INVESTOR PRESENTATION May 2015
FORWARD-LOOKING STATEMENTS / NON-GAAP FINANCIAL MEASURES The statements included in this presentation contain forward- looking statements within the meaning of the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended. These forward- looking statements (which in many instances can be identified by words like may, will, should, expects, plans, believes, and other comparable words) are based on the Partnership s current expectations and beliefs concerning future developments and their potential effects on the Partnership, but are not guarantees of future performance, and involve risks and uncertainties. You are cautioned not to place undue reliance on forward- looking statements, as many of these factors are beyond our ability to control or predict, and which speak only as of the date hereof. The Partnership undertakes no obligation to publicly update or revise any forward- looking statements after the date they are made, whether as a result of new information, future events, or otherwise. You are urged to carefully review and consider the cautionary statements and other disclosures made in the Partnership s Annual Report on Form 10- K for fiscal year 2014, including under the heading Risk Factors, which identify and discuss significant risks, uncertainties, and various other factors that could cause actual results to vary significantly from those expected or implied in the forwardlooking statements. 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, 2014. 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. We use non- generally accepted accounting principles ( non- GAAP ) financial measures in this presentation. Our reconciliation of non- GAAP financial measures to comparable GAAP measures can be found in MarkWest s Annual Report on our website at www.markwest.com. These non- GAAP measures should not be considered an alternative to GAAP financial measures. 2
MARKWEST ENERGY: EXPANDING ON SUCCESS HIGH-QUALITY DIVERSIFIED ASSETS Leading midstream provider with nearly 6.0 Bcf/d of processing capacity, 379 MBbl/d of fractionation capacity and nearly 4,700 miles of pipeline We are the second largest gas processor in the U.S. SUBSTANTIAL GROWTH OPPORTUNITIES PROVEN CUSTOMER SATISFACTION STRONG FINANCIAL PROFILE 2015 growth capital forecast of $1.5 to $1.9 billion 19 major processing and fractionation projects under construction Long-term agreements with over 160 producer customers Received the #1 rating for Total Midstream Customer Satisfaction in every EnergyPoint Research Survey since its inception in 2006 No incentive distribution rights, which drives a lower cost of capital Distributions have increased by 264% (11% CAGR) since IPO 3
U.S. NATURAL GAS SUPPLY & DEMAND 120 100 80 60 40 Offshore U.S. Dry Natural Gas Production (billion cubic feet per day) 2015 Plant Fuel/Pipeline Use 52% 18% Shale gas Tight gas 1% Alaska 3% 20 6% 8% 5% Coalbed methane 4% Other 18% 10% 0 2000 2005 2010 2015 2020 2025 2030 2035 2040 Source: U.S. Energy Information Administration, Annual Energy Outlook 2015 55% Total U.S. natural gas supply is forecasted to grow by over 26 Bcf/d from 2015 to 2040 Shale gas is forecasted to account for 55% of total U.S. gas production by 2040 Demand growth will come from LNG and pipeline exports, and domestic power generation U.S. Gas Demand in 2040 Industrial 24% Power Generation 27% Residential/ Commercial 22% Plant Fuel 6% Pipeline Use 3% Vehicle Use LNG Exports 9% 2% Exports to Mexico & Canada 7% 4
