Bank of America Merrill Lynch Energy Conference November 2009

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, 2008, and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, 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 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) attributable to the Partnership. In general, we define Distributable Cash Flow as net income (loss) attributable to the Partnership adjusted for (i) depreciation, amortization, accretion and impairment 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’s 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”); (viii) provision for deferred income taxes; (ix) 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) attributable to the Partnership adjusted for (i) depreciation, amortization, accretion, and impairment expense; (ii) interest expense; (iii) amortization of deferred financing costs; (iv) losses (gains) on the disposal of PP&E; (v) non-cash derivative activity; (vi) non-cash compensation expense; (vii) provision for income taxes; (viii) adjustments for cash flow from unconsolidated investments; (ix) adjustment for non-controlling interest of consolidated 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 and Slide 22 for reconciliations of Adjusted EBITDA and Distributable Cash Flow, respectively, to net income (loss) attributable to the Partnership.

MWE: Key Investment Considerations Committed to maintaining strong credit ratios Debt / book capitalization of approximately 50% Debt / Adjusted EBITDA with Material Project Adjustments (MPAs) of approximately 4.3x Adjusted EBITDA w/MPAs / Interest Expense of approximately 3.3x No incentive distribution rights Since IPO, distributions have increased by 156% (14% CAGR) 11 acquisitions totaling ~$875 million (excluding the MarkWest Hydrocarbon merger) since IPO Proven ability to expand organizational capabilities 2009 growth capital forecast of approximately $465 million 2010 growth capital forecast of approximately $480 million Growth projects are well diversified across the asset base Long-term organic growth opportunities focused on unconventional 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 Michigan 250-mile intrastate crude pipeline 90-mile gas gathering pipeline Western Oklahoma 275 MMcf/d gathering capacity 160 MMcf/d processing plant Southeast Oklahoma 500 MMcf/d gathering capacity Centrahoma processing JV Arkoma Connector JV with ArcLight Capital Partners Starfish (50% equity ownership) West Cameron dehydration facility 1.2 Bcf/d Stingray interstate pipeline Appalachia Four processing plants with combined 330 MMcf/d processing capacity 24,000 Bbl/d NGL fractionation facility 260,000 barrel storage capacity 80-mile NGL pipeline Javelina Refinery off-gas processing, fractionation, and transportation facilities East Texas 500 MMcf/d gathering capacity 280 MMcf/d processing plant Other Southwest 12 gas gathering systems 4 lateral gas pipelines Liberty M&R JV 100 MMcf/d gathering capacity 100 MMcf/d processing capacity

Competitive advantages Located in prolific East Texas Basin Cotton Valley, Travis Peak and Pettit formations Haynesville Shale Currently gathering ~30 MMcf/d; expected to grow Multiple gas and NGL outlets to downstream markets System and plant are essentially new; highly fuel efficient with minimal losses Low-pressure service Common suction design for optimized compression redundancy Market Access Interconnects to the Natural Gas Pipeline (NGPL) and CenterPoint Energy Gas Transmission Pipeline (CEGT) Gathering system 500 MMcf/d capacity (current throughput greater than 450 MMcf/d) More than 440 miles of pipe More than 100,000 hp of compression Gas processing plant 280 MMcf/d cryogenic gas plant Highly fuel efficient East Texas System Overview LEGEND NGPL CEGT

Competitive advantages Located in prolific Anadarko Basin and the Granite Wash formation (in the Texas panhandle) Low and medium pressure service System and plant are essentially new; highly fuel efficient and reliable with minimal losses Market Access Interconnects to Panhandle Eastern Pipeline (PEPL), ANR Pipeline System (ANR), CEGT, and NGPL Gathering system 275 MMcf/d current capacity Includes 80 MMcf/d expansion into the Granite Wash formation completed in 2008 More than 475 miles of pipe More than 50,000 hp of compression Gas processing plant 160 MMcf/d cryogenic gas plant Highly fuel efficient Western Oklahoma System Overview NGPL PIPELINE CEGT PIPELINE ANR PIPELINE PEPL PIPELINE GAS PROCESSING PLANT

