Wells Fargo 9th Annual MLP Symposium December 7, 2010

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 “Partnership”) current information, expectations and beliefs, concerning future developments and their potential effects on MarkWest. 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, 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, performance, distributions, events or transactions to differ materially from those expressed or implied, are those risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2009 and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, as filed with the SEC. 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 our 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 we gather, transport, process, and/or fractionate; A reduction in the demand for the products we produce and sell; Financial credit risks / failure of customers to satisfy payment or other obligations under our contracts; Effects of our debt and other financial obligations, access to capital, or our 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 our operations, and adequate insurance coverage; Terrorist attacks directed at our facilities or related facilities; Changes in and impacts of laws and regulations affecting our operations and risk management strategy; and Failure to integrate recent or future acquisitions.

Non-GAAP Measures Distributable Cash Flow and Adjusted EBITDA 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). In general, we define Distributable Cash Flow as net income (loss) adjusted for (i) depreciation, amortization, accretion, and other non-cash expense; (ii) amortization of deferred financing costs; (iii) non-cash (earnings) loss from unconsolidated affiliates; (iv) distributions from (contributions to) unconsolidated affiliates (net of affiliate growth capital expenditures); (v) non-cash compensation expense; (vi) non-cash derivative activity; (vii) losses (gains) on the disposal of property, plant, and equipment (PP&E) and unconsolidated affiliates; (viii) provision for deferred income taxes; (ix) cash adjustments for non-controlling interest in consolidated subsidiaries; (x) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period; and (xi) maintenance capital expenditures. We define Adjusted EBITDA as net income (loss) adjusted for (i) depreciation, amortization, accretion, and other non-cash expense; (ii) interest expense; (iii) amortization of deferred financing costs; (iv) losses (gains) on the disposal of PP&E and unconsolidated affiliates; (v) non-cash derivative activity; (vi) non-cash compensation expense; (vii) provision for income taxes; (viii) adjustments for cash flow from unconsolidated affiliates; (ix) adjustment related to non-wholly owned subsidiaries; and (x) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period. 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. Please see the Appendix for reconciliations of Distributable Cash Flow and Adjusted EBITDA to net income (loss), respectively.

MarkWest Key Investment Considerations Committed to maintaining strong financial profile Debt to book capitalization of 43% Debt to Adjusted EBITDA of 3.5x Adjusted EBITDA to Interest Expense of 3.5x Established relationships with joint venture partners, which provides capital flexibility No incentive distribution rights, which drives a lower cost of capital Distributions have increased by 156% (12.1% CAGR) since IPO 11 acquisitions totaling ~$875 million since IPO Proven ability to expand organizational capabilities 2011 growth capital forecast of $300 million to $350 million Growth projects are well diversified across the asset base and increase percentage of fee-based net operating margin Long-term organic growth opportunities focused on resource plays High-Quality, Diversified Assets Proven Track Record of Growth Strong Financial Profile Leading presence in five core natural gas producing regions of the U.S. Key long-term contracts with high-quality producers to develop the Marcellus Shale, Woodford Shale, Haynesville Shale, and Granite Wash formation Substantial Growth Opportunities

Geographic Footprint NORTHEAST Appalachia 330 MMcf/d processing capacity 24,000 Bbl/d NGL fractionation facility 260,000 barrel propane storage facility NGL marketing by truck, rail, and barge Michigan 250-mile interstate crude pipeline LIBERTY JV with The Energy & Minerals Group High-BTU acreage in the Marcellus 200 MMcf/d gathering capacity 290 MMcf/d cryogenic processing capacity 335 MMcf/d processing capacity under construction 60,000 Bbl/d fractionator under construction Planned 50,000 Bbl/d Mariner Ethane Project GULF COAST Javelina 140 MMcf/d cryogenic gas plant processing refinery off-gas 29,000 Bbl/d NGL fractionation capacity NGL marketing and transportation SOUTHWEST East Texas Cotton Valley, Travis Peak, Petit, and Haynesville 500 MMcf/d gathering capacity 280 MMcf/d cryogenic processing capacity Interconnects to CEGT, NGPL, & TGT Western Oklahoma Anadarko Basin and Granite Wash 275 MMcf/d gathering capacity 160 MMcf/d cryogenic processing capacity Interconnects to ANR, CEGT, NGPL, & PEPL Southeast Oklahoma Largest Woodford Shale gathering system 550 MMcf/d gathering capacity Centrahoma processing JV Arkoma Connector Pipeline JV Interconnects to CEGT, CPFS, & Enogex

