MarkWest Energy Partners Reports First Quarter Financial Results, Record Volumes and Increases Common Unit Distribution

  MarkWest Energy Partners Reports First Quarter Financial Results, Record
  Volumes and Increases Common Unit Distribution

  *Acquired Granite Wash midstream assets from Chesapeake Energy in Texas
    Panhandle and Western Oklahoma for $245 million and entered into long-term
    fee-based gathering and processing agreements.
  *Placed into service four additional processing facilities with combined
    capacity of 645 MMcf/d. The Partnership has 18 major processing and
    fractionation projects currently under construction, which are expected to
    be completed by the end of 2014.
  *Executed an agreement with Antero Resources to expand the Sherwood
    processing complex by 200 MMcf/d, bringing total capacity in the Marcellus
    Shale to 3.2 Bcf/d by the end of 2014.
  *Executed agreements with four producers in the Utica Shale, bringing total
    producers under contract to six.
  *Executed long-term fee-based agreement with Newfield Exploration to
    acquire and develop rich- gas gathering facilities in the Eagle Ford
    Shale.
  *Fee-based net operating margin increased from 39 percent to 58 percent
    when compared to the first quarter of last year.

Business Wire

DENVER -- May 08, 2013

MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported
quarterly cash available for distribution to common unitholders, or
distributable cash flow (DCF), of $110.2 million for the three months ended
March 31, 2013, compared to $109.2 million for the three months ended March
31, 2012. DCF for the three months ended March 31, 2013 represents 102 percent
coverage of the first quarter distribution of $108.4 million or $0.83 per
common unit, which will be paid to unitholders on May 15, 2013. The first
quarter 2013 distribution represents an increase of $0.01 per common unit or
1.2 percent over the fourth quarter 2012 distribution and an increase of $0.04
per common unit or 5.1 percent compared to the first quarter 2012
distribution. As a Master Limited Partnership, cash distributions to common
unitholders are largely determined based on DCF. A reconciliation of DCF to
net income, the most directly comparable GAAP financial measure, is provided
within the financial tables of this press release.

The Partnership reported Adjusted EBITDA of $140.8 million for the three
months ended March 31, 2013, compared to $153.1 million for the same period in
2012. The Partnership believes the presentation of Adjusted EBITDA provides
useful information because it is commonly used by investors in Master Limited
Partnerships to assess financial performance and operating results of ongoing
business operations. A reconciliation of Adjusted EBITDA to net income, the
most directly comparable GAAP financial measure, is provided within the
financial tables of this press release.

The Partnership reported (loss) income before provision for income tax for the
three months ended March 31, 2013 of ($14.2) million, compared to $20.8
million for the same period in 2012. Income (loss) before provision for income
tax includes non-cash gains (losses) associated with the change in fair value
of derivative instruments of $9.0 million and ($48.2) million for the three
months ended March 31, 2013 and March 31, 2012, respectively, and a (loss)
associated with the redemption of debt of ($38.5) million for the three months
ended March 31, 2013. Excluding these items, income before provision for
income tax for the three months ended March 31, 2013 and 2012 would have been
$15.3 million and $69.0 million, respectively.

“Our diverse set of midstream assets continues to deliver strong financial
results and create opportunities for future growth,” said Frank Semple,
Chairman, President and Chief Executive Officer. “The recent completion of
nine major projects since last October and the planned completion of 18
additional major projects over the next year and a half will continue to grow
our fee-based income and distributable cash flow for years to come. In
addition, we are very pleased with the acquisition of the Chesapeake assets in
the Granite Wash and our entrance into the liquids-rich Eagle Ford Shale
through our strategic agreement with Newfield Exploration.”