MARCELLUS & UTICA: DRIVING U.S. GAS SUPPLY The Marcellus & Utica account for over 20% of total U.S. Gas Supply 65 21 Rest of U.S. Billion cubic feet per day (Bcf/d) 64 63 62 61 60 59 58 57 56 Marcellus & Utica Rest of U.S. 19 17 15 13 11 9 7 5 Marcellus & Utica Billion cubic feet per day (Bcf/d) 55 3 Apr-09 Apr-10 Apr-11 Apr-12 Apr-13 Apr-14 Apr-15 Note: Wellhead gas production (before flaring and NGL extraction) Source: As of 4.30.15. Bloomberg (LCI Energy Insight Estimates), BENTEK, MarkWest Energy Partners, L.P. 5
IRR BY RESOURCE PLAY MarkWest is focused in high IRR resource plays 30% 25% 20% ~75% 2015 Operating Income Forecasted from Marcellus & Utica 15% 10% 5% 0% Year: 2015 2016 2017 2018 2019 2020 2021 2022+ WTI Oil: $50.87 $57.98 $61.75 $64.11 $65.85 $67.48 $67.48 $67.48 NYMEX Gas: $3.02 $3.23 $3.44 $3.54 $3.61 $3.71 $3.71 $3.71 Areas where MarkWest Operates Source: Credit Suisse 4.2.15 6
GROWTH DRIVEN BY CUSTOMER SATISFACTION MarkWest has received the #1 rating for total customer satisfaction in every EnergyPoint Research survey since its inception in 2006 7
SOUTHWEST SEGMENT In the Southwest segment, we provide best-in-class midstream services including gathering and processing in many resource plays throughout Oklahoma and Texas. In addition, we process and fractionate off-gas on behalf of six refineries in the Gulf Coast. 2.1Bcf/d Gathering capacity 1.2Bcf/d Processing capacity 29MBbl/d C2+ Fractionation capacity Carthage Buffalo Creek Under Construction Processing 80 MMcf/d processing capacity expansion in East Texas 8
SOUTHWEST SEGMENT In 2014, we increased our processing capacity in the Southwest by 45% Western Oklahoma 775MMcf/d Gathering capacity Oklahoma Tulsa Office Southeast Oklahoma 550MMcf/d Gathering capacity 435MMcf/d Processing capacity 104MMcf/d Processing capacity* Gulf Coast East Texas 142MMcf/d Processing capacity Houston Office 640MMcf/d Gathering capacity Texas 29MBl/d 520MMcf/d C2+ Fractionation capacity Processing capacity *Represents 40% of processing capacity through the Partnership s Centrahoma JV with Atlas Pipeline Partners, L.P. 9
NORTHEAST SEGMENT We are the largest processor and fractionator in the southern portion of the Appalachian Basin Our existing infrastructure in Kentucky and West Virginia is strategically positioned to support the development of the emerging Rogersville Shale 620MMcf/d Processing capacity 24MBbl/d C3+ Fractionation capacity Langley 10
MARCELLUS SEGMENT We are the largest processor and fractionator in the Marcellus Shale and provide fully integrated natural gas midstream services 1.0Bcf/d Gathering capacity 3.1Bcf/d Processing capacity 286MBbl/d C2+ Fractionation capacity (1) Mobley Under Construction Processing 1.8 Bcf/d cryogenic capacity Fractionation 201,000 Bbl/d of shared fractionation capacity (2) (1) 120,000 Bbl/d of C3+ fractionation capacity shared with the Utica Segment (2) 60,000 Bbl/d C3+ fractionation capacity shared with the Utica segment 11
MARCELLUS SEGMENT OVERVIEW 3,500 3,000 2,500 2,000 1,500 1,000 500 0 Processed Volumes (MMcf/d) Processed volumes increased 73% compared from the first quarter 2014 and 11% compared to the fourth quarter 2014 ~50% Forecasted Avg. Increase from FY2014 to FY2015 2Q15 through 4Q15 Avg. 1Q10 4Q10 3Q11 2Q12 1Q13 4Q13 3Q14 2Q15F Houston Majorsville Mobley Sherwood Keystone Average utilization of Marcellus processing assets was 90% in the first quarter 2015 We process approximately 1Q15 1Q15 90% of richgas production Average from the Average Marcellus 1Q15 Shale Complex Capacity (MMcf/d) * *Based on weighted average number of days plant(s) in service Volume (MMcf/d) Utilization (%) Sherwood 1,000 934 93% Mobley 720 649 90% Majorsville 870 779 90% Houston 355 323 91% Keystone 210 160 76% 1Q15 Total 3,155 2,845 90% 4Q14 Total 2,920 2,556 88% 12
UTICA SEGMENT In the Utica segment, we have a leading position in developing fully integrated natural gas midstream services 700MMcf/d Gathering capacity 925MMcf/d Processing capacity 160MBbl/d C2+ Fractionation capacity (1) Seneca Under Construction Processing 600 MMcf/d cryogenic capacity Fractionation 60,000 Bbl/d of shared C3+ capacity (2) (1) 120,000 Bbl/d of C3+ fractionation capacity shared with the Marcellus Segment (2) 60,000 Bbl/d C3+ fractionation capacity shared with the Marcellus segment 13
UTICA SEGMENT OVERVIEW 900 800 700 600 500 400 300 200 100 0 Processed Volumes (MMcf/d) ~95% Forecasted Avg. Increase from FY2014 to FY2015 4Q12 2Q13 4Q13 2Q14 4Q14 2Q15F 4Q15F Seneca Cadiz 2Q15 through 4Q15 Avg. MarkWest Utica EMG supports producers development of the Utica Shale, with the largest fully integrated midstream system in Ohio Processed volumes increased 201% from the first quarter 2014 and 16% from the fourth quarter 2014 Average utilization of Utica processing complexes reached 82% during the first quarter 2015, up from 76% last quarter Complex 1Q15 Average Capacity (MMcf/d) * *Based on weighted average number of days plant(s) in service 1Q15 Average Volume (MMcf/d) 1Q15 Utilization (%) Cadiz 325 274 84% Seneca 600 481 80% 1Q15 Total 925 755 82% 4Q14 Total 855 652 76% 14
MARCELLUS & UTICA: 34 PROJECTS COMPLETE MWE Gathering System MWE Marcellus Complex MWE Utica Complex MWE NGL Pipeline MWE Purity Ethane Pipeline MWE NGL/Purity Ethane Pipeline Under Construction ATEX Express Pipeline TEPPCO Product Pipeline Sunoco Mariner Pipeline 18 Major projects under construction, 10 to be completed in 2015 HOPEDALE FRACTIONATION COMPLEX (MarkWest & MarkWest Utica EMG shared fractionation capacity) C3+ Fractionation I & II 120,000 Bbl/d Operational C3+ Fractionation III 60,000 Bbl/d 1Q16 OHIO GATHERING & OHIO CONDENSATE MarkWest Utica EMG s Joint Venture with Summit Midstream, LLC Stabilization Facility 23,000 Bbl/d Operational CADIZ COMPLEX Cadiz I & II 325 MMcf/d Operational Tuscarawas Cadiz III 200 MMcf/d 3Q15 Cadiz IV 200 MMcf/d 2Q16 De-ethanization 40,000 Bbl/d Operational Noble SENECA COMPLEX Seneca I III 600 MMcf/d Operational Seneca IV 200 MMcf/d 3Q15 Harrison Carroll Monroe Belmont OHIO Jefferson WEST VIRGINIA Marshall Wetzel Doddridge Hancock Brooke Ohio Beaver Washington Butler PENNSYLVANIA Allegheny Washington Greene KEYSTONE COMPLEX Bluestone I II & Sarsen I 210 MMcf/d Operational Bluestone III 200 MMcf/d 4Q15 Bluestone IV 200 MMcf/d 3Q16 C2 Fractionation 14,000 Bbl/d Operational C3+ Fractionation 12,000 Bbl/d Operational De-ethanization 40,000 Bbl/d 4Q16 C3+ Fractionation 31,000 Bbl/d 4Q15 FOX COMPLEX Fox I 200 MMcf/d 4Q16 De-ethanization 20,000 Bbl/d 4Q16 HOUSTON COMPLEX Houston I III 355 MMcf/d Operational Houston IV 200 MMcf/d 2Q15 C3+ Fractionation 60,000 Bbl/d Operational De-ethanization 40,000 Bbl/d Operational MAJORSVILLE COMPLEX Majorsville I V 870 MMcf/d Operational Majorsville VI 200 MMcf/d 2Q15 Majorsville VII 200 MMcf/d 2Q16 De-ethanization 40,000 Bbl/d Operational MOBLEY COMPLEX Mobley I IV 720 MMcf/d Operational Mobley V 200 MMcf/d 4Q15 De-ethanization 10,000 Bbl/d 4Q15 SHERWOOD COMPLEX Sherwood I V 1,000 MMcf/d Operational Sherwood VI 200 MMcf/d 2Q15 Sherwood VII 200 MMcf/d 2Q16 De-ethanization 40,000 Bbl/d 4Q15 15
SIGNIFICANT AREA DEDICATIONS & VOLUME COMMITMENTS IN THE NORTHEAST Nearly 8 million acres dedicated to MarkWest in the Utica & Marcellus PENNSYLVANIA Utica Area Dedications: 3.7 million acres Volume Protection: 25% of 2015 capacity contains minimum volume commitments OHIO WEST VIRGINIA Marcellus Area Dedications: 4 million acres Volume Protection: 70% of 2015 capacity contains minimum volume commitments 16
PROCESSED VOLUME GROWTH We are now the second largest gas processor in the U.S. ~1.3 Bcf/d ~2.3 Bcf/d ~5.3 Bcf/d Increase of 4 Bcf/d in 4 years 17
NORTHEAST GAS PRODUCTION FORECAST 35 Billion cubic feet per day (Bcf/d) 30 25 20 15 10 ~30% Northeast Rich Gas ~70% Northeast Dry Gas 5-2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: Bentek North America NGL Market Call 4.28.15 18
ANNOUNCED GAS TAKEAWAY PROJECTS Approximately $20 Billion in Capital Investments and 29 Bcf/d of Natural Gas Pipeline Projects on the Horizon Pipeline Bcf/d 4 Projects ~4.2 $2.9bn Pipeline Bcf/d 31 Projects ~8.8 investment in new natural gas transmission capacity needed through 2035 is projected to average $7.3bn $4.0bn $14 billion per year... $5.6bn Pipeline Bcf/d 3 Projects ~3.4 Pipeline Bcf/d 12 Projects ~8.3 $0.9bn Pipeline Source: Goldman Sachs Global Investment Research, Feb. 2015 & The INGAA Foundation North American Midstream Infrastructure Study March 2014 Bcf/d 5 Projects ~4.3 19
NORTHEAST NGL PRODUCTION Northeast NGL production is forecasted to reach nearly 1.2 million barrels per day over the next 10 years 1,400 1,200 Northeast NGL Production (MBld/d) 1,000 800 600 400 200 The Marcellus & Utica shales are forecasted to supply nearly a quarter of total U.S. NGL production by 2024 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Ethane Propane Normal Butane Iso-Butane Natural Gasoline Source: Bentek North America NGL Market Call 4.28.15, NGL Production from Gas Plants 20
INFRASTRUCTURE TO SUPPORT GROWING SUPPLY Mariner West MI TEPPCO ATEX MIDWEST & USGC SARNIA OH WV PA Mariner East MarkWest s Operations MARCUS HOOK The Northeast is poised for midstream infrastructure growth, with investments totaling more than $80 billion throughout the projection (2014-2035). International exports are critical Regional petrochemical projects & other facilities NGL takeaway projects to Canada, Midwest, and USGC Source: MarkWest Energy Partners, L.P. & The INGAA Foundation North American Midstream Infrastructure Study March 2014 21
PROPOSED DOWNSTREAM NGL PROJECTS Kinder Morgan Utopia East MI UMTP Project OH PPT Global Chemical/Marubeni Cracker Marathon Cornerstone Pipeline WV Shell Ethane Cracker PA Braskem Ethane Cracker Sunoco Logistics Mariner East Pipeline & Marcus Hook Facilities Proposed regional cracker projects to support ethane demand Proposed UMTP project, Utopia East Pipeline, PDH facility at Marcus Hook and other petrochemical projects to support propane and butane demand Proposed Cornerstone Pipeline and other projects to support NGL and condensate demand Potential new export facilities at multiple locations on the Eastern seaboard to support international NGL demand 22
UTICA CONDENSATE EXPANSION OHIO GATHERING & OHIO CONDENSATE MarkWest Utica EMG s Joint Venture with Summit Midstream, LLC Stabilization Facility 23,000 Bbl/d Operational Canton, OH (MPC Refinery) OHIO Tuscarawas Guernsey CADIZ COMPLEX Stark Carroll Harrison Columbiana MPLX LP s Cornerstone Pipeline Jefferson Jefferson Belmont HOPEDALE FRACTIONATION COMPLEX Our recently completed 23,000 Bbl/d facility will serve as the origin for MPLX LP s (NYSE: MPLX) Cornerstone Pipeline a 50-mile pipeline to Marathon Petroleum Company LP s (MPC) Canton, Ohio refinery Condensate production is expected to grow rapidly in eastern Ohio and provides value for producers in the area Our facility is the largest of its kind in the Utica and we believe this is an important progression in connecting the Utica and Marcellus NGLs to refinery and petrochemical markets Noble SENECA COMPLEX Monroe MWE Gathering System MWE Utica Complex MWE NGL Pipeline MWE Purity Ethane Pipeline MWE NGL/Purity Ethane Pipeline Under Construction ATEX Express Pipeline TEPPCO Product Pipeline 23
FINANCIAL FORECAST 2015 DCF Forecast: $700MM $800MM 2015 EBITDA Forecast: $925MM $1,025MM Capital Investment Forecast Net Operating Margin Forecast 2015: $1.5B to $1.9B 100% 2015 76% 12% 12% 80% 60% 40% 20% 90% Fee-based 53% of C3+ commodity exposure hedged for 2015 0% Fee-Based Percent-of-Proceeds Keep-Whole NOTE: Net Operating Margin is calculated as segment revenue less purchased product costs 24
FINANCIAL SUMMARY MarkWest has over $1.4 billion of liquidity MarkWest preserves a strong balance sheet to fund growth We have over $1.4 billion of liquidity to support our capital investment program MarkWest maintains flexible financing options Funding of base capital requirements using a combination of long-term debt and equity In March, we successfully completed an upsized senior notes offering of $650 million at a yield of 4.66% As of May 5, 2015 we are undrawn on our $1.3 billion senior secured credit facility As of March 31, 2015 our leverage ratio was 4.4x During the first quarter of 2015, the Partnership did not issue any equity We are well positioned to fund our 2015 capital expenditure plan MarkWest is committed to achieving strong, long-term distribution growth We forecast distributions of approximately $3.70 for 2015, $3.97 for 2016 and an annual growth rate of 10% for 2017 to 2020. We anticipate the annualized distribution coverage ratio during the entire period will be between 1.0 and 1.2 times 25
2015 DISTRIBUTABLE CASH FLOW: SENSITIVITY TABLE MarkWest is more sensitive to changes in volumes than changes in commodity prices MarkWest Partnership periodically estimates the effect on DCF resulting from changes in its volume forecast and NGL price For the full-year 2015, the Partnership estimates that net operating margin will be approximately 90 percent fee-based NGL $/Gallon (2)(3) Volume Forecast (1) Low Case Base Case High Case $0.70 $ 735 $ 758 $ 779 $0.65 $ 729 $ 751 $ 772 $0.60 $ 722 $ 744 $ 765 $0.55 $ 716 $ 737 $ 757 $0.50 $ 709 $ 730 $ 750 $0.45 $ 701 $ 723 $ 742 1) Volume Forecast is increased/decreased by 5% in the Marcellus and Utica segments for the High and Low Cases. 2) The composition is based on the Partnership s projected NGL barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%. 3) Composite NGL prices are based on the Partnership s average forecasted price. 26
DISTRIBUTION GROWTH SINCE IPO Forecasted distribution of $3.70 for 2015, $3.97 for 2016 and annual growth rate of 10% from 2017 to 2020 11% CAGR since IPO $2.51 $2.56 $2.57 $2.86 $3.22 $3.38 $3.54 $3.70 $3.97 $4.00 $3.00 $1.24 $1.49 $1.62 $1.88 $2.16 $2.00 Distribution in $ $0.62 $1.00 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015F 2016F $- 27
MARKWEST INVESTMENT CONSIDERATIONS: WHAT TO EXPECT Maintain strong customer base in key resource plays with high-quality assets and exceptional service Continue to execute on growth projects that are well diversified across the asset base Fee-based margin increasing to approximately 90% for the full-year 2015 Long-term distribution growth of 10% as Northeast shale facilities are completed and producer volumes increase Long-term sustainable total returns in the top tier 28
APPENDIX
RECONCILIATION OF DCF & DISTRIBUTION COVERAGE Three Months Ended Year Ended ($ in millions) 3/31/2015 12/31/2014 Net Income $ 5.5 $ 160.3 Depreciation, amortization and other non-cash operating expenses 135.7 489.4 (Gain) loss on sale or disposal of property, plant and equipment (0.8) 1.1 Amortization of deferred financing costs and debt discount 1.6 7.3 (Earnings) loss from unconsolidated affiliates (0.5) 4.5 Distributions from unconsolidated affiliates 10.9 12.5 Non-cash compensation expense 5.9 10.3 Unrealized loss (gain) on derivative instruments 8.2 (82.1) Deferred income tax (benefit) expense (4.2) 41.6 Cash adjustment for non-controlling interest of consolidated subsidiaries (10.4) (17.9) Revenue deferral adjustment 0.9 7.0 Impairment expense 25.5 62.4 Other (1) 4.6 29.1 Maintenance capital expenditures (2.6) (19.1) Distributable Cash Flow (DCF) $ 180.3 $ 706.4 Total distributions declared for the period 169.9 629.0 Distribution Coverage Ratio (DCF / Total distributions declared) 1.06x 1.12x (1) Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of joint venture capital projects. 30
RECONCILIATION OF ADJUSTED EBITDA LTM Ended Year Ended Year Ended ($ in millions) 3/31/2015 12/31/2014 12/31/2013 Net income $ 149.9 $ 160.3 $ 40.4 Non-cash compensation expense 12.3 10.3 7.8 Unrealized (gain) loss on derivative instruments (62.1) (82.0) 15.6 Interest expense (1) 173.3 165.4 150.1 Depreciation, amortization and other non-cash operating expenses 506.1 489.4 365.7 Loss (gain) on disposal of property, plant and equipment 0.4 1.1 (33.8) Loss on redemption of debt - - 38.5 Provision for income tax expense 25.6 42.2 12.7 Adjustment for cash flow from unconsolidated affiliates 26.2 16.9 4.9 Impairment expense 88.0 62.5 - Adjustment for non-controlling interest in consolidated subsidiaries (25.9) (17.9) 6.1 Other (2) 22.6 26.3 (2.0) Adjusted EBITDA $ 916.4 $ 874.3 $ 606.0 (1) Includes amortization of deferred financing costs and debt discount, and excludes interest expense related to the Steam Methane Reformer. (2) Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of joint venture capital projects 31
RECONCILIATION OF NET OPERATING MARGIN Three Months Ended Year Ended ($ in millions) 3/31/2015 12/31/2014 Income from operations $ 52.5 $ 377.2 Facility expenses 91.8 343.4 Derivative gain (2.8) (95.3) Revenue deferral adjustment and other (5.2) (9.7) Revenue adjustment for unconsolidated affiliate 27.5 41.5 Purchased product costs from unconsolidated affiliate - (0.3) Selling, general and administrative expenses 34.6 126.5 Depreciation 119.7 422.8 Amortization of intangible assets 15.8 64.9 (Gain) loss on disposal of property, plant and equipment (0.8) 1.1 Accretion of asset retirement obligations 0.2 0.6 Impairment expense 25.5 62.4 Net Operating Margin $ 358.8 $ 1,335.1 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