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): February 27, 2014 (February 26, 2014)

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):

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

oSoliciting 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 February 26, 2014, MarkWest Energy Partners, L.P. (the “Partnership”) announced its consolidated financial results for the three months and year ended December 31, 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, and other non-cash operating expenses; (ii) amortization of deferred financing costs and discount; (iii) loss on redemption of debt net of tax benefit; (iv) non-cash (earnings) loss from unconsolidated affiliates; (v) distributions from unconsolidated affiliates ; (vi) non-cash compensation expense; (vii) non-cash derivative activity; (viii) loss (gain) on the sale and or disposal of assets, net of tax; (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 and proceeds from trade-in of property plant and equipment. We define Adjusted EBITDA as net income (loss) adjusted for (i) depreciation, amortization,  and other non-cash operating expenses; (ii) interest expense; (iii) amortization of deferred financing costs; (iv) loss on redemption of debt; (v) losses (gains) on the sale and or  disposal of assets; (vi) non-cash derivative activity; (vii) non-cash compensation expense; (viii) provision for income taxes; (ix) adjustments for cash flow from unconsolidated affiliates; and (x)  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.

ITEM 7.01. Regulation FD

In accordance with General Instruction B.2 of Form 8-K, the following information in this Current Report on Form 8-K (including the exhibit) is furnished pursuant to Item 7.01 and shall not be deemed to be “filed” for the purpose of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.  This Current Report will not be deemed an admission as to the materiality of any information in the report that is required to be disclosed solely by Regulation FD.

On February 27, 2014, MarkWest Energy Partners, L.P. (the “Partnership”) posted on its website an earnings call presentation that will be used in the earnings call.  The information included with this Current Report as

2

Exhibit 99.1 includes graphic images or slides that will be made available at upcoming presentations.  These slides are available for viewing at our website, www.markwest.com, although we reserve the right to discontinue that availability at any time.

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 31, 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.

3

ITEM 9.01.  Financial Statements and Exhibits.

(d)Exhibits.

Exhibit No.	Description of Exhibit
99.1	Press release dated February 26, 2014, reporting 2013 4th quarter and full year financial results.
99.2	Earnings call presentation on February 27, 2014

4

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: February 27, 2014	By:	/s/ NANCY K. BUESE
		Nancy K. Buese Executive Vice President and Chief Financial Officer

5

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 Fourth Quarter and Full Year Financial Results

·Increased total processing capacity in the Marcellus and Utica Shales to over 2.8 Bcf/d with the completion of five major gas processing facilities totaling 1 Bcf/d in the past five months

·Placed into service the Hopedale fractionation and marketing complex in the Utica Shale, increasing current fractionation capacity for propane and heavier purity products in the Northeast to over 140,000 Bbl/d

·Announced the development of 200 MMcf/d of additional processing capacity at the Seneca complex in the Utica Shale to support Antero Resources

·Placed into service the Buffalo Creek processing plant, a 200 MMcf/d cryogenic processing facility in the Anadarko Basin, that is supported by long-term fee-based agreements with Chesapeake Energy

·The Partnership has 19 major processing and fractionation facilities under construction in the Northeast

·Fee-based net operating margin increased from 53 percent to 65 percent when compared to the fourth quarter of 2012

DENVER—February 26, 2014—MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported quarterly cash available for distribution to common unitholders, or distributable cash flow (DCF), of $127.2 million for the three months ended December 31, 2013, and $483.4 million for the year ended December 31, 2013.  DCF for the three months and year ended December 31, 2013 represents distribution coverage of 94 percent and 99 percent, respectively.  The fourth quarter distribution of $135.9 million, or $0.86 per common unit, was paid to unitholders on February 14, 2014. The fourth quarter 2013 distribution represents an increase of $0.01 per common unit or 1.2 percent over the third quarter 2013 distribution and an increase of $0.04 per common unit or 4.9 percent compared to the fourth 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 of $155.5 million for the three months ended December 31, 2013 and $606.0M for the year ended December 31, 2013, as compared to $138.0 million and $528.5 million for the three months and year ended December 31, 2012.  The Partnership believes the presentation of Adjusted EBITDA provides useful information because it is commonly used by investors in Master Limited Partnerships to assess financial performance and operating results of ongoing business operations.  A reconciliation of Adjusted EBITDA to net income, the most

1

directly comparable GAAP financial measure, is provided within the financial tables of this press release.

The Partnership reported (loss) income before provision for income tax for the three months and year ended December 31, 2013, of $(3.8) million and $53.1 million, respectively.  (Loss) income before provision for income tax includes non-cash loss associated with the change in fair value of derivative instruments of $14.4 million and $15.6 million for the respective three months and year ended December 31, 2013, a gain of $0.8 million and $39.7 million related to the divestiture of gathering assets in the Marcellus Shale for the respective three months and year ended December 31, 2013, and a loss associated with the redemption of debt of $38.5 million for the year ended December 31, 2013.  Excluding these items, income before provision for income tax for the three months and year ended December 31, 2013 would have been $9.8 million and $67.5 million, respectively.

“We are very pleased to close 2013 with the completion of major infrastructure projects that are critical to the development of the Marcellus and Utica Shales,” stated Frank Semple, Chairman, President and Chief Executive Officer. “Our producers’ ongoing success and expanding development plans continue to provide us with exceptional future growth opportunities. We are committed to delivering another year of strong financial results, operational excellence and best of class customer service in many of America’s most exciting resource plays.”

BUSINESS HIGHLIGHTS

Marcellus:

·In November 2013, the Partnership announced an expansion of the Sherwood complex in Doddridge County, West Virginia to support Antero Resources Corporation’s (NYSE: AR) highly prospective rich-gas Marcellus Shale acreage. The Partnership will construct Sherwood V, a new 200 million cubic feet per day (MMcf/d) processing facility that is scheduled to begin operations in the third quarter of 2014.

·In November 2013, the Partnership completed Majorsville V, a 200 MMcf/d processing plant at the Majorsville complex in Marshall County, West Virginia. Majorsville V supports growing rich-gas production from Chesapeake Energy Corporation (NYSE: CHK), and Statoil ASA (NYSE: STO) and increases the total processing capacity of the complex to 670 MMcf/d.

