MarkWest Energy Partners Reports Record Distributable Cash Flow and Full-Year Distribution Growth of 12.6 Percent

  MarkWest Energy Partners Reports Record Distributable Cash Flow and
  Full-Year Distribution Growth of 12.6 Percent

Business Wire

DENVER -- February 27, 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 $111.8 million for the three months ended
December 31, 2012, and $416.4 million for the year ended December 31, 2012.
Distributable cash flow for the three months and year ended December 31, 2012,
represents distribution coverage of 106 percent and 112 percent, respectively.
The fourth quarter distribution of $105.4 million, or $0.82 per common unit,
was paid to unitholders on February 14, 2013. The fourth quarter 2012
distribution represents an increase of $0.01 per common unit over the third
quarter 2012 distribution and a full-year increase of 12.6 percent compared to
2011. 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 $135.1 million for the three
months ended December 31, 2012 and $528.2 million for the year ended December
31, 2012, as compared to $147.2 million and $515.3 million for the three
months and year ended December 31, 2011. 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
months and year ended December 31, 2012, of $26.9 million and $257.1 million,
respectively. Income before provision for income tax includes non-cash gain
associated with the change in mark-to-market of derivative instruments of $0.3
million and $102.1 million for the three months and year ended December 31,
2012, respectively. Excluding these items, income before provision for income
tax for the three months and year ended December 31, 2012, would have been
$26.6 million and $155.0 million, respectively.

“We are extremely pleased with our performance in 2012, which was highlighted
by record distributable cash flow, our second consecutive year of double-digit
distribution increases and 23 percent growth in processed volumes,” said Frank
Semple, Chairman, President and Chief Executive Officer. “We have continued to
build on our industry-leading position in the Marcellus Shale and as a result
of our producer customers’ very successful drilling programs our fourth
quarter year-over-year Liberty processed volumes increased by 86 percent. In
addition, with our partner EMG, we have made enormous progress in the
development of our full service integrated midstream platform to support the
rapidly developing Utica Shale. In 2012 we invested almost $2 billion on
strategic growth projects primarily in our Marcellus and Utica business units
and in 2013 we expect to invest between $1.5 and $1.8 billion on additional
capital projects, which are supported by long-term, largely fee-based
contracts. Our diverse asset base and strategic position in some of the
premier resource plays in the U.S.continues to provide us
withsignificantgrowth opportunities.We are committed to provide our
producer customerswith fully-integratedmidstream solutions and outstanding
customer service.”

BUSINESS HIGHLIGHTS

Business Development

Liberty:

  *In October 2012, the Partnership commenced operations of the 200 million
    cubic feet per day (MMcf/d) Sherwood I processing facility and associated
    gathering and compression in Doddridge County, West Virginia. These assets
    are supported by a long-term, fee-based agreement with Antero Resources.
    The initiation of Sherwood operations represents the first phase of the
    Partnership’s on-going development of midstream infrastructure in
    Doddridge County. The Partnership expects the Sherwood II and Sherwood III
    cryogenic processing plants, totaling 400 MMcf/d, to be operational in the
    second and third quarters of 2013, respectively.
  *In November 2012, the Partnership announced plans to further expand the
    processing capacity at its Mobley complex in Wetzel County, West Virginia
    by 200 MMcf/d. This expansion is supported by an existing long-term,
    fee-based agreement with EQT Corporation (NYSE: EQT) and is expected to be
    completed in the fourth quarter of 2013. Upon completion of the third
    facility, the Partnership’s total cryogenic processing capacity at Mobley
    will be 520 MMcf/d.
  *In December 2012, the Partnership commenced operations of the first Mobley
    processing facility. The 200 MMcf/d plant supports the development of
    rich-gas acreage in the Marcellus Shale by EQT Corporation, Magnum Hunter
    Resources Corporation (NYSE: MHR) and other producers.

