2014 Analyst & Investor Day Highlights

2014 Analyst &
Investor Day
May 12, 2014
1
Strong. Innovative. Growing.

Forward-Looking Statements
This presentation contains forward-looking statements within the meaning of the federal securities laws. Forward-looking
statements are not guarantees of performance. They involve risks, uncertainties and assumptions. The future results of
EnLink Midstream, LLC, EnLink Midstream Partners, LP and their respective affiliates (collectively known as “EnLink
Midstream”) may differ materially from those expressed in the forward-looking statements contained throughout this
presentation and in documents filed with the Securities and Exchange Commission (“SEC”). Many of the factors that will
determine these results are beyond EnLink Midstream’s ability to control or predict. These statements are necessarily based
upon various assumptions involving judgments with respect to the future, including, among others, drilling levels; the
dependence on Devon Energy Corporation for a substantial portion of the natural gas that EnLink Midstream gathers,
processes and transports; the risk that EnLink Midstream will not be integrated successfully or that such integration will take
longer than anticipated; the possibility that expected synergies will not be realized, or will not be realized within the expected
timeframe; EnLink Midstream’s lack of asset diversification; EnLink Midstream’s vulnerability to having a significant portion of
its operations concentrated in the Barnett Shale; the amount of hydrocarbons transported in EnLink Midstream’s gathering
and transmission lines and the level of its processing and fractionation operations; fluctuations in oil, natural gas and natural
gas liquids (NGL) prices; construction risks in its major development projects; its ability to consummate future acquisitions,
successfully integrate any acquired businesses, realize any cost savings and other synergies from any acquisition; changes in
the availability and cost of capital; competitive conditions in EnLink Midstream’s industry and their impact on its ability to
connect hydrocarbon supplies to its assets; operating hazards, natural disasters, weather-related delays, casualty losses and
other matters beyond its control; and the effects of existing and future laws and governmental regulations, including
environmental and climate change requirements and other uncertainties and other factors discussed in EnLink Midstream’s
Annual Reports on Form 10-K for the year ended December 31, 2013, and in EnLink Midstream’s other filings with the SEC.
You are cautioned not to put undue reliance on any forward-looking statement. EnLink Midstream has no obligation to publicly
update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.
2

Non-GAAP Financial Information
This presentation contains non-generally accepted accounting principle financial measures that EnLink Midstream refers to
as adjusted EBITDA, gross operating margin, segment cash flows, growth capital expenditures and maintenance capital
expenditures. Adjusted EBITDA is defined as net income plus interest expense, provision for income taxes, depreciation and
amortization expense, stock-based compensation, (gain) loss on noncash derivatives, transaction costs, distribution of equity
investment and non-controlling interest; and income (loss) on equity investment. Gross operating margin is defined as
revenue less the cost of purchased gas, NGLs, condensate and crude oil. Segment cash flows is defined as revenue less the
cost of purchased gas, NGLs, condensate, crude oil and operating and maintenance expenditures. The amounts included in
the calculation of these measures are computed in accordance with generally accepted accounting principles (GAAP) with the
exception of maintenance capital expenditures. Growth capital expenditures are defined as all construction-related direct
labor and material costs, as well as indirect construction costs including general engineering costs and the costs of funds
used in construction. Maintenance capital expenditures are capital expenditures made to replace partially or fully
depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives.
EnLink Midstream believes these measures are useful to investors because they may provide users of this financial
information with meaningful comparisons between current results and prior-reported results and a meaningful measure of
EnLink Midstream’s cash flow after it has satisfied the capital and related requirements of its operations.
Adjusted EBITDA, segment cash flows, gross operating margin, growth capital expenditures and maintenance capital
expenditures, as defined above, are not measures of financial performance or liquidity under GAAP. They should not be
considered in isolation or as an indicator of EnLink Midstream’s performance. Furthermore, they should not be seen as
measures of liquidity or a substitute for metrics prepared in accordance with GAAP.
3

Investor Notice
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves
that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of
resources that do not constitute such reserves. This presentation may contain certain terms, such as resource potential and
exploration target size and risked resource. These estimates are by their nature more speculative than estimates of proved,
probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC
guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the
disclosure in Devon Energy Corporation’s Form 10-K, available at Devon Energy Corporation, Attn. Investor Relations, 333
West Sheridan, Oklahoma City, OK 73102-5015. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or
from the SEC’s website at www.sec.gov.
4

Agenda & Speakers
Roadmap for Growth
• Barry Davis President & CEO
• Michael Garberding EVP and CFO
Devon Energy
Sponsorship
• John Richels Devon Energy Corporation, CEO
Natural Gas
Businesses
• Steve Hoppe EVP, President of Gas Gath., Proc. & Trans.
• Mike Burdett SVP of Commercial Development
• Brad Iles SVP of Business Development
• Stan Golemon SVP of Engineering
Liquids
Businesses
• Mac Hummel EVP & President of NGL & Crude
• Stan Golemon SVP of Engineering
• Chris Tennant VP of NGL
• Paul Weissgarber SVP of Ohio River Valley
Financial
Outlook
• Michael Garberding EVP and CFO
Non-Operated
Investments
• Brad Iles SVP of Business Development
5

The Roadmap
for Growth
Barry E. Davis,
President and Chief Executive Officer
6

Management Team Experience
Barry Davis
President & CEO
Barry Davis is President and Chief Executive Officer of EnLink Midstream. Mr. Davis led the founding of
Crosstex Energy in 1996 prior to the initial public offerings of Crosstex Energy, L.P. in 2002 and Crosstex
Energy, Inc. in 2004. Under his leadership, Crosstex evolved into a significant service provider in the energy
industry’s midstream business sector.
Joe Davis
EVP & General Counsel
Joe Davis is Executive Vice President and General Counsel of EnLink Midstream. Mr. Davis joined Crosstex
Energy in 2005 after serving as a partner at Hunton & Williams, an international law firm, where he also
was a member of the executive committee. Mr. Davis began his legal career at Worsham Forsythe, which
merged with Hunton & Williams in 2001.
Michael Garberding
EVP & CFO
Michael Garberding is Executive Vice President and Chief Financial Officer of EnLink Midstream. Previously,
Mr. Garberding held various positions at Crosstex Energy, including Executive Vice President and Chief
Financial Officer, and Senior Vice President of Business Development and Finance. Prior to joining Crosstex
in 2008, Mr. Garberding was assistant treasurer at TXU Corp. where he focused on structured transactions
such as project financing for coal plant development and the sale of TXU Gas Company.
Steve Hoppe
EVP & President of Gas Gathering,
Processing and Transportation
Steve Hoppe is Executive Vice President and President of the Gathering, Processing and Transportation
Business of EnLink Midstream. Mr. Hoppe previously served as Vice President of Midstream Operations for
Devon, which he joined in 2007. Prior to joining Devon, Mr. Hoppe spent eight years at Thunder Creek Gas
Services, most recently serving as president.
EnLink Midstream management team is comprised of former Crosstex and Devon senior management
and other experienced midstream leaders
McMillan (Mac) Hummel
EVP & President of NGL
and Crude Oil
Mac Hummel is Executive Vice President and President of the Natural Gas Liquids and Crude Business of
EnLink Midstream. Mr. Hummel previously served as Vice President of Commodity Services at Williams
Companies Inc. since 2013, and prior to that he served as Vice President, NGLs & Olefins at Williams from
2010 to 2012. Mr. Hummel worked at Williams for 29 years.
The Leadership:
Experienced Management Team with a
Proven Track Record
7

