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

F O RWA R D - L O O K I N G S TAT E M E N T S

T he statements inc lude d in th is presentat io n conta in “ forward- look in g statements ” with in the meaning o f the Secur i t ie s Act o f 1933 and the Secur i t ie s Exchange Act o f 1934, each as amended. These forward- look ing statements (which in many instances can be ident i f i e d by wo rds l ike “may,” “wi l l , ” “should,” “expects ,” “p lans ,” “bel ie ve s , ” and other comparable words) are based on the Partnershi p’s current expectat ions and bel iefs concerning future develop m en ts and their potent ia l ef fects on the Partnershi p, but are no t guarantees o f future perfo rmance, and invo lve r i sks and uncerta int i es . You are caut ioned not to p lace undue re l iance on forward-lo o k ing statements , as many o f these factors are beyond our abi l i ty to contro l or predic t , and which speak only as o f the date hereof . T he Partnership undertak es no o bl igat io n to publ ic ly update or rev ise any forward- lo ok in g statements a f ter the date they are made, whether as a resul t o f new informat ion, future events , o r o therwise. You are urged to carefu l ly rev iew and cons ider the caut ionary statements and o ther d isc lo sur es made in the Partnershi p’ s Annual Report on Form 10-K for f i sca l year 2014, inc ludi n g under the heading “R isk Facto rs ,” which ident i f y and d iscuss s igni f icant r i sks , uncerta int ie s , and var ious other factors that could cause actua l resul ts to vary s igni f icant l y f ro m tho se expected or impl i e d in the fo rward- look ing statements . Among the facto rs that could cause resul ts to d i f fer mater ia l l y are those r i sks d iscusse d in the per iodic reports f i led with the SEC, inc ludi n g MarkWest ’ s Annual Report o n Fo rm 10-K for the year ended December 31, 2014. I f any o f the uncerta int ie s or r i sks develo p into actua l events o r o ccurrences, o r i f under l y i n g assumpt ion s prove incorrect , i t co uld cause actua l resul ts to vary s igni f icant l y f rom tho se express e d in the presentat io n, and MarkWest ’ s bus ine ss , f inanc ia l condit ion, or resul ts o f operat ions could be mater ia l l y adverse l y a f fected. Key uncerta int i es and r i sks that may d i rect ly a f fect MarkWest ’ s performance, future growth, resul ts o f operat ions , and f inanc ia l condit ion, inc lude, but are no t l imite d to :

• Fluctuat ion s and vo lat i l i ty o f natura l gas , NGL products , and o i l pr ices ;

• A reduct io n in natura l gas o r ref iner y o f f -gas product ion which MarkWest gathers , t ransports , processes , and/or f ract ionates;

• A reduct ion in the demand fo r the products MarkWest produces and se l l s ;

• Financ ia l c redi t r i sks / fa i lure o f customers to sat i s fy payment or o ther obl igat ion s under MarkWest ’ s contracts ;

• Ef fects o f MarkWest ’ s debt and other f inanc ia l obl igat io ns , access to capi ta l , o r i t s future f inanc ia l o r operat iona l f lex ib i l i t y o r l iqui d i ty ;

• Co nstruct io n, pro curemen t , and regulatory r i sks in our develo pm e nt pro jects ;

• Hurr icanes, f i res , and other natura l and acc identa l events impact ing MarkWest ’ s o perat ions , and adequate insurance co verage;

• Terro r ist a t tacks d i rected at MarkWest fac i l i t ies or re lated fac i l i t ies ;

• Changes in and impacts o f laws and regulat io n s a f fect ing MarkWest operat ions and r i sk management st rategy; and

• Fa i lure to integrate recent o r future acquis i t io ns .

