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2015 Analyst & Investor Day

March 30, 2015

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; 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; a failure in its computing

systems or a cyber-attack on its systems; 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, 2014, 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, adjusted EBITDA of EMH, 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. Adjusted EBITDA of EMH is defined as earnings plus depreciation, provisions for income

taxes and distribution of equity investment less income on equity investment. 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. 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. 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, adjusted EBITDA of EMH, 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.

Reconciliations of these measures to their most directly comparable GAAP measures are included in the Appendix to this

presentation.

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

5

• Barry Davis President & CEO

• Michael Garberding EVP & CFO

EnLink Midstream

Vision & Strategy

• David Hager Devon Energy Corporation, COO Devon Energy

Sponsorship

Presenter & Panelist

• Steve Hoppe EVP, President of Gas Business Unit

Panelists

• Mike Burdett SVP of Commercial

• Andy Deck SVP of Permian Basin

• Stan Golemon SVP of Engineering & Operations Services

• Ben Lamb SVP of Finance & Corporate Development

Natural Gas

Businesses

Vision & Panel

Presenter & Panelist

• Mac Hummel EVP & President of Liquids Business Unit

Panelists

• Ben Lamb SVP of Finance & Corporate Development

• Shannon Flowers VP of Crude

• John Pellegrin VP of Commercial

• Chris Tennant VP of NGL

Liquids

Businesses

Strategic Vision

& Panel

• Michael Garberding EVP & CFO Financial Overview

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 Energy evolved into a significant

service provider in the energy industry’s midstream business sector.

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 Business Unit

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’s executive management team is comprised of former Crosstex and Devon

senior management and other experienced midstream leaders

McMillan (Mac) Hummel

EVP & President of

Liquids Business Unit

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

6

Experienced Executive Management Team

with a Proven Track Record

Built for the Road Ahead:

Executing on Our Growth

Strategy

Barry E. Davis, President and Chief Executive Officer

7

Strong, Diversified Investment in the MLP Space

8

Designed for Safety, Stability & Growth

Stability of cash flows ~95% fee-based contracts

~50% of gross operating margin from long-term Devon contracts

Top tier midstream energy service for our customers Mastio Service Award winner in 2014

Leverage Devon Energy sponsorship for growth Expect significant growth from dropdowns

Serve Devon E&P portfolio in its growth areas

Strong organic growth South Louisiana, West Texas and Ohio River Valley (ORV) expansion projects

Top-tier balance sheet Investment grade credit rating at ENLK since inception

Strong liquidity with a $1.5 billion credit facility

Note: Adjusted EBITDA and gross operating margin are non-GAAP financial measures and are explained on page 3.

The Vehicle for Sustainable Growth

Devon is EnLink Midstream’s largest customer

(>50% of consolidated 2015E adjusted EBITDA*)

EnLink Midstream’s growth projects focused on crude/NGL services and rich gas processing

Strong emphasis on fee-based contracts

9

Diverse, Fee-Based Cash Flows

2015E EnLink Midstream Consolidated *

95%

5%

Gross Operating Margin By Contract Type **

Texas 51%

26%

Ohio 6%

17%

Segment Cash Flow By Region **

52% Devon

48% Other

Gross Operating Margin By Customer **

Fee-Based

Commodity

Sensitive

* Based on 2015 Guidance information.

** Gross operating margin, segment cash flow and adjusted EBITDA percentage estimates are provided for illustrative purposes.

Note: Adjusted EBITDA, segment cash flow and gross operating margin are non-GAAP financial measures and are explained on page 3.

Louisiana

Oklahoma

The Vehicle for Sustainable Growth Stable Cash Flows From High Quality Contracts

0%

20%

40%

60%

80%

100%

Texas Oklahoma Louisiana Ohio RiverValley

~80% of EnLink’s segment cash flows are supported by long-term, fee-based contracts with

either firm transport agreements or minimum volume commitments.

Top Customers

Include

~80%

10 Note: Segment cash flow is a Non-GAAP metric and is explained in greater detail on page 3. See Appendix for a reconciliation to Operating Income.

Segment

Cash Flow


Significant Size & Scale

~ 9,100 miles of pipelines

16 gas processing plants, 3.6 Bcf/d capacity

7 NGL fractionators, 280,000 Bbl/d capacity

Diversity of Basins

Barnett

Permian

Midcontinent: Cana & Arkoma-Woodford

Eagle Ford

Ohio River Valley: Utica & Marcellus

Louisiana: demand market (gas, NGLs)

Diversity of Services

Natural Gas: transport, processing, storage & mktng.

NGL: transport, fractionation, storage & mktng.

Condensate: transport, storage & mktng.

Crude: transport, storage & mktng.

11

Powered By a Diverse Set of Assets & Services

EnLink Midstream Partners, LP

Master Limited Partnership NYSE: ENLK

(BBB / Baa3)

EnLink Midstream, LLC

General Partner NYSE: ENLC

Public

Unitholders

~70% ~30%

~1% GP

~17% LP

EnLink Midstream Holdings (formerly Devon Midstream Holdings)

~41%

LP

~41%

LP

Devon Energy

Corp. NYSE: DVN

(BBB+ / Baa1)

GP + 75% LP

12

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

~25%

LP

Note: The ownership percentages shown above is approximate and as of March 20, 2015.

The Vehicle for Sustainable Growth MLP Structure With a Premier Sponsor

First Year Project Execution ~$3.7 Billion of Drop Downs, Growth Projects

and Acquisitions

E2 in Ohio River Valley

25% of EMH

Victoria Express in Eagle Ford (subject

to closing)

AVENUE 1

Dropdowns

~$1.3 Billion

Completed &

Announced

Ajax plant announced and

associated gathering in Permian

~$200 MM+

Announced

AVENUE 2

Growing

With Devon

Cajun-Sibon in TX/LA complete

Bearkat construction in Permian

complete

ORV condensate expansion announced

Marathon-Garyville pipeline announced

~$1 Billion

Completed

~$300 MM+

Announced

AVENUE 3

Organic

Growth

Projects

Chevron Gulf Coast pipelines and

storage in South Louisiana

Coronado Midstream in Midland basin

LPC in Midland basin

~$935 MM

Completed

AVENUE 4

Mergers &

Acquisitions 13

Near-term focus on

acquisitions in and

around current

platforms

Longer-term focus on

pursuing scale

positions in new

basins, especially in

areas where Devon is

active

ORV condensate

expansion

Marathon-Garyville

pipeline

Gas to liquids pipeline

conversions in

Louisiana *

Permian Basin

expansions from

Coronado and LPC

acquisitions

Expansions to Cana

gathering and

processing *

Ajax plant in Permian

14

Access Pipeline in

Canadian Oil Sands

25% of EMH

Additional drop downs

from Devon

Dropdowns *

Growing

With Devon

Organic Growth

Projects

Mergers &

Acquisitions

AVENUE 1 AVENUE 2 AVENUE 3 AVENUE 4

The Four Avenues for Growth Identified Opportunities from 2015 - 2017

* This information is for illustrative purposes only. No agreements, understandings or obligations exist regarding these potential transactions and projects. The completion of any future

drop down will be subject to a number of conditions.

