The latest PowerPoint slide deck MarkWest pushed out to investors and analysts recapping 2014 results and looking forward to 2015. MarkWest, a midstream (pipelines & processing plants) company continues its expansion in the northeast and is perhaps the biggest midstreamer in the Marcellus/Utica.

1. FOURTH QUARTER 2014
CONFERENCE CALL PRESENTATION
F e b r u a r y 2 5 , 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. 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

3. N ON - G AAP MEASU R ES
Distributable Cash Flow (DCF), Adjusted EBITDA 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). In general, the Partnership defines DCF as net income (loss)
adjusted for (i) depreciation, amortization, impairment, 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) non-cash (earnings) loss from unconsolidated affiliates; (vii) distributions from (contributions to)
unconsolidated affiliates (net of affiliates’ growth capital expenditures); (viii) non-cash compensation expense; (ix) non-cash derivative
activity; (x) losses (gains) on the sale or disposal of property, plant and equipment (“PP&E”), net of tax; (xi) provision for deferred
income taxes; (xii) cash adjustments for non-controlling interest of consolidated subsidiaries; (xiii) revenue deferral adjustment; (xiv)
losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period; and (xv) maintenance capital
expenditures, net of joint venture partner contributions and proceeds from trade-in of PP&E. The Partnership defines Adjusted EBITDA
as net income (loss) adjusted for (i) depreciation, amortization, impairment, 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) losses (gains) on the sale
or disposal of PP&E; (vi) impairment of unconsolidated affiliates; (vii) gain on sale of unconsolidated affiliate; (viii) non-cash derivative
activity; (ix) non-cash compensation expense; (x) provision for income taxes; (xi) adjustments for cash flow from unconsolidated
affiliates; and (xii) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period.
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. FOU RTH QU ARTER 2 01 4 H IG H L IG H TS
• Record fourth quarter and full-year 2014 volumes: Total system volume of 5.0 Bcf/d for
fourth quarter: 10% increase over the prior quarter; and 47% increase when comparing
full-year 2013 to 2014
• Record Distributable Cash Flow (DCF) of $201.0 million for fourth quarter and $706.4
million for the full-year 2014, an increase of 46% over the full-year 2013
• Record Adjusted EBITDA of $243.0 million for fourth quarter and $874.3 million for the
full-year 2014, an increase of 44% over the full-year 2013
• Increased fourth quarter 2014 distribution to 90 cents per common unit, while
maintaining a coverage ratio of 1.20 times
• Completed six new facilities increasing processing capacity by 720 MMcf/d and
fractionation capacity by 83,000 Bbl/d
• Announced new projects in Cana-Woodford, East Texas and Marcellus Shale
• 18 major infrastructure projects currently under construction; 10 to be completed during
2015. These new facilities will increase our processing capacity to 8.2 Bcf/d and
fractionation capacity to over 600,000 Bbl/d
4

5. -
200
400
600
800
1,000
1,200
1Q10 3Q10 1Q11 3Q11 1Q12 3Q12 1Q13 3Q13 1Q14 3Q14 1Q15F3Q15F
Gulf Coast SEOK WOK East Texas
• Commenced operations of fourth plant in
East Texas during December 2014
• Announced Panola NGL Pipeline JV in East
Texas with Enterprise and others
• Announced new agreement with Newfield
for STACK play in the Cana-Woodford
• Average utilization of processing complexes
was 85% during the fourth quarter 2014
SO U TH W EST SEG MEN T O VERVIEW
5
1Q15through4Q15Avg.
Processed Volumes (MMcf/d)
Forecasted
Avg. Increase from
FY2014 to FY2015
~12%
Complex
4Q14
Average
Capacity
(MMcf/d) *
4Q14
Average
Volume
(MMcf/d)
Utilization
(%)
East Texas 429 431 100%
Western OK 435 300 69%
Southeast OK**
84 84 100%
Gulf Coast 142 116 82%
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

6. -
500
1,000
1,500
2,000
2,500
3,000
1Q10 4Q10 3Q11 2Q12 1Q13 4Q13 3Q14 2Q15F
Keystone Houston Majorsville Mobley Sherwood
MAR C EL L U S SEG MEN T O VERVIEW
Processed Volumes (MMcf/d) • Marcellus segment continues to achieve record
operating income and volume growth
• Processed volumes increased 15% compared
to third quarter 2014 and 82% from the fourth
quarter 2013
• Average utilization of five Marcellus processing
complexes was 88% in the fourth quarter 2014
*Based on weighted average number of days plant(s) in service
6
Complex
4Q14
Average
Capacity
(MMcf/d)*
4Q14
Average
Volume
(MMcf/d)
Utilization
(%)
Sherwood 930 780 84%
Mobley 555 545 98%
Majorsville 870 765 88%
Houston 355 311 88%
Keystone 210 155 74%
Total 2,920 2,556 88%
Forecasted Avg. Increase
from FY2014 to FY2015
~55%
1Q15through4Q15Avg.

