Credit Suisse Energy Summit David Stover, President and COO February 2014

Noble Energy

2

Execution delivering a unique future

Outstanding Growth Agenda Production expected to more than double by 2018 Cash flow to increase $1 B per year Returns to reach record levels

Diversified Portfolio Provides Exceptional Optionality Inventory of ultra-high return opportunities U.S. unconventional, global deepwater and

exploration all play material roles

7.5 BBoe Proved Reserves and Discovered Unbooked Resources Fueling Growth

Industry-leading Exploration Capability Potential to add materially to discovered resources

Financial and Organizational Capacity in Place to Deliver

3

19%

22%

Visible Growth Profile from Discovered Resources

Contributions from All Operating Areas

Superior Operational and Financial Outcomes by 2018 Production 629 MBoe/d

Reserves 2.9 BBoe

ROACE* 17%

$8.3 B discretionary cash flow**

18% net debt-to-cap ratio

Debt-Adjusted Growth per Share* (CAGR)

Production Cash Flow

* Term defined in appendix ** See appendix for referenced price case

Superior long-term performance Five-Year Growth Outlook – 2013 to 2018

Organic Cash Capital

0

2

4

6

8

10

2014 2015 2016 2017 2018

Cash Flow Outlook

4

Growing cash flows support investment program

Grows $1 B per Year with 5-year CAGR of 19% Exceeds Cash Capital Beginning in 2016 $1 B Cumulative Excess through 2018

* Term defined in appendix

$ B

Discretionary Cash Flow* Organic Cash Capital*

DJ Basin

Marcellus

DW GOM

West Africa

Eastern Med.

Other

2018

DJ Basin

Marcellus DW GOM

West Africa

Eastern Med. Other

2014 Discretionary Cash Flow*

2013 Accomplishments

5

Continuing to build on success

Sales Volume Up 20 Percent, Excluding Divestitures Record Reserves of 1.4 BBoe, Up 19 Percent Reserve replacement of 369% with all-in F&D cost of $12/Boe

Delivered Three Major Projects Tamar producing 2.5 years from sanction First production from Alen, 6 months ahead of plan First Integrated Development Plan (IDP)

at Wells Ranch in DJ Basin

Six New Major Projects Sanctioned Exploration Discoveries Continue Building the Future Troubadour, Dantzler, Karish and Tamar SW

Discovered Unbooked Resources Up Over 25% Enhanced Portfolio with Acquisitions and Exchanges Industry-leading Safety Performance

YE 2013 Reserve Roll Forward

6

Nearly 20 percent increase driven by all core areas

1,184

1,406

800

1,000

1,200

1,400

1,600

YE 2012 Production Sales andPurchases

Extensions Performance Price YE 2013

MMBoe

Liquids

Int. Natural

Gas

U.S. Natural

Gas

By Commodity

DJ Basin

Marcellus

DW GOM

West Africa

Eastern Med.

Other

By Core Area

2013 Reserve Replacement of 369%

A Closer Look at 2014 Substantial growth in core areas

7

DJ Basin

Marcellus DW

GOM

West

Africa

Eastern Med

New Ventures

Other

$4.8 B Capital*

Production Outlook 302 – 322 MBoe/d 18% Year Over Year Increase, Adjusting

for Sales and Exchange Led by DJ Basin, Marcellus Shale and Israel

Preparing and Investing for Future Growth Accelerating U.S. onshore developments Developing our next phase of major projects

Increasing Optionality of Eastern Mediterranean Gas Growing Israel domestic market Executing contracts Scoping LNG – floating and onshore

Maintaining High-impact, Strategic Exploration Program NE Nevada play, Cameroon and deepwater GOM Maturing other frontier areas for new drilling

7

*Assume no joint venture carry in the Marcellus Shale program - maximum potential impact $225 MM

DJ Basin

8

Creating and accelerating value … again! Contiguous High-value Acreage Position 609,000 net acres with 87% in oil window Supports acceleration and optimization from IDP’s

Net Risked Resources of 2.6 BBoe 9,500 normal length equivalent locations

Drilling Activity Doubles to Nearly 700 Equivalent Wells per Year by 2018

Five-Year Production CAGR of 23% Technical and Operation Excellence

in All Phases ERLs generating 3X the NPV of normal laterals

Integrated Development Plans (IDPs) enhancing NPV by 30 - 50%

DJ Basin 2014 Operations

9

Premier acreage position

NBL Acreage

Oil Window*

Gas Window

Greater Wattenberg Area

(GWA)