Destination 2017

15

Line of Sight to Double the Size of EnLink

LA

$85 WTI

$4.00 gas

Incremental Adjusted EBITDA

Assets VEX & Access

Pipelines

Cana, Eagle Ford

& Permian

Louisiana,

Permian,

Eagle Ford, Utica

TBD

Estimated Capital VEX: $210-220

MM

Access: TBD

$750 MM –

$1.25 B $1.0 – 1.75 B $1.0 – 2.0 B

Annual Estimated Adjusted

EBITDA by 2017 $130 – 180 MM $90 – 160 MM $100 – 175 MM $125 – 250 MM

Note: The information in this slide is for illustrative purposes only.

* Based on 2015 Guidance. Adjusted EBITDA is a non-GAAP and is explained in greater detail on page 3. See Appendix for a reconciliation to Operating Income.

** Includes price deck and potential basin decline sensitivities

$500

$700

$900

$1,100

$1,300

$1,500

$1,700

2015EAdjusted EBITDA*

DropDowns

Growingwith DVN

OrganicGrowth**

M&A Destination 2017

Adjusted EBITDA ($000)

$ 1.4 B

We’re Just Getting Started Executing on Growth Strategy to Double

In Size By 2017

Powered by strategically located and complementary assets

Generating stable and growing cash flows

Backed by strong sponsorship from Devon

Driven by people with deep industry expertise

Deliver Results Focus on People Be Ethical Strive for Excellence

ENLINK’S CORE VALUES

Built for safety, stability and growth

16

Devon Energy Sponsorship

Dave Hager, Chief Operating Officer

of Devon Energy Corporation

17

E&P Industry

North America is in the midst of a shale revolution

Dramatic positive impact on supply of hydrocarbons

Energy independence in North America is possible

Success creating near-term imbalance between supply and

demand

Altering the global marginal cost curve

Keys to success in current environment

Top-tier assets

Superior execution

Financial strength

18

Where Are We Today?

Devon Today

Focused and balanced portfolio

Proved reserves: 2.8 billion BOE

Net production: 664 MBOED

Upstream revenue: 60% oil

Deep inventory of opportunities

Prolific Eagle Ford assets

High-quality Permian position

World-class heavy oil projects

Top-tier liquids-rich gas plays

Strategic EnLink business to support

growth initiatives

19

A Leading North American E&P

Heavy Oil

Rockies Oil

Barnett Shale

Eagle Ford

Permian Basin

Note: All figures represent Devon’s retained asset portfolio.

Anadarko Basin

Oil Assets

Liquids-Rich Gas Assets

A Leading North American E&P

Premier and sustainable asset portfolio

— High-returning projects

— Positioned in top-tier basins

— Balanced between oil and gas

— Deep inventory of opportunities

Focused on superior execution

— Technical and operational excellence

— Production optimization

Maintain financial strength and flexibility

Strategic midstream business

20

Strategy for Long-Term Success

Strategic Midstream Business

Devon’s equity ownership interest

41% of MLP (ENLK: 120 MM units)

70% of GP (ENLC: 115 MM shares)

Highly accretive transaction

DVN assets initially valued at $4.8 billion

Devon’s ownership interest in ENLK and

ENLC currently valued >$7 billion

Distributions could reach ≈$300 MM in 2015*

GP incentive distributions at highest tier

Initial asset dropdown announced

Victoria Express Pipeline in Eagle Ford

Transaction valued at $210-$220 million

21

EnLink Ownership Overview

* Based on 2015 Guidance.

Note: The ownership information shown above is approximate and as of March 20, 2015

Why EnLink is Important to Devon?

EnLink infrastructure enhances value of E&P production stream

• A competitive advantage in high activity basins

• Ownership interest ensures midstream support of E&P activity

Improves capital efficiency

• EnLink funds majority of midstream capital requirements

• Increases availability of capital to invest in core E&P business

Achieves tax-deferred valuation for midstream assets

Additional asset dropdown potential

Increases diversification, scale and growth trajectory of midstream

business

22

Building Operational Momentum 2014 Highlights

23

Completed portfolio transformation

• Creation of EnLink Midstream

• Accretive Eagle Ford acquisition

• Divested >$5 billion of non-core assets

EnLink drove record midstream profits

Oil production increased 37%

Top-line production 15% higher

Q4 liquids approach 60% of production mix

Proved oil reserves increase to all-time high

Note: All figures represent Devon’s retained asset portfolio.

Disciplined Capital Allocation 2015 Capital Outlook

24

Balances capital with cash inflows

Reduced 20% from 2014

Focused on best development

opportunities

Minimal exploration activity

Organic midstream capital(1):

≈$135 million

Dynamically allocate capital

throughout 2015

(1): Excludes EnLink related capital.

Oil Driving Production Growth 2015 Production & Midstream Outlook

25 Note: All figures represent Devon’s retained asset portfolio.

Oil production growth: ≈20% - 25%

—Driven by Eagle Ford, Permian & Jackfish 3

Top-line BOE growth: ≈5%

Capital efficient growth achievable

with 20% less spend than 2014

Midstream profit expected to reach

another all time high in 2015

Strong Balance Sheet & Liquidity

Strong investment-grade ratings

• Cash balances: $1.5 billion

• Net debt(1): $7.8 billion (excluding EnLink)

Cash flow protected by hedges

• >50% of 2015 oil protected at $91 per barrel

• ≈40% of 2015 gas protected at $4.17 per Mcf

• Fair market value of hedges: ≈$2 billion (12/31/14)

The EnLink Midstream advantage

• Equity ownership interest valued in ENLK and ENLC at >$7 billion

• Cash distributions from EnLink could reach ≈$300 million in 2015

• Midstream asset dropdown potential

26

EnLink Enhances Financial Strength

(1) Net debt is a Non-GAAP measure defined as total debt less cash and cash equivalents and debt attributable to the consolidation of

EnLink Midstream.

Information on this page is as of March 20, 2015

Eagle Ford

Top-tier acreage position

• 82,000 net acres focused in DeWitt

• Q4 net production: 98 MBOED

Highest returning asset in portfolio

• Delivering industry-leading well results

• ≈1,000 undrilled locations in inventory

• 2014 cash margin >$50 per BOE

2015 Outlook: High activity in DeWitt

• 2015 capital: ≈$1.1 billion

• Running 11 to 12 rigs in 2015

27

Overview

Eagle Ford

28

Strategic EnLink Infrastructure

Victoria Express Pipeline

First Devon to EnLink dropdown

transaction *

≈56 mile crude oil pipeline from

Devon’s Eagle Ford core to Port

of Victoria terminal

Operational Flexibility

‒ Pipeline operational capacity:

• ≈ 50,000 Bbl/d currently

• ≈ 90,000 Bbl/d by YE 2015

‒ Storage capacity:

• ≈ 150,000 Bbl currently

• ≈ 360,000 Bbl by YE 2015

* Subject to the closing of the transaction between Devon and EnLink.

Permian Basin

Industry leader in basin

• 1.2 million net surface acres with stacked pay


• Production growth 23% higher in 2014

Deep inventory of low-risk projects

• >5,000 locations in Delaware Basin

• Significant upside from downspacing

Expect to leverage EnLink’s expanding

Permian operations

2015 Outlook: Most active asset

• 2015 capital: ≈$1.3 billion

• Running 13 operated rigs in Delaware Basin

29

Overview

Heavy Oil

Located in best part of oil sands

• Low geologic risk

• Thick and continuous reservoir

• Industry leading operating results

• Massive risked resource: 1.4 BBO

Features of each Jackfish project:

• 300 MMBO gross EUR

• Long reserve life >20 years

• Flat production profile

2015 Outlook: 20%-plus growth

• 2015 capital: ≈$700 million

• Delivering >20% production growth

30

Overview

Heavy Oil Dropdown Potential

Three ≈180 mile pipelines from

Sturgeon Terminal to Devon’s

thermal acreage

≈30 miles of dual pipeline from

Sturgeon Terminal to

Edmonton

Capacity net to Devon:

Blended bitumen: 170 MBOD

Devon ownership: 50%

≈$1 Billion invested to date

31

Access Pipeline

Anadarko Basin

Excellent Q4 results in Cana-Woodford


• Production increased 35% YoY

• 1st operated STACK well brought

online

High-rate development wells in Q4

• Cana results >20% above type curve

• Driven by improved completion design

EnLink infrastructure provides

significant competitive advantage

2015 Outlook: Accelerating Cana

activity

• 2015 capital: $400 million

• Running 8 rigs in 2015

32

Cana-Woodford Overview

Barnett Shale

Significant gas optionality

Net acres: 623,000

Best position in play

Q4 net production: 201 MBOED

Liquids 27% of production mix

EnLink midstream infrastructure

significantly enhances rates of return

Generated free cash flow of $1 billion

in 2014

2015 Outlook

2015 capital: ≈$150 million

Focused on optimizing base

production

33

Overview

Other Potential Midstream Activity

Potential for additional midstream activity in:

Permian Basin

• Delaware Basin

• Northern Midland Basin

Anadarko Basin

• Cana-Woodford

• Emerging STACK opportunity

Eagle Ford

Future business development optionality

• Additional build-out in core assets

• New basins

34

Gas Business Unit

Steve Hoppe, EVP & President of Gas Business Unit

35

Gas Business Unit

36

North Texas, Oklahoma & West Texas

$114 $126

$132

$114

WTX 7%

OK 25%

NTX 68%

2015E

Consolidated

Segment

Cash Flows *

* Based on 2015 guidance projections. 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.

** EnLink Midstream and Apache Corp. each have 50% ownership interest in the Deadwood facility.

North Texas

• Largest gatherer and processer in

Barnett Shale

• Basin has a long and stable future

• Supported by long-term contracts with

Devon Energy and third parties

Oklahoma

• Expecting growth in Cana

• Supported by long-term contracts with

Devon Energy and third parties

• Opportunities to expand in developing

areas

West Texas

• Core growth area in prolific Midland

Basin

• Recently announced ~$1.25 - $1.45 B

in acquisitions and growth projects

**

North Texas Significant Platform Position With

Long-Term Future

Key Customers

Segment Cash Flows $MM

Key Takeaways

• Basin has a long, stable

future

• Focus on increasing market

share and offsetting declines

• Excellent upside in improved

commodity environment

$440 $380

2014 * 2015E **

68% 82%

Gas G&T ProcessingUtilization Capacity

1.2 Bcf/d

Capacity

4.0 Bcf/d

Capacity

2014 Utilization

2015 Contract Structure

86% (77% of total with MVCs)

12% 2% Devon Fee-Based

Other Fee-Based

Commodity-BasedProcessing

37 * Represents Q2-Q4 2014 annualized segment cash flows

** Based on 2015 Guidance

Note: Segment cash flow is a Non-GAAP metric and is explained in greater detail on page 3. See Appendix for a reconciliation to Operating Income.

North Texas Opportunities Acquisition, Consolidation & Optimization

Optimization

• Significant refrac and

recomplete potential

• Targeting pressure

reduction projects offsetting

decline

Increase Market Share

• Positioned to be basin

consolidator

5.1 5.2 5.6 5.7

5.2 5.1

2009 2010 2011 2012 2013 2014

(Bcf/d)

Barnett Shale Production *

0102030405060708090

Ma

r-1

1

Sep-1

1

Ma

r-1

2

Sep-1

2

Ma

r-1

3

Sep-1

3

Ma

r-1

4

Sep-1

4

Ma

r-1

5

Barnett Shale Rig Count **

* Source: Powell Shale Digest

** Source: Baker Hughes 38

Projected Capital Investment Opportunities

for 2015-17: ~$150 - $300 MM

Oklahoma Stable Assets with Expansion Opportunities

Key Takeaways

• Continued expansion

opportunities for Cana

• Pursuing large position in SCOOP

or Stack

• Potential pipeline expansion into

NTX to support production

development

$155 $145

2014 * 2015 **

83%

13% 4% Devon Fee-Based Contracts

Linn Fee-Based

Other Fee-Based


Key Customers

69% 65%

0

200

400

600

G&T Processing

Utilization Capacity

550 MMcf/d

Capacity 605 MMcf/d

Capacity

2014 Utilization

39

* Represents Q2-Q4 2014 annualized segment cash flows




Oklahoma Growth Opportunities Core Growth Area for Devon & EnLink

Expansion Opportunities *

• Establish a core position in a

3rd play GW/Stack/Scoop/

Miss

• Transmission or rich gathering

expansion opportunities

Devon’s Cana Production Growth (Mboe/d)

Cana Outlook

• Devon & non-operated

rigs in 2015: 8

• Devon gross wells: 95

• New Stack potential with

Devon

• Enhanced completion

design

• Existing wells benefit

from workovers

40 * This information is for illustrative purposes only. No agreements, understandings or obligations exist regarding these opportunities.


for 2015-17: ~$300 - $550 MM

Potential Expansion Opportunity Linking Cana & North Texas

Expansion Opportunity *

• Evaluating project to integrate

Oklahoma and North Texas assets

• Pipeline could be routed through active

production areas

• Opportunity to utilize North Texas

capacity and market access

• Potential capacity of 200 to 1,000

MMcf/d

41 * This information is for illustrative purposes only. No agreements, understandings or obligations exist regarding this opportunity.

