INVESTOR PRESENTATION
 
FORWARD-LOOKING STATEMENTS
The s tatements inc luded in th is presentat ion conta in “ forward- look ing s tatements” wi th in the meaning of the Secur i t ies Act of 1933
and the Secur i t ies Exchange Act of 1934, each as amended. These forward- look ing s tatements (which in many instances can be
ident i f ied by words l ike “may,” “wi l l , ” “should ,” “expects ,” “p lans ,” “be l ieves ,” and other comparable words) are based on the
Partnersh ip ’s current expectat ions and be l ie fs concern ing f uture deve lopments and the i r potent ia l e f fects on the Partnersh ip , but are
not guarantees of future per formance, and involve r i sks and uncerta int ies . You are caut ioned not to p lace undue re l iance on forward-
look ing s tatements , as many of these f actors are beyond our ab i l i ty to contro l or predict , and which speak only as of the date hereof .
The Partnersh ip undertakes no obl igat ion to publ ic ly update or rev ise any forward- look ing s tatements a f ter the date they are made,
whether as a resu l t of new informat ion, future events , or otherwise . You are urged to carefu l ly rev iew and cons ider the caut ionary
statements and other d isc losures made in the Partnersh ip ’s Annual Report on Form 10-K for f i sca l year 2013, inc lud ing under the
heading “R isk Factors ,” which ident i fy and d iscuss s ign i f i cant r i sks , uncerta int ies , and var ious other factors that could cause actua l
resu l ts to vary s ign i f i cant ly f rom those expected or impl ied in the forward- look ing s tatements .
Among the factors that could cause resu l ts to d i f fer mater ia l ly are those r i sks d iscussed in the per iod ic reports f i led wi th the SEC,
inc lud ing MarkWest ’s Annual Report on Form 10-K for the year ended December 31 , 2013. You are urged to carefu l ly rev iew and
cons ider the caut ionary s tatements and other d isc losures , inc lud ing those under the heading “R isk Factors ,” made in those documents .
I f any of the uncerta int ies or r i sks deve lop into actua l events or occurrences , or i f under ly ing assumpt ions prove incorrect , i t could
cause actua l resu l ts to vary s ign i f i cant ly f rom those expressed in the presentat ion, and MarkWest ’s bus iness , f inanc ia l condi t ion, or
resu l ts of operat ions could be mater ia l ly adverse ly a f fected. Key uncerta int ies and r i sks that may d i rect ly a f fect MarkWest ’s
performance, future growth, resu l ts of operat ions , and f inanc ia l condi t ion, inc lude, but are not l imi ted to :
• F luctuat ions and vo lat i l i ty of natura l gas , NGL products , and o i l pr ices ;
• A reduct ion in natura l gas or ref inery of f -gas product ion which MarkWest gathers , t ransports , processes , and/or
fract ionates ;
• A reduct ion in the demand for the products MarkWest produces and se l l s ;
• F inanc ia l c red i t r i sks / fa i lure of customers to sat i s fy payment or other ob l igat ions under MarkWest ’s contracts ;
• Ef fects of MarkWest ’s debt and other f inanc ia l ob l igat ions , access to cap i ta l , or i t s future f inanc ia l or operat iona l f lex ib i l i ty
or l iqu id i ty ;
• Construct ion, procurement , and regulatory r i sks in our deve lopment pro jects ;
• Hurr icanes , f i res , and other natura l and acc identa l events impact ing MarkWest ’s operat ions , and adequate insurance
coverage;
• Terror i s t at tacks d i rected at MarkWest fac i l i t ies or re lated fac i l i t ies ;
• Changes in and impacts of laws and regulat ions af fect ing MarkWest operat ions and r i sk management s t rategy; and
• Fa i lure to integrate recent or future acquis i t ions .
2
 
N O N - G A A P M E A S U R E S
Distr ibutab le Cash F low (DCF) , Adjusted EBITDA are non-GAAP F inanc ia l Measures , and should not be cons idered separate ly f rom or as a
subst i tute for net income, income f rom operat ions , or cash f low as ref lected in our f inanc ia l s tatements . The GAAP measure most
d i rect ly comparable to DCF and Adjusted EBITDA i s net income ( loss ) . In genera l , the Partnersh ip def ines DCF as net income ( loss )
ad justed for ( i ) deprec iat ion, amort i zat ion, impairment , and other non-cash operat ing expenses ; ( i i ) amort i zat ion of deferred f inanc ing
costs and debt d iscount; ( i i i ) loss on redempt ion of debt , net of tax benef i t ; ( i v ) impairment of unconsol idated af f i l ia tes ; (v ) ga in on
sa le of unconsol idated af f i l ia te ; (v i ) non-cash (earn ings) loss f rom unconsol idated af f i l ia tes ; (v i i ) d i s t r ibut ions f rom (contr ibut ions to)
unconsol idated af f i l ia tes (net of a f f i l ia tes ’ growth cap i ta l expendi tures) ; (v i i i ) non-cash compensat ion expense; ( i x ) non-cash der ivat ive
act iv i ty ; (x ) losses (ga ins) on the sa le or d isposa l o f property , p lant and equipment (“PP&E”) , net of tax ; (x i ) prov is ion for deferred
income taxes ; (x i i ) cash ad justments for non-contro l l ing interest of consol idated subs id iar ies ; (x i i i ) revenue deferra l ad justment ; (x iv )
losses (ga ins) re lat ing to other misce l laneous non-cash amounts a f fect ing net income for the per iod; and (xv ) maintenance capi ta l
expendi tures , net of jo int v enture partner contr ibut ions and proceeds f rom trade- in of PP&E. . The Partnersh ip def ines Adjusted EBITDA
as net income ( loss ) ad justed for ( i ) deprec iat ion, amort i zat ion, impairment , and other non-cash operat ing expenses ; ( i i ) interest
expense; ( i i i ) amort i zat ion of deferred f inanc ing costs and debt d iscount ; ( iv ) loss on redempt ion of debt ; (v ) losses (ga ins) on the sa le
or d isposa l of PP&E; (v i ) impairment of unconsol idated af f i l ia tes ; (v i i ) ga in on sa le of unconsol idated af f i l ia te ; (v i i i ) non-cash der ivat ive
act iv i ty ; ( i x ) non-cash compensat ion expense; (x ) prov is ion f or income taxes ; (x i ) ad justments for cash f low f rom unconsol idated
af f i l ia tes ; and (x i i ) losses (ga ins ) re lat ing to other misce l laneous non-cash amounts a f fect ing net income for the per iod.
DCF i s a f inanc ia l per formance measure used by management as a key component in the determinat ion of cash d is t r ibut ions pa id to
uni tho lders . The Partnersh ip be l ieves DCF i s an important f inanc ia l measure for un i tho lders as an ind icator of ca sh return on
investment and to eva luate w hether the Partnersh ip i s generat ing suf f i c ient cash f low to support quarter ly d i s t r ibut ions . In addi t ion,
DCF i s commonly used by the investment community because the market va lue of publ ic ly t raded partnersh ips i s based, in part , on DCF
and cash d is t r ibut ions pa id to un i tholders .
Adjusted EBITDA i s a f inanc ia l per formance measure used by management , industry ana lysts , investors , lenders , and rat ing agenc ies to
assess the f inanc ia l per formance and operat ing resu l ts of the Partnersh ip ’s ongoing bus iness operat ions . Addi t iona l ly , the Partnersh ip
bel ieves Adjusted EBITDA prov ides usefu l in format ion to investors for t rending , ana lyz ing and benchmark ing our operat ing resu l ts f rom
per iod to per iod as compared to other companies that may have d i f ferent f inanc ing and capi ta l s t ructures .
Net Operat ing Marg in i s a f inanc ia l per formance measure used by management and investors to eva luate the under ly ing base l ine
operat ing performance of our contractua l arrangements . Management a lso uses Net Operat ing Marg in to eva luate the Partnersh ip ’s
f inanc ia l per formance for purposes of p lanning and forecast ing .
P lease see the Appendix for reconc i l ia t ions of D is t r ibutab le Cash F low, Adjusted EBITDA, and Net O perat ing Marg in to the most d i rect ly
comparable GAAP measure .
 
K E Y I N V E S T M E N T C O N S I D E R AT I O N S
Leading presence in major resource plays
including Marcellus,
Utica, Woodford,
Haynesville and
Granite Wash
Largest processor
Customer Satisfaction
IPO
SUBSTANIAL
GROWTH
OPPORTUNITES
PROVEN
CUSTOMER
SATISFACTION 
STRONG
FINANCIAL
PROFILE
HIGH-QUALITY
DIVERSIFIED
ASSETS 
4
 
W H E R E W E O P E R AT E  
Southwest
In the Utica segment, we have a leading position with
925 MMcf/d of processing capacity and 100 MBbl/d
of shared C2+ fractionation capacity. Growing to over
1.5 Bcf/d of processing capacity and 220 MBbl/d of
shared C2+ fractionation capacity
gathering capacity and 1.0
Bcf/d of processing capacity
and fractionator in the
liquids-rich areas of the
Marcellus Shale with over
2.9 Bcf/d of processing
shared C2+ fractionation
Bcf/d of processing capacity
C2+ fractionation capacity
 
G R O W T H D R I V E N B Y C U S T O M E R S AT I S FA C T I O N
6
MarkWest has received the #1 rating for total customer satisfaction in every
EnergyPoint Research survey since its inception in 2006
 
0
5
10
15
20
25
30
35
40
1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040
S H A L E P L AY S A R E D R I V I N G N AT U R A L G A S S U P P LY
• EIA data concludes that total
U.S. natural gas supply will
increase by approximately 55%
primarily by increased demand
for power generation and
increase will be met by shale gas
production
production is forecasted to
2040 it will account for 53% of
total U.S. natural gas supply
• Resource plays will continue to
drive midstream investment for
investments in these areas Source: U.S. Energy Information Administration,  Annual Energy Outlook 2014
2014
40%
21%
1%
9%
6%
10%
13%
22%
3%
8%
5%
5%
4%
53%
U.S. Dry Natural Gas Production (trillion cubic feet per year)
7
 
M A R C E L L U S & U T I C A : D R I V I N G U . S . G A S S U P P L Y  
   R    e    s   t    o     f    U  .   S  .   –    B    i    l    l   i   o    n    c   u     b    i   c     f   e    e    t    p    e    r     d    a    y     (   B    c     f    /     d     )
Note: Wellhead gas production (before flaring and NGL extraction)
Source: As of 11/5/14, Bloomberg (LCI Energy Insight Estimates),
BENTEK, MarkWest Energy Partners, L.P.
By YE 2014, Marcellus & Utica will account for over 20% of total U.S. Gas Supply
   M    a    r   c    e     l    l   u    s    &    U    t   i   c    a   –    B    i    l    l   i   o    n    c    u     b    i   c     f   e    e    t    p    e    r     d    a    y     (   B    c     f    /     d     )
8
7
9
11
13
15
17
19
55
56
57
58
59
60
61
62
63
Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14
Marcellus & Utica
 
S O U T H W E S T S E G M E N T  
1.0Bcf/d 
29,000Bbl/d
Processing
Fractionation
Gathering
1.9Bcf/d
plays throughout Oklahoma and Texas. In addition, we process
and fractionate off-gas on behalf of six oil refineries in the Gulf
Coast and have four intrastate pipelines feeding power plants
9
Transmission
1.4Bcf/d
 
 -
1Q09 4Q09 3Q10 2Q11 1Q12 4Q12 3Q13 2Q14 1Q15F 4Q15F
East Texas WOK SEOK Gulf Coast
• Average utilization of 85% during the
third quarter 2014
last quarter and 26% compared to the
third quarter 2013
utilized and we have scheduled early
completion of a new 120 MMcf/d plant
in Carthage, Texas by the end of 2014
• In Western Oklahoma, producer activity
in the Granite Wash continues to drive
growth at our Buffalo Creek facility and
recent upstream A&D activity highlights
future opportunity
straight year
S O U T H W E S T S E G M E N T O V E R V I E W
Forecasted
   1    Q    1    5    t    h    r   o    u    g
    h    4    Q    1    5    A    v    g
 .
 