Growth Driven by Customer Satisfaction R A N G E RESOURCES Since 2006, MarkWest has Ranked #1 or #2 in Natural Gas Midstream Services Customer Satisfaction EnergyPoint Research, Inc. Customer Satisfaction Survey

 MarkWest’s Commitment to Major Unconventional Resource Plays Map Source: RBC Capital Markets/RBC Richardson Barr U.S. Gas Resource Plays MarkWest’s Role in Emerging Resource Plays MarkWest is the largest gatherer in the Woodford with a system that covers more than 750 square miles of the core Woodford shale. MarkWest’s East Texas system covers more than 1,200 square miles of the Haynesville shale. MarkWest expanded its western Oklahoma system to gather significant new Granite Wash production in the Texas Panhandle. MarkWest Liberty is the largest gatherer and processor in the rich-gas area of the Marcellus Shale. Barnett Haynesville Fayetteville Woodford (Arkoma) Eagle Ford Granite Wash Marcellus/Huron Acquisitions Develop Emerging Resource Plays Build Base Production * Includes growth capital that has been funded or is expected to be funded through joint ventures and divestiture activities. 2004 2005 2006 2007 2008 2009 2010F Total Growth Capital Investment* 2011F 0 100 200 300 400 500 600

Diverse Volume Growth Emerging Resource Plays Base Production (Conventional / Tight Sand)

Long-term Appalachian History MarkWest is the largest gas processor and fractionator in the Appalachian Basin MarkWest operates four gas processing plants with total capacity of approximately 330 MMcf/d NGLs are transported to Siloam for fractionation, storage, and marketing Existing propane and heavier fractionation capacity of 24,000 Bbl/d Existing storage capacity of approximately 260,000 barrels The Northeast provides premium markets for NGLs produced in the Marcellus Fractionating NGLs into purity products is critical Marketing options must include truck, rail, and pipeline Storage is essential MarkWest has operated vertically integrated gas processing and NGL fractionation, storage and marketing in the Northeast for more than 20 years

DRY GAS RICH GAS RICH GAS ` Liberty Marcellus Project Schedule Ohio West Virginia Pennsylvania MarkWest Liberty is developing integrated and scalable gathering, processing, fractionation, and marketing infrastructure to support production in excess of 1 Bcf/d TEPPCO PRODUCTS PIPELINE 55 miles 125 – 150 miles 40 miles 200 – 250 miles 10 18 – 20 50,000 Hp 120,000 Hp

Houston Processing and Fractionation Complex

Majorsville Processing Complex

Tremendous Growth Opportunities Siloam Kenova Cobb Kermit Boldman Majorsville Houston

Project Mariner Overview Sunoco 8” Pipeline New MarkWest Liberty Houston to Delmont Pipeline Sunoco Philadelphia Storage and Docks MarkWest Liberty will modify the Houston and Majorsville plants to recover ethane MarkWest Liberty will construct a 45-mile liquid ethane pipeline Sunoco Logistics will convert its existing 250-mile, 8-inch refined products pipeline to liquid ethane service The pipeline will have capacity of approximately 50,000 bbl/day Sunoco Logistics will construct refrigerated ethane store facilities and load it onto refrigerated LPG carriers LPG carriers will transport the ethane to Gulf Coast markets The Mariner Project will be operational in 2012 A purity-ethane project to the Gulf Coast will maximize producer economics

2010 Financial Forecast 2010 growth capital forecast of approximately $300 million Southwest Amine plant Haynesville gathering lines Compressor / pipeline additions New well connects Other expansion Liberty Rich-gas gathering system Houston III processing plant Majorsville I processing plant Majorsville II processing plant Fractionation facility NGL Pipeline Railyard / truck loading facility 2010 DCF forecast of $225 million to $235 million

2011 Financial Forecast 2011 growth capital forecast of $300 million to $350 million Southwest Haynesville gathering lines Compressor / pipeline additions New well connects / trunklines Other expansion Liberty Rich-gas gas gathering system Houston III processing plant Majorsville II processing plant Fractionation facility NGL Pipeline Railyard / truck loading facility 2011 DCF forecast of $240 million to $280 million

Capital Markets and Liquidity Update As of early November, MarkWest had ~$750 million of available liquidity to fund growth capital In 2010, MarkWest has completed three significant capital market transactions A common unit equity offering of 4.9 million units for net proceeds of approximately $142 million A $705 million senior secured revolving credit facility that matures in July 2015 The new credit facility provides additional financial flexibility, lowers the Partnership’s borrowing costs, and maintains key financial covenants substantially unchanged from the previous credit facility A public offering of $500 million, 6.75% senior unsecured notes due 2020 Proceeds from the offering were used to complete a tender offer for the outstanding senior notes due 2014, to repay borrowings under the revolving credit facility, and to provide working capital In addition, in 2010 Moody’s and S&P upgraded MarkWest’s credit ratings to Ba3 and BB- and Fitch initiated coverage on MarkWest with a BB rating The primary drivers behind the ratings actions include MarkWest’s successful track record in executing its growth strategy, improved liquidity and strengthened balance sheet, increased fee-based operating margin, and commitment to issuing equity

