MarkWest Energy Partners Reports Fourth Quarter and Full Year Financial Results

  MarkWest Energy Partners Reports Fourth Quarter and Full Year Financial
  Results

  *Increased total processing capacity in the Marcellus and Utica Shales to
    over 2.8 Bcf/d with the completion of five major gas processing facilities
    totaling 1 Bcf/d in the past five months
  *Placed into service the Hopedale fractionation and marketing complex in
    the Utica Shale, increasing current fractionation capacity for propane and
    heavier purity products in the Northeast to over 140,000 Bbl/d
  *Announced the development of 200 MMcf/d of additional processing capacity
    at the Seneca complex in the Utica Shale to support Antero Resources
  *Placed into service the Buffalo Creek processing plant, a 200 MMcf/d
    cryogenic processing facility in the Anadarko Basin, that is supported by
    long-term fee-based agreements with Chesapeake Energy
  *The Partnership has 19 major processing and fractionation facilities under
    construction in the Northeast
  *Fee-based net operating margin increased from 53 percent to 65 percent
    when compared to the fourth quarter of 2012

Business Wire

DENVER -- February 26, 2014

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 $127.2 million for the three months ended
December 31, 2013, and $483.4 million for the year ended December 31, 2013.
DCF for the three months and year ended December 31, 2013 represents
distribution coverage of 94 percent and 99 percent, respectively. The fourth
quarter distribution of $135.9 million, or $0.86 per common unit, was paid to
unitholders on February 14, 2014. The fourth quarter 2013 distribution
represents an increase of $0.01 per common unit or 1.2 percent over the third
quarter 2013 distribution and an increase of $0.04 per common unit or 4.9
percent compared to the fourth quarter 2012 distribution. As a Master Limited
Partnership, cash distributions to common unitholders are largely determined
based on DCF. A reconciliation of DCF to net income, the most directly
comparable GAAP financial measure, is provided within the financial tables of
this press release.

The Partnership reported Adjusted EBITDA of $155.5 million for the three
months ended December 31, 2013 and $606.0 million for the year ended December
31, 2013, as compared to $138.0 million and $528.5 million for the three
months and year ended December 31, 2012. The Partnership believes the
presentation of Adjusted EBITDA provides useful information because it is
commonly used by investors in Master Limited Partnerships to assess financial
performance and operating results of ongoing business operations. A
reconciliation of Adjusted EBITDA to net income, the most directly comparable
GAAP financial measure, is provided within the financial tables of this press
release.

The Partnership reported (loss) income before provision for income tax for the
three months and year ended December 31, 2013, of $(3.8) million and $53.1
million, respectively. (Loss) income before provision for income tax includes
non-cash loss associated with the change in fair value of derivative
instruments of $14.4 million and $15.6 million for the respective three months
and year ended December 31, 2013, a gain of $0.8 million and $39.7 million
related to the divestiture of gathering assets in the Marcellus Shale for the
respective three months and year ended December 31, 2013, and a loss
associated with the redemption of debt of $38.5 million for the year ended
December 31, 2013. Excluding these items, income before provision for income
tax for the three months and year ended December 31, 2013 would have been $9.8
million and $67.5 million, respectively.

“We are very pleased to close 2013 with the completion of major infrastructure
projects that are critical to the development of the Marcellus and Utica
Shales,” stated Frank Semple, Chairman, President and Chief Executive Officer.
“Our producers’ ongoing success and expanding development plans continue to
provide us with exceptional future growth opportunities. We are committed to
delivering another year of strong financial results, operational excellence
and best of class customer service in many of America’s most exciting resource
plays.”

