MarkWest Energy Partners Reports Third Quarter Financial Results and Increases Common Unit Distribution by 11 Percent

  MarkWest Energy Partners Reports Third Quarter Financial Results and
  Increases Common Unit Distribution by 11 Percent

Business Wire

DENVER -- November 07, 2012

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 $104.3 million for the three months ended
September 30, 2012, and $304.6 million for the nine months ended September 30,
2012. Distributable cash flow for the three months ended September 30, 2012,
represents distribution coverage of 109 percent. The third quarter
distribution of $95.3 million, or $0.81 per common unit, will be paid to
unitholders on November 14, 2012. The third quarter 2012 distribution
represents an increase of $0.01 per common unit, or 1.3 percent, over the
second quarter 2012 distribution and an increase of $0.08 per common unit, or
11.0 percent, over the third quarter 2011 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 nine months ended
September 30, 2012, of $108.2 million and $371.7 million, respectively, as
compared to $107.0 million and $323.2 million for the three and nine months
ended September 30, 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 (loss) income before provision for income tax for the
three and nine months ended September 30, 2012, of $(22.2) million and $230.3
million, respectively. (Loss) income before provision for income tax includes
non-cash (loss) gain associated with the change in mark-to-market of
derivative instruments of $(43.7) million and $101.8 million for the three and
nine months ended September 30, 2012, respectively. Excluding these items,
income before provision for income tax for the three and nine months ended
September 30, 2012, would have been $21.5 million and $128.5 million,
respectively.

“Our organic growth strategy continues to deliver solid financial results and
significant opportunities for future expansion and capital investment,” said
Frank Semple, Chairman, President and Chief Executive Officer. “MarkWest’s
diverse set of assets and focus on delivering high quality customer service
resulted in year over year volume increases of over 20% and 11% distribution
growth. In addition, our ongoing development in the Marcellus Shale and the
Utica Shale continues to provide critical midstream infrastructure for our
producer customers’ drilling programs and provides a significant inventory of
future growth projects.”

BUSINESS HIGHLIGHTS

Business Development

  *Liberty: In July 2012, the Partnership announced a new long-term,
    fee-based agreement with XTO Energy (XTO) to transport, fractionate and
    market natural gas liquids (NGLs) from their 125 million cubic feet per
    day (MMcf/d) processing plant located in Butler County, Pennsylvania. NGLs
    will initially be transported by truck from XTO’s plant to the Houston
    fractionation and marketing complex in Washington County, Pennsylvania. By
    the end of 2013, an extension of the Partnership’s NGL gathering pipeline
    into northwest Pennsylvania is expected to be complete, which will connect
    the Keystone complex and XTO facility to the Houston complex.

    In September 2012, the Partnership announced a 10-year agreement to become
    a firm shipper on the Mariner East pipeline project (“Mariner East”)
    subject to final regulatory approvals. Mariner East is currently designed
    to transport ethane and propane sourced at the Partnership’s Houston
    complex to Sunoco, Inc’s Marcus Hook facility located near Philadelphia,
    Pennsylvania. Once delivered, the ethane-propane mix will be
    re-fractionated into purity products for sale to domestic and
    international markets.

    During the third quarter, the Partnership continued to transport propane
    from the Houston fractionation complex to Marcus Hook for delivery to
    international markets. Since the commencement of propane exports in July
    2012, the Partnership has marketed over 900,000 barrels. Total propane
    volumes loaded onto ships at Marcus Hook include the Partnership’s volume
    and purchased product sourced at Sunoco’s local-area facilities. The
    Partnership anticipates the continuation of exports from Marcus Hook as
    long as it is economically possible for our producer customers to capture
    premium prices that currently exist in the international markets.

    In October 2012, the Partnership commenced operations of the 200 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
    development of midstream infrastructure in Doddridge County. The
    Partnership expects the Sherwood II facility, a 200 MMcf/d cryogenic
    processing plant, to be operational in the second quarter of 2013.

    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 and is expected to be completed
    in the fourth quarter of 2013.

  *Utica: In November 2012, MarkWest Utica EMG, LLC (MarkWest Utica) a joint
    venture between MarkWest and The Energy and Minerals Group, 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 will initially bring
    online an interim 45 MMcf/d refrigeration processing plant at its Seneca
    processing complex, with an expected second quarter of 2013 completion
    date. This interim facility will be followed by Seneca I, a 200 MMcf/d
    cryogenic gas processing facility, which is expected to begin operations
    by the third quarter of 2013. The definitive agreements contemplate the
    construction of additional facility, Seneca II, a 200 MMcf/d cryogenic
    processing facility, which may be installed as soon as the end of 2013. In
    addition to its Seneca processing complex, MarkWest Utica will construct
    an NGL gathering system to its Cadiz processing complex and then on to the
    Harrison County, Ohio fractionation and marketing complex. The Cadiz
    complex will include a de-ethanization facility where purity ethane will
    be produced and delivered into the ATEX ethane pipeline. The propane and
    heavier natural gas liquids will then flow via pipeline to the Harrison
    County fractionator for further separation into purity products. The
    completion of the NGL gathering system and fractionation will provide
    Antero Resources direct market access to the planned ethane and propane
    pipeline projects in the northeast.
  *Northeast: In October 2012, the Partnership commenced operations of its
    150 MMcf/d Langley 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 655
    MMcf/d and further expands the Partnership’s position as the largest
    natural gas processor in the Appalachian Basin.
  *Southwest: In September 2012, Centrahoma Processing, LLC a joint venture
    between MarkWest and Cardinal Midstream, LLC in Southeast Oklahoma agreed
    to construct a 120 MMcf/d processing plant expansion in order to support
    drilling programs in the Woodford Shale. The plant is expected to be
    operational in the fourth quarter of 2013.

Capital Markets

  *On August 10, 2012, the Partnership completed a public offering of $750
    million aggregate principal amount of 5.5% senior unsecured notes due 2023
    issued at 99.015% of par. The aggregate net proceeds of approximately $731
    million were used to repay borrowings under the Partnership’s revolving
    credit facility, to partially fund the Partnership’s capital expenditure
    program and for other general partnership purposes.

  *On August 17, 2012, the Partnership completed a common unit equity
    offering of 6.9 million common units. The net proceeds of  approximately 
    $338 million were used to partially fund the Partnership’s capital
    expenditure program and for other general partnership purposes.

FINANCIAL RESULTS

Balance Sheet

  *At September 30, 2012, the Partnership had $411.5 million of cash and cash
    equivalents in wholly owned subsidiaries and $1.18 billion available for
    borrowing under its $1.2 billion revolving credit facility after
    consideration of $21.6 million of outstanding letters of credit.

Operating Results

  *Operating income before items not allocated to segments for the three
    months ended September 30, 2012, was $145.5 million, a decrease of $2.3
    million when compared to segment operating income of $147.8 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 20 percent when compared to the
    third quarter of 2011, primarily due to the Partnership’s Liberty and
    Southwest segments.

    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 $8.4 million in the third quarter of 2012 and
    $15.8 million in the third quarter of 2011.

Capital Expenditures

  *For the three and nine months ended September 30, 2012, the Partnership’s
    portion of capital expenditures was $603.7 million and $1,185.9 million,
    respectively. These expenditures do not include the Keystone purchase
    price of $509.6 million.

2012 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2012, the Partnership forecasts DCF in a range of $410 million to $430
million based on its current forecast of operational volumes and prices for
crude oil, natural gas and natural gas liquids; derivative instruments
currently outstanding; and the Keystone acquisition, as mentioned above. The
midpoint of this range results in approximately 117 percent coverage of the
Partnership’s full-year distribution based on current quarterly distributions
and common units outstanding.

The Partnership’s portion of growth capital expenditures for 2012 has
increased primarily due to accelerated spending on key expansion projects in
the Marcellus Shale, and is forecasted to be approximately $1.8 billion. This
range excludes the Keystone purchase price of $509.6 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership forecasts DCF 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. The midpoint of this range results in approximately 141
percent coverage of the Partnership’s full-year distribution based on current
quarterly distributions and common units 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
forecasted in a range of $1.4 billion to $1.9 billion.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Thursday, November
8, 2012, at 12:00 p.m. Eastern Time to review its third quarter 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
(866) 495-9346 (no passcode required).

MarkWest Energy Partners, L.P. is a master limited partnership engaged in the
gathering, transportation, and processing of natural gas; the transportation,
fractionation, marketing, and storage of natural gas liquids; and the
gathering and transportation of crude oil. MarkWest has extensive natural gas
gathering, processing, and transmission operations in the southwest, Gulf
Coast, and northeast regions of the United States, including the Marcellus
Shale, and is the largest natural gas processor and fractionator in the
Appalachian region.

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, 2011 and its Quarterly Reports on
Form 10-Q for the quarters ended March 31, 2012, June 30, 2012 and September
30, 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
(unaudited, in thousands, except per unit data)
                                                               
                  Three months ended September      Nine months ended September
                  30,                               30,
Statement of      2012              2011            2012             2011
Operations Data
Revenue:
Revenue           $ 320,137         $ 400,883       $ 1,029,304      $ 1,109,632
Derivative         (36,400   )      106,943       50,952         61,854    
(loss) gain
Total revenue      283,737         507,826       1,080,256      1,171,486 
                                                                     
Operating
expenses:
Purchased           119,369           189,284         386,655          497,493
product costs
Derivative loss
(gain) related      11,643            (1,274    )     (21,136    )     17,866
to purchased
product costs
Facility            53,293            44,236          150,671          124,358
expenses
Derivative loss
(gain) related      4,028             (2,787    )     1,136            (2,871    )
to facility
expenses
Selling,
general and         21,922            20,162          69,025           60,454
administrative
expenses
Depreciation        48,136            38,715          132,199          110,280
Amortization of
intangible          14,988            10,985          38,280           32,632
assets
Loss on
disposal of         655               147             2,983            4,619
property, plant
and equipment
Accretion of
asset              141             557           540            934       
retirement
obligations
Total operating    274,175         300,025       760,353        845,765   
expenses
                                                                     
Income from         9,562             207,801         319,903          325,721
operations
                                                                     
Other income
(expense):
Earnings (loss)
from                246               (507      )     788              (1,262    )
unconsolidated
affiliates
Interest income     64                62              295              214
Interest            (30,621   )       (26,899   )     (86,855    )     (83,036   )
expense
Amortization of
deferred
financing costs
and discount (a     (1,428    )       (1,002    )     (3,943     )     (3,873    )
component of
interest
expense)
Loss on
redemption of       -                 (133      )     -                (43,461   )
debt
Miscellaneous
income             1               (4        )    63             127       
(expense), net
(Loss) Income
before              (22,176   )       179,318         230,251          194,430
provision for
income tax
                                                                     
Provision for
income tax
(benefit)
expense:
Current             (17,948   )       3,959           2,202            8,104
Deferred           10,528          21,905        39,396         18,338    
Total provision    (7,420    )      25,864        41,598         26,442    
for income tax
                                                                     
Net (loss)          (14,756   )       153,454         188,653          167,988
income
                                                                     
Net loss
(income)
attributable to     416               (13,142   )     (65        )     (33,208   )
non-controlling
interest
                                                                  
Net (loss)
income            $ (14,340   )     $ 140,312      $ 188,588       $ 134,780   
attributable to
the Partnership
                                                                     
Net (loss)
income
attributable to
the
Partnership's
common
unitholders per
common unit:
Basic             $ (0.13     )     $ 1.77         $ 1.77          $ 1.75      
Diluted           $ (0.13     )     $ 1.77         $ 1.49          $ 1.75      
                                                                     
Weighted
average number
of outstanding
common units:
Basic              113,994         78,619        105,916        76,118    
Diluted            113,994         78,760        126,595        76,276    
                                                                     
Cash Flow Data
Net cash flow
provided by
(used in):
Operating         $ 133,281         $ 124,885       $ 389,718        $ 331,249
activities
Investing         $ (658,573  )     $ (125,637  )   $ (1,746,071 )   $ (587,686  )
activities
Financing         $ 814,894         $ 64,894        $ 1,654,401      $ 348,164
activities
                                                                     
Other Financial
Data
Distributable     $ 104,289         $ 85,311        $ 304,649        $ 244,391
cash flow
Adjusted EBITDA   $ 108,180         $ 107,013       $ 371,655        $ 323,204
                                                                     
Balance Sheet     September 30,     December 31,
Data              2012              2011
Working capital   $ (17,336   )     $ 4,234
Total assets        6,237,143         4,070,425
Total debt          2,522,854         1,846,062
Total equity      $ 2,620,940       $ 1,502,067
                                                                     

MarkWest Energy Partners, L.P.
Operating Statistics
                                                                
                                   Three months ended     Nine months ended
                                   September 30,          September 30,
                                   2012        2011       2012        2011
Southwest
East Texas gathering systems       471,200     417,400    440,700     423,800
throughput (Mcf/d)
East Texas natural gas processed   270,200     229,700    260,400     226,000
(Mcf/d)
East Texas NGL sales (gallons,     67,800      59,000     199,300     175,200
in thousands)
                                                                      
Western Oklahoma gathering         227,900     241,300    247,300     224,400
system throughput (Mcf/d) (1)
Western Oklahoma natural gas       209,600     153,200    210,800     156,600
processed (Mcf/d)
Western Oklahoma NGL sales         50,900      37,000     169,900     111,100
(gallons, in thousands)
                                                                      
Southeast Oklahoma gathering       484,400     512,600    496,200     507,500
system throughput (Mcf/d)
Southeast Oklahoma natural gas     128,600     105,400    116,700     103,100
processed (Mcf/d) (2)
Southeast Oklahoma NGL sales       46,700      30,600     121,000     92,100
(gallons, in thousands)
Arkoma Connector Pipeline          310,400     298,600    323,400     294,300
throughput (Mcf/d)
                                                                      
Other Southwest gathering system   23,600      29,900     25,000      31,500
throughput (Mcf/d)
                                                                      
Northeast
Natural gas processed (Mcf/d)      318,500     277,400    322,800     300,700
(3)
NGLs fractionated (Bbl/d) (4)      16,500      19,300     16,800      21,400
                                                                      
Keep-whole sales (gallons, in      23,200      21,700     96,500      82,600
thousands)
Percent-of-proceeds sales          33,700      31,600     103,500     95,600
(gallons, in thousands)
Total NGL sales (gallons, in       56,900      53,300     200,000     178,200
thousands) (5)
                                                                      
Crude oil transported for a fee    8,700       9,900      9,100       10,500
(Bbl/d)
                                                                      
Liberty
Natural gas processed (Mcf/d)      479,400     366,200    424,300     306,700
Gathering system throughput        444,700     258,300    373,700     228,900
(Mcf/d)
NGLs fractionated (Bbl/d) (6)      22,300      12,400     20,700      9,300
NGL sales (gallons, in             90,800      61,100     264,200     163,500
thousands) (7)
                                                                      
Gulf Coast
Refinery off-gas processed         123,800     122,000    120,000     113,200
(Mcf/d)
Liquids fractionated (Bbl/d)       23,800      23,100     23,000      21,400
NGL sales (gallons excluding       92,100      89,200     264,400     245,500
hydrogen, in thousands)

      Includes natural gas gathered in Western Oklahoma and from the Granite
(1)  Wash formation in the Texas Panhandle as it is 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.
      
      Includes throughput from the Kenova, Cobb, Boldman and Langley
(3)   processing plants. We acquired the Langley processing plants in February
      2011. The volumes reported for the nine months ended September 30, 2011
      are the average daily rates for the days of operation.
      
      Amount includes zero barrels per day and 4,400 barrels per day
      fractionated on behalf of Liberty for the three months ended September
      30, 2012 and 2011, respectively and includes zero barrels per day and
(4)   5,100 barrels per day fractionated on behalf of Liberty for the nine
      months ended September 30, 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 outages or force majeure events.
      
      Represents sales from the Siloam facilities. The total sales exclude
      approximately 600,000 gallons and 17,100,000 gallons sold by the
      Northeast on behalf of Liberty for the three months ended September 30,
(5)   2012 and 2011, respectively and 975,000 gallons and 58,600,000 gallons
      sold for the nine months ended September 30, 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
(6)   facilities and fractionated into purity products at our Liberty
      fractionation facility.
      