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 – 3Q16
De-ethanization – 20,000 Bbl/d – 3Q16
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 – 1Q16
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 – 3Q15
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
200
400
600
800
4Q12 2Q13 4Q13 2Q14 4Q14 2Q15F 4Q15F
Seneca Cadiz
U TIC A SEG MEN T O VERVIEW
• MarkWest Utica EMG continues to establish the
leading midstream system in the Utica Shale
• Processed volumes increased 42% compared to
last quarter and nearly 300% from the prior year
quarter
• Average utilization of processing complexes
reached 76% during the fourth quarter 2014, up
from 63% last quarter
Processed Volumes (MMcf/d)
*Based on weighted average number of days plant(s) in service
8
Complex
4Q14 Average
Capacity
(MMcf/d) *
4Q14
Average
Volume
(MMcf/d)
Utilization
(%)
Cadiz 255 215 84%
Seneca 600 437 73%
Total 855 652 76%
Forecasted Avg.
Increase
from FY2014 to
FY2015
~100%
1Q15through4Q15Avg.

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
Joint Ventures with
Summit Midstream, LLC
Stabilization Facility – 23,000 Bbl/d – Operational
SENECA COMPLEX
Seneca I – III – 600 MMcf/d – Operational
Seneca IV – 200 MMcf/d – 2Q15
CADIZ COMPLEX
Cadiz I & II – 325 MMcf/d – Operational
Cadiz III – 200 MMcf/d – 2Q15
Cadiz IV – 200 MMcf/d – 1Q16
De-ethanization – 40,000 Bbl/d – Operational

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
~55%Forecasted
Avg. Increase from
FY2014 to FY2015
Fractionated Volumes (Bbl/d)
Complex
4Q14 Average
Capacity
(Bbl/d)*
4Q14 Average
Volume
(Bbl/d)
Utilization
(%)
Marcellus 110,000 116,500 106%
Utica 29,000 24,900 86%
Total C3+ 139,000 141,400 102%
Total C2 134,000 62,500 47%
• Total C2+ fractionated volumes were a record
204 MBbl/d for the fourth quarter 2014, an
increase of 258% from the prior year quarter
• Achieved full utilization of total C3+
fractionation capacity in the fourth quarter,
up from 91% utilization in the third quarter
2014
• Commenced operations of 60,000 Bbl/d
Hopedale II fractionation facility in December
2014, providing additional just-in-time C3+
capacity
*Based on weighted average number of days plant(s) in service
10
1Q15through4Q15Avg.

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
349MBbl/d
215,000
Miles of Pipeline
Field Compression
Horsepower
11
Source: BENTEK Energy - NGL Facilities Databank as of 1.21.2015
MarkWest has 3x the market share of our largest competitor

12. 0.0
1.0
2.0
3.0
4.0
5.0
6.0
2011 2012 2013 2014 2015F
M A R K W E S T ’ S T O TA L P R O C E S S E D V O L U M E F O R E C A S T
1
2
ProcessedVolumes(Bcf/d)
12
5 Bcf/d
For 2015, total
processed volumes are
forecasted to exceed

13. 0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
2008 2009 2010 2011 2012 2013 2014 2015F
2015 Forecast Net Operating Margin by
Contract Type
FEE- BASED MAR G IN G R O W TH
13
Note: Forecast assumes Crude Oil ($/bbl) range
of $47.33 to $58.66 and Natural Gas ($mmbtu)
range of $2.66 to $3.14
NOTE: Net Operating Margin is calculated as segment revenue less purchased product costs
Fee-Based
89%
Increasing Fee-Based Margin to nearly
90% for the Full-Year 2015
13
Increase of
250%
since 2008
44% of C3+
commodity
exposure hedged
for 2015
Keep-Whole
2%
POP&POL
9%

14. C APITAL IN VESTMEN T FO R EC AST
$0
$1,000
$2,000
Previous 2015 Forecast Current 2015 Forecast
Marcellus Utica Southwest
8%
20%
72%
12%
20%
68%
Previous Forecast
$1.8-$2.3 billion
Current Forecast
$1.5-$1.9 billion
14
2016 capital investment forecast reduced by $500 million to $1.5 billion
• Reduced mid-point of 2015 CapEx
forecast by $350 million
• Continuously optimizing capital to
match producers’ revised drilling plans
• Adjusted startup schedule for 10 of 18
facilities currently under construction
• “Just In Time” philosophy for capacity
additions
• Operating facilities at high utilization
to maximize financial efficiency
• Construction costs decreasing as
contractors compete for reduced slate
of industry projects