EnLink Midstream Partners, LP
Master Limited Partnership
NYSE: ENLK
(BBB / Baa3)
EnLink Midstream, LLC
General Partner
NYSE: ENLC
Public
Unitholders
~70% ~30%
~1% GP
~7% LP
EnLink Midstream Holdings
(formerly Devon Midstream Holdings)
~52%
LP
~40%
LP
50% LP
Devon Energy
Corp.
NYSE: DVN
(BBB+ / Baa1)
GP + 50% LP
The Vehicle for Sustainable Growth:
MLP Structure with a Premier Sponsor
8
Dist./Q Split Level
< $0.2500 2% / 98%
< $0.3125 15% / 85%
< $0.3750 25% / 75%
> $0.3750 50% / 50%
Current
Position
ENLC owns 100% of IDRs
~50%
LP

Gathering System
Processing Plant
Fractionation Facility
North Texas Systems
Louisiana Gas System
Louisiana NGL System
Cajun-Sibon Expansion
Howard Energy
Ohio River Valley Pipeline
Storage
Crude & Brine Truck Station
Brine Disposal Well
Barge Terminal
Rail Terminal
Condensate Stabilizers
(1) Increasing to 7 facilities with 252,000 Bbl/d of total net capacity upon completion of the
Cajun-Sibon phase II expansion expected in the second half of 2014.
AUSTIN CHALK
EAGLE
FORD
PERMIAN
BASIN
CANA-WOODFORD
ARKOMA-
WOODFORD
BARNETT
SHALE
HAYNESVILLE
& COTTON
VALLEY
UTICA
MARCELLUS
LA
TX
OK
OH
WV
PA
Strategically Located and
Complementary Assets
Gas Gathering and Transportation
 ~7,300 miles of gathering and
transmission lines
Gas Processing
 12 plants with 3.3 Bcf/d of total
net inlet capacity
 1 plant with 60 MMcf/d of net inlet
capacity under construction
NGL Transportation,
Fractionation and Storage
 ~570 miles of liquids transport line
 6 fractionation facilities with
180,000 Bbl/d of total net capacity(1)
 3 MMBbl of underground NGL storage
Crude, Condensate and Brine Handling
 200 miles of crude oil pipeline
 Barge and rail terminals
 500,000 Bbl of above ground storage
 100 vehicle trucking fleet
 8 Brine disposal wells
9

Jackfish
Pike
Granite Wash
Barnett Shale
Permian
Basin
Ferrier
Corridor
Cana Woodford
Mississippian-Woodford
Rockies Oil
Greater
Wapiti
Washakie
Carthage
Groesbeck
Access Pipeline
Water Handling
Ferrier Plant
Rockies
Midstream
E. Texas Midstream
Devon’s Upstream Portfolio &
Non-Contributed Midstream Assets
Horn River
Oil
Liquids-Rich
Dry Gas
Midstream
Haynesville/Bossier
Devon is Committed to the Success of
EnLink Midstream
 Devon has dedicated ~800,000 net acres
to EnLink Midstream
 Long-term contracts in place to stabilize
future cash flows
̶ 10-year fixed-fee contracts with rate
escalators
̶ 5-year minimum gathering commitments
(>1.3 Bcf/d)
̶ 5-year minimum processing commitments
(>1.0 Bcf/d)
 Development of Devon’s upstream
portfolio provides organic growth
opportunities
 Potential to acquire additional Devon
midstream assets
10

Diverse, Fee-Based Cash Flows
 Devon is EnLink Midstream’s largest customer
(>50% of consolidated 2014E adjusted EBITDA*)
 EnLink Midstream’s growth projects focused on crude/NGL services and rich gas processing
 Strong emphasis on fee-based contracts
2014E EnLink Midstream Consolidated
Gross Operating Margin*
95%
5%
By Contract Type
Texas
57%
19%
Ohio
5%
Okla.
19%
By Region
56%
Devon
44%
Other
By Customer
Fee-Based
Commodity
Sensitive
* Gross operating margin and adjusted EBITDA percentage estimates are provided for illustrative purposes and reflect period following transaction closing (2Q-4Q 2014).
Note: Adjusted EBITDA and gross operating margin are non-GAAP financial measures and are explained on page 3.
Louisiana
11

Strong Balance Sheet and Liquidity
 Devon assets contributed with no debt
 Investment grade balance sheet at ENLK (BBB / Baa3) provides low
cost of capital
 Long-term commitment to investment grade metrics (debt/adjusted
EBITDA <3.5x)
 Expected long-term distribution growth of high single digits at ENLK
 Expected long-term distribution growth of 20% at ENLC
 Combined Enterprise value of approximately $14 Billion
̶ LP Enterprise Value of ~$8 Billion
̶ GP Enterprise Value of ~$6 Billion
12

Pipeline Infrastructure Capital Spending Needed
Per Year in the U.S.*
(2011 – 2035)
$30.0 B
$14.6 B
$15.4 B
Total
Gas
Liquids
The Road Conditions:
Exponentially Growing Energy Market
13* Source: INGAA Study
Surging U.S. Production Requires the Re-Piping of America,
With Expected Midstream Investment of $30 Billion Annually for 20+ years *
*
***

NYMEX Gas Breakeven Price ($/MMBtu) for 10% Return WTI Oil Breakeven Price ($/Bbl) for 15% IRR
Presence in the Profitable Plays
14
Source: Credit Suisse; Natural Gas and Oil prices used for breakeven calculations are $4/MMBtu and $90/Barrel, respectively.
Devon and EnLink Midstream Have Significant Presence in Most Prolific and Profitable Shale Plays
$5.37
$5.05
$4.25
$4.13
$3.81
$3.75
$3.70
$3.66
$3.65
$3.34
$3.27
$3.26
$3.02
$2.94
$2.50
$2.47
$1.35
$0.62
$0.29
$0.00
$0.00
$0.00
$0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00
Haynesville/Bossier Shale - NE…
Woodford Shale - Arkoma
Eagle Ford Shale - Dry Gas
Haynesville Shale - Core LA / TX
Piceance Basin Valley
Pinedale
Barnett Shale - Southern…
Barnett Shale
Horn River Basin
Barnett Shale - Core
Fayetteville Shale
Marcellus Shale - SW
Marcellus Shale - NE
Cotton Valley Horizontal
Cana Woodford Shale
Granite Wash - Liquids Rich…
Utica - Wet Gas
Marcellus Shale - SW Liquids…
Mississippian Horizontal - West
Eagle Ford - Liquids Rich
Utica - Liquids Rich
Marcellus Shale - Super Rich
$90.00
$84.45
$74.95
$73.10
$72.15
$68.77
$68.54
$68.52
$66.89
$64.74
$64.63
$64.05
$61.57
$61.57
$59.92
$58.48
$55.29
$55.02
$53.92
$46.10
$46.05
$44.04
$42.15
$32.39
$25.63
$24.23
$20 $40 $60 $80 $100
Cotton Valley Horizontal
Barnett Shale - Southern…
Uinta - Wasatch (V)
Granite Wash - Liquids Rich Horiz.
Uinta - Wasatch (H)
Uinta - Green River
Wolfcamp - N. Delaware…
Bone Spring (3rd) - W TX
Three Forks
Bakken Shale
Wolfberry
Mississippian Horizontal - West
Cana Woodford Shale
Wolfcamp - S. Midland…
Cana Woodford Shale - Oil…
Yeso
Eagle Ford - Oil Window
Bone Spring (1st / 2nd) - NM
Wolfcamp - N. Midland…
Niobrara - Wattenberg
Eagle Ford - Liquids Rich
Utica - Liquids Rich
Mississippian Horizontal - East
Utica - Wet Gas
Marcellus Shale - Super Rich
Marcellus Shale - SW Liquids Rich
EnLink and/or Devon assets are in these plays Neither EnLink nor Devon assets are in these plays

