MarkWest Energy Partners Reports Third Quarter Financial Results; Places into Service Three Major Facilities; Announces

  MarkWest Energy Partners Reports Third Quarter Financial Results; Places
  into Service Three Major Facilities; Announces Additional Midstream
  Infrastructure Project in the Marcellus Shale

  *Placed into service Seneca I, a 200 MMcf/d cryogenic processing facility
    in the Utica Shale and is the first of three major processing facilities
    expected to be operational at this complex within the next six months.
  *Placed into service Majorsville V, a 200 MMcf/d cryogenic processing
    facility that increases the Partnership’s total processing capacity in the
    Marcellus Shale to over 1.8 Bcf/d.
  *Executed agreements with Antero Resources to expand the Sherwood
    processing complex by 200 MMcf/d, bringing total capacity of the complex
    to 1 Bcf/d by the third quarter of 2014.
  *MarkWest Utica EMG and Kinder Morgan Energy Partners announced a binding
    open season to solicit commitments for the NGL pipeline project from
    Mercer, PA to Mt. Belvieu, TX.
  *The Partnership has 22 major processing and fractionation facilities under
    construction.
  *Fee-based net operating margin increased from 53 percent to 62 percent
    when compared to the third quarter of 2012.

Business Wire

DENVER -- November 12, 2013

MarkWest Energy Partners, L.P. (NYSE:MWE) (the Partnership) today reported
quarterly cash available for distribution to common unitholders, or
distributable cash flow (DCF), of $117.9 million for the three months ended
September 30, 2013, and $356.1 million for the nine months ended September 30,
2013. DCF for the three months ended September 30, 2013 represents 92 percent
coverage of the third quarter distribution of $127.9 million or $0.85 per
common unit, which will be paid to unitholders on November 14, 2013. The third
quarter 2013 distribution represents an increase of $0.01 per common unit or
1.2 percent over the second quarter 2013 distribution and an increase of $0.04
per common unit or 4.9 percent compared to the third 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 nine months ended
September 30, 2013, of $153.9 million and $450.5 million, respectively, as
compared to $115.5 million and $390.5 million for the three and nine months
ended September 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 (loss) income before provision for income tax for the
three and nine months ended September 30, 2013, of $(30.3) million and $56.9
million, respectively. (Loss) income before provision for income tax includes
non-cash loss associated with the change in fair value of derivative
instruments of $47.5 million and $1.2 million for the respective three and
nine months ended September 30, 2013, a gain of $0.7 million and $38.9 million
related to the divestiture of gathering assets in the Marcellus Shale for the
respective three and nine months ended September 30, 2013, and a loss
associated with the redemption of debt of $38.5 million for the nine months
ended September 30, 2013. Excluding these items, income before provision for
income tax for the three and nine months ended September 30, 2013 would have
been $16.5 million and $57.7 million, respectively.

“Our results reflect the continued success of our producers’ as they rapidly
develop their acreage positions in high-quality unconventional resource plays,
as well as several short-term operational constraints that we have recently
experienced in the Northeast,” said Frank Semple, Chairman, President and
Chief Executive Officer. “Development of the Marcellus and Utica Shales
continues to provide us with significant future growth opportunities for the
expansion of critical midstream infrastructure. We are committed to providing
our producers with exceptional customer service and unique solutions that will
support their ongoing success.”