Competitive advantages Located in prolific Arkoma Basin Low pressure service In excess of 160,000 dedicated acres in the Woodford Shale play and the Hartshorne coal bed methane (CBM) play Market Access Interconnects to CEGT, CPFS, Enogex, and Arkoma Connector Pipeline with 1.3 Bcf/d of takeaway capacity Arkoma Connector pipeline is a 50/50 joint venture with ArcLight Capital Partners and connects to Midcontinent Express and Gulf Crossing pipelines Gathering system 500 MMcf/d capacity (currently flowing 470 MMcf/d) More than 700 miles of mostly large diameter pipe More than 23 compressor stations with 85,000 HP Processing and treating capacity 40 MMcf/d processing capacity through 40% ownership of Centrahoma joint venture Three amine treating facilities at north and south end of gathering system Southeast Oklahoma System Overview CPFS PIPELINE CEGT PIPELINE ARKOMA CONNECTOR PIPELINE MEP PIPELINE GULF CROSSING PIPELINE

Refinery off-gas processing 140 MMcf/d cryogenic gas plant produces NGLs and residue gas NGLs are fractionated and residue gas is returned to the refiners for fuel gas Hydrogen is separated from the off-gas through pressure swing absorption (PSA) process Fractionation 29,000 Bbl/d NGL fractionation capacity Products produced include ethylene, ethane, propane, propylene, mixed-butanes, and pentanes Steam methane reformer (SMR) SMR will deliver high-purity hydrogen to refinery customers, a critical component in the production of ultra-low sulfur diesel The SMR was sold to Air Products in September 2009 but integrates with Javelina facility and expands hydrogen supply Javelina Processing Facility Overview Competitive advantages Javelina provides critical services for six refineries in Corpus Christi, Texas All refinery off-gas is committed to Javelina under long-term contracts Excellent relationships with refinery customers Efficient off-gas processing and fractionation facility Product pipelines to critical end markets

Appalachia Overview Processing Plants Four plants with total gas processing capacity of approximately 330 MMcf/d Cobb plant expansion completed in mid 2009; capacity increased to approximately 70 MMcf/d Kenova plant modified in 2008 to improve propane recovery Siloam Current fractionation capacity of 24,000 Bbl/d, including expansion completed in 2009 Competitive advantages Largest gas processor in the prolific Appalachian Basin, a critical source of natural gas and natural gas liquids to Northeastern markets More than 20 years of operational experience NGLs from the gas plants are shipped to Siloam for fractionation, storage, and marketing Produces purity propane, iso-butane, normal butane, and natural gasoline Strategic and longstanding marketing relationships with sales by truck, rail, and barge Propane storage capacity of more than 10 million gallons

Liberty Overview Competitive advantages Significant first mover advantage in the prolific Marcellus Shale with key producer acreage dedications of up to 300,000 rich-gas acres Critical gathering, processing, transportation, fractionation, and storage infrastructure that currently did not exist in the Northeast System and plants are new; highly fuel efficient with minimal losses Low-pressure service Experienced mid-stream operator with extensive northeast marketing experience Market Access Interconnected to Columbia Gas Transmission (CGT) Gathering system 100 MMcf/d gathering capacity and growing daily More than 50 miles of pipe and 25,000 hp of compression Gas processing plant 65 MMcf/d mechanical refrigeration gas plant 35 MMcf/d cryogenic gas plant Joint Venture with NGP Midstream & Resources (M&R) Long-term partnership to develop midstream services in the Marcellus Partners one of the best midstream companies with a strong financial partner that shares a common view towards the inherent value of the Marcellus Allows MarkWest to meet the significant gathering and processing needs of its producer customers while significantly reducing MW up-front capital Majorsville

Long-term Liberty Development Plans Ohio West Virginia Houston Fractionation Complex Depropanizer (1Q09) 1,000 Bbl/day Depropanizer (4Q09) 4,000 Bbl/day Full Fractionation (1Q11) 37,000 Bbl/day Rail Loading (1Q11) 200 Rail Cars Truck Loading (1Q10) 8 Bays Pipeline (1Q10) C3 TEPPCO Deliveries NGL Storage 1.3 MBbls Majorsville Processing Complex Majorsville I (3Q10) 120 MMcf/d Majorsville II (TBD) 120 MMcf/d NGL Pipeline to Houston (3Q10) Houston Processing Complex Interim Plant (4Q08) 65 MMcf/d Houston I (1Q09) 35 MMcf/d Houston II (4Q09) 120 MMcf/d Houston III (1Q11) 200 MMcf/d Houston IV (TBD) 200 MMcf/d Gathering Facilities HP Pipelines (4Q09) 45 miles HP Pipeline (4Q12) 150 – 175 miles LP Pipelines (4Q09) 20 miles LP Pipeline (4Q12) 70 - 80 miles Compressor stations (4Q09) 10 Compressor stations (4Q012) 28 - 34 Compression (4Q09) 27,000 Hp Compression (4Q12) 90,000 Hp