East Pony Northern Colorado

Wells Ranch

* Liquids above 50%

Accelerating Pace of Development 320 operated horizontal wells, which

includes 55 ERLs

Production Up 28%, Adjusting for the Asset Exchange

Performing Basin Wide Downspacing (24 - 32 wells per section) 30 - 40% of 2014 well count Located in 5 IDP areas

Strong Well Performance and Lower Well Costs

IDPs Maximizing Value While Reducing Impacts Wells Ranch and East Pony in progress

Investing $2 B or 40% of Total Capital Program

DJ Basin Downspacing Maximizing value through testing of optimal spacing

Confirmed Minimum 16 Wells per Section in Oil Window

30 to 40 Percent of 2014 Wells at Higher Density Spacing Five IDPs represent over 50% of total

acreage

Determining Optimal Spacing for each IDP considering Reservoir characterization Legacy vertical wellbores Surface constraints

10

24 wells/sec 2014 32 wells/sec 2014

East Pony IDP • 20-35 downspace wells • A, B, and C benches

Mustang IDP • 6-12 downspace wells • B, C, and Codell benches

Greeley Crescent IDP • 6-12 downspace wells • A, B, C, and

Codell benches

Wells Ranch IDP • 50-80 downspace wells • A and C benches

Core IDP • 4-8 downspace wells • A, C, and

Codell benches

Multiple IDP Areas Delivering Superior Results Strong performance of standard length and ERLs

11

East Pony IDP 3 Rohn State ERLs • 8,700’ lateral average • Combined volume of 2,300 Bo/d

and 800 Mcf/d after 20 days

Core IDP 5 well Loeffler Pad • 4,400’ lateral average • Producing 3,200 Boe/d after 30 days

East Pony IDP Timbro – 1st East Pony ERL • 9,040’ lateral • Producing 600 Bo/d and 800

Mcf/d after 90 days

Wells Ranch IDP Recent batch of 10 wells • 4,500’ lateral average • 8 of 10 performing in line

with 400 MBoe EUR • Remaining 2 performing

at 305 MBoe average

Wells Ranch IDP Jenkins – 1st Codell ERL • 6,985’ lateral • Producing 300 Bo/d and 1,400

Mcf/d after 60 days

Integrated Development Plan Impact

12

Decreasing footprint and increasing economics in all phases of the asset life-cycle

Operational Efficiencies

Trucking

Infrastructure

Longer Laterals

Infrastructure

Operational Efficiencies

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

$1.2

$ MM East Pony IDP Incremental Value Uplift per Well

Reduced Development Costs $0.4 to $0.8 MM per well ($1.15 – 2.30 per Boe*) No need for tanks on each well Less water trucking due to distribution lines Pad drilling & ERL efficiencies

Reduced Operating Costs $0.1 to $0.3 MM per well ($0.30 - 0.90 per Boe*) Eliminates oil hauling Eliminates water hauling More efficient use of pumpers Reduced emissions

Drives $2B in Incremental Value for Two Currently Sanctioned IDPs Accounts for only 18% of acreage

Current

Future

* Based on 345 MBoe EUR type curve for East Pony

Marcellus Shale

13

Maximizing value from a premier resource play

Net Risked Resources of 15 Tcfe, Doubled Over Two Years 350,000 net acres in southwest fairway 88% NRI enhances returns

Five Year Production CAGR Over 45% Efficiencies and Learnings Driving Well

Costs Down On track to deliver 20% reduction over 2 year period

ending 2014

Well Performance - EURs and IPs Continue to Improve

Multiple Upside Opportunities Downspacing, delineation, completions

and new intervals

Marcellus 2014 Activity

14

Delivering value with upside opportunities

Accelerating Development 100 operated wet gas and 70 dry gas wells

Lateral lengths on operated wells to average over 7,000 ft.

