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MarkWest Energy Partners Reports Record Second Quarter Results and Announces Plans to form a Joint Venture with Kinder Morgan to

  MarkWest Energy Partners Reports Record Second Quarter Results and Announces
  Plans to form a Joint Venture with Kinder Morgan to Support Northern Ohio
  Rich-Gas Development and NGL Pipeline to Gulf Coast

  *MarkWest Utica EMG announced plans to form a Joint Venture with Kinder
    Morgan to support northern Ohio rich-gas processing, an NGL pipeline to
    the Gulf Coast, and additional Gulf Coast fractionation facilities.
  *Placed into service three processing facilities with combined capacity of
    525 MMcf/d.
  *Commenced operations of the first large-scale de-ethanization facility in
    the Northeast, which is producing purity ethane for delivery initially to
    Mariner West and ultimately to all planned ethane projects including ATEX
    and Mariner East.
  *Announced expansion of Mobley processing complex by 200 MMcf/d to support
    EQT and other producers, bringing total expected capacity in the Marcellus
    Shale to nearly 3.6 billion cubic feet per day.
  *Executed agreements with Antero Resources to expand the Seneca processing
    complex by 200 MMcf/d, bringing total capacity in the Utica Shale to over
    900 MMcf/d by the third quarter of 2014.
  *Announced four additional fractionation projects, which will increase
    total fractionation capacity in the Marcellus and Utica Shales by 96,000
    to 332,000 barrels per day by the first quarter of 2015.
  *The Partnership has 23 major processing and fractionation currently under
    construction.
  *Fee-based net operating margin increased from 50 percent to 61 percent
    when compared to the second quarter of 2012.

Business Wire

DENVER -- August 7, 2013

MarkWest Energy Partners, L.P. (NYSE: MWE) (the Partnership) today reported
record quarterly cash available for distribution to common unitholders, or
distributable cash flow (DCF), of $128.4 million for the three months ended
June 30, 2013, and $238.2 million for the six months ended June 30, 2013. DCF
for the three months ended June 30, 2013 represents 108 percent coverage of
the second quarter distribution of $118.4 million or $0.84 per common unit,
which will be paid to unitholders on August 14, 2013. The second quarter 2013
distribution represents an increase of $0.01 per common unit or 1.2 percent
over the first quarter 2013 distribution and an increase of $0.04 per common
unit or 5.0 percent compared to the second 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 for the three and six months ended
June 30, 2013, of $156.1 million and $296.5 million, respectively, as compared
to $121.9 million and $275.0 million for the three and six months ended June
30, 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 income before provision for income tax for the three
and six months ended June 30, 2013, of $101.8 million and $87.2 million,
respectively. Income before provision for income tax includes non-cash gains
associated with the change in fair value of derivative instruments of $37.3
million and $46.3 million for the three and six months ended June 30, 2013, a
gain of $38.2 million related to the divestiture of gathering assets in the
Marcellus Shale for the three months ended June 30, 2013 and a loss associated
with the redemption of debt of $38.5 million for the six months ended June 30,
2013. Excluding these items, income before provision for income tax for the
three and six months ended June 30, 2013 would have been $26.3 million and
$41.2 million, respectively.

“Our full-service midstream model and commitment to delivering exceptional
customer service continues to deliver record volumes and financial
performance,” said Frank Semple, Chairman, President and Chief Executive
Officer. “We are excited to announce new strategic opportunities and growth
projects throughout our core operating areas, which continue to support the
ongoing success of our producer customers.”

BUSINESS HIGHLIGHTS

Liberty:

  *In May 2013, the Partnership commenced operations of Majorsville III, a
    200 million cubic feet per day (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 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 total processing capacity at the Sherwood complex has
    increased to 400 MMcf/d.
  *In June 2013, the Partnership closed on the sale of a non-strategic,
    high-pressure gas gathering system in Doddridge County, West Virginia to
    Summit Midstream Partners, LP (NYSE: SMLP) for $207.9 million in cash, net
    of fees. Rich-gas gathered by this system is supported by a long-term,
    fee-based contract with an affiliate of Antero, and is dedicated to the
    Partnership for processing at the Sherwood complex.
  *In July 2013, the Partnership commenced operations of the Houston
    De-ethanizer, a 38,000 barrel per day (Bbl/d) fractionator that is
    producing purity ethane from Marcellus rich-gas production. The Houston
    De-ethanizer will initially support Mariner West, a joint project with
    Sunoco Logistics Partners, L.P. (NYSE: SXL) and in the future will support
    all the planned ethane takeaway pipeline projects.
  *Today, the Partnership is announcing an expansion of the Mobley Complex in
    Wetzel County, West Virginia to support EQT Corporation (EQT) and other
    producers’ rich-gas development. EQT has requested 145 MMcf/d of
    additional priority capacity at the Mobley complex. To support the
    increase in priority capacity, MarkWest will construct Mobley IV, a new
    200 MMcf/d processing facility that is scheduled to begin operations by
    the first quarter of 2015. Upon completion of this facility, Mobley’s
    processing capacity will be 720 MMcf/d.
  *The Partnership is also announcing the development of additional
    fractionation facilities to support producers’ growing rich-gas production
    in the Marcellus Shale. By the first quarter of 2014, the Partnership will
    install de-ethanization and de-propanization units totaling 20,000 Bbl/d
    of capacity at the Keystone complex in Butler County, Pennsylvania. In
    addition, the Partnership will install a 38,000 Bbl/d de-ethanization
    facility at the Sherwood complex in Doddridge County, West Virginia, which
    is expected to be operational during the first quarter of 2015.

Utica:

  *In May 2013, MarkWest Utica EMG executed definitive agreements with CNX
    and two additional producers to provide processing, fractionation, and
    marketing services in the Utica Shale.
  *In May 2013, MarkWest Utica EMG commenced 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.
  *In June 2013, MarkWest Utica EMG executed definitive agreements with
    Antero for the development of Seneca III, a 200 MMcf/d processing facility
    in Noble County, Ohio. Seneca III is scheduled to be operational during
    the second quarter of 2014 and will support rich-gas production from
    Antero and other producers in the southern core area of the Utica Shale.
  *Today, MarkWest Utica EMG is announcing installation of a 38,000 Bbl/d
    de-ethanization facility at the Seneca complex, which is expected to be
    operational as soon as the fourth quarter of 2014.
  *Today, MarkWest Utica EMG announced plans to form a Joint Venture (JV)
    with Kinder Morgan Energy Partners, LP (NYSE: KMP) (Kinder Morgan) to
    pursue three critical new projects to support producers in the Utica and
    Marcellus Shales:

  *Under the first joint project, Kinder Morgan and MarkWest Utica EMG would
    develop a processing complex to be constructed on Kinder Morgan’s existing
    220-acre site in Tuscarawas County, Ohio (JV processing complex) with an
    initial processing capacity of 200 MMcf/d, expandable to 400 MMcf/d of
    processing capacity. In addition, Kinder Morgan would convert a 65-mile
    segment of its existing 26-inch Tennessee Gas Pipeline into rich-gas
    gathering service. MarkWest Utica EMG would also construct additional
    rich-gas and NGL pipelines to connect the complex with its large-scale
    full-service midstream infrastructure. This project would serve new
    customers in Carroll, Columbiana, Mahoning and Trumbull counties in
    northern Ohio. The JV would own the processing complex on a 50-50 basis.
  *The second joint project with Kinder Morgan would involve the development
    of a 200,000 Bbl/d C2+ NGL pipeline originating at the JV processing
    complex to Gulf Coast fractionation facilities. This would be accomplished
    through the conversion of over 900 miles of existing Kinder Morgan
    pipeline assets and the construction of approximately 200 miles of
    additional pipeline to connect to Gulf Coast liquids and fractionation
    infrastructure. The NGL pipeline would be expandable to 400,000 Bbl/d.
    Subject to sufficient shipper commitments, permitting and all related
    regulatory approvals, the pipeline would be operational during the fourth
    quarter of 2015. The Partnership and MarkWest Utica EMG would utilize
    their extensive NGL pipeline network to deliver NGLs from the Marcellus
    and Utica to the new NGL pipeline. By converting over 900 miles of
    existing pipeline and utilizing the Partnership and MarkWest Utica EMG’s
    existing NGL network, the JV’s NGL pipeline solution is best positioned to
    provide a cost effective outlet from the Utica and Marcellus Shale plays
    to Gulf Coast area markets. Kinder Morgan would own at least 75 percent of
    the NGL pipeline and MarkWest Utica EMG would have the option to invest up
    to 25 percent.
  *The third joint project with Kinder Morgan would involve the development
    of new fractionation facilities, as well as utilizing third-party
    fractionation facilities, throughout the Gulf Coast.