15. $-
$200
$400
$600
$800
$1,000
$1,200
2011 2012 2013 2014 2015F
DCF Adjusted EBITDA
D C F & AD J U STED EBITD A FO R EC ASTDCF&AdjustedEBITDA($inmillions)
2015 DCF Forecast of $700MM to $800MM &
Adjusted EBITDA Forecast of $925MM to $1,025MM
15
$333
$417
$483
$706
$446
$528
$606
$874
$925–$1,025
$700–$800

16. FIN AN C IAL SU MMARY
• MarkWest preserves a strong balance sheet to fund growth
> We have over $900 million 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
> During 2014, we raised over $1.6 billion through our at-the-market equity program
> Completed a $500 million bond deal in the fourth quarter 2014, 10-year note with a coupon
of 4.875%
> From the third quarter 2014 to the fourth quarter 2014, leverage decreased from 4.4 times to
4.0 times
> We have significantly pre-funded our 2015 capital expenditures and are well positioned
• MarkWest is committed to achieving strong, long-term distribution growth
> For 2014, the distribution was $3.54. We forecast distributions of approximately $3.70 for
2015, $3.97 for 2016 and an annual growth rate of 10% for 2017 to 2020. The annualized
distribution coverage ratio during the entire period is expected to be 1.0 times to 1.2 times
MarkWest has over $900 million of liquidity
16

17. APPENDIX

18. R EC ON C IL IATION OF D C F & D ISTR IBU TIO N C O VER AG E
Year Ended Year Ended
($ in millions) 12/31/2014 12/31/2013
Net Income $ 160.3 $ 40.4
Depreciation, amortization and other non-cash operating expenses 489.4 365.7
Loss (gain) on sale or disposal of property, plant and equipment, net of tax benefit 1.1 (30.7)
Loss on redemption of debt, net of tax benefit - 36.2
Amortization of deferred financing costs and debt discount 7.3 6.7
Loss (earnings) from unconsolidated affiliates 4.5 (1.4)
Distributions from unconsolidated affiliates 12.5 6.4
Non-cash compensation expense 10.3 7.8
Unrealized (gain) loss on derivative instruments (82.1) 15.6
Deferred income tax expense 41.6 23.9
Cash adjustment for non-controlling interest of consolidated subsidiaries (17.9) 6.1
Revenue deferral adjustment 7.0 7.2
Impairment expense 62.4 -
Other (1)
29.1 18.5
Maintenance capital expenditures (2) (19.1) (19.0)
Distributable Cash Flow (DCF) $ 706.4 $ 483.4
Total distributions declared for the period 629.0 490.6
Distribution Coverage Ratio (DCF / Total distributions declared) 1.12x 0.99x
18
(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.
(2) Net of joint venture partner contributions.

19. R EC O N C IL IATIO N O F AD J U STED EBITD A
19
(1) Includes amortization of deferred financing costs and debt discount, and excludes interest expense related to the Steam Methane Reformer.
(2) For the three months and year ended December 31, 2014, Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of
joint venture capital projects.
Year Ended Year Ended Year Ended
($ in millions) 12/31/2014 12/31/2013 12/31/2012
Net income $ 160.3 $ 40.4 $ 217.0
Non-cash compensation expense 10.3 7.8 8.2
Unrealized (gain) loss on derivative instruments (82.1) 15.6 (102.1)
Interest expense (1)
165.4 150.1 117.1
Depreciation, amortization and other non-cash operating expenses 489.4 365.7 237.6
Loss (gain) on disposal of property, plant and equipment 1.1 (33.8) 6.2
Loss on redemption of debt - 38.5 -
Provision for income tax expense 42.2 12.7 38.3
Adjustment for cash flow from unconsolidated affiliates 16.9 4.9 6.1
Impairment expense 62.4 - -
Other(2) 8.4 4.1 0.1
Adjusted EBITDA $ 874.3 $ 606.0 $ 528.5
19

20. R EC ON C IL IATION OF N ET O PER ATIN G MAR G IN
Year Ended Year Ended
($ in millions) 12/31/2014 12/31/2013
Income from operations $ 377.2 $ 245.9
Facility expenses 343.4 291.1
Derivative (gain) loss (95.3) 25.8
Revenue deferral adjustment and other (9.7) 6.2
Revenue adjustment for unconsolidated affiliate 41.5 -
Purchased product costs from unconsolidated affiliate (0.3) -
Selling, general and administrative expenses 126.5 101.6
Depreciation 422.8 299.9
Amortization of intangible assets 64.9 64.6
Loss (gain) on disposal of property, plant and equipment 1.1 (33.8)
Accretion of asset retirement obligations 0.6 0.8
Impairment of goodwill 62.4 -
Net Operating Margin $ 1,335.1 $ 1,002.1
20

21. 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