BUSINESS HIGHLIGHTS

Liberty:

  *In February 2013, the Partnership commenced operations of an additional
    120 million cubic feet per day (MMcf/d) processing facility at the Mobley
    complex in Wetzel County, West Virginia. This facility is supported by
    long-term, fee-based agreements with EQT Corporation (NYSE: EQT), Magnum
    Hunter Resources Corporation (NYSE: MHR) and other producers. With the
    completion of the second facility, total processing capacity at Mobley is
    320 MMcf/d and in less than six months the utilization of the complex has
    increased to approximately 70 percent.
  *In May 2013, the Partnership commenced operations of Majorsville III, a
    200 MMcf/d processing facility in Marshall County, West Virginia.
    Majorsville III is supported by long-term, fee-based agreements with
    Consol Energy, Inc. (NYSE: CNX) (CNX) and Noble Energy, Inc. (NYSE: NBL).
    The facility will also provide additional processing capacity to Range
    Resources Corporation (NYSE: RRC) (Range), Chesapeake Energy Corporation
    (NYSE: CHK) (Chesapeake) and other producers prior to the completion of
    subsequent facilities. The Partnership’s first two processing facilities
    are operating at approximately 90 percent utilization and with the
    addition of the third facility, total processing capacity of the
    Majorsville complex has increased to 470 MMcf/d.
  *In May 2013, the Partnership commenced operations of Sherwood II, a 200
    MMcf/d processing facility in Doddridge County, West Virginia. Sherwood II
    is supported by long-term, fee-based agreements with Antero Resources
    (Antero). The Partnership’s first 200 MMcf/d facility is operating near
    full capacity in just over six months and the completion of the second
    facility brings total processing capacity at the Sherwood complex to 400
    MMcf/d.

Utica:

  *In February 2013, the Partnership, together with EMG, completed an Amended
    and Restated Limited Liability Company Agreement (Amended LLC Agreement)
    for MarkWest Utica EMG. The Amended LLC Agreement increases EMG’s capital
    commitment to MarkWest Utica EMG from $500 million to $950 million. The
    transaction provides the Partnership with flexibility in the timing of
    future capital contributions to MarkWest Utica EMG and accelerates the
    continued development of critical midstream infrastructure in the highly
    prospective Utica Shale.
  *In February 2013, MarkWest Utica EMG announced the execution of definitive
    agreements with Rex Energy Corporation (NYSE: REXX) (Rex) to provide
    gathering, processing, fractionation, and marketing services in the Utica
    Shale. MarkWest Utica EMG expects to begin providing the full-suite of
    midstream services for Rex by the end of the second quarter of 2013.
  *In March 2013, MarkWest Utica EMG announced the execution of definitive
    agreements with PDC Energy, Inc. (NASDAQ: PDCE) (PDC) to provide
    gathering, processing, fractionation, and marketing services in the Utica
    Shale. MarkWest Utica EMG expects to begin providing the full-suite of
    midstream services for PDC by the end of the second quarter of 2013.
  *In May 2013, MarkWest Utica EMG announced the execution of definitive
    agreements with CNX and an additional producer to provide processing,
    fractionation, and marketing services in the Utica Shale.
  *In May 2013, MarkWest Utica EMG is commencing operations of Cadiz I, a 125
    MMcf/d cryogenic processing facility in Harrison County, Ohio. Cadiz I is
    supported by fee-based agreements with Gulfport Energy Corporation
    (NASDAQ: GPOR), Antero and other producers.

Southwest:

  *Today, the Partnership announced the execution of definitive agreements to
    acquire 100% of the ownership interests of midstream assets in the Texas
    Panhandle and Western Oklahoma from a wholly owned subsidiary of
    Chesapeake for consideration of $245 million in cash. In conjunction with
    the acquisition, the Partnership has executed long-term, fee-based
    agreements with Chesapeake for gas gathering and processing services. As
    part of the gas processing agreement, Chesapeake has dedicated to the
    Partnership approximately 130,000 acres throughout the Anadarko Basin. The
    transaction is immediately accretive and the Partnership expects it to
    contribute $30 million to EBITDA for the full-year 2014.
  *In May 2013, the Partnership announced the execution of long-term
    fee-based agreement with Newfield Exploration (NYSE: NFX) (Newfield) to
    acquire and develop rich-gas gathering facilities in the Eagle Ford Shale.
    The Partnership will construct additional gathering pipelines, field
    compression, and liquids storage to support production from Newfield’s
    West Asherton project in Dimmit County, Texas. The Partnership plans
    capital investment of approximately $50 million to support Newfield’s
    development plans.

