Investor Handout

Investor Handout

Investor Handout June 2016 Energizing the World, Bettering People’s Lives ® Navigating the Cycle From a Position of Strength Four differentiated ke...

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Investor Handout June 2016

Energizing the World, Bettering People’s Lives ®

Navigating the Cycle From a Position of Strength Four differentiated keys to success

Diverse Yet Focused Portfolio Proficient Organization and Capabilities

Financial Preparedness

Driven by Corporate Values

By Commodity, Geography, and Project Type

Industry-Leading U.S. Onshore Unconventional and Global Offshore Businesses Cost and Major Project Execution Disciplined Capital Allocation and Value Creation Focus Actively Managing Portfolio

Commitment to Stakeholder Engagement and Safety

Energizing the World, Bettering People’s Lives® 2

Global Operations Leading portfolio provides exceptional investment optionality 2016E Sales Volumes Mix International Gas 20%

2016E 405 MBoe/d

Liquids 45%

Marcellus Shale DJ Basin Eagle Ford & Delaware Israel / Cyprus

Gulf of Mexico U.S. Gas 35%

US International Suriname

U.S. Onshore Unconventional

Global Offshore

DJ Basin

GOM



Scale, inventory running room and infrastructure advantage

Eagle Ford 

High productivity, upside from downspacing and testing new areas



Stacked pay potential, contiguous acreage and high oil content

Marcellus  3

Gas price optionality, exposure to top U.S. gas play

High exploration success rate, shorter cycle time, and high oil contribution

Equatorial Guinea 

Permian 

Equatorial Guinea / Cameroon Gabon

Strong production profile and cash flow contribution with minimal capital requirements

Israel  

Strong reservoir deliverability and secular increase in regional demand Growing production

Falkland Islands

New ventures

Strategic Focus Through Commodity Downturn Maintain capabilities and drive long-term value enhancement Protect the Balance Sheet  Disciplined and flexible investment plan

Leverage Benefits of a Well-Positioned and Diversified Portfolio  Continue portfolio optimization opportunities

Continue to Deliver Sustainable Cost Reductions Advance Technical Competencies and Readiness for Recovery  Optimize returns with enhanced completions in best areas

Capitalize on Low Cost Environment with Quality Long-Cycle Major Project Sanctions Enhance Long-Term Exploration Portfolio with Minimal Commitments

4

Financial Position Track record of financial strength Maintained $5 B of Liquidity1  $1 B cash and $4 B undrawn revolver  No near-term debt maturities  Debt-to-capital 39%; well below 65% covenant level2

2016 Hedge Positions Cover 40% of Global Oil and 28% of U.S. Gas Volumes  Adding 2017 hedges at measured pace

Dividend Adjustment and Debt Refinancing

Investment Grade Rating

 Up to $200 MM annual cash benefit  Term loan provides de-leveraging flexibility

1Liquidity

defined as cash plus unused credit capacity. for impairments to reflect debt facility calculation Note: Financial position as of March 31, 2016. 2Adjusted

5

Rating Agency Summary

Moody’s

Baa3

Negative

S&P

BBB

Negative

Fitch

BBB-

Stable

Active Portfolio Management Portfolio high-grading generating substantial cash flows

$B

Over $3 B of Cumulative Proceeds Since 2010

Proceeds From Asset Monetizations

1.5

 Non-core, low-growth assets  Accelerating tail inventory value

U.S. Onshore, North Sea

Non-Core Asset Sales Transactions Totaling Over $775 MM Year to Date

1.0 CONE MLP, U.S. Onshore, China

U.S. Onshore

EMed, U.S. Onshore

Capital Allocation Only to Core Assets

0.5

Positioned for Additional Asset Monetizations

U.S. Onshore

U.S. Onshore

 DJ Basin infrastructure

Ecuador

0.0 2010

2011

2012

Onshore

7

2013

Protecting Balance Sheet/ Supporting Investment Grade Rating

2014

CONE MLP

2015

Int'l

2016

 EMED projects farm downs

Optimize Returns with Cost Focus and Well Completions 40% reduction in DJ Basin well costs, greater than 50% sustainable $MM 8.5

