Exhibit 99.1

 Morgan Stanley Midstream MLP & Diversified Natural Gas Corporate Access Event March 5, 2013

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, 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 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 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. 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 No incentive distribution rights, which drives a lower cost of capital Distributions have increased by 224% (12% CAGR) since IPO Over $7 billion of organic growth and acquisitions since IPO Ranked #1 in EnergyPoint’s 2011 midstream customer satisfaction survey 2013 growth capital forecast of $1.5 to $1.8 billion Growth projects are well diversified across the asset base and increase the percentage of fee-based net operating margin Long-term organic growth opportunities focused on resource plays 4 Committed to maintaining strong financial profile Debt to book capitalization of 44% Debt to Adjusted EBITDA of 4.34x Adjusted EBITDA to Interest Expense of 5.01x Established relationships with joint venture partners, which provides capital flexibility

MarkWest Operational Assets SOUTHWEST Granite Wash, Haynesville Shale, Woodford Shale, Gulf Coast 1.6 Bcf/d gathering capacity 917 MMcf/d processing 29 MBbl/d NGL fractionation capacity 1.5 Bcf/d transmission capacity including Arkoma Connector Pipeline NGL marketing and transportation NORTHEAST Huron/Berea Shale 652 MMcf/d processing 24 MBbl/d fractionation 285 MBbl NGL storage NGL marketing by truck, rail, & barge LIBERTY Marcellus Shale 525 MMcf/d gathering 1.2 Bcf/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 UTICA Utica Shale Joint Venture with EMG 60 MMcf/d processing Under construction: 725 MMcf/d processing 100 MBbl/d fractionation, storage, and marketing complex in Harrison County, Ohio 5

Growth Driven by Customer Satisfaction 6 Ranked #1 in Midstream Customer Satisfaction Survey for 2011 Since 2006, we have been ranked #1 or #2 by EnergyPoint Research

U.S. Shale Plays are Driving Natural Gas Supply 7 EIA data concludes shale gas development will increase from 8.1 trillion cubic feet in 2012 to 11.0 trillion cubic feet by 2020, a 36% increase. In 2020, shale gas will account for 42% of total U.S. dry natural gas production MarkWest is focused on midstream development in resource plays (Marcellus, Utica, Granite Wash, Haynesville, Huron, Woodford) and has benefited tremendously from the advantages of being a first mover Source: U.S. Energy Information Administration, Annual Energy Outlook 2013 Early Release 2012 34% 24% 2% 7% 7% 10% 16% 24% 1% 5% 6% 11% 11%

U.S. Shale Play Volume Growth 8 In 2012, the Marcellus Shale became the largest producing natural gas resource play in the U.S. Sources: EIA, Lippman Consulting, Inc. gross withdrawal estimates as of December 2012 and converted to dry production estimates with EIA-calculated average gross-to-dry shrinkage factors by state and/or shale play. Barnett Haynesville Marcellus

Emerging Resource Plays Base Production (Conventional / Tight Sand) Base Production (Conventional / Tight Sand) 9 Commitment to Resource Plays Capital investments and acquisitions in resource plays since 2004 are driving strong, long-term volume growth.

 2013 Forecasted Segment Operating Income Contributions to Operating Income by Segment 2013 Segment Forecasted Operating Income 2013 Forecasted Segment Operating Income 40% 14% 44% 2% Southwest Liberty Utica Northeast 10 2013 Forecasted Segment Operating Income

Southwest Segment Competitive advantages Rated 1st for midstream services in East Texas, Midcontinent and Texas Intrastate by large customers Recently constructed gathering systems provide low-pressure and fuel-efficient service Ready access to markets with interconnects to CEGT, NGPL, TGT, ANR, PEPL, CFS and Enogex East Texas system overlays the rich Haynesville core and we recently completed a 120 MMcf/d processing expansion We own and operate the Javelina facility in Corpus Christi, Texas that processes and fractionates off-gas from six local area refineries Under Construction 120 MMcf/d processing in Woodford Shale with Centrahoma, a joint venture with Atlas Pipeline, L.P. Areas of Operation Oklahoma, Texas, and New Mexico Resource Plays Woodford Shale, Granite Wash, Haynesville Shale, Anadarko Basin, Cotton Valley, Travis Peak, Petitt, Permian Basin Gathering 1.6 Bcf/d capacity Fractionation 29,000 Bbl/d capacity Processing 917 MMcf/d capacity Transportation 1.5 Bcf/d transmission capacity, including Arkoma Connector Pipeline JV with ArcLight Capital Partners 11 2013 Forecasted Segment Operating Income