BUSINESS HIGHLIGHTS

Marcellus:

  *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 million
    cubic feet per day (MMcf/d) processing facility that is scheduled to begin
    operations in the third quarter of 2014.
  *In November 2013, the Partnership completed Majorsville V, a 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.
  *In November 2013, the Partnership completed Sherwood III, a 200 MMcf/d
    processing plant at the Sherwood complex. Sherwood III supports Antero
    Resources Corporation and increases the total processing capacity of the
    complex to 600 MMcf/d.
  *In December 2013, the Partnership completed Mobley III, a 200 MMcf/d
    processing plant at the Mobley complex in Wetzel County, West Virginia.
    Mobley III supports rapidly growing rich-gas production from EQT
    Corporation (NYSE: EQT) and Magnum Hunter Resources Corporation (NYSE:
    MHR) and increases the total processing capacity of the complex to 520
    MMcf/d.
  *In December 2013, the Partnership completed the 38,000 barrels per day
    (Bbl/d) de-ethanization unit at the Majorsville complex. The new
    de-ethanizer doubles the Partnership’s total purity ethane production
    capacity in the Marcellus Shale to 76,000 Bbl/d and provides producers
    with the ability to consistently meet residue gas quality specifications
    and deliver downstream ethane pipeline commitments.
  *In December 2013, the Partnership completed the Liberty Ethane Pipeline.
    The Liberty Ethane Pipeline transports purity ethane produced at the
    Majorsville complex to the Houston complex in Washington County,
    Pennsylvania. Once delivered to the Houston complex, the purity ethane has
    direct access to multiple, major ethane takeaway projects including,
    Mariner West and ATEX, which began operations in December, and Mariner
    East, which is scheduled to come online for ethane service in 2015.
  *In February 2014, the Partnership announced the development of a 40,000
    Bbl/d de-ethanization facility at the Mobley complex. The Mobley
    de-ethanizer will support purity ethane production for EQT Corporation,
    Magnum Hunter Resources Corporation and other producers. The new facility
    is scheduled to begin operations during the third quarter of 2015.

Utica:

  *In November 2013, MarkWest Utica EMG commenced operations at the Seneca
    complex in Noble County, Ohio. The Seneca complex currently consists of
    two cryogenic processing plants totaling 400 MMcf/d of capacity and 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.
  *In December 2013, the Partnership and The Energy & Minerals Group (EMG)
    executed definitive agreements with Gulfport Energy Corporation to provide
    condensate stabilization and logistics services in eastern Ohio. As part
    of these agreements, the Partnership and EMG formed Ohio Condensate
    Company, LLC, a new Joint Venture (JV) related to the development of
    industry-leading facilities and services to support the rapid growth of
    condensate production occurring in the Utica Shale. The JV will initially
    develop a 23,000 Bbl/d condensate stabilization facility in Harrison
    County, Ohio. The new facility is scheduled to commence operations in the
    third quarter of 2014 and will be co-located with condensate storage and
    logistics terminal, which will be constructed and operated by a subsidiary
    of Toledo International, Inc., Ohio-based Midwest Terminals.
  *In January 2014, MarkWest Utica EMG and the Partnership completed
    construction and commenced operations of the jointly-owned Hopedale
    fractionation and marketing complex (Hopedale complex) in Harrison County,
    Ohio. The Hopedale complex consists of a 60,000 Bbl/d propane and heavier
    purity products (C3+) fractionator, over 230,000 barrels of purity product
    storage, a 24-bay rail car loading facility with slots to accommodate 200
    rail cars, and truck loading and off loading facilities. The Hopedale
    complex is connected by NGL pipeline to MarkWest Utica EMG’s Cadiz
    processing complex in Harrison County, Ohio, to the Seneca processing
    complex in Noble County, Ohio and to its extensive NGL gathering network
    in the Marcellus Shale.
  *In January 2014, the Partnership commenced operations of a NGL pipeline
    connecting the Hopedale fractionation and marketing complex to the
    Partnership’s industry-leading NGL infrastructure in the Marcellus Shale.
    By integrating two industry-leading midstream systems, the Partnership has
    expanded the fractionation capacity for its Marcellus producers.
  *Today, MarkWest Utica EMG is announcing the expansion of the Seneca
    complex with a new 200 MMcf/d processing plant. The plant is anchored by a
    new agreement with Antero Resources Corporation supporting its expanding
    Utica development plans. The Seneca IV plant is scheduled to commence
    operations in the first quarter of 2015 and will expand total processing
    capacity of the complex to 800 MMcf/d.