Growth Driven by Customer Satisfaction R A N G E RESOURCES MarkWest Ranked # 1 in 2006 and #2 in 2009 Natural Gas Midstream Services Customer Satisfaction EnergyPoint Research, Inc. Customer Satisfaction Survey

Risk Management Program Net Operating Margin(1) by Contract Type Net Operating Margin(1) including Hedges 2009 – 2012 Combined Hedge Percentage (1) For the nine months ended September 30, 2009. Net Operating Margin is calculated as revenue less purchased product costs. Fee-Based 41% POP&POI 30% Keep-Whole 29% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 2009 2010 2011 2012 Percentage Hedged Fee-Based 40% Hedged 43% Commodity Based 17%

Distribution Growth Since IPO 156% Distribution Growth since IPO in May 2002 (14% CAGR) * Distributions have been annualized. $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 2002* 2003 2004 2005 2006 2007 2008 2009* Distribution per Common Unit

2009 Growth Capital Forecast 2009 growth capital forecast ~$ 465 million Less funding through joint ventures / divestitures ~$(310) million Net MarkWest growth capital ~$ 155 million SMR hydrogen production facility Gulf Coast Southwest Arkoma Connector pipeline Stiles Ranch Southeast Oklahoma / Woodford expansion Well connects / compression Northeast Cobb plant expansion Siloam plant expansion Liberty Develop midstream infrastructure in the Marcellus shale Gulf Coast ~$25 LIberty ~$190 MM Southwest ~$235 MM Northeast $15

2010 Growth Capital Forecast 2010 growth capital forecast ~$ 480 million Less funding through joint venture contributions ~$(180) million Net MarkWest growth capital ~$ 300 million Southwest Haynesville gathering lines Compressor / pipeline additions New well connects Other expansion Liberty Wet gas gathering system Houston II processing plant Houston III processing plant Majorsville I processing plant Fractionation facility Railyard / truck loading facility Southwest ~$70 MM Liberty ~$410 MM

millions millions Distributable Cash Flow 1 (1) See slide 22 for a reconciliation of DCF to net income attributable to the Partnership. Strategic Investments Drive DCF NOTE: Financial data for periods prior to 2008 has not been restated for the MarkWest Hydrocarbon merger $170M–$180M Capital Investment Acquisitions Growth Capital to Develop Emerging Resource Plays * Approximately $330 million and $180 million in 2009 and 2010, respectively, is expected to be funded through joint ventures and divestiture activities. Growth Capital to Build Base Production $170M–$210M $0 $100 $200 $300 $400 $500 $600 2004 2005 2006 2007 2008 2009F* 2010F* $0 $50 $100 $150 $200 $250 2004 2005 2006 2007 2008 2009F 2010F

2010 Forecasted DCF Sensitivity Analysis $146 $174 $180 $181 $185 C $206 $209 $218 $224 $228 B $241 $253 $261 $267 $272 A $90 Crude Oil to Natural Gas Ratio $156 $181 $205 $162 $191 $220 $169 $202 $236 $175 $214 $252 16:1 $199 $207 $213 $217 A $60 $138 $158 $164 $165 C $183 $187 $194 $199 B $212 $222 $228 $232 A $70 $141 $164 $171 $172 C $153 $178 $202 $159 $188 $210 $248 14:1 C B A C B B A NGL Correlation $151 $174 $199 $158 $184 $204 $243 12:1 $146 $169 $194 $151 $178 $197 $236 10:1 $164 $134 $187 $50 $172 $136 $192 $225 8:1 Crude Oil Price $80 NOTE: The table is based on information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions MarkWest management may take to mitigate exposure to changes. Nor does the table consider the effects that such hypothetical adverse changes may have on overall economic activity. Estimated Range of 2010 DCF ($ in millions) The table reflects an estimated range of 2010 DCF based on three natural gas liquids (NGL) correlation scenarios, including: (A) One standard deviation above the historical average NGL correlation to crude over the past three years; (B) The historical average NGL correlation to crude over the past three years; (C) One standard deviation below the historical average NGL correlation to crude over the past three years. The analysis assumes derivative instruments outstanding as of November 6, 2009, and production volumes estimated through December 31, 2010 During the past 10 years, the annual average NGL correlation has ranged between one standard deviation below the historical average and one standard deviation above the historical average.

