201 014 4 Analyst alyst & Investor vestor Day ay May 12, - - PowerPoint PPT Presentation

201 014 4 Analyst alyst & Investor vestor Day ay

May 12, 2014

1

St Stron

• ng. Innovati

ative.

• e. Gro

rowi wing. ng.

Forward-Lookin Looking g Statemen ements ts

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

• ther 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 Non-GAAP AAP Fi Financia ial Informati rmation

• n

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

Inves estor

• r Notice

ice

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.

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Age gend nda a & S & Spe peak aker ers

Roadm dmap for Growth wth

• Barry Davis

President & CEO

• Michael Garberding

EVP and CFO

Devon

• n En

Energy rgy Spon

• nsor

sorsh ship ip

• John Richels

Devon Energy Corporation, CEO

Natural ural Gas s Bus usine ness sses es

• 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 uids Bus usine ness sses es

• Mac Hummel

EVP & President of NGL & Crude

• Stan Golemon

SVP of Engineering

• Chris Tennant

VP of NGL

• Paul Weissgarber

SVP of Ohio River Valley

Financia ancial l Out utloo

• ok
• Michael Garberding

EVP and CFO

Non

• n-Op

Oper erat ated ed Inves estm tmen ents ts

• Brad Iles

SVP of Business Development

5

The he Road admap map for Growth wth

Barry E. Davis,

President and Chief Executive Officer

6

Managem gemen ent t Team Experience rience

Barry rry Davis is 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 e Davis is 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.

Mich chael el Garb rberd rding ing 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.

Stev eve e Hoppe ppe 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.

EnLin ink k Midstre tream am manag agem ement t team am is comp

• mpri

rised ed of forme rmer r Cross

• sstex

tex and Devon evon senior ior manag agem emen ent and d other her exper erienc ienced ed midstre stream am lead ader ers

McMil illan (Mac) c) Hummel el 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 Le e Leade dership ip:

Experien perienced ed Mana nagem ement nt Team m with h a Proven en Track ck Recor

• rd

7

EnLink nk Midstream am Pa Partner ers, s, LP Master Limited Partnership

NYSE: ENLK (BBB / Baa3)

EnLink nk Midstream, am, LLC General Partner

NYSE: ENLC

Public Unitholders

~70% ~30% ~1% GP ~7% LP

EnLink k Mids dstre tream am Holdings

(formerly Devon Midstream Holdings) ~52% LP ~40% LP 50% LP

Devon Ener ergy Corp.

NYSE: DVN (BBB+ / Baa1) GP + 50% LP

The V e Veh ehic icle le for r Susta tain inabl ble e Growth wth:

MLP Stru tructure cture with h a Premier emier Sponsor nsor

8

Dist./Q Split Level < $0.2500 2% / 98% < $0.3125 15% / 85% < $0.3750 25% / 75% > $0.3750 50% / 50% Curren ent Po Position tion ENLC ow

• wns 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

The V e Veh ehic icle le for r Susta tain inabl ble e Growth wth:

Strat rateg egic icall ally Locat ated ed and nd Complem mplemen enta tary y Assets ts

Gas Gather herin ing and Trans anspor

• rta

tatio ion

• ~7,300 miles of gathering and

transmission lines

Gas Proc

• cess

essin ing

• 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 Tran ansp spor

• rtatio

tation, Frac actio tionat atio ion and Stor

• rage

age

• ~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, de, Conden densat sate e and d Brine ine Handling dling

• 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

Jackf kfis ish Pike Granit nite e Wash Barnett ett Shale Pe Permian ian Basin Ferrier ier Corridor idor Cana Woodf dfor

• rd

Mississip ippian ian-Woodf

• dfor
• rd

Rockies ies Oil Great ater er Wapiti ti Washakie kie Carthage age Groes esbeck eck Acces ess Pipeline eline Mississip ippian ian-Woodf

• dfor
• rd

Water Handling ling Ferrier ier Plant Rockies ies Midstr tream eam

• E. Texas Midstr

tream eam

Devon’s Upstream Portfolio & Non Non-Co Contr trib ibuted ed Mids dstr trea eam m Assets ts

Horn River ver

Oil Liquid uids-Ric Rich Dry Gas Midstream eam

Hayne nesville/ ville/Bos

• ssier

ier

The V e Veh ehic icle le for r Susta tain inabl ble e Growth wth:

De Devon n is Committ mmitted ed to the Suc uccess ess of EnLin Link k Midst stream eam

• 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

• pportunities
• Potential to acquire additional Devon

midstream assets

10

The V e Veh ehic icle le for r Susta tain inabl ble e Growth wth:

Diverse, e, Fee-Bas Based ed Cash h 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 4E EnLink nk Mids dstre ream Consoli

• lidat

dated Gross ss Operati ating ng Margin* n*

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

The V e Veh ehic icle le for r Susta tain inabl ble e Growth wth:

Strong

• ng Balance

nce Sheet t and Liquidi idity ty

• 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 ne Infrastr rastruc uctu ture re Capita tal Spending ding Needed d Per Year in the U.S.*

(2011 – 2035)

$30.0 B $14.6 B $15.4 B

Total Gas Liquids

The R e Road d Condi dition ions:

Expon ponen entially tially Growin wing g Energy ergy Mark rket

13

* Source: INGAA Study

Surgin ing U.S. . Produ

• duction

tion Requ equir ires the Re-Pip ipin ing of Ameri erica, a, With Expec ected ted Midstre stream am Inve vestm stmen ent of $30 Billio lion Annually ally for 20+ year ars s *

* ***

NYMEX X Gas Brea eakev keven en Price ice ($/M /MMBtu) u) for 10% % Return n WTI Oil Brea eakev keven en Price ce ($/B /Bbl) l) for 15% IRR

The R e Road d Condi dition ions:

Presen esence e in the Prof

• fitable

itable Plays ys

14

Source: Credit Suisse; Natural Gas and Oil prices used for breakeven calculations are $4/MMBtu and $90/Barrel, respectively.

Devo von and d EnLink Mids dstr trea eam m Have ve Signific ificant t Prese sence e in Most st Proli

• lific

ic and Prof

• fitab

itable le Shale le 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 h American an Ethyle ylene ne Plants ts & Capaci citi ties s *

** South h Louisia siana: a: 10 Plants, s, 15.0 B Lb/Yr Yr, , ~25% of N.A. cap apac acity ty

12.5%

4 Plants ts 8.6 B Lb/Yr

3.3% %

2 Plants ts 2.3 B Lb/Yr

80%

33 Plants ts 56.1 1 B Lb/Yr** r** 3.6% %

2 Plants ts 2.5 B Lb/Yr

0.6% %

1 Plant t 0.4 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.

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 th Louisian ana Etha hane ne Balance ces s *

The R e Road d Condi dition ions:

Globa bal l Shif ift t in Petr etroc

• chemica

hemical l Industr ustry

15

U.S. . Petro rochem hemic ical l Produ

• ducer

ers in Gulf Coas ast have ve trem emendou dous deman and d for r NGLs, , and there re is now w a shor

• rtfall

fall of locally lly produce

• duced

d supply ly in South h Louisia siana* a*

• Near-term focus on

platform expansion

• pportunities
• 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

Des estin inati tion

• n 2017:

The Four Avenue ues s for Growt wth

16

• E2 dropdown
• Dropdown of legacy

Devon midstream assets at ENLC

• Access Pipeline

dropdown

• Eagle Ford Victoria

Express Pipeline dropdown

Dropdo pdown n Opportu tuni nities Growing With th Devon Organi nic c Growth th Projects cts Mergers & Ac Acqu quisitions ns

AVENUE VENUE 1 AVENUE VENUE 2 AVENUE VENUE 3 AVENUE VENUE 4

Devon von En Energy ergy Sponsorship

• nsorship

John Richels,

Chief Executive Officer

• f Devon Energy Corporation

17

Devon

• n Over

ervie iew

Sharpening pening The Focus

18

Devon’s Core & E Emergin merging Asset sets

Core Emerging ging

Heavy Oil Rocki kies s Oil Miss ssissipp sippian an- Woodford Barnett tt Shale Permian n 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

Sharpe rpenin ing g The F e Focus us

Devon’s Recent Strategic Actions

• Innovative midstream combination
• Accretive Eagle Ford acquisition
• Announced non-core asset sales

19

Permian ian Basin in

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 ghts

• 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
• il plays (>$1 billion of drilling carries in 2014)

Devon’s 2014 Capit ital al Budge get $5.0 - 5.4 Billion

• n

Eagle e Ford Heavy y Oil Anada darko Basin in Barnett t Shale Emerging ging Oil Other Non-Core

