This document provides an overview and highlights of MarkWest's first quarter 2015 results. It discusses increasing processing volumes across its Southwest, Marcellus, and Utica segments. MarkWest processed a total of 5.4 Bcf/d in the first quarter, up 52% year-over-year. The company reported $180 million in distributable cash flow and $230 million in adjusted EBITDA for the quarter. MarkWest has 19 major infrastructure projects currently under construction to increase processing and fractionation capacity going forward.

1. FIRST QUARTER 2015
CONFERENCE CALL PRESENTATION
M a y 6 , 2 0 1 5

2. FORWAR D - L OO KIN G STATEMEN TS
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 forward-looking 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.
2

3. N ON - G AAP MEASU R ES
Distributable Cash Flow (DCF), Adjusted EBITDA and Net Operating Margin are non-GAAP Financial Measures, 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 DCF and Adjusted EBITDA is net income (loss). The GAAP measure most
directly comparable to Net Operating Margin is income from operations. In general, the Partnership defines DCF as net income (loss)
adjusted for (i) depreciation, amortization, and other non-cash operating expenses; (ii) amortization of deferred financing costs and
debt discount; (iii) loss on redemption of debt, net of tax benefit; (iv) impairment of unconsolidated affiliates; (v) gain on sale of
unconsolidated affiliate; (vi) impairment expense; (vii) (earnings) loss from unconsolidated affiliates; (viii) distributions from
(contributions to) unconsolidated affiliates (net of affiliates’ growth capital expenditures); (ix) non-cash compensation expense; (x)
unrealized gain (loss) on derivative instruments; (xi) loss (gain) on the sale or disposal of property, plant and equipment (“PP&E”) (xii)
deferred income tax expense (benefit); (xiii) cash adjustments for non-controlling interest of consolidated subsidiaries; (xiv) revenue
deferral adjustment; (xv) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period; and (xvi)
maintenance capital expenditures, net of joint venture partner contributions. The Partnership defines Adjusted EBITDA as net income
(loss) adjusted for (i) depreciation, amortization, and other non-cash operating expenses; (ii) interest expense; (iii) amortization of
deferred financing costs and debt discount; (iv) loss on redemption of debt; (v) loss (gain) on the sale or disposal of PP&E; (vi)
impairment of unconsolidated affiliates; (vii) gain on sale of unconsolidated affiliate; (viii) impairment expense; (ix) non-cash
derivative activity; (x) non-cash compensation expense; (xi) provision for income tax (benefit); (xii) adjustments for cash flow from
unconsolidated affiliates; and (xiii) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the
period. In general, the Partnership defines Net Operating Margin as segment revenue, excluding any derivative gain (loss), less
purchased product costs excluding any derivative gain (loss).
DCF is a financial performance measure used by management as a key component in the determination of cash distributions paid to
unitholders. The Partnership believes DCF 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,
DCF is commonly used by the investment community because the market value of publicly traded partnerships is based, in part, on DCF
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, the Partnership
believes 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

4. FIR ST QU ARTER 2 0 1 5 H IG H L IG H TS
•Total volume of 5.4 Bcf/d for the first quarter 2015, an increase of 52%
over the first quarter 2014 and 8% over the fourth quarter 2014
•We are now the second largest gas processor in the U.S.
•Reported Distributable Cash Flow (DCF) of $180.3 million and Adjusted
EBITDA of $229.7 million for the first quarter 2015
•Increased distribution to $0.91 cents per common unit for the first quarter
2015, while maintaining a coverage ratio of 1.06 times
•19 major infrastructure projects currently under construction; which when
complete, will increase our processing capacity to 8.4 Bcf/d and
fractionation capacity to over 600,000 Bbl/d
4

5. • Utilization of processing complexes in the
Southwest averaged 83% during the first quarter
2015
• Announced 80 MMcf/d processing expansion in
East Texas to support continued growth of rich-gas
production from Haynesville Shale
• This month, we expect to complete a 60 mile
pipeline connecting the Cana-Woodford system to
our existing Western Oklahoma system
SO U TH W EST SEG MEN T O VERVIEW
5
Processed Volumes (MMcf/d)
Complex
1Q15
Average
Capacity
(MMcf/d) *
1Q15
Average
Volume
(MMcf/d)
1Q15
Utilization
(%)
East Texas 520 497 96%
Western OK 435 291 67%
Southeast OK**
104 104 100%
Gulf Coast 142 100 70%
1Q15 Total 1,201 992 83%
4Q14 Total 1,090 931 85%
*Based on weighted average number of days plant(s) in service
**Processing capacity includes Partnership’s portion of Centrahoma JV
-
200
400
600
800
1,000
1,200
1Q10 4Q10 3Q11 2Q12 1Q13 4Q13 3Q14 2Q15F
Gulf Coast SEOK WOK East Texas
Forecasted
Avg. Increase from
FY2014 to FY2015
~10%
2Q15through4Q15Avg.

6. 0
500
1,000
1,500
2,000
2,500
3,000
3,500
1Q10 4Q10 3Q11 2Q12 1Q13 4Q13 3Q14 2Q15F
Houston Majorsville Mobley Sherwood Keystone
MAR C EL L U S SEG MEN T O VERVIEW
Processed Volumes (MMcf/d) • Processed volumes increased 73% compared
from the first quarter 2014 and 11%
compared to the fourth quarter 2014
• Average utilization of Marcellus processing
assets was 90% in the first quarter 2015
• We process approximately 90% of rich-gas
production from the Marcellus Shale
*Based on weighted average number of days plant(s) in service
6
Complex
1Q15
Average
Capacity
(MMcf/d)*
1Q15
Average
Volume
(MMcf/d)
1Q15
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%
Forecasted
Avg. Increase from
FY2014 to FY2015
~50%
2Q15through4Q15Avg.