M A R C E L L U S S E G M E N T  
2.9Bcf/d 
226,000Bbl/d
Processing
Fractionation*
Gathering
615MMcf/d
Marcellus Shale and provide fully-integrated natural gas
midstream services
Under Construction
Fractionation  240,000 Bbl/d of shared C2+ capacity
11
 
 -
1Q09 4Q09 3Q10 2Q11 1Q12 4Q12 3Q13 2Q14 1Q15F 4Q15F
M A R C E L L U S S E G M E N T O V E R V I E W
Forecasted Avg.
Increase from
   1    Q    1    5    t    h    r   o    u    g
    h    4    Q    1    5    A    v    g
 .
and operating income at five major complexes
• Processed volumes increased 22% when
compared to last quarter and 95% from the
third quarter 2013
quarter 2014, up from 79% last quarter
 
*Based on weighted average number of days plant(s) in service
12
 
M A R K W E S T M A R C E L L U S O P E R AT I O N S
Doddridge
Marshall
 Wetzel
Harrison
Butler
 Washington 
De-ethanization – 40,000 Bbl/d – 3Q15
FOX COMPLEX (formerly Hillman)
De-ethanization – 10,000 Bbl/d – 1Q16
De-ethanization – 40,000 Bbl/d – Operational
De-ethanization – 40,000 Bbl/d – Operational
De-ethanization – 10,000 Bbl/d – 2Q15
De-ethanization – 40,000 Bbl/d – 3Q15
MWE NGL/Purity Ethane Pipeline Under Construction
Sunoco Mariner Pipeline
MWE Marcellus Complex
MWE Gathering System
TEPPCO Product Pipeline
HOPEDALE FRACTIONATION COMPLEX
fractionation capacity)
24 facilities completed: 16 facilities under construction
WEST VIRGINI
 
U T I C A S E G M E N T  
925MMcf/d 
100,000Bbl/d
Processing
Fractionation*  
Gathering
385MMcf/d
> In the Utica segment, we are partnered with The Energy & Minerals
Group and Summit Midstream, and have a leading position in
developing fully-integrated gathering, processing, fractionation, and
NGL marketing solutions
Fractionation 120,000 Bbl/d of shared C3+ capacity
1
Marcellus
 100
 200
 300
 400
 500
 600
 700
 800
 900
 1,000
U T I C A S E G M E N T O V E R V I E W
• MarkWest Utica EMG continues to develop its
leading fully integrated midstream system in
eastern Ohio
last quarter and 251% compared to the third
quarter 2013
quarter 2014, up from 56% last quarter
Forecasted
   1    Q    1    5    t    h    r   o    u    g
    h    4    Q    1    5    A    v    g
 .
 
 Wetzel
Harrison
Noble
OHIO
Belmont
Monroe
M A R K W E S T U T I C A O P E R AT I O N S
16
Summit Midstream, LLC
Carroll
 JeffersonTuscarawas
Guernsey
CADIZ COMPLEX
De-ethanization – 40,000 Bbl/d – Operational
fractionation capacity)
 
 -
 300,000 C3+ C2
 
   1    Q    1    5    t    h    r   o    u    g
    h    4    Q    1    5    A    v    g
 .
• Total C2+ fractionated volumes for the third
quarter 2014 were a record 177 MBbl/d
• Utilization of MarkWest’s Marcellus Utica
C3+ fractionation capacity averaged 91% in
the third quarter, up from 75% last quarter
• Ahead of schedule for the completion of
Hopedale II, a 60,000 Bbl/d C3+ expansion
with a targeted in-service date by year-end
*Based on weighted average number of days plant(s) in service
17
scale condensate stabilization facility
terminal capabilities in Harrison
includes stabilization capacity of
operational in fourth quarter 2014
• Condensate production is expected
provides great uplift for producers in
the area
downstream condensate splitter
MarkWest Utica EMG’s Joint Venture with Summit Midstream, LLC
Stabilization Facility – 23,000 Bbl/d – 4Q14 
CADIZ COMPLEX
HOPEDALE FRACTIONATION
COMPLEX Jefferson
 
C O N D E N S A T E S O L U T I O N S I N T H E U T I C A S H A L E  
19
Harrison
Noble
OHIO
Belmont
Monroe
Carroll
facility. Once stabilized, condensate will be transported
by truck and rail to local refinery markets and
Canadian export markets
and fully integrated with a logistics terminal to be
operated by a subsidiary of Toledo, Ohio-based
Midwest Terminals
• The facility will serve as the origin for MPLX LP’s (NYSE:
MPLX) Cornerstone Pipeline—a proposed 50-mile
pipeline to Marathon Petroleum Company LP’s (MPC)
Canton, Ohio refinery
Summit Midstream, LLC
CADIZ COMPLEX HOPEDALE FRACTIONATION
Proposed
Cornerstone
Pipeline
 Jefferson
 