• re Asset

ets

2014 4 E&P &P Capi pital Progra

• gram

Deliv iver ering ing Strong ng Oil Growt wth

20

Per ermia ian Basin in

2014 Focus s Areas as

• 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 Arch Diablo Platform

New Mexico Texas

Midland

Wolfberry Conventional Wolfcamp Shale Eastern Shelf Bone Spring & Delaware

TEXAS NEW MEXICO OKLAHOMA

21

Eagl gle e Ford

World-Cl Class ass Oil Asse set

• 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

ALBERTA BRITISH 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

Hea eavy Oil il – Jackfish ish & Pi & Pike e

SAGD D Oil Development lopment

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
• 2014 plans: Drill ≈200 wells

Basin

Wheeler Hemphill Canadian Blaine Caddo Johnson Tarrant Denton Wise Parker

• Ft. Worth

Denton Oklahoma City

Barnett

ett Shale

Net Acres: >600,000 Q4 Production: >1.3 BCFED Operated Rigs: 2

Anada

adark rko

• Basin

(Cana & Granite e Wash) h)

Net Acres: >350,000 Q4 Production: 512 MMCFED Operated Rigs: 2

Barnet ett t Shale e & A & Anada dark rko

• Basin

in

Liquids uids-Ri Rich h Gas

24

Mis issis issip ippi pian-Wood

• odfor
• rd

d & R & Rockie ckies

Emergi erging g Oil l Oppor

• rtunities

tunities

Missis sissippi ippian-Wood

• dfor
• rd
• 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

Rockie ies 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
• 2014 plans: Drill ≈30 wells

Rocki kies es Oil

Net Acres: 150,000 Q4 Production: 21 MBOED Operated Rigs: 3

Miss ississ issipp ippian ian-Wood Woodford

• rd

Net Trend Acres: >600,000 Dec Net Production: 16,000 BOED Operated Rigs: 8

WYOMING OKLAHOMA

25

Wh Why EnL nLin ink Is Impor mporta tant nt to Devon

• n
• 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
• wnership 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

Poten enti tial l Drop p Down Asset et

Access s Pipeline peline (SAGD

GD Oil Midstre stream) am)

• 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

Poten enti tial l Drop p Down Asset et

Victoria

• ria Express

press Pipeline eline (VEX) EX) (Ea

Eagle le Ford) d)

• ≈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 er Poten enti tial al Mid idstrea eam m Acti tivit ity

29

The he Four ur Avenues enues for Growth wth

Barry E. Davis,

President & Chief Executive Officer

Michael J. Garberding,

EVP & Chief Financial Officer

30

• Near-term focus on

platform expansion

• pportunities
• 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

Des estin inati tion

• n 2017:

The Four Avenue ues s for Growt wth

31

• E2 dropdown
• Dropdown of legacy

Devon midstream assets at ENLC

• Access Pipeline

dropdown

• Eagle Ford Victoria

Express Pipeline dropdown

Dropdo pdown n Opportu tuni nities Growing With th Devon Organi nic c Growth th Projects cts Mergers & Ac Acqu quisitions ns

AVENUE VENUE 1 AVENUE VENUE 2 AVENUE VENUE 3 AVENUE VENUE 4

Aven enue e 1: Future re Dropd pdown wns s

Devon Sponsor nsorship ship Creat ates es Dropd pdown n Oppor

• rtunit

tunities ies

32

Estimated Capital Cost:

$80 MM

Estimated Cash Flow:

~$12 MM

Estimated Capital Cost:

$1.0 B

Estimated Cash Flow:

~$150 MM

Acquisition Cost:

$2.4 .4 B

Estimated Cash Flow:

~$20 200 0 MM

Estimated Capital Cost:

$70 MM

Estimated Cash Flow:

~$12 MM 2014 2015 2016 2017 Devo von Spon

• nso

sorsh ship ip Prov

• vide

ides s Poten ential tial for ~$375 MM of Cash h Flow

• w from

m Dropd

• pdowns

Other Potential Devon Dropdowns

E2 E2

Legac acy Devon

• n Mids

dstr trea eam m Assets ts Ac Access ss Pipeline eline Victor

• ria

ia Express ss Pipeline line

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

• bligated 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
• n 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 4 E&P Capital tal Budget t