·In November 2013, the Partnership completed Sherwood III, a 200 MMcf/d processing plant at the Sherwood complex. Sherwood III supports Antero Resources Corporation and increases the total processing capacity of the complex to 600 MMcf/d.

·In December 2013, the Partnership completed Mobley III, a 200 MMcf/d processing plant at the Mobley complex in Wetzel County, West Virginia. Mobley III supports rapidly growing rich-gas production from EQT Corporation (NYSE: EQT) and Magnum Hunter Resources Corporation (NYSE: MHR) and increases the total processing capacity of the complex to 520 MMcf/d.

·In December 2013, the Partnership completed the 38,000 barrels per day (Bbl/d) de-ethanization unit at the Majorsville complex. The new de-ethanizer doubles the Partnership’s total purity ethane production capacity in the Marcellus Shale to 76,000 Bbl/d and provides producers with the ability to consistently meet residue gas quality specifications and deliver downstream ethane pipeline commitments.

2

·In December 2013, the Partnership completed the Liberty Ethane Pipeline. The Liberty Ethane Pipeline transports purity ethane produced at the Majorsville complex to the Houston complex in Washington County, Pennsylvania. Once delivered to the Houston complex, the purity ethane has direct access to multiple, major ethane takeaway projects including, Mariner West and ATEX, which began operations in December, and Mariner East, which is scheduled to come online for ethane service in 2015.

·In February 2014, the Partnership announced the development of a 40,000 Bbl/d de-ethanization facility at the Mobley complex. The Mobley de-ethanizer will support purity ethane production for EQT Corporation, Magnum Hunter Resources Corporation and other producers. The new facility is scheduled to begin operations during the third quarter of 2015.

Utica:

·In November 2013, MarkWest Utica EMG commenced operations at the Seneca complex in Noble County, Ohio. The Seneca complex currently consists of two cryogenic processing plants totaling 400 MMcf/d of capacity and is supported by long-term fee-based agreements with Antero Resources Corporation, Gulfport Energy Corporation (NASDAQ: GPOR), Rex Energy Corporation (NASDAQ: REXX), PDC Energy (NASDAQ: PDCE) and others.

·In December 2013, the Partnership and The Energy & Minerals Group (EMG) executed definitive agreements with Gulfport Energy Corporation to provide condensate stabilization and logistics services in eastern Ohio. As part of these agreements, the Partnership and EMG formed Ohio Condensate Company, LLC, a new Joint Venture (JV) related to the development of industry-leading facilities and services to support the rapid growth of condensate production occurring in the Utica Shale. The JV will initially develop a 23,000 Bbl/d condensate stabilization facility in Harrison County, Ohio. The new facility is scheduled to commence operations in the third quarter of 2014 and will be co-located with condensate storage and logistics terminal, which will be constructed and operated by a subsidiary of Toledo International, Inc., Ohio-based Midwest Terminals.

·In January 2014, MarkWest Utica EMG and the Partnership completed construction and commenced operations of the jointly-owned Hopedale fractionation and marketing complex (Hopedale complex) in Harrison County, Ohio. The Hopedale complex consists of a 60,000 Bbl/d propane and heavier purity products (C3+) fractionator, over 230,000 barrels of purity product storage, a 24-bay rail car loading facility with slots to accommodate 200 rail cars, and truck loading and off loading facilities. The Hopedale complex is connected by NGL pipeline to MarkWest Utica EMG’s Cadiz processing complex in Harrison County, Ohio, to the Seneca processing complex in Noble County, Ohio and to its extensive NGL gathering network in the Marcellus Shale.

·In January 2014, the Partnership commenced operations of a NGL pipeline connecting the Hopedale fractionation and marketing complex to the Partnership’s industry-leading NGL infrastructure in the Marcellus Shale. By integrating two industry-leading midstream systems, the Partnership has expanded the fractionation capacity for its Marcellus producers.

·Today, MarkWest Utica EMG is announcing the expansion of the Seneca complex with a new 200 million cubic feet per day (MMcf/d) processing plant. The plant is anchored by a new agreement with Antero Resources Corporation supporting its expanding Utica development plans. The Seneca IV plant is scheduled to commence operations in the first quarter of 2015 and will expand total processing capacity of the complex to 800 MMcf/d.

3

Southwest:

·In February 2014, the Partnership announced the commencement of the 200 MMcf/d Buffalo Creek processing facility in Beckham County, Oklahoma, and associated gas gathering and compression assets in the Granite Wash. The new facility is supported by long-term fee-based agreements with Chesapeake Energy Corporation, which include a 130,000 acre dedication throughout the area.  The completion of the Buffalo Creek plant increases the Partnership’s total processing capacity in the Anadarko Basin to 435 MMcf/d at two major complexes.

Capital Markets

·During the fourth quarter of 2013, the Partnership offered 10.0 million units and received net proceeds of approximately $658.2 million under the $1 billion continuous offering program launched in the third quarter of 2013.

FINANCIAL RESULTS

Balance Sheet

·As of December 31, 2013, the Partnership had $80.0 million of cash and cash equivalents in wholly owned subsidiaries and $1.19 billion of 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 December 31, 2013, was $185.1 million, an increase of $23.1 million when compared to segment operating income of $162.0 million over the same period in 2012.  This increase was primarily attributable to higher processing volumes.  Processed volumes continued to increase in the fourth quarter of 2013, growing approximately 51 percent when compared to the fourth quarter of 2012, primarily due to the Partnership’s Marcellus and Southwest segments.  While the Partnership continued to increase its operating income and volumes, it experienced several operational constraints during the second half of 2013. Due to these considerations, operating income was approximately $12.0 million lower than expected for the three months ended December 31, 2013, and approximately $24.1 million for the year ended December 31, 2013.  The operational constraints included increased costs related to the transportation of producer natural gas liquids in excess of our fractionation capacity to third party fractionation facilities, delays related to the completion of Sunoco Logistics Partners’, L.P. (NYSE: SXL) Mariner West purity ethane pipeline and an NGL line break that took the Partnership’s Mobley complex offline and curtailed processing volumes at the Partnership’s Sherwood complex for approximately two months.  As of January 2014, all operational constraints have been resolved.

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 losses on commodity derivative instruments.  Realized losses on commodity derivative instruments were $8.7 million in the fourth quarter of 2013 and $2.1 million in the fourth quarter of 2012.