North American Ethylene Plants & Capacities *
** South Louisiana: 10 Plants, 15.0 B Lb/Yr, ~25% of N.A. capacity
12.5%
4 Plants
8.6 B
Lb/Yr
3.3%
2 Plants
2.3 B
Lb/Yr
80%
33 Plants
56.1 B
Lb/Yr**
3.6%
2 Plants
2.5 B
Lb/Yr
0.6%
1 Plant
0.4 B
Lb/Yr
* Source: En*Vantage, April 2014; Chart represents the maximum capability to
crack ethane at S. LA ethylene plants versus the maximum capability to extract
ethane in Louisiana.
0
100
200
300
400
500
600
700
2012 2013 2014 2015 2016 2017 2018 2019 2020
New World-Scale Plant
Conversions/Expansions/Restarts
2012 Ethane Cracking Capability
LA Gulf Coast Ethane Extraction Capability
South Louisiana Ethane Balances *
Global Shift in Petrochemical Industry
15
U.S. Petrochemical Producers in Gulf Coast have tremendous demand for NGLs, and there is now a shortfall of locally
produced supply in South Louisiana*

 Near-term focus on
platform expansion
opportunities
 Longer-term focus on
pursuing scale
positions in new
basins, especially in
areas where Devon is
active
 South Louisiana
Liquids Expansions –
Cajun-Sibon
 West Texas Gas
Expansions – Bearkat
 Other focused areas
for growth
 Potential Areas where
Devon Needs
Infrastructure
̶ Eagle Ford
̶ Permian Basin
̶ Oklahoma
̶ New Basins
Destination 2017:
The Four Avenues for Growth
16
 E2 dropdown
 Dropdown of legacy
Devon midstream
assets at ENLC
 Access Pipeline
dropdown
 Eagle Ford Victoria
Express Pipeline
dropdown
Dropdown
Opportunities
Growing
With Devon
Organic Growth
Projects
Mergers &
Acquisitions
AVENUE 1 AVENUE 2 AVENUE 3 AVENUE 4

Devon Energy
Sponsorship
John Richels,
Chief Executive Officer
of Devon Energy Corporation
17

Devon Overview
Sharpening The Focus
18
Devon’s Core & Emerging Assets
Core
Emerging
Heavy Oil
Rockies Oil
Mississippian-
Woodford
Barnett Shale
Permian Basin
Anadarko Basin
Eagle Ford
(1) Excludes non-core assets identified for monetization.
 Proved reserves: 2.6 billion BOE(1)
 2014e net production: 580 – 620 MBOED(1)
̶ Expect multi-year oil growth >20%
̶ Oil & liquids ≈55% of 2014e production
 Deep inventory of oil opportunities
̶ Top-tier Eagle Ford development
̶ Strong Permian Basin position
̶ World-class steam-assisted-gravity-drainage
(“SAGD”) oil projects
̶ Upside potential in emerging plays
 Midstream business valued at >$7 billion
 Devon’s Enterprise Value: ≈$35 billion

Sharpening The Focus
Devon’s Recent Strategic Actions
 Innovative midstream combination
 Accretive Eagle Ford acquisition
 Announced non-core asset sales
19

Permian Basin
28%
21%21%
7%
5%
11%
2% 5%
Note: Capital figures exclude capitalized G&A and interest, midstream and other corporate capital. For 2014, this
represents approximately $1.4 billion.
Key Highlights
 Devon 2014 E&P capital expenditures:
— “Go-forward” assets: $4.8 - $5.2 billion
— $260 million attributable to non-core properties
 Capital concentrated in oil development plays
— “Go forward” assets delivering >70% growth in
U.S. oil production
— Long-term investment in Canadian oil growth
— “Go forward” assets growing top-line production ≈10%
 Total capital spend to remain within cash flow
 JV carries minimize capital costs in emerging
oil plays (>$1 billion of drilling carries in 2014)
Devon’s 2014 Capital Budget
$5.0 - 5.4 Billion
Eagle Ford
Heavy Oil
Anadarko Basin
Barnett Shale
Emerging Oil
Other
Non-Core Assets
2014 E&P Capital Program
Delivering Strong Oil Growth
20

Permian Basin
2014 Focus Areas
 Devon Net acreage: 1.3 million
basin-wide with stacked-pay potential
 Q4 2013 net production: 86 MBOED
(≈60% oil)
 Deep inventory of low-risk projects
 Delivering highly economic & robust
production growth
— Expect ≈20% oil growth in 2014
 Operated rig count: 23
 2014 E&P capital: $1.5 billion
 2014 plans: Drill ≈350 wells
Midland
Basin
Northwestern
Shelf
Central
Basin
Platform
Ozona ArchDiablo
Platform
NewMexico
Texas
Midland
Wolfberry
Conventional Wolfcamp
Shale
Eastern
Shelf
Bone Spring
& Delaware
TEXAS
NEW MEXICO OKLAHOMA
21

Eagle Ford
World-Class Oil Asset
 Located in best part of Eagle Ford
 Devon Net acreage: 82,000
— Working interest: 50%
— Net revenue interest: 38%
 Acquisition closed on February 28th
 2014e net production: 70 – 80 MBOED(1)
— 57% Oil & Condensate
— 19% NGLs
— 24% Gas
 Risked resource: ≈400 MMBOE
 Drilling inventory: ≈1,200 locations
 2014 E&P capital: $1.1 billion
— Drill ≈200 wells
Karnes
Devon Acreage
Gonzales
DeWitt
Lavaca
TEXAS
OKLAHOMA
(1) Represents Devon’s average estimated net production from March through December 22

Ft. McMurray
Edmonton
Calgary
ALBERTABRITISH
COLUMBIA
Jackfish & Pike
Jackfish 1
Jackfish 2
Jackfish 3
Access Pipeline
R8 R7 R6 R5 R4
T76
T75
T74
T73
Jackfish Acreage (100% WI) Pike Acreage (50% WI) Access Pipeline
(50% Ownership)
Pike Project Area
6 Miles
Jackfish 1
 Facility running at peak capacity
 Delivering top-tier operating results
Jackfish 2
 Q4 production increased >30%
sequentially
 New well pad ramping up
Jackfish 3
 Plant start-up expected in Q3 2014
Pike
 Expect phase 1 sanctioning decision
and regulatory approval in 2014
Heavy Oil – Jackfish & Pike
SAGD Oil Development
23

Net risked resource: >25 TCFE
Risked locations: >10,000
 Devon net acreage: >950,000
 Low average royalty burden: <20%
 Q4 2013 net production: 1.9 BCFED (30% liquids)
 Significant free cash flow (≈$1 billion in 2014)
 Operated rig count: 4
 2014 E&P capital: $600 million
Basin
Wheeler
Hemphill
Canadian
Blaine
Caddo
Johnson
Tarrant
DentonWise
Parker Ft. Worth
Denton
Oklahoma City
Barnett Shale
Net Acres: >600,000
Q4 Production: >1.3 BCFED
Operated Rigs: 2
Anadarko Basin
(Cana & Granite Wash)
Net Acres: >350,000
Q4 Production: 512 MMCFED
Operated Rigs: 2
Barnett Shale & Anadarko Basin
Liquids-Rich Gas
24

Mississippian-Woodford & Rockies
Emerging Oil Opportunities
 Multiple oil-bearing intervals
 Best wells to-date: IP’s >1,000 BOED
 Drilling activity focused on JV acreage
 Improving consistency
 Integration of 3D seismic will optimize
 2014 E&P capital: ≈$300 million
 2014 plans: Drill >200 wells
Rockies Oil
 Focused in the Powder River Basin
 Stacked oil targets (Parkman, Turner, Frontier & others)
 Best wells to-date: IP’s >1,000 BOED
 2014 E&P capital: ≈$300 million
Rockies Oil
Net Acres: 150,000
Q4 Production: 21 MBOED
Operated Rigs: 3
Net Trend Acres: >600,000
Dec Net Production: 16,000 BOED
Operated Rigs: 8
WYOMING
OKLAHOMA
25