Capital Markets

  *In January 2013, the Partnership completed a public offering of $1.0
    billion of 4.50% senior unsecured notes priced at par due in 2023. A
    portion of the net proceeds of approximately $986.0 million, together with
    cash on hand resulting in part from recent equity offerings, was used to
    fund the redemption of all of its outstanding 8.75% senior notes due 2018,
    and a portion of its 6.50% senior notes due 2021 and 6.25% senior notes
    due 2022, with the balance of such proceeds to be used to fund the
    Partnership’s capital expenditure program and for general partnership
    purposes.
  *During the first quarter of 2013, the Partnership offered 1.9 million
    units and received net proceeds of approximately $103.9 million under the
    continuous offering program that was launched in the fourth quarter of
    2012.

FINANCIAL RESULTS

Balance Sheet

  *As of March 31, 2013, the Partnership had $502.3 million of cash and cash
    equivalents in wholly owned subsidiaries and $1.19 billion remaining
    capacity under its $1.2 billion revolving credit facility after
    consideration of $11.3 million of outstanding letters of credit.

Operating Results

  *Operating income before items not allocated to segments for the three
    months ended March 31, 2013, was $163.1 million, a decrease of $31.1
    million when compared to segment operating income of $194.2 million over
    the same period in 2012. This decrease was primarily attributable to lower
    commodity prices compared to the prior year quarter. Processed volumes
    continued to remain strong, growing approximately 40 percent when compared
    to the first quarter of 2012, primarily due to the Partnership’s Liberty
    Segment and East Texas operations.

    A reconciliation of operating income before items not allocated to
    segments to income (loss) before provision for income tax, the most
    directly comparable GAAP financial measure, is provided within the
    financial tables of this press release.

  *Operating income before items not allocated to segments does not include
    gains (losses) on commodity derivative instruments. Realized gains
    (losses) on commodity derivative instruments were $1.8 million in the
    first quarter of 2013 and ($17.6) million in the first quarter of 2012.

Capital Expenditures

  *For the three months ended March 31, 2013, the Partnership’s portion of
    capital expenditures was $366.2 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership’s forecast for DCF has been narrowed to a range of
$500 million to $540 million based on its current forecast of operational
volumes and revised prices for crude oil, natural gas and natural gas liquids;
and derivative instruments currently outstanding. A commodity price
sensitivity analysis for forecasted 2013 DCF is provided within the tables of
this press release.

The Partnership’s portion of growth capital expenditures for 2013 is unchanged
and remains in a range of $1.5 billion to $1.8 billion. These expenditures do
not include the Granite Wash acquisition cost of $245 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, May 9,
2013, at 12:00 p.m. Eastern Time to review its first quarter 2013 financial
results. Interested parties can participate in the call by dialing (800)
475-0218 (passcode “MarkWest”) approximately ten minutes prior to the
scheduled start time. To access the webcast, please visit the Investor
Relations section of the Partnership’s website at www.markwest.com. A replay
of the conference call will be available on the MarkWest website or by dialing
(888) 402-8736 (no passcode required).

MarkWest Energy Partners, L.P. is a master limited partnership engaged in the
gathering, processing and transportation of natural gas; the gathering,
transportation, fractionation, storage and marketing of natural gas liquids;
and the gathering and transportation of crude oil. MarkWest has a leading
presence in many unconventional gas plays including the Marcellus Shale, Utica
Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash
formation.