2009 Capital Markets and Liquidity Update MarkWest completed one private placement of senior notes and two public offerings of common units in 2009 May 2009 – $150 million of 6.875% senior unsecured notes due 2014 Priced at 12.59% yield to maturity Net proceeds of approximately $113.8 million June 2009 – 3.3 million common unit offering at $18.15 Net proceeds of approximately $57.9 million August 2009 – 6.0 million common unit offering at $20.95 Net proceeds of approximately $121.0 million In addition, MarkWest executed two joint ventures in 2009 January 2009 – joint venture with NGP Midstream & Resources Dedicated to the construction and operation of natural gas midstream services in the Marcellus Shale May 2009 – joint venture with ArcLight Capital Partners Dedicated to the Arkoma Connector pipeline, a 50-mile interstate pipeline that provides Woodford Shale takeaway capacity and interconnects with Midcontinent Express Pipeline and Gulf Crossing Pipeline In September 2009, MarkWest sold to Air Products and Chemicals, Inc. the steam methane reformer (SMR) facility currently being constructed at its Javelina processing facility MarkWest has approximately $350 million available on its $435.6 million revolving credit facility

Capital Structure ($ in millions) As of December 31, 2008 As of September 30, 2009 Cash $ 3.3 $ 65.3 Credit Facility 184.7 51.8 6-7/8% Senior Notes due 2014 215.3 216.5 6-7/8% Senior Notes due 2014 – 119.1 8-1/2% Senior Notes due 2016 274.1 274.2 8-3/4% Senior Notes due 2018 498.8 498.9 Total Debt $ 1,172.9 $ 1,160.5 Partners' Capital $ 1,204.5 $ 1,163.5 Total Capitalization $ 2,377.4 $ 2,324.0 LTM Adjusted EBITDA (1) $ 289.0 $ 261.0 Total Debt / Capitalization 49% 50% Total Debt / LTM Adjusted EBITDA 4.1x 4.4x Adjusted EBITDA / Interest Expense 4.0x 2.9x Total Debt / LTM Adjusted EBITDA w//MPAs (2) 3.8x 4.3x Adjusted EBITDA w/ MPAs / Interest Expense (2) 4.5x 3.3x (1) Adjusted EBITDA calculated in accordance with Credit Facility covenants; See Appendix for reconciliation of Adjusted EBITDA to net income attributable to the Partnership. (2) Adjusted EBITDA w/ MPAs and leverage and interest coverage ratios are calculated in accordance with Credit Facility covenants.

 3.3 – Starfish partial insurance settlement ($ in millions) Year ended December 31, 2008 Nine months ended September 30, 2009 Net income (loss) attributable to the Partnership $ 208.1 $ (88.9) Depreciation, amortization, accretion, impairments, and loss on disposal of PP&E 184.3 107.9 Non-cash derivative activity (263.1) 147.2 Non-cash compensation expense 14.9 3.3 Non-cash losses from unconsolidated affiliates (0.1) (1.3) Distributions from (contributions to) unconsolidated affiliates, net of growth capital 0.4 (6.4) Provision for income tax – deferred 53.8 (34.7) Adjustment for non-controlling interest of consolidated subsidiaries – (2.6) Other 7.0 6.7 Maintenance capital expenditures (7.2) (5.3) Distributable cash flow (DCF) $ 198.1 $ 129.2 Total distributions paid $ 142.2 $ 117.4 Distribution coverage ratio (DCF / Total distributions paid) 1.39x 1.10x Distribution Coverage

2009 and 2010 Guidance 2009 Financial Guidance Distributable cash flow of $170 million to $180 million Growth capital expenditures of approximately $465 million approximately $330 million is expected to be funded by joint venture and divestiture activities 2010 Financial Guidance Distributable cash flow of $170 million to $210 million Growth capital expenditures of approximately $480 million approximately $180 million is expected to be funded by joint venture and divestiture activities

Investment Highlights High quality / diversified asset base Proven track record of growth Substantial growth opportunities Strong financial profile

Appendix

 (9.4) (3.4) 4.9 Adjustment for non-controlling interest of consolidated subsidiaries 6.7 14.9 20.5 Non-cash compensation expense 1.9 6.5 – Adjustment for cash flow from unconsolidated investments $ 220.4 150.4 42.4 (24.6) 66.2 $ (39.4) Year ended December 31, 2007 $ 289.0 (263.1) 72.9 68.8 184.3 $ 208.1 Year ended December 31, 2008 $ 261.0 (152.7) 88.6 24.2 210.2 $ 91.4 LTM ended September 30, 2009 ($ in millions) Interest expense Provision for income tax Non-cash derivative activity Depreciation, amortization, accretion, impairments, and other non-cash operating expenses Adjusted EBITDA Net income (loss) attributable to the Partnership Reconciliation of Adjusted EBITDA

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