Exhibit 99.1

Credit Suisse Energy Summit 2012 February 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 “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 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, 2010, and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011. 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. 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-wholly owned 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 4 Committed to maintaining strong financial profile Debt to book capitalization of 44% Debt to Adjusted EBITDA of 3.2x Adjusted EBITDA to Interest Expense of 4.3x 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 204% (12% CAGR) since IPO ~$5.0 billion in organic growth and expansion projects and acquisitions since IPO (includes the acquisition of the 49%, non-controlling interest of the Liberty JV) Proven ability to expand organizational capabilities Ranked #1 in EnergyPoint’s 2011 midstream customer satisfaction survey 2011 growth capital forecast of $675 million to $700 million 2012 growth capital forecast of $900 million to $1.3 billion 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 and Customer Satisfaction Strong Financial Profile Leading presence in six core natural gas producing regions of the U.S. Key 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 Substantial Growth Opportunities

Geographic Footprint SOUTHWEST Granite Wash, Woodford, Cotton Valley, Travis Peak, Haynesville 1.6 Bcf/d gathering capacity 655 MMcf/d processing capacity Arkoma Connector Pipeline JV NORTHEAST Huron/Berea Shale 505 MMcf/d processing capacity 24,000 Bbl/d NGL fractionation facility 285,000 barrel propane storage NGL marketing by truck, rail, & barge Infrastructure under construction Langley processing expansion LIBERTY Marcellus Shale 325 MMcf/d gathering capacity 625 MMcf/d cryogenic processing 60,000 Bbl/d C3+ fractionator Infrastructure under construction 920 MMcf/d processing capacity 115,000 Bbl/d de-ethanization 50,000 Bbl/d Mariner West project GULF COAST 140 MMcf/d cryogenic gas plant processing refinery off-gas 29,000 Bbl/d NGL fractionation capacity NGL marketing and transportation 5

Growth Driven by Customer Satisfaction 6 MarkWest Ranked #1 in Natural Gas Midstream Services Customer Satisfaction EnergyPoint Research, Inc. 2011 Customer Satisfaction Survey

7 Shale Plays Are Driving Natural Gas Supply

8 Resource Play Economics Source: Goldman Sachs – May 31, 2011

MarkWest’s Commitment to Resource Plays 9 Net capital investments in emerging resource plays since 2006 are driving strong, long-term volume growth. Emerging Resource Plays Base Production (Conventional / Tight Sand)

Long-term Appalachian History 10 MarkWest is the largest gas processor and fractionator in the Appalachian Basin MarkWest operates five gas processing plants with total capacity of approximately 505 MMcf/d, including recently acquired Langley complex NGLs are transported to Siloam for fractionation, storage, and marketing Propane and heavier fractionation capacity of 24,000 Bbl/d On-site NGL storage capacity of approximately 285,000 barrels with access to more than 1MM barrels of additional dedicated storage Midstream infrastructure under construction Expansion of cryogenic processing capacity at Langley complex MarkWest has operated vertically integrated gas processing and NGL fractionation, storage, and marketing in the Northeast for more than 20 years The Northeast provides premium markets for NGLs Fractionating NGLs into purity products is critical Marketing options must include truck, rail, and pipeline Storage is essential Langley NGL Pipeline Fractionation Facility Processing Plant

MarkWest Liberty Overview Competitive advantages Significant first-mover advantage in the prolific Marcellus Shale with key producer production commitments and acreage dedications in excess of 400,000 liquids-rich acres Critical gathering, processing, transportation, fractionation, storage, and marketing infrastructure On-site NGL storage capacity of approximately 52,000 barrels with access to more than 1MM barrels of additional dedicated storage Extensive NGL marketing experience in the Northeast Market Access Interconnected to Columbia Gas Transmission (CGT), National Fuel, TETCO, and TEPPCO Products Pipeline 50,000 Bbl/d Mariner West Project to deliver Marcellus ethane to Sarnia, Ontario markets under construction Gas gathering capacity 325 MMcf/d gathering capacity More than 200 miles of pipe and 72,000 hp of compression Cryogenic gas processing capacity 625 MMcf/d current capacity ~1.0 Bcf/d under construction NGL fractionation capacity 60,000 Bbl/d C3+ fractionation capacity 115,000 Bbl/d de-ethanization facility under construction 11

MarkWest Liberty Marcellus Project Schedule 12 MarkWest Liberty is developing integrated and scalable gathering, processing, fractionation, and marketing infrastructure to support production in excess of 1.5 Bcf/d TEPPCO PRODUCTS PIPELINE Majorsville I,II,III,IV Houston I,II,III Mobley I,II Sherwood I MARINER WEST PROPOSED EPD ETHANE PIPELINE PROPOSED MARINER EAST

Houston Processing and Fractionation Complex 13

Majorsville Processing and Fractionation Complex 14

Strong Forecasted Growth in Ethane Demand 15 Source: Wells Fargo Securities, LLC Ethane demand is forecasted to increase by more than 40% over the next 6 years Increased demand driven by Gulf Coast ethane crackers Heavy-to-light conversions New builds Expansions Re-starts Forecasted ethane supply includes ethane from the Marcellus Shale

MarkWest Liberty has the ability to recover ethane at all of its processing plants and to transport the ethane to de-ethanization facilities via its extensive NGL gathering system MarkWest Liberty is developing three large de-ethanizers at its Houston and Majorsville processing complexes The first phase will have capacity of 75,000 Bbl/d and will commence operation in mid-2013 to coincide with the start-up of Mariner West The second phase will increase the capacity to 115,000 Bbl/d of ethane and will be online in 2014 MarkWest will also construct an ethane pipeline to transport ethane from Majorsville to Houston MarkWest Liberty’s Processing Complexes Support Ethane Recovery MW Liberty Planned Ethane Fractionation Capacity MW Liberty Must Recover Ethane MW Liberty Total Recoverable Ethane 16

Marcellus Ethane – A Third-Party Viewpoint 17 Implied Ethane Production In the Marcellus Based on Processing Capacity Source: Wells Fargo, January 2012

Project Mariner: A Comprehensive Ethane Solution 18 MarkWest Houston Fractionator Mariner East Mariner West New MarkWest Liberty Pipeline Existing Sunoco Pipeline Existing Sunoco Pipeline Sarnia Pittsburgh Philadelphia

Project Mariner: A Comprehensive Ethane Solution MarkWest Liberty and Sunoco Logistics are developing efficient and scalable ethane projects that meet producers’ ethane production schedules and provide access to attractive NGL markets in North America and Europe Project Mariner requires minimal pipeline construction – a combined total of approximately 85 miles of new pipe is required to deliver ethane to the Sarnia, Gulf Coast, and European markets Project Mariner will have access to ethane storage at Sarnia and would construct ethane storage at Philadelphia and the Gulf Coast near Nederland, Texas Mariner West is scheduled to come online in mid-2013 for transportation to Sarnia, with potential future ethane deliveries to favorable European and Gulf Coast markets via Mariner East The capacity of Sunoco Logistics’ 8-inch pipeline to Philadelphia can be increased to meet increased demand 19 Sarnia Pittsburgh Gulf Coast Philadelphia

MarkWest Utica Overview Joint venture with The Energy & Minerals Group (EMG) Long-term partnership to develop significant natural gas processing and NGL fractionation, transportation, and marketing infrastructure to serve producers’ drilling programs in the Utica shale in eastern Ohio Partners one of the best midstream companies with a strong financial partner that share a common view towards the value of the Utica Allows MarkWest to meet the significant gathering and processing needs of its producer customers while significantly reducing MWE’s up-front capital Competitive advantages Extensive gathering, processing, transportation, fractionation, storage, and marketing infrastructure throughout the Appalachian region Extensive NGL marketing experience in the Northeast Announced midstream development 200 MMcf/d cryogenic processing complex in Harrison County, Ohio by mid-2013 Monroe County, OH processing complex in 2013 100,000 Bbl/d fractionation, storage, and marketing complex in Harrison County in 2013 20 Mobley Sherwood NGL pipeline TEPPCO Pipeline 200 MMcf/d Harrison processing plant Monroe processing plant 100,000 Bbl/d fractionation and marketing facilities Houston NGL pipeline Majorsville

MarkWest is the Midstream Leader in Northeast Shale's 21 Siloam Langley Kenova Cobb Kermit Boldman Majorsville Houston Mobley Marcellus Shale Huron Shale Utica Shale Sherwood Harrison Monroe

Financial Overview

2011 and 2012 DCF and Capital Expenditure Forecast 2011 DCF forecast of $325 million to $345 million 2011 capital expenditure forecast of $675 million to $700 million* Southwest $85 to $90 Northeast $270 to $280 Liberty $320 to $330 * Includes the $230 million Langley/Ranger acquisition from EQT Liquids-rich gas gathering system Houston III processing plant Majorsville II processing plant Mobley I processing plant Sherwood I processing plant Fractionation facility NGL pipeline Railyard / truck loading facility Liberty Northeast Southwest Arapaho III processing plant Haynesville gathering lines Compressor / pipeline additions New well connects / trunklines Other expansion Langley III processing plant Completion of Ranger NGL pipeline EQT Acquisition: Langley processing complex ~28,000 horsepower of compression Partially constructed Ranger NGL pipeline 23 2012 DCF forecast of $480 million to $540 million 2012 capital expenditure forecast of $900 million to $1.3 billion

Capital Markets and Liquidity Update MarkWest focuses on the right timing and size of capital market activities to fund capital expenditures while consistently improving its credit metrics and maintaining a strong liquidity position In 2011, the Partnership completed four equity offerings and three senior note offerings for combined net proceeds of $2.3 billion The proceeds were used to fund the $230 million EQT acquisition as well as the refinancing of $275 million of the 2016 senior notes and approximately $420 million of the 2018 senior notes in addition to providing working capital for general partnership purposes The refinancing resulted in a significant reduction of annual interest expense and significantly extended the maturity of the Partnership’s debt The Partnership extended its credit facility by one year to 2016, lowered the pricing grid by 75 bps, and increased the size to $900 million Overall, the Partnership’s weighted average cost of capital has come down by more than 200 basis points in the past year 24 In January 2012, MarkWest had available liquidity of $1 billion

Capital Structure ($ in millions) As of December 31, 2010 As of September 30, 2011 As Adjusted September 30, 2011(1) Cash $ 67.5 $ 159.2 $ 219.8 Credit Facility – 145.1 – 8-1/2% Senior Notes due 2016 274.3 – – 8-3/4% Senior Notes due 2018 499.1 333.8 81.0 6-3/4% Senior Notes due 2020 500.0 500.0 500.0 6-1/2% Senior Notes due 2021 – 499.0 499.0 6-1/2% Senior Notes due 2022 – – 700.0 Total Debt $ 1,273.4 $ 1,478.0 $ 1,780.0 Total Equity $ 1,536.0 $ 1,909.1 $ 1,691.6 (2) Total Capitalization $ 2,809.4 $ 3,387.1 $ 3,471.6 LTM Adjusted EBITDA (3) $ 333.1 $ 411.4 $ 475.5 Total Debt / Capitalization 45% 44% 51% Total Debt / LTM Adjusted EBITDA (4) 3.5x 3.2x 3.4x Adjusted EBITDA / Interest Expense (4) 3.5x 4.3x 4.2x Adjusted for the net proceeds from the October 2011 equity offering of approximately $251 million, the net proceeds from the November 2011 senior note offering of approximately $688 million, the repurchase of approximately $253 million of the 2018 Senior Notes in November 2011, the net proceeds from the December 2011 equity offering of approximately $559 million, the MarkWest Liberty Midstream acquisition, and the issuance of Class B Units to EMG. Reflects after-tax charges of approximately $32.3 million associated with the partial retirement of the 2018 Notes, the difference between the fair value of the consideration paid to EMG and the carrying value of EMG’s non-controlling interest on the closing date (approx $1.3 billion), the fair value of the Class B units issued to EMG (approx. $800 million), and the non-controlling interest amount equal to the carrying value of the interest acquired from EMG (approx. $459 million as of September 30, 2011). 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. 25

Strong Distribution Growth and Unit Performance $60.00 $50.00 $40.00 $30.00 $20.00 $10.00 $0.00 Unit Price ($) 204% Distribution Growth since IPO in May 2002 (12% CAGR) Distribution per Common Unit Distribution Unit Price 2002* 2003 2004 2005 2006 2007 2008 2009 2010 2011

Cost of Equity Capital Source: CapIQ as of January 31, 2012 27 0% 2% 4% 6% 8% 10% 12% 14% 16% NKA ETP KMP NS GLP BWP TLP PNG XTEX HEP EEP CMLP EROC PAA RGP NGLS EPB TCP CPNO SEP WPZ DPM BPL GEL APL SXL OKS CHKM MWE EPD MMP WES 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-of-class midstream services for our producer customers Preserve strong financial profile Deliver superior and sustainable total returns EXECUTE, EXECUTE, EXECUTE !!! 28

Appendix 29

Reconciliation of DCF and Distribution Coverage ($ in millions) Year ended December 31, 2010 Nine months ended September 30, 2011 Net income $ 31.1 $ 168.0 Depreciation, amortization, impairment, and other non-cash operating expenses 167.7 148.7 Loss on redemption of debt, net of tax benefit 42.0 39.6 Non-cash (earnings) loss from unconsolidated affiliates (1.6) 1.3 Distributions from unconsolidated affiliates 2.5 0.3 Non-cash derivative activity 23.9 (102.7) Non-cash compensation expense 7.5 3.7 Provision for income tax – deferred (4.5) 18.3 Cash adjustment for non-controlling interest of consolidated subsidiaries (30.6) (46.3) Revenue deferral adjustment – 12.9 Other 13.1 8.4 Maintenance capital expenditures, net of joint venture partner contributions (10.0) (7.8) Distributable cash flow (DCF) $ 241.1 $ 244.4 Total distributions declared for the period $ 186.0 $ 167.8 Distribution coverage ratio (DCF / Total distributions declared) 1.30x 1.46x 30

Reconciliation of Adjusted EBITDA ($ in millions) Year ended December 31, 2009 Year ended December 31, 2010 LTM ended September 30, 2011 Net income (loss) $ (113.4) $ 31.1 $ 124.8 Non-cash compensation expense 3.9 7.5 4.8 Non-cash derivative activity 222.8 24.7 (64.0) Interest expense 1 94.6 105.2 107.7 Depreciation, amortization, impairments, and other non-cash operating expenses 144.4 167.7 193.9 Loss on redemption of debt – 46.3 89.7 Provision for income tax (42.0) 3.2 19.5 Gain on sale of unconsolidated affiliate (6.8) – – Adjustment for cash flow from unconsolidated affiliate (1.7) 1.0 1.3 Adjustment related to non-wholly owned, consolidated subsidiaries (22.6) (52.3) (64.4) Other – (1.3) (1.9) Adjusted EBITDA $ 279.2 $ 333.1 $ 411.4 (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. 31

Reconciliation of Net Operating Margin ($ in millions) Year ended December 31, 2010 Nine months ended September 30, 2011 Income from operations $ 188.5 $ 325.7 Facility expense 151.4 124.4 Derivative activity 80.4 (46.9) Revenue deferral adjustment – 12.9 Selling, general and administrative expenses 75.3 60.5 Depreciation 123.2 110.3 Amortization of intangible assets 40.8 32.6 Loss on disposal of property, plant, and equipment 3.1 4.6 Accretion of asset retirement obligations 0.2 0.9 Net operating margin $ 662.9 $ 625.0 32

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 33