Wells Ranch Long Lateral 9000’ Well Cost $8.2

7.5

Cost Savings Breakdown

6.5 5.5

$4.8 Completion

4.5 3.5

Drilling 1Q15

Structural

Cyclical

1Q16 Facility

Structural Cost Savings Include:  2016 lateral length average of 7300’ up 16% from 2015

 Monobore and cycle time improvement  Fluid design changes, including slickwater  Infrastructure optimization 7

$3.4MM Savings per Well

Driving Rosetta Merger Synergies Combination offers financial and operational value

1Q16 Total LOE and G&A Including Rosetta Flat in Absolute Amount Versus Noble-Only 1Q15  Added ~ 100 MBoe/d period over period

Realizing $90 MM in G&A Savings and Rosetta Synergies Reduced Drilling Times by 20% Versus Prior Performance Total Company G&A

Total Company LOE $/BOE

$/BOE

$3.3

$5.5

22%

$5.0 $4.5

27% $2.8 $2.3

$4.0 $1.8

$3.5 $3.0

$1.3 1Q15

8

1Q16

1Q15

1Q16

Momentum Driving Improved 2016 Outlook Increased 2016 sales volumes 15 MBoe/d on reduced capital Capital Program Priorities:

MBoe/d

 Maintain and enhance operating capabilities in the U.S. onshore

400

 Progress our offshore discovered resources to development

300

Any Additions to Current Capital Program Would Focus on DJ Basin and Delaware Basin

Sales Volumes

390

405

200

100 2013

2014

2015

2016E Prior 2016E New

 Requires fundamental change in commodity outlook

Operational Capability to Support Doubling of U.S. Onshore Rig Count Reasonably Quickly

$MM 5,000

Organic Capital Expenditures

4,000 3,000 2,000

1,500

<1,500

1,000 0 2013 9

2014

2015

2016E Prior 2016E New

2016 Capital Program Disciplined and prudent investment approach Represents a 50% Reduction to 2015 Program While Maintaining Agility and Flexibility U.S. Onshore: Focus On Best Return Areas and Maximize Use of Existing Infrastructure

Less Than $1.5 Billion Capex 405 MBoe/d Volumes GOM Program Focus on Gunflint development and Katmai appraisal

DJ Basin Program Focus on Wells Ranch and East Pony IDPs

Progress Long-Term Major Projects  Gunflint project complete mid-2016  Alba compression project  Position for EMED FID

Exploration Focused on U.S. GOM Drilling and Int’l Seismic

10

DJ Basin Texas Marcellus GOM EMed West Africa Other Marcellus Program Activity limited to working down a portion of DUC inventory in dry gas area

Texas Program Eagle Ford development drilling in Gates Ranch and Delaware appraisal

Onshore U.S. Unconventional Operations Integrate learnings between basins to unlock resource value

DJ Basin

11

Marcellus

Delaware Basin and Eagle Ford Shale

Over 360,000 Net Acres

~350,000 Net Acres

Over 100,000 Net Acres

1Q16 Average Net Production of 118 MBoe/d

1Q16 Average Net Production of 573 MMcfe/d

1Q16 Average Net Production of 60 MBoe/d

Premier Liquids Play with Running Room and Infrastructure Advantage

Top Tier Gas Play Provides Long Term Optionality

Accelerating Rate of Change in Two New Basins

DJ Basin Focus on Wells Ranch and East Pony Highest value areas and leveraging existing infrastructure Over 360,000 DJ Basin Net Acres  More than 110,000 net acres in Wells Ranch and East Pony

Operating Two Drilling Rigs During 2016  2016 lateral length average of 7,300’ up 16% from 2015

CO

 Wells Ranch CPF turnaround in 2Q16

Enhancing Capital Efficiency and Long Term Value Through:

East Pony

 Focus in liquid-rich areas

 Maximizing use of existing NBL infrastructure  Capital and operating cost reductions  Improving performance with innovative completion techniques

12

Wells Ranch NBL Acreage 2016 Development

Optimizing DJ Basin Well Results Driving continuous learning curve in the DJ Basin Two Rig Program in the DJ Basin  Lateral footage of 4+ rigs

Advanced Slickwater Completions with Higher Proppant Concentration  Testing range of 1,100-1,800 pounds per lateral foot

