity.  Historical prices and ratios of NGL-to-crude oil do not guarantee future results.

Although MarkWest believes the expectations reflected in this analysis are reasonable, MarkWest can give no assurance that such expectations will prove to be correct and readers are cautioned that projected performance, results, or distributions may not be achieved.  Actual changes in market prices, and the ratio between crude oil and NGL prices, may differ from the assumptions utilized in the analysis.  Actual results, performance, distributions, volumes, events, or transactions could vary significantly from those expressed, considered, or implied in this analysis.  All results, performance, distributions, volumes, events, or transactions are subject to a number of uncertainties and risks. Those uncertainties and risks may not be factored into or accounted for in this analysis.  Readers are urged to carefully review and consider the cautionary statements and disclosures made in MarkWest’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”

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MarkWest Energy Partners, L.P.

Financial Statistics

(unaudited, in thousands, except per unit data)

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Statement of Operations Data
Revenue:
Revenue	$	395,421		$	306,755		$	768,879		$	702,733
Derivative gain	19,699			136,067			19,514			87,352
Total revenue	415,120			442,822			788,393			790,085
Operating expenses:
Purchased product costs	155,359			112,731			307,916			267,286
Derivative gain related to purchased product costs	(20,432		)	(51,579		)	(31,136		)	(32,779		)
Facility expenses	62,797			48,230			122,307			96,555
Derivative loss (gain) related to facility expenses	800			(1,146		)	468			(2,892		)
Selling, general and administrative expenses	25,499			21,700			50,741			46,748
Depreciation	71,562			41,336			139,579			80,918
Amortization of intangible assets	17,092			12,307			31,922			23,292
(Gain) loss on sale or disposal of property, plant and equipment	(37,736		)	1,342			(37,598		)	2,328
Accretion of asset retirement obligations	157			160			509			396
Total operating expenses	275,098			185,081			584,708			481,852
Income from operations	140,022			257,741			203,685			308,233
Other income (expense):
Gain from unconsolidated affiliates	430			1,109			665			1,548
Interest income	62			159			211			231
Interest expense	(36,955		)	(26,762		)	(75,291		)	(56,234		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,784		)	(1,245		)	(3,614		)	(2,515		)
Loss on redemption of debt	—			—			(38,455		)	—
Miscellaneous income, net	6			4			6			62
Income before provision for income tax	101,781			231,006			87,207			251,325
Provision for income tax (benefit) expense:
Current	(2,745		)	4,809			(8,159		)	20,150
Deferred	19,028			39,664			30,999			28,868
Total provision for income tax	16,283			44,473			22,840			49,018
Net income	85,498			186,533			64,367			202,307
Net (income) loss attributable to non-controlling interest	(1,799		)	375			3,874			621
Net income attributable to the Partnership’s unitholders	$	83,699		$	186,908		$	68,241		$	202,928
Net income attributable to the Partnership’s common unitholders per common unit:	.
Basic	$	0.63		$	1.74		$	0.52		$	1.98
Diluted	$	0.55		$	1.47		$	0.45		$	1.66
Weighted average number of outstanding common units:
Basic	131,227			106,825			129,928			101,833
Diluted	151,866			127,468			150,580			122,531
Cash Flow Data
Net cash flow provided by (used in):
Operating activities	$	92,553		$	45,708		$	177,596		$	253,621
Investing activities	$	(825,660	)	$	(834,145	)	$	(1,435,021	)	$	(1,087,114	)
Financing activities	$	435,634		$	562,860		$	1,266,223		$	841,534
Other Financial Data
Distributable cash flow	$	128,390		$	91,183		$	238,216		$	200,379
Adjusted EBITDA	$	156,110		$	121,853		$	296,541		$	274,991
	June 30, 2013			December 31, 2012
Balance Sheet Data
Working capital	$	(116,922	)	$	(84,512	)
Total assets	8,200,883			6,728,362
Total debt	3,022,704			2,523,051
Total equity	3,482,316			3,111,398

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MarkWest Energy Partners, L.P.