BUSINESS HIGHLIGHTS

Marcellus:

  *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, an ethane purity
    products pipeline project being developed by Sunoco Logistics Partners,
    L.P. (NYSE: SXL) (Sunoco), and in the future, will support the ATEX and
    Mariner East ethane takeaway projects.
  *In August 2013, the Partnership announced the development of additional
    fractionation facilities to support producers’ growing rich-gas production
    in the Marcellus Shale. By the second 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 announced plans to install a 38,000 Bbl/d
    de-ethanization facility at the Sherwood complex in Doddridge County, West
    Virginia.
  *In August 2013, the Partnership announced an expansion of the Mobley
    complex in Wetzel County, West Virginia to support EQT Corporation (NYSE:
    EQT) and other producers’ rich-gas development in the Marcellus Shale. The
    new 200 million cubic feet per day (MMcf/d) processing facility is
    currently scheduled to begin operations in the fourth quarter of 2014.
    Upon completion of this facility, the Mobley complex will have processing
    capacity of 720 MMcf/d.
  *In November 2013, the Partnership announced an expansion of the Sherwood
    complex in Doddridge County, West Virginia to support Antero Resources
    Corporation’s (NYSE: AR) highly prospective rich-gas Marcellus Shale
    acreage. The Partnership will construct Sherwood V, a new 200 MMcf/d
    processing facility that is scheduled to begin operations in the third
    quarter of 2014. Upon completion of this facility, the Sherwood complex
    will have processing capacity of 1 billion cubic feet per day (Bcf/d).
  *In November 2013, the Partnership announced the completion of Majorsville
    V, a new 200 MMcf/d processing plant at the Majorsville complex in
    Marshall County, West Virginia. Majorsville V supports growing rich-gas
    production from Chesapeake Energy Corporation (NYSE: CHK), and Statoil ASA
    (NYSE: STO) and increases the total processing capacity of the complex to
    670 MMcf/d.

Utica:

  *In August 2013, MarkWest Utica EMG announced plans to install a 38,000
    (Bbl/d) de-ethanization facility at the Seneca complex in Noble County,
    Ohio.
  *In August 2013, 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. The JV would develop a processing complex in Tuscarawas
    County, Ohio with an initial capacity of 200 MMcf/d and a 150,000 Bbl/d
    NGL pipeline to transport ethane and heavier natural gas liquids to JV
    fractionation facilities in Mt. Belvieu. In November 2013, MarkWest Utica
    EMG and Kinder Morgan announced a binding open season to solicit
    commitments for the NGL pipeline project.

  *In November 2013, MarkWest Utica EMG announced it commenced operations of
    Seneca I, a 200 MMcf/d cryogenic processing facility in Noble County,
    Ohio. Seneca I is supported by long-term fee-based agreements with Antero
    Resources Corporation, Gulfport Energy Corporation (NASDAQ: GPOR), Rex
    Energy Corporation (NASDAQ: REXX), PDC Energy (NASDAQ: PDCE) and others.

Southwest:

  *In August 2013, the Partnership announced the connection of gathering
    assets acquired from a wholly owned subsidiary of Chesapeake Energy to the
    Partnership’s existing Anadarko Basin gathering system. Connecting these
    gathering systems has allowed the Partnership to begin processing
    approximately 50 MMcf/d of additional rich-gas production at its Arapaho
    processing complex.

Capital Markets

  *During the third quarter of 2013, the Partnership offered 10.4 million
    units and received net proceeds of approximately $691.5 million.
  *During the third quarter of 2013, the Partnership completed the $600
    million and $400 million continuous offering programs launched in the
    fourth quarter of 2012 and third quarter of 2013, respectively. In
    addition, during the third quarter of 2013, the Partnership launched a $1
    billion continuous offering program under which the Partnership has issued
    0.9 million units and received $59.5 million of net proceeds as of the end
    of the third quarter of 2013.

FINANCIAL RESULTS

Balance Sheet

  *As of September 30, 2013, the Partnership had $326.6 million of cash and
    cash equivalents in wholly owned subsidiaries and $1.19 billion of
    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 September 30, 2013, was $181.9 million, an increase of $37.9
    million when compared to segment operating income of $144.0 million over
    the same period in 2012. This increase was primarily attributable to
    higher processing volumes. Processed volumes continued to increase in the
    third quarter of 2013, growing approximately 57 percent when compared to
    the third quarter of 2012, primarily due to the Partnership’s Marcellus
    and Southwest segments. While the Partnership continued to increase its
    operating income and volumes, it experienced several operational
    constraints during the third quarter of 2013. Due to these considerations,
    operating income was lower than expected by approximately $14 million.

  *The Partnership’s producer customers’ highly successful drilling programs
    throughout the Marcellus and Utica have resulted in a dramatic increase in
    natural gas liquids (NGLs) production. As a result, liquids production
    throughout the region has surpassed the capacity of the Partnership’s
    60,000 Bbl/d Houston fractionator in Washington County, Pennsylvania and
    its 24,000 Bbl/d Siloam fractionator in South Shore, Kentucky. In January
    2014, the Partnership and MarkWest Utica EMG, a joint venture between the
    Partnership and the Energy & Minerals Group, expect to commence operations
    of the Hopedale fractionation and marketing complex in Harrison County,
    Ohio. The complex will be connected via an NGL pipeline to the
    Partnership’s Marcellus infrastructure and will alleviate the current
    constraints associated with the production of purity products. However, in
    the interim the Partnership has made arrangements for continued
    fractionation services for its producer customer’s excess volumes through
    third-party facilities. As part of these arrangements, the Partnership has
    incurred, and until the end of the year, will continue to incur additional
    transportation costs and realize lower fractionation income.
  *In July, the Partnership placed into operation its first large-scale
    de-ethanization facility in the Northeast capable of producing purity
    ethane. Since startup, the facility has provided line-fill for Mariner
    West, an ethane purity products pipeline project being developed by
    Sunoco, which will deliver Marcellus purity ethane to Sarnia, Ontario,
    Canada. Delays of the Sunoco project have occurred, and as a result, the
    Partnership has realized lower income during this period. The Mariner West
    pipeline is expected to become operational during the fourth quarter of
    2013. Together with the completion of the ATEX pipeline project and
    Mariner East project, the Partnership anticipates growing utilization of
    its de-ethanization facilities.
  *A landslide in August impacted a portion of the Partnership’s NGL pipeline
    in a remote area of Wetzel County, West Virginia causing a line break. As
    a result of this incident, the Mobley complex was offline for
    approximately two months as necessary repairs and remediation were
    completed. During this period the Partnership’s Sherwood complex in
    Doddridge County, West Virginia also experienced partially curtailed
    processing volumes; however, NGLs produced at the Sherwood complex were
    delivered by truck for fractionation. During mid-October, the Partnership
    safely resumed operations of the pipeline and the Mobley and Sherwood
    complexes have returned to full operation.

The Partnership has changed the Liberty segment name. Starting with the third
quarter of 2013 financial and operating results, the Liberty segment will now
be reported as the Marcellus segment. 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
    losses on commodity derivative instruments. Realized losses on commodity
    derivative instruments were $5.3 million in the third quarter of 2013 and
    $8.4 million in the third quarter of 2012.

Capital Expenditures

  *For the three months ended September 30, 2013, the Partnership’s portion
    of capital expenditures was $650.5 million.

2013 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2013, the Partnership forecasts DCF in a range of $475 million to $485
million based on its current forecast of operational volumes, expected impact
of short-term operational constraints and prices for crude oil, natural gas,
natural gas liquids and derivative instruments currently outstanding.

The Partnership’s portion of growth capital expenditures for 2013 has
increased to a range of $2.0 billion to $2.3 billion primarily due to the
addition of announced expansion projects and an acceleration of spending on
other projects in the Marcellus and Utica segments. These expenditures do not
include the Granite Wash Acquisition or the divestiture of the high-pressure
gathering system in the Marcellus Shale during the second quarter 2013.
Maintenance capital is forecasted at approximately $20 million.

2014 DCF AND GROWTH CAPITAL EXPENDITURE FORECAST

For 2014, the Partnership forecasts DCF in a range of $600 million to $690
million based on its current forecast of operational volumes and prices for
crude oil, natural gas, natural gas liquids and derivative instruments
currently outstanding. A commodity price sensitivity analysis for forecasted
2014 DCF is provided within the tables of this press release.