      Includes sale of all purity products fractionated at the Liberty
(7)   facilities and sale of all unfractionated NGLs. Also includes the sale
      of purity products fractionated and sold from the Siloam facilities on
      behalf of Liberty.
      

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                                               Gulf
ended September   Southwest     Northeast     Liberty      Coast      Total
30, 2012
Revenue           $ 181,456     $ 39,987      $ 78,852     $ 21,477   $ 321,772
                                                                      
Operating
expenses:
Purchased           92,112        11,054        16,203       -          119,369
product costs
Facility           20,527      6,267       20,241     8,928     55,963
expenses
Total operating
expenses before
items not           112,639       17,321        36,444       8,928      175,332
allocated to
segments
                                                                      
Portion of
operating
income             1,543       -           (627   )    -         916
attributable to
non-controlling
interests
Operating
income before
items not         $ 67,274     $ 22,666     $ 43,035    $ 12,549   $ 145,524
allocated to
segments
                                                                      
                                                                      
Three months                                               Gulf
ended September   Southwest     Northeast     Liberty      Coast      Total
30, 2011
Revenue           $ 241,998     $ 55,920      $ 78,586     $ 26,868   $ 403,372
                                                                      
Operating
expenses:
Purchased           141,067       15,947        32,270       -          189,284
product costs
Facility           21,043      6,879       9,108      9,798     46,828
expenses
Total operating
expenses before
items not           162,110       22,826        41,378       9,798      236,112
allocated to
segments
                                                                      
Portion of
operating
income             1,227       -           18,223     -         19,450
attributable to
non-controlling
interests
Operating
income before
items not         $ 78,661     $ 33,094     $ 18,985    $ 17,070   $ 147,810
allocated to
segments
                                                                      
                                                                      
                  Three months ended
                  September 30,
                  2012          2011
                                                                      
Operating
income before
items not         $ 145,524     $ 147,810
allocated to
segments
Portion of
operating
income              916           19,450
attributable to
non-controlling
interests
Derivative
(loss) gain not     (52,071 )     111,004
allocated to
segments
Revenue
deferral            (1,635  )     (2,489  )
adjustment
Compensation
expense
included in
facility            (193    )     (263    )
expenses not
allocated to
segments
Facility
expenses            2,863         2,855
adjustments
Selling,
general and         (21,922 )     (20,162 )
administrative
expenses
Depreciation        (48,136 )     (38,715 )
Amortization of
intangible          (14,988 )     (10,985 )
assets
Loss on
disposal of         (655    )     (147    )
property, plant
and equipment
Accretion of
asset              (141    )    (557    )
retirement
obligations
Income from         9,562         207,801
operations
Other income
(expense):
Earnings (loss)
from                246           (507    )
unconsolidated
affiliate
Interest income     64            62
Interest            (30,621 )     (26,899 )
expense
Amortization of
deferred
financing costs
and discount (a     (1,428  )     (1,002  )
component of
interest
expense)
Loss on
redemption of       -             (133    )
debt
Miscellaneous
income             1           (4      )
(expense), net
(Loss) Income
before            $ (22,176 )   $ 179,318 
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
(unaudited, in thousands)
                                                                   
Nine months                                                   Gulf
ended September   Southwest      Northeast      Liberty       Coast      Total
30, 2012
Revenue           $ 585,343      $ 168,956      $ 213,906     $ 66,703   $ 1,034,908
                                                                         
Operating
expenses:
Purchased           288,137        49,662         48,856        -          386,655
product costs
Facility           66,553       17,577       46,135      28,173    158,438
expenses
Total operating
expenses before
items not           354,690        67,239         94,991        28,173     545,093
allocated to
segments
                                                                         
Portion of
operating
income             4,579        -            (740    )    -         3,839
attributable to
non-controlling
interests
Operating
income before
items not         $ 226,074     $ 101,717     $ 119,655    $ 38,530   $ 485,976
allocated to
segments
                                                                         
                                                                         
Nine months                                                   Gulf
ended September   Southwest      Northeast      Liberty       Coast      Total
30, 2011
Revenue           $ 679,347      $ 201,687      $ 168,142     $ 73,310   $ 1,122,486
                                                                         