Early Indications Show Enhanced Completions Outperforming

Well Productivity: IP-30 /1000 ft. Rate

200 150 100 50 0

 1Q16 IP-30 per 1000 ft. up more than 30% versus 1Q15

Focus on Core IDP Drilling Driving Volume Up 34% Versus 1Q15 in Wells Ranch and East Pony  Optimizing use of existing infrastructure

1Q14

1Q16

Completion Specifications

IP-30 (Boe/d) Lateral Length (ft.) Product Mix (Oil / NGL / Gas) Well Cost ($/lateral ft.) Number of Wells

13

1Q15

1Q14

1Q15

1Q16

405

566

836

4,127

5,227

5,860

56%/20%/24%

59%/18%/23%

68%/15%/17%

1,230

1,221

737

69

63

22

Noble Energy Strategic DJ Basin Acreage Exchange Further enhancing value of Wells Ranch position Received 11,700 Net Acres in Wells Ranch for 13,500 Net Acres Primarily in Bronco Area

WELD COUNTY

 Creates synergies for both parties  Simplifies long term DJ Basin development  Reduces number of surface locations

Improved Contiguous Position in Wells Ranch  Increased Wells Ranch acreage position by ~20%  Increased long lateral drilling opportunities

NBL Acreage

 Leverages existing infrastructure

NBL IDP Areas

NBL DJ Basin Acreage Post Transaction Close East Pony

44,900

Wells Ranch

78,100

Other

238,300

Total

361,300

Wells Ranch

Wells Ranch

NBL Acreage

Pre-Trade 14

PDC Acreage

Post-Trade

DJ Basin Assets and Sale Area Accelerating value through partial Greeley Crescent divestiture Generating $505 MM Cash Proceeds

WELD COUNTY

 Closing expected as early as June 2016 East Pony

33,100 Net Acres Sold, Primarily Undeveloped  Approximately 8% of NBL DJ Basin acreage

Wells Ranch

 Assets included associated production of 2,400 Boe/d net to NBL

NBL Development Currently Focused on Higher Value Wells Ranch and East Pony Areas

Noble Acreage Held Noble Acreage Sold

 Deep inventory of higher oil content, long lateral opportunities  Efficiencies leveraging existing infrastructure

15

NBL DJ Basin Acreage Post Transaction Close

East Pony

44,900

Wells Ranch

66,700

Other

251,500

Total

363,100

A Premier Acreage Position in the Eagle Ford Top-tier, low-risk asset in highly productive areas EUR(Boe)/Lat. ft.

    Tom Hanks



Central Dimmit Briscoe Ranch

Basin Assumptions Gates Ranch

*Source: ITG Investment Research

16

Eagle Ford 45,000 net acres 100% WI Multi-zone 20% oil / 40% NGL / 40% gas 51 MBoe/d 1Q16 Avg.

Formation

EUR (MBoe)

EUR (Boe)/ Lat. ft.

% Liquid

D&C ($MM)

Spacing (feet)

Gross Locations

S. Gates Ranch Lower Eagle Ford

3,000

600

55%

$6.0

475-950

~65

Other Gates Ranch Lower Eagle Ford

1,000

200

57%

$6.0

475-950

~100

Other Lower Eagle Ford

400

80

68%

$5.4

475-950

~75

Upper Eagle Ford

500+

100+

58%

$5.4

475-950

~400

Note: Locations expected to be economic at strip pricing. D&C cost based on 5,000’ lateral and includes flowlines. EUR’s are three-stream.

Impressive Eagle Ford Results New completion designs deliver substantial enhancement NBL Drilling and Completing Some of the Most Productive Wells in the Eagle Ford

Tom Hanks

 Combination of tier-1 acreage with NBL enhanced completions  Drilling times materially reduced

Central Dimmit Briscoe Ranch

Recent South Gates Ranch Wells Outperforming 3 MMBoe Type Curve

Well Locations NBL Acreage

Gates Ranch

 Testing various lateral spacing concepts

NBL Interests

 30-day IP average of last 5 wells ~ 5,000 Boe/d

Briscoe Ranch Wells Demonstrate Enhanced Completions in New Areas  Reduced stage and cluster spacing