2

N O N - G A A P M E A S U R E S

Distr ibu tab l e Cash F low (DCF) , Adjusted EBIT DA and Net Operat ing Margin are non-GAAP F inanc ia l Measures , and should not be cons idere d separate ly f rom or as a subst i t ut e for net income, income f rom operat ions, or cash f low as ref lected in our f inanc ia l s tatements . The GAAP measure most d i rect ly comparable to DCF and Adjusted EBITDA is net income ( loss) . The GAAP measure most d i rect ly co mparable to Net Operat in g Margin i s income f rom operat io ns. In genera l , the Partnershi p def ine s DCF as net income ( loss) adjusted fo r ( i ) deprec iat io n, amo rt izat ion, and other non-cash operat ing expens es; ( i i ) amort izat ion o f deferred f inanc ing costs and debt d iscount ; ( i i i ) lo ss o n redempt io n o f debt , net o f tax benef i t ; ( iv ) impairm e nt o f unco nso l i dat e d af f i l ia tes ; (v ) ga in on sa le o f unconso l i dat ed af f i l ia te; (v i ) impairm e nt expense; (v i i ) (earnings) loss f rom unconso l idat e d af f i l ia tes ; (v i i i ) d ist r ib u t io ns f rom (co ntr ibut ion s to ) unco nso l i dat e d af f i l ia tes (net o f a f f i l ia tes ’ growth capi ta l expend i t ur es ) ; ( i x ) non-cash compensat ion expense ; (x) unrea l i ze d ga in ( lo ss) o n der ivat i ve instrum e nt s; ( x i ) loss (ga in) on the sa le or d isposa l o f property , p lant and equip me n t ( “PP&E”) (x i i ) deferred inco me tax expens e (benef i t ) ; ( x i i i ) cash adjustmen ts for non-contro l l i ng interes t o f conso l idated subs id iar i e s ; ( x iv ) revenue deferra l adjustmen t; ( xv ) losses (ga ins) re lat ing to other miscel la neo u s non-cash amounts a f fect ing net income for the per iod; and (xv i ) maintenanc e capi ta l expend it u r es , net o f jo int venture partner contr ibut io n s. The Partnershi p def ine s Adjusted EBITDA as net income ( lo ss) adjusted for ( i ) deprec iat io n, amo rt izat ion, and other non-cash operat ing expense s; ( i i ) interest expens e; ( i i i ) amort izat ion o f deferred f inanc ing costs and debt d isco unt ; ( iv ) loss on redempt io n o f debt ; (v ) loss (ga in) on the sa le or d isposa l o f PP&E; (v i ) impairme n t o f unconso l i date d af f i l ia tes ; (v i i ) ga in on sa le o f unconso l i dat e d af f i l ia te; (v i i i ) impairm e nt expens e; ( ix ) non-cash der ivat i v e act iv i ty ; ( x ) no n-cash co mpensat io n expens e; ( x i ) prov is io n for income tax (benef i t ) ; ( x i i ) adjustment s for cash f low f rom unco nso l i dat ed af f i l ia tes ; and (x i i i ) losses (ga ins) re lat ing to other miscel lan eo us non-cash amounts a f fect ing net income for the per iod. In genera l , the Partnershi p def ines Net Operat in g Margin as segment revenu e, exc ludi n g any der ivat i v e ga in ( loss) , less purchased product costs exc ludi n g any der ivat iv e ga in ( loss) . DCF i s a f inanc ia l performance measure used by management as a key component in the determi nat io n o f cash d ist r i b ut io ns pa id to uni tho l d er s . The Partnershi p bel ie ve s DCF i s an important f inanc ia l measure for uni tho l d er s as an indicator o f cash return on investm e nt and to eva luate whether the Partnershi p i s generat i n g suf f ic ient cash f low to support quarter ly d ist r ib u t io ns. In addit ion, DCF i s co mmo nly used by the investm e nt co mmunity because the market va lue o f publ ic l y t raded partnersh i ps i s based, in part , on DCF and cash d ist r ib u t io ns pa id to uni tho l d er s . Adjuste d EBITDA is a f inanc ia l perfo rmance measure used by manageme nt , industr y ana lysts , investors , lender s , and rat ing agenc ies to assess the f inanc ia l performance and o perat ing resul ts o f the Partnership ’s ongo ing bus ine ss operat ions. Addit io na l l y , the Partnershi p bel iev e s Adjusted EBIT DA prov ides useful informat io n to investors for t rendin g, ana lyz ing and benchmark i n g our operat ing resul ts f rom per iod to per iod as co mpared to o ther companies that may have d i f fere nt f inanc ing and capi ta l s t ructures . Net Operat in g Margin i s a f inanc ia l perfo rmance measure used by manageme nt and investor s to eva luate the under l y i ng basel in e operat ing perfo rmance o f o ur co ntractua l arrangemen ts . Manageme nt a lso uses Net Operat ing Margin to eva luate the Partnershi p’s f inanc ia l performance fo r purpo ses o f p lanni n g and forecast ing. P lease see the Appen d ix for reco nc i l ia t io n s o f D ist r ibuta b l e Cash F low, Adjuste d EBITDA, and Net Operat ing Margin to the most d i rect ly comparable GAAP measure.