7. Doddridge
Marshall
Wetzel
Harrison
Butler
Washington
PENNSYLVANIA
OHIO
Washington
Tyler
Ritchie
Jefferson
Beaver
Allegheny
Greene
Ohio
Brooke
Hancock
MAR KW EST MAR C EL L U S O PER ATIO N S
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
ATEX Express Pipeline
MWE Purity Ethane Pipeline
MWE NGL Pipeline
MWE NGL/Purity Ethane
Pipeline Under Construction
Sunoco Mariner Pipeline
MWE Marcellus Complex
MWE Gathering System
TEPPCO Product Pipeline
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
27 facilities completed: 15 facilities under construction
WEST VIRGINIA
7

8. 0
100
200
300
400
500
600
700
800
900
4Q12 2Q13 4Q13 2Q14 4Q14 2Q15F 4Q15F
Seneca Cadiz
U TIC A SEG MEN T O VERVIEW
• 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
Processed Volumes (MMcf/d)
*Based on weighted average number of days plant(s) in service
8
Complex
1Q15
Average
Capacity
(MMcf/d) *
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%
Forecasted
Avg. Increase from
FY2014 to FY2015
~95%
2Q15through4Q15Avg.

9. Wetzel
Harrison
Noble
OHIO
Belmont
Monroe
Carroll
JeffersonTuscarawas
Guernsey
MAR KW EST U TIC A O PER ATIO N S
9
9 facilities completed: 4 facilities under construction
ATEX Express Pipeline
MWE Purity Ethane Pipeline
MWE NGL Pipeline
MWE NGL/Purity Ethane
Pipeline Under Construction
Sunoco Mariner Pipeline
MWE Utica Complex
MWE Gathering System
TEPPCO Product Pipeline
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
Cadiz III – 200 MMcf/d – 3Q15
Cadiz IV – 200 MMcf/d – 2Q16
De-ethanization – 40,000 Bbl/d – Operational
SENECA COMPLEX
Seneca I – III – 600 MMcf/d – Operational
Seneca IV – 200 MMcf/d – 3Q15

10. -
50,000
100,000
150,000
200,000
250,000
1Q13 3Q13 1Q14 3Q14 1Q15F 3Q15F
C3+ C2
MAR C EL L U S & U TIC A FR AC TIO N ATIO N O VERVIEW
Fractionated Volumes (Bbl/d)
Complex
1Q15 Average
Capacity
(Bbl/d)*
1Q15 Average
Volume
(Bbl/d)
1Q15
Utilization
(%)
Marcellus 123,000 126,500 103%
Utica 69,000 30,300 44%
Total C3+ 192,000 156,800 82%
Total C2 134,000 58,700 44%
• Total C2+ fractionated volumes from the
Marcellus and Utica exceeded 215 MBbl/d
for the first quarter 2015, an increase of
68% from the first quarter 2014
• Scheduled to begin operation of three new
fractionation facilities in 2015, adding over
80,000 Bbl/d of C2+ capacity
• 50% forecasted average increase from full-
year 2014 to full-year 2015
*Based on weighted average number of days plant(s) in service
10
Forecasted
Avg. Increase from
FY2014 to FY2015
~50%
2Q15through4Q15Avg.

11. MAR C EL L U S & U TIC A O PER ATIO N S
4.1Bcf/d
2.6Bcf/d
MarkWest
61%of current
capacity
OPERATES
Market Share of Processing Capacity
Currently Operational
1,000
Facilities Completed
34
Plants Under Construction
18
Processing Capacity
4.1Bcf/d
C2+ Fractionation Capacity
326MBbl/d
215,000
Miles of Pipeline
Field Compression
Horsepower
11
Source: BENTEK Energy - NGL Facilities Databank as of 4.15.2015
MarkWest has 3x the market share of our largest competitor

12. PR O C ESSED VO L U ME G R O W TH
~1.3 Bcf/d ~5.3 Bcf/d~2.3 Bcf/d
We are now the second largest gas processor in the U.S.
Increase of 4 Bcf/d in 4 years
12

13. Fee-Based Percent-of-Proceeds Keep-Whole
0%
20%
40%
60%
80%
100%
FIN AN C IAL FO R EC AST
2015 DCF Forecast: $700MM – $800MM
2015 EBITDA Forecast: $925MM – $1,025MM
NOTE: Net Operating Margin is calculated as segment revenue less purchased product costs
13
53% of C3+
commodity exposure
hedged for 2015
90%Fee-based
Capital Investment Forecast Net Operating Margin Forecast
2015: $1.5B to $1.9B 2015
76%
12%
12%

14. FIN AN C IAL SU MMARY
• 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
MarkWest has over $1.4 billion of liquidity
14

15. APPENDIX

16. R EC ON C IL IATION OF D C F & D ISTR IBU TIO N C O VER AG E
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
16
(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.

17. R EC O N C IL IATIO N O F AD J U STED EBITD A
17
(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
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
17

18. R EC ON C IL IATION OF N ET O PER ATIN G MAR G IN
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
18

19. 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