Utica:

  *In November 2012, MarkWest Utica EMG, LLC (MarkWest Utica EMG) a joint
    venture between the Partnership and The Energy and Minerals Group (EMG),
    announced the execution of definitive agreements with Antero Resources to
    provide gas processing, fractionation and marketing services in Noble
    County, Ohio. Under long-term, fee-based agreements, MarkWest Utica EMG
    will construct two processing facilities totaling 400 MMcf/d at its Seneca
    complex. In addition to the Seneca processing complex, MarkWest Utica EMG
    will construct an NGL gathering system to the Cadiz processing complex and
    then on to the Hopedale fractionation and marketing complex in Harrison
    County, Ohio.
  *In November 2012, MarkWest Utica EMG completed its refrigeration facility
    at the Cadiz complex, which provides 60 MMcf/d of interim processing
    capacity to support rapidly expanding development of the Utica Shale. The
    completion of this facility is a significant milestone and is MarkWest
    Utica EMG’s first processing facility in the 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 June 1, 2013.
  *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 allows EMG to increase
    its capital investment in 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.

Northeast:

  *In October 2012, the Partnership commenced operations of its 150 MMcf/d
    Langley cryogenic processing plant expansion supporting producers’ gas
    development in the Huron/Berea Shale. This expansion increases the
    Partnership’s total processing capacity in the Northeast segment to 652
    MMcf/d and further expands the Partnership’s position as the largest
    natural gas processor in the Appalachian Basin.

Southwest:

  *In November 2012, the Partnership completed its 120 MMcf/d Carthage East
    cryogenic processing plant, to support producers’ gas development in the
    liquids-rich Haynesville Shale. This expansion increases the Partnership’s
    total processing capacity in East Texas to 400 MMcf/d.

Capital Markets

  *On November 7, 2012, the Partnership filed a prospectus supplement for an
    at-the-market equity program with a total value of up to $600 million.
    This program allows, but does not require, the Partnership to issue common
    units from time to time. Through the year ended December 31, 2012 the
    Partnership offered 0.13 million common units. The net proceeds of 
    approximately  $6.3 million were used to fund the Partnership’s capital
    expenditure program and for general partnership purposes.
  *On November 19, 2012, the Partnership completed an equity offering of 9.8
    million common units. The net proceeds of  approximately  $437.2 million
    were used to partially fund the Partnership’s capital expenditure program
    and for general partnership purposes.
  *On January 10, 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 $986.9 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.

FINANCIAL RESULTS

Balance Sheet

  *At December 31, 2012, the Partnership had $313.0 million of cash and cash
    equivalents in wholly owned subsidiaries and $1.19 billion available for
    borrowing under its $1.2 billion revolving credit facility after
    consideration of $11.6 million of outstanding letters of credit.

Operating Results

  *Operating income before items not allocated to segments for the three
    months ended December 31, 2012, was $163.1 million, a decrease of $7.9
    million when compared to segment operating income of $171.0 million over
    the same period in 2011. This decrease was primarily attributable to lower
    commodity prices compared to the prior year quarter. Processed volumes
    continued to remain strong, growing over 27 percent when compared to the
    fourth quarter of 2011, primarily due to the Partnership’s Liberty and
    Southwest segments. The Partnership has changed its segment reporting. The
    Javelina facility, which was previously reported separately in the Gulf
    Coast segment, is now included in the Southwest segment. In addition,
    operations in Ohio are now reported separately as the Utica segment.

    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
    loss on commodity derivative instruments. Realized losses on commodity
    derivative instruments were $2.1 million in the fourth quarter of 2012 and
    $20.0 million in the fourth quarter of 2011.

Capital Expenditures

  *For the three months and year ended December 31, 2012, the Partnership’s
    portion of capital expenditures was $532.5 million and $1,718.4 million,
    respectively. These expenditures do not include the Keystone purchase
    price of $507.3 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership is maintaining its DCF forecast in a range of $500
million to $575 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 has been
narrowed to a range of $1.5 billion to $1.8 billion.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, February
28, 2013, at 12:00 p.m. Eastern Time to review its fourth quarter and full
year 2012 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
(800) 388-9075 (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. 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
(in thousands, except per unit data)
                                                                   