Why EnLink Is Important to Devon
 Devon retains majority ownership
— GP (ENLC 70%)
— MLP (ENLK 52%)
 EnLink transaction highly accretive
to shareholders
— Initial transaction valued contributed
assets at $4.8 billion
 Market value of Devon’s EnLink
ownership interest: >$7 billion
 Improves capital efficiency, diversification,
scale and growth of midstream business
AUSTIN
CHALK
EAGLE
FORD
PERMIAN
BASIN
CANA-WOODFORD
ARKOMA-
WOODFORD
BARNETT
SHALE
HAYNESVILLE
& COTTON
VALLEY
UTICA
MARCELLUS
LA
TX
OK
OH
WV
PA
Gathering System
Processing Plant
Fractionation Facility
North Texas Systems
Louisiana Gas System
Louisiana NGL System
Cajun-Sibon Expansion
Howard Energy
Ohio River Valley Pipeline
Storage
Crude & Brine Truck Station
Brine Disposal Well
Barge Terminal
Rail Terminal
Condensate Stabilizers
26

Potential Drop Down Asset
Access Pipeline (SAGD Oil Midstream)
 Three ≈180 mile pipelines from Sturgeon
Terminal to Devon’s thermal acreage
 ~30 miles of dual pipeline from Sturgeon
Terminal to Edmonton
 Devon ownership: 50%
 Capacity net to Devon (after 2014 expansion):
— Blended bitumen: 170 MBPD
— Diluent: 95 MBPD
 Expandable with additional investment
 Access to Edmonton refining and rail,
West Coast waterborne and U.S. markets
 Flexibility enhances economics
EDMONTON
HARDISTY
Express P/L
To U.S. Rockies
16” Diluent Line (Edmonton to Jackfish Area)
Oil Pipelines
JACKFISH & PIKE
Sturgeon Terminal
24” Diluent Line (Sturgeon to Jackfish Area)
42” Blend Line (Jackfish Area to Sturgeon)
30” Blend Line (Sturgeon to Edmonton)
27

Potential Drop Down Asset
Victoria Express Pipeline (VEX) (Eagle Ford)
 ≈56 mile crude oil pipeline from Eagle
Ford core to Devon’s Port of Victoria
terminal
 50 MBOPD start-up capacity (expandable for
3rd parties)
 ≈300,000 barrels of storage available
 VEX commissioning to begin early Q3
 Provides additional market options
for crude and condensate
 Devon ownership: 100%
 Total current project capital: $70 MM
(≈1/2 of capital spent by GeoSouthern)
Point Comfort
Port of Victoria
Karnes
Gonzales
DeWitt
Lavaca
Victoria
Jackson
Goliad
Wharton
Colorado
Calhoun
Refugio
Aransas
Matagorda
VEX Potential Expansion
VEX Under Construction
Devon Acreage
Gulf of
Mexico
28

Potential for additional midstream activity in:
 Eagle Ford
 Permian Basin
 Oklahoma
 New basins
Other Potential Midstream Activity
29

The Four Avenues
for Growth
Barry E. Davis,
President & Chief Executive Officer
Michael J. Garberding,
EVP & Chief Financial Officer
30

 Near-term focus on
platform expansion
opportunities
 Longer-term focus on
pursuing scale
positions in new
basins, especially in
areas where Devon is
active
 South Louisiana
Liquids Expansions –
Cajun-Sibon
 West Texas Gas
Expansions – Bearkat
 Other focused areas
for growth
 Potential Areas where
Devon Needs
Infrastructure
̶ Eagle Ford
̶ Permian Basin
̶ Oklahoma
̶ New Basins
Destination 2017:
The Four Avenues for Growth
31
 E2 dropdown
 Dropdown of legacy
Devon midstream
assets at ENLC
 Access Pipeline
dropdown
 Eagle Ford Victoria
Express Pipeline
dropdown
Dropdown
Opportunities
Growing
With Devon
Organic Growth
Projects
Mergers &
Acquisitions
AVENUE 1 AVENUE 2 AVENUE 3 AVENUE 4

Avenue 1: Future Dropdowns
Devon Sponsorship Creates Dropdown Opportunities
32
Estimated Capital Cost:
$80 MM
Estimated Cash Flow:
~$12 MM
$1.0 B
~$150 MM
Acquisition Cost:
$2.4 B
~$200 MM
$70 MM
~$12 MM
2014 2015 2016 2017
Devon Sponsorship Provides Potential for ~$375 MM of Cash Flow from Dropdowns
Other Potential Devon Dropdowns
E2 Legacy Devon Midstream Assets
Access Pipeline
Victoria Express
Pipeline
Cautionary Note: The information on this slide is for illustrative purposes only. No agreements or understandings exist regarding the terms of these potential dropdowns, and Devon is not
obligated to sell or contribute any of these assets to EnLink. The completion of any future dropdown will be subject to a number of conditions. The capital cost and cash flow information
on this slide is based on management’s current estimates and current market information and is subject to change.

Note: Capital spend figures exclude capitalized G&A and interest, midstream and other corporate capital. For 2014, this represents approximately $1.4 billion.
Devon 2014 E&P Capital Budget
$5.0 - 5.4 Billion
Avenue 2: Growing With Devon
Serving Devon’s Needs is a Priority
 Devon has significant financial incentive to contract
midstream development with EnLink
̶ 70% ownership of ENLC, 52% ownership of ENLK
̶ Once EnLink enters the 50% level of the splits,
approximately $0.60 of each incremental $1.00
distributed by EnLink goes to Devon
 Devon has historically spent $350-$700 MM annually
on midstream capital expenditures
28%
21%21%
7%
5%
11%
2% 5%
Permian Basin
Eagle Ford
Heavy Oil
Anadarko Basin
Barnett Shale
Emerging Oil
Other
Non-Core Assets
$0
$100
$200
$300
$400
$500
$600
$700
$800
2011 2012 2013 2014E
Devon Historical Midstream
Capital Expenditures
($MM)
33

Avenue 3: Organic Growth
Significant Organic Growth Projects
Already Underway
34
South Louisiana
Platform Expansion
• Focused on bolt-on expansions around premier
South Louisiana liquids position
• Cajun-Sibon expansion expected to be operational in 2014
• Increasing utilization of existing NGL asset base
West Texas
Platform Expansion
3rd Party Growth
Around Legacy Devon
Midstream Assets
• Significant bolt-on expansion opportunities around Cana-Woodford
and Barnett Shale assets
• Commercial teams currently in discussions with various potential
producers
Expand Canadian Oil
Sands Presence
• Access Pipeline creates platform for significant growth in Alberta
Canada
• Will have commercial teams looking at additional expansions and
services
• Focused on providing associated gas processing and high pressure
gathering services
• Bearkat plant and high pressure gathering pipelines expected to be
complete in 2014
• Excess pipeline capacity opportunity for continued growth

Avenue 4: Mergers & Acquisitions
 Near-term focus on platform expansion opportunities
 Longer-term focus on pursuing scale positions in new basins, especially in
areas where Devon is active
 Superior financing capabilities already in place
̶ Low cost of capital with investment grade balance sheet (BBB / Baa3)
̶ Significant flexibility with approximately $1.0 billion of liquidity at ENLK
 Potential to pursue strategic acquisitions jointly with Devon
35