$5.0 .0 - 5.4 Billion lion

Aven enue e 2: Growi wing g Wit ith 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
• n 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 Histor

• rica

ical Mids dstr trea eam m Capital ital Expen endit ditures

($MM)

33

Aven enue e 3: Orga ganic ic Growth wth

Sign gnif ific icant ant Orga ganic nic Gr Growth th Projects jects Already eady Und Under erway

34

South uth Louisiana siana Platform

• rm Ex

Expansion nsion

• 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 t Texas as Platform

• rm Ex

Expansion nsion 3rd Par Party y Growth wth Ar Around nd Leg egacy acy Devon

• n

Midstre stream am As Asse sets ts

• Significant bolt-on expansion opportunities around Cana-Woodford

and Barnett Shale assets

• Commercial teams currently in discussions with various potential

producers

Ex Expand nd Canadia dian n Oil Sands ds Presence sence

• 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

Aven enue ue 4: Mer erge gers & A & Acquisit uisition ions

• 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

EnL nLin ink Mid idstrea eam m Toda day & Tomorr

• rrow

EnLink k Midstr strea eam Today EnLink k Midstr strea eam Poten enti tial al Future ure in 2017

36

South Louisi siana Grow

• wth:

h: Cajun-Sibo bon West st Texas Grow

• wth:

h: Beark rkat Victori ria Expre ress ss Drop

• pdow

down Com

• mplet

ete E2 Drop

• pdow

down Com

• mplet

ete

Oth ther er Poten enti tial l Step p Changes ges Oth ther er Grow

• wth

th Factors ctors

• Growth from Serving Devon
• Mergers & Acquisitions

Pot

• tent

ential al for $375 MM

• f Addit

itional ional Cash h Flow

• ws from

m dropdow

• pdowns

ns

Acces ess s Pipel eline e Drop

• pdow

down Com

• mplet

ete

CANADIAN OIL SANDS

Signif nific icant ant Organic nic Grow

• wth

h Project ects Under derway

Midstrea ream Holdi dings gs Drop

• pdow

down Com

• mplet

ete

Na Natu tural ral Gas as Assets sets

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

Natura ral l Gas Gather erin ing, g, Proce

• cessin

ssing g and d Transpo porta tati tion

• n Busin

ines ess Uni Unit

$126 $126 $114 $114

North th Texas as

• Gas gathering
• Gas processing & NGL fractionation
• Condensate stabilization
• Gas Transportation

Oklahoma lahoma

• Gas gathering
• Gas processing
• Condensate stabilization

West t Texas as

• Gas gathering
• Gas processing & NGL fractionation

Gas Busines iness s Un Unit Q2-Q4 Q4 2014 Forec ecast sted ed Segmen ment Cash sh Flow: : ~ $420 MM *

Gas 76% 76%

38

Liqui uids 24% 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

• n Contracts

racts Provi vide de Cash Fl Flow Stabil ilit ity y in in No North th Texas and d Okla lahoma homa

• Term:

: 10 year initial term (acreage dedication), year-to-year thereafter; 5 year minimum volume commitment

• Finan

ancial ial terms: ms: Per-MMbtu fees for gathering and processing with CPI escalator

• Volume

e Commitm itmen ent: t: Approximately 88% of expected volumes for the 12 months ending 9/30/2014

• Gather

erin ing g and Proces essin sing g Obligat gation ion: : EnLink Midstream obligated to gather and process on a firm basis

• Downstre
• wnstream

am Mark rketin ing: g: Devon is responsible for nominations and scheduling of redelivered residue gas, condensate and NGLs

• Well Connec

ections: tions: 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 ct Contract ct Term m (Years) Minimu nimum Gather ering ing Volume ume Commit mitmen ment (MMcf cf/d) Minimu nimum m Proces cessing ing Volume ume Commit mitmen ment (MMcf cf/d) Minimu nimum Volume lume Commit mitmen ment Term m (Years) Annua ual l Rate e Esca calator lator

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 Legac acy Devon von Midstream ream assets support

• rted

ed by fee-bas ased ed contrac tracts with minimum um volum ume e guarant rantees ees for five e years

39

North th Texas Assets ets

Posit sitioned ioned for Long-Term erm Perform

• rman

ance ce

Gather hering

• 3,640 miles of pipeline
• 2,600 MMcf/d capacity

Proc

• cess

ssin ing

• 4 plants 1,100 MMcf/d capacity
• 1 Stabilizer 5 MBbl/d
• Truck and rail loading