4

Capital Expenditures

·For the three months ended December 31, 2013, the Partnership’s portion of capital expenditures was $870.2 million.

2014 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2014, the Partnership forecasts DCF in a range of $600 million to $690 million based on its current forecast of operational volumes and prices for crude oil, natural gas, natural gas liquids and derivative instruments currently outstanding.  The Partnership has become less sensitive to changes in commodity prices as a result of fee-based income increasing significantly.  For the full year 2014, the Partnership estimates that operating income will be over 70 percent fee-based.  In addition, the Partnership has hedged approximately 60 percent of its forecasted 2014 NGL exposure on a volumetric basis, 90 percent of these with direct product hedges.  An updated sensitivity analysis for forecasted 2014 DCF based on changes in composite NGL prices and changes in volume assumptions is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2014 is forecasted in a range of $1.8 billion to $2.3 billion.  Maintenance capital is forecasted at approximately $25 million.

CONFERENCE CALL

The Partnership will host a conference call on Thursday, February 27, 2014, at 12:00 p.m. Eastern Time to review its fourth quarter and full year 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.  Prior to the conference call, the Partnership will post a fourth quarter earnings call presentation to its website.  To access the conference call and presentation, 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 Partnership’s website or by dialing (866) 448-4799 (no passcode required).

###

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, 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.

5

MarkWest Energy Partners, L.P.

Financial Statistics

(unaudited, in thousands, except per unit data)

	Three months ended December 31,						Twelve months ended December 31,
Statement of Operations Data	2013			2012			2013			2012
Revenue:
Revenue	$	467,372		$	363,570		$	1,687,085		$	1,383,279
Derivative (loss) gain	(13,834		)	5,583			(24,638		)	56,535
Total revenue	453,538			369,153			1,662,447			1,439,814
Operating expenses:
Purchased product costs	191,577			143,673			691,165			530,328
Derivative loss (gain) related to purchased product costs	9,165			7,174			(1,737		)	(13,962		)
Facility expenses	91,220			57,422			291,069			206,861
Derivative loss related to facility expenses	69			235			2,869			1,371
Selling, general and administrative expenses	24,161			24,973			101,549			93,444
Depreciation	83,982			55,778			299,884			183,250
Amortization of intangible assets	16,719			15,040			64,644			53,320
Loss (gain) on sale or disposal of property, plant and equipment	1,995			3,271			(33,763		)	6,254
Accretion of asset retirement obligations	155			137			824			672
Total operating expenses	419,043			307,703			1,416,504			1,061,538
Income from operations	34,495			61,450			245,943			378,276
Other (expense) income:
(Loss) earnings from unconsolidated affiliates	(139		)	74			1,422			2,328
Interest income	24			124			262			419
Interest expense	(37,671		)	(33,336		)	(151,851		)	(120,191		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,528		)	(1,658		)	(6,726		)	(5,601		)
Loss on redemption of debt	—			—			(38,455		)	—
Miscellaneous income (expense), net	1,009			(1		)	2,519			62
(Loss) income before provision for income tax	(3,810		)	26,653			53,114			255,293
Provision for income tax (benefit) expense:
Current	(705		)	(4,568		)	(11,208		)	(2,366		)
Deferred	790			1,298			23,877			40,694
Total provision for income tax	85			(3,270		)	12,669			38,328
Net (loss) income	(3,895		)	29,923			40,445			216,965
Net (loss) income attributable to non-controlling interest	(2,665		)	1,891			(2,368		)	3,437
Net (loss) income attributable to the Partnership’s unitholders	$	(6,560	)	$	31,814		$	38,077		$	220,402
Net (loss) income attributable to the Partnership’s common unitholders per common unit:
Basic	$	(0.05	)	$	0.26		$	0.26		$	1.98
Diluted	$	(0.05	)	$	0.22		$	0.24		$	1.69
Weighted average number of outstanding common units:
Basic	151,153			122,079			138,409			109,979
Diluted	151,153			142,720			160,443			130,648
Cash Flow Data
Net cash flow provided by (used in):
Operating activities	$	104,991		$	106,229		$	435,650		$	492,013
Investing activities	$	(876,255	)	$	(726,339	)	$	(3,062,562	)	$	(2,472,088	)
Financing activities	$	528,416		$	553,513		$	2,366,461		$	2,211,499
Other Financial Data
Distributable cash flow	$	127,242		$	111,774		$	483,355		$	417,086
Adjusted EBITDA	$	155,512		$	137,952		$	605,989		$	528,467

Balance Sheet Data	December 31, 2013			December 31, 2012
Working capital	$	(353,273	)	$	(84,512	)
Total assets	$	9,396,423		$	6,728,362
Total debt	$	3,023,071		$	2,523,051
Total equity	$	4,798,133		$	3,111,398

6

MarkWest Energy Partners, L.P.

Operating Statistics

	Three months ended December 31,		Twelve months ended December 31,
	2013	2012	2013	2012
Marcellus
Gathering system throughput (Mcf/d) (1)	580,700	587,600	549,500	425,000
Natural gas processed (Mcf/d)	1,401,700	696,000	1,101,900	496,400
NGLs fractionated (Bbl/d) (2)	56,700	31,100	47,600	24,900
NGL sales (gallons, in thousands) (3)	284,300	129,400	820,400	393,600
Utica (4)
Gathering system throughput (Mcf/d)	107,800	6,400	62,400	5,000
Natural gas processed (Mcf/d)	166,200	5,000	88,400	4,200
Northeast (5)
Natural gas processed (Mcf/d)	287,500	313,700	296,100	320,500
NGLs fractionated (Bbl/d) (6)	23,900	18,900	20,200	17,300
Keep-whole sales (gallons, in thousands)	24,900	35,100	117,500	131,600
Percent-of-proceeds sales (gallons, in thousands)	32,600	36,200	134,300	139,700
Total NGL sales (gallons, in thousands) (7)	57,500	71,300	251,800	271,300
Crude oil transported for a fee (Bbl/d)	9,500	9,900	9,700	9,300
Southwest
East Texas gathering systems throughput (Mcf/d)	501,100	477,600	504,000	450,000
East Texas natural gas processed (Mcf/d)	357,700	302,000	355,100	270,800
East Texas NGL sales (gallons, in thousands) (8)	85,100	76,500	334,400	275,800
Western Oklahoma gathering system throughput (Mcf/d) (9)	268,800	200,800	238,600	235,600
Western Oklahoma natural gas processed (Mcf/d)	215,000	193,800	202,600	206,500
Western Oklahoma NGL sales (gallons, in thousands)	77,000	44,500	239,200	214,400
Southeast Oklahoma gathering system throughput (Mcf/d)	405,100	463,100	443,700	487,900
Southeast Oklahoma natural gas processed (Mcf/d) (10)	146,700	137,000	153,800	121,800
Southeast Oklahoma NGL sales (gallons, in thousands)	22,300	42,400	159,600	163,300
Other Southwest gathering system throughput (Mcf/d) (11)	46,500	22,300	35,000	24,300
Gulf Coast refinery off-gas processed (Mcf/d)	83,400	113,600	103,400	118,400
Gulf Coast liquids fractionated (Bbl/d)	14,600	21,000	18,800	22,500
Gulf Coast NGL sales (gallons excluding hydrogen, in thousands)	56,300	81,000	288,800	345,300