EnLink Midstream Today & Tomorrow
EnLink Midstream
Today
EnLink Midstream
Potential Future in 2017
36
South Louisiana
Growth: Cajun-Sibon
West Texas
Growth: Bearkat
Victoria
Express
Dropdown
Complete
E2
Dropdown
Complete
Other Potential Step Changes
Other
Growth
Factors
• Growth from Serving Devon
• Mergers & Acquisitions
Potential
for $375 MM
of Additional Cash
Flows from
dropdowns
Heavy Oil
Access
Pipeline
Dropdown
Complete
CANADIAN
OIL
SANDS
Significant
Organic Growth
Projects
Underway
Midstream
Holdings
Dropdown
Complete

Natural Gas
Assets
Steve Hoppe,
EVP, President of Gathering, Processing and
Transportation
Mike Burdett,
SVP of Commercial Development
Brad Iles,
SVP of Business Development
Stan Golemon,
SVP of Engineering 37

Natural Gas Gathering, Processing and
Transportation Business Unit
$126
$114
North Texas
 Gas gathering
 Gas processing & NGL fractionation
 Condensate stabilization
 Gas Transportation
Oklahoma
 Gas gathering
 Gas processing
 Condensate stabilization
West Texas
 Gas gathering
 Gas processing & NGL fractionation
Gas Business Unit Q2-Q4 2014 Forecasted
Segment Cash Flow:
~ $420 MM *
Gas
76%
38
Liquids
24%
* Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.

Devon Contracts Provide Cash Flow
Stability in North Texas and Oklahoma
 Term: 10 year initial term (acreage dedication), year-to-year thereafter; 5 year minimum volume commitment
 Financial terms: Per-MMbtu fees for gathering and processing with CPI escalator
 Volume Commitment: Approximately 88% of expected volumes for the 12 months ending 9/30/2014
 Gathering and Processing Obligation: EnLink Midstream obligated to gather and process on a firm basis
 Downstream Marketing: Devon is responsible for nominations and scheduling of redelivered residue gas, condensate and
NGLs
 Well Connections: EnLink Midstream is responsible for connecting wells located within three miles of the pipeline system at
its cost; at greater than three miles, EnLink Midstream has the right, but not the obligation to connect wells
Contract
Contract
Term (Years)
Minimum
Gathering
Volume
Commitment
(MMcf/d)
Minimum
Processing
Volume
Commitment
(MMcf/d)
Minimum Volume
Commitment
Term (Years)
Annual Rate
Escalator
Bridgeport gathering and processing contract 10 850 650 5 CPI
East Johnson County gathering contract 10 125 - 5 CPI
Northridge gathering and processing contract 10 40 40 5 CPI
Cana gathering and processing contract 10 330 330 5 CPI
Legacy Devon Midstream assets supported by fee-based contracts with minimum volume guarantees for five years
39

North Texas Assets
Positioned for Long-Term Performance
Gathering
 3,640 miles of pipeline
 2,600 MMcf/d capacity
Processing
 4 plants 1,100 MMcf/d capacity
 1 Stabilizer 5 MBbl/d
 Truck and rail loading
Fractionation
 1 plant, 15 MBbl/d capacity
Transportation
 Gas Pipelines
̶ 260 miles of pipeline
̶ 1,300 MMcf/d capacity
 NGL Pipelines
̶ 30 Miles
̶ 20 MBbl/d capacity
40

86%
12% 2%
Devon Contracts
Other Fee-Based
Commodity-Based Processing
Key Customers
(most active operators in basin)
North Texas Q2-Q4 2014 Forecasted
Segment Cash Flow: ~ $304 MM *
Contract Mix
North Texas Assets:
Solid Platform – Broad Reach
Key Considerations
 Premier position in Barnett shale
 Largest gatherer and processor in the basin
 Stable cash flow from firm contracts with significant volumes
 Sizable acreage dedications with undrilled locations
 Growth opportunities through consolidations & optimization
41* Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.

North Texas Synergies:
Operational Flexibility
42
Reduced O&M costs or increased revenues
$20 MM annually
Goal
Reduced capital expendituresGoal
 Currently implementing projects that save ~$4 MM annually
 Interconnect systems reducing rental compression
 Flow reconfiguration lowering system pressures / offsetting production declines
 Increased blending of gas to reduce treating costs
 Increased market share by providing producers more alternatives to receipt points, access
markets, lower pressures
 Identified capital savings opportunities of ~$15 MM
 Reduced capital to connect new wells due to larger footprint
 Reduced expansion capital by interconnecting systems to fully utilize installed capacity
 Consolidate operations freeing up equipment for relocation (compressors / plants)

North Texas Assets:
Current Trends and Growth Strategy
5.1 5.2
5.6 5.7
5.2
2009 2010 2011 2012 2013
Average Annual
Production (Bcf/d) *
0
10
20
30
40
50
60
70
80
90
Apr-11
Jul-11
Oct-11
Jan-12
Apr-12
Jul-12
Oct-12
Jan-13
Apr-13
Jul-13
Oct-13
Jan-14
Apr-14
Barnett Shale Current Trends
 Reduced gas well drilling as result of low gas prices
 Producers focused on optimizing base production
Our Growth Strategy
Short Term
 Optimize combined systems
 Enhance customer services
 Execute identified expansion projects
Long Term
 Expand systems & customer base
• Extend into new production areas
• Support 3rd party and Devon activities & opportunities
• Acquire and consolidate other assets
43
Barnett Shale Rig Count **
* Source: Power Shale Digest
** Source: Baker Hughes

Oklahoma Assets:
Solid Platform for Bolt-On Projects
Cana
 Gathering
• 410 miles of pipeline
• 530 MMcf/d capacity
 Processing
• 1 plant
Northridge
 Gathering
• 140 miles of pipeline
 Processing
• 1 plant
$114
$126
Scoop
Stack
Arkoma
Woodford
44

Oklahoma Assets:
Stable Cash Flows and Opportunities for
3rd Party Cash Flows
Key Considerations
 Large acreage commitments
 Stable cash flow from firm contracts with significant volumes
 Many undrilled locations on acreage dedications
 Capacity to expand into several active plays
Scoop
Stack
Arkoma
Woodford
Key Customers
Oklahoma Q2-Q4 2014 Forecasted
100%
Fee-Based Contracts
Contract Mix
45

Oklahoma Assets:
Current Trends
 Reduced gas well drilling due to low gas prices
 Producers focused on optimizing base production
 Increased oil drilling generating associated gas, condensate and
NGL production
Our Growth Strategy
Short Term
 Maximize utilization of regional capacities with
other midstream providers
Long Term
̶ Support 3rd party and Devon activities & opportunities
̶ Extend into new production areas
̶ Develop new midstream infrastructure projects
̶ Acquire and consolidate other assets
46
100
125
150
175
200
225
Oklahoma Rig Count from 2012
to 2014 **
Oklahoma Total
Devon Acreage in Oklahoma *
* Source: DrillingInfo.com

Permian Assets:
A Platform in a Prolific Basin
Gathering
 65 miles of pipeline under
construction
 65 miles of fuel and gas lift
pipeline under construction
 200 MMcf/d capacity
Processing
 1 plant, 58 MMcf/d capacity
(50% interest with Apache)
 1 plant under construction, 60
MMcf/d capacity
 Truck and rail loading
Fractionation
 1 plant, 15 MBbl/d capacity
47

Permian Assets:
Growing From Our Platform
48
Key Customers
• Deadwood:
• Bearkat: Two Producers
Contract Mix
Key Considerations
• Focused on providing high pressure gathering and processing
services for associated gas in extremely active drilling area
• Currently constructing Bearkat facility and high pressure
gathering system
• Expanding from platform that started in 2012 with Deadwood
facility and Mesquite fractionator
Permian Q2-Q4 2014 Forecasted
100%
Fee-Based