Permian Significant Platform in Core of Midland Basin

Key Customers

Key Takeaways

• Key growth area with large

platform in core of Midland

Basin

• Coronado acquisition adds

large scale long-term growth

potential

• Core of the Midland Basin has

superior drilling economics

$9

$40

2014E 2015E


Processing Capacity

YE 2014 YE 2015E

125 MMcf/d

400 MMcf/d


(1) (2)

56%

44% Fee-Based

Commodity-BasedProcessing

42

(1) Represents Q2-Q4 2014 annualized segment cash flows

(2) Based on 2015 Guidance and includes partial year contributions from Coronado

(3) EnLink Midstream and Apache Corp. each have 50% ownership interest in the Deadwood facility.

(4) Includes the gross operating capacity of the Deadwood plant, which is 50% owned by Apache Corp.


(3)

(4) (4)

Permian Growth Opportunities

43

Significant Acreage with Multiple Pay Zones

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

1,600,000

Effective Acreage from Multiple

Zones in Midland Basin

Source: EnLink Midstream estimates

Source: Credit Suisse

Permian Growth Opportunities Superior Drilling Economics in Midland Basin

Midland Basin / Lower Spraberry Drilling Economics *

* Source: Diamondback Energy Investor Presentation, February 2015

** Represents Diamondback’s additional ROR related to 88% ownership of Viper which owns mineral interests underlying acreage operated by FANG.

• Key producers delivering superior ROR in low price

environment

• Diamondback Energy reports 50-125% ROR with

$50 crude

• Lower drilling and completion costs

• Low cost vertical drilling also yielding strong returns

Multiple zone development

Diamondback has assembled a strong

acreage position in the North Midland

Basin that will continue to serve as a key

driver of production growth for many

years. We are excited about the

development potential for multiple

horizontal targets within the area that has

and will continue to serve the Coronado

system in the future.

Diamondback has been involved with

Coronado since its formation and we have

grown together as business partners. We

look forward to working together with

EnLink Midstream to support each other’s

growth aspirations.

“

” Travis Stice,

CEO, Diamondback Energy

44

** **

Permian Growth Opportunities Superior Drilling Economics in Midland

Basin

EnLink’s System Capacity Expansions (MMcf/d)

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

2015 2016 2017 2018 2019 2020

Expansion Opportunities **

• Leverage LPC services

• Bolt-on and step out

opportunities in

Dawson/Howard/Regan

counties

• Expand into Delaware

Basin

EnLink’s Midland Basin Growth Plans

• Integrate Coronado assets

with Bearkat

• Continued construction of

facilities to accommodate

drilling dedicated acreage of

245,000+

• Capacity increasing 30% per

year next 3 years

45


for 2015-17: ~$600 - $800 MM

*

• EnLink Midstream and Apache Corp. each have 50% ownership interest in the Deadwood facility.

** This information is for illustrative purposes only. No agreements, understandings or obligations exist regarding these opportunities.

Gas Business Unit Summary

46

Oklahoma

Permian

North Texas

Basin has a long, stable future

Focus on increasing market

share and offsetting declines

Excellent upside in improved

commodity environment

Continued expansion of Cana

Pursuing large position in a 3rd

play

Pipeline expansion into NTX

supports production development

2015 Key

Takeaways

2015E Segment

Cash Flows *

~ $380 MM

~ $40 MM

~ $145 MM

Core growth area with large

platform in Midland Basin

Coronado acquisition adds large

scale long term growth potential

Midland Basin core generates

superior returns in low prices

2015-17

Capital Investment

Opportunities **

* Based on 2015 guidance. Segment cash flow is a Non-GAAP metric and is explained in greater detail on page 3. See Appendix for a reconciliation to Operating Income.


~ $150 - $300 MM

~ $300 - $550 MM

~ $600 - $800 MM

Louisiana Strategic Review

Mac Hummel Executive Vice President

Liquids BU President

47

Crude

Oil

NGLs

Natural

Gas

Louisiana Strategic Review Executive Summary

48

Natural gas demand growth will

outpace supply growth

The Northeast becomes a net

exporter, mainly to the Gulf Coast

US NGL supply expected to

continue growing

Majority of all supplies expected to

make their way to the Gulf Coast

Crude growth will slow but will still

increase

Where economic, imported barrels

will be displaced

KEY TAKEAWAYS

• US market dynamics are

creating regional supply

and demand imbalances

which in turn are

generating infrastructure

opportunities

• Louisiana market dynamics

across all products are

creating similar

opportunities

• EnLink’s platform in

Louisiana positions it

uniquely to provide

solutions created by

changing dynamics in the

natural gas, NGL, and

crude markets

• EnLink will continue to be

active in capturing those

opportunities

EnLink’s Louisiana Assets Are Unique and Well Positioned

49

0

2

4

6

8

10

12

0

20

40

60

80

100

120

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

LNG

De

man

d (B

cf/d) Su

pp

ly/D

em

and

(B

cf/d

)

Midcon Rockies/West Southeast/Texas Northeast U.S. Gas Demand (Including Shrink) LNG Demand

US Natural Gas Demand Is Projected to Outpace Supply

Source: Ponderosa Advisors

Lower-48 Gross Natural Gas Production

Production (Bcf/d)

Production growth slows

due to associated gas slow

down (crude directed

drilling)

Demand growth driven by

LNG exports and industrial

new build/ expansions

50

LNG

Growth

reflected

in total

Louisiana Gas Supply Will Decrease While Demand Will Increase

51 Source: En*Vantage, EIA, Louisiana DNR

From

4.2 to

2.2

bcf/d

North Region

Production From

5.3 to

2.7

bcf/d

Total Louisiana

Production

From

1.0 to

0.5

bcf/d

South Region

Production

From

0.1 to

0.0

bcf/d

Offshore State

Waters Production

2015 – 2020 Supply vs Demand Fundamentals

Increase

4 – 8

bcf/d

by 2020

LNG Markets

Demand

Increase

2 - 4

bcf/d

by 2020

Industrial Markets

Demand

EnLink SE Markets

HENRY

HUB

Haynesville

Future LNG projects Future LNG projects

EnLink

Future LNG projects

Increased Gas Demand in Louisiana Will Be Supported by Production in the Northeast

2014 – 2017: 20+

pipeline projects to

move gas west and

south

14.8 bcf/d of reversal

projects

Louisiana is destination

due to pipeline design

EnLink’s expansive

Louisiana infrastructure

allows for movement

across the entire state,

and enables us to be

the “last mile”

EnLink’s system

provides flexibility,

storage, and access

to multiple markets

and supply points

52

Increase

4 – 8

bcf/d

by 2020

LNG Markets Demand

Increase

2 - 4

bcf/d

by 2020

Industrial Markets

Demand

Marcellus/Utica

Gas Seeking

Louisiana

Markets

Including

Industrial, LNG,

Seasonal Outlets

Perryville

Source: En*Vantage

Source: En*Vantage

US NGLs Will Increase and Barrels Will Work to Make Their Way to Mont Belvieu

53

Incremental US

NGLs

by 2020

1.6 MM Bbl/d

By 2020 Louisiana

will only contribute

~4% of total supply,

but will account for

~25% of ethane

demand

Increase in NGL Supplies

2015 – 2020 (000’s Bpd)

Excess supplies will

make their way to the

Gulf Coast

~80% of North

American petchem

capacity is in Texas /

Louisiana

Ethane Demand in Louisiana Will Continue to Outpace Supply

Source: En*Vantage 54

Louisiana

Sarnia

Edmonton/

Ft. Saskatchewan

Conway

Mt.

Belvieu

NGLs Will Need to Move From Mont Belvieu Into Louisiana – Creating Another Cajun-Sibon-Type Opportunity

55

Cajun-Sibon

Source: EnLink Midstream

As Crude Oil Production Increases It Will Continue to Push Out Imports

0

2

4

6

8

10

12

14

16

18

20

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Cru

de

Oil

(MM

b/d

)

US Production Refinery Inputs

I

M

P

O

R

T

S

Source: Ponderosa Advisors 56

Most of the Crude Demand in Louisiana Is Supplied From Offshore Production Or Is Imported

Onshore

production

:

0.2 MMb/d

Offshore

production

:

1.2 MMb/d

Louisiana

demand:

2.9 MMb/d

Source: Ponderosa Advisors

0.4 MMb/d from Texas

57

Imported Barrels into Louisiana Will Continue to be Displaced

0.0

0.5

1.0

1.5

2.0

2.5

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

Imp

ort

s (M

Mb

/d)

0-25 25-35 35-42 42-50 50+ Grand Total

Louisiana crude oil imports have decreased over time,

but there still exists non-structural imports that can be backed out going forward

Source: Ponderosa Advisors, EIA

--- Structural Imports Gravity

58

~700,000 bpd of

non-structural

imports can still be

displaced

Non-structural

Imports

Key Takeaways

US market dynamics are creating regional

supply and demand imbalances which in

turn are generating infrastructure

opportunities

Louisiana market dynamics across all

products are creating similar opportunities

EnLink’s platform in Louisiana positions it

uniquely to provide solutions created by

changing dynamics in the natural gas,

NGLs, and crude markets

EnLink will continue to be active in

capturing those opportunities

59


Mac Hummel, EVP & President of Liquids Business Unit

60


61

Louisiana Gas & Liquids, ORV &

Crude/Condensate LA Gas

20%

52%

Crude / Cond 28%

LA NGLs**

LPC

System Victoria

Express

Louisiana

Gas & NGLs

ORV 2015E

Consolidated

Segment

Cash Flows *

* Based on 2015 guidance projections. 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.

** Louisiana NGLs segment cash flows include hedge impacts of ~$9.0 MM.

Louisiana NGLs • NGL services from Mt. Belvieu to the river

• New alternative for market supply flexibility

• Long-term supply and product sales contracts

Louisiana Gas • Full range of services including gathering,

treating, processing, transmission, storage and

supply

• Expected growth due to industrial expansions,

LNG exports and optimization

ORV • Condensate volumes driving stabilization,

transportation and first purchaser opportunities

Crude/Condensate • New crude platforms for growth in Permian

Basin and Eagle Ford

• Opportunities being realized with Devon

Louisiana Gas and NGLs

62

Providing the Fuel for Industrial Growth

$114 $126

$132

$114

2015E

Consolidated

Segment

Cash Flows *

LA Gas 20%

52%

Crude / Cond 28%

LA NGLs**

* Based on 2015 guidance projections. 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.

** Louisiana NGLs segment cash flows include hedge impacts of ~$9.0 MM.

Louisiana NGLs System

• One of largest NGL platforms in Louisiana

• Provides service to market characterized by

declining local supply and higher demand,

primarily for ethane

• Strategically links upstream producers and the

Texas Gulf Coast with Cajun-Sibon customers

• Asset optimization and expansion opportunities

underway

Louisiana Gas System

• Premier end use market delivery system in the

expanding Mississippi River corridor

• Integrated wellhead to market services

• Geographical diversity for gas supply throughout

Louisiana and extended market reach

• Extensive market, supply and asset

optimizations underway

• Storage evaluations for return to service

Louisiana NGLs A New Supply Alternative for Louisiana

Key Customers

NGL Capacities

$72

$151

2014 * 2015E **

70

130

77

194

Start of2014

Start of2015

Pipeline Fractionation

Mbbl/d

Key Contracts

• Long term fee-based

Cajun-Sibon supply

agreements with key

industry participants in

various producing regions

• Long term purity product

sales agreements to key

Louisiana customers,

including Dow, Williams

and Marathon

63

* Represents Q2-Q4 2014 annualized segment cash flows and includes hedge impacts.

** Based on 2015 Guidance and includes hedge impacts of ~$9.0 MM.



Key Takeaways

• Completion and market reach of Cajun-

Sibon provides significant bolt-on

opportunities

• Marathon-Garyville pipeline expansion in

development

• Assets running well and fully integrated

• Significant asset optimization opportunities

Louisiana Gas Developing Opportunities from Market

Leading Position

Key Customers 2015 Contract Structure


2014 * 2015E **

Pipeline Processing

85%

15%

Fee-Based

Commodity-Based

$64 $59

Natural Gas Capacities

2.0

4.0

1.7 1.7

4.0

Start of2014

Start of2015

Pipeline Processing Storage

Bcf/d

64



*** Does not include 7.0 Bcf of inactive natural gas storage capacity at Napoleonville.


***

Key Takeaways

• Positioned to participate in demand growth

driven by industrial expansion and LNG exports

• Asset footprint provides diversity of

supply/markets

• Henry Hub, system interconnects and storage

capabilities provide enhanced flexibility and

services for customers

Gulf Coast Acquisition Numerous Opportunities in Development

Estimated Estimated

Potential Projects** Capital Cost Adjusted EBITDA *

• Near-term Optimization Projects ~$50 MM ~$10-20 MM

• Repurposing Pipelines ~$130-300 MM ~$30-40 MM

Currently

Pursued

Opportunities

65 * Adjusted EBITDA is a Non-GAAP metric and is explained in greater detail on page 3. See Appendix for a reconciliation to net income.