Southwest:

  *In May 2013, the Partnership acquired midstream assets in the Texas
    Panhandle and Western Oklahoma from a wholly owned subsidiary of
    Chesapeake for consideration of $225.2 million in cash (Granite Wash
    Acquisition). In conjunction with the acquisition, the Partnership
    executed long-term, fee-based agreements with Chesapeake for gas gathering
    and processing services. As part of the fee-based gas processing
    agreement, Chesapeake has dedicated to the Partnership approximately
    130,000 acres throughout the Anadarko Basin.
  *In May 2013, the Partnership executed a long-term fee-based agreement with
    Newfield Exploration (NYSE: NFX) (Newfield) to develop rich-gas gathering
    facilities in the Eagle Ford Shale. The Partnership will construct
    gathering pipelines, field compression, and liquids storage to support
    production from Newfield’s West Asherton project in Dimmit County, Texas.

Capital Markets

  *During the second quarter of 2013, the Partnership offered 3.8 million
    units and received net proceeds of approximately $244.5 million under the
    continuous offering program that was launched in the fourth quarter of
    2012. The Partnership completed the $600 million program in July 2013.

FINANCIAL RESULTS

Balance Sheet

  *As of June 30, 2013, the Partnership had $278.9 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 June 30, 2013, was $177.5 million, an increase of $32.8
    million when compared to segment operating income of $144.7 million over
    the same period in 2012. This increase was primarily attributable to
    higher processing volumes, offset by lower commodity prices compared to
    the prior year quarter. Processed volumes continued to remain strong,
    growing approximately 53 percent when compared to the second 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 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 $2.0 million in the
    second quarter of 2013 and ($5.0) million in the second quarter of 2012.

Capital Expenditures

  *For the three months ended June 30, 2013, the Partnership’s portion of
    capital expenditures was $443.0 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership’s DCF forecast remains in a range of $500 million to
$540 million based on its current forecast of operational volumes and 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 or the divestiture of the
high-pressure gathering system in the Marcellus Shale.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, August 8,
2013, at 12:00 p.m. Eastern Time to review its second 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
(866) 454-1418 (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 June 30, 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 June 30,     Six months ended June 30,
Statement of      2013            2012            2013             2012
Operations Data
Revenue:
Revenue           $ 395,421       $ 306,755       $ 768,879        $ 702,733
Derivative gain    19,699        136,067       19,514         87,352     
Total revenue      415,120       442,822       788,393        790,085    
                                                                   
Operating
expenses:
Purchased           155,359         112,731         307,916          267,286
product costs
Derivative gain
related to          (20,432   )     (51,579   )     (31,136    )     (32,779    )
purchased
product costs
Facility            62,797          48,230          122,307          96,555
expenses
Derivative loss
(gain) related      800             (1,146    )     468              (2,892     )
to facility
expenses
Selling,
general and         25,499          21,700          50,741           46,748
administrative
expenses
Depreciation        71,562          41,336          139,579          80,918
Amortization of
intangible          17,092          12,307          31,922           23,292
assets
(Gain) loss on
sale or
disposal of         (37,736   )     1,342           (37,598    )     2,328
property, plant
and equipment
Accretion of
asset              157           160           509            396        
retirement
obligations
Total operating    275,098       185,081       584,708        481,852    
expenses
                                                                   
Income from         140,022         257,741         203,685          308,233
operations
                                                                   