Frac actio tionat atio ion

• 1 plant, 15 MBbl/d capacity

Tran ansp spor

• rtat

tatio ion

• 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 Custome

• mers

(most active operators in basin)

North th Texas as Q2-Q4 Q4 2014 Forecast asted ed Segmen ment Cash sh Flow: : ~ $304 MM *

Contra tract ct Mix

North th Texas Assets ets:

Solid lid Plat atfor

• rm

m – Broad ad Reach

Key Conside sidera rati tion

• ns
• 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 th Texas Syner ergi gies: es:

Operat rational ional Flexibility xibility

42

Reduced O&M costs or increased revenues $20 MM annually Goal Reduced capital expenditures Goal

• 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 th Texas Assets ets: :

Curren rrent t Trends ends and Growt wth Strat trategy egy

5.1 5.2 5.6 5.7 5.2 2009 2010 2011 2012 2013

Average age Annual al Produ ducti ction

• n (Bcf/d)

/d) *

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 tt Shale Curre rent nt Trends nds

• Reduced gas well drilling as result of low gas prices
• Producers focused on optimizing base production

Our Growth th Strat rategy

Shor

• rt Term

rm

• Optimize combined systems
• Enhance customer services
• Execute identified expansion projects

Long

• ng Term

rm

• Enhance customer services
• Expand systems & customer base
• Extend into new production areas
• Support 3rd party and Devon activities & opportunities
• Acquire and consolidate other assets

43

Barnett tt Shale Rig Count nt **

* Source: Power Shale Digest ** Source: Baker Hughes

Oklahoma homa Asset ets: s:

Solid lid Plat atfor

• rm

m for Bolt-On On Projects jects

Cana

• Gathering
• 410 miles of pipeline
• 530 MMcf/d capacity
• Processing
• 1 plant
• 350 MMcf/d capacity

Northridge hridge

• Gathering
• 140 miles of pipeline
• 75 MMcf/d capacity
• Processing
• 1 plant
• 200 MMcf/d capacity

$114 $126

Scoop Stack Arkoma Woodford

44

Oklahoma homa Asset ets: s:

Stable able Cash sh Flows s and nd Oppor

• rtunitie

unities s for 3rd

rd Pa

Party ty Cash h Flows ws

Key Conside siderations rations

• 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 Custome

• mers

Oklahoma lahoma Q2-Q4 Q4 2014 Forecast sted ed Segmen ent Cash Flow: : ~ $104 04 MM * 100%

Fee-Based Contracts

Contr tract Mix

45

* 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.

Oklahoma homa Asset ets: s:

Curren rrent t Trends ends and Growt wth Strat trategy egy

Curre rrent nt Trends nds

• 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 th Strat rategy

Shor

• rt Term

rm

• Maximize utilization of regional capacities with
• ther midstream providers
• Enhance customer services

Long

• ng Term

rm

• Enhance customer services
• Expand systems & customer base

̶ 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

Oklaho ahoma ma Rig Count t from

• m 2012

to 2014 4 **

Oklahoma Total

Devon Ac Acreage in Oklaho homa *

* Source: DrillingInfo.com ** Source: Baker Hughes

Per ermia ian Assets: ets:

A Plat atform

• rm in a Prolif
• lific

ic Basin in

Gather hering

• 65 miles of pipeline under

construction

• 65 miles of fuel and gas lift

pipeline under construction

• 200 MMcf/d capacity

Proc

• cess

ssin ing

• 1 plant, 58 MMcf/d capacity

(50% interest with Apache)

• 1 plant under construction, 60

MMcf/d capacity

• Truck and rail loading

Frac actio tionat atio ion

• 1 plant, 15 MBbl/d capacity

47

Per ermia ian Assets: ets:

Growing ing From m Our Plat atform

• rm

48

Key Cust stome mers

• Deadwood:
• Bearkat: Two Producers

Contra tract ct Mix Key Conside siderations rations

• 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 Permia mian Q2-Q4 Q4 2014 Forecast asted ed Segmen ment Cash sh Flow: : ~ $11 MM * 100%

Fee-Based

* 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.