Louisiana Growth Opportunities Focus on Optimization, Re-purposing & Bolt-Ons

Ascension Pipeline: First Bolt-On Expansion to Cajun-Sibon

66

Louisiana Gas & NGLs

Projected Capital

Investment Opportunities

for 2015-17:

~$350 - $700 MM

Louisiana NGLs

Outlook

• Expand market reach to

new customers and new

areas of Louisiana

• Execute on Ascension

pipeline – 50/50 JV with

Marathon Petroleum

• Bolt-on opportunities to

increase capacity to serve

customers

Louisiana Gas Outlook

• Weighted average life of

north Louisiana

transmission contracts: 3

yrs.

• Growing gas storage

business – 11 Bcf capacity

• Upside from improved gas

processing environment

• Asset and supply

optimization opportunities

• Re-purpose pipelines to

higher value service

Crude & Condensate Assets

67

Expanding Our Footprint and Services

LPC

System

Louisiana

Crude

Victoria

Express

ORV

* Segment cash flow is a Non-GAAP metric and is explained in greater detail on page 3. See Appendix for a reconciliation to Operating Income.

** Based on 2015 Guidance and includes hedge impacts of ~$9.0 MM.

LA Gas 20%

52%

Crude / Cond 28%

LA NGLs**

2015E

Consolidated

Segment

Cash Flows *

Louisiana Crude • Crude terminals at Eunice and Riverside with rail,

truck and barge loading capabilities

• Exclusive firm trans-loading contract at Riverside

expected to provide $8MM of adjusted EBITDA in

2015

Victoria Express • First drop down from Devon to EnLink (subject to

closing)

• 56-mile pipeline with planned, expanded capacity

of 90,000 Bbl/d

• Entry to Eagle Ford – develop full range of services

LPC

• Acquired in January 2015

• Growing with West Texas gas business

• Broader service offering to customers

ORV

• Focused on growing condensate services

Victoria Express Drop Down New Platform in the Eagle Ford

Key Customer


Key Takeaways

• 56 mile crude / condensate line from

Eagle Ford core to Port of Victoria

• Capacity

– Pipeline Today: 50,000 Bbl/d

– Planned Pipeline By YE ‘15:

90,000 Bbl/d

– Storage Today: 150,000 Bbl

– Storage by YE ‘15: 360,000 Bbl

• Expansion Plans

– Capital cost of expansion: ~$30-$40

MM

– Plan to serve Devon & third parties

• Devon in Eagle Ford

– Production in Q4 ‘14: 98 MBOED

– Reserves 247 MMBOE

– 2015E Drilling plans ~225 gross wells

$0

$8

2014 * 2015E **


100%

0%

Fee-Based

Commodity-Based

68

Illustrative Timeline

* Represents Q2-Q4 2014 annualized segment cash flows.

** Based on 2015 Guidance.

Segment cash flow is a Non-GAAP metric and is explained in greater detail on page 3. See Appendix for a reconciliation to Operating Income.

Note: The completion of the VEX drop down is subject to the satisfaction of certain closing conditions. The expansion information on this slide is for illustrative purposes only. No

agreements, understandings or obligations exist regarding these expansion opportunities.



*** Expected growth by year-end 2015


ORV Focused on Condensate Services

Key Customers


Key Takeaways

• Maintaining legacy crude

business

• Enhancing stabilization and

compression services

• Growing condensate and

brine services footprint –

pipeline continues in open

season

$26

$48

2014 * 2015E **


96%

4%

Fee-Based

Commodity-Based

19

37

460

760

YE 2014 YE 2015 ***

0

200

400

600

800

0

10

20

30

40

Stab. (thousand Bbl/d)

Comp. (MCF/D)

Stabilization and

Compression Capacity

69

000

Bbl/d

Mcf/d

ORV Growth Opportunities

Condensate Pipeline

• Extension of Open Season

through mid-April 2015

• Ongoing discussions with key

long-term shippers

• Utilize truck fleet to move

product until system

expansion is complete

Water *

• Increased water production

accompanying increases in oil

and condensate

• Enter term water-handling

agreements with key producers

• Improve injection capacity via

acquisition and development of

new injection wells

70 * Sources: Ohio Department of Natural Resources, Pennsylvania Department of Environmental Protection and West Virginia Department of Environmental Protection


*

Liquids Business Unit Summary

71

ORV

Louisiana

Gas

Louisiana

NGLs

Integrated supplier to

Louisiana

Pipeline conversion & bolt-on

opportunities

Maintaining legacy crude

business

Growing condensate and brine

services footprint – pipeline

continues in open season

2015 Key

Takeaways

2015E Segment

Cash Flows *

Crude

Assets

~ $151 MM

~ $59 MM

Louisiana Riverside crude

terminals

VEX drop down in Eagle Ford

LPC acquisition in Permian

~ $32 MM

~ $48 MM

~ $350 - $700 MM

~ $250 - $600 MM

2015-17 Long-Term

Capital Investment

Opportunities **

* Based on 2015 guidance. Segment cash flow is a Non-GAAP metric and is explained in greater detail on page 3. See Appendix for a reconciliation to Operating Income.


Growth driven by industrial

demand and LNG exports

Footprint provides diversity of

supply/markets and enhanced

flexibility/services for customers

Financial Outlook

Michael Garberding, EVP & Chief Financial Officer

72

Sustainable

Growth

Substantial

Scale &

Scope

Diverse,

Fee-Based

Cash Flow

Strong Balance

Sheet &

Credit Profile


73

Well Positioned with a Strong Balance Sheet

Investment grade balance sheet at ENLK (BBB, Baa3)

Target debt / adjusted EBITDA of ~3.5x

Strong liquidity with $1.5 billion credit facility

~ 95% fee-based margin

Balanced cash flow (Devon ~50%)

Balanced portfolio of rich gas processing and NGL/crude oil

Total consolidated enterprise value of ~$13 - 14 billion

Projected 2015 Combined Adjusted EBITDA: ~$740 MM

Geographically diverse assets with multi-commodity exposure

Stable base cash flow supported by long-term contracts

Organic growth opportunities through Devon’s upstream portfolio

Expect significant growth from drop downs

Note: Adjusted EBITDA is a non-GAAP financial measure and is explained in greater detail on page 3.