Permian Assets: Bearkat Project
Processing and Gathering System Currently Under
Construction
 Builds on success of Deadwood joint
venture with Apache, which was on-time,
on-budget and is near full capacity
 ~ 60 MMcf/d processing plant
 ~65-mi., 12” gathering system with
combined capacity of 200,000 Mscf/d
 ~65-mi., 6” lean gas fuel line – providing
producer fuel and gas lift
 Supported by long-term, fee-based
contracts with multiple producers
 Completion expected in second half of
2014
49

Permian Assets:
Permian Basin Current Trends
 Increased oil drilling generating more associated gas,
condensate and NGL production
 Producers seek reduced wellhead pressures and reliable
residue takeaway in order to maximize crude production
Our Growth Strategy
Short Term
̶ Provide capacity relief for constrained producers
Long Term
̶ Develop new midstream infrastructure projects
̶ Acquire and consolidate other assets
Cline
Shal
e
Wolfcamp
Shale
Midland Basin
Central Basin
Platform
+ N/NW Shelf
Delaware Basin
Source:
Wells – Rig Data
Regions – Apache
Glasscock
County
300
350
400
450
500
550
600
Permian Rig Count from 2011
to 2014 **
50
* Source: Apache
Permian Basin Resource Plays*

Natural Gas Assets:
Potential Growth Projects from 2014-2017
51
North Texas Potential Projects
Consolidation of Midstream Assets / Potential Acquisitions
Compressor and Plant Consolidations
Gathering Expansions
Strategic Interconnects and Flow Reconfigurations to Lower Pressures
Oklahoma Potential Projects
Interconnects w/ 3rd Party Pipes to Maximize Existing Capacities
Various Gathering and Plant Expansions
Permian Potential Projects
Bearkat Processing Expansions
Various Bearkat Gathering Expansions

Mac Hummel,
EVP, President of NGL and Crude
Chris Tennant,
VP of NGL
Stan Golemon,
SVP of Engineering
Paul Weissgarber,
SVP of Ohio River Valley
Liquids Assets
52

Liquids Business Unit
Louisiana
 NGL gathering and transportation
 NGL fractionation
 NGL storage
 Crude handling
 Natural Gas transportation
 Natural Gas processing
Ohio River Valley (ORV)
 Crude/Condensate transportation
 Crude/Condensate storage
 Brine Disposal
 Condensate Stabilization &
Gas Compression
53
$126
$114
Liquids Business Unit Q2-Q4 2014
Forecasted Segment Cash Flow:
~ $133 MM *
Gas
76%
Liquids
24%

Cajun-Sibon Expansion:
Game Changer for EnLink in the Gulf Coast
 258 miles of NGL pipeline from Mont Belvieu area to NGL fractionation assets in
south Louisiana (195 miles new, 63 miles re-purposed)
 140 MBbl/d south Louisiana fractionation expansion
 Phase I completed fourth quarter 2013; Phase II projected completion in fourth
quarter 2014
 Expected run-rate adjusted EBITDA of Phase I and Phase II approximately $115
MM
54

Louisiana Assets:
Growing Gulf Coast Capabilities
Crude Handling
 2 terminals
 ~18 MBbl/d capacity
Natural Gas
Transportation
 2,000 miles of intra-
state pipelines
 2.0 Bcf/d of capacity
Natural Gas Processing
 6 plants
 2.5 Bcf/d of capacity
NGL Transportation
 120 MBbl/d capacity
post-Cajun-Sibon
 789 miles of NGL
pipeline in service
 119 miles of NGL
pipeline under
construction
NGL Fractionation
 3 plants, 95 MBbl/d
capacity
 1 plant under
construction, 100
MBbl/d capacity
NGL Storage
 3.2 MMBbl of
underground NGL
storage capacity
55

 ~139 mile, 12-inch NGL pipeline from Mt. Belvieu to Eunice with NGL
capacity of 70,000 Bbl/d
 Expansion of Eunice NGL fractionator from 15,000 to 55,000 Bbl/d
 Completed in Q4 2013
Cajun-Sibon Expansion – Phase I:
Complete
56

 Adding pumps to expand NGL pipeline capacity from 70,000 to 120,000 Bbl/d
 100,000 Bbl/d fractionator at Plaquemine under construction
 Converting Riverside fractionator to Butanes-plus facility
 Extending Bayou Jack lateral by 32 miles to Plaquemine
 Building ~57 miles of additional NGL pipelines
 Expected run-rate adjusted EBITDA of Phase I and Phase II approximately $115 MM
Cajun-Sibon Expansion – Phase 2:
Expected completion in Q4 2014
57

Louisiana NGL Assets:
Linking North American Supply to
Louisiana Demand
Key Customers / Suppliers
Contract Mix
Key Considerations
 Cajun-Sibon expansion provides access to North American NGL
length flowing into Mont Belvieu and access to additional deal flow
 Increased Louisiana NGL demand and insufficient Louisiana supply
creates further expansion opportunities
 NGL fractionation assets in south Louisiana provide flexibility and
value
Louisiana NGL Q2-Q4 2014 Forecasted
Segment Cash Flow: ~$55 MM *
100%
Fee-Based
58

Louisiana NGL Assets:
Current Trends
 Louisiana industrial complex built to take advantage of offshore supply
now reliant on non-Louisiana supplies
 Infrastructure growing to connect NGL oversupply in Mont Belvieu area
with NGL shortfall in Louisiana
 Numerous industrial growth projects drive increased ethane demand
due to attractive pricing and subsequent advantages garnered by U.S.
petrochemical companies
Our Growth Strategy
Short Term
 Fully utilize existing assets
 Secure additional supply via spot/seasonal deals, transloading of raw
make and other disadvantaged supplies
 Assist customers in managing supply security and delivery flexibility
Long Term
 Optimize supply, capacity and logistics across basins and hubs
 Expand Cajun-Sibon platform through bolt-on growth projects or
acquisitions
 Rationalize EnLink and Devon NGL supply positions
0
100
200
300
400
500
2013 2018
Supply Demand
0
10
20
30
40
50
60
Global Ethylene Cash Costs **
(Cents per Lb of Ethylene)
Mid-East
Ethane
Canadian
Ethane
U.S.
Ethane
Mid-East
Propane
W. Euro
Naphtha
SE Asia
Naphtha
NE Asia
Naphtha
59
Louisiana Ethane Supply/Demand *
(MBbl/d)
* Source: Hodson Report, February 2013
** Source: En*Vantage

Louisiana Crude Assets:
Terminals at Eunice and Riverside Facilities
60
Key CustomersKey Considerations
 Crude assets at Eunice and Riverside with attractive rail,
truck and barge capabilities
 Well positioned to service local demand and local supply
as it develops
 Well positioned via rail service for Canadian and other
regional supplies
 Riverside terminal provides $10 MM of annual Adjusted
EBITDA under firm contract
Nearburg Producing
Louisiana Crude Q2-Q4 2014 Forecasted
Contract Mix
100%
Fee-Based

Louisiana Crude Assets:
Current Trends
 Dramatic growth in U.S. crude production
 Significant crude supplies moving by truck and rail
with producers increasingly involved with logistics
 Condensate supply growing with more competitive
pricing
 Growing discussions about exports
Our Growth Strategy
Short Term
• Increase asset utilization with pipeline supplies,
Riverside rail-to-barge loading and Eunice rail-to-truck
trans-loading
• Purchase crude at the lease and utilize assets to
capture blending uplifts and regional arbitrage
opportunities
Long Term
• Expand Riverside terminal to provide unit train service
for 20 – 40 MBbl/d
• Pursue crude/condensate opportunities with Devon
• Acquire assets complementing existing facilities and
growing footprint
32% 19%
U.S. Crude Production *
61* Source: EIA
** Source: Association of American Railroads
Rail Carloads of Crude Petroleum on
US Class I Railroads from 2003-2015**