 Increased proppant

Briscoe Ranch Lower Eagle Ford Performance

Cum. MBoe 200

BR 36 BR 32 400 MBoe Type Curve

160 120 80 40 0 0

18

10

20 30 40 Days on Production

50

60

Initial Delaware Basin Performance Results confirming quality across extent of existing acreage Productivity Per Lateral Foot Up 13% Compared to Prior Asset Average First Two Completions Verify Tier 1 Wolfcamp A Position  Calamity Jane - substantially above type curve Soapy Smith 36 1H

 Soapy Smith - extension confirmed quality

Running Room With Over a Decade of Inventory 2016 Activity Focused on Further Delineation

Calamity Jane 2001H NBL’s First Completions NBL Acreage

Wells Outperforming Type Curve Cum. MBoe 60

Completion Specifications Soapy Smith 36 1H Calamity Jane 2001H NBL 700 MBoe Type Curve

40 20 0 0 18

10 20 Days on Production

Note: Normalized to 5,000’ lateral and gross three-stream volumes.

30

Soapy Smith

Calamity Jane

IP-30 (Boe/d)

728

1,599

Lateral Length (ft.)

2,790

4,190

Product Mix (Oil / NGL / Gas)

68%/16%/16%

49%/26%/25%

Fluid

Slickwater

Hybrid Gel

Proppant (lbs./ft.)

1,800

1,700

Cluster Spacing (ft.)

60

60

Target Interval

Wolfcamp A

Wolfcamp A

Marcellus Shale Low-cost U.S. natural gas basin provides optionality Substantial Acreage Position in SW Marcellus  350,000 net acres in southwest fairway  Leases largely held by production

Well Performance – EURs and IPs Continue to Improve

JV Activity Significantly Reduced in Current Price Environment  No drilling…focus on completion activity  Spending within cash flow

19

Wet Gas Noble Operated

Dry Gas CONSOL Operated

CONE Midstream Partners LP Overview Significant embedded midstream value Marcellus Gathering MLP  Jointly owned by NBL and CNX  Material acreage dedication from sponsors  Substantial pipeline and compression facilities

NBL Retains a 32.1% LP Interest and 50% Ownership of GP

CNNX Performance Has Exceeded Expectations  Set multiple throughput records in 2015  CONE debottlenecking project underway, expect capacity increase of 240 MMcf/d beginning in 2H16

21

Leveraging Offshore Capabilities in the Down Cycle EMED and West Africa sanctions success story $6 B in Gross Project Sanctions of Aseng, Alen and Tamar During Last Down Cycle Continued and Consistent Development Project Success  Locked in costs at low point of the cycle  Project delivered on schedule or early and on budget  Very reliable operations

Strong Production Profile and Cash Flow Contribution Today with Minimal Follow-On Capital Requirements

2009

21 21

2010

2011

ASENG

TAMAR

ALEN

Asset Type: FPSO Location: West Africa Sanction to First Oil: 2.3 Years Capital: $1.2 Billion (Excludes Leased FPSO)

Asset Type: Platform Location: Israel Sanction to First Gas: 2.5 Years Capital: $3.1 Billion

Asset Type: Platform Location: West Africa Sanction to First Gas: 2.6 Years Capital: $1.3 Billion

Leveraging Offshore Capabilities in the Down Cycle Opportunistic timing for Leviathan sanction UCCI Index: 2016 Offshore Costs at Lowest Level in the Last Decade 40%

300 Offshore Sanctions Aseng July 2009 Tamar September 2010 Alen January 2011

30% 20%

250 Leviathan Sanction Target

200

10% 150 22

0%

100 -10% Offshore Index YOY 50

-20% Offshore Index -30%

0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 Source: IHS Energy

2016 Offshore Costs Expected 19% Lower than 2009 Downturn Levels Leviathan Sanction Timing Enhances Long-Term EMED Cash Flow Potential 22

Global Offshore Operations Delivering value through exploration and major project expertise