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

(2)Amount includes all NGLs that were produced at the Marcellus processing facilities and fractionated into purity products at our Marcellus fractionation facility.  Excludes 7,300 and 0 barrels per day of ethane fractionated for the three months ended December 31, 2013 and 2012, respectively, and 300 and 0 barrels per day of ethane fractionated for the twelve months ended December 31, 2013 and 2012, respectively.

(3)Includes sale of all purity products fractionated at the Marcellus facilities and sale of all unfractionated NGLs. Also includes the sale of purity products fractionated and sold at the Siloam facilities on behalf of Marcellus customers.

(4)Utica operations began in August 2012. The volumes reported for 2012 are the average daily rate for the days of operation.

(5)Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants.

(6)Amount includes 8,200 and 1,400 barrels per day fractionated for the three months ended December 31, 2013 and 2012, respectively, and 5,200 and 400 barrels per day fractionated on behalf of Marcellus for the twelve months ended December 31, 2013 and 2012, respectively.

(7)Represents sales at the Siloam fractionator. The total sales exclude approximately 31,800,000 and 5,500,000 gallons sold by the Northeast on behalf of Marcellus for the three months ended December 31, 2013 and 2012, respectively, and approximately 59,700,000 and 6,500,000 gallons sold for the twelve months ended December 31, 2013 and 2012, respectively. These volumes are included as part of NGLs sold at Marcellus.

(8)Includes approximately 14,420,000 gallons produced in conjunction with take in kind contracts for the year ended December 31, 2013.

(9)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.

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

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

7

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)

Three months ended December 31, 2013	Marcellus		Utica			Northeast		Southwest			Total
Segment revenue	$	151,229	$	13,852		$	52,796	$	251,333		$	469,210
Operating expenses:
Purchased product costs	27,481		—			15,074		149,022			191,577
Facility expenses	34,252		14,849			7,887		36,085			93,073
Total operating expenses before items not allocated to segments	61,733		14,849			22,961		185,107			284,650
Portion of operating loss attributable to non-controlling interests	—		(418		)	—		(136		)	(554		)
Operating income (loss) before items not allocated to segments	$	89,496	$	(579	)	$	29,835	$	66,362		$	185,114

Three months ended December 31, 2012	Marcellus		Utica			Northeast		Southwest		Total
Segment revenue	$	106,106	$	426		$	56,862	$	201,637	$	365,031
Operating expenses:
Purchased product costs	25,168		—			18,740		99,765		143,673
Facility expenses	21,281		2,377			6,529		29,727		59,914
Total operating expenses before items not allocated to segments	46,449		2,377			25,269		129,492		203,587
Portion of operating (loss) income attributable to non-controlling interests	—		(619		)	—		78		(541		)
Operating income (loss) before items not allocated to segments	$	59,657	$	(1,332	)	$	31,593	$	72,067	$	161,985

	Three months ended December 31,
	2013			2012
Operating income before items not allocated to segments	$	185,114		$	161,985
Portion of operating loss attributable to non-controlling interests	(554		)	(541		)
Derivative loss not allocated to segments	(23,068		)	(1,826		)
Revenue deferral adjustment and other	(1,838		)	(1,461		)
Compensation expense included in facility expenses not allocated to segments	(834		)	(196		)
Facility expenses adjustments	2,687			2,687
Selling, general and administrative expenses	(24,161		)	(24,973		)
Depreciation	(83,982		)	(55,778		)
Amortization of intangible assets	(16,719		)	(15,040		)
Loss on disposal of property, plant and equipment	(1,995		)	(3,271		)
Accretion of asset retirement obligations	(155		)	(136		)
Income from operations	34,495			61,450
Other (expense) income:
(Loss) earnings from unconsolidated affiliates	(139		)	74
Interest income	24			124
Interest expense	(37,671		)	(33,336		)
Amortization of deferred financing costs and discount (a component of interest expense)	(1,528		)	(1,658		)
Miscellaneous income (expense), net	1,009			(1		)
(Loss) income before provision for income tax	$	(3,810	)	$	26,653

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)

Twelve months ended December 31, 2013	Marcellus		Utica			Northeast		Southwest		Total
Segment revenue	$	527,073	$	26,442		$	204,326	$	935,426	$	1,693,267
Operating expenses:
Purchased product costs	100,262		—			65,192		525,711		691,165
Facility expenses	108,781		35,081			28,425		127,112		299,399
Total operating expenses before items not allocated to segments	209,043		35,081			93,617		652,823		990,564
Portion of operating (loss) income attributable to non-controlling interests	—		(3,499		)	—		21		(3,478		)
Operating income (loss) before items not allocated to segments	$	318,030	$	(5,140	)	$	110,709	$	282,582	$	706,181

Twelve months ended December 31, 2012	Marcellus		Utica			Northeast		Southwest		Total
Segment revenue	$	319,867	$	571		$	225,818	$	842,958	$	1,389,214
Operating expenses:
Purchased product costs	74,024		—			68,402		387,902		530,328
Facility expenses	65,825		3,968			24,106		122,691		216,590
Total operating expenses before items not allocated to segments	139,849		3,968			92,508		510,593		746,918
Portion of operating (loss) income attributable to non-controlling interests	—		(1,359		)	—		176		(1,183		)
Operating income (loss) before items not allocated to segments	$	180,018	$	(2,038	)	$	133,310	$	332,189	$	643,479