Capital Structure ($ in millions) As of December 31, 2009 As of September 30, 2010 Pro Forma September 30, 2010 (1) Cash $ 97.8 $ 98.5 $ 98.5 Credit Facility 59.3 101.8 8.8 6-7/8% Senior Notes due 2014 216.9 218.3  6-7/8% Senior Notes due 2014 120.7 122.8  8-1/2% Senior Notes due 2016 274.2 274.3 274.3 8-3/4% Senior Notes due 2018 498.9 499.0 499.0 6-3/4% Senior Notes due 2020   500.0 Total Debt $ 1,170.0 $ 1,216.2 $ 1,282.1 Total Equity $ 1,379.4 $ 1,612.8 $ 1,570.9 Total Capitalization $ 2,549.4 $ 2,829.0 $ 2,853.0 LTM Adjusted EBITDA (2) $ 279.2 $ 321.8 $ 321.8 Total Debt / Capitalization 46% 43% 45% Total Debt / LTM Adjusted EBITDA (3) 4.1x 3.5x 3.5x Adjusted EBITDA / Interest Expense (3) 3.2x 3.5x 3.5x Pro forma for the $500 million senior note offering the Partnership completed in November 2010. Assumes proceeds from the offering were used to redeem the 2014 Senior Notes, including related accrued interest, and to reduce borrowings on the Credit Facility. Adjusted EBITDA is calculated in accordance with Credit Facility covenants; See Appendix for reconciliation of Adjusted EBITDA to net income (loss). Leverage ratio and interest coverage ratio are calculated in accordance with Credit Facility covenants.

Risk Management Program Nine months ended September 30, 2010 Net Operating Margin by Contract Type Nine months ended September 30, 2010 Net Operating Margin including Hedges 2010 – 2013 Combined Hedge Percentage NOTE: Net Operating Margin is calculated as revenue less purchased product costs.

Keys to Success Maintain stronghold in key resource plays with high-quality assets Execute growth projects that are well diversified across the asset base Provide best-of-class midstream services for our producer customers Preserve strong financial profile Deliver sustainable distribution growth EXECUTE, EXECUTE, EXECUTE

Appendix

($ in millions) Year ended December 31, 2009 Nine months ended September 30, 2010 Net (loss) income $ (113.4) $ 74.3 Depreciation, amortization, impairment, and other non-cash operating expenses 144.4 122.6 Non-cash earnings from unconsolidated affiliates (3.5) (1.5) Contributions to unconsolidated affiliates, net of growth capital (0.4) 2.5 Gain on sale of unconsolidated affiliate (6.8)  Non-cash derivative activity 223.6 (14.8) Non-cash compensation expense 3.9 6.5 Provision for income tax – deferred (50.1)  Cash adjustment for non-controlling interest of consolidated subsidiaries (8.1) (19.3) Other 10.3 8.9 Maintenance capital expenditures (7.5) (7.3) Distributable cash flow (DCF) $ 192.4 $ 171.9 Total distributions paid $ 159.8 $ 137.2 Distribution coverage ratio (DCF / Total distributions paid) 1.20x 1.25x DCF and Distribution Coverage

($ in millions) Year ended December 31, 2009 LTM ended September 30, 2010 Net income (loss) $ (113.4) $ 47.9 Non-cash compensation expense 3.9 7.0 Non-cash derivative activity 222.8 61.6 Interest expense 1 94.6 101.9 Depreciation, amortization, accretion, impairments, and other non-cash operating expenses 144.4 159.0 Provision for income tax (42.0) (3.7) Gain on sale of unconsolidated affiliate (6.8) (6.8) Adjustment for cash flow from unconsolidated affiliates (1.7) (0.2) Adjustment related to non-wholly owned subsidiaries (22.6) (44.1) Other  (0.8) Adjusted EBITDA $ 279.2 $ 321.8 Reconciliation of Adjusted EBITDA (1) Includes derivative activity related to interest expense and excludes interest expense related to the SMR.

1515 Arapahoe Street Tower 2, Suite 700 Denver, Colorado 80202 Phone: 303-925-9200 Investor Relations: 866-858-0482 Email: investorrelations@markwest.com Website: www.markwest.com