Eastern Mediterranean

Gulf of Mexico

Equatorial Guinea/ Cameroon

1Q16 Average Net Production of 266 MMcf/d

1Q16 Average Net Production of 29 MBoe/d

1Q16 Average Net Sales of 65 MBoe/d

Maximizing Natural Gas Deliveries to Israel

Focused on Subsea Tieback Opportunities Near Existing Infrastructure

Optimizing Production and Cash Flow from Existing Fields

Testing Additional Resources with Exploration and Appraisal

Expanding into New Exploration Opportunities

Positioned to Supply Underserved Regional Market for Decades 23

Eastern Mediterranean Strategic assets positioned to meet regional market demand

1Q16 Israel Natural Gas Sales Volumes of 266 MMcf/d, Net  10% growth over 1Q15

4 Bcf/d Unmet Regional Demand  NBL discoveries of 40 Tcf gross

Israel Natural Gas Framework Fully Implemented Progressing Leviathan Field Toward Sanction Realized ~$200 MM in Cash Proceeds from Sale of Undeveloped Properties During 1Q16  Tanin/Karish  Cyprus farm-out to BG/Shell

Cyprus 35% WI

Tamar 36% WI

Leviathan 40% WI Tamar SW 36% WI Producing

Discovery

Ashdod AOT 47% WI

Israel Egypt

24

Tel Aviv

NBL Acreage

10 Tcf Tamar Field Supplying growing domestic and demand World-Class Reservoir and Outstanding Operational Performance  Near 100% facility uptime  Provides over 50% of Israel’s electricity generation

350 Record 1Q Sales

300

Strong Growth and Cash Flow Profile

250

 1Q16 sales volumes up 10% year-over-year

200

 Minimal maintenance capex

150

 $318 million in net income in 2015, net to NBL

Tamar Net Sales Volumes

MMcf/d

1Q

2Q 2014

1.1 Bcf/d Gross Capacity

3Q 2015

4Q

2016

Near-Term Volume Upside Potential  Incremental domestic demand from coal displacement

Opportunistically Monetize 11% Interest in Tamar  Over 6 year time period 25

Leviathan Road Map to Sanction Recent momentum on critical project work streams

26

Cyprus Block 12 Aphrodite Discovery Provides long-term optionality to serve regional demand Gross Mean Natural Gas Resources of ~4 Trillion Cubic Feet Announced Partnership with BG/Shell in November 2015  Noble maintains operatorship  Working interest 35% versus prior 70%  BG/Shell brings substantial technical, financial and marketing capacity

Submitted Preliminary Field Development Plan to Government Potential Development Synergies with Leviathan Multiple Natural Gas Demand Outlets  Cyprus domestic market of approximately 60 - 100 MMcf/d  Potential exports to Europe and Egypt

27

Eastern Mediterranean Gas Opportunities Current and expected demand far exceeds supply Eastern Mediterranean Regional Gas Deficit Bcf/d 9

6

3

0 2016

2017

2018

2019

2020

2021

2022

2023

2024

Egypt LNG Plant Deficit

Egypt Domestic Deficit

Israel Deficit

Jordan Deficit

Turkey Contract Openers

Cyprus Deficit

2025

Note: Data represents NBL estimates. Also reflects Egypt LNG imports of ~1.2 Bcf/d through 2020.

Current Regional Gas Deficit of Approximately 4 Bcf/d, Growing to 9 Bcf/d Existing Regional Discoveries Do Not Meet Demand 28

Gulf of Mexico Program Sustained value creation with significant growth Leveraging New Project Startups

Swordfish 85% WI

Louisiana

 2016 sales volumes nearly double 2015

Galapagos 26% Avg WI

 50% reduction in capital versus 2015

Strategy to Focus on Capital Efficient Subsea Tie-Back Opportunities Gunflint Oil Development Planned for Mid-2016 Startup

NBL Interests Producing Under development Gunflint 31% WI

Discovery

Katmai 50% WI

Katmai Appraisal Drilling  Discovered 40 – 60 MMBoe, testing upside to 100 MMBoe gross resources

Additional Inventory of Exploration Opportunities

29

Troubadour 60% WI

Dantzler 45% WI

Ticonderoga 50% WI

Big Bend 54% WI

Deepwater GOM Major Projects Proven track record of exploration and development success Leading-edge Technology with Disciplined Processes Short Discovery to Production Cycle Times; Delivered Within Budget  Integrated approach including exploration, appraisal, and development teams  Leveraging existing third-party infrastructure; Big Bend and Dantzler online in 3 and 2 years from discovery