	Twelve months ended December 31,
	2013			2012
Operating income before items not allocated to segments	$	706,181		$	643,479
Portion of operating loss attributable to non-controlling interests	(3,478		)	(1,183		)
Derivative (loss) gain not allocated to segments	(25,770		)	69,126
Revenue deferral adjustment and other	(6,182		)	(5,935		)
Compensation expense included in facility expenses not allocated to segments	(2,421		)	(1,022		)
Facility expenses adjustments	10,751			10,751
Selling, general and administrative expenses	(101,549		)	(93,444		)
Depreciation	(299,884		)	(183,250		)
Amortization of intangible assets	(64,644		)	(53,320		)
Gain (loss) on disposal of property, plant and equipment	33,763			(6,254		)
Accretion of asset retirement obligations	(824		)	(672		)
Income from operations	245,943			378,276
Other income (expense):
Earnings from unconsolidated affiliates	1,422			2,328
Interest income	262			419
Interest expense	(151,851		)	(120,191		)
Amortization of deferred financing costs and discount (a component of interest expense)	(6,726		)	(5,601		)
Loss on redemption of debt	(38,455		)	—
Miscellaneous income, net	2,519			62
Income before provision for income tax	$	53,114		$	255,293

9

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure

Distributable Cash Flow

(unaudited, in thousands)

	Three months ended December 31,						Twelve months ended December 31,
	2013			2012			2013			2012
Net (loss) income	$	(3,895	)	$	29,923		$	40,445		$	216,965
Depreciation, amortization and other non-cash operating expenses	100,934			71,032			365,664			237,554
Loss (gain) on sale and or disposal of assets, net of tax	2,051			3,271			(30,660		)	6,254
Loss on redemption of debt, net of tax benefit	—			—			36,178			—
Amortization of deferred financing costs and discount	1,528			1,658			6,726			5,601
Non-cash loss (earnings) from unconsolidated affiliates	139			(74		)	(1,422		)	(2,328		)
Distributions from unconsolidated affiliates	1,418			1,792			6,370			8,416
Non-cash compensation expense	2,358			1,977			7,822			8,247
Non-cash derivative activity	14,380			(312		)	15,602			(102,127		)
Provision for income tax - deferred	790			1,298			23,877			40,694
Cash adjustment for non-controlling interest of consolidated subsidiaries	1,449			908			6,121		#	2,299
Revenue deferral adjustment	2,049			1,837			7,213			7,441
Other	9,666			(58		)	17,419			3,372
Maintenance capital expenditures (1)	(5,625		)	(1,478		)	(18,000		)	(15,302		)
Distributable cash flow	$	127,242		$	111,774		$	483,355		$	417,086
Maintenance capital expenditures (1)	$	5,625		$	1,478		$	18,000		$	15,302
Growth capital expenditures	864,612			709,141			3,028,956			1,935,022
Total capital expenditures	870,237			710,619			3,046,956			1,950,324
Acquisitions, net of cash acquired (2)	(2,322		)	—			222,888			506,797
Total capital expenditures and acquisitions	867,915			710,619			3,269,844			2,457,121
Joint venture partner contributions	—			(178,018		)	(716,982		)	(233,018		)
Total capital expenditures and acquisitions, net	$	867,915		$	532,601		$	2,552,862		$	2,224,103
Distributable cash flow	$	127,242		$	111,774		$	483,355		$	417,086
Maintenance capital expenditures (1)	5,625			1,478			18,000			15,302
Changes in receivables and other assets	(59,131		)	(1,655		)	(133,601		)	24,641
Changes in accounts payable, accrued liabilities and other long-term liabilities	42,458			(3,740		)	91,015			41,728
Derivative instrument premium payments, net of amortization	—			—			—			—
Cash adjustment for non-controlling interest of consolidated subsidiaries	(1,449		)	(908		)	(6,121		)	(2,299		)
Other	(9,754		)	(720		)	(16,998		)	(4,445		)
Net cash provided by operating activities	$	104,991		$	106,229		$	435,650		$	492,013

(1) Net of joint venture partner contributions and proceeds from trade-in of property plant and equipment.

(2) On May 29, 2012, the Partnership acquired natural gas gathering and processing assets from Keystone, during the three months ended December 2013, we received $2.3 million related to a working capital adjustment.

10

MarkWest Energy Partners, L.P.

Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure

Adjusted EBITDA

(unaudited, in thousands)

	Three months ended December 31,						Twelve months ended December 31,
	2013			2012			2013			2012
Net (loss) income	$	(3,895	)	$	29,923		$	40,445		$	216,965
Non-cash compensation expense	2,358			1,977			7,822			8,247
Non-cash derivative activity	14,380			(312		)	15,602			(102,127		)
Interest expense (1)	37,096			32,838			150,084			117,098
Depreciation, amortization and other non-cash operating expenses	100,934			71,032			365,664			237,554
Loss (gain) on sale and or disposal of assets	1,995			3,271			(33,763		)	6,254
Loss on redemption of debt	—			—			38,455			—
Provision for income tax	85			(3,270		)	12,669			38,328
Adjustment for cash flow from unconsolidated affiliates	1,557			1,718			4,948			6,088
Other	1,002			775			4,063			60
Adjusted EBITDA	$	155,512		$	137,952		$	605,989		$	528,467

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

11

MarkWest Energy Partners, L.P.

Distributable Cash Flow Sensitivity Analysis

(unaudited, in millions)

The Partnership periodically estimates the effect on DCF resulting from changes in its volume forecast and NGL prices.   The Partnership has become less sensitive to changes in commodity prices because fee-based income has increased significantly.  For the full year 2014, the Partnership estimates that operating income will be over 70 percent fee-based.  In addition, the Partnership has hedged approximately 60 percent of its forecasted 2014 NGL exposure on a volumetric basis, 90 percent of these with direct product hedges.

The analysis further assumes derivative instruments outstanding as of February 26, 2014, and production volumes estimated through December 31, 2014.  The range of stated hypothetical changes in commodity prices considers current and historic market performance.

Estimated Range of 2014 DCF

NGL $/Gal		Volume Forecast (3)
(1) (2)		Low Case		Base Case		High Case
$	1.05	$	610	$	662	$	720
$	1.00	$	601	$	652	$	709
$	0.95	$	591	$	642	$	698
$	0.90	$	583	$	633	$	690
$	0.85	$	574	$	624	$	681

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

(2)Composite NGL prices is based on the Partnership’s average price.