Other income
(expense):
Gain from
unconsolidated      430             1,109           665              1,548
affiliates
Interest income     62              159             211              231
Interest            (36,955   )     (26,762   )     (75,291    )     (56,234    )
expense
Amortization of
deferred
financing costs
and discount (a     (1,784    )     (1,245    )     (3,614     )     (2,515     )
component of
interest
expense)
Loss on
redemption of       -               -               (38,455    )     -
debt
Miscellaneous      6             4             6              62         
income, net
Income before
provision for       101,781         231,006         87,207           251,325
income tax
                                                                   
Provision for
income tax
(benefit)
expense:
Current             (2,745    )     4,809           (8,159     )     20,150
Deferred           19,028        39,664        30,999         28,868     
Total provision    16,283        44,473        22,840         49,018     
for income tax
                                                                   
Net income          85,498          186,533         64,367           202,307
                                                                   
Net (income)
loss
attributable to     (1,799    )     375             3,874            621
non-controlling
interest
                                                                
Net income
attributable to
the               $ 83,699       $ 186,908      $ 68,241        $ 202,928    
Partnership's
unitholders
                                                                   
Net income
attributable to
the
Partnership's       
common
unitholders per
common unit:
Basic             $ 0.63         $ 1.74         $ 0.52          $ 1.98       
Diluted           $ 0.55         $ 1.47         $ 0.45          $ 1.66       
                                                                   
Weighted
average number
of outstanding
common units:
Basic              131,227       106,825       129,928        101,833    
Diluted            151,866       127,468       150,580        122,531    
                                                                   
Cash Flow Data
Net cash flow
provided by
(used in):
Operating         $ 92,553        $ 45,708        $ 177,596        $ 253,621
activities
Investing         $ (825,660  )   $ (834,145  )   $ (1,435,021 )   $ (1,087,114 )
activities
Financing         $ 435,634       $ 562,860       $ 1,266,223      $ 841,534
activities
                                                                   
Other Financial
Data
Distributable     $ 128,390       $ 91,183        $ 238,216        $ 200,379
cash flow
Adjusted EBITDA   $ 156,110       $ 121,853       $ 296,541        $ 274,991
                                                                   
                                                                   
Balance Sheet     June 30, 2013   December 31,
Data                              2012
Working capital   $ (116,922  )   $ (84,512   )
Total assets        8,200,883       6,728,362
Total debt          3,022,704       2,523,051
Total equity        3,482,316       3,111,398
                                                                   

                                                                
MarkWest Energy Partners, L.P.
Operating Statistics
                                                                      
                               Three months ended June   Six months ended June
                               30,                       30,
                               2013           2012       2013         2012
Liberty
Gathering system throughput    683,600        367,400    644,700      337,800
(Mcf/d)
Natural gas processed          1,033,700      400,600    931,400      396,400
(Mcf/d)
NGLs fractionated (Bbl/d)      48,900         19,800     43,000       19,900
NGL sales (gallons, in         160,300        75,900     306,200      173,400
thousands) (1)
                                                                      
Utica (2)
Gathering system throughput    46,300         -          27,800       -
(Mcf/d)
Natural gas processed          46,300         -          27,200       -
(Mcf/d)
                                                                      
Northeast
Natural gas processed          296,400        328,200    299,500      324,900
(Mcf/d)
NGLs fractionated (Bbl/d)      18,100         17,200     17,600       16,900
                                                                      
Keep-whole sales (gallons,     27,100         23,700     60,000       73,300
in thousands)
Percent-of-proceeds sales      32,200         36,800     67,100       69,800
(gallons, in thousands)
Total NGL sales (gallons, in   59,300         60,500     127,100      143,100
thousands)
                                                                      
Crude oil transported for a    9,700          8,300      10,000       9,400
fee (Bbl/d)
                                                                      
Southwest
East Texas gathering systems   521,700        440,400    510,500      425,200
throughput (Mcf/d)
East Texas natural gas         377,600        268,300    358,600      255,400
processed (Mcf/d)
East Texas NGL sales           90,200         68,000     170,700      131,400
(gallons, in thousands)
                                                                      
Western Oklahoma gathering
system throughput (Mcf/d)      220,000        252,200    211,400      257,100
(3)
Western Oklahoma natural gas   189,900        218,900    188,100      211,400
processed (Mcf/d)
Western Oklahoma NGL sales     42,900         61,700     97,700       119,000
(gallons, in thousands)
                                                                      