The Partnership’s portion of growth capital expenditures for 2014 is
forecasted in a range of $1.8 billion to $2.3 billion. Maintenance capital is
forecasted at approximately $25 million.

CONFERENCE CALL

The Partnership will host a conference call and webcast on Wednesday, November
13, 2013, at 12:00 p.m. Eastern Time to review its third 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
(800) 926-7934 (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 September 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 September    Nine months ended September 30,
                  30,
Statement of      2013            2012            2013             2012
Operations Data
Revenue:
Revenue           $ 450,834       $ 316,976       $ 1,219,713      $ 1,019,709
Derivative         (30,318   )    (36,400   )    (10,804    )    50,952     
(loss) gain
Total revenue      420,516       280,576       1,208,909      1,070,661  
                                                                   
Operating
expenses:
Purchased           191,672         119,369         499,588          386,655
product costs
Derivative loss
(gain) related      20,234          11,643          (10,902    )     (21,136    )
to purchased
product costs
Facility            77,542          52,883          199,849          149,438
expenses
Derivative loss
related to          2,332           4,028           2,800            1,136
facility
expenses
Selling,
general and         26,647          21,723          77,388           68,471
administrative
expenses
Depreciation        76,323          46,554          215,902          127,472
Amortization of
intangible          16,003          14,988          47,925           38,280
assets
Loss (gain) on
sale or
disposal of         1,840           655             (35,758    )     2,983
property, plant
and equipment
Accretion of
asset              160           140           669            536        
retirement
obligations
Total operating    412,753       271,983       997,461        753,835    
expenses
                                                                   
Income from         7,763           8,593           211,448          316,826
operations
                                                                   
Other income
(expense):
Equity in
earnings from       896             706             1,561            2,254
unconsolidated
affiliates
Interest income     27              64              238              295
Interest            (38,889   )     (30,621   )     (114,180   )     (86,855    )
expense
Amortization of
deferred
financing costs
and discount (a     (1,584    )     (1,428    )     (5,198     )     (3,943     )
component of
interest
expense)
Loss on
redemption of       -               -               (38,455    )     -
debt
Miscellaneous      1,504         1             1,510          63         
income, net
(Loss) income
before              (30,283   )     (22,685   )     56,924           228,640
provision for
income tax
                                                                   
Provision for
income tax
(benefit)
expense:
Current             (2,344    )     (17,948   )     (10,503    )     2,202
Deferred           (7,912    )    10,528        23,087         39,396     
Total provision    (10,256   )    (7,420    )    12,584         41,598     
for income tax
                                                                   
Net (loss)          (20,027   )     (15,265   )     44,340           187,042
income
                                                                   
Net (loss)
income
attributable to     (3,577    )     925             297              1,546
non-controlling
interest
                                                                
Net (loss)
income
attributable to   $ (23,604   )   $ (14,340   )   $ 44,637        $ 188,588    
the
Partnership's
unitholders
                                                                   
Net (loss)
income
attributable to
the
Partnership's
common
unitholders per
common unit:
Basic             $ (0.17     )   $ (0.13     )   $ 0.32          $ 1.77       
Diluted           $ (0.17     )   $ (0.13     )   $ 0.29          $ 1.49       
                                                                   
Weighted
average number
of outstanding
common units:
Basic              142,352       113,994       134,115        105,916    
Diluted            142,352       113,994       153,455        126,595    
                                                                   
Cash Flow Data
Net cash flow
provided by
(used in):
Operating         $ 153,063       $ 132,163       $ 330,659        $ 385,784
activities
Investing         $ (751,286  )   $ (658,635  )   $ (2,186,307 )   $ (1,745,749 )
activities
Financing         $ 571,822       $ 816,452       $ 1,838,045      $ 1,657,986
activities
                                                                   