Destination 2017

74

Line of Sight to Double the Size of EnLink

LA

$85 WTI

$4.00 gas

Incremental Adjusted EBITDA

Assets VEX & Access

Pipelines

Cana, Eagle Ford

& Permian

Louisiana,

Permian,

Eagle Ford, Utica

TBD

Estimated Capital VEX: $210-220

MM

Access: TBD

$750 MM –

$1.25 B $1.0 – 1.75 B $1.0 – 2.0 B

Annual Estimated Adjusted

EBITDA by 2017 $130 – 180 MM $90 – 160 MM $100 – 175 MM $125 – 250 MM

Note: The information in this slide is for illustrative purposes only.

* Based on 2015 Guidance. Adjusted EBITDA is a non-GAAP and is explained in greater detail on page 3. See Appendix for a reconciliation to Operating Income.

** Includes price deck and potential basin decline sensitivities

$500

$700

$900

$1,100

$1,300

$1,500

$1,700

2015EAdjusted EBITDA*

DropDowns

Growingwith DVN

OrganicGrowth**

M&A Destination 2017

Adjusted EBITDA ($000)

$ 1.4 B

Long Term Vision

ENLK’s investment grade (BBB/Baa3) credit ratings provides great access to capital

Since inception, ENLK has effectively refinanced its balance sheet and financed its growth totaling

~$2.4B through the debt and equity capital markets:

Significant liquidity/financial flexibility with $1.5 Billion revolving credit facility at ENLK and

$250MM revolving credit facility at ENLC

Remaining 25% EMH drop down to provide a run-rate of ~$100MM of unlevered adjusted EBITDA

at ENLK in return for ENLK units to ENLC

EnLink’s strong credit position gives it significant capacity to pursue organic growth or acquisitions 75

Strong Balance Sheet

EnLink has a strong, investment grade balance sheet

Transaction Timing Amount2.700% Senior Notes Due 2019 March 2014 ~ $400MM

4.400% Senior Notes Due 2024 March 2014 ~ $450MM

5.600% Senior Notes Due 2044 March 2014 ~ $350MM

4.400% Senior Notes Due 2024 November 2014 ~ $100MM

5.050% Senior Notes Due 2045 November 2014 ~ $300MM

At The Market Equity Programs (sales) December 2014 ~ $ 80MM

Overnight Equity Offering of ~12MM units November 2014 ~ $330MM

Coronado Equity to Sellers March 2015 ~ $360MM

Eq

uit

y

Issu

an

ces

Bo

nd

Issu

an

ces

Total

Proceeds

of ~$1.6 B

Total

Proceeds of

~$770 MM

Note: Adjusted EBITDA is a non-GAAP financial measure and is explained in greater detail on page 3.

% of 2015E

Segment

Cash Flow *

Devon Bridgeport Contract - 9 years remaining on contract with 4 years remaining on minimum volume commitments (MVC)

Devon East Johnson County Contract - 9 years remaining on contract with 4 years remaining on MVC

Existing FT Transmission & Gathering - Volume Commitments with remaining terms of 2-10 years

Bearkat Plant - Volume Commitment with 10 year term from initial flow

Devon Cana Contract - 9 years remaining on contract with 4 years remaining on MVC

Linn Northridge Contract ** - 9 years remaining on contract with 4 years remaining on MVC

North LIG Firm Transport - Reservation fee with avg remaining life of 3 years

Firm Treating & Processing - Remaining term minimum 2 years

Cajun-Sibon Phases I & II - 5 & 10 year agreements for supply and sale of key products

E2 Compression / Stabilization Contract - 7 years ~62%

~80%

ORV

% of Total Segment Cash Flow for 2015E *

~77%

Segment / Key Contract

Texas

Oklahoma

~92%

Louisiana

~83%


76

Cash Flow Stability from Long-Term Contracts

* Based on 2015 Guidance estimates.

** As previously disclosed, Devon assigned this contract to a subsidiary of Linn Energy, effective as of December 1, 2014

Note: Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3.

~80% of EnLink’s cash flows are supported by long-term, fee-based contracts with either

firm transport agreements or minimum volume commitments.

Drop Downs

77

Devon Sponsorship Creates Drop Down

Opportunities

2014 2015 2016 2017

Other Potential Devon Drop Downs **

E2

25% EMH **

Access Pipeline **

Victoria

Express

Pipeline *

* Subject to the closing of the drop down transaction with Devon.

** Cautionary Note: The information regarding these potential drop downs is for illustrative purposes only. No agreements or understandings exist regarding the terms of these potential drop

downs, and Devon is not obligated to sell or contribute any of these assets to EnLink. The completion of any future drop down will be subject to a number of conditions. The cost and

adjusted EBITDA Information on this slide is based on management’s current estimates and current market information and is subject to change.

*** Based on 2015 Guidance and accounts for 25% of the total estimated adjusted EBITDA of EMH. Adjusted EBITDA of EMH is a non-GAAP financial measure and is explained on page 3.

Note: Adjusted EBITDA is a non-GAAP financial measure and is explained on page 3.

Drop Down Cost:

~$193 MM Estimated Adjusted EBITDA:

~$20-25 MM

Capital Cost for Construction:

~$1.0 B

Estimated Adjusted EBITDA

by 2017:

~$100-150 MM

Drop Down Cost for 25% Interest:

$925 MM

Estimated Adjusted EBITDA:

~$100 MM ***

Drop Down Cost:

~$210-220 MM

Estimated Adjusted EBITDA

by 2017:

~$30 MM

25%

EMH

Adjusted EBITDA & Volumes

Combined Adjusted

EBITDA*:

* Adjusted EBITDA is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to net income.

** Based on 2015 Guidance. 78

49% 58%

27% 19%

18% 20%

6% 3%

2015E ** Q2-Q4 2014Annualized

Texas Louisiana Oklahoma ORV

Midstream Service Volumes (000s)

Texas

Gathering and Transportation (MMBtu/d) 2,690 2,960

Processing (MMBtu/d) 1,090 1,150

Louisiana

Gathering and Transportation (MMBtu/d) 1,270 615

Processing (MMBtu/d) 610 550

NGL Fractionation (Bbl/d) 130 90

Oklahoma

Gathering and Transportation (MMBtu/d) 430 470

Processing (MMBtu/d) 390 440

ORV

Crude/Condensate Handling (Bbls/d)1 80 16

Brine Disposal (Bbls/d) 5 5

1. Includes crude/condensate handling by the ORV, Oklahoma & Louisiana segments

2015E 2014

2015 Consolidated Capital Expenditures

79

Potential long term capital spending of $2-3 billion per year for acquisitions & drop downs

Coronado $130MM Other

Permian $170MM

Louisiana & NGL

$65MM LPC

$5MM

ORV Condensate

$95MM

Other $35MM

Growth Capital Expenditures * 2015E Combined: ~$500 MM

Texas $26MM

Oklahoma $8MM

Louisiana $12MM

ORV $4MM

Maintenance Capital Expenditures * 2015E Combined: ~$50 MM

* Growth capital expenditures and maintenance capital expenditures are non-GAAP financial measures and are explained in greater detail on page 3.