Southeast Oklahoma gathering   473,300        503,300    467,300      502,200
system throughput (Mcf/d)
Southeast Oklahoma natural     160,400        119,600    155,800      110,700
gas processed (Mcf/d) (4)
Southeast Oklahoma NGL sales   54,000         41,300     93,300       74,300
(gallons, in thousands)
                                                                      
Other Southwest gathering
system throughput (Mcf/d)      39,900         26,700     30,300       25,600
(5)
                                                                      
Gulf Coast refinery off-gas    117,700        115,800    106,600      118,000
processed (Mcf/d)
Gulf Coast liquids             22,100         21,700     19,700       22,500
fractionated (Bbl/d)
Gulf Coast NGL sales
(gallons excluding hydrogen,   84,600         83,000     149,700      172,300
in thousands)
                                                                      

(1)  Includes sale of all purity products fractionated at the Liberty
      facilities and the 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 June 30,    Liberty        Utica         Northeast   Southwest   Total
2013
Segment revenue   $ 120,057      $ 3,594       $ 45,365    $ 227,842   $ 396,858
                                                                       
Operating
expenses:
Purchased           16,993         -             15,126      123,240     155,359
product costs
Facility           22,272       6,412       6,655      29,778     65,117  
expenses
Total operating
expenses before
items not           39,265         6,412         21,781      153,018     220,476
allocated to
segments
                                                                       
Portion of
operating
(loss) income      -            (1,143  )    -          53         (1,090  )
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 80,792      $ (1,675  )   $ 23,584    $ 74,771    $ 177,472 
not allocated
to segments
                                                                       
                                                                       
Three months
ended June 30,    Liberty        Utica         Northeast   Southwest   Total
2012
Segment revenue   $ 59,477       $ -           $ 42,051    $ 206,551   $ 308,079
                                                                       
Operating
expenses:
Purchased           8,018          -             12,921      91,792      112,731
product costs
Facility           13,364       283         4,932      32,156     50,735  
expenses
Total operating
expenses before
items not           21,382         283           17,853      123,948     163,466
allocated to
segments
                                                                       
Portion of
operating
(loss) income      -            (113    )    -          28         (85     )
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 38,095      $ (170    )   $ 24,198    $ 82,575    $ 144,698 
not allocated
to segments
                                                                       
                                                                       
                  Three months ended June
                  30,
                  2013           2012
                                                                       
Operating
income before
items not         $ 177,472      $ 144,698
allocated to
segments
Portion of
operating
(loss) income       (1,090   )     (85     )
attributable to
non-controlling
interests
Derivative gain
not allocated       39,331         188,792
to segments
Revenue
deferral            (1,437   )     (1,324  )
adjustment and
other
Compensation
expense
included in
facility            (368     )     (183    )
expenses not
allocated to
segments
Facility
expenses            2,688          2,688
adjustments
Selling,
general and         (25,499  )     (21,700 )
administrative
expenses
Depreciation        (71,562  )     (41,336 )
Amortization of
intangible          (17,092  )     (12,307 )
assets
Gain (loss) on
disposal of         37,736         (1,342  )
property, plant
and equipment
Accretion of
asset              (157     )    (160    )
retirement
obligations
Income from         140,022        257,741
operations
Other income
(expense):
Earnings from
unconsolidated      430            1,109
affiliate
Interest income     62             159
Interest            (36,955  )     (26,762 )
expense
Amortization of
deferred
financing costs
and discount (a     (1,784   )     (1,245  )
component of
interest
expense)
Miscellaneous      6            4       
income, net
Income before
provision for     $ 101,781     $ 231,006 
income tax
                                                                       
                                                                       
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)
                                                                       
Six months
ended June 30,    Liberty        Utica         Northeast   Southwest   Total
2013
Segment revenue   $ 228,554      $ 4,217       $ 102,701   $ 436,208   $ 771,680
                                                                       
Operating
expenses:
Purchased           35,786         -             34,788      237,342     307,916
product costs
Facility           44,908       10,374      13,179     58,468     126,929 
expenses
Total operating
expenses before
items not           80,694         10,374        47,967      295,810     434,845
allocated to
segments
                                                                       