Other Financial
Data
Distributable     $ 117,897       $ 104,289       $ 356,113        $ 304,950
cash flow
Adjusted EBITDA   $ 153,936       $ 115,531       $ 450,477        $ 390,515
                                                                   
                                                                   
Balance Sheet     September 30,   December 31,
Data              2013            2012
Working capital   $ (263,896  )   $ (84,512   )
Total assets        8,917,716       6,728,362
Total debt          3,022,887       2,523,051
Total equity        4,150,443       3,111,398
                                                                   

                                                                
MarkWest Energy Partners, L.P.
Operating Statistics
                                                                      
                               Three months ended       Nine months ended
                               September 30,            September 30,
                               2013          2012       2013          2012
Marcellus
Gathering system throughput    563,200       444,700    617,200       373,700
(Mcf/d) (1)
Natural gas processed          1,137,400     479,400    1,000,900     424,300
(Mcf/d)
NGLs fractionated (Bbl/d)      48,200        22,300     44,500        20,700
NGL sales (gallons, in         229,900       90,800     536,100       264,200
thousands) (2)
                                                                      
Utica (3)
Gathering system throughput    85,100        N/A        47,100        N/A
(Mcf/d)
Natural gas processed          131,100       N/A        62,200        N/A
(Mcf/d)
                                                                      
Northeast
Natural gas processed          297,800       318,500    298,900       322,800
(Mcf/d)
NGLs fractionated (Bbl/d)      21,500        16,500     18,900        16,800
                                                                      
Keep-whole sales (gallons,     28,200        23,200     92,600        96,500
in thousands)
Percent-of-proceeds sales      34,700        33,700     101,800       103,500
(gallons, in thousands)
Total NGL sales (gallons, in   62,900        56,900     194,400       200,000
thousands) (4)
                                                                      
Crude oil transported for a    9,400         8,700      9,800         9,100
fee (Bbl/d)
                                                                      
Southwest
East Texas gathering systems   494,300       471,200    505,000       440,700
throughput (Mcf/d)
East Texas natural gas         345,400       270,200    354,200       260,400
processed (Mcf/d)
East Texas NGL sales           78,500        67,800     249,300       199,300
(gallons, in thousands) (5)
                                                                      
Western Oklahoma gathering
system throughput (Mcf/d)      262,000       227,900    228,400       247,300
(6)
Western Oklahoma natural gas   218,500       209,600    198,400       210,800
processed (Mcf/d)
Western Oklahoma NGL sales     64,400        50,900     162,200       169,900
(gallons, in thousands)
                                                                      
Southeast Oklahoma gathering   444,200       484,400    459,500       496,200
system throughput (Mcf/d)
Southeast Oklahoma natural     156,700       128,600    156,100       116,700
gas processed (Mcf/d) (7)
Southeast Oklahoma NGL sales   44,000        46,700     137,300       121,000
(gallons, in thousands)
                                                                      
Other Southwest gathering
system throughput (Mcf/d)      33,000        23,600     31,200        25,000
(8)
                                                                      
Gulf Coast refinery off-gas    117,100       123,800    110,100       120,000
processed (Mcf/d)
Gulf Coast liquids             21,400        23,800     20,300        23,000
fractionated (Bbl/d)
Gulf Coast NGL sales
(gallons excluding hydrogen,   82,800        92,100     232,500       264,400
in thousands)
                                                                      