Per ermia ian Assets: ets: Bea earkat rkat Project

• ject

Processin cessing g and nd Ga Gatherin hering g Syst stem em Cur urren rentl tly Und Under er Constru struction ction

• Builds on success of Deadwood joint

venture with Apache, which was on-time,

• n-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

Per ermia ian Assets: ets:

Curren rrent t Trends ends and Growt wth Strat trategy egy

Permian n Basin n Current rent Trends nds

• 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 th Strat rategy

Shor

• rt Term

rm

• Expand systems & customer base

̶ Provide capacity relief for constrained producers ̶ Support 3rd party and Devon activities & opportunities ̶ Extend into new production areas

Long

• ng Term

rm

• Expand systems & customer base

̶ Support 3rd party and Devon activities & opportunities ̶ Extend into new production areas ̶ 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 n Rig Count t from m 2011 1 to 2014 4 **

50

* Source: Apache ** Source: Baker Hughes

Permian n Basin n Resour urce ce Plays*

Natura ral l Gas Asset ets: s:

Poten enti tial al Growth th Proje

• jects

cts from m 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

Consolidation of Midstream Assets / Potential Acquisitions 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 uids Assets sets

52

Liqui iquids ds Busin ines ess Uni Unit

Louisiana isiana

• NGL gathering and transportation
• NGL fractionation
• NGL storage
• Crude handling
• Natural Gas transportation
• Natural Gas processing

Ohio

• River

er Valle lley (ORV RV)

• Crude/Condensate transportation
• Crude/Condensate storage
• Brine Disposal
• Condensate Stabilization &

Gas Compression

53

$126 $126 $114 $114

Liquids quids Business ess Un Unit Q2-Q4 Q4 2014 Forec ecast sted ed Segme ment t Cash sh Flow: : ~ $133 MM *

Gas 76% 76% Liqui uids 24% 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.

Caju jun-Si Sibon bon Expa pansion ion:

Game e Changer ger for EnLin Link k in the Gulf Coast ast

• 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

Louis isia iana Asset ets: s:

Gr Growing ing Gu Gulf Coast st Capabil biliti ities es

Crude de Handli dling

• 2 terminals
• ~18 MBbl/d capacity

Natural al Gas s Tran ranspor

• rtat

tatio ion

• 2,000 miles of intra-

state pipelines

• 2.0 Bcf/d of capacity

Natural al Gas s Proc

• cess

essin ing

• 6 plants
• 2.5 Bcf/d of capacity

NGL Tran ansp spor

• rtatio

tation

• 120 MBbl/d capacity

post-Cajun-Sibon

• 789 miles of NGL

pipeline in service

• 119 miles of NGL

pipeline under construction NGL Frac actio ionat atio ion

• 3 plants, 95 MBbl/d

capacity

• 1 plant under

construction, 100 MBbl/d capacity NGL Stor

• rage
• 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

Caju jun-Si Sibon bon Expa pansion ion – Phase e I:

Comple plete

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

Caju jun-Si Sibon bon Expa pansion ion – Phase e 2:

Expect pected ed comple leti tion

• n in Q4 2014

57

Louis isia iana NGL Assets: ets:

Linking king North th Americ erican an Supply ly to Loui uisiana siana De Dema mand nd

Key Custome

• mers

s / Supplier liers Contr tract Mix

Key Conside sidera rati tion

• ns
• 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 isiana NGL Q2-Q4 Q4 2014 Forecast asted ed Segmen ment Cash sh Flow: : ~$55 MM * 100%

Fee-Based

58

* 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.

Loui uisia iana na NGL Assets: ets:

Curren rrent t Trends ends and Growt wth Strat trategy egy

Curre rrent nt Trends nds

• 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 th Strat rategy

Shor

• rt Term

rm

• 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

• ng Term

rm

• 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

100 200 300 400 500 2013 2018 Supply Demand

10 20 30 40 50 60

Globa

• bal Ethylene

lene Cash sh Costs sts **

(Cents ts per Lb of Ethylen hylene) e)

Mid-East Ethane Canadian Ethane

U.S. Ethane

Mid-East Propane

• W. Euro

Naphtha SE Asia Naphtha NE Asia Naphtha

59

Louisiana isiana Ethane ane Supply/De /Dema mand d *

(MBbl/d l/d)

* Source: Hodson Report, February 2013 ** Source: En*Vantage

Louis isia iana Crude de Asset ets: s:

Termi rminals nals at Eunice ice and River ersid side e Facili liti ties es

60

Key Custome

• mers

Key Conside siderations rations

• 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 isiana Crude de Q2-Q4 Q4 2014 Forecast sted ed Segmen ment Cash sh Flow: : ~$8 MM * Contr tract Mix 100%

Fee-Based

* 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.