Portion of
operating
(loss) income      -            (2,482  )    -          117        (2,365  )
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 147,860     $ (3,675  )   $ 54,734    $ 140,281   $ 339,200 
not allocated
to segments
                                                                       
                                                                       
Six months
ended June 30,    Liberty        Utica         Northeast   Southwest   Total
2012
Segment revenue   $ 135,054      $ -           $ 128,969   $ 441,927   $ 705,950
                                                                       
Operating
expenses:
Purchased           32,653         -             38,608      196,025     267,286
product costs
Facility           25,611       283         11,310     64,094     101,298 
expenses
Total operating
expenses before
items not           58,264         283           49,918      260,119     368,584
allocated to
segments
                                                                       
Portion of
operating
(loss) income      -            (113    )    -          31         (82     )
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 76,790      $ (170    )   $ 79,051    $ 181,777   $ 337,448 
not allocated
to segments
                                                                       
                                                                       
                  Six months ended June 30,
                  2013           2012
                                                                       
Operating
income before
items not         $ 339,200      $ 337,448
allocated to
segments
Portion of
operating
(loss) income       (2,365   )     (82     )
attributable to
non-controlling
interests
Derivative gain
not allocated       50,182         123,023
to segments
Revenue
deferral            (2,801   )     (3,217  )
adjustment and
other
Compensation
expense
included in
facility            (754     )     (633    )
expenses not
allocated to
segments
Facility
expenses            5,376          5,376
adjustments
Selling,
general and         (50,741  )     (46,748 )
administrative
expenses
Depreciation        (139,579 )     (80,918 )
Amortization of
intangible          (31,922  )     (23,292 )
assets
Gain (loss) on
disposal of         37,598         (2,328  )
property, plant
and equipment
Accretion of
asset              (509     )    (396    )
retirement
obligations
Income from         203,685        308,233
operations
Other income
(expense):
Earnings from
unconsolidated      665            1,548
affiliate
Interest income     211            231
Interest            (75,291  )     (56,234 )
expense
Amortization of
deferred
financing costs
and discount (a     (3,614   )     (2,515  )
component of
interest
expense)
Loss on
redemption of       (38,455  )     -
debt
Miscellaneous      6            62      
income, net
Income before
provision for     $ 87,207      $ 251,325 
income tax
                                                                       

                                                           
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
                                                                 
                  Three months ended June 30,    Six months ended June 30,
                  2013            2012           2013            2012
                                                                 
Net income        $ 85,498        $ 186,533      $ 64,367        $ 202,307
Depreciation,
amortization
and other           88,889          53,881         172,166         104,762
non-cash
operating
expenses
(Gain) loss on
sale and or
disposal of         (34,689   )     1,342          (34,551   )     2,328
assets, net of
tax benefit
Loss on
redemption of       -               -              36,178          -
debt, net of
tax benefit
Amortization of
deferred            1,784           1,245          3,614           2,515
financing costs
and discount
Non-cash
earnings from       (430      )     (1,109   )     (665      )     (1,548    )
unconsolidated
affiliate
Distributions
from                1,962           1,774          2,728           4,566
unconsolidated
affiliate
Non-cash
compensation        1,157           2,580          3,541           5,290
expense
Non-cash
derivative          (37,287   )     (193,744 )     (46,320   )     (145,527  )
activity
Provision for
income tax -        19,028          39,664         30,999          28,868
deferred
Cash adjustment
for
non-controlling     1,720           364            3,489           604
interest of
consolidated
subsidiaries
Revenue
deferral            1,645           1,700          3,410           3,968
adjustment
Other               2,827           647            4,865           2,235
Maintenance
capital
expenditures,      (3,714    )    (3,694   )    (5,605    )    (9,989    )
net of joint
venture partner
contributions
Distributable     $ 128,390      $ 91,183      $ 238,216      $ 200,379   
cash flow
                                                                 