Louisiana Natural Gas Assets:
Pipeline and Processing Plant Flexibility
• Largest intrastate gas pipeline system in Louisiana - north
Louisiana assets supported by firm contracts averaging
remaining term of ~4.0 years
• Transportation and processing assets well positioned to
support new Louisiana and Gulf of Mexico supplies
• Mississippi River market area heavily industrialized and
expanding
Pipeline Customers
Louisiana Gas Q2-Q4 2014 Forecasted
74%
26%
Fee-Based
Commodity-Based Processing
Contract Mix
62
Processing Customers

Louisiana Natural Gas Assets:
Current Trends
 Tuscaloosa Marine Shale, Austin Chalk and Deep
Miocene/Wilcox targets continue to attract producer interest
and investment
 Producers refocusing efforts on liquids-richer Cotton
Valley/Bossier targets versus Haynesville
 Louisiana gas demand growing with petrochemical, industrial
and LNG expansions
Our Growth Strategy
Short-Term Strategy
 Maximize existing capacity
 Optimize supply via new connections
 Maximize processing margins and opportunities
 Expand market connectivity to service petrochemical,
industrial and LNG demand along the Mississippi River
Long-Term Strategy
 Pursue strategic acquisitions
 Consolidate inefficient facilities and utilize existing assets in
highest value use
 Expand position as premier Louisiana gas franchise
Capital Spending for Announced Louisiana
Natural Gas Driven Manufacturing **
Louisiana Gas Demand (Bcf/d)
2010 – 2025 *
63* Source: ICF International
** Source: LSU Center for Energy Studies

Ohio River Valley Assets:
Established History of Service
Crude/Condensate Transportation
 200 miles of crude pipeline, 17 MBbl/d
capacity
 2,500 miles of unused right-of-way
 Truck fleet capacity of 25 MBbl/d
 Barge terminal on Ohio River
 Rail terminal on Ohio Central Railroad
Crude/Condensate Storage
 ~600 MBbl of above ground storage
Brine disposal wells
 8 total wells – 6 owned, 2 jointly-owned
64

80%
20%
Fee-Based Crude/Condensate
Fee-Based Brine
Ohio River Valley Assets:
Well Positioned in the Utica and
Western Marcellus
 Pipeline and terminal assets strategically located in Utica’s
condensate-rich window where stabilization requirements
are significant
 Truck fleet provides access to both the Utica and the
Western Marcellus in Pennsylvania and West Virginia
 Establishing “rolling pipeline” via truck fleet until volumes
warrant laying new pipelines
 Brine disposal capacity increasingly stressed ORV Q2-Q4 2014 Forecasted
Segment Cash Flow:~$28 MM *
Contract Mix
65

ORV Assets:
Current Trends
 Producers are delineating their acreage and high-grading drilling
locations
 Condensate supplies from the Utica and Western Marcellus are
growing
 Out-of-region condensate markets will be needed
 Midstream imperatives are high flow assurance and reliable
market outlets
Short Term Growth Strategy
 Establish “rolling pipeline” via truck fleet to capture “first
barrels”
 Optimize our existing assets and businesses in legacy crude and
brine disposal assets
Long Term Growth Strategy
 Complete condensate pipeline and expansion of condensate
stabilization and storage
 Develop premium condensate markets including potentially
building and operating a condensate refinery
 Pursue additional midstream opportunities including gas
gathering and processing and NGL movements
66
15
20
25
30
35
40
45
Jul-12
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
Jan-14
Feb-14
Mar-14
Ohio Pennsylvania West Virginia
* Sources: Ohio Department of National Resources, Pennsylvania Department of Environmental Protection, West Virginia Department of Natural Resources
ORV Rig Count *
ORV Drilling Permits Issued *
0
100
200
300
400
500
600
700
Q3 '12 Q4 '12 Q1 '13 Q2 '13 Q3 '13 Q4 '13 Q1 '14
Ohio Pennsylvania West Virginia

Louisiana Potential Projects
LPG Export Facility
Mixed Heavy NGL Pipeline
Terminal Repurposing
NGL Batching Pipeline
Market-Area Pipeline
ORV Potential Projects
Condensate Refinery
Condensate Pipeline
67
Liquids Assets:
Potential Growth Projects from 2014-2017

Non-Operated
Investments
Brad Iles,
SVP of Business Development
68

Howard Energy Investment:
Strategic South Texas Asset Footprint
Key Customers
Ownership Structure
31%
59%
10%
EnLink Midstream
Alinda Capital Partners
HEP Management
Key Considerations
 Howard Energy Partners (“HEP”) is a high growth midstream
company with a strategically located asset base in South Texas
 Franchise position in western Eagle Ford with access to
multiple producing zones (Eagle Ford, Olmos, Escondido, Pearsall
and Buda)
 Diverse footprint including rich & dry gas gathering,
processing, liquids terminalling and stabilization assets
 ~70% of cash flow underwritten by firm contracts with
minimum volume commitments
69
HEP Q2-Q4 2014 Forecasted
Distribution Income:~$20 MM

E2 Investment:
Innovative Solution to Grow ORV Condensate
Business
Customer
70
E2 Q2-Q4 Cash Flow
Post-Dropdown:~$9 MM
Key Considerations
 E2 is 93% owned by ENLC and 7% owned by E2
management
 E2 is highly skilled management team focused on
building compression and stabilization assets in
the Utica and Marcellus region
 100% fee-based contracts with minimum volume
commitments to ORV growth strategies
 Approximately $80 million invested to date through
EnLink Midstream, LLC with dropdown expected
mid-year 2014
E2 Compression & Condensate Stabilization
 Capacity of 320 MMcf/d and 16,000 Bbl/d
 Two facilities completed, one under construction

Gulf Coast Fractionator Investment:
Serving Devon in Mont Belvieu
71
38.75%
22.50%
38.75%
Key Considerations
 EnLink owns a contractual right to the economics of Devon’s interest in the
Gulf Coast Fractionator (GCF)
 GCF is a partnership between Devon, Targa and Phillips 66 with Phillips 66
serving as the operator
 Located at Mont Belvieu, Texas, GCF has capacity of ~ 120–145 MBbl/d
depending on composition
 GCF provides fractionation services for a large percentage of Devon’s equity
NGLs
Targa
Resources Devon
Phillips 66
GCF Estimated Q2-Q4
Cash Flow:~$9 MM

Financial Outlook
Michael Garberding,
EVP & Chief Financial Officer
72

Sustainable
Growth
Substantial
Scale &
Scope
Diverse,
Fee-Based
Cash Flow
Strong B/S
Credit Profile
73
• Investment grade balance sheet at ENLK (BBB, Baa3)
• Debt/EBITDA of ~3.5x
• ~$1.0 billion in liquidity
• ~ 95% fee-based margin
• Projects focused on crude/NGL services and
rich gas processing
• Balanced cash flow (Devon ~50%)
• Total consolidated enterprise value of ~$14 billion
• Geographically diverse assets with presence in
major US shale plays
• Stable base cash flow supported by long-term contracts
• Organic growth opportunities through Devon’s
upstream portfolio
• Potential additional cash flow from dropdowns: ~$375 million
Louisiana
ORV
Long Term Vision:
EnLink’s Key Financial Attributes