Operating
expenses:
Purchased           373,251        72,527         51,715        -          497,493
product costs
Facility           62,055       19,402       22,875      27,100    131,432
expenses
Total operating
expenses before
items not           435,306        91,929         74,590        27,100     628,925
allocated to
segments
                                                                         
Portion of
operating
income             3,745        -            45,782      -         49,527
attributable to
non-controlling
interests
Operating
income before
items not         $ 240,296     $ 109,758     $ 47,770     $ 46,210   $ 444,034
allocated to
segments
                                                                         
                                                                         
                  Nine months ended September
                  30,
                  2012           2011
                                                                         
Operating
income before
items not         $ 485,976      $ 444,034
allocated to
segments
Portion of
operating
income              3,839          49,527
attributable to
non-controlling
interests
Derivative gain
not allocated       70,952         46,859
to segments
Revenue
deferral            (5,604   )     (12,854  )
adjustment
Compensation
expense
included in
facility            (826     )     (1,491   )
expenses not
allocated to
segments
Facility
expenses            8,593          8,565
adjustments
Selling,
general and         (69,025  )     (60,454  )
administrative
expenses
Depreciation        (132,199 )     (110,280 )
Amortization of
intangible          (38,280  )     (32,632  )
assets
Loss on
disposal of         (2,983   )     (4,619   )
property, plant
and equipment
Accretion of
asset              (540     )    (934     )
retirement
obligations
Income from         319,903        325,721
operations
Other income
(expense):
Earnings (loss)
from                788            (1,262   )
unconsolidated
affiliate
Interest income     295            214
Interest            (86,855  )     (83,036  )
expense
Amortization of
deferred
financing costs
and discount (a     (3,943   )     (3,873   )
component of
interest
expense)
Loss on
redemption of       -              (43,461  )
debt
Miscellaneous      63           127      
income, net
Income before
provision for     $ 230,251     $ 194,430  
income tax
                                                                         

MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
                                                             
                   Three months ended September   Nine months ended September
                   30,                            30,
                   2012            2011           2012            2011
                                                                  
Net income         $  (14,756  )   $ 153,454      $ 188,653       $ 167,988
Depreciation,
amortization,
impairment, and       63,998         50,482         174,236         148,699
other non-cash
operating
expenses
Loss on
redemption of         -              119            -               39,618
debt, net of tax
benefit
Amortization of
deferred              1,428          1,002          3,943           3,873
financing costs
and discount
Non-cash
(earnings) loss
from                  (246     )     507            (788      )     1,262
unconsolidated
affiliate
Distributions
from                  500            -              2,200           300
unconsolidated
affiliate
Non-cash
compensation          981            995            6,270           3,707
expense
Non-cash
derivative            43,712         (126,802 )     (101,815  )     (102,681 )
activity
Provision for
income tax -          10,528         21,905         39,396          18,338
deferred
Cash adjustment
for
non-controlling       (490     )     (18,227  )     (2,513    )     (46,285  )
interest of
consolidated
subsidiaries
Revenue deferral      1,635          2,489          5,604           12,854
adjustment
Other                 1,173          1,334          3,962           4,537
Maintenance
capital
expenditures,        (4,174   )    (1,947   )    (14,499   )    (7,819   )
net of joint
venture partner
contributions
Distributable      $  104,289     $ 85,311      $ 304,649      $ 244,391  
cash flow
                                                                  
Maintenance
capital            $  4,174        $ 2,179        $ 14,499        $ 8,577
expenditures
Growth capital       654,489      123,631      1,226,367    351,349  
expenditures
Total capital         658,663        125,810        1,240,866       359,926
expenditures
Acquisitions         -            -            506,797       230,728  
Total capital
expenditures and      658,663        125,810        1,747,663       590,654
acquisitions
Joint venture
partner              (55,000  )    (14,474  )    (55,000   )    (68,501  )
contributions
Total capital
expenditures and   $  603,663     $ 111,336     $ 1,692,663    $ 522,153  
acquisitions,
net
                                                                  