                  Three months ended December     Twelve months ended December
                  31,                             31,
Statement of      2012            2011            2012             2011
Operations Data
Revenue:
Revenue           $ 365,927       $ 424,802       $ 1,395,231      $ 1,534,434
Derivative gain    5,583         (90,889   )    56,535         (29,035   )
(loss)
Total revenue      371,510       333,913       1,451,766      1,505,399 
                                                                   
Operating
expenses:
Purchased           143,673         184,877         530,328          682,370
product costs
Derivative loss
(gain) related      7,174           35,094          (13,962    )     52,960
to purchased
product costs
Facility            57,714          49,240          208,385          173,598
expenses
Derivative loss
(gain) related      235             (3,609    )     1,371            (6,480    )
to facility
expenses
Selling,
general and         25,091          20,775          94,116           81,229
administrative
expenses
Depreciation        57,350          39,674          189,549          149,954
Amortization of
intangible          15,040          10,985          53,320           43,617
assets
Loss on
disposal of         3,271           4,178           6,254            8,797
property, plant
and equipment
Accretion of
asset              137           256           677            1,190     
retirement
obligations
Total operating    309,685       341,470       1,070,038      1,187,235 
expenses
                                                                   
Income (loss)       61,825          (7,557    )     381,728          318,164
from operations
                                                                   
Other income
(expense):
(Loss) earnings
from                (89       )     167             699              (1,095    )
unconsolidated
affiliates
Interest income     124             208             419              422
Interest            (33,336   )     (30,595   )     (120,191   )     (113,631  )
expense
Amortization of
deferred
financing costs
and discount (a     (1,658    )     (1,241    )     (5,601     )     (5,114    )
component of
interest
expense)
Loss on
redemption of       -               (35,535   )     -                (78,996   )
debt
Miscellaneous
(expense)          (1        )    17            62             144       
income, net
Income (loss)
before              26,865          (74,536   )     257,116          119,894
provision for
income tax
                                                                   
Provision for
income tax
(benefit)
expense:
Current             (4,568    )     9,474           (2,366     )     17,578
Deferred           1,298         (22,267   )    40,694         (3,929    )
Total provision    (3,270    )    (12,793   )    38,328         13,649    
for income tax
                                                                   
Net income          30,135          (61,743   )     218,788          106,245
(loss)
                                                                   
Net loss
(income)
attributable to     1,679           (12,342   )     1,614            (45,550   )
non-controlling
interest
                                                                
Net income
(loss)            $ 31,814       $ (74,085   )   $ 220,402       $ 60,695    
attributable to
the Partnership
                                                                   
Net income
(loss)
attributable to
the
Partnership's
common
unitholders per
common unit:
Basic             $ 0.26         $ (0.87     )   $ 1.98          $ 0.75      
Diluted           $ 0.22         $ (0.87     )   $ 1.69          $ 0.75      
                                
Weighted
average number
of outstanding
common units:
Basic              122,079       85,431        109,979        78,466    
Diluted            142,720       85,431        130,648        78,619    
                                                                   
Cash Flow Data
Net cash flow
provided by
(used in):
Operating         $ 106,995       $ 83,449        $ 496,713        $ 414,698
activities
Investing         $ (726,281  )   $ (188,867  )   $ (2,472,352 )   $ (776,553  )
activities
Financing         $ 552,121       $ 63,257        $ 2,206,522      $ 411,421
activities
                                                                   
Other Financial
Data
Distributable     $ 111,774       $ 88,405        $ 416,423        $ 332,796
cash flow
Adjusted EBITDA   $ 135,079       $ 147,235       $ 528,168        $ 515,258
                                                                   
                                                                   
Balance Sheet     December 31,    December 31,
Data              2012            2011
Working capital   $ (82,587   )   $ 4,234
Total assets        6,835,716       4,070,425
Total debt          2,523,051       1,846,062
Total equity        3,215,591       1,502,067
                                                                   