U T I C A D R Y G A S P O T E N T I A L
Doddridge
Marshall
 Wetzel
Noble
Butler
economically viable dry gas
plays in the U.S.
excess of 15 Bcfe
• Ultimate volumes could exceed
gathering and processing
systems and relationships
opportunity
20
 
2 7 M A J O R P L A N T P R O J E C T S C O M P L E T E D I N T H E
L A S T T W O Y E A R S - 1 7 P L A N T S TA R T- U P S I N 2 0 1 4
Langley III
Mobley III
 
 
processing complexes will produce
• MarkWest has the ability to bring
significant critical mass and
project
producers
gas takeaway pipelines
 
M A R C E L L U S & U T I C A : F U L L - S E R V I C E C A PA B I L I T I E S  
23
fractionation and logistics solutions
• Growing to over 500 MBbl/d of total
C2+ fractionation capacity
• Access to all major NGL takeaway
pipeline projects in the Northeast
• Access to Gulf Coast NGL markets
through a proposed joint venture with
Kinder Morgan
2011 2012 2013 2014F 2015F
M A R K W E S T ’ S T O T A L P R O C E S S E D V O L U M E F O R E C A S T  
   P    r   o    c    e    s   s   e     d    V    o     l   u    m    e    s     (   B    c     f    /     d     )
24
 
F I N A N C I A L S U M M A R Y  
• MarkWest preserves a strong balance sheet to fund growth
> As of today, we have over $1.0 billion of liquidity to support our capital investment program
> As of September 30, 2014, our total Debt to Capital was 38%, interest coverage was 5.0 times
and our leverage ratio has declined from 4.6 times at the end of second quarter 2014 to 4.4
times
• MarkWest maintains flexible financing options
> Funding of base capital requirements using a combination of long-term debt and equity
> Year-to-date through November 5th 2014, we have raised over $1.5 billion through our at-the-
market equity program and we have begun prefunding for 2015
• MarkWest is focused on delivering top-quartile total returns to its unitholders
> Projected distribution growth of 7% in 2015 and 10% in 2016
MarkWest has over $1.0 billion of liquidity
25
2011 2012 2013 2014F 2015F DCF Adjusted EBITDA
D C F & A D J U S T E D E B I T D A F O R E C A S T  
   D    C    F    &    A     d    j   u    s   t   e     d    E    B    I   T    D    A     (    $    i   n    m    i    l    l   i   o    n    s    )
22% Growth in DCF
 
2015 DCF Forecast of $800 to $880MM & Adjusted EBITDA of $1.0 to $1.1B
26
Growth Capex (Net) Growth Capex as % of Gross PP&E
C A P I T A L I N V E S T M E N T F O R E C A S T  
27
Marcellus
72%
Utica*
20%
Southwest
8%
$1.8 to $2.3 billion Growth Capital Investments and PP&E
*Partnership’s share of MarkWest Utica EMG Joint Venture
 
2008YE 2009YE 2010YE 2011YE 2012YE 2013YE 2014F 2015F
 
2015 fee-based net operating margin is forecasted to be approximately 80%
   N    e    t    O    p    e    r   a    t   i   n    g    M    a    r   g    i   n     (   %     )
   2    5    %    3
Note: 2015 Forecast Assumes Crude Oil ($/bbl) range of $79.70
 
MarkWest is more sensitive to changes in volumes than changes in commodity prices
2 0 1 5 D I S T R I B U TA B L E C A S H F L O W :
S E N S I T I V I T Y TA B L E
29
• MarkWest estimates the effect on 2015 DCF resulting from changes in volume forecast and NGL
prices
• The Partnership has become less sensitive to changes in commodity prices as fee-based income has
increased significantly and is expected to reach approximately 80% in 2015
(1) Volume Forecast is increased/decreased by 5% in the Marcellus and Utica segments for the High and Low Cases.
(2) The composition is based on the Partnership’s projected NGL barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%.
(3) Composite NGL prices are based on the Partnership’s average forecasted price.
Volume Forecast (1)
$1.00 $832 $872 $910
$0.95 $814 $854 $892
$0.90 $796 $836 $873
$0.85 $779 $818 $855
$0.80 $761 $800 $836
 $0.20
 $0.40
 $0.60
 $0.80
 $1.00
D I S T R I B U T I O N G R O W T H S I N C E I P O  
30
Over 11% CAGR in distributions since IPO
   D    i   s   t   r   i    b    u    t   i   o    n    i   n     $
30
256%
   2    0    1    5    7    %    A    v    e    r   a    g    e    I   n    c    r   e    a    s   e
 
MWE Alerian S&P 500
MarkWest Provides Superior Total Return
   C    u    m    u     l   a    t   i   v    e    T   o    t   a     l    R    e    t   u    r   n     (   %     )
M A R K W E S T 5 - Y E A R T O TA L R E T U R N  
Source: Bloomberg data from 11/2/09 to 11/10/2014
(Cumulative Total Return, Gross Dividends) 31
288%
166%
117%
with high-quality assets and exceptional service
Continue to execute on growth projects that are well
diversified across the asset base
Annual DCF growth of over 20% in 2015
Fee-based margin increasing to approximately 80%
for the full-year 2015
Northeast shale facilities are completed and
producer volumes increase
MLP industry
M A R K W E S T I N V E S T M E N T C O N S I D E R AT I O N S :
WHAT TO EXPEC T
 
 
($ in millions)  
9/30/2014  12/31/2013 
Depreciation, amortization and other non-cash operating expenses 360.9 365.7
Loss (Gain) on sale or disposal of property, plant and equipment 0.6 (30.7)
Loss on redemption of debt, net of tax benefit - 36.2
Amortization of deferred financing costs and debt discount 5.7 6.7
Equity in loss (earnings) from unconsolidated affiliates 2.0 (1.4)
Distributions from unconsolidated affiliates 7.2 6.4
Non-cash compensation expense 7.4 7.8
Unrealized (gain) loss on derivative instruments (18.2) 15.6
Deferred income tax expense (benefit) 20.3 23.9
Cash adjustment for non-controlling interest of consolidated subsidiaries (10.6) 6.1
Revenue deferral adjustment 5.5 7.2
Other (1) 24.7 17.5
Total distributions declared for the period 460.9 490.6
Distribution Coverage Ratio (DCF / Total distributions declared) 1.10x  
0.99x 
34
(1) Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of joint venture capital projects.
(2) Net of joint venture partner contributions.
 
R E C O N C I L I A T I O N O F A D J U S T E D E B I T D A  
35
(1) Includes amortization of deferred financing costs and debt discount, and excludes interest expense related to the Steam Methane Reformer.
(2) For the three and nine months ended September 30, 2014, Other includes amounts related to capitalized interest associated with joint venture capital expenditures and fees earned related to development of
 joint venture capital projects
Non-cash compensation expense 9.8 7.8 8.2
Unrealized (gain) loss on derivative instruments (3.8) 15.6 (102.1)
Interest expense (1) 160.4 150.1 117.1
Depreciation, amortization and other non-cash operating expenses 461.9 365.7 237.6
Loss (Gain) on disposal of property, plant and equipment 2.6 (33.8) 6.2
Loss on redemption of debt - 38.5 -
Provision for income tax expense (benefit) 20.7 12.7 38.3
Adjustment for cash flow from unconsolidated affiliates 10.8 4.9 6.1
Other (2) 13.3 4.1 0.1
Adjusted EBITDA $ 786.8 $ 606.0 $ 528.5
35
 
R E C O N C I L I A T I O N O F N E T O P E R A T I N G M A R G I N  
Nine Months Ended Year Ended
($ in millions)  
Facility expenses 250.8 291.1
Segment Purchased product costs adjustment for unconsolidated affiliate (0.1) -
Selling, general and administrative expenses  91.8 101.6
Depreciation 311.1 299.9
Amortization of intangible assets 48.3 64.6
Loss (gain) on disposal of property, plant, and equipment 0.6 (33.8)
Accretion of asset retirement obligations 0.5 0.8
Net Operating Margin $ 977.4 $ 1,002.1
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