Southwest:

  *In February 2014, the Partnership announced the commencement of the 200
    MMcf/d Buffalo Creek processing facility in Beckham County, Oklahoma, and
    associated gas gathering and compression assets in the Granite Wash. The
    new facility is supported by long-term fee-based agreements with
    Chesapeake Energy Corporation, which include a 130,000 acre dedication
    throughout the area. The completion of the Buffalo Creek plant increases
    the Partnership’s total processing capacity in the Anadarko Basin to 435
    MMcf/d at two major complexes.

Capital Markets

  *During the fourth quarter of 2013, the Partnership offered 10.0 million
    units and received net proceeds of approximately $658.2 million under the
    $1 billion continuous offering program launched in the third quarter of
    2013.

FINANCIAL RESULTS

Balance Sheet

  *As of December 31, 2013, the Partnership had $80.0 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 December 31, 2013, was $185.1 million, an increase of $23.1
    million when compared to segment operating income of $162.0 million over
    the same period in 2012. This increase was primarily attributable to
    higher processing volumes. Processed volumes continued to increase in the
    fourth quarter of 2013, growing approximately 51 percent when compared to
    the fourth 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 second half of 2013. Due to these considerations,
    operating income was approximately $12.0 million lower than expected for
    the three months ended December 31, 2013, and approximately $24.1 million
    for the year ended December 31, 2013. The operational constraints included
    increased costs related to the transportation of producer natural gas
    liquids in excess of our fractionation capacity to third party
    fractionation facilities, delays related to the completion of Sunoco
    Logistics Partners, L.P.’s (NYSE: SXL) Mariner West purity ethane pipeline
    and an NGL line break that took the Partnership’s Mobley complex offline
    and curtailed processing volumes at the Partnership’s Sherwood complex for
    approximately two months. As of January 2014, all operational constraints
    have been resolved.

    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 $8.7 million in the fourth quarter of 2013 and
    $2.1 million in the fourth quarter of 2012.

Capital Expenditures

  *For the three months ended December 31, 2013, the Partnership’s portion of
    capital expenditures was $870.2 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. The Partnership has become less sensitive to changes in
commodity prices as a result of fee-based margin increasing significantly. For
the full year 2014, the Partnership estimates that net operating margin will
be over 70 percent fee-based. In addition, the Partnership has hedged
approximately 60 percent of its forecasted 2014 NGL exposure on a volumetric
basis, 90 percent of these with direct product hedges. An updated sensitivity
analysis for forecasted 2014 DCF based on changes in composite NGL prices and
changes in volume assumptions 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 on Thursday, February 27, 2014, at
12:00 p.m. Eastern Time to review its fourth quarter and full year 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. Prior to the conference call, the Partnership will post
a fourth quarter earnings call presentation to its website. To access the
conference call and presentation, 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 Partnership’s website or by dialing (866)
448-4799 (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, 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 December    Twelve months ended December
                    31,                             31,
Statement of        2013           2012            2013            2012
Operations Data
Revenue:
Revenue             $ 467,372       $ 363,570       $ 1,687,085      $ 1,383,279
Derivative           (13,834   )    5,583         (24,638    )    56,535     
(loss) gain
Total revenue        453,538       369,153       1,662,447      1,439,814  
                                                                     
Operating
expenses:
Purchased             191,577         143,673         691,165          530,328
product costs
Derivative loss
(gain) related        9,165           7,174           (1,737     )     (13,962    )
to purchased
product costs
Facility              91,220          57,422          291,069          206,861
expenses
Derivative loss
related to            69              235             2,869            1,371
facility
expenses
Selling,
general and           24,161          24,973          101,549          93,444
administrative
expenses
Depreciation          83,982          55,778          299,884          183,250
Amortization of
intangible            16,719          15,040          64,644           53,320
assets
Loss (gain) on
sale or
disposal of           1,995           3,271           (33,763    )     6,254
property, plant
and equipment
Accretion of
asset                155           137           824            672        
retirement
obligations
Total operating      419,043       307,703       1,416,504      1,061,538  
expenses
                                                                     