Northeast Segment Competitive advantages Rated 1st for midstream services in the Appalachian Basin by all customers We are the largest gas processor and fractionator in the Appalachian Basin We have operated vertically integrated gas processing, fractionation, storage, and marketing in the Northeast for nearly 25 years In Appalachia, approximately 60% of the volume we process and fractionate is under contract for at least 10 years Areas of Operation Kentucky, West Virginia, Michigan Resource Plays Appalachian Basin, Huron/Berea Shale, the Niagaran Reef Processing 652 MMcf/d capacity Fractionation 24,000 Bbl/d capacity NGL Marketing & Storage NGL marketing by truck, rail and barge 285,000 Bbl NGL capacity with access to 1.2 MBbls of propane storage Transportation 250 mile crude oil transmission pipeline 12 2013 Forecasted Segment Operating Income

Liberty Segment Competitive advantages Rated 1st for midstream services in the Marcellus Shale 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. Average historical plant utilization rates are approximately 60% within a 12 month period following commissioning and continuing to increase to 70% to 80% in the first 18 months and we anticipate similar utilization rates for new plants Ready access to markets with interconnects to Columbia Gas, National Fuel, TETCO, and TEPPCO Products Pipeline Acquisition of Keystone Midstream Services, LLC: Supports extension of NGL gathering into Northwest PA Added two new significant customers Areas of Operation Southwest and Northwest Pennsylvania and northern West Virginia Resource Plays Marcellus Shale Gathering 525 MMcf/d capacity Processing 1.2 Bcf/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 storage capacity with access to 1.2 MBbls 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 13 2013 Forecasted Segment Operating Income

MarkWest Liberty: Current Processing Capacity of 1.2 Bcf/d 14 Growing to nearly 3 Bcf/d of processing capacity in the Marcellus Shale by 2014 TEPPCO PRODUCTS PIPELINE SUNOCO PIPELINE EPD ATEX EXPRESS PIPELINE 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, III Mobley I, II, III Hopedale Fractionation & marketing facilities Sarsen Bluestone I Majorsville I-II Houston I-III Mobley I, II Sherwood I Majorsville III, V Mobley III Sherwood II, III Bluestone II, III Majorsville IV, VI 2014 2013 Current Mariner East

Liberty Project Schedule 15 Current Operations Project Schedule Houston I, II & III 355 MMcf/d De-ethanization 38,000 Bbl/d 3Q13 C3+ Fractionation 60,000 Bbl/d Mariner West ethane pipeline 50,000 Bbl/d 3Q13 Interconnect to TEPPCO pipeline Rail Loading 200 Rail cars Truck Loading 12 Bays Majorsville I & II 270 MMcf/d Majorsville III 200 MMcf/d 2Q13 NGL Pipeline to Houston 43,400 Bbl/d Majorsville IV 200 MMcf/d 1Q14 Majorsville V 200 MMcf/d 4Q13 Majorsville VI 200 MMcf/d 2014 De-ethanization I 38,000 Bbl/d 4Q13 De-ethanization II 38,000 Bbl/d 1Q14 Purity Ethane Pipeline to Houston 3Q13 Mobley I 200 MMcf/d Mobley III 200 MMcf/d 4Q13 Mobley II 120 MMcf/d NGL Pipeline to Majorsville Sherwood I 200 MMcf/d Sherwood II 200 MMcf/d 2Q13 Sherwood III 200 MMcf/d 3Q13 200 NGL Pipeline to Mobley 1Q13 Sarsen 40 MMcf/d Bluestone II 120 MMcf/d 2Q14 Bluestone I 50 MMcf/d Bluestone III 200 MMcf/d TBD NGL Pipeline into Northwest PA 1Q14 Sherwood Processing Complex Sherwood Processing Complex Keystone Processing Complex Keystone Processing Complex Houston Processing and Fractionation Complex Houston Processing and Fractionation Complex Majorsville Processing and Fractionation Complex Majorsville Processing and Fractionation Complex Mobley Processing Complex Mobley Processing Complex

Utica Segment Competitive advantages 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 $950 million of capital expenditures MarkWest has completed definitive agreements with Gulfport Energy Corporation, Antero Resources, and Rex Energy 785 MMcf/d of processing capacity and 100,000 Bbl/d of fractionation capacity by 2014. Based on Utica well results and historical plant utilization rates, we anticipate achieving a 60% or better utilization within a 12 month period following commissioning Areas of Operation Eastern Ohio Resource Plays Utica Shale Under Construction Processing: 725 MMcf/d cryogenic capacity 325 MMcf/d at Cadiz Complex 400 MMcf/d at Seneca Complex Fractionation: 100,000 Bbl/d C2+ capacity NGL Transportation: Extensive NGL gathering system, interconnects to TEPPCO and ATEX pipelines as well as rail and truck loading Marketing: 200 car rail facility and a 8 bay truck loading in Harrison County, Ohio 16 2013 Segment Forecasted Operating Income

Utica Development Timeline 17 MarkWest Utica EMG joint venture is formed Agreement with Rex Energy to provide gathering, processing, fractionation and marketing June 2012 January 2012 Agreement with Antero Resources to provide processing in Noble County and fractionation and marketing in Harrison County Cadiz Interim Refrigeration plant is completed in Harrison County 4 Construction begins on the Seneca complex in Noble County 3 November 2012 Construction begins on the Cadiz complex in Harrison County 1 April 2012 February 2013 November 2012 1 2 4 Agreement with Gulfport Energy to provide gathering, processing, fractionation and marketing in Harrison, Guernsey, and Belmont counties 2 December 2012 Four plants with 725 MMcf/d cryogenic processing capacity and 100,000 Bbl/d of fractionation capacity coming online by 20145 2013 3 5

MarkWest Utica EMG JV Processing Capacity 18 Growing to nearly 600 MMcf/d of processing capacity in the Utica Shale by the end of 2013 Cadiz II, Cadiz Interim Cadiz I Seneca I, II 2013 Current Mobley Sherwood Houston Majorsville Seneca I, II Hopedale Fractionator TEPPCO PRODUCTS PIPELINE EPD ATEX EXPRESS PIPELINE Sarsen & Bluestone INTERCONNECT TO 3RD PARTY PIPELINE Cadiz I, II and De-ethanization SUNOCO PIPELINE 2014

MarkWest Utica EMG JV Project Schedule 19 Utica Project Schedule Cadiz interim Refrigeration 60 MMcf/d Completed Cadiz I 125 MMcf/d 2Q13 Cadiz II 200 MMcf/d 2Q14 Initial truck and rail loading 3Q13 NGL pipeline to Hopedale Fractionator Mid-2013 C3+ Fractionation 60,000 Bbl/d 1Q14 De-ethanization I 40,000 Bbl/d 1Q14 Interconnect with ATEX pipeline 1Q14 Interconnect with TEPPCO pipeline 1Q14 Truck Loading 8 Bays Mid-2013 Rail Loading 200 Rail cars Mid-2013 Seneca I 200 MMcf/d 3Q13 Seneca II 200 MMcf/d 4Q13 NGL Pipeline to Hopedale Fractionator 1Q14 NGL Pipeline from Majorsville to Hopedale Fractionator 1Q14 Other Cadiz Processing Complex in Harrison County, Ohio Hopedale Fractionation Complex in Harrison County, Ohio Seneca Processing Complex in Noble County, Ohio

Our core area, where we believe we have a competitive advantage, covers approximately 1.5 million acres. Additional producers identified in the core area have combined acreage of between 200,000 and 250,000 acres Additional Opportunities in Core Area Summary of Opportunity MarkWest Utica EMG now has the critical mass and full spectrum of services to enable us to capture a significant portion of the production inside our core area Utica producers are interested in fee based agreements and are willing to provide volume backstops Utica Shale - Tremendous Opportunity MarkWest Utica Core Area 20

100% 34% 44% 22% MarkWest Marcellus & Utica Fractionation Capacity 21 Approximately 275,000 Bbl/d of fractionation capacity in the Marcellus and Utica Shales by 2014 2014 2013 Current 2014: Majorsville De-Ethanization 38,000 Bbl/d 2013: Majorsville De-Ethanization 38,000 Bbl/d 2013: Houston De-Ethanization 38,000 Bbl/d 2012: Houston C3+ Fractionation 60,000 Bbl/d 2014 175,000 Bbl/d 100,000 Bbl/d Liberty Utica 2014: Harrison C3+ Fractionation 60,000 Bbl/d 2014: Harrison De-Ethanization 40,000 Bbl/d

MarkWest’s Perspective on Northeast Ethane Production Prior to July of this year, no ethane will be recovered (other than at MarkWest's Keystone facilities) and some residue pipelines may reject gas deliveries due to high Btu content Between July of this year and the start-up of the ATEX pipeline in early 2014, the Mariner West project will be the only active ethane project and MarkWest will be the only processor recovering ethane In 2013 through 2015 Marcellus and Utica producers will probably only recover the minimum amount of ethane in order for their residue gas to meet gas quality specifications By 2017, MarkWest’s producer customers could produce as much as 200,000 Bbl/d of ethane We estimate that our producer customers have committed between 100,000 and 125,000 Bbl/d to current ethane projects 22 Purity product pipeline projects in Marcellus and Utica will maximize producer economics Image Source: BENTEK and MarkWest Mobley Processing Seneca Processing Cadiz Processing & Hopedale Fractionation Rich Utica Rich Marcellus Sherwood Processing Marketing Capabilities Truck Rail Pipe Boat Majorsville Processing & De-Ethanization Houston Processing & Fractionation Keystone Processing 40 Mb/d TEPPCO ATEX Mariner Pipelines Mariner West Mariner East

Northeast Propane Supply and Demand 23 The Targa and Enterprise Gulf Coast export facilities should create sufficient demand to offset growth in NGLs in 2013 and 2014 New PDH plants will also increase long-term propane demand MarkWest has led the Northeast propane export efforts and we have been exporting propane internationally since June 2012 MarkWest and Range Resources have committed to 25,000 Bbl/d of propane export capacity on Mariner East Important to watch whether producers in northern Utica counties like Carroll and Columbiana, OH, and northwestern PA can address the frac barrier challenges. If so, PADD I may no longer be a net importer in the winter and a new y-grade pipeline may have economic justification Exports in the Northeast are key to maintaining the supply short position of PADD I in the winter. Every month that PADD I is a net importer, Northeast producers make an additional $0.10 to $0.25 per wellhead Mcf Photo by Wheeling & Lake Erie Railway Co. MarkWest Houston Rail Yard

Northeast Butanes and Gasoline Supply and Demand 24 Marcellus natural gasoline already serves western Canadian heavy oil markets and Utica condensate production will increase access to these markets. Marcellus natural gasoline will maintain its transportation advantage over the US Gulf Coast supplies Northeast iso-butane will continue to effectively compete with Canadian, Midwestern US, and Gulf Coast iso-butane supplies, and Northeast iso-butane will maintain its advantaged pricing over normal butane For the Northeast, the saying was “propane was the new ethane” but that has evolved into “butane is the new propane” The Northeast supply and demand balance would be helped by either new butane isomerization capacity or a butane export facility. A new y-grade pipeline would also effectively increase Northeast butane demand We continue to analyze the installation of an isomerization facility but are currently focusing on butane exports. Fortunately, there are a number of potential butane export facilities that could begin operation in the next year

DCF and Capital Investments 25 2013 Capital Expenditure Forecast of $1.5 to 1.8 Billion DCF Growth ($ millions) 2004 to 2012 and Forecast DCF has grown at a CAGR of 35% since 2004 and has increased by over 1,000% in the same time period 35% CAGR 2013 DCF Forecast of $500 million to $575 million 2013 Capital Expenditures Forecast of $1.5 to $1.8 billion

Strong Liquidity Position In November 2012, MarkWest successfully completed a one-day marketed equity with net proceeds of $437 million In November 2012, MarkWest launched a continuous equity offering with a total value of $600 million. This program allows the Partnership to issue equity on an at-the-market basis In January 2013, MarkWest successfully completed a $1 billion senior unsecured notes offering at 4.5% due in 2023, the lowest coupon issued for the Partnership MarkWest’s recent Notes offering was the lowest new-issue yield and coupon for long dated benchmark non-investment grade natural resources bonds since the financial crisis (2nd half of 2008) Approximately 50% of the proceeds will fund a significant portion of the Partnership’s 2013 financing plan. The remaining proceeds will be used to fund three senior note redemptions resulting approximately $10 million in annual interest expense reduction This issuance represents the Partnership’s first non-callable structure, marking a movement towards an investment grade-style structure In February 2013, MarkWest completed an amended LLC agreement for the MarkWest Utica EMG Joint Venture. The transaction provides our joint venture partner, The Energy & Minerals Group, the ability to increase their initial capital investment from $500 million to $950 million MarkWest is currently undrawn on its $1.2 billion credit facility 26 MarkWest has approximately $500 million of cash on hand to fund its 2013 capital program as of February 28, 2013

Increasing Fee-Based Net Operating Margin 27 Note: Forecast Assumes Crude Oil ($/bbl) range of $93.60 to $90.80 and Natural Gas ($/mmbtu) range of $3.29 to $4.55 By 2013, total net operating margin is forecasted to be greater than 60% fee-based

2013 Forecast Net Operating Margin by Contract Type 2013 – 2014 Combined Hedge Percentage Risk Management Program NOTE: Net Operating Margin is calculated as segment revenue less purchased product costs. 28 2013 Forecast Net Operating Margin Including Hedges

Keys to Success Maintain stronghold in key resource plays with high-quality assets Execute growth projects that are well diversified across the asset base 29 EXECUTE, EXECUTE, EXECUTE!!! Provide best-in-class midstream services for our producer customers Preserve strong financial profile Deliver superior & sustainable total returns

APPENDIX

Reconciliation of DCF and Distribution Coverage ($ in millions) Year ended December 31, 2011 Year ended December 31, 2012 Net income $ 106.2 $ 218.8 Depreciation, amortization, impairment, and other non-cash operating expenses 203.9 250.1 Loss on redemption of debt, net of tax benefit 72.1 - Amortization of deferred financing costs and discount 5.1 5.6 Non-cash loss from unconsolidated affiliates 1.1 (0.7) (Contributions to) distributions from unconsolidated affiliates (0.3) 2.6 Non-cash derivative activity (0.3) (102.1) Non-cash compensation expense 3.4 8.2 Provision for income tax – deferred (3.9) 40.7 Cash adjustment for non-controlling interest of consolidated subsidiaries (64.5) (2.6) Revenue deferral adjustment 15.4 7.4 Other 9.2 3.7 Maintenance capital expenditures, net of joint venture partner contributions (14.6) (15.3) Distributable cash flow (DCF) $ 332.8 $ 416.4 Total distributions declared for the period $ 240.7 $ 370.3 Distribution coverage ratio (DCF / Total distributions declared) 1.38x 1.12x 31

Reconciliation of Adjusted EBITDA ($ in millions) Year ended December 31, 2011 Year ended December 31, 2012 Net income (loss) $ 106.3 $ 218.8 Non-cash compensation expense 3.4 8.2 Non-cash derivative activity (0.3) (102.1) Interest expense (1) 109.9 117.1 Depreciation, amortization, impairments, and other non-cash operating expenses 203.9 250.1 Loss on redemption of debt 79.0 - Provision for income tax 13.7 38.3 Adjustment for cash flow from unconsolidated affiliate 1.3 1.9 Other (1.9) (4.1) Adjusted EBITDA $ 515.3 $ 528.2 Includes amortization of deferred financing costs and discount, and excludes interest expense related to the Steam Methane Reformer. 32

($ in millions) Year ended December 31, 2011 Year ended December 31, 2012 Income from operations $ 318.2 $ 381.7 Facility expense 173.6 208.4 Derivative activity 75.5 (69.1) Revenue deferral adjustment 15.4 7.4 Selling, general and administrative expenses 81.2 94.1 Depreciation 150.0 189.5 Amortization of intangible assets 43.6 53.3 Loss on disposal of property, plant, and equipment 8.8 6.3 Accretion of asset retirement obligations 1.1 0.7 Net operating margin $ 867.4 $ 872.3 33 Reconciliation of Net Operating Margin

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