Operating Statistics

	Three months ended June 30,		Six months ended June 30,
	2013	2012	2013	2012
Liberty
Gathering system throughput (Mcf/d)	683,600	367,400	644,700	337,800
Natural gas processed (Mcf/d)	1,033,700	400,600	931,400	396,400
NGLs fractionated (Bbl/d)	48,900	19,800	43,000	19,900
NGL sales (gallons, in thousands) (1)	160,300	75,900	306,200	173,400
Utica (2)
Gathering system throughput (Mcf/d)	46,300	—	27,800	—
Natural gas processed (Mcf/d)	46,300	—	27,200	—
Northeast
Natural gas processed (Mcf/d)	296,400	328,200	299,500	324,900
NGLs fractionated (Bbl/d)	18,100	17,200	17,600	16,900
Keep-whole sales (gallons, in thousands)	27,100	23,700	60,000	73,300
Percent-of-proceeds sales (gallons, in thousands)	32,200	36,800	67,100	69,800
Total NGL sales (gallons, in thousands)	59,300	60,500	127,100	143,100
Crude oil transported for a fee (Bbl/d)	9,700	8,300	10,000	9,400
Southwest
East Texas gathering systems throughput (Mcf/d)	521,700	440,400	510,500	425,200
East Texas natural gas processed (Mcf/d)	377,600	268,300	358,600	255,400
East Texas NGL sales (gallons, in thousands)	90,200	68,000	170,700	131,400
Western Oklahoma gathering system throughput (Mcf/d) (3)	220,000	252,200	211,400	257,100
Western Oklahoma natural gas processed (Mcf/d)	189,900	218,900	188,100	211,400
Western Oklahoma NGL sales (gallons, in thousands)	42,900	61,700	97,700	119,000
Southeast Oklahoma gathering system throughput (Mcf/d)	473,300	503,300	467,300	502,200
Southeast Oklahoma natural gas processed (Mcf/d) (4)	160,400	119,600	155,800	110,700
Southeast Oklahoma NGL sales (gallons, in thousands)	54,000	41,300	93,300	74,300
Other Southwest gathering system throughput (Mcf/d) (5)	39,900	26,700	30,300	25,600
Gulf Coast refinery off-gas processed (Mcf/d)	117,700	115,800	106,600	118,000
Gulf Coast liquids fractionated (Bbl/d)	22,100	21,700	19,700	22,500
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands)	84,600	83,000	149,700	172,300

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

(2)   Utica operations began in August 2012.

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

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

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

8

MarkWest Energy Partners, L.P.

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure

Operating Income before Items not Allocated to Segments

(unaudited, in thousands)

	Liberty		Utica			Northeast		Southwest		Total
Three months ended June 30, 2013
Segment revenue	$	120,057	$	3,594		$	45,365	$	227,842	$	396,858
Operating expenses:
Purchased product costs	16,993		—			15,126		123,240		155,359
Facility expenses	22,272		6,412			6,655		29,778		65,117
Total operating expenses before items not allocated to segments	39,265		6,412			21,781		153,018		220,476
Portion of operating (loss) income attributable to non-controlling interests	—		(1,143		)	—		53		(1,090		)
Operating income (loss) before items not allocated to segments	$	80,792	$	(1,675	)	$	23,584	$	74,771	$	177,472

	Liberty		Utica			Northeast		Southwest		Total
Three months ended June 30, 2012
Segment revenue	$	59,477	$	—		$	42,051	$	206,551	$	308,079
Operating expenses:
Purchased product costs	8,018		—			12,921		91,792		112,731
Facility expenses	13,364		283			4,932		32,156		50,735
Total operating expenses before items not allocated to segments	21,382		283			17,853		123,948		163,466
Portion of operating (loss) income attributable to non-controlling interests	—		(113		)	—		28		(85		)
Operating income (loss) before items not allocated to segments	$	38,095	$	(170	)	$	24,198	$	82,575	$	144,698

	Three months ended June 30,
	2013			2012
Operating income before items not allocated to segments	$	177,472		$	144,698
Portion of operating (loss) income attributable to non-controlling interests	(1,090		)	(85		)
Derivative gain not allocated to segments	39,331			188,792
Revenue deferral adjustment and other	(1,437		)	(1,324		)
Compensation expense included in facility expenses not allocated to segments	(368		)	(183		)
Facility expenses adjustments	2,688			2,688
Selling, general and administrative expenses	(25,499		)	(21,700		)
Depreciation	(71,562		)	(41,336		)
Amortization of intangible assets	(17,092		)	(12,307		)
Gain (loss) on disposal of property, plant and equipment	37,736			(1,342		)
Accretion of asset retirement obligations	(157		)	(160		)
Income from operations	140,022			257,741
Other income (expense):
Earnings from unconsolidated affiliate	430			1,109
Interest income	62			159
Interest expense	(36,955		)	(26,762		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,784		)	(1,245		)
Miscellaneous income, net	6			4
Income before provision for income tax	$	101,781		$	231,006

9

MarkWest Energy Partners, L.P.

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure

Operating Income before Items not Allocated to Segments

(unaudited, in thousands)

	Liberty		Utica			Northeast		Southwest		Total
Six months ended June 30, 2013
Segment revenue	$	228,554	$	4,217		$	102,701	$	436,208	$	771,680
Operating expenses:
Purchased product costs	35,786		—			34,788		237,342		307,916
Facility expenses	44,908		10,374			13,179		58,468		126,929
Total operating expenses before items not allocated to segments	80,694		10,374			47,967		295,810		434,845
Portion of operating (loss) income attributable to non-controlling interests	—		(2,482		)	—		117		(2,365		)
Operating income (loss) before items not allocated to segments	$	147,860	$	(3,675	)	$	54,734	$	140,281	$	339,200

	Liberty		Utica			Northeast		Southwest		Total
Six months ended June 30, 2012
Segment revenue	$	135,054	$	—		$	128,969	$	441,927	$	705,950
Operating expenses:
Purchased product costs	32,653		—			38,608		196,025		267,286
Facility expenses	25,611		283			11,310		64,094		101,298
Total operating expenses before items not allocated to segments	58,264		283			49,918		260,119		368,584
Portion of operating (loss) income attributable to non-controlling interests	—		(113		)	—		31		(82		)
Operating income (loss) before items not allocated to segments	$	76,790	$	(170	)	$	79,051	$	181,777	$	337,448