This press release 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 MarkWest believes that the expectations
reflected in the forward-looking statements are reasonable, MarkWest can give
no assurance that such expectations will prove to be correct. The
forward-looking statements involve risks and uncertainties that affect
operations, financial performance, and other factors as discussed in filings
with the Securities and Exchange Commission (SEC). 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, 2012 and our Quarterly Report on
Form 10-Q for the quarter ended March 31, 2013. You are urged to carefully
review and consider the cautionary statements and other disclosures made in
those filings, specifically those under the heading “Risk Factors.” MarkWest
does not undertake any duty to update any forward-looking statement except as
required by law.


MarkWest Energy Partners, L.P.
Financial Statistics
(unaudited, in thousands, except per unit data)
                                                          
                                            Three months ended March 31,
Statement of Operations Data                2013             2012
Revenue:
Revenue                                     $  376,137       $   399,181
Derivative loss                               (185      )      (48,715    )
Total revenue                                 375,952         350,466    
                                                             
Operating expenses:
Purchased product costs                        152,557           154,555
Derivative (gain) loss related to              (10,704   )       18,800
purchased product costs
Facility expenses                              59,755            48,840
Derivative gain related to facility            (332      )       (1,746     )
expenses
Selling, general and administrative            25,408            25,224
expenses
Depreciation                                   69,597            41,145
Amortization of intangible assets              14,830            10,985
Loss on disposal of property, plant and        138               986
equipment
Accretion of asset retirement obligations     353             238        
Total operating expenses                      311,602         299,027    
                                                             
Income from operations                         64,350            51,439
                                                             
Other (expense) income:
Loss from unconsolidated affiliate             (85       )       (9         )
Interest income                                149               72
Interest expense                               (38,336   )       (29,472    )
Amortization of deferred financing costs
and discount (a component of interest          (1,830    )       (1,270     )
expense)
Loss on redemption of debt                     (38,455   )       -
Miscellaneous income, net                     -               58         
(Loss) income before provision for income      (14,207   )       20,818
tax
                                                             
Provision for income tax (benefit)
expense:
Current                                        (5,414    )       15,341
Deferred                                      11,971          (10,796    )
Total provision for income tax                6,557           4,545      
                                                             
Net (loss) income                              (20,764   )       16,273
                                                             
Net loss (income) attributable to              5,304             (253       )
non-controlling interest
                                                            
Net (loss) income attributable to the       $  (15,460   )   $   16,020     
Partnership's unitholders
                                                             
Net (loss) income attributable to the
Partnership's common unitholders per                       
common unit:
Basic                                       $  (0.12     )   $   0.16       
Diluted                                     $  (0.12     )   $   0.14       
                                                             
Weighted average number of outstanding
common units:
Basic                                         128,615         96,840     
Diluted                                       128,615         117,593    
                                                             
Cash Flow Data
Net cash flow provided by (used in):
Operating activities                        $  85,043        $   207,913
Investing activities                        $  (609,361  )   $   (252,969   )
Financing activities                        $  830,589       $   278,674
                                                             
Other Financial Data
Distributable cash flow                     $  110,194       $   109,177
Adjusted EBITDA                             $  140,810       $   153,140
                                                             
                                                             
Balance Sheet Data                          March 31, 2013   December 31, 2012
Working capital                             $  173,419       $   (82,587    )
Total assets                                   7,720,554         6,835,716
Total debt                                     3,022,521         2,523,051
Total equity                                   3,240,300         3,215,591
                                                                            

                                                             
MarkWest Energy Partners, L.P.
Operating Statistics
                                                                    
                                                  Three months ended March 31,
                                                  2013              2012
Liberty
Gathering system throughput (Mcf/d)               605,400           308,100
Natural gas processed (Mcf/d)                     828,100           392,100
NGLs fractionated (Bbl/d)                         37,000            20,000
NGL sales (gallons, in thousands) (1)             145,900           97,500
                                                                    