Distributable      $  104,289      $ 85,311       $ 304,649       $ 244,391
cash flow
Maintenance
capital               4,174          1,947          14,499          7,819
expenditures,
net
Changes in
receivables and       (85,436  )     (17,856  )     26,946          (33,255  )
other assets
Changes in
accounts
payable, accrued      110,559        38,405         45,368          69,372
liabilities and
other long-term
liabilities
Derivative
instrument
premium               -              1,137          -               3,281
payments, net of
amortization
Cash adjustment
for
non-controlling       490            18,227         2,513           46,285
interest of
consolidated
subsidiaries
Other                (795     )    (2,286   )    (4,257    )    (6,644   )
Net cash
provided by        $  133,281     $ 124,885     $ 389,718      $ 331,249  
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 September     Nine months ended September
                  30,                              30,
                  2012              2011           2012           2011
                                                                  
Net income        $  (14,756  )     $ 153,454      $ 188,653      $ 167,988
Non-cash
compensation         981              995            6,270          3,707
expense
Non-cash
derivative           43,712           (126,802 )     (101,815 )     (102,681 )
activity
Interest             29,882           25,687         84,260         80,235
expense ^(1)
Depreciation,
amortization,
impairment, and      63,998           50,482         174,236        148,699
other non-cash
operating
expenses
Loss on
redemption of        -                133            -              43,461
debt
Provision for        (7,420   )       25,864         41,598         26,442
income tax
Adjustment for
cash flow from       254              507            1,412          1,562
unconsolidated
affiliate
Adjustment
related to
non-guarantor,       (7,951   )       (22,713  )     (21,434  )     (44,819  )
consolidated
subsidiaries
^(2)
Other               (520     )      (594     )    (1,525   )    (1,390   )
Adjusted EBITDA   $  108,180       $ 107,013     $ 371,655     $ 323,204  

(1)  Includes amortization of deferred financing costs and discount, and
      excludes interest expense related to the Steam Methane Reformer.
      The non-guarantor subsidiaries, in accordance with Credit Facility
      covenants, are MarkWest Liberty Midstream & Resources, L.L.C. and its
(2)   subsidiaries (Liberty), MarkWest Utica EMG L.L.C., MarkWest Pioneer,
      L.L.C., Wirth Gathering Partnership, and Bright Star Partnership. As of
      January 1, 2012, Liberty is a wholly owned subsidiary but remains a
      non-guarantor in accordance with the Credit Facility.
      

                        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 60% for 2013.
b. NGL-to-crude oil ratio at 50% for 2013.
c. NGL-to-crude oil ratio at 40% for 2013.

The analysis further assumes derivative instruments outstanding as of November
2, 2012, and production volumes estimated through December31, 2013. The range
of stated hypothetical changes in commodity prices considers current and
historic market performance.

                           
                        Natural Gas Price (Henry Hub)
Crude Oil   NGL-to-Crude
Price      oil ratio (1)  $ 2.50   $ 3.00   $ 3.50   $ 4.00   $ 4.50
(WTI)
           60% of WTI     $ 699    $ 694    $ 689    $ 683    $ 678
$110        50% of WTI     $ 606    $ 601    $ 596    $ 591    $ 585
          40% of WTI     $ 517    $ 512    $ 507    $ 502    $ 496
            60% of WTI     $ 668    $ 662    $ 657    $ 652    $ 647
$100        50% of WTI     $ 585    $ 580    $ 574    $ 569    $ 564
          40% of WTI     $ 504    $ 499    $ 494    $ 488    $ 483
            60% of WTI     $ 634    $ 628    $ 623    $ 618    $ 613
$90         50% of WTI     $ 561    $ 556    $ 551    $ 545    $ 540
          40% of WTI     $ 488    $ 483    $ 478    $ 472    $ 467
            60% of WTI     $ 611    $ 605    $ 600    $ 595    $ 590
$80         50% of WTI     $ 546    $ 541    $ 535    $ 530    $ 525
          40% of WTI     $ 481    $ 476    $ 470    $ 465    $ 460
            60% of WTI     $ 592    $ 587    $ 582    $ 577    $ 572
$70         50% of WTI     $ 536    $ 530    $ 525    $ 520    $ 515
          40% of WTI     $ 479    $ 473    $ 467    $ 462    $ 456

          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
 
Press spacebar to pause and continue. Press esc to stop.