(1)   Gathered volumes reflect the first full quarter following the sale of
        the Sherwood gathering assets in the 2nd quarter of 2013.
(2)     Includes sale of all purity products fractionated at the Marcellus
        facilities and the sale of all unfractionated NGLs.
(3)     Utica operations began in August 2012.
        Represents sales at the Siloam fractionator. The total sales exclude
        approximately 21,000,000 gallons, 595,000 gallons, 27,900,000 gallons,
(4)     and 975,000 gallons sold by the Northeast on behalf of Marcellus for
        the three months and nine months ended September 30, 2013 and 2012,
        respectively. These volumes are included as part of NGLs sold at
        Marcellus.
        Includes approximately 1,390,000 gallons and 13,700,000 gallons
(5)     processed in conjunction with take in kind contracts for the three and
        nine months ended September 30, 2013, respectively.
        Includes natural gas gathered in Western Oklahoma and from the Granite
(6)     Wash formation in the Texas Panhandle as management considers this one
        integrated area of operations.
(7)     The natural gas processing in Southeast Oklahoma is outsourced to
        Centrahoma or other third-party processors.
(8)     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 September   Marcellus      Utica          Northeast     Southwest     Total
30, 2013
Segment revenue   $ 147,290      $ 8,373        $ 48,829      $ 247,885     $ 452,377
                                                                            
Operating
expenses:
Purchased           36,995         -              15,330        139,347       191,672
product costs
Facility           29,621       9,858        7,359       32,559      79,397    
expenses
Total operating
expenses before
items not           66,616         9,858          22,689        171,906       271,069
allocated to
segments
                                                                            
Portion of
operating
(loss) income      -            (599     )    -           40          (559      )
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 80,674      $ (886     )   $ 26,140     $ 75,939     $ 181,867   
not allocated
to segments
                                                                            
                                                                            
Three months
ended September   Marcellus      Utica          Northeast     Southwest     Total
30, 2012
Segment revenue   $ 78,707       $ 145          $ 39,987      $ 199,394     $ 318,233
                                                                            
Operating
expenses:
Purchased           16,203         -              11,054        92,112        119,369
product costs
Facility           18,933       1,308        6,267       28,870      55,378    
expenses
Total operating
expenses before
items not           35,136         1,308          17,321        120,982       174,747
allocated to
segments
                                                                            
Portion of
operating
(loss) income      -            (627     )    -           67          (560      )
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 43,571      $ (536     )   $ 22,666     $ 78,345     $ 144,046   
not allocated
to segments
                                                                            
                                                                            
                  Three months ended
                  September 30,
                  2013           2012
                                                                            
Operating
income before
items not         $ 181,867      $ 144,046
allocated to
segments
Portion of
operating loss
attributable to     (559     )     (560     )
non-controlling
interests
Derivative loss
not allocated       (52,884  )     (52,071  )
to segments
Revenue
deferral            (1,543   )     (1,257   )
adjustment and
other
Compensation
expense
included in
facility            (833     )     (193     )
expenses not
allocated to
segments
Facility
expenses            2,688          2,688
adjustments
Selling,
general and         (26,647  )     (21,723  )
administrative
expenses
Depreciation        (76,323  )     (46,554  )
Amortization of
intangible          (16,003  )     (14,988  )
assets
Loss on
disposal of         (1,840   )     (655     )
property, plant
and equipment
Accretion of
asset              (160     )    (140     )
retirement
obligations
Income from         7,763          8,593
operations
Other income
(expense):
Earnings from
unconsolidated      896            706
affiliates
Interest income     27             64
Interest            (38,889  )     (30,621  )
expense
Amortization of
deferred
financing costs
and discount (a     (1,584   )     (1,428   )
component of
interest
expense)
Miscellaneous      1,504        1        
income, net
Income before
provision for     $ (30,283  )   $ (22,685  )
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
ended September   Marcellus      Utica          Northeast     Southwest     Total
30, 2013
Segment revenue   $ 375,844      $ 12,590       $ 151,530     $ 684,093     $ 1,224,057
                                                                            
Operating
expenses:
Purchased           72,781         -              50,118        376,689       499,588
product costs
Facility           74,529       20,232       20,538      91,027      206,326   
expenses
Total operating
expenses before
items not           147,310        20,232         70,656        467,716       705,914
allocated to
segments
                                                                            
Portion of
operating
(loss) income      -            (3,081   )    -           157         (2,924    )
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 228,534     $ (4,561   )   $ 80,874     $ 216,220    $ 521,067   
not allocated
to segments
                                                                            