MarkWest Energy Partners, L.P.
Operating Statistics
                                                                
                                   Three months ended     Twelve months ended
                                   December 31,           December 31,
                                   2012        2011       2012        2011
Southwest
East Texas gathering systems       477,600     423,100    450,000     423,600
throughput (Mcf/d)
East Texas natural gas processed   302,000     235,100    270,800     228,300
(Mcf/d)
East Texas NGL sales (gallons,     76,500      63,500     275,800     238,700
in thousands)
                                                                      
Western Oklahoma gathering         200,800     277,500    235,600     237,900
system throughput (Mcf/d) (1)
Western Oklahoma natural gas       193,800     231,700    206,500     175,500
processed (Mcf/d)
Western Oklahoma NGL sales         44,500      66,100     214,400     177,200
(gallons, in thousands)
                                                                      
Southeast Oklahoma gathering       463,100     524,800    487,900     511,900
system throughput (Mcf/d)
Southeast Oklahoma natural gas     137,000     104,200    121,800     103,400
processed (Mcf/d) (2)
Southeast Oklahoma NGL sales       42,400      33,000     163,300     125,100
(gallons, in thousands)
Arkoma Connector Pipeline          253,700     346,000    305,900     307,300
throughput (Mcf/d)
                                                                      
Other Southwest gathering system   22,300      25,100     24,300      29,900
throughput (Mcf/d) (3)
                                                                      
Gulf Coast refinery off-gas        113,600     113,700    118,400     113,300
processed (Mcf/d)
Gulf Coast liquids fractionated    21,000      20,800     22,500      21,200
(Bbl/d)
Gulf Coast NGL sales (gallons
excluding hydrogen, in             81,000      80,200     345,300     325,700
thousands)
                                                                      
Northeast (4)
Natural gas processed (Mcf/d)      313,700     320,300    320,500     305,900
NGLs fractionated (Bbl/d) (5)      19,500      17,200     17,500      20,300
                                                                      
Keep-whole sales (gallons, in      35,100      31,100     131,600     113,800
thousands)
Percent-of-proceeds sales          36,200      34,700     139,700     130,300
(gallons, in thousands)
Total NGL sales (gallons, in       71,300      65,800     271,300     244,100
thousands) (6)
                                                                      
Crude oil transported for a fee    9,900       9,700      9,300       10,300
(Bbl/d)
                                                                      
Liberty
Natural gas processed (Mcf/d)      696,000     374,800    496,400     323,900
Gathering system throughput        587,600     295,600    425,000     245,700
(Mcf/d)
NGLs fractionated (Bbl/d) (7)      31,100      19,200     24,900      11,800
NGL sales (gallons, in             129,400     77,700     393,600     241,200
thousands) (8)
                                                                      
Utica (9)
Natural gas processed (Mcf/d)      5,000       N/A        4,200       N/A
Gathering system throughput        6,400       N/A        5,000       N/A
(Mcf/d)
                                                                      

      Includes natural gas gathered in Western Oklahoma and from the Granite
(1)  Wash formation in the Texas Panhandle. It is considered one integrated
      area of operations.
(2)   The natural gas processing in Southeast Oklahoma is outsourced to
      Centrahoma, our equity investment, or other third party processors.
(3)   Excludes lateral pipelines where revenue is not based on throughput.
      Includes throughput from the Kenova, Cobb, Boldman and Langley
(4)   processing plants. We acquired the Langley processing plant in February
      2011. The volumes reported are the average daily rates for the days of
      operation.
      Amount includes 1,400 and 200 barrels per day fractionated on behalf of
      Liberty for the three months ended December 31, 2012 and 2011,
      respectively, and 400 and 3,900 barrels per day fractionated for the
(5)   twelve months ended December 31, 2012 and 2011, respectively. Beginning
      in the fourth quarter of 2011, Siloam no longer fractionates NGLs on
      behalf of Liberty due to the operation of Liberty’s fractionation
      facility that began in September 2011 except during temporary periods of
      capacity constraint.
      Represents sales at the Siloam fractionator. The total sales exclude
      approximately 5,500,000 and 600,000 gallons, sold by the Northeast on
(6)   behalf of Liberty for three months ended December 31, 2012 and 2011,
      respectively, and 6,500,000 and 59,200,000 gallons sold for the twelve
      months ended December 31, 2012 and 2011, respectively. These volumes are
      included as part of NGLs sold at Liberty.
      Amount includes all NGLs that were produced at the Liberty processing
      facilities and fractionated into purity products at our Liberty
(7)   fractionation facility. Through August 2011, only propane was recovered
      at our Liberty facilities. In September 2011, Liberty’s fractionation
      facility commenced operations and Liberty now has full fractionation
      capabilities.
      Includes sale of all purity products fractionated at the Liberty
(8)   facilities and sale of all unfractionated NGLs. Also includes the sale
      of purity products fractionated and sold at the Siloam facilities on
      behalf of Liberty.
(9)   Utica operations began in August 2012. The volumes reported are the
      average daily rate for the days of operation.
      


MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Operating Income before Items not Allocated to Segments
(in thousands)
                                                                    
Three months
ended December    Southwest       Northeast      Liberty     Utica        Total
31, 2012
Revenue           $ 204,370       $ 56,862       $ 106,106   $ 426        $ 367,764
                                                                          
Operating
expenses:
Purchased           99,765          18,740         25,168      -            143,673
product costs
Facility           30,195        6,529        21,281     2,377      60,382
expenses
Total operating
expenses before
items not           129,960         25,269         46,449      2,377        204,055
allocated to
segments
                                                                          
Portion of
operating
income (loss)      1,211         -            -          (619   )    592
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 73,199       $ 31,593      $ 59,657    $ (1,332 )   $ 163,117
not allocated
to segments
                                                                          
                                                                          
Three months
ended December    Southwest       Northeast      Liberty     Utica        Total
31, 2011
Revenue           $ 279,329       $ 67,197       $ 80,807    $ -          $ 427,333
                                                                          
Operating
expenses:
Purchased           133,660         19,085         32,132      -            184,877
product costs
Facility           32,042        7,724        12,038     -          51,804
expenses
Total operating
expenses before
items not           165,702         26,809         44,170      -            236,681
allocated to
segments
                                                                          
Portion of
operating
income             1,686         -            17,949     -          19,635
attributable to
non-controlling
interests
Operating
income before
items not         $ 111,941      $ 40,388      $ 18,688     N/A       $ 171,017
allocated to
segments
                                                                          
                                                                          
                  Three months ended December
                  31,
                  2012            2011
                                                                          
Operating
income before
items not         $ 163,117       $ 171,017
allocated to
segments
Portion of
operating
income              592             19,635
attributable to
non-controlling
interests
Derivative loss
not allocated       (1,826    )     (122,374 )
to segments
Revenue
deferral            (1,837    )     (2,531   )
adjustment
Compensation
expense
included in
facility            (196      )     (290     )
expenses not
allocated to
segments
Facility
expenses            2,864           2,854
adjustments
Selling,
general and         (25,091   )     (20,775  )
administrative
expenses
Depreciation        (57,350   )     (39,674  )
Amortization of
intangible          (15,040   )     (10,985  )
assets
Loss on
disposal of         (3,271    )     (4,178   )
property, plant
and equipment
Accretion of
asset              (137      )    (256     )
retirement
obligations
Income (loss)       61,825          (7,557   )
from operations
Other income
(expense):
(Loss) earnings
from                (89       )     167
unconsolidated
affiliate
Interest income     124             208
Interest            (33,336   )     (30,595  )
expense
Amortization of
deferred
financing costs
and discount (a     (1,658    )     (1,241   )
component of
interest
expense)
Loss on
redemption of       -               (35,535  )
debt
Miscellaneous
(expense)          (1        )    17       
income, net
Income (loss)
before            $ 26,865       $ (74,536  )
provision for
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
(in thousands)
                                                                          
Twelve months
ended December    Southwest       Northeast      Liberty     Utica        Total
31, 2012
Revenue           $ 856,416       $ 225,818      $ 319,867   $ 571        $ 1,402,672
                                                                          
Operating
expenses:
Purchased           387,902         68,402         74,024      -            530,328
product costs
Facility           124,921       24,106       65,825     3,968      218,820
expenses
Total operating
expenses before
items not           512,823         92,508         139,849     3,968        749,148
allocated to
segments
                                                                          