Utica (2)
Gathering system throughput (Mcf/d)               9,000             N/A
Natural gas processed (Mcf/d)                     7,900             N/A
                                                                    
Northeast
Natural gas processed (Mcf/d)                     302,600           321,700
NGLs fractionated (Bbl/d)                         17,100            16,700
                                                                    
Keep-whole sales (gallons, in thousands)          37,400            49,500
Percent-of-proceeds sales (gallons, in            34,900            33,000
thousands)
Total NGL sales (gallons, in thousands)           72,300            82,500
                                                                    
Crude oil transported for a fee (Bbl/d)           10,300            10,400
                                                                    
Southwest
East Texas gathering systems throughput (Mcf/d)   500,300           410,000
East Texas natural gas processed (Mcf/d)          339,500           242,500
East Texas NGL sales (gallons, in thousands)      80,600            63,400
                                                                    
Western Oklahoma gathering system throughput      202,600           262,000
(Mcf/d) (3)
Western Oklahoma natural gas processed (Mcf/d)    186,300           203,800
Western Oklahoma NGL sales (gallons, in           54,800            57,300
thousands)
                                                                    
Southeast Oklahoma gathering system throughput    461,300           501,200
(Mcf/d)
Southeast Oklahoma natural gas processed          151,200           101,700
(Mcf/d) (4)
Southeast Oklahoma NGL sales (gallons, in         39,300            33,000
thousands)
Arkoma Connector Pipeline throughput (Mcf/d)      273,800           328,700
                                                                    
Other Southwest gathering system throughput       20,600            25,000
(Mcf/d) (5)
                                                                    
Gulf Coast refinery off-gas processed (Mcf/d)     95,300            120,300
Gulf Coast liquids fractionated (Bbl/d)           17,200            23,400
Gulf Coast NGL sales (gallons excluding           65,100            89,300
hydrogen, in thousands)
                                                                    

(1)  Includes sale of all purity products fractionated at the Liberty
      facilities and sale of all unfractionated NGLs.
(2)   Utica operations began in August 2012.
      Includes natural gas gathered in Western Oklahoma and from the Granite
(3)   Wash formation in the Texas Panhandle as management considers this one
      integrated area of operations.
(4)   The natural gas processing in Southeast Oklahoma is outsourced to
      Centrahoma or other third party processors.
(5)   Excludes lateral pipelines where revenue is not based on throughput.


MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(unaudited, in thousands)
                                                                 
Three months
ended March 31,   Southwest     Northeast     Liberty     Utica        Total
2013
Revenue           $ 211,446     $ 57,336      $ 108,497   $ 623        $ 377,902
                                                                       
Operating
expenses:
Purchased           114,102       19,662        18,793      -            152,557
product costs
Facility           29,123      6,524       22,636     3,962      62,245
expenses
Total operating
expenses before
items not           143,225       26,186        41,429      3,962        214,802
allocated to
segments
                                                                       
Portion of
operating
income (loss)      1,387       -           -          (1,339 )    48
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 66,834     $ 31,150     $ 67,068    $ (2,000 )   $ 163,052
not allocated
to segments
                                                                       
                                                                       
Three months
ended March 31,   Southwest     Northeast     Liberty     Utica        Total
2012
Revenue           $ 238,954     $ 86,918      $ 75,577    $ -          $ 401,449
                                                                       
Operating
expenses:
Purchased           104,233       25,687        24,635      -            154,555
product costs
Facility           32,630      6,378       12,247     -          51,255
expenses
Total operating
expenses before
items not           136,863       32,065        36,882      -            205,810
allocated to
segments
                                                                       
Portion of
operating
income             1,446       -           -          -          1,446
attributable to
non-controlling
interests
Operating
income before
items not         $ 100,645    $ 54,853     $ 38,695    $ -         $ 194,193
allocated to
segments
                                                                       
                                                                       
                  Three months ended March
                  31,
                  2013          2012
                                                                       