                                                                            
Nine months
ended September   Marcellus      Utica          Northeast     Southwest     Total
30, 2012
Segment revenue   $ 213,761      $ 145          $ 168,956     $ 641,321     $ 1,024,183
                                                                            
Operating
expenses:
Purchased           48,856         -              49,662        288,137       386,655
product costs
Facility           44,544       1,591        17,577      92,964      156,676   
expenses
Total operating
expenses before
items not           93,400         1,591          67,239        381,101       543,331
allocated to
segments
                                                                            
Portion of
operating
(loss) income      -            (740     )    -           98          (642      )
attributable to
non-controlling
interests
Operating
income (loss)
before items      $ 120,361     $ (706     )   $ 101,717    $ 260,122    $ 481,494   
not allocated
to segments
                                                                            
                                                                            
                  Nine months ended September
                  30,
                  2013           2012
                                                                            
Operating
income before
items not         $ 521,067      $ 481,494
allocated to
segments
Portion of
operating loss
attributable to     (2,924   )     (642     )
non-controlling
interests
Derivative
(loss) gain not     (2,702   )     70,952
allocated to
segments
Revenue
deferral            (4,344   )     (4,474   )
adjustment and
other
Compensation
expense
included in
facility            (1,587   )     (826     )
expenses not
allocated to
segments
Facility
expenses            8,064          8,064
adjustments
Selling,
general and         (77,388  )     (68,471  )
administrative
expenses
Depreciation        (215,902 )     (127,472 )
Amortization of
intangible          (47,925  )     (38,280  )
assets
Gain (loss) on
disposal of         35,758         (2,983   )
property, plant
and equipment
Accretion of
asset              (669     )    (536     )
retirement
obligations
Income from         211,448       316,826
operations
Other income
(expense):
Earnings from
unconsolidated      1,561          2,254
affiliates
Interest income     238            295
Interest            (114,180 )     (86,855  )
expense
Amortization of
deferred
financing costs
and discount (a     (5,198   )     (3,943   )
component of
interest
expense)
Loss on
redemption of       (38,455  )     -
debt
Miscellaneous      1,510        63       
income, net
Income before
provision for     $ 56,924      $ 228,640  
income tax
                                                                            

                                                           
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)
                                                                 
                   Three months ended            Nine months ended September
                   September 30,                 30,
                   2013            2012          2013            2012
                                                              
Net income         $  (20,027  )   $ (15,265 )   $ 44,340        $ 187,042
Depreciation,
amortization and
other non-cash        92,564         61,761        264,730         166,522
operating
expenses
Loss (gain) on
sale and or
disposal of           1,840          655           (32,711   )     2,983
assets, net of
tax
Loss on
redemption of         -              -             36,178          -
debt, net of tax
benefit
Amortization of
deferred              1,584          1,428         5,198           3,943
financing costs
and discount
Non-cash
earnings from         (896     )     (706    )     (1,561    )     (2,254    )
unconsolidated
affiliates
Distributions
from                  2,224          2,058         4,952           6,624
unconsolidated
affiliates
Non-cash
compensation          1,924          981           5,464           6,271
expense
Non-cash
derivative            47,542         43,712        1,222           (101,815  )
activity
Provision for
income tax -          (7,912   )     10,528        23,087          39,396
deferred
Cash adjustment
for
non-controlling       1,183          787           4,672           1,391
interest of
consolidated
subsidiaries
Revenue deferral      1,754          1,635         5,164           5,604
adjustment
Other                 2,887          549           7,753           3,067
Maintenance
capital
expenditures,        (6,770   )    (3,834  )    (12,375   )    (13,824   )
net of joint
venture partner
contributions
Distributable      $  117,897     $ 104,289    $ 356,113      $ 304,950   
cash flow
                                                                 