Production up Over 90% Further Improvement in Well Cost

and Performance Continue to Implement IDP Concept Conduct 500 Ft. Downspacing Tests

in Multiple Areas No interference on 750 ft. spacing

Delineate New Areas Oxford / Pennsboro / Shirley Drill several Burkett tests

Allegheny Airport

Majorsville

Oxford / Pennsboro / Shirley

SW PA Dry

Wet Gas Acreage

Dry Gas Acreage

Focus Areas

Marcellus Operational Excellence

15

Tremendous value added in short period of time

Returns Doubled Through Efficiencies and Performance Improvement EURs up 60% from acquisition Realized 10% cost improvement Focus on long laterals

Wet Gas Area Historical* Today Future

Laterals 5,000 7,000 7,000 - 10,000

Well Cost $7.2 MM $8.0 MM $7.1 - $8.3 MM

$ M Per Lateral Foot $1.44 $1.14 $1.01 - $0.83

Zones Marcellus Marcellus Multiple Targets

Spacing 1,000’ 750’ 750’ - 500’

Stages 300’ 150’ - 250’ 150’ - 250’

EURs

4.3 Bcfe

0.86 Bcfe/1,000’ $1.67 F&D

9.6 Bcfe

1.37 Bcfe/1,000’ $0.83 F&D

BT NPV10 $1.5 MM $7.4 MM

Value Impact of Improvements (Wet Gas)

0

2

4

6

8

Historical* EUR Uplift CostReductions

LongerLaterals

Today

BT NPV10 $ MM

*EUR estimates from JV initiation in 2011. Cost estimates from 2012 Analyst Conference

0

20

40

60

80

100

0 20 40 60 80 100 120 140

Mcf/Lateral Ft.

Days

Marcellus Performance Upside

16

Potential to materially increase resources and type curves

Positive Results from Reduced Stage and Cluster Spacing (RSCS) Average initial rate up to 40% higher

Designing more tests across the JV

Optimized Flowback and Production Potential EUR uplift of 5 - 15%

Potential to increase condensate production

Testing Refrac Potential Offset Wells RSCS Wells

Cum. Production (Normalized) on RSCS Wells and Offsets

Deepwater Gulf of Mexico

17

Sustained value creation with visibility for significant growth

Proven Track Record of Exploration Success Leading-edge technology with disciplined processes

Production and Cash Flow to More than Double in Next Five Years Oil-dominated production delivers strong margins

Existing Infrastructure Contributing to Significant Value Creation

Four Recent Discoveries to Add More than $1.3 B BT NPV10 with Upside Big Bend and Gunflint startups in 2015 - 2016 Dantzler, Troubadour tie-ins to existing infrastructure

Existing Portfolio with 3.8 BBoe Gross Unrisked Resources 4 - 5 prospects planned for drilling in next 2 years

Big Bend Development

18

Substantial upside to initial base development

NBL Operated with 54% WI Gross Resources of 30 - 65 MMBoe Single Well Subsea Tie-back

Development First oil expected late 2015 Peak rate 22,000 Boe/d gross, 90% oil

Additional Potential Resources of 30 - 50 MMBoe Gross Additional producer wells Water injection considered for

secondary recovery

Strong Point Forward Economics (50 MMBoe case) Net capital $385 MM (gross $710 MM) Payout within 2 years of startup BT NPV10 $390 MM BT ROR 42%

• 18 mile subsea tie-back • 6,050 - 7,200 ft. water depth • Accommodate additional

developments

Dantzler Development

19

Leveraging Big Bend infrastructure for exceptional returns

NBL Operated with 45% WI Multi-zone Discover 55 - 95 MMBoe gross resources Over 85% oil

Planned Tie-in to Big Bend Development Allows acceleration of first production

to 1H16 Peak rate 36 MBoe/d gross

Strong Point Forward Economics (55 MMBoe) Net capital $245 MM (gross $540 MM) Payout less than 1 year from startup BT NPV10 $695 MM BT ROR 98%

Big Bend Dantzler

Troubadour

West Africa

20

Leveraging expertise and experience in Africa

Unique Approach to Creating Value Liquids and gas monetization with

LPG, LNG and Methanol

Two Major Projects Brought Online in Last Two Years

Leveraging Infrastructure for Future Developments Diega sanction targeted in 2014

Expanding Regional Position into Highly Prospective Areas

Progressing Regional Gas Monetization Plans

Exploration Well Planned for Cameroon in 2014

Alen, Another Major Project Success

21

Unique design leverages Aseng FPSO

Project Sanction to Startup in 30 Months First production in May 2013, 6 months early On budget for $1.3 B gross

Designed to Maximize Value Offshore gas plant for condensate separation Gas reinjection for enhanced condensate recovery

and future monetization Condensate storage and offloading at Aseng FPSO

Field Expected to Reach 30 - 35 MBbl/d Gross in 2014 Currently producing 28 MBbl/d

Best-in-class Safety Performance Over 11 million man hours worked since sanction with only

one lost-time incident

Greater Diega Area

22

Leveraging existing infrastructure

Diega, Carla and Carmen Operated with 45% WI 70 - 200 MMBoe gross resources 75% liquids