Operating
income before
items not         $ 163,052     $ 194,193
allocated to
segments
Portion of
operating
income              48            1,446
attributable to
non-controlling
interests
Derivative gain
(loss) not          10,851        (65,769 )
allocated to
segments
Revenue
deferral            (1,765  )     (2,268  )
adjustment
Compensation
expense
included in
facility            (387    )     (449    )
expenses not
allocated to
segments
Facility
expenses            2,877         2,864
adjustments
Selling,
general and         (25,408 )     (25,224 )
administrative
expenses
Depreciation        (69,597 )     (41,145 )
Amortization of
intangible          (14,830 )     (10,985 )
assets
Loss on
disposal of         (138    )     (986    )
property, plant
and equipment
Accretion of
asset              (353    )    (238    )
retirement
obligations
Income from         64,350        51,439
operations
Other income
(expense):
Loss from
unconsolidated      (85     )     (9      )
affiliate
Interest income     149           72
Interest            (38,336 )     (29,472 )
expense
Amortization of
deferred
financing costs
and discount (a     (1,830  )     (1,270  )
component of
interest
expense)
Loss on
redemption of       (38,455 )     -
debt
Miscellaneous      -           58      
income, net
(Loss) income
before            $ (14,207 )   $ 20,818  
provision for
income tax
                                                                       

                                                               
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
                                                                   
                                                  Three months ended March 31,
                                                  2013             2012
                                                                   
Net (loss) income                                 $  (20,764   )   $ 16,273
Depreciation, amortization, impairment, and          84,996          53,432
other non-cash operating expenses
Loss on redemption of debt, net of tax benefit       36,178          -
Amortization of deferred financing costs and         1,830           1,270
discount
Non-cash loss from unconsolidated affiliate          85              9
Distributions from unconsolidated affiliate          -               900
Non-cash compensation expense                        2,384           2,710
Non-cash derivative activity                         (9,033    )     48,217
Provision for income tax - deferred                  11,971          (10,796 )
Cash adjustment for non-controlling interest of      633             (1,017  )
consolidated subsidiaries
Revenue deferral adjustment                          1,765           2,268
Other                                                2,040           2,208
Maintenance capital expenditures, net of joint      (1,891    )    (6,297  )
venture partner contributions
Distributable cash flow                           $  110,194      $ 109,177 
                                                                   
Maintenance capital expenditures                  $  1,891         $ 6,297
Growth capital expenditures                         629,667       247,966 
Total capital expenditures                           631,558         254,263
Acquisitions, net of cash acquired                  -             -       
Total capital expenditures and acquisitions          631,558         254,263
Joint venture partner contributions                 (265,320  )    -       
Total capital expenditures and acquisitions,      $  366,238      $ 254,263 
net
                                                                   
Distributable cash flow                           $  110,194       $ 109,177
Maintenance capital expenditures, net of joint       1,891           6,297
venture partner contributions
Changes in receivables and other assets              1,109           57,655
Changes in accounts payable, accrued                 (27,608   )     35,244
liabilities and other long-term liabilities
Cash adjustment for non-controlling interest of      (633      )     1,017
consolidated subsidiaries
Other                                               90            (1,477  )
Net cash provided by operating activities         $  85,043       $ 207,913 
                                                                             


MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
                                                                
                                                  Three months ended March 31,
                                                  2013             2012
                                                                   
Net (loss) income                                 $  (20,764  )    $ 16,273
Non-cash compensation expense                        2,384           2,710
Non-cash derivative activity                         (9,033   )      48,217
Interest expense ^(1)                                38,022          28,552
Depreciation, amortization, impairment, and          84,996          53,432
other non-cash operating expenses
Loss on redemption of debt                           38,455          -
Provision for income tax                             6,557           4,545
Adjustment for cash flow from unconsolidated         85              909
affiliate
Other                                               108           (1,498  )
Adjusted EBITDA                                   $  140,810      $ 153,140 
                                                                             

(1)  Includes amortization of deferred financing costs and discount, and
      excludes interest expense related to the Steam Methane Reformer.
      