Income from           34,495          61,450          245,943          378,276
operations
                                                                     
Other (expense)
income:
(Loss) earnings
from                  (139      )     74              1,422            2,328
unconsolidated
affiliates
Interest income       24              124             262              419
Interest              (37,671   )     (33,336   )     (151,851   )     (120,191   )
expense
Amortization of
deferred
financing costs
and discount (a       (1,528    )     (1,658    )     (6,726     )     (5,601     )
component of
interest
expense)
Loss on
redemption of         -               -               (38,455    )     -
debt
Miscellaneous
income               1,009         (1        )    2,519          62         
(expense), net
(Loss) income
before                (3,810    )     26,653          53,114           255,293
provision for
income tax
                                                                     
Provision for
income tax
(benefit)
expense:
Current               (705      )     (4,568    )     (11,208    )     (2,366     )
Deferred             790           1,298         23,877         40,694     
Total provision      85            (3,270    )    12,669         38,328     
for income tax
                                                                     
Net (loss)            (3,895    )     29,923          40,445           216,965
income
                                                                     
Net (loss)
income
attributable to       (2,665    )     1,891           (2,368     )     3,437
non-controlling
interest
                                                                  
Net (loss)
income
attributable to     $ (6,560    )   $ 31,814       $ 38,077        $ 220,402    
the
Partnership's
unitholders
                                                                     
Net (loss)
income
attributable to
the
Partnership's
common
unitholders per
common unit:
Basic               $ (0.05     )   $ 0.26         $ 0.26          $ 1.98       
Diluted             $ (0.05     )   $ 0.22         $ 0.24          $ 1.69       
                                                                     
Weighted
average number
of outstanding
common units:
Basic                151,153       122,079       138,409        109,979    
Diluted              151,153       142,720       160,443        130,648    
                                                                     
Cash Flow Data
Net cash flow
provided by
(used in):
Operating           $ 104,991       $ 106,229       $ 435,650        $ 492,013
activities
Investing           $ (876,255  )   $ (726,339  )   $ (3,062,562 )   $ (2,472,088 )
activities
Financing           $ 528,416       $ 553,513       $ 2,366,461      $ 2,211,499
activities
                                                                     
Other Financial
Data
Distributable       $ 127,242       $ 111,774       $ 483,355        $ 417,086
cash flow
Adjusted EBITDA     $ 155,320       $ 137,952       $ 605,797        $ 528,467
                                                                     
                                                                     
Balance Sheet       December 31,    December 31,
Data                2013            2012
Working capital     $ (353,273  )   $ (84,512   )
Total assets        $ 9,396,423     $ 6,728,362
Total debt          $ 3,023,071     $ 2,523,051
Total equity        $ 4,798,133     $ 3,111,398



MarkWest Energy Partners, L.P.
Operating Statistics

                             Three months ended      Twelve months ended
                               December 31,             December 31,
                               2013         2012       2013         2012
Marcellus
Gathering system               580,700       587,600    549,500       425,000
throughput (Mcf/d) (1)
Natural gas processed          1,401,700     696,000    1,101,900     496,400
(Mcf/d)
NGLs fractionated (Bbl/d)      56,700        31,100     47,600        24,900
(2)
NGL sales (gallons, in         284,300       129,400    820,400       393,600
thousands) (3)
                                                                      
Utica (4)
Gathering system               107,800       6,400      62,400        5,000
throughput (Mcf/d)
Natural gas processed          166,200       5,000      88,400        4,200
(Mcf/d)
                                                                      
Northeast (5)
Natural gas processed          287,500       313,700    296,100       320,500
(Mcf/d)
NGLs fractionated (Bbl/d)      23,900        18,900     20,200        17,300
(6)
                                                                      