Maintenance
capital           $ 3,714         $ 3,694        $ 5,605         $ 9,989
expenditures
Growth capital     799,812       323,745      1,429,479     570,991   
expenditures
Total capital       803,526         327,439        1,435,084       580,980
expenditures
Acquisitions,
net of cash        225,210       506,797      225,210       506,797   
acquired
Total capital
expenditures        1,028,736       834,236        1,660,294       1,087,777
and
acquisitions
Joint venture
partner            (360,499  )    -            (625,819  )    -         
contributions
Total capital
expenditures
and               $ 668,237      $ 834,236     $ 1,034,475    $ 1,087,777 
acquisitions,
net
                                                                 
Distributable     $ 128,390       $ 91,183       $ 238,216       $ 200,379
cash flow
Maintenance
capital
expenditures,       3,714           3,694          5,605           9,989
net of joint
venture partner
contributions
Changes in
receivables and     (68,610   )     54,300         (67,501   )     111,955
other assets
Changes in
accounts
payable,
accrued             37,661          (100,434 )     10,053          (65,190   )
liabilities and
other long-term
liabilities
Cash adjustment
for
non-controlling     (1,720    )     (364     )     (3,489    )     (604      )
interest of
consolidated
subsidiaries
Other              (6,882    )    (2,671   )    (5,288    )    (2,908    )
Net cash
provided by       $ 92,553       $ 45,708      $ 177,596      $ 253,621   
operating
activities
                                                                             

                                                             
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
                                                                  
                      Three months ended June 30,   Six months ended June 30,
                      2013           2012           2013          2012
                                                                  
Net income            $  85,498      $ 186,533      $ 64,367      $ 202,307
Non-cash
compensation             1,157         2,580          3,541         5,290
expense
Non-cash derivative      (37,287 )     (193,744 )     (46,320 )     (145,527 )
activity
Interest expense         36,610        25,826         74,632        54,378
(1)
Depreciation,
amortization and         88,889        53,881         172,166       104,762
other non-cash
operating expenses
(Gain) loss on sale
and or disposal of       (37,736 )     1,342          (37,598 )     2,328
assets
Loss on redemption       -             -              38,455        -
of debt
Provision for            16,283        44,473         22,840        49,018
income tax
Adjustment for cash
flow from                1,532         665            2,063         3,018
unconsolidated
affiliate
Other                   1,164       297          2,395       (583     )
Adjusted EBITDA       $  156,110    $ 121,853     $ 296,541    $ 274,991  
                                                                             

(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 50% for 2013.
b. NGL-to-crude oil ratio at 40% for 2013.
c. NGL-to-crude oil ratio at 30% for 2013.

The analysis further assumes derivative instruments outstanding as of August
7, 2013, and production volumes estimated through December31, 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 Price  NGL-to-Crude   $3.00  $3.50  $4.00  $4.50  $5.00
    (WTI)             Oil ratio (1)
                     50% of WTI     $ 548  $ 546  $ 543  $ 541  $ 539
    $120              40% of WTI     $ 518  $ 516  $ 514  $ 512  $ 509
                    30% of WTI     $ 490  $ 488  $ 486  $ 483  $ 481
                     50% of WTI     $ 540  $ 538  $ 535  $ 533  $ 531
    $110              40% of WTI     $ 513  $ 511  $ 508  $ 506  $ 504
                    30% of WTI     $ 486  $ 484  $ 482  $ 479  $ 477
                     50% of WTI     $ 530  $ 528  $ 526  $ 524  $ 521
    $100              40% of WTI     $ 506  $ 504  $ 502  $ 499  $ 497
                    30% of WTI     $ 481  $ 478  $ 476  $ 474  $ 472
                     50% of WTI     $ 519  $ 517  $ 515  $ 512  $ 510
    $90               40% of WTI     $ 497  $ 495  $ 493  $ 491  $ 488
                    30% of WTI     $ 474  $ 472  $ 470  $ 468  $ 465
                     50% of WTI     $ 509  $ 507  $ 505  $ 503  $ 500
    $80               40% of WTI     $ 489  $ 486  $ 484  $ 482  $ 480
                    30% of WTI     $ 470  $ 467  $ 465  $ 462  $ 459

      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
Executive VP and CFO
or
Josh Hallenbeck, 866-858-0482
VP of Finance & Treasurer
investorrelations@markwest.com