Favorable Cash Operating Margins  Primarily oil development  Attractive cost structure  High per-well deliverability

Discovery

2013

Rio Grande Big Bend Dantzler Gunflint 30

Sanction

First Oil

2014

2015

2016

Rio Grande Development (Big Bend and Dantzler) Positive 2016 capital efficiency impact to NBL Rio Grande development

NBL Interests Infrastructure Producing Discovery

Big Bend 54% WI

Troubadour 60% WI

Big Bend (Online 3 Years From Discovery)  Potential for additional producer wells

Dantzler Leveraging Big Bend Infrastructure  Allowed acceleration of first production to year-end 2015 (2 years from discovery)

Produced at Peak Rate of 19 MBoe/d, Net in 1Q16

Thunder Hawk Production Facility

 Over 85% oil

 Big Bend and Dantzler gross mean resources of 115210 MMBoe Dantzler 45% WI

31

Gunflint Development Provides capital efficiency benefit into 2017 NBL Operated with 31% Working Interest  Mississippi Canyon 948/992

First Oil on Track for Mid-2016:  Two-well subsea tieback  PHA with Gulfstar host facility

Minimum Net Production of 5,000 Boe/d  Upside potential on an interruptible basis depending on host capacity  80% oil

Initial Development Based on Gross Resources of 35 - 90 MMBoe

32

West Africa Operations Substantial cash-flow with material upside Alba Platform Installation Complete  Expected startup mid 2016  Extends the economic life of the field

Strong Production Profile with Minimal Capital Requirements 3D Seismic Processing of Blocks O and I Offshore Equatorial Guinea is Complete  Interpretation underway

Gabon Seismic Acquisition Finishes Mid 2016 Progressing Gas Monetization Discussions

Alba Field 34% WI

Cameroon

Equatorial Guinea Methanol Plant 45% WI LPG Plant 28% WI

Bioko Island

NBL Interests Producing Discovery Exploration

33

Alen 45% WI

YoYo License 100% WI

Aseng 40% WI

Tilapia PSC 47% WI

Alba, Aseng and Alen Major Project Success Reliable and safe performance enhances value

Alba Field in Equatorial Guinea 

34

34% non-operated working interest

Alen

Aseng

Alba

Block I in Equatorial Guinea

Block O in Equatorial Guinea





40% operated working interest

45% operated working interest

2.3 Yrs Sanction to First Oil

2.6 Yrs Sanction to First Oil

2015 Average Net Sales of 51 MBoe/d

2015 Average Net Sales of 11 MBbl/d

2015 Average Net Sales of 13 MBbl/d

Platform Installation Complete

First FPSO Infrastructure in Douala Basin

Offshore Gas Plant for Condensate Separation

Over 99% Average Production Uptime Over Project Life

Condensate Storage and Offloading at Aseng FPSO

Commitment to Global Exploration Excellent environment to build long-term portfolio Exceptional Value From Conventional Offshore Exploration  West Africa and Israel continue cash flow generation  Gulf of Mexico is big contributor to U.S. crude growth in 2016

Exploration Focus:  Large inventory of conventional opportunities globally  Low entry costs in current price environment without drilling commitments

Existing Exploration Portfolio Opportunities:  Additional Gulf of Mexico Miocene exploration appraisal activity planned for 2016 at Katmai  Gabon seismic acquisition finishes mid 2016  Over 10 MM gross acres offshore in the Falkland Islands with multi-billion barrel gross unrisked resource potential

 October 2015 acquisition of a non-operated 20% working interest in Block 54 offshore Suriname; seismic processing underway

35

Guyana – Suriname Basin High potential basin Significant Recent Discovery at Liza Proves Working Hydrocarbon System Block 54 Offshore Suriname  NBL 20% WI, non op.  Tullow operated

 4 year seismic option 2014 – 2018  Proprietary 3D survey completed and in processing; fast track data in-house  Multiple play types

 Maturing leads on block

36

South Basin

Falkland Islands New frontier with significant prospectivity Over 10 MM Gross Acres  North Basin - operated with 75% WI  South Basin - operated with 35% WI