(3)Volume Forecast is increased/decreased by 10% in the Marcellus and Utica segments for the High and Low Cases.

The table is based on current information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions the Partnership’s 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 volumes, prices and correlations do not guarantee future results.

Although the Partnership believes the expectations reflected in this analysis are reasonable, the Partnership 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, market conditions and constraints, production, NGL composition, infrastructure availability, market participants, and ratios between product 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 the Partnership’s periodic reports filed with the SEC, specifically those under the heading “Risk Factors.”

12

EX-99.2

Exhibit 99.2

FOURTH QUARTER 2013 CONFERENCE CALL PRESENTATION FEBRUARY 27, 2014

Forward-Looking Statements This presentation contains forward-looking statements and information. These forward-looking statements, which in many instances can be identified by words like “could,” “may,” “will,” “should,” “expects,” “plans,” “project,” “anticipates,” “believes,” “planned,” “proposed,” “potential,” and other comparable words, regarding future or contemplated results, performance, transactions, or events, are based on MarkWest Energy Partners, L.P. (“MarkWest” and the “Partnership”) current information, expectations and beliefs, concerning future developments and their potential effects on MarkWest. Although MarkWest believes that the expectations reflected in the forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct, and actual results, performance, distributions, events or transactions could vary significantly from those expressed or implied in such statements and are subject to a number of uncertainties and risks. 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, 2013. You are urged to carefully review and consider the cautionary statements and other disclosures, including those under the heading “Risk Factors,” made in those documents. If any of the uncertainties or risks develop into actual events or occurrences, or if underlying assumptions prove incorrect, it could cause actual results to vary significantly from those expressed in the presentation, and MarkWest’s business, financial condition, or results of operations could be materially adversely affected. Key uncertainties and risks that may directly affect MarkWest’s performance, future growth, results of operations, and financial condition, include, but are not limited to: Fluctuations and volatility of natural gas, NGL products, and oil prices; A reduction in natural gas or refinery off-gas production which MarkWest gathers, transports, processes, and/or fractionates; A reduction in the demand for the products MarkWest produces and sells; Financial credit risks / failure of customers to satisfy payment or other obligations under MarkWest’s contracts; Effects of MarkWest’s debt and other financial obligations, access to capital, or its future financial or operational flexibility or liquidity; Construction, procurement, and regulatory risks in our development projects; Hurricanes, fires, and other natural and accidental events impacting MarkWest’s operations, and adequate insurance coverage; Terrorist attacks directed at MarkWest facilities or related facilities; Changes in and impacts of laws and regulations affecting MarkWest operations and risk management strategy; and Failure to integrate recent or future acquisitions. 2

Non-GAAP Measures Distributable Cash Flow, Adjusted EBITDA, and Net Operating Margin are not measures of performance calculated in accordance with GAAP, and should not be considered separately from or as a substitute for net income, income from operations, or cash flow as reflected in our financial statements. The GAAP measure most directly comparable to Distributable Cash Flow and Adjusted EBITDA is net income (loss). The GAAP measure most directly comparable to Net Operating Margin is income (loss) from operations. 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. Distributable Cash Flow 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, distributable cash flow 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. Net Operating Margin is a financial performance measure used by management and investors to evaluate the underlying baseline operating performance of our contractual arrangements. Management also uses Net Operating Margin to evaluate the Partnership’s financial performance for purposes of planning and forecasting. Please see the Appendix for reconciliations of Distributable Cash Flow, Adjusted EBITDA, and Net Operating Margin to the most directly comparable GAAP measure. 3

Fourth Quarter 2013: Financial Summary 4 Record total volume for fourth quarter and full year 2013 Total system volume of 3.2 Bcf/d for fourth quarter, an increase of 8% from the prior quarter. Total volume increased over 30% for full year 2013 vs. 2012 Marcellus total volume grew by 22% compared to prior quarter. Volume increased over 135% for full year 2013 vs. 2012 Utica total volume grew by 27% compared to prior quarter DCF for fourth quarter and full year 2013 DCF for fourth quarter was $127.2 million, an increase of 8% from the prior year quarter DCF for full year 2013 was a record $483.4 million, an increase of 17% from the full year 2012 Full year 2013 DCF was reduced by $27 million due to operational impacts during the second half of 2013. As of January 2014, all of these constraints have been resolved Increased fourth quarter distribution to 86 cents per common unit

Fourth Quarter 2013: Operational Summary 5 19 major projects under development, which will increase our total processing capacity in the region to nearly 5 billion cubic feet per day and total fractionation capacity to over 400,000 barrels per day Completed eight new major projects Five processing facilities totaling 1 Bcf/d of new processing capacity in the Marcellus and Utica Shales Two fractionation facilities: 60,000 Bbl/d propane plus Hopedale fractionation facility to support producers in the Marcellus and Utica Shales 38,000 Bbl/d De-ethanization facility at Majorsville complex in the Marcellus Shale 200 MMcf/d Buffalo Creek processing plant in Granite Wash Announced three new major projects Executed amendments to agreements with Antero Resources for 200 MMcf/d of additional processing to be constructed at the Seneca processing facility in the Utica Shale 40,000 Bbl/d de-ethanization facility at Mobley complex in the Marcellus Shale Condensate stabilization solution in the Utica Shale

Southwest Segment Overview Southwest continued to deliver strong financial results in Granite Wash, Haynesville Shale, Woodford Shale and Gulf Coast Total volumes increased 2% compared to the prior year quarter and declined 3% compared to prior quarter primarily due to planned Gulf Coast turnaround Processing capacity operated at approximately 86% utilization during the fourth quarter Commenced operations of 200 MMcf/d Buffalo Creek in Granite Wash to support Chesapeake Energy In early planning stages for additional plant in East Texas to support Haynesville rich-gas development ~20% Forecasted Increase from FY2013 to FY2014 2014 Avg. 6

Marcellus Segment Overview 7 MarkWest continues to achieve record volumes and operating income at five major complexes Continue to execute growth strategy and announced one new major project Segment operating income was $89.5m, an increase from the prior quarter of 10% Total volumes increased 22% from the prior quarter and over 135% for the full year 2013 versus full year 2012 Houston fractionation facility operated at full utilization Completed second 38,000 Bbl/d Marcellus De-ethanizer at Majorsville complex Constructed approximately 200 miles of gas and liquids pipeline in 2013 ~75% Forecasted Increase from FY2013 to FY2014 2014 Avg.