Based on 2015 Guidance information.

Note: the information on this slide is for illustrative purposes only.

EnLink’s Credit Exposure

80

Investment grade counterparties comprise 82% of EnLink’s credit exposure

Investment Grade 82%

Non-Investment

Grade 18%

Counterparty Credit Ratings

EnLink’s Top 20 unsecured counterparties, based on 2014 monthly receipts,

consist primarily of creditworthy customers with investment grade credit

ratings

ENLC 2015E Tax Overview

81

ENLC has three principal sources of income, each with different levels of exposure to

federal and state income tax:

− IDRs: ENLC receives a special allocation of taxable income in relation to the IDR

payouts such that they are fully taxable

− LP and GP Distributions: Distributions from ENLK have a different tax shield from

what public unitholders receive; for 2015, it is forecasted that ENLC will be allocated a

small amount of losses from its ENLK interests, and thus the tax shield will be

approximately 100%

− Income from EnLink Midstream Holdings: Tax shield is estimated to be approximately

90% on distributions from ENLC’s ownership interest in EnLink Midstream Holdings

ENLC has stand-alone deductions for its direct interest expense, G&A costs, etc., and has

net operating loss carryforwards of approximately $48 MM available to be applied against

taxable income in 2015. These deductions have been factored into tax shield percentages

noted above.

After applicable deductions and applying available net operating losses in 2015, ENLC is

forecasted to incur a cash tax liability in 2015 of ~$20 MM.

As dropdowns and acquisitions are executed, the composition of ENLC’s income streams

will change, and therefore cash taxes could be materially different than initial guidance.

Key Performance Drivers

Short Term Performance Drivers

Production optimization in Oklahoma and Barnett shale

Timing of Utica condensate production and ORV execution

Indirect exposure to commodity prices

Long Term Performance Drivers

Potential additional adjusted EBITDA from dropdowns: $130-$180 MM

Stable cash flows from long-term Devon contracts

Organic development in the Gulf Coast, Permian and Ohio River Valley

Organic development with Devon

M&A activity and development of the recent LPC and Coronado

acquisitions

82 * Adjusted EBITDA is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to net income.

Closing Remarks Barry Davis, President & CEO

83

We’re Just Getting Started Executing on Growth Strategy to Double

In Size By 2017

Powered by strategically located and complementary assets

Generating stable and growing cash flows

Backed by strong sponsorship from Devon

Driven by people with deep industry expertise

Deliver Results Focus on People Be Ethical Strive for Excellence

ENLINK’S CORE VALUES

Built for safety, stability and growth

84

Appendix

85

Assets & Capacities

86

* Includes the net capacity from EnLink Midstream’s 50% ownership interest in the Deadwood processing facility.

** Includes the net capacity from EnLink Midstream’s 38.75% economic interest in the Gulf Coast Fractionators (GCF). The fac ility is located in Mont Belvieu, Texas

and primarily serves North Texas volumes. Distributions received from the GCF ownership interest is reported as income from equity investments.

Regions - Assets Miles / # Capacity Regions - Assets Miles / # CapacityTexas Oklahoma

North Texas Gas Gathering & Transmission Pipelines 480 mi. 605 MMcf/d

Gas Gathering & Transmission Pipelines 4,072 mi. 4,045 MMcf/d Processing Plants 2 plants 550 MMcf/d

Processing Plants 4 plants 1,041 MMcf/d

NGL Fractionation Facilities 1 frac. 15,000 Bbl/d Louisiana

Gas Gathering & Transmission Pipelines 3,320 mi. 3,975 MMcf/d

West Texas Processing Plants 5 plants 1,710 MMcf/d

Gas Gathering Pipelines 90 mi. 240 MMcf/d Natural Gas Storage 2 caverns 11 Bcf

Processing Plants * 5 plants 264 MMcf/d NGL Transmission Pipelines 600 mi. 130,000 Bbl/d

NGL Fractionation Facilities 1 frac. 15,000 Bbl/d NGL Fractionation Facilities 4 fracs 194,000 Bbl/d

Crude Oil Pipelines 67 mi. - NGL Storage Facilities 1 cavern 3,200,000 Bbl

Fleet of Tractor Trailers 43 trucks -

Pipeline and Refinery Injection Stations 13 stations - Ohio River Valley

Crude / Condensate Pipeline 200 mi. 19,000 Bbl/d

South Texas - Victoria Express Condensate Stabilization 5 stations 19,000 Bbl/d

Pipeline 56 mi. 50,000 Bbl/d Trucking Fleet 100 trucks 25,000 Bbl/d

Storage 5 tanks 360,000 Bbl Brine Disposal Wells 8 wells 5,000 Bbl/d

Gulf Coast Fractionator ** 1 frac. 56,000 Bbl/d

Total Miles/# CapacityGas Pipelines 9,155 mi.

Processing Capacity 16 plants 3,565 MMcf/d

Factionation Capacity 7 fracs. 280,000 Bbl/d

Reconciliation

87

Segment Cash Flow to Operating Income

2015

Forecasted

Q2-Q4 2014

Annualized

($MM)

Total segment cash flows* $854 $779

General and administrative

expenses (145) (114)

Depreciation and amortization

expense (372) (303)

Other ** (26) (20)

Operating Income $311 $342

*Segment cash flows is defined as revenue less the cost of purchased gas, NGLs, condensate, crude oil and operating and maintenance expenditures **Other includes stock-based compensation and (gain) loss on debt extinguishment

Reconciliation

88

Net Income to Consolidated Adjusted EBITDA

2015

Forecasted

Q2-Q4 2014

Annualized

($MM)

Net Income $219 $347

Interest expense 105 56

Depreciation and amortization

expense 372 303

Net distribution from equity

investments* 17 10

Other ** 27 (26)

Consolidated Adjusted EBITDA $740 $690

* Includes distribution from equity investment and non-controlling interest, net of income (loss) on equity investment **Other includes provision for income taxes, stock-based compensation, (gain) loss on noncash derivatives and transaction costs

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

89

Howard Energy Estimated 2015

Distributions: ~$21 MM

Gulf Coast Fractionator Investment: Serving Devon in Mont Belvieu

90

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 among 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 2015

Distributions: ~$12 MM

Net to EnLink Midstream

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