Portion of
operating
income (loss)      5,790         -            -          (1,359 )    4,431
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 337,803      $ 133,310     $ 180,018   $ (2,038 )   $ 649,093
not allocated
to segments
                                                                          
                                                                          
Twelve months
ended December    Southwest       Northeast      Liberty     Utica        Total
31, 2011
Revenue           $ 1,031,986     $ 268,884      $ 248,949   $ -          $ 1,549,819
                                                                          
Operating
expenses:
Purchased           506,911         91,612         83,847      -            682,370
product costs
Facility           121,197       27,126       34,913     -          183,236
expenses
Total operating
expenses before
items not           628,108         118,738        118,760     -            865,606
allocated to
segments
                                                                          
Portion of
operating
income             5,431         -            63,731     -          69,162
attributable to
non-controlling
interests
Operating
income before
items not         $ 398,447      $ 150,146     $ 66,458     N/A       $ 615,051
allocated to
segments
                                                                          
                                                                          
                  Twelve months ended December
                  31,
                  2012            2011
                                                                          
Operating
income before
items not         $ 649,093       $ 615,051
allocated to
segments
Portion of
operating
income              4,431           69,162
attributable to
non-controlling
interests
Derivative gain
(loss) not          69,126          (75,515  )
allocated to
segments
Revenue
deferral            (7,441    )     (15,385  )
adjustment
Compensation
expense
included in
facility            (1,022    )     (1,781   )
expenses not
allocated to
segments
Facility
expenses            11,457          11,419
adjustments
Selling,
general and         (94,116   )     (81,229  )
administrative
expenses
Depreciation        (189,549  )     (149,954 )
Amortization of
intangible          (53,320   )     (43,617  )
assets
Loss on
disposal of         (6,254    )     (8,797   )
property, plant
and equipment
Accretion of
asset              (677      )    (1,190   )
retirement
obligations
Income from         381,728         318,164
operations
Other income
(expense):
Earnings (loss)
from                699             (1,095   )
unconsolidated
affiliate
Interest income     419             422
Interest            (120,191  )     (113,631 )
expense
Amortization of
deferred
financing costs
and discount (a     (5,601    )     (5,114   )
component of
interest
expense)
Loss on
redemption of       -               (78,996  )
debt
Miscellaneous      62            144      
income, net
Income before
provision for     $ 257,116      $ 119,894  
income tax
                                                                          

                                                             
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(in thousands)
                                                                  
                   Three months ended December    Twelve months ended December
                   31,                            31,
                   2012             2011          2012            2011
                                                                  
Net income         $  30,135        $ (61,743 )   $ 218,788       $ 106,245
(loss)
Depreciation,
amortization,
impairment, and       75,876          55,171        250,112         203,870
other non-cash
operating
expenses
Loss on
redemption of         -               32,446        -               72,064
debt, net of tax
benefit
Amortization of
deferred              1,658           1,241         5,601           5,114
financing costs
and discount
Non-cash loss
(earnings) from       89              (167    )     (699      )     1,095
unconsolidated
affiliate
Distributions
from                  400             (560    )     2,600           (260     )
unconsolidated
affiliate
Non-cash
compensation          1,977           (308    )     8,247           3,399
expense
Non-cash
derivative            (312      )     102,391       (102,127  )     (290     )
activity
Provision for
income tax -          1,298           (22,267 )     40,694          (3,929   )
deferred
Cash adjustment
for
non-controlling       (67       )     (18,185 )     (2,580    )     (64,470  )
interest of
consolidated
subsidiaries
Revenue deferral      1,837           2,531         7,441           15,385
adjustment
Other                 (314      )     4,634         3,648           9,171
Maintenance
capital
expenditures,        (803      )    (6,779  )    (15,302   )    (14,598  )
net of joint
venture partner
contributions
Distributable      $  111,774      $ 88,405     $ 416,423      $ 332,796  
cash flow
                                                                  