Louis isia iana Crude de Asset ets: s:

Curren rrent t Trends ends and Growt wth Strat trategy egy

Curre rrent nt Trends nds

• 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 th Strat rategy

Shor

• rt Term

rm

• 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

• pportunities

Long

• ng Term

rm

• 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% 32% 19% 19%

U.S. Crude de Producti uction n *

61

* Source: EIA ** Source: Association of American Railroads

Rail il Car arloa loads ds of Crude de Pet etroleum

• leum on

US Class ass I R Railr ilroad ads s from

• m 2003-2015 **

**

Louis isia iana Natural l Gas Assets: ets:

Pipeli eline e and Proc

• cessing

essing Plant ant Flexibility xibility

Key Custome

• mers

Key Conside siderations rations

• 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 isiana Gas Q2-Q4 Q4 2014 Forecast asted ed Segmen ent Cash Flow: : ~$43 43 MM * 74% 26%

Fee-Based Commodity-Based Processing

Contr tract Mix

62

Processing Customers

* 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.

Louis isia iana Natural l Gas Assets: ets:

Curren rrent t Trends ends and Growt wth Strat trategy egy

Curre rrent nt Trends nds

• 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 th Strat rategy Short-Term rm St Strateg egy

• 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 rm St Strateg egy

• Pursue strategic acquisitions
• Consolidate inefficient facilities and utilize existing assets in

highest value use

• Expand position as premier Louisiana gas franchise

Capit ital al Spend nding ing for Anno noun unced ed Louis isiana iana Natura ural l Gas Driv iven en Manufac facturing turing ** Louis isiana iana Gas Demand and (Bcf/d) d) 2010 – 2025 *

63

* Source: ICF International ** Source: LSU Center for Energy Studies

Ohio io Riv iver er Valley y Assets: ets:

Esta tablis blished ed Hist stor

• ry

y of Servic vice

Crude/Co de/Cond ndensa nsate Trans nspo porta tati tion

• n
• 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/ de/Co Cond ndensat nsate Stora rage

• ~600 MBbl of above ground storage

Brine ne disposa sposal l wells

• 8 total wells – 6 owned, 2 jointly-owned

64

80% 20%

Fee-Based Crude/Condensate Fee-Based Brine

Ohio io Riv iver er Valley y Assets: ets:

Well Positioned sitioned in n the Utic ica a and nd Wester ern Marcellu ellus

Key Custome

• mers

Key Conside siderations rations

• 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 RV Q2-Q4 Q4 2014 For

• rec

ecast sted ed Segmen ment Cash sh Flow:~$28 MM * Contr tract Mix

65

* 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.

ORV Asset ets: s:

Current rrent Tren ends ds and Growt wth Stra trategy egy

Curre rrent nt Trends nds

• 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 t Term Growth th Strat ategy gy

• 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 th Strat rategy

• 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 RV Rig Count t * ORV RV Drilli lling Permits mits Issued ed *

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

Consolidation of Midstream Assets / Potential Acquisitions LPG Export Facility Mixed Heavy NGL Pipeline Terminal Repurposing NGL Batching Pipeline Market-Area Pipeline

ORV Potential Projects

Consolidation of Midstream Assets / Potential Acquisitions Condensate Refinery Condensate Pipeline

67

Liqui iquids ds Asset ets: s:

Poten enti tial al Growth th Proje

• jects

cts from m 2014-2017

No Non-Operated Operated Investme vestments nts

Brad Iles,

SVP of Business Development

68

Howard d Ener ergy gy Inves estmen ment: t:

Strat rategic egic South uth Texas xas Asset t Footp tprint rint

Key Cust stome mers Ownersh ship Structu ructure re

31% 59% 10% EnLink Midstream Alinda Capital Partners HEP Management

Key Conside siderations rations

• 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 4 2014 4 Forecast asted Distr stributi ution n Income:~$20 20 MM

E2 Inves estment ment:

Inn nnovativ ative e Solution ution to Gr Grow ORV V Condensat ndensate e Business iness

Cust stomer

• mer

70

E2 Q2-Q4 Cash h Flow Post-Dr Dropdo pdown: wn:~$9 9 MM Key Conside siderations rations