3

F I R S T Q U A RT E R 2 0 1 5 H I G H L I G H T S

•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

• 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

S O U T H W E S T S E G M E N T O V E RV I E W

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 2Q15FGulf Coast SEOK WOK East Texas

Forecasted Avg. Increase from FY2014 to FY2015

~10%

2Q15

thro

ugh

4Q15

Avg

.

0

500

1,000

1,500

2,000

2,500

3,000

3,500

1Q10 4Q10 3Q11 2Q12 1Q13 4Q13 3Q14 2Q15FHouston Majorsville Mobley Sherwood Keystone

M A R C E L L U S S E G M E N T O V E RV I E W

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%

2Q15

thro

ugh

4Q15

Avg

.

Doddridge

Marshall

Wetzel

Harrison

Butler

Washington

PENNSYLVANIA

OHIO

Washington

Tyler

Ritchie

Jefferson

Beaver

Allegheny

Greene

Ohio

Brooke

Hancock

M A R K W E S T M A R C E L L U S O P E R AT I O 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

0

100

200

300

400

500

600

700

800

900

4Q12 2Q13 4Q13 2Q14 4Q14 2Q15F 4Q15F

Seneca Cadiz

U T I C A S E G M E N T O V E RV I E W

• 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%

2Q15

thro

ugh

4Q15

Avg

.

Wetzel

Harrison

Noble

OHIO

Belmont

Monroe

Carroll

Jefferson Tuscarawas

Guernsey

M A R K W E S T U T I C A O P E R AT I O 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

-

50,000

100,000

150,000

200,000

250,000

1Q13 3Q13 1Q14 3Q14 1Q15F 3Q15FC3+ C2

M A R C E L L U S & U T I C A F R A C T I O N AT I O N O V E RV I E W

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%

2Q15

thro

ugh

4Q15

Avg

.

M A R C E L L U S & U T I C A O P E R AT I O N S

4.1 Bcf/d

2.6 Bcf/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

P R O C E S S E D V O L U M E G R O W T H

~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

Fee-Based Percent-of-Proceeds Keep-Whole0%

20%

40%

60%

80%

100%

F I N A N C I A L F O R E C A S T

2015 DCF Forecast: $700MM – $800MM 2015 EBITDA Forecast: $925MM – $1,025MM

NOTE: Net Operating Margin is calculated as segment revenue less purchased product costs

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53% of C3+ commodity exposure

hedged for 2015

90%

Fee

-bas

ed

Capital Investment Forecast Net Operating Margin Forecast 2015: $1.5B to $1.9B 2015

76%

12%

12%

F I N A N C I A L S U M M A RY

• 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

APPENDIX

R E C O N C I L I AT I O N O F D C F & D I S T R I B U T I O N C O V E R A G 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.

R E C O N C I L I AT I O N O F A D J U S T E D E B I T D 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

R E C O N C I L I AT I O N O F N E T O P E R AT I N G M A R G I N

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

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1515 Arapahoe Street

Tower 1, Suite 1600

Denver, Colorado 80202

PHONE: 303-925-9200

INVESTOR RELATIONS: 866-858-0482

EMAIL: investorrelat ions@markwest.com

W EBSITE: www.markwest.com