MarkWest Energy Partners, L.P.
Distributable Cash Flow Sensitivity Analysis
(unaudited, in millions)

MarkWest periodically estimates the effect on DCF resulting from its commodity
risk management program, changes in crude oil and natural gas prices, and the
ratio of NGL prices to crude oil. The table below reflects MarkWest’s estimate
of the range of DCF for 2013 and forecasted crude oil and natural gas prices
for 2013. The analysis assumes various combinations of crude oil and natural
gas prices as well as three NGL-to-crude oil ratio scenarios, including:
a. NGL-to-crude oil ratio at 55% for 2013.
b. NGL-to-crude oil ratio at 45% for 2013.
c. NGL-to-crude oil ratio at 35% for 2013.

The analysis further assumes derivative instruments outstanding as of May 8,
2013, and production volumes estimated through December 31, 2013. The range of
stated hypothetical changes in commodity prices considers current and historic
market performance.

Estimated Range of 2013 DCF
                                                               
                         Natural Gas Price (Henry Hub)
    Crude
    Oil     NGL-to-Crude   $ 3.00   $ 3.50   $ 4.00   $ 4.50   $ 5.00
    Price     oil ratio
    (WTI)
             55% of WTI     $ 568    $ 566    $ 564    $ 563    $ 561
    $110      45% of WTI     $ 526    $ 524    $ 522    $ 520    $ 518
           35% of WTI     $ 484    $ 483    $ 481    $ 479    $ 477
             55% of WTI     $ 551    $ 549    $ 547    $ 546    $ 544
    $100      45% of WTI     $ 512    $ 511    $ 509    $ 507    $ 505
           35% of WTI     $ 475    $ 473    $ 471    $ 469    $ 468
             55% of WTI     $ 531    $ 529    $ 527    $ 526    $ 524
    $90       45% of WTI     $ 497    $ 495    $ 493    $ 491    $ 489
           35% of WTI     $ 461    $ 459    $ 457    $ 455    $ 453
             55% of WTI     $ 513    $ 512    $ 510    $ 508    $ 506
    $80       45% of WTI     $ 484    $ 482    $ 480    $ 478    $ 476
           35% of WTI     $ 451    $ 449    $ 447    $ 445    $ 442
             55% of WTI     $ 501    $ 499    $ 497    $ 495    $ 493
    $70       45% of WTI     $ 471    $ 469    $ 467    $ 466    $ 464
           35% of WTI     $ 446    $ 443    $ 441    $ 438    $ 435

      The composition is based on MarkWest’s average projected barrel of
(1)  approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane:
      12%, Natural Gasoline: 12%.
      

The table is based on current 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. Historical prices and ratios of
NGL-to-crude oil do not guarantee future results.

Although MarkWest believes the expectations reflected in this analysis are
reasonable, MarkWest can give no assurance that such expectations will prove
to be correct and readers are cautioned that projected performance, results,
or distributions may not be achieved. Actual changes in market prices, and the
ratio between crude oil and NGL prices, may differ from the assumptions
utilized in the analysis. Actual results, performance, distributions, volumes,
events, or transactions could vary significantly from those expressed,
considered, or implied in this analysis. All results, performance,
distributions, volumes, events, or transactions are subject to a number of
uncertainties and risks. Those uncertainties and risks may not be factored
into or accounted for in this analysis. Readers are urged to carefully review
and consider the cautionary statements and disclosures made in MarkWest’s
periodic reports filed with the SEC, specifically those under the heading
“Risk Factors.”

Contact:

MarkWest Energy Partners, L.P.
Frank Semple, 866-858-0482
Chairman, President & CEO
or
Nancy Buese, 866-858-0482
Senior VP and CFO
or
Josh Hallenbeck, 866-858-0482
VP of Finance & Treasurer
investorrelations@markwest.com