	Six months ended June 30,
	2013			2012
Operating income before items not allocated to segments	$	339,200		$	337,448
Portion of operating (loss) income attributable to non-controlling interests	(2,365		)	(82		)
Derivative gain not allocated to segments	50,182			123,023
Revenue deferral adjustment and other	(2,801		)	(3,217		)
Compensation expense included in facility expenses not allocated to segments	(754		)	(633		)
Facility expenses adjustments	5,376			5,376
Selling, general and administrative expenses	(50,741		)	(46,748		)
Depreciation	(139,579		)	(80,918		)
Amortization of intangible assets	(31,922		)	(23,292		)
Gain (loss) on disposal of property, plant and equipment	37,598			(2,328		)
Accretion of asset retirement obligations	(509		)	(396		)
Income from operations	203,685			308,233
Other income (expense):
Earnings from unconsolidated affiliate	665			1,548
Interest income	211			231
Interest expense	(75,291		)	(56,234		)
Amortization of deferred financing costs and discount (a component of interest expense)	(3,614		)	(2,515		)
Loss on redemption of debt	(38,455		)	—
Miscellaneous income, net	6			62
Income before provision for income tax	$	87,207		$	251,325

10

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure

Distributable Cash Flow

(unaudited, in thousands)

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Net income	$	85,498		$	186,533		$	64,367		$	202,307
Depreciation, amortization and other non-cash operating expenses	88,889			53,881			172,166			104,762
(Gain) loss on sale and or disposal of assets, net of tax benefit	(34,689		)	1,342			(34,551		)	2,328
Loss on redemption of debt, net of tax benefit	—			—			36,178			—
Amortization of deferred financing costs and discount	1,784			1,245			3,614			2,515
Non-cash earnings from unconsolidated affiliate	(430		)	(1,109		)	(665		)	(1,548		)
Distributions from unconsolidated affiliate	1,962			1,774			2,728			4,566
Non-cash compensation expense	1,157			2,580			3,541			5,290
Non-cash derivative activity	(37,287		)	(193,744		)	(46,320		)	(145,527		)
Provision for income tax - deferred	19,028			39,664			30,999			28,868
Cash adjustment for non-controlling interest of consolidated subsidiaries	1,720			364			3,489			604
Revenue deferral adjustment	1,645			1,700			3,410			3,968
Other	2,827			647			4,865			2,235
Maintenance capital expenditures, net of joint venture partner contributions	(3,714		)	(3,694		)	(5,605		)	(9,989		)
Distributable cash flow	$	128,390		$	91,183		$	238,216		$	200,379
Maintenance capital expenditures	$	3,714		$	3,694		$	5,605		$	9,989
Growth capital expenditures	799,812			323,745			1,429,479			570,991
Total capital expenditures	803,526			327,439			1,435,084			580,980
Acquisitions, net of cash acquired	225,210			506,797			225,210			506,797
Total capital expenditures and acquisitions	1,028,736			834,236			1,660,294			1,087,777
Joint venture partner contributions	(360,499		)	—			(625,819		)	—
Total capital expenditures and acquisitions, net	$	668,237		$	834,236		$	1,034,475		$	1,087,777
Distributable cash flow	$	128,390		$	91,183		$	238,216		$	200,379
Maintenance capital expenditures, net of joint venture partner contributions	3,714			3,694			5,605			9,989
Changes in receivables and other assets	(68,610		)	54,300			(67,501		)	111,955
Changes in accounts payable, accrued liabilities and other long-term liabilities	37,661			(100,434		)	10,053			(65,190		)
Cash adjustment for non-controlling interest of consolidated subsidiaries	(1,720		)	(364		)	(3,489		)	(604		)
Other	(6,882		)	(2,671		)	(5,288		)	(2,908		)
Net cash provided by operating activities	$	92,553		$	45,708		$	177,596		$	253,621

11

MarkWest Energy Partners, L.P.

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure

Adjusted EBITDA

(unaudited, in thousands)

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
Net income	$	85,498		$	186,533		$	64,367		$	202,307
Non-cash compensation expense	1,157			2,580			3,541			5,290
Non-cash derivative activity	(37,287		)	(193,744		)	(46,320		)	(145,527		)
Interest expense (1)	36,610			25,826			74,632			54,378
Depreciation, amortization and other non-cash operating expenses	88,889			53,881			172,166			104,762
(Gain) loss on sale and or disposal of assets	(37,736		)	1,342			(37,598		)	2,328
Loss on redemption of debt	—			—			38,455			—
Provision for income tax	16,283			44,473			22,840			49,018
Adjustment for cash flow from unconsolidated affiliate	1,532			665			2,063			3,018
Other	1,164			297			2,395			(583		)
Adjusted EBITDA	$	156,110		$	121,853		$	296,541		$	274,991

(1) Includes amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.

12