noble energy analyst conference · 2 agenda june 3 analyst conference fcompany overview chuck...

Noble EnergyAnalyst ConferenceJune 3, 2010

2

AgendaJune 3 Analyst Conference

Company Overview Chuck DavidsonChairman and CEO

Operations Summary Dave StoverPresident and COO

Project Management Keith ElliottVP Major Projects

Gulf of Mexico John LewisVP U.S. – Southern Region

U.S. Onshore Ted BrownSVP U.S. – Northern Region

Eastern Mediterranean Rodney Cook / Susan Cunningham SVP International / SVP Exploration

West Africa Rodney Cook / Terry GerhartSVP International / VP Global Gas

Exploration Susan CunninghamSVP Exploration

Financial Review Ken FisherSVP and CFO

Closing Remarks / Q&A Chuck Davidson

3

Forward-looking Statement and Non-GAAP Measures

This presentation/communication may include projections and other “forward-looking statements” within the meaning of the federal securities laws. Any such projections or statements reflect Noble Energy’s current views about future events and financial performance. No assurances can be given that such events or performance will occur as projected, and actual results may differ materially from those projected. Risks, uncertainties and assumptions that could cause actual results to differ materially from those projected 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 action, the ability of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are detailed in its Securities and Exchange Commission filings. Words such as “anticipates,” “believes,” “expects,” “intends,” “will,” “should,” “may,” and similar expressions may be used to identify forward-looking statements. Noble Energy assumes no obligation and expressly disclaims any duty to update the information contained herein except as required by law.

This presentation includes certain non-GAAP financial measures, which are intended to help facilitate comparison of company operating performance across periods and with peer companies. Reconciliations of the differences between any non-GAAP measures used in this presentation and the most directly comparable GAAP financial measures are included in the Appendix.

The Securities and Exchange Commission permits 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. Beginning with year-end reserves for 2009, the SEC permits the optional disