Exhibit 99.1

MORGAN STANLEY MIDSTREAM MLP & DIVERSIFIED NATURAL GAS EVENT MARCH 5, 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

Key Investment Considerations Quarterly Distribution Growth of 244% Since IPO Leading presence in major resource plays including Marcellus, Utica, Huron/Berea, Woodford, Haynesville and Granite Wash Largest processor in the Marcellus and Utica Shales Largest fractionator in the Northeast HIGH-QUALITY DIVERSIFIED ASSETS PROVEN GROWTH &CUSTOMER SATISFACTION SUBSTANTIAL GROWTH OPPORTUNITIES STRONG FINANCIAL PROFILE Over $9 billion of organic growth and acquisitions since IPO Over $6 billion invested in Marcellus and Utica since 2008 Received top ranking in EnergyPoint’s 2013 Midstream Customer Satisfaction survey 2014 growth capital forecast of $1.8 to $2.3 billion 19 major processing and fractionation projects under construction Long-term agreements with over 25 major producer customers Established relationships & joint venture partners No incentive distribution rights, which drives a lower cost of capital Distributions have increased by 244% (11.6% CAGR) since IPO Growing fee-based margin to over 70% for full-year 2014 4

Southwest Best-in-class midstream services in the Granite Wash, Haynesville, Woodford and Eagle Ford Shales with over 1.9 Bcf/d of gathering capacity and over 1 Bcf/d of processing capacity Largest processor and fractionator in the Marcellus Shale with over 2.2 Bcf/d of processing capacity and 172,000 Bbl/d of C2+ fractionation capacity. Growing to over 3.7 Bcf/d of processing capacity and over 300,000 Bbl/d of C2+ fractionation capacity Marcellus Largest processor and fractionator in the southern Appalachian Basin Northeast MarkWest Assets: Expansion & Diversification Developing a leading position in the southern core of the Utica Shale with 585 MMcf/d of processing capacity. Growing to over 1.1 Bcf/d of processing capacity and over 100,000 Bbl/d of C2+ fractionation capacity Utica 5

U.S. Shale Plays Are Driving Natural Gas Supply 6 EIA data concludes that natural gas supply will increase by approximately 25% by 2030 driven primarily by increased demand by power generation and transportation sectors. Essentially all of the supply increase will be met by shale gas production. From 2013 to 2030, shale gas production will increase by 65% and in 2030 it will account for 48% of total U.S. natural gas supply Resource plays will continue to drive midstream investment for decades to come and MarkWest will continue to focus our investments in these areas Source: U.S. Energy Information Administration, Annual Energy Outlook 2013 Early Release 2013 36% 24% 1% 6% 7% 11% 15% 22% 4% 6% 5% 7% 8% 48% U.S. Dry Natural Gas Production (trillion cubic feet per year)

MarkWest has received the top rating in three of the last four EnergyPoint Research surveys Growth Driven by Customer Satisfaction 7 7

Utica 13% Marcellus 47% Northeast 9% Southwest 31% 2014 Forecasted Operating Income by Segment 8 * *Utica Operating Income Percentage is Gross of Non-Controlling Interest

Marcellus & Utica: Driving U.S. Gas Production Growth 9 Source: Bloomberg (LCI Energy Insight Estimates), MarkWest Energy Partners, L.P. Wellhead gas production (before flaring and NGL extraction)

Marcellus Segment Key Considerations We are the largest processor of natural gas and fractionator of natural gas liquids in the Marcellus Shale Operate fully integrated gathering, processing, fractionation, storage and marketing operations Areas of Operation Southwest and Northwest Pennsylvania, Northern West Virginia Resource Plays Marcellus Shale Gathering 615 MMcf/d capacity Processing 2.2 Bcf/d cryogenic capacity Fractionation 172,000 Bbl/d total C2+ capacity: 98 MBbl/d at Houston, 38 MM BBl/d at Majorsville, and 60% of 60 MBbl/d at Hopedale NGL Marketing & Storage NGL Marketing by truck and large-scale rail facility 90,000 Bbl NGL storage capacity with access to more than 900,000 Bbls of propane storage Under Construction Processing 1.5 Bcf/d cryogenic capacity Fractionation 136,000 Bbl/d C2+ capacity NGL Transportation Extensive NGL gathering system with access to purity ethane projects 10 2014 Forecasted Segment Operating Income

MarkWest Marcellus: Current Processing Capacity of 2.2 Bcf/d 11 Growing to over 3.7 Bcf/d of processing capacity Bluestone II Majorsville IV Mobley IV Sherwood IV, V Sarsen Bluestone I Houston I-III Majorsville I-III, V Mobley I – III Sherwood I – III Bluestone III Houston IV Majorsville VI 2015+ 2014 Current

Marcellus Segment Overview 12 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

Utica Segment Key Considerations We are developing a leading position in the southern core of the highly prospective Utica Shale We have partnered with The Energy & Minerals Group (EMG) to develop fully integrated gathering, processing, fractionation, storage and marketing operations 13 2014 Forecasted Segment Operating Income* Areas of Operation Eastern Ohio Resource Plays Utica Shale Gathering 185 MMcf/d capacity Processing 585 MMcf/d capacity Fractionation 40% of 60,000 Bbl/d C3+ at Hopedale Marketing Large scale rail and truck loading in Harrison County, Ohio Under Construction Processing 600 MMcf/d cryogenic capacity 200 MMcf/d at Cadiz Complex 400 MMcf/d at Seneca Complex Fractionation 78,000 Bbl/d C2 capacity NGL Transportation Extensive NGL gathering system, interconnects to TEPPCO and ATEX pipelines *Utica Operating Income Percentage is Gross of Non-Controlling Interest

Utica Processing Capacity 14 Seneca I, II Cadiz I & Refrigeration Cadiz II Seneca III Seneca IV 2015 2014 Current Growing to over 1.1 Bcf/d of processing capacity

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 Ohio MWE Utica Counties MWE Marcellus Counties MWE Plants ATEX Express Pipeline TEPPCO Product Pipeline Jefferson WEST VIRGINIA Marcellus & Utica: 23 Major Projects Complete Mariner Projects Rich Utica Rich Marcellus MWE Gathering Area 15 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 OHIO PENNSYLVANIA

Virginia Michigan West Virginia Pennsylvania Gathering & Processing NGL Transportation & Marketing NGL Gathering & Fractionation Fully integrated NGL transportation, fractionation and logistics solutions in the Marcellus and Utica Shales Growing to over 400 MBbls/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 nearly 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 Gulf Coast Mobley Sherwood Keystone Seneca Lake Erie MWE Gathering Systems Rich-Gas Areas TEPPCO Product Pipeline Mariner East Mariner West Utica Marcellus Texas Pipeline (UMTP) Marcellus & Utica: Full-Service Capabilities Houston Hopedale Cadiz Condensate JV 16 Ohio Majorsville

17 Northeast Ethane: Innovative Solutions MarkWest is currently operating two large-scale de-ethanization facilities in the Northeast: a 38,000 Bbl/d unit at the Houston complex and a 38,000 Bbl/d unit at the Majorsville complex During the second quarter of 2014, MarkWest will begin operations of its third de-ethanization facility—a 40,000 Bbl/d unit in the Utica Shale MarkWest’s customers will have direct access to all the Northeast purity ethane pipeline projects, including Mariner West, Mariner East and ATEX Marcellus and Utica producers are expected to recover sufficient ethane to meet their firm downstream obligations and residue gas pipeline quality specifications MarkWest’s fractionation solutions are a critical link to the successful development of ethane pipeline projects in the Northeast

Hopedale Fractionator: Growing Our Integrated Asset Base 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 the MarkWest’s extensive Marcellus infrastructure in order to provide the most comprehensive and fully integrated system for fractionation and liquids marketing The complex includes extensive purity product storage capacity and critical logistics marketing infrastructure, including a large-scale rail yard and truck loading docks 18

LPG Exports by World Region 19 North America expected to increase exports by from 2013-2030 76% The shale gas revolution taking place in key U.S. resources plays such as the Marcellus and Utica Shales is set to rapidly increase North America LPG supply over the coming decades The Middle East will remain the dominant exporter of LPGs, but North America will serve as a key export player in the global marketplace North America to provide substantial LPG export supply Source: IHS CERA

World LPG Demand by Region Asia will become the primary demand market for LPG, as strong economic growth and rise in personal incomes will drive consumption LPG imports in Asia will be necessary as demand far exceeds regional supply New propane dehydrogenation (PDH) units slated to be built in China will serve as a key source of demand for world LPG Asian Demand for LPG at Forefront The Navigator Gas Vessel. Photo courtesy of Navigatorgas.com 20 Source: IHS CERA

Capital Investments 2014 Capital Forecast by Segment 21 2014 Capital Forecast by Category 2014 Capital Expenditures Forecast of $1.8 to $2.3 billion Utica 26% Southwest 7% Marcellus 67%

Liquidity 22 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% 23 Increase of ~3x since 2008 Over 70% 25% 39% 38% 38% 53% 61%

Total Volume Growth 24 Base case total volumes are forecasted to increase over 50% from 2013 42% 62% 52%

Distributable Cash Flow: Forecast 24% 33% 43% DCF of $483.4 million 2014 DCF Forecast of $600 to $690 million 25

MarkWest Investment Considerations: What to Expect Maintain strong customer base in key resource plays with high-quality assets and exceptional service Continue to execute on growth projects that are well diversified across the asset base Annual DCF growth of 35% in 2014 and accelerating as volumes increase Fee-based margin increasing to 70% for the full-year 2014 Long-term distribution growth in excess of 10% as Northeast shale facilities are completed and producer volumes increase 26 Long-term sustainable total returns in top quartile of MLP industry

APPENDIX

Reconciliation of DCF and Distribution Coverage 28 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 29 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

Reconciliation of Net Operating Margin 30 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