Keep-whole sales (gallons,     24,900        35,100     117,500       131,600
in thousands)
Percent-of-proceeds sales      32,600        36,200     134,300       139,700
(gallons, in thousands)
Total NGL sales (gallons,      57,500        71,300     251,800       271,300
in thousands) (7)
                                                                      
Crude oil transported for      9,500         9,900      9,700         9,300
a fee (Bbl/d)
                                                                      
Southwest
East Texas gathering           501,100       477,600    504,000       450,000
systems throughput (Mcf/d)
East Texas natural gas         357,700       302,000    355,100       270,800
processed (Mcf/d)
East Texas NGL sales
(gallons, in thousands)        85,100        76,500     334,400       275,800
(8)
                                                                      
Western Oklahoma gathering
system throughput (Mcf/d)      268,800       200,800    238,600       235,600
(9)
Western Oklahoma natural       215,000       193,800    202,600       206,500
gas processed (Mcf/d)
Western Oklahoma NGL sales     77,000        44,500     239,200       214,400
(gallons, in thousands)
                                                                      
Southeast Oklahoma
gathering system               405,100       463,100    443,700       487,900
throughput (Mcf/d)
Southeast Oklahoma natural     146,700       137,000    153,800       121,800
gas processed (Mcf/d) (10)
Southeast Oklahoma NGL
sales (gallons, in             22,300        42,400     159,600       163,300
thousands)
                                                                      
Other Southwest gathering
system throughput (Mcf/d)      46,500        22,300     35,000        24,300
(11)
                                                                      
Gulf Coast refinery            83,400        113,600    103,400       118,400
off-gas processed (Mcf/d)
Gulf Coast liquids             14,600        21,000     18,800        22,500
fractionated (Bbl/d)
Gulf Coast NGL sales
(gallons excluding             56,300        81,000     288,800       345,300
hydrogen, in thousands)

     
(1)    The 2013 volumes exclude Sherwood gathering as this system was sold to
       Summit Midstream in June 2013.
       Amount includes all NGLs that were produced at the Marcellus processing
       facilities and fractionated into purity products at our Marcellus
(2)    fractionation facility. Excludes 7,300 and 0 barrels per day of ethane
       fractionated for the three months ended December 31, 2013 and 2012,
       respectively, and 300 and 0 barrels per day of ethane fractionated for
       the twelve months ended December 31, 2013 and 2012, respectively.
       Includes sale of all purity products fractionated at the Marcellus
(3)    facilities and sale of all unfractionated NGLs. Also includes the sale
       of purity products fractionated and sold at the Siloam facilities on
       behalf of Marcellus customers.
(4)    Utica operations began in August 2012. The volumes reported for 2012
       are the average daily rate for the days of operation.
(5)    Includes throughput from the Kenova, Cobb, Boldman and Langley
       processing plants.
       Amount includes 8,200 and 1,400 barrels per day fractionated for the
(6)    three months ended December 31, 2013 and 2012, respectively, and 5,200
       and 400 barrels per day fractionated on behalf of Marcellus for the
       twelve months ended December 31, 2013 and 2012, respectively.
       Represents sales at the Siloam fractionator. The total sales exclude
       approximately 31,800,000 and 5,500,000 gallons sold by the Northeast on
       behalf of Marcellus for the three months ended December 31, 2013 and
(7)    2012, respectively, and approximately 59,700,000 and 6,500,000 gallons
       sold for the twelve months ended December 31, 2013 and 2012,
       respectively. These volumes are included as part of NGLs sold at
       Marcellus.
(8)    Includes approximately 14,420,000 gallons produced in conjunction with
       take in kind contracts for the year ended December 31, 2013.
       Includes natural gas gathered in Western Oklahoma and from the Granite
(9)    Wash formation in the Texas Panhandle as management considers this one
       integrated area of operations.
(10)   The natural gas processing in Southeast Oklahoma is outsourced to
       Centrahoma or other third party processors.
(11)   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 December      Marcellus       Utica           Northeast     Southwest       Total
31, 2013
Segment revenue     $ 151,229       $ 13,852        $  52,796     $ 251,333       $ 469,210
                                                                                  