Maintenance
capital            $  6,770        $ 3,834       $ 12,375        $ 13,824
expenditures
Growth capital       734,865      654,891     2,164,344     1,225,881 
expenditures
Total capital         741,635        658,725       2,176,719       1,239,705
expenditures
Acquisitions,
net of cash          -            -           225,210       506,797   
acquired
Total capital
expenditures and      741,635        658,725       2,401,929       1,746,502
acquisitions
Joint venture
partner              (91,163  )    (55,000 )    (716,982  )    (55,000   )
contributions
Total capital
expenditures and   $  650,472     $ 603,725    $ 1,684,947    $ 1,691,502 
acquisitions,
net
                                                                 
Distributable      $  117,897      $ 104,289     $ 356,113       $ 304,950
cash flow
Maintenance
capital
expenditures,         6,770          3,834         12,375          13,824
net of joint
venture partner
contributions
Changes in
receivables and       (6,969   )     (85,658 )     (74,470   )     26,296
other assets
Changes in
accounts
payable, accrued      38,504         110,658       48,557          45,468
liabilities and
other long-term
liabilities
Cash adjustment
for
non-controlling       (1,183   )     (787    )     (4,672    )     (1,391    )
interest of
consolidated
subsidiaries
Other                (1,956   )    (173    )    (7,244    )    (3,363    )
Net cash
provided by        $  153,063     $ 132,163    $ 330,659      $ 385,784   
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
                  30,                               September 30,
                  2013              2012            2013          2012
                                                                  
Net income        $  (20,027  )     $  (15,265  )   $ 44,340      $ 187,042
Non-cash
compensation         1,924             981            5,464         6,271
expense
Non-cash
derivative           47,542            43,712         1,222         (101,815 )
activity
Interest             38,356            29,882         112,988       84,260
expense (1)
Depreciation,
amortization
and other            92,564            61,761         264,730       166,522
non-cash
operating
expenses
Loss (gain) on
sale and or          1,840             655            (35,758 )     2,983
disposal of
assets
Loss on
redemption of        -                 -              38,455        -
debt
Provision for        (10,256  )        (7,420   )     12,584        41,598
income tax
Adjustment for
cash flow from       1,328             1,352          3,391         4,370
unconsolidated
affiliate
Other               665             (127     )    3,061       (716     )
Adjusted EBITDA   $  153,936       $  115,531     $ 450,477    $ 390,515  
                                                                  

(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 2014 and forecasted crude oil and natural gas prices
for 2014. 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 2014.
b. NGL-to-crude oil ratio at 40% for 2014.
c. NGL-to-crude oil ratio at 30% for 2014.

The analysis further assumes derivative instruments outstanding as of November
5, 2013, and production volumes estimated through December31, 2014. The range
of stated hypothetical changes in commodity prices considers current and
historic market performance.


Estimated Range of 2014 DCF
                                                      
                               Natural Gas Price (Henry Hub)
                                                           
Crude Oil Price  NGL-to-Crude    $3.00   $3.50   $4.00   $4.50
(WTI)             Oil ratio (1)
$110              50% of WTI      $ 740   $ 737   $ 733   $ 730
                  40% of WTI      $ 684   $ 681   $ 677   $ 674
                30% of WTI      $ 634   $ 630   $ 627   $ 623
$100              50% of WTI      $ 710   $ 706   $ 703   $ 699
                  40% of WTI      $ 661   $ 658   $ 654   $ 650
                30% of WTI      $ 609   $ 605   $ 602   $ 598
$90               50% of WTI      $ 678   $ 675   $ 671   $ 668
                  40% of WTI      $ 644   $ 641   $ 637   $ 634
                30% of WTI      $ 589   $ 585   $ 582   $ 578
$80               50% of WTI      $ 649   $ 645   $ 642   $ 638
                  40% of WTI      $ 613   $ 609   $ 606   $ 602
                30% of WTI      $ 572   $ 569   $ 565   $ 560

      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
 
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