Long Term Vision:
Strong Balance Sheet
 ENLK has investment grade (BBB/Baa3) credit ratings
̶ Leverage target of ≤ 3.5x EBITDA provides access to relatively inexpensive debt capital
 On March 12th, EnLink priced $1.2 billion in senior notes with a weighted-average yield to
maturity of 4.20%:
 Significant liquidity/financial flexibility with $1 Billion revolving credit facility at MLP and $250
MM revolving credit facility at GP
 EnLink’s strong credit position gives it significant capacity to pursue organic growth or
acquisitions
74
EnLink has one of the strongest balance sheets in the industry
2.700% Senior Notes
Due 2019
4.400% Senior Notes
Due 2024
5.600% Senior Notes
Due 2044
Principal Amount $400,000,000 $450,000,000 $350,000,000
Maturity Date 1-Apr-19 1-Apr-24 1-Apr-44
Spread to Treasury +115 bps +170 bps +195 bps
Yield to Maturity 2.732% 4.421% 5.605%

Strong Balance Sheet:
Execution of Financial Synergies
EnLink financing activity has positioned the company to realize financial synergies of over $35 MM
annually compared to Crosstex standalone
 Refinancing $725 MM of 8.875% bonds due 2018
̶ Including call / tender premium, total cost to retire of ~$760 MM
̶ Weighted-average interest rate on new bonds of 4.2% results in annual interest savings of ~$32 MM
 Equity claw redemption of $53.5 MM of 7.125% bonds due 2022
̶ Including redemption premium, cost to retire of ~$57 MM
̶ Annual interest savings of ~$1.4MM
 Reduction in letters of credit of ~$44 MM
̶ Annual interest savings of ~$1.3 MM
 Reduction in revolving credit facility interest and fees
̶ Reduction in undrawn commitment fee from 0.5% to 0.175%
̶ Reduction in drawn spread from +300bps to +125bps at current EnLink ratings
75
At the time the merger was announced, EnLink guided the market to expect
financial synergies of $25 million

Long Term Vision:
Stable and Diversified Cash Flows
76
Each of EnLink Midstream’s segments benefits from the stability provided by long-term, fee-based contracts
Segment / Key Contract
% of Q4 2014
Segment
Cash Flow
Texas
New Devon Bridgeport Contract - 10 years with 5 year MVC
85%
New Devon East Johnson County Contract - 10 years with 5 year MVC
Existing FT Transmission & Gathering - Volume Commitments with remaining terms of 2-10 years
Apache Deadwood Plant - Dedicated interest with 8.5 years remaining on 10 year term
Bearkat Plant - Volume Commitment with 10 year term from initial flow
Oklahoma
New Devon Cana Contract - 10 years with 5 year MVC
100%
New Devon Northridge Contract - 10 years with 5 year MVC
Louisiana
North LIG Firm Transport - Reservation fee with avg remaining life of 4 years
70%
Firm Treating & Processing - Remaining term minimum 2 years
Cajun-Sibon Phases I & II - 5 & 10 year agreements for supply and sale of key products
ORV
E2 Compression / Stabilization Contract - 7 years ~30%
% of Total Segment Cash Flow in Q4 2014 ~80%
Note: Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.

Long Term Vision:
Sustainable Growth
77
Distribution growth targets are high single digits for MLP and 20% plus for GP
2014 2015 2016 2017
Estimated Capital Cost: $80
MM
~$12 MM
$1.0 B
~$150 MM
Acquisition Cost:
$2.4 B
~$200 MM
Estimated Capital Cost: $70
MM
~$12 MM
Other Potential Devon Dropdowns
E2 Legacy Devon Midstream Assets
Access Pipeline
Victoria Express
Pipeline
Cautionary Note: The information on this slide is for illustrative purposes only. No agreements or understandings exist regarding the terms of these potential dropdowns, and Devon is not
obligated to sell or contribute any of these assets to EnLink. The completion of any future dropdown will be subject to a number of conditions. The capital cost and cash flow information
on this slide is based on management’s current estimates and current market information and is subject to change.

2014 EBITDA & Volumes Forecasts
Q2-Q4 2014 Combined
Annualized EBITDA:
~ $675 MM *
57%
19%
19%
5%
Texas Louisiana Oklahoma ORV
Midstream Service:
Q2 - Q4 2014
Forecasted
Volumes
Texas
Gathering and Transportation (MMBtu/d) 2,968,000
Processing (MMBtu/d) 1,022,000
Louisiana
Gathering and Transportation (MMBtu/d) 499,000
Processing (MMBtu/d) 585,000
NGL Fractionation (Gals/d) 3,570,000
Oklahoma
Gathering and Transportation (MMBtu/d) 389,000
Processing (MMBtu/d) 391,000
ORV
Crude/Condensate Handling (Bbls/d) 1
28,000
Brine Disposal (Bbls/d) 7,000
1. Includes crude/condensate handling by both the ORV and Louisiana segments.
* Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income. 78

Key Performance Drivers
Short Term Performance Drivers
 Timing and execution of Cajun Sibon II and Bearkat Projects
 Drilling activity in Barnett and Oklahoma
 Remediation of Bayou Corne Sinkhole
 Timing/amount of operational synergies
 Timing of Utica condensate production and ORV execution
Long Term Performance Drivers
 Potential additional cash flow from dropdowns: $375 million
 Stable cash flows from long-term Devon contracts
 Organic development in west Texas and south Louisiana
 Organic development with Devon
79

2014 Consolidated Capital Expenditures
80
Potential long term capital spending of $1.0 billion - $2.0 billion per year with drop downs
$200 MM
$194 MM
Cajun-Sibon
Bearkat
Other
$50 MM
Legacy
DVN
$46 MM
Growth Capex *
Q2-Q4 ‘14 Combined: ~$490 MM
$43 MM
$12 MM
$7 MM
Texas
Oklahoma
ORV
$2 MM
Louisiana
Maintenance Capex *
Q2-Q4 ‘14 Combined: ~$65 MM
* Growth capital expenditures and maintenance capital expenditures are non-GAAP financial measure and are explained in greater detail on page 3.

ENLC Tax
 ENLC has three principal sources of cash flow, each with different level of
exposure to federal income tax
̶ GP Distributions/IDRs: ENLC receives an allocation of taxable income in the amount of its IDR
distributions such that they are fully taxable
̶ LP Distributions: Distributions from ENLK to ENLC receive a lower tax shield (about 50%) than
public unit holders
̶ Income from EnLink Midstream Holdings: Taxable income is estimated to be at ~70% of cash flow
in 2014
 ENLC also receives deductions for its direct interest expense, G&A Costs, etc.
 Results in an effective tax rate of ~20% in 2014 before the application of net
operating loses (NOLs)
̶ Includes one-time benefit from transaction related expenses
 As dropdowns are executed, the composition of ENLC’s cash flow streams, and
therefore its effective tax rate will change
̶ Degree of tax shield on LP distribution may also change over time
 ENLC also has available $146 MM in federal NOL carry forwards
̶ After NOL usage, ENLC currently estimates minimal 2014 cash taxes
81

Closing Remarks
Barry Davis,
President & CEO
82

Key Takeaways
83
The right team in place
Strategically located and complementary assets
Stability of cash flows
Strong sponsorship support from Devon
Continued focus on organic growth projects

Reconciliation: Segment Cash Flow to
Operating Income
85
(Amounts in MM) Q2-Q4 Forecasted
‪ Total business unit segment cash flow $555
‪ Shared services (26)
‪ General and administrative expenses (53)
‪ Other * (14)
‪ Depreciation, amortization and impairment (215)
Operating Income $247
* Other includes stock based compensation and loss on debt extinguishment

Reconciliation: Net Income to Consolidated
Adjusted EBITDA
86
(Amounts in MM) Q2-Q4 Annualized
‪ Net Income $287
‪ Interest expense 45
‪ Depreciation, amortization and impairment 287
‪ Net distribution from equity investments 40
‪ Other * 16
Consolidated Adjusted EBITDA $675
* Other includes taxes, stock based compensation and other non-cash items

2014 Analyst & Investor Day Highlights

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2014 Analyst & Investor Day Highlights