Diega Oil Development Positive results from 2013 appraisal Successful flow test confirmed

reservoir continuity and quality Initial development phase

30 - 135 MMBoe gross

Moving Forward with Sanction Finalize development plans by mid 2014 Expect first oil late 2016 at 10 MBbl/d per well Evaluate regional development scenarios,

including Carmen and Carla discoveries

Alen

Diega Aseng

Eastern Mediterranean

23

World-class discoveries with world-class opportunities

Approximately 40 Tcf Gross Resources Discovered Over 19 Tcf available for export markets

Outstanding Operational Performance from Tamar Averaging 750 MMcf/d since startup

Growing Domestic and Regional Markets Israel demand growth expectation increased to 17% Multiple regional markets emerging

Leviathan Development Options Progressing Continuing Exploration and Appraisal Program 3 BBbl and 4 Tcf of remaining potential

Generating Strong Cash Flow to Support Future Projects

0.0

0.4

0.8

1.2

1.6

Capacity Expected Annual Avg. Sales

2014 2015 2016

Tamar Field

24

Supplying a growing domestic market

Outstanding Operational Performance Near 100% facility uptime Current deliverability capacity of 1 Bcf/d Averaged 750 MMcf/d since startup

Quality Investment $0.90/Mcf F&D, $0.40/Mcf LOE Average price realization $5.75/Mcf

200 MMcf/d Onshore Compression Expansion Project Underway $220 MM gross investment with

mid 2015 startup Tamar SW provides added flexibilty Underpinned by IEC gas purchase option

Additional Expansion to 1.5 Bcf/d Planned for 2016 Supported by identified / executed contracts

AOT Compression +22%

Planned Further Expansion +25%

Capacity and Sale Projection

Bcf/d

Leviathan Development

25

Monetizing 19 Tcf of natural gas resources

Phased Development Approach Diversifies supply to Israel New regional and LNG markets

Focus on Partnering with Government and Customers

Initial Development Targeting Domestic and Regional Markets Sanction driven by market and

regulatory maturity Targeting first sales in 2017

LNG, FLNG Options Progressing Finalizing the Sell Down to

Woodside

Leviathan FLNG

Leviathan FPSO

Fixed Platform

Leviathan Memorandum of Understanding

26

Bring in a strategic partner with LNG expertise

NBL Selling 9.66% Interest to Woodside Continue as upstream operator with 30% working interest

Cash Payments Totaling $525 MM $390 MM at closing, which is expected in 2014 $135 MM at FID of LNG project or as regional exports contracts are signed

Revenue Sharing Up to $502 MM 2.9% of WPL’s export revenues, once gross export volumes exceeds 2 Tcf

Other Payments $19 MM should Leviathan resources be determined to exceed 20 Tcf 1.0% royalty on WPL’s oil revenues related to deep Mesozoic oil development

Woodside to Operate LNG field development Subject to Execution of Definitive Agreements and

Customary Regulatory Approvals

Robust Exploration Prospect Inventory

27

Testing 850 MMBoe net risked resources in the next 24 months

Eastern Mediterranean • Deep Mesozoic oil test in Israel • Drill next Cyprus gas prospect

Deepwater GOM • Test 4 – 5 Miocene prospects

Falkland Islands • Complete 3D seismic evaluation • Spud first operated well

NE Nevada • Drilling additional wells • Conduct production tests Sierra Leone

• 3D seismic acquisition

Cameroon • Exploration well planned

Noble Energy

28

Delivering a unique future

Forward-looking Statements and Other Matters

29

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,” 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. 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.

This presentation also contains certain historical and forward-looking non-GAAP measures of financial performance that management believes are good tools for internal use and the investment community in evaluating Noble Energy’s overall financial performance. These non-GAAP measures are broadly used to value and compare companies in the crude oil and natural gas industry. Please also see Noble Energy’s website at http://www.nobleenergyinc.com under “Investors” for reconciliations of the differences between any historical non-GAAP measures used in this presentation and the most directly comparable GAAP financial measures. The GAAP measures most comparable to the forward-looking non-GAAP financial measures are not accessible on a forward-looking basis and reconciling information is not available without unreasonable effort.

The Securities and Exchange Commission 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 “discovered unbooked resources”, “resources”, “risked resources”, “recoverable resources”, “unrisked resources”, “unrisked exploration prospectivity” and “estimated ultimate recovery” (EUR). 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.