Operating
expenses:
Purchased             27,481          -                15,074       149,022         191,577
product costs
Facility             34,252        14,849         7,887       36,085        93,073  
expenses
Total operating
expenses before
items not             61,733          14,849           22,961       185,107         284,650
allocated to
segments
                                                                                  
Portion of
operating loss
attributable to      -             (418    )       -           (136    )      (554    )
non-controlling
interests
Operating
income (loss)
before items        $ 89,496       $ (579    )     $  29,835     $ 66,362       $ 185,114 
not allocated
to segments
                                                                                  
                                                                                  
Three months
ended December      Marcellus       Utica           Northeast     Southwest       Total
31, 2012
Segment revenue     $ 106,106       $ 426           $  56,862     $ 201,637       $ 365,031
                                                                                  
Operating
expenses:
Purchased             25,168          -                18,740       99,765          143,673
product costs
Facility             21,281        2,377          6,529       29,727        59,914  
expenses
Total operating
expenses before
items not             46,449          2,377            25,269       129,492         203,587
allocated to
segments
                                                                                  
Portion of
operating
(loss) income        -             (619    )       -           78            (541    )
attributable to
non-controlling
interests
Operating
income (loss)
before items        $ 59,657       $ (1,332  )     $  31,593     $ 72,067       $ 161,985 
not allocated
to segments
                                                                                  
                                                                                  
                    Three months ended December
                    31,
                    2013            2012
                                                                                  
Operating
income before
items not           $ 185,114       $ 161,985
allocated to
segments
Portion of
operating loss
attributable to       (554    )       (541    )
non-controlling
interests
Derivative loss
not allocated         (23,068 )       (1,826  )
to segments
Revenue
deferral              (1,838  )       (1,461  )
adjustment and
other
Compensation
expense
included in
facility              (834    )       (196    )
expenses not
allocated to
segments
Facility
expenses              2,687           2,687
adjustments
Selling,
general and           (24,161 )       (24,973 )
administrative
expenses
Depreciation          (83,982 )       (55,778 )
Amortization of
intangible            (16,719 )       (15,040 )
assets
Loss on
disposal of           (1,995  )       (3,271  )
property, plant
and equipment
Accretion of
asset                (155    )      (136    )
retirement
obligations
Income from           34,495          61,450
operations
Other (expense)
income:
(Loss) earnings
from                  (139    )       74
unconsolidated
affiliates
Interest income       24              124
Interest              (37,671 )       (33,336 )
expense
Amortization of
deferred
financing costs
and discount (a       (1,528  )       (1,658  )
component of
interest
expense)
Miscellaneous
income               1,009         (1      )
(expense), net
(Loss) income
before              $ (3,810  )     $ 26,653  
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)
                                                                                  
Twelve months
ended December      Marcellus        Utica            Northeast     Southwest     Total
31, 2013
Segment revenue     $ 527,073        $ 26,442         $ 204,326     $ 935,426     $ 1,693,267
                                                                                  
Operating
expenses:
Purchased             100,262          -                65,192        525,711       691,165
product costs
Facility             108,781        35,081         28,425       127,112      299,399   
expenses
Total operating
expenses before
items not             209,043          35,081           93,617        652,823       990,564
allocated to
segments
                                                                                  
Portion of
operating
(loss) income        -              (3,499   )      -            21           (3,478    )
attributable to
non-controlling
interests
Operating
income (loss)
before items        $ 318,030       $ (5,140   )     $ 110,709     $ 282,582     $ 706,181   
not allocated
to segments
                                                                                  
                                                                                  
Twelve months
ended December      Marcellus        Utica            Northeast     Southwest     Total
31, 2012
Segment revenue     $ 319,867        $ 571            $ 225,818     $ 842,958     $ 1,389,214
                                                                                  