Maintenance
capital            $  803           $ 7,490       $ 15,302        $ 16,067
expenditures
Growth capital       709,758       183,865     1,936,125     535,214  
expenditures
Total capital         710,561         191,355       1,951,427       551,281
expenditures
Acquisitions,
net of cash          -             -           506,797       230,728  
acquired
Total capital
expenditures and      710,561         191,355       2,458,224       782,009
acquisitions
Joint venture
partner              (178,018  )    (61,115 )    (233,018  )    (129,616 )
contributions
Total capital
expenditures and   $  532,543      $ 130,240    $ 2,225,206    $ 652,393  
acquisitions,
net
                                                                  
Distributable      $  111,774       $ 88,405      $ 416,423       $ 332,796
cash flow
Maintenance
capital               803             6,779         15,302          14,598
expenditures,
net
Changes in
receivables and       (1,540    )     (32,268 )     25,406          (65,523  )
other assets
Changes in
accounts
payable, accrued      (3,645    )     466           41,723          69,838
liabilities and
other long-term
liabilities
Derivative
instrument
premium               -               1,155         -               4,436
payments, net of
amortization
Cash adjustment
for
non-controlling       67              18,185        2,580           64,470
interest of
consolidated
subsidiaries
Other                (464      )    727         (4,721    )    (5,917   )
Net cash
provided by        $  106,995      $ 83,449     $ 496,713      $ 414,698  
operating
activities
                                                                             

                                                              
MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA ^(1)
(in thousands)
                                                                   
                  Three months ended December 31,   Twelve months ended
                                                    December 31,
                  2012              2011            2012           2011
                                                                   
Net income        $  30,135         $  (61,743  )   $ 218,788      $ 106,245
(loss)
Non-cash
compensation         1,977             (308     )     8,247          3,399
expense
Non-cash
derivative           (312     )        102,391        (102,127 )     (290    )
activity
Interest             32,838            29,634         117,098        109,869
expense ^(2)
Depreciation,
amortization,
impairment, and      75,876            55,171         250,112        203,870
other non-cash
operating
expenses
Loss on
redemption of        -                 35,535         -              78,996
debt
Provision for        (3,270   )        (12,793  )     38,328         13,649
income tax
Adjustment for
cash flow from       489               (167     )     1,901          1,395
unconsolidated
affiliate
Other               (2,654   )       (485     )    (4,179   )    (1,875  )
Adjusted EBITDA   $  135,079       $  147,235     $ 528,168     $ 515,258 
                                                                             

      The Partnership has changed its calculation of adjusted EBITDA and
(1)  removed the line "Adjustment related to non-guarantor of consolidated
      subsidiaries".
(2)   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 February
27, 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        NGL-to-Crude
Oil          oil                                                
Price
(WTI)      ratio (1)         $2.50   $3.00   $3.50   $4.00   $4.50
            55% of WTI        $ 614   $ 610   $ 606   $ 602   $ 599
$110         45% of WTI        $ 538   $ 534   $ 530   $ 527   $ 523
          35% of WTI        $ 466   $ 463   $ 459   $ 455   $ 451
            55% of WTI        $ 583   $ 579   $ 575   $ 571   $ 568
$100         45% of WTI        $ 515   $ 512   $ 508   $ 504   $ 500
          35% of WTI        $ 450   $ 446   $ 442   $ 439   $ 435
            55% of WTI        $ 549   $ 545   $ 542   $ 538   $ 534
$90          45% of WTI        $ 491   $ 487   $ 483   $ 479   $ 475
          35% of WTI        $ 431   $ 427   $ 424   $ 420   $ 416
            55% of WTI        $ 526   $ 522   $ 518   $ 514   $ 510
$80          45% of WTI        $ 473   $ 470   $ 466   $ 462   $ 458
          35% of WTI        $ 421   $ 417   $ 413   $ 408   $ 404
            55% of WTI        $ 507   $ 503   $ 499   $ 495   $ 491
$70          45% of WTI        $ 461   $ 457   $ 453   $ 449   $ 445
          35% of WTI        $ 414   $ 410   $ 405   $ 400   $ 395
                                                                           

      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