Marcellus Segment Overview 8 Five complexes in Marcellus with over 2.2 Bcf/d of total processing capacity Added 600 MMcf/d of processing capacity during the quarter – new 200 MMcf/d plants at Majorsville, Mobley & Sherwood Total utilization of processing capacity was 63% during the fourth quarter 2013 Complex Capacity (MMcf/d) 4Q13 Avg. Volume (MMcf/d) Utilization (%) Houston 355 333 94 Majorsville 670 414 62 Mobley 520 248 48 Sherwood 600 325 54 Keystone 90 82 91 Total 2,235 1,402 63

9 MWE Gathering Area MWE NGL Pipelines MWE Marcellus Counties MWE Plants MWE Purity Ethane Pipeline MWE NGL/Purity Ethane Pipelines Under Construction Brooke Doddridge Marshall Ohio Ritchie Tyler Wetzel Allegheny Beaver Butler Greene Washington KEYSTONE COMPLEX MOBLEY COMPLEX SHERWOOD COMPLEX MarkWest’s Marcellus Producers Sunoco Mariner Pipeline ATEX Express Pipeline TEPPCO Product Pipeline HOUSTON COMPLEX MAJORSVILLE COMPLEX

MarkWest Utica EMG’s Producers 10 MWE NGL Pipelines MWE Gathering Area MWE Purity Ethane Pipeline MWE NGL/Purity Ethane Pipelines Under Construction MWE Utica Counties MWE Plants CADIZ & SENECA COMPLEXES Belmont Guernsey Harrison Monroe Noble

Utica Segment Overview 11 MarkWest Utica EMG continues to develop its full-service leading position in Ohio Total volumes increased by 27% compared to prior quarter Processing capacity operated at 43% utilization for the fourth quarter 2013. Over 50% of the capacity was brought into service during the quarter Recently announced two new major projects, including an additional processing plant at the Seneca complex and a condensate stabilization facility Constructed over 200 miles of gas and liquids pipeline in 2013 ~530% Forecasted Increase from FY2013 to FY2014 2014 Avg.

Utica Condensate Solutions MarkWest and EMG will construct a condensate stabilization facility with associated logistics and storage terminal capabilities in Harrison County, Ohio The facility will provide condensate handling and stabilization services, and we are in active discussions with numerous Utica producers The facility will have initial stabilization capacity of 23,000 Bbl/d and is expected to be in service by the third quarter of 2014 Stabilizers will remove butanes and lighter NGLs from produced condensate in order to yield a higher value pentanes plus product 12 Hopedale Belmont Guernsey Harrison Monroe Noble Ohio

Hopedale Fractionation Complex In January 2014, MarkWest began operations of its third world-class fractionation and marketing complex in the Northeast The Hopedale fractionator is located in Harrison County, Ohio and has increased MarkWest’s C3+ fractionation in the region to 144,000 Bbl/d The complex is connected via an NGL pipeline to MarkWest’s extensive Marcellus infrastructure The complex includes extensive purity product storage capacity and critical logistics marketing infrastructure, including a large-scale rail yard and truck loading docks 13

MWE Complexes ATEX Express Pipeline MWE Purity Ethane Pipeline MWE NGL Pipelines MWE NGL/Purity Ethane Pipelines Under Construction UMTP Pipeline Sunoco Mariner Pipeline Virginia Michigan West Virginia Pennsylvania Gathering & Processing NGL Transportation & Marketing MWE Gathering Systems NGL Gathering & Fractionation Rich-Gas Areas Fully integrated NGL transportation, fractionation and logistics solutions in the Marcellus and Utica Shales Growing to over 400 MBbl/d of total C2+ fractionation capacity Integrated natural gas gathering systems 7 major processing complexes with current capacity of 2.8 Bcf/d. Growing to over 5 Bcf/d Access to all major NGL takeaway pipeline projects in the Northeast Access to Gulf Coast NGL markets through a proposed joint venture with Kinder Morgan TEPPCO Product Pipeline Gulf Coast Mobley Sherwood Keystone Seneca Lake Erie Mariner East Mariner West Utica Marcellus Texas Pipeline (UMTP) Marcellus & Utica: Full-Service Capabilities Houston Hopedale Cadiz Condensate JV 14 Ohio

Total Volume Growth 15 Base case total volumes are forecasted to increase over 50% from 2013 42% 62% 52%

MWE NGL Pipelines Barbour Brooke Doddridge Hancock Harrison Marion Marshall Monongalia Ohio Pleasants Preston Ritchie Taylor Tyler Wetzel Wood Belmont Carroll Columbiana Coshocton Guernsey Harrison Holmes Mahoning Medina Monroe Morgan Muskingum Noble Portage Stark Summit Trumbull Tuscarawas Washington Wayne Allegheny Armstrong Beaver Butler Clarion Crawford Fayette Greene Lawrence Mercer Venango Washington Westmoreland West Virginia Ohio MWE Utica Counties MWE Marcellus Counties MWE Plants ATEX Express Pipeline TEPPCO Product Pipeline Jefferson Marcellus & Utica: 23 Major Projects Complete Mariner Projects Rich Utica Rich Marcellus MWE Gathering Area 16 MWE Purity Ethane Pipeline 19 Major projects under construction HOUSTON COMPLEX Houston I – III – 355 MMcf/d – Complete Houston IV – 200 MMcf/d – 1Q15 C3+ Fractionation – 60,000 Bbl/d – Complete De-ethanization – 38,000 Bbl/d – Complete HOPEDALE FRACTIONATOR C3+ Fractionation – 60,000 Bbl/d – Complete MAJORSVILLE COMPLEX Majorsville I – III, V – 670 MMcf/d – Complete Majorsville IV – 200 MMcf/d – 2Q14 Majorsville VI – 200 MMcf/d – 2016 De-ethanization I – 38,000 Bbl/d – Complete De-ethanization II – 38,000 Bbl/d – TBD MOBLEY COMPLEX Mobley I – III – 520 MMcf/d – Complete Mobley IV – 200 MMcf/d – 4Q14 De-ethanization – 40,000 Bbl/d – 3Q15 SHERWOOD COMPLEX Sherwood I – III – 600 MMcf/d – Complete Sherwood IV – 200 MMcf/d – 3Q14 Sherwood V – 200 MMcf/d – 4Q14 De-ethanization – 38,000 Bbl/d – TBD MWE NGL/Purity Ethane Pipelines Under Construction UTICA CONDENSATE JV Stabilization Facility – 23,000 Bbl/d – 3Q14 CADIZ COMPLEX Cadiz I & Refrig – 185 MMcf/d – Complete Cadiz II – 200 MMcf/d – 3Q14 De-ethanization – 40,000 Bbl/d – 2Q14 SENECA COMPLEX Seneca I – II – 400 MMcf/d – Complete Seneca III – 200 MMcf/d – 2Q14 Seneca IV – 200 MMcf/d – 1Q15 De-ethanization – 38,000 Bbl/d – TBD KEYSTONE COMPLEX Bluestone I & Sarsen I – 90 MMcf/d – Complete Bluestone II – 120 MMcf/d – 2Q14 Bluestone III – 200 MMcf/d – TBD De-ethanization – 10,000 Bbl/d – 2Q14 C3+ Fractionation – 10,000 Bbl/d –2Q14