Operating
expenses:
Purchased             74,024           -                68,402        387,902       530,328
product costs
Facility             65,825         3,968          24,106       122,691      216,590   
expenses
Total operating
expenses before
items not             139,849          3,968            92,508        510,593       746,918
allocated to
segments
                                                                                  
Portion of
operating
(loss) income        -              (1,359   )      -            176          (1,183    )
attributable to
non-controlling
interests
Operating
income (loss)
before items        $ 180,018       $ (2,038   )     $ 133,310     $ 332,189     $ 643,479   
not allocated
to segments
                                                                                  
                                                                                  
                    Twelve months ended December
                    31,
                    2013             2012
                                                                                  
Operating
income before
items not           $ 706,181        $ 643,479
allocated to
segments
Portion of
operating loss
attributable to       (3,478   )       (1,183   )
non-controlling
interests
Derivative
(loss) gain not       (25,770  )       69,126
allocated to
segments
Revenue
deferral              (6,182   )       (5,935   )
adjustment and
other
Compensation
expense
included in
facility              (2,421   )       (1,022   )
expenses not
allocated to
segments
Facility
expenses              10,751           10,751
adjustments
Selling,
general and           (101,549 )       (93,444  )
administrative
expenses
Depreciation          (299,884 )       (183,250 )
Amortization of
intangible            (64,644  )       (53,320  )
assets
Gain (loss) on
disposal of           33,763           (6,254   )
property, plant
and equipment
Accretion of
asset                (824     )     (672     )
retirement
obligations
Income from           245,943          378,276
operations
Other income
(expense):
Earnings from
unconsolidated        1,422            2,328
affiliates
Interest income       262              419
Interest              (151,851 )       (120,191 )
expense
Amortization of
deferred
financing costs
and discount (a       (6,726   )       (5,601   )
component of
interest
expense)
Loss on
redemption of         (38,455  )       -
debt
Miscellaneous        2,519          62       
income, net
Income before
provision for       $ 53,114        $ 255,293  
income tax
                                                                                  


Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Distributable Cash Flow
(unaudited, in thousands)

                  Three months ended          Twelve months ended December
                    December 31,                 31,
                    2013         2012           2013           2012
                                                              
Net (loss)          $ (3,895  )   $ 29,923       $ 40,445        $ 216,965
income
Depreciation,
amortization
and other             100,934       71,032         365,664         237,554
non-cash
operating
expenses
Loss (gain) on
sale and or
disposal of           2,051         3,271          (30,660   )     6,254
assets, net of
tax
Loss on
redemption of         -             -              36,178          -
debt, net of
tax benefit
Amortization of
deferred              1,528         1,658          6,726           5,601
financing costs
and discount
Non-cash loss
(earnings) from       139           (74      )     (1,422    )     (2,328    )
unconsolidated
affiliates
Distributions
from                  1,418         1,792          6,370           8,416
unconsolidated
affiliates
Non-cash
compensation          2,358         1,977          7,822           8,247
expense
Non-cash
derivative            14,380        (312     )     15,602          (102,127  )
activity
Provision for
income tax -          790           1,298          23,877          40,694
deferred
Cash adjustment
for
non-controlling       1,449         908            6,121           2,299
interest of
consolidated
subsidiaries
Revenue
deferral              2,049         1,837          7,213           7,441
adjustment
Other                 9,666         (58      )     17,419          3,372
Maintenance
capital              (5,625  )    (1,478   )    (18,000   )    (15,302   )
expenditures
(1)
Distributable       $ 127,242    $ 111,774     $ 483,355      $ 417,086   
cash flow
                                                               
Maintenance
capital             $ 5,625       $ 1,478        $ 18,000        $ 15,302
expenditures
(1)
Growth capital       864,612     709,141      3,028,956     1,935,022 
expenditures
Total capital         870,237       710,619        3,046,956       1,950,324
expenditures
Acquisitions,
net of cash          (2,322  )    -            222,888       506,797   
acquired (2)
Total capital
expenditures          867,915       710,619        3,269,844       2,457,121
and
acquisitions
Joint venture
partner              -           (178,018 )    (716,982  )    (233,018  )
contributions
Total capital
expenditures
and                 $ 867,915    $ 532,601     $ 2,552,862    $ 2,224,103 
acquisitions,
net
                                                                 