• 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 Comp mpressio ression n & Conde densat nsate Stabilizat zation

• n
• Capacity of 320 MMcf/d and 16,000 Bbl/d
• Two facilities completed, one under construction

Gulf f Coast Fracti tiona

• nator
• r Inves

estm tmen ent: t:

Serving ing Devon in Mont Belvieu vieu

71

38.75% 22.50% 38.75%

Key Conside sidera rati tion

• ns
• 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 es

Devon Phillip lips 66

GCF Esti tima mated d Q2-Q4 Q4 Cash h Flow: w:~$9 $9 MM

Financial ancial Ou Outl tlook

• ok

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

Louis isiana iana ORV RV

Long g Ter erm Vis isio ion: EnLink’s Key Financial Attributes

Long g Ter erm Vis isio ion: Strong

• ng Balance

e Sheet eet

• 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 k has one of the stro ronges ngest balance sheets ets in the indus dustry try

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

• ng Balance

e Sheet eet: Exec ecution ution of Fi Financia ial Syner ergie gies

EnLink k fina nanci ncing ng activi vity ty has posi siti tione

• ned

d the comp mpany to realize ze fina nanci ncial synerg ergies es of over $35 MM annua ually y comp mpare red d to Cross sstex x stan anda dalone ne

• 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 e the merger r was announc unced, ed, EnLink k guide ded d the marke ket t to expect ct fina nanci ncial synergi rgies s of $25 million

• n

Long g Term Vis isio ion: Stable le and D d Div iversif ifie ied d Cash Flows

76

Each of EnLink Midstream’s segments benefits from the stability provided by long-ter erm, , fee-ba base sed d contrac tracts ts

Segmen ent t / K Key Contrac ract % % of Q4 2014 Segmen ent Cash Flow

• w

Texa xas 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

• ma

New Devon Cana Contract - 10 years with 5 year MVC 100% New Devon Northridge Contract - 10 years with 5 year MVC Louis isian iana 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 tal Segmen ment Cash sh Flow w 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 g Ter erm Vis isio ion: Sustain inable ble Growth wth

77

Distr trib ibutio ion grow

• wth

h targets ets are e high single le digit its s for MLP and d 20% plus for GP 2014 2015 2016 2017

Estimated Capital Cost: $80

MM MM

Estimated Cash Flow:

~$12 MM

Estimated Capital Cost:

$1.0 B

Estimated Cash Flow:

~$150 50 MM

Acquisition Cost:

$2.4 .4 B

Estimated Cash Flow:

~$20 200 0 MM

Estimated Capital Cost: $70

MM MM

Estimated Cash Flow:

~$12 MM Other Potential Devon Dropdowns

E2 E2

Legac acy Devon

• n Mids

dstr trea eam m Assets ts Ac Access ss Pipeline eline Victor

• ria

ia Express ss Pipeline line

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

• bligated 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
• n this slide is based on management’s current estimates and current market information and is subject to change.

2014 4 EBITDA A & V & Volume lumes s Forec ecasts sts

Q2 Q2-Q4 Q4 2014 Comb mbine ned d Annual alize ized d EBITD TDA: A: ~ $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 Per erformanc rmance e Driv iver ers

Short t Term Performance rmance 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 Perform rman ance Driver ers

• 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 4 Cons nsolid

• lidat

ated ed Cap apit ital al Expe pend ndit itures ures

80

Poten entia ial long term m cap apital ital spendin ding of

• f $1.0 bill

llio ion - $2.0 .0 billi llion

• n per year

ar with th drop

• p dow
• wns

$200 MM $194 MM Cajun-Sibon Bearkat Other $50 MM Legacy DVN $46 MM

Growth th Capex x *

Q2-Q4 ‘14 Combined: ~$490 MM $43 MM $12 MM $7 MM Texas Oklahoma ORV $2 MM Louisiana

Mainten enan ance ce Capex x *

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 ax

• 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
• perating 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

Clos losing ing Rema marks rks

Barry Davis,

President & CEO

82

Key Tak akea eaways ys

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

Appendix pendix

84

Rec econcil

• ncilia

iation ion: : Seg egmen ent t Cash Fl Flow to Ope peratin ing g Income

• me

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

Rec econcil

• ncilia

iation ion: : Net et Income me to Consoli lida dated ed Adj djust sted ed 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