Liquidity 17 MarkWest preserves a strong balance sheet to fund growth As of today, we have $1 billion of liquidity to support our capital investment program As of December 31, 2013, our total Debt to Capital was 39%, interest coverage was 4.5 times and our leverage ratio was 4.5 times Maintain flexible financing options Funding of base capital requirements using a combination of long-term debt and equity $1.2 billion dollar revolving credit facility to support short-term funding needs Ability to maintain consistent access to the equity markets through our continuous equity program Enhancing financial flexibility through partnerships and joint ventures MarkWest has $1 billion of liquidity

Increasing Fee-Based Income Note: Forecast Assumes Crude Oil ($/bbl) range of $97.26 to $89.47 and Natural Gas ($/mmbtu) range of $5.03 to $4.32 2014 fee-based net operating margin is forecasted to exceed 70% 18 Increase of ~3x since 2008 Over 70% 25% 39% 38% 38% 53% 61%

Distributable Cash Flow: Sensitivity Table 19 MarkWest estimates the effect on DCF resulting from changes in volume forecast and NGL prices The Partnership has become less sensitive to changes in commodity prices as fee-based income has increased significantly (1) The composition is based on the Partnership’s projected barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%. (2) Composite NGL prices is based on the Partnership’s average price. (3 Volume Forecast is increased/decreased by 10% in the Marcellus and Utica segments for the High and Low Cases. Volume Forecast (3) Composite NGL $/Gal (1) (2) Low Case Base Case High Case $1.05 $610 $662 $720 $1.00 $601 $652 $709 $0.95 $591 $642 $698 $0.90 $583 $633 $690 $0.85 $574 $624 $681 MarkWest is more sensitive to changes in volumes than changes in commodity prices

Distributable Cash Flow: Forecast 24% 33% 43% DCF of $483.4 million 2014 DCF Forecast of $600 to $690 million 20

2014 Capital Forecast 21 Utica 26% Southwest 7% Marcellus 67% 2014 Capital Forecast of $1.8 to $2.3 billion

APPENDIX

Reconciliation of DCF and Distribution Coverage 23 Year Ended Year Ended ($ in millions) 12/31/2012 12/31/2013 Net Income $ 217.0 $ 40.4 Depreciation, amortization, impairment, and other non-cash operating  237.6 365.7 expenses  Loss (gain) on sale and or disposal of assets, net of tax benefit 6.3 (30.7) Loss on redemption of debt, net of tax benefit - 36.2 Amortization of deferred financing costs and discount 5.6 6.7 Non-cash earnings from unconsolidated affiliates (2.3) (1.4) Distributions from unconsolidated affiliates 8.4 6.4 Non-cash compensation expense 8.2 7.8 Non-cash derivative activity (102.1) 15.6 Provision for income tax –deferred 40.7 23.9 Cash adjustment for non-controlling interest of consolidated subsidiaries 2.3 6.1 Revenue deferral adjustment 7.4 7.2 Other 3.3 17.5 Maintenance capital expenditures, net of joint venture partner contributions (15.3) (18.0) Distributable cash flow (DCF) $ 417.1 $ 483.4 Total distributions declared for the period 370.3 490.6 Distribution coverage ratio (DCF / Total distributions declared) 1.13x 0.99x

Reconciliation of Adjusted EBITDA 24 Includes derivative activity related to interest expense, amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer. Year Ended Year Ended Year Ended ($ in millions) 12/31/2011 12/31/2012 12/31/2013 Net income $ 104.8 $ 217.0 $ 40.4 Non-cash compensation expense 3.4 8.2 7.8 Non-cash derivative activity (0.3) (102.1) 15.6 Interest expense (1) 109.9 117.1 150.1 Depreciation, amortization, impairments,   188.8 237.6 365.7 and other non-cash operating expenses  Loss (gain) on sale and disposal of assets 8.8 6.2 (33.8) Loss on redemption of debt 79.0 - 38.5 Provision for income tax 13.7 38.3 12.7 Adjustment for cash flow from   4.2 6.1 4.9 unconsolidated affiliate  Other 3.0 0.1 4.1 Adjusted EBITDA $ 515.3 $ 528.5 $ 606.0 (1) Includes derivative activity related to interest expense, amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer.

Reconciliation of Net Operating Margin 25 Year Ended Year Ended ($ in millions) 12/31/2012 12/31/2013  Income from operations $ 378.3 $ 245.9 Facility expense 206.9 291.1 Derivative activity (69.1) 25.8 Revenue deferral adjustment and other 5.9 6.2 Selling, general and administrative expenses 93.4 101.6 Depreciation 183.3 299.9 Amortization of intangible assets 53.3 64.6 Loss (gain) on disposal of property, plant, and  6.2 (33.8) equipment  Accretion of asset retirement obligations 0.7 0.8 Net operating margin $ 858.9 $ 1,002.1

1515 Arapahoe Street Tower 1, Suite 1600 Denver, Colorado 80202 Phone: 303-925-9200 Investor Relations: 866-858-0482 Email: investorrelations@markwest.com Website: www.markwest.com