Distributable       $ 127,242     $ 111,774      $ 483,355       $ 417,086
cash flow
Maintenance
capital               5,625         1,478          18,000          15,302
expenditures
(1)
Changes in
receivables and       (59,131 )     (1,655   )     (133,601  )     24,641
other assets
Changes in
accounts
payable,
accrued               42,458        (3,740   )     91,015          41,728
liabilities and
other long-term
liabilities
Cash adjustment
for
non-controlling       (1,449  )     (908     )     (6,121    )     (2,299    )
interest of
consolidated
subsidiaries
Other                (9,754  )    (720     )    (16,998   )    (4,445    )
Net cash
provided by         $ 104,991    $ 106,229     $ 435,650      $ 492,013   
operating
activities
                                               

    
(1)   Net of joint venture partner contributions and proceeds from trade-in of
      property plant and equipment.
      On May 29, 2012, the Partnership acquired natural gas gathering and
(2)   processing assets from Keystone, during the three months ended December
      2013, we received $2.3 million related to a working capital adjustment.
      

MarkWest Energy Partners, L.P.
Reconciliation of GAAP Financial Measure to Non-GAAP Financial Measure
Adjusted EBITDA
(unaudited, in thousands)
                                                             
                  Three months ended December 31,   Twelve months ended
                                                    December 31,
                  2013              2012            2013          2012
                                                                  
Net (loss)        $  (3,895   )     $  29,923       $ 40,445      $ 216,965
income
Non-cash
compensation         2,358             1,977          7,822         8,247
expense
Non-cash
derivative           14,380            (312     )     15,602        (102,127 )
activity
Interest             37,096            32,838         150,084       117,098
expense (1)
Depreciation,
amortization
and other            100,934           71,032         365,664       237,554
non-cash
operating
expenses
Loss (gain) on
sale and or          1,995             3,271          (33,763 )     6,254
disposal of
assets
Loss on
redemption of        -                 -              38,455        -
debt
Provision for        85                (3,270   )     12,669        38,328
income tax
Adjustment for
cash flow from       1,557             1,718          4,948         6,088
unconsolidated
affiliates
Other               1,002           775          4,063       60       
Adjusted EBITDA   $  155,512       $  137,952     $ 605,989    $ 528,467  

(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)

The Partnership periodically estimates the effect on DCF resulting from
changes in its volume forecast and NGL prices. The Partnership has become less
sensitive to changes in commodity prices because fee-based margin has
increased significantly. For the full year 2014, the Partnership estimates
that net operating margin will be over 70 percent fee-based. In addition, the
Partnership has hedged approximately 60 percent of its forecasted 2014 NGL
exposure on a volumetric basis, 90 percent of these with direct product
hedges.

The analysis further assumes derivative instruments outstanding as of February
26, 2014, 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
                                         
                        Volume Forecast (3)
                  Low Case   Base Case   High Case
              $1.05     $   610    $   662     $   720
NGL $/Gal     $1.00     $   601    $   652     $   709
(1) (2)       $0.95     $   591    $   642     $   698
              $0.90     $   583    $   633     $   690
            $0.85   $   574    $   624     $   681


      The composition is based on the Partnership’s projected barrel of
(1)  approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane:
      12%, Natural Gasoline: 12%.
(2)   Composite NGL prices is based on the Partnership’s average price.
(3)   Volume Forecast is increased/decreased by 10% in the Marcellus and Utica
      segments for the High and Low Cases.
      

The table is based on current information, expectations, and beliefs
concerning future developments and their potential effects, and does not
consider actions the Partnership’s 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 volumes,
prices and correlations do not guarantee future results.

Although the Partnership believes the expectations reflected in this analysis
are reasonable, the Partnership 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, market conditions and constraints, production, NGL composition,
infrastructure availability, market participants, and ratios between product
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 the Partnership'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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