 Multi-billion barrel gross unrisked resource potential  2,500 sq. miles 3D seismic acquired to date

Similar Geologic Plays to West Africa Margin Rhea Prospect Drilling Dependent on Rig Commitment Timing:  De-risked by nearby multiple discoveries including 400+ MMBoe Sea Lion

Sea Lion Discovery

Rhea

North Basin

Falkland Islands

South Basin

 Multiple Cretaceous targets  Stratigraphic trap play

NBL Interests Basin Floor Fan

 ~ 250 MMBo prospect

Slope Fan

Tilted Fault Block

37

2016 Guidance Updated Original 2016 Guidance

2016 Update

2Q16 Guidance

390

405

405 - 415

32% / 13% / 55%

31% / 14% / 55%

30% / 14% / 56%

1.5

<1.5

0.35 - 0.4

90 - 110

90 - 110

15 - 25

Lease Operating ($/Boe)

4.20 - 4.50

4.00 - 4.30

3.90 - 4.20

Transportation, Gathering ($/Boe)

2.90 - 3.10

2.90 - 3.10

2.90 - 3.10

16.00 - 16.50

16.00 - 16.50

16.00 - 16.50

Production Taxes (% Revenues)

4.7 - 5.2

4.5 - 5.0

4.5 - 5.0

Marketing and Processing ($MM)

80 - 100

80 - 100

20 - 25

Exploration ($MM)

330 - 380

330 - 380

60 - 75

G&A ($MM)

410 - 440

400 - 430

100 - 110

Interest, net ($MM)

310 - 330

310 - 330

75 - 85

Sales Volumes (MBoe/d) Product Mix (Oil / NGL / Gas) Organic Capital ($B) Equity Investment Income ($MM)

DD&A ($/Boe)

38

Why NBL? As the energy world continues to evolve Keys to Success: Diverse Yet Focused Portfolio

Financial Strength Delivering Outstanding 2016 Results

Leveraging Downturn: Costs and Efficiency Gains Positioned For Future Value Delivery

39

Appendix

Highly Diversified Asset Base Portfolio offers investment choices and production stability

1Q16 Asset Production Mix

DJ Basin Texas Marcellus GOM EMed West Africa Other

41

1Q16 Commodity Mix

Crude Oil and Condensate Natural Gas Liquids U.S. Natural Gas International Natural Gas

Forward-looking Statements and Other Matters This presentation contains certain “forward-looking statements” within the meaning of the federal securities law. Words such as “anticipates,” “believes,” “expects,” “intends,” “will,” “should,” “may,” “estimate,” and similar expressions may be used to identify forward-looking statements. Forward-looking statements are not statements of historical fact and reflect Noble Energy’s current views about future events. They include estimates of oil and natural gas reserves and resources, estimates of future production, assumptions regarding future oil and natural gas pricing, planned drilling activity, future results of operations, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. No assurances can be given that the forward-looking statements contained in this presentation will occur as projected, and actual results may differ materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. These risks include, without limitation, the volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves, environmental risks, drilling and operating risks, exploration and development risks, competition, government regulation or other actions, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are discussed in its most recent Form 10-K and in other reports on file with the Securities and Exchange Commission (“SEC”). These reports are also available from Noble Energy’s offices or website, http://www.nobleenergyinc.com. Forward-looking statements are based on the estimates and opinions of management at the time the statements are made. Noble Energy does not assume any obligation to update forward-looking statements should circumstances or management's estimates or opinions change. The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The SEC permits the optional disclosure of probable and possible reserves, however, we have not disclosed our probable and possible reserves in our filings with the SEC. We use certain terms in this presentation, such as “MMBoe type curve”, “gross mean” and “total gross resources”. 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 disclosures and risk factors in our most recent Form 10-K and in other reports on file with the SEC, available from Noble Energy’s offices or website, http://www.nobleenergyinc.com.

42

Investors Relations Contacts Brad Whitmarsh

Megan Repine

281.943.1670 [email protected]

832.639.7380 [email protected]

Visit us at the Investor Relations Homepage on nobleenergyinc.com

Energizing the World, Bettering People’s Lives ®