8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): June 3, 2009

MARKWEST ENERGY PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization) 001-31239 (Commission File Number) 27-0005456 (I.R.S. Employer Identification Number)

1515 Arapahoe Street, Tower 2, Suite 700, Denver CO 80202

(Address of principal executive offices)

Registrant’s telephone number, including area code: 303-925-9200

Not Applicable.

(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o    Written Communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-Commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-Commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

ITEM 7.01. Regulation FD

In accordance with General Instruction B.2 of Form 8-K, the following information in this Current Report on Form 8-K (including the exhibit) is furnished pursuant to Item 7.01 and shall not be deemed to be “filed” for the purpose of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.  This Current Report will not be deemed an admission as to the materiality of any information in the report that is required to be disclosed solely by Regulation FD.

On June 3, 2009, Frank Semple, Chairman of the Board, President & Chief Executive Officer, and Nancy Buese, Senior Vice President & Chief Financial Officer, will meet with analysts and investors at the UBS 2009 MLP Conference in Las Vegas, Nevada.  The information included with this Current Report as Exhibit 99.1 includes graphic images or slides that will be made available at this conference.

On June 3, 2009, Randy S. Nickerson, Senior Vice President & Chief Commercial Officer, will make a presentation on developments in the Marcellus Shale region to RBC Global & Energy Power investors in western Pennsylvania.  The information included with this Current Report as Exhibit 99.2 includes graphic images or slides that will be provided at this conference.

The earnings release furnished with this Current Report on Form 8-K utilizes the Non-GAAP financial measures of Distributable Cash Flow and Adjusted EBITDA.  In general, we define Distributable Cash Flow as net income attributable to the Partnership adjusted for (i) depreciation, amortization, accretion and impairment expense; (ii) amortization of deferred financing costs, (iii) non-cash earnings from unconsolidated affiliates; (iv) distributions from (contributions to) unconsolidated affiliates (net of affiliate’s growth capital expenditures); (v) non-cash compensation expense; (vi) non-cash derivative activity; (vii) losses (gains) on the disposal of property, plant and equipment (“PP&E”); (viii) provision for deferred income taxes; (ix) adjustments for non-controlling interest in consolidated subsidiaries; (x) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period; and (xi) maintenance capital expenditures.   We define Adjusted EBITDA as net income attributable to the Partnership adjusted for (i) depreciation, amortization, accretion, and impairment expense; (ii) interest expense; (iii) amortization of deferred financing costs; (iv) losses (gains) on the disposal of PP&E; (v) non-cash derivative activity; (vi) non-cash compensation expense; (vii) provision for income taxes; (viii) adjustments for non-controlling interest in consolidated subsidiaries; and (ix) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period.  The above definitions clarify and give additional detail to the definitions given in previous presentations and securities filings, but do not represent a change to the way we calculate these two financial measures.

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.

Cautionary Statements

This filing includes “forward-looking statements.” All statements other than statements of historical facts included or incorporated herein may constitute forward-looking statements. Actual results could vary significantly from those expressed or implied in such statements and are subject to a number of risks and uncertainties. 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. The forward-looking statements involve risks and uncertainties that affect our operations, financial performance, and other factors as discussed in our filings with the Securities and Exchange Commission. 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, 2008, and our Quarterly Report on Form 10-Q, for the three months ended March 31, 2009, as filed with the SEC. You are urged to

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carefully review and consider the cautionary statements and other disclosures made in those filings, specifically those under the heading “Risk Factors.”

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ITEM 9.01.  Financial Statements and Exhibits.

(d)Exhibits.

Exhibit No.	Description of Exhibit
99.1	Presentation to UBS analysts and investors on June 3, 2009.
99.2	Presentation to RBC investors on June 3, 2009.

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SIGNATURE

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	MARKWEST ENERGY PARTNERS, L.P.
	(Registrant)
	By:	MarkWest Energy GP, L.L.C.,
		Its General Partner
Date: June 3, 2009	By:	/s/ NANCY K. BUESE
		Nancy K. Buese Senior Vice President and Chief Financial Officer

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EX-99.1

Exhibit 99.1

UBS 2009 MLP Conference June 2009

Forward-Looking Statements This presentation contains forward-looking statements and information. These forward-looking statements, which in many instances can be identified by words like “could,” “may,” “will,” “should,” “expects,” “plans,” “project,” “anticipates,” “believes,” “planned,” “proposed,” “potential,” and other comparable words, regarding future or contemplated results, performance, transactions, or events, are based on MarkWest Energy Partners, L.P. (“MarkWest” and “Partnership”) current information, expectations and beliefs, concerning future developments and their potential effects on MarkWest. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct, and actual results, performance, distributions, events or transactions could vary significantly from those expressed or implied in such statements and are subject to a number of uncertainties and risks. Among the factors that could cause results, performance, distributions, events or transactions to differ materially from those expressed or implied, are those risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2008, and our Quarterly Report on Form 10-Q for the three months ended March 31, 2009, as filed with the SEC. You are urged to carefully review and consider the cautionary statements and other disclosures, including those under the heading “Risk Factors,” made in those documents. If any of the uncertainties or risks develop into actual events or occurrences, or if underlying assumptions prove incorrect, it could cause actual results to vary significantly from those expressed in the presentation, and our business, financial condition, or results of operations could be materially adversely affected. Key uncertainties and risks that may directly affect MarkWest’s performance, future growth, results of operations, and financial condition, include, but are not limited to: Fluctuations and volatility of natural gas, NGL products, and oil prices; A reduction in natural gas or refinery off-gas production which we gather, transport, process, and/or fractionate; A reduction in the demand for the products we produce and sell; Financial credit risks / failure of customers to satisfy payment or other obligations under our contracts; Effects of our debt and other financial obligations, access to capital, or our future financial or operational flexibility or liquidity; Construction, procurement, and regulatory risks in our development projects; Hurricanes, fires, and other natural and accidental events impacting our operations, and adequate insurance coverage; Terrorist attacks directed at our facilities or related facilities; Changes in and impacts of laws and regulations affecting our operations; and Failure to integrate recent or future acquisitions.

Non-GAAP Measures Distributable Cash Flow and Adjusted EBITDA are not measures of performance calculated in accordance with GAAP, and should not be considered separately from or as a substitute for net income, income from operations, or cash flow as reflected in our financial statements. The GAAP measure most directly comparable to Distributable Cash Flow and Adjusted EBITDA is net income attributable to the Partnership. In general, we define Distributable Cash Flow as net income attributable to the Partnership adjusted for (i) depreciation, amortization, accretion and impairment expense; (ii) amortization of deferred financing costs, (iii) non-cash earnings from unconsolidated affiliates; (iv) distributions from (contributions to) unconsolidated affiliates (net of affiliate’s growth capital expenditures); (v) non-cash compensation expense; (vi) non-cash derivative activity; (vii) losses (gains) on the disposal of property, plant and equipment (“PP&E”); (viii) provision for deferred income taxes; (ix) adjustments for non-controlling interest in consolidated subsidiaries; (x) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period; and (xi) maintenance capital expenditures. We define Adjusted EBITDA as net income attributable to the Partnership adjusted for (i) depreciation, amortization, accretion, and impairment expense; (ii) interest expense; (iii) amortization of deferred financing costs; (iv) losses (gains) on the disposal of PP&E; (v) non-cash derivative activity; (vi) non-cash compensation expense; (vii) provision for income taxes; (viii) adjustments for non-controlling interest in consolidated subsidiaries; and (ix) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period. Distributable Cash Flow is a financial performance measure used by management as a key component in the determination of cash distributions paid to unitholders. We believe distributable cash flow is an important financial measure for unitholders as an indicator of cash return on investment and to evaluate whether the Partnership is generating sufficient cash flow to support quarterly distributions. In addition, distributable cash flow is commonly used by the investment community because the market value of publicly traded partnerships is based, in part, on distributable cash flow and cash distributions paid to unitholders. Adjusted EBITDA is a financial performance measure used by management, industry analysts, investors, lenders, and rating agencies to assess the financial performance and operating results of the Partnership’s ongoing business operations. Additionally, we believe Adjusted EBITDA provides useful information to investors for trending, analyzing, and benchmarking our operating results from period to period as compared to other companies that may have different financing and capital structures. Please see the Appendix and Slide 18 for reconciliations of Adjusted EBITDA and Distributable Cash Flow, respectively, to net income attributable to the Partnership.

Key Investment Highlights Focused on maintaining strong credit ratios Debt / book capitalization of approximately 50% Debt / Adjusted EBITDA of approximately 4.0x Access to approximately $300 million under our revolving credit facility after recently completed Arkoma Connector JV and senior notes offering Long-term contracts with high-quality customers Active commodity price risk management program Meaningful portion of fee-based contracts Midstream MLP with no incentive distribution rights and a successful track record of quality growth and financial performance Since IPO, distributions have increased by 156% (15% CAGR) 11 acquisitions totaling ~$875 million (excluding the MarkWest Hydrocarbon merger) since IPO 2009 capital budget of approximately $225 million for growth projects (excludes capital expenditures associated with Liberty Midstream joint venture) Growth projects are well diversified across the asset base High Quality / Diversified Asset Base Substantial Growth Opportunities Proven Track Record of Growth Stable Cash Flows Strong Financial Profile Leading presence in five core natural-gas producing regions of the U.S. Key long-term contracts with high quality producers to develop the Marcellus Shale and Woodford Shale; largest natural gas processor in Appalachia

Geographic Footprint Michigan 250-mile intrastate crude pipeline 90-mile gas gathering pipeline Western Oklahoma 275 MMcf/d gathering capacity 160 MMcf/d processing plant Southeast Oklahoma 500 MMcf/d gathering capacity Centrahoma processing JV Arkoma Connector JV with ArcLight Capital Partners Starfish (50% equity ownership) West Cameron dehydration facility 1.2 Bcf/d Stingray interstate pipeline Appalachia Five processing plants with combined 330 MMcf/d processing capacity 1 million Gal/d NGL fractionation facility 11 million gallon storage capacity 80-mile NGL pipeline Midstream & Resources joint venture to develop midstream infrastructure in the Marcellus shale Javelina Refinery off-gas processing, fractionation, and transportation facilities East Texas 500 MMcf/d gathering capacity 280 MMcf/d processing plant Other Southwest 12 gas gathering systems 4 lateral gas pipelines

Competitive advantages Located in prolific East Texas Basin Cotton Valley, Travis Peak and Pettit formations Haynesville Shale Multiple gas and NGL outlets to downstream markets System and plant are essentially new; highly fuel efficient with minimal losses Low-pressure service Common suction design for optimized compression redundancy Market Access Interconnects to the Natural Gas Pipeline (NGPL) and CenterPoint Energy Gas Transmission Pipeline (CEGT) Gathering system 500 MMcf/d capacity (current throughput greater than 450 MMcf/d) Over 440 miles of pipe Over 100,000 hp of compression Gas processing plant 280 MMcf/d cryogenic gas plant, including 80 MMcf/d expansion completed in 2008 Highly fuel efficient East Texas System Overview LEGEND NGPL CEGT

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

Competitive advantages Located in prolific Arkoma Basin Low pressure service In excess of 160,000 dedicated acres in the Woodford Shale play and the Hartshorne coal bed methane (CBM) play Market Access Interconnects to CenterPoint Energy Gas Transmission (CEGT) and Enogex, Inc. Joint venture with ArcLight Capital Partners to construct and operate the Arkoma Connector pipeline that will connect to Midcontinent Express and Gulf Crossing pipelines at Bennington; operational in June 2009 With Arkoma Connector, we will have 1.3 Bcf/d of takeaway capacity Gathering system 500 MMcf/d capacity Over 700 miles of mostly large diameter pipe Over 23 compressor stations with 85,000 HP Processing and treating capacity 40 MMcf/d processing capacity through 40% ownership of Centrahoma joint venture Three amine treating facilities at north and south end of gathering system Southeast Oklahoma System Overview CEGT PIPELINE ARKOMA CONNECTOR PIPELINE MEP PIPELINE GULF CROSSING PIPELINE

Refinery off-gas processing 140 MMcf/d cryogenic gas plant produces NGLs and residue gas NGLs are fractionated and residue gas is returned to the refiners for fuel gas Hydrogen is separated from the off-gas through pressure swing absorption (PSA) process Fractionation 1.2 million Gal/d NGL fractionation capacity Products produced include ethylene, ethane, propane, propylene, mixed-butanes, and pentanes Steam methane reformer (SMR) expansion SMR will deliver high-purity hydrogen to refinery customers, a critical component in the production of ultra-low sulfur diesel The expansion is under way and is expected to be operational in early 2010 Project is anchored by a long-term, fee-based contract Javelina Processing Facility Overview Competitive advantages Javelina provides critical services for six refineries in Corpus Christi, Texas All refinery off-gas is committed to Javelina under long-term contracts Excellent relationships with refinery customers Efficient off-gas processing and fractionation facility Product pipelines to critical end markets Corpus Christi Bay Javelina Facilities Valero Refineries Citgo Refineries Flint Hills Refineries

Appalachia Overview Processing Plants Five plants with total gas processing capacity of 330 MMcf/d Kenova plant modified in 2008 to improve propane recovery Significant plant expansion under way at Cobb; expected to be operational in mid 2009 Siloam Current fractionation capacity of 1,000,000 Gal/d, including expansion completed in 2009 Marcellus JV with NGP Midstream & Resources (M&R) Long-term partnership to develop midstream services in the Marcellus Owned 60% by MarkWest and 40% by M&R MarkWest contributed approximately $100 million of existing Marcellus assets and M&R will invest the next $200 million of capital MarkWest expects to invest approximately $200 million in incremental capital by the end of 2011 Competitive advantages Largest gas processor in the prolific Appalachian Basin, a critical source of natural gas and natural gas liquids to Northeastern markets Deep local knowledge developed over 20 years of operations NGLs from the gas plants are shipped to Siloam for fractionation, storage, and marketing Produces purity propane, iso-butane, normal butane, and natural gasoline Deep marketing relationships and sales by truck, rail, and barge Storage capacity of approximately 11 million gallons Existing fractionation, storage and marketing complex (22,000 Bbl/d following expansion) Existing gas processing facilities Third-party processing facility

Long-term Marcellus Joint Venture Development Plans Ohio Pennsylvania West Virginia Houston Plant Complex Processing and fractionation capacity Majorsville Plants Cryogenic plants and pipeline NGL product pipeline and rail yard Propane pipeline to TEPPCO Area to be served by Columbia Gas and MarkWest joint gathering and compression facilities Area to be served by MarkWest gathering infrastructure High-pressure gathering Over 100+ miles of high-pressure trunkline and 20+ compressor stations MarkWest standalone rich-gas gathering capacity of 150+ MMcf/d Columbia/MarkWest rich-gas gathering capacity of 240+ MMcf/d Processing capacity 4 processing plants with up to 390 MMcf/d of processing capacity Market outlets to Columbia Gas Transmission, Texas Eastern Transmission Company, and National Fuel NGL Infrastructure Fractionation capacity of up to 25,000+ Bbl/day Plant products marketed by truck, pipeline, and rail

“MarkWest Energy Named #1 in Natural Gas Midstream Services Customer Satisfaction” Most Recent EnergyPoint Research, Inc. Customer Satisfaction Survey Growth Driven by Customer Satisfaction R A N G E RESOURCES

Distribution Growth Since IPO 156% Distribution Growth since IPO in May 2002 (15% CAGR) Common Unit Distribution $0.00 $0.10 $0.20 $0.30 $0.40 $0.50 $0.60 $0.70 3Q02 4Q02 1Q03 2Q03 3Q03 4Q03 1Q04 2Q04 3Q04 4Q04 1Q05 2Q05 3Q05 4Q05 1Q06 2Q06 3Q06 4Q06 1Q07 2Q07 3Q07 4Q07 1Q08 2Q08 3Q08 4Q08 1Q09

2009 Growth Capital Forecast 2009 Forecast: approximately $225 million (1) Completion of SMR hydrogen production facility Gulf Coast Southwest Arkoma Connector pipeline Stiles Ranch Southeast Oklahoma / Woodford expansion Well connects / compression Northeast Cobb plant replacement Siloam plant expansion Note 1: Forecast excludes estimated growth capital expenditures of approximately $200 million associated with the Liberty Midstream joint venture. Refer to slide 10 for additional information. Southwest ~$190 MM Gulf Coast ~$25 MM Northeast ~$10 MM

Capital Investment millions millions Distributable Cash Flow* *See slide 18 for a reconciliation of DCF to net income attributable to the Partnership. Acquisitions Growth capital Strategic Investments Drive DCF NOTE: Financial data for periods prior to 2008 has not been restated for the MarkWest Hydrocarbon merger $160M–$200M $0 $100 $200 $300 $400 $500 $600 2004 2005 2006 2007 2008 2009F $0 $50 $100 $150 $200 $250 2004 2005 2006 2007 2008 2009F

2009 Forecasted DCF Sensitivity Analysis Crude Oil to Natural Gas Ratio Crude Oil Price NGL Correlation 11:1 10:1 9:1 8:1 7:1 6:1 $70 A $241 $239 $237 $232 $226 $218 B $212 $209 $208 $203 $199 $198 C $183 $181 $181 $179 $178 $177 $60 A $230 $229 $228 $223 $219 $211 B $201 $199 $199 $194 $191 $190 C $172 $171 $172 $171 $170 $169 $50 A $225 $223 $223 $219 $215 $209 B $195 $193 $193 $190 $187 $186 C $167 $165 $167 $166 $166 $165 $40 A $218 $217 $218 $215 $212 $207 B $188 $187 $188 $185 $183 $182 C $158 $158 $160 $160 $160 $159 $30 A $210 $210 $211 $209 $208 $205 B $179 $179 $180 $178 $177 $176 C $150 $151 $153 $153 $153 $153 NOTE: The table is based on information, expectations, and beliefs concerning future developments and their potential effects, and does not consider actions MarkWest management may take to mitigate exposure to changes. Nor does the table consider the effects that such hypothetical adverse changes may have on overall economic activity. Estimated Range of 2009 DCF ($ in millions) The table reflects an estimated range of 2009 DCF based on three natural gas liquids (NGL) correlation scenarios, including: (A) One standard deviation above the historical average NGL correlation to crude over the past three years; (B) The historical average NGL correlation to crude over the past three years; (C) One standard deviation below the historical average NGL correlation to crude over the past three years. The analysis assumes derivative instruments outstanding as of May 11, 2009, production volumes estimated through December 31, 2009, and incorporates actual results for the first quarter of 2009. During the past 10 years, the annual average NGL correlation has ranged between one standard deviation below the historical average and one standard deviation above the historical average.

Capital Structure ($ in millions) As of December 31, 2008 As of March 31, 2009 As of March 31, 2009 Proforma for Debt Offering and Arkoma JV Cash $ 3.3 $ 32.0 $ 32.0 Credit Facility (1) 184.7 294.4 118.4 6-7/8% Senior Notes due 2014 215.3 215.7 215.7 6-7/8% Senior Notes due 2014 – May 2009 Issuance – – 117.0 8-1/2% Senior Notes due 2016 274.1 274.1 274.1 8-3/4% Senior Notes due 2018 498.8 498.9 498.9 Total Debt $ 1,172.9 $ 1,283.1 $ 1,224.1 Total Partners' Capital $ 1,204.5 $ 1,187.6 $ 1,187.6 Total Capitalization $ 2,377.4 $ 2,470.7 $ 2,411.7 LTM Adjusted EBITDA(2) $ 289.0 $ 296.3 $ 296.3 Total Debt / Capitalization 49% 52% 51% Total Debt / LTM Adjusted EBITDA (2) 4.1x 4.3x 4.1x Adjusted EBITDA / Interest Expense (2) 4.0x 3.7x 3.7x (1) Pro forma Credit Facility assumes repayment from net proceeds of May 2009 notes offering and May 2009 Arkoma Connector joint venture (2) Adjusted EBITDA and interest expense calculated in accordance with Credit Facility covenants.

($ in millions) Year ended December 31, 2008 Three months ended March 31, 2009 Net income attributable to the Partnership $ 208.1 $ (29.6) Depreciation, amortization, accretion, impairments, and loss on disposal of PP&E 184.3 32.0 Non-cash derivative activity (263.1) 65.7 Non-cash compensation expense 14.9 1.9 Non-cash losses from unconsolidated affiliates (0.1) 0.1 Distributions from (contributions to) unconsolidated affiliates, net of growth capital 0.4 (5.0) Provision for income tax – deferred 53.8 (15.6) Adjustment for non-controlling interest of consolidated subsidiaries – (0.2) Other 7.0 1.6 Maintenance capital expenditures (7.2) (2.0) Distributable cash flow (DCF) $ 198.1 $ 48.9 Total distributions paid $ 142.2 $ 36.4 Distribution coverage ratio (DCF / Total distributions paid) 1.39x 1.34x Distribution Coverage

2009 Guidance 2009 Financial Guidance Distributable cash flow of $160 million to $200 million Growth capital expenditures of approximately $225 million

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

Appendix

($ in millions) Year ended December 31, 2007 Year ended December 31, 2008 LTM ended March 31, 2009 Net income attributable to the Partnership $ (39.4) $ 208.1 $ 159.3 Depreciation, amortization, accretion, impairments, and loss on disposal of PP&E 66.2 184.3 194.9 Taxes (24.6) 68.8 36.0 Interest expense 42.4 72.9 79.9 Non-cash derivative activity 150.4 (263.1) (192.5) Non-cash compensation expense 20.5 14.9 11.3 Adjustment for cash flow from non-consolidated investments – 6.5 7.6 Adjustment for non-controlling interest of consolidated subsidiaries 4.9 (3.4) (0.2) Adjusted EBITDA $ 220.4 $ 289.0 $ 296.3 Reconciliation of Adjusted EBITDA

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

EX-99.2

Exhibit 99.2

RBC Global Energy and Power Site Visit to the Marcellus Shale Randy Nickerson – Senior VP, Chief Commercial Officer June 3, 2009

Forward-Looking Statements This presentation contains forward-looking statements and information. These forward-looking statements, which in many instances can be identified by words like “could,” “may,” “will,” “should,” “expects,” “plans,” “project,” “anticipates,” “believes,” “planned,” “proposed,” “potential,” and other comparable words, regarding future or contemplated results, performance, transactions, or events, are based on MarkWest Energy Partners, L.P. (“MarkWest” and “Partnership”) current information, expectations and beliefs, concerning future developments and their potential effects on MarkWest. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct, and actual results, performance , distributions , events or transactions could vary significantly from those expressed or implied in such statements and are subject to a number of uncertainties and risks. Among the factors that could cause results, performance, distributions, events or transactions to differ materially from those expressed or implied, are those risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2008, and our Quarterly Report on Form 10-Q for the three months ended March 31, 2009, as filed with the SEC. You are urged to carefully review and consider the cautionary statements and other disclosures, including those under the heading “Risk Factors,” made in those documents. If any of the uncertainties or risks develop into actual events or occurrences, or if underlying assumptions prove incorrect, it could cause actual results to vary significantly from those expressed in the presentation, and our business, financial condition, or results of operations could be materially adversely affected. Key uncertainties and risks that may directly affect MarkWest’s performance, future growth, results of operations, and financial condition, include, but are not limited to: Fluctuations and volatility of natural gas, NGL products, and oil prices; A reduction in natural gas or refinery off-gas production which we gather, transport, process, and/or fractionate; A reduction in the demand for the products we produce and sell; Financial credit risks / failure of customers to satisfy payment or other obligations under our contracts; Effects of our debt and other financial obligations, access to capital, or our future financial or operational flexibility or liquidity; Construction, procurement, and regulatory risks in our development projects; Hurricanes, fires, and other natural and accidental events impacting our operations, and adequate insurance coverage; Terrorist attacks directed at our facilities or related facilities; Changes in and impacts of laws and regulations affecting our operations; and Failure to integrate recent or future acquisitions.

MarkWest Overview Growth-oriented, customer-focused midstream company traded on the NYSE Common Units outstanding 56.9 million Market cap (5.28.09) $1.0 billion Long-term debt $1.15 billion Enterprise value (5.28.09) $2.2 billion 1Q09 annualized distribution $2.56 per common unit 2009 growth capital approximately $225 million (1) Note 1: excludes capital expenditures associated with Markwest Liberty Midstream & Resources joint venture

Geographic Footprint Michigan 250-mile intrastate crude pipeline 90-mile gas gathering pipeline Western Oklahoma 275 MMcf/d gathering capacity 160 MMcf/d processing plant Southeast Oklahoma 500 MMcf/d gathering capacity Centrahoma processing JV Arkoma Connector JV with ArcLight Capital Partners Starfish (50% equity ownership) West Cameron dehydration facility 1.2 Bcf/d Stingray interstate pipeline Appalachia Five processing plants with combined 330 MMcf/d processing capacity 1 million Gal/d NGL fractionation facility 11 million gallon storage capacity 80-mile NGL pipeline Midstream & Resources joint venture to develop midstream infrastructure in the Marcellus shale Javelina Refinery off-gas processing, fractionation, and transportation facilities East Texas 500 MMcf/d gathering capacity 280 MMcf/d processing plant Other Southwest 12 gas gathering systems 4 lateral gas pipelines

“MarkWest Energy Named #1 in Natural Gas Midstream Services Customer Satisfaction” Most Recent EnergyPoint Research, Inc. Customer Satisfaction Survey Growth Driven by Customer Satisfaction R A N G E RESOURCES

Appalachia Overview Processing Plants Five plants with total gas processing capacity of 330 MMcf/d Kenova plant modified in 2008 to improve propane recovery Significant plant expansion under way at Cobb; expected to be operational in mid 2009 Siloam Current fractionation capacity of 1,000,000 Gal/d, including expansion completed in 2009 Marcellus JV with NGP Midstream & Resources (M&R) Long-term partnership to develop midstream services in the Marcellus Owned 60% by MarkWest and 40% by M&R MarkWest contributed approximately $100 million of existing Marcellus assets and M&R will invest the next $200 million of capital MarkWest expects to invest approximately $200 million in incremental capital by the end of 2011 Competitive advantages Largest gas processor in the prolific Appalachian Basin, a critical source of natural gas and natural gas liquids to Northeastern markets Deep local knowledge developed over 20 years of operations NGLs from the gas plants are shipped to Siloam for fractionation, storage, and marketing Produces purity propane, iso-butane, normal butane, and natural gasoline Deep marketing relationships and sales by truck, rail, and barge Storage capacity of approximately 11 million gallons Existing fractionation, storage and marketing complex (22,000 Bbl/d following expansion) Existing gas processing facilities Third-party processing facility

Current Focus in the Marcellus Area currently under significant development by MarkWest Liberty Midstream & Resources Marcellus Fairway WET GAS DRY GAS

 MarkWest’s Role in the Marcellus Services provided by MarkWest in the Marcellus Interstate and Intrastate Gas Transmission Pipelines NGL Products Ethane Propane Normal Butane Isobutane Natural Gasoline Fractionation Facility Processing Plants Gathering and Compression Pipeline Quality Natural Gas to Utilities, Homeowners and Factories Mixed NGLs Raw Natural Gas Production

Ohio Pennsylvania West Virginia Marcellus Midstream Facilities – SW Pennsylvania Gas Gathering and Compression NGL Fractionation NGL Storage and Marketing Gas Processing

Ohio Pennsylvania West Virginia Marcellus Gathering and Compression Infrastructure Anticipated Gathering Facilities 80 – 90 miles of high-pressure gathering pipeline 12 – 14 central delivery compressor stations 75,000 – 100,000 horsepower of compression

Ohio Pennsylvania West Virginia Houston, PA Marcellus Gas Processing Facilities Houston Plant 2 120 Mmcf/d Cryogenic Plant and Depropanizer (4Q09 - 1Q10) Houston Plant 1 30 Mmcf/d Cryogenic Plant and Depropanizer (April 2009) Houston Plant 3 120?? Mmcf/d Cryogenic Plant (2011) Houston Interim Plant 30 Mmcf/d Refrigeration Plant (Oct 2008)

Ohio Pennsylvania West Virginia Majorsville, WV Marcellus Gas Processing Facilities Majorsville Plant 1 120 Mmcf/d Cryogenic Plant & Pipeline (2Q10) Columbia Gas Transmission Facilities

Ohio Pennsylvania West Virginia Marcellus NGL Fractionation and Marketing Facilities NGL Marketing Infrastructure On-site and Off-site storage TEPPCO pipeline interconnect Truck loading Rail loading (2010) Propane Pipeline to TEPPCO Houston Fractionation Facility 23,000 Bbl/d full fractionation facility (4Q10 – 1Q11)

Ohio Pennsylvania West Virginia Marcellus Midstream Facilities – SW Pennsylvania Columbia Gas Transmission Gathering Facilities Gathering Facilities 80 – 90 miles of high-pressure gathering pipeline 12 – 14 central delivery compressor stations 75,000 – 100,000 horsepower of compression Houston Interim Plant 30 Mmcf/d Refrigeration Plant (Oct 2008) Houston Plant 1 30 Mmcf/d Cryogenic Plant and Depropanizer (April 09) Houston Plant 2 120 Mmcf/d Cryogenic Plant and Depropanizer (4Q09 or 1Q10) Houston Fractionation Facility (4Q10 – 1Q11) Majorsville Plant 1 120 Mmcf/d Cryogenic Plant & Pipeline (2Q10) Area to be served by MarkWest gathering and compression facilities

MarkWest Contact Information Dan Campbell Assistant Treasurer / Investor Relations (303) 542-0639 Office dcampbell@markwest.com Randy Nickerson Senior VP, Chief Commercial Officer (303) 925-9235 Office rnickerson@markwest.com