Exhibit 99.1

MarkWest Energy Partners Morgan Stanley Marcellus-Utica Mini-Conference September 19, 2012

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 MarkWest files with the SEC, including its Annual Report on Form 10-K for the year ended December 31, 2011 and its Quarterly Report on Form 10-Q for the quarters ended March 31, 2012 and June 30, 2012. 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 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) 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. 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) 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 define Net Operating Margin as revenue, excluding any derivative activity and adjusted for the non-cash impact of revenue deferrals related to certain agreements, less purchased product costs, excluding any derivative activity. 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

MarkWest Key Investment Considerations High-Quality, Diversified Assets Proven Track Record of Growth and Customer Satisfaction Substantial Growth Opportunities Strong Financial Profile Leading presence in six core natural gas producing regions of the U.S. Long-term contracts with high-quality producers to develop the Marcellus Shale, Utica Shale, Huron/Berea Shale, Woodford Shale, Haynesville Shale, and Granite Wash formation No incentive distribution rights Distributions have increased by 220% (12% CAGR) since IPO More than $5.0 billion of organic growth and acquisitions since IPO Ranked #1 or #2 in the last three EnergyPoint midstream customer satisfaction surveys 2012 growth capital forecast of $1.1 to $1.5 billion Long-term organic growth opportunities focused on resource plays 85% of capex is being invested in growing Marcellus and Utica plays. Contracts are primarily fee based Committed to maintaining strong financial profile Debt to book capitalization of 46% Debt to Adjusted EBITDA of 3.3x Adjusted EBITDA to Interest Expense of 5.6x 4 Keystone

US Shale Plays are Driving Natural Gas Supply 5 Source: EIA and En*Vantage EIA estimates that Lower 48 natural gas production will increase by 17% from 2011 to 2020. Shale gas production is responsible for all of the growth, offsetting the decline in the conventional gas plays. En*Vantage research indicates that rich legacy gas is 20 Bcf/d (7.3 Tcf/yr) and it is declining at an average rate of 9%/yr. Rich offshore gas is currently 4.5 Bcf/d (1.6 Tcf/yr) and it is declining at a rate of 13%/yr. US Lower 48 Gas Production vs Demand (Trillion Cubic Feet) 0 5 10 15 20 25 30 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 0 5 10 15 20 25 30 Non-associated onshore Non-associated offshore Associated w/ oil Tight Gas Coal Bed Methane Shale Gas Net Imports Domestic Gas Demand 21% 9% 10% 9% 26% 23% 39% 25% 7% 9% 7% 13% Source EIA AEO 2012

MarkWest Operational Assets: Focused on the Shales UTICA Utica Shale Under construction: 630 MMcf/d at the Harrison and Noble processing complexes 100 MBbl/d fractionation, storage, and marketing complex in Harrison County SOUTHWEST Granite Wash, Woodford, Cotton Valley, Haynesville 1.6 Bcf/d gathering capacity 655 MMcf/d processing 1.5 Bcf/d transmission capacity including Arkoma Connector Pipeline Under construction: 120 MMcf/d processing capacity in East Texas NORTHEAST Huron/Berea Shale 505 MMcf/d processing 24 MBbl/d fractionation 285 MBbl NGL storage NGL marketing by truck, rail, & barge Under construction: 150 MMcf/d processing capacity at Langley LIBERTY Marcellus Shale 390 MMcf/d gathering 715 MMcf/d processing 60 MBbl/d C3+ fractionator 90 MBbl NGL storage Under construction: 1.8 Bcf/d processing 115 MBbl/d C2 fractionation 50 MBbl/d Mariner West ethane pipeline project GULF COAST 140 MMcf/d cryogenic gas plant processing refinery off-gas 29 MBbl/d NGL fractionation capacity NGL marketing and transportation 6

Contributions to Operating Income by Segment 7 2011 Segment Operating Income 2012 Forecasted Segment Operating Income

MarkWest Liberty: Marcellus Business Unit Competitive advantages Rated 1st for midstream services in the Marcellus MarkWest is the largest processor of natural gas in the Marcellus Shale with liquids-rich acreage dedications in excess of 400,000 acres Operate fully integrated gathering, processing, fractionation, storage and marketing operations Ready access to markets with interconnects to Columbia Gas, National Fuel, TETCO, and TEPPCO Acquisition of Keystone Midstream Services, LLC: Supports extension of NGL header into Northwest PA Added two new significant producer customers Areas of Operation Southwest and Northwest Pennsylvania and northern West Virginia Resource Plays Marcellus Shale Gathering 390 MMcf/d capacity Processing 715 MMcf/d cryogenic capacity Fractionation 60,000 Bbl/d C3+ capacity NGL Marketing & Storage NGL Marketing by truck and 200 railcar facility 90,000 Bbl NGL capacity with access to 1.2 MMBbls of propane storage Under Construction Processing: 1.8 Bcf/d cryogenic capacity Fractionation: 115,000 Bbl/d de-ethanization capacity NGL Transportation: Extensive NGL gathering system, 50,000 Bbl/d Mariner West purity ethane pipeline 8 2012 Forecasted Segment Operating Income 28%

MarkWest Liberty: 715 MMcf/day of processing capacity TEPPCO PRODUCTS PIPELINE SUNOCO PIPELINE EPD ATEX EXPRESS PIPELINE 9 Growing to 2.15 Bcf/d and Fractionation capacity of 172,000 Bbl/d by the end of 2013 Mariner West De-ethanization I Houston I, II, III De-ethanization I, II Majorsville I, II, III, IV, V, VI Sarsen & Bluestone I, II, III Sherwood I, II Mobley I, II Harrison Fractionation & marketing facilities Proposed Shell ethane cracker Houston Processing and Fractionation Complex Houston I - III 355 MMcf/d C3+ Fractionation 60,000 Bbl/d Interconnect to TEPPCO pipeline Rail Loading 200 Rail cars Under Construction De-ethanization (mid-2013) 38,000 Bbl/d Mariner West ethane pipeline (3Q13) 50,000 Bbl/d Majorsville Processing and Fractionation Complex Majorsville I & II 270 MMcf/d NGL Pipeline to Houston 43,400 Bbl/d Under Construction Majorsville III - V (2013) 600 MMcf/d Majorsville VI (2014) 200 MMcf/d De-ethanization (mid-2013) 38,000 Bbl/d De-ethanization (2014) 38,000 Bbl/d Purity Ethane Pipeline to Houston (3Q13) Mobley Processing Complex Under Construction Mobley I (4Q12) 200 MMcf/d Mobley II (1Q13) 120 MMcf/d NGL Pipeline to Majorsville (3Q12) Sherwood Processing Complex Under Construction Sherwood I (3Q12) 200 MMcf/d Sherwood II (4Q13) 200 MMcf/d NGL Pipeline to Mobley (3Q12) Keystone Sarsen 40 MMcf/d Bluestone I 50 MMcf/d Under Construction Bluestone II (4Q13) 120 MMcf/d Bluestone III (TBD) 200 MMcf/d NGL Pipeline into Northwest PA (4Q13)

MarkWest Utica: 230 MMcf/d by 1Q2013 10 Growing to 430 MMcf/d and Fractionation capacity of 100,000 Bbl/d by the end of 2013 Mobley Sherwood Houston Majorsville Noble I Harrison de-ethanization Proposed Shell ethane cracker TEPPCO PRODUCTS PIPELINE EPD ATEX EXPRESS PIPELINE Sarsen & Bluestone INTERCONNECT TO 3RD PARTY PIPELINE Harrison I SUNOCO PIPELINE Joint venture with The Energy & Minerals Group (EMG) to develop significant midstream infrastructure to serve producers’ drilling programs in the liquids-rich Utica Shale in eastern Ohio EMG will fund the first $500 million of capital expenditures Recent Developments MarkWest has completed definitive agreements with Gulfport Energy Corporation to provide gathering, processing, fractionation and marketing for liquids-rich Utica production Letter agreement with Rex Energy to discuss similar midstream services Harrison Processing and Fractionation Complex Under Construction Harrison Interim (3Q12) 60 MMcf/d Harrison I (1Q13) 125 MMcf/d Harrison II (TBD) 200 MMcf/d C3+ Fractionation (4Q13) 60,000 Bbl/d Interconnect to TEPPCO pipeline (4Q13) Interconnect to ATEX pipeline (1Q14) De-ethanization (1Q14) 40,000 Bbl/d Truck Loading (mid-2013) 8 Bays Rail Loading (mid-2013) 200 Rail cars Noble Processing Complex Planned Construction Interim Noble Refridgeration (4Q12) 45 MMcf/d Noble I (2013) 200 MMcf/d NGL Pipelines Under Construction NGL Pipeline from Harrison to Majorsville (4Q13) NGL Pipeline from Harrison to Noble (4Q13)

Gulfport Energy Utica Shale Activity Map ~ 125,000 gross (62,500 net) acres Focused within the wet gas/retrograde condensate and mature oil windows of the Utica/Point Pleasant 5 year lease terms that are extendable with 5 year options Continue to pursue attractive acreage acquisition opportunities 50% interest / 100% operated 455 MBOE – 910 MBOE EUR / well (3) 781 gross locations (4) 36.4 MMBoe of gross original oil in place per section Asset Overview (1) 2012 Planned Activities (1) Currently running two rigs Plan to drill approximately 20 gross wells CAPEX (net): $72 to $76 million OHIO PENNSYLVANIA WEST VIRGINIA Chesapeake Mangun #8H 3.1 Mmcfpd + 1,015 Bblpd liquids Six 400 Bbl tanks on location Chesapeake Buell #8H 9.5 MMcfpd + 1,425 Bblpd liquids Six 400 Bbl tanks on location Anadarko Spencer #A-1H & #A-5H 2-Month Production: 20,000 Bbls of oil + 37 MMcf of gas Range Resources Zahn #1H 7-Day Average Test Rate of 4.4 MMcfepd East / Shell Patterson #2013 – 1HU Completed Chesapeake Neider #3H 3.8 MMcfpd + 980 Bblpd liquids Chesapeake Thompson #3H 6.4 MMcfpd Enervest RHDK Investments #8H Completed Rex Energy Cheeseman #1H 24-Hour Test Rate of 9.2 MMcfpd Antero Miley #5H Completed Hess / Marquette N. American Coal #3H-3 24-Hour Test Rate of 11 MMcfpd Chesapeake Shaw #5H Peak rate 2.9 Mmcfpd + 180 Bblpd of NGL + 770 Bblpd of oil Chesapeake Brown #10H Peak rate 1,445 Boepd (Inc. 8.7 MMcfpd of gas) Chesapeake Conglio #6H Peak Rate 5.0 Mmcfpd + 290 Bopd Gulfport Energy Wagner #1-28H Peak rate 17.1 MMcfpd + 432 Bblpd of condensate Gulfport Energy Boy Scout #1-33H Peak rate 7.1 MMcfpd + 1,560 Bblpd of condensate Gulfport Energy Ryser #1-25H Completing Gulfport Energy Shugert #1-12H Drilling Chesapeake Burgett #8H Peak rate 2.1 Mmcfpd + 140 Bblpd of NGL + 720 Bblpd of oil Anadarko Brookfield #A-3H 20 Day Production: ~9,500 Bbls of oil + ~12 MMcf of gas HG Energy Whitacre Enterprises #701 N-5H Completed Hess Capstone Holdings #2H-9 Drilled Gulfport Energy Shugert #1-1H Completed, Resting Gulfport Energy BK Stephens #1-16H Drilling Antero Rubel Unit Completed Gulfport Energy Groh #1-12H Completed, Resting Chesapeake Snoddy #6H Peak Rate 4.2 MMcfpd + 250 Bblpd of NGL + 320 Bblpd of oil Chesapeake Bailey #3H Peak Rate 5.7 MMcfpd + 270 Bblpd of NGL + 205 Bblpd of oil Source: Gulfport Energy Corp., Sept. 2012 11

MarkWest: The Midstream Leader in the Northeast Shales We Continue to Expand our Fully Integrated Services in the Marcellus and Utica We are the largest fractionator in Appalachia with 25 years of experience in NGL marketing We are the largest processor in the Marcellus and Huron Shales By 2014, we will have midstream infrastructure capable of: Supporting rich-gas production of nearly 3 Bcf/d C2+ fractionation capacity of approximately 275,000 Bbl/d Providing multiple market outlets for producers gas, ethane, propane, and heavier NGLs NGL marketing and logistics is the key 12 Majorsville Processing & De-Ethanization Mobley Processing Houston Processing & Fractionation Noble Processing Harrison Processing & Fractionation Keystone Processing Rich Utica Rich Marcellus Sherwood Processing

OUTLOOK FOR NGL SUPPLY AND DEMAND BALANCE

New Processing Plants About 12 BCFD of new gas processing being built by 2015. 32% will be built in the Marcellus/Utica region. 32% in the TX Inland region (Eagle Ford, Avalon/Bone Springs, Granite Wash and Cotton Valley plays). 12% in TX Gulf Coast region (Eagle Ford). 14 Source: En*Vantage, July 2012 2012 2013 2014 2015 Total Breakdown EIA Region MM Cfd MM Cfd MM Cfd MM Cfd MM Cfd % California 200 0 0 0 200 2% Rockies 250 110 750 0 1,110 9% N. Tier (Bakken) 100 425 0 0 525 4% Texas Inland 1,460 1,745 500 100 3,805 32% Texas Gulf Coast 450 550 400 0 1,400 12% Mid-Continent 260 350 200 0 810 7% SE New Mexico 0 250 100 0 350 3% Marcellus/Utica 1,030 2,545 200 0 3,775 32% Total 3,750 5,975 2,150 100 11,975 100% Announced Gas Processing Capacity

Forecast of US NGL Extraction Capability Gas processing industry’s NGL extraction capability should increase from 2.45 MM BPD in 2011 to about 3.36 MM BPD by 2020. Ethane extraction capability could increase from 1.04 MM BPD in 2011 to 1.60 MM BPD by 2020 period. Legacy NGLs are declining ~5%/yr from 2011 to 2020. By 2020 legacy NGLs will be at 1.04 MM BPD, new NGLs at 2.3 MM BPD. 15 Source: En*Vantage, July 2012 Forecast Max NGL Extraction Capability (1000 BDD) 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 Propane, Butanes, Natural Gasoline Ethane Forecast Forecast Max NGL Extraction Capability (1000 BDD) 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 Forecast Legacy NGLs New NGLs 1.59 MM BPD 1.04 MM BPD

Max US Ethane Supply Capability vs. Max Ethane Cracking Capability Through 2013, expect a close balance between ethane supply and demand. From 2014 to 2015 ethane supply overhang is likely, but it can easily be resolved by rejecting ethane in the Marcellus. In the 2014/2015 period ethane prices could be subject to extreme volatility. Post 2015, more ethane supplies will be needed to support more than two world-scale ethane crackers. Source: En*Vantage, July 2012 16 Max US Ethane Supply vs Max Ethane Cracking Capability (1000 BPD) 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 Low Probability New Plants High Probability New Plants US Ethane Cracked in Canada Converisons/Expansions/Restarts Base C2 Cracking Capability Max C2 Supply

 Outlook For US Propane Supply & Demand Propane supplies driven by gas processing, refinery supplies staying constant at best, imports trailing off. Ethylene feedstock demand for propane will be declining, offset by rising dehydrogenation demand for propane as four new PDH units will be built by 2018. Fuel demand for propane slowly declining MBPD. The export market will compete for the incremental propane barrel. Source: En*Vantage, July 2012 17 Forecast of US Propane Supplies (1000 BPD) 0 200 400 600 800 1000 1200 1400 2011 2012 2013 2014 2015 2016 2017 2018 Refining Propane Gas Processing Propane Imports Forecast of US Propane Demand (1000 BPD) 0 200 400 600 800 1000 1200 1400 2011 2012 2013 2014 2015 2016 2017 2018 Fuel Uses Propane Cracking Propane Dehydro Exports

Northeast Propane Supply and Distribution MarkWest has invested significant capital to develop a world-class processing, NGL fractionation, storage, and marketing complex with pipeline, rail, and truck facilities Waterborne and pipeline imports into the Northeast will decrease as local propane production increases Northeast markets can support significant propane sales from the Marcellus and Utica Shales In June, MarkWest began exporting Northeast propane from Sunoco’s Marcus Hook facility located outside Philadelphia, Pennsylvania to international markets 18

Emerging Resource Plays Base Production (Conventional / Tight Sand) Base Production (Conventional / Tight Sand) 19 Commitment to Resource Plays Capital investments and acquisitions in resource plays since 2004... ... are driving strong, long-term volume growth. CAGR = 14%

20 Commitment to Strong Distribution Growth and Unit Performance 220% Distribution Growth since IPO in May 2002 (12% CAGR) Unit price as of 8/16/12

FINANCIAL OVERVIEW

2012 DCF and Capital Guidance Liberty Northeast Southwest Utica * * The first $500 million of capex for the Utica JV will be funded by EMG, after which MarkWest will fund 100% of the capital requirements until it achieves 70% ownership. Gulf Coast 4th Inlet compressor Liquids-rich gas gathering system Majorsville III, IV, V, & VI processing plants Mobley I & II processing plants Sherwood I & II processing plants 115 Bbl/d de-ethanization capacity 50,000 Bbl/d Mariner West ethane project Multiple NGL and ethane pipelines 120 MMcf/d Carthage East cryogenic processing capacity 140 MMcf/d Haynesville gathering lines Compressor / pipeline additions New well connects / trunklines Other expansion 185 MMcf/d processing complex in Harrison County, Ohio 245 MMcf/d processing complex in Noble County, Ohio 100,000 Bbl/d fractionation, storage, and marketing complex in Harrison County, Ohio 150 MMcf/d Langley III processing plant 22 2012 DCF Forecast of $400 million to $440 million 2012 Capital Expenditures Forecast of $1.1 billion to $1.5 billion

Six months ended June 30, 2012 Net Operating Margin by Contract Type 2012 – 2014 Combined Hedge Percentage Risk Management Program NOTE: Net Operating Margin is calculated as segment revenue less purchased product costs. Fully Hedged 23 Six months ended June 30, 2012 Net Operating Margin Including Hedges Winter Propane Market vs MarkWest Production Summer Propane Market vs MarkWest Production

Increasing Fee-Based Net Operating Margin 24 Note: Forecast Assumes Crude Oil ($/bbl) range of $95.38 to $91.07 and Natural Gas ($/mmbtu) range of $2.74 to $3.98 By 2014, total net operating margin is forecasted to be greater than 60% fee-based

Source: CapIQ as of August 10, 2012 Cost of Equity Capital 25 0% 2% 4% 6% 8% 10% 12% 14% ETP NKA KMP WPZ CMLP EROC XTEX NS GLP EEP BWP RGP NGLS EPB PNG TLP BPL CPNO DPM PAA APL TCP SEP HEP OKS ACMP MWE SXL GEL WES EPD MMP Cost of Equity Capital Common Unit Yield IDR Load

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-in-class midstream services for our producer customers Preserve strong financial profile Deliver superior and sustainable total returns 26 EXECUTE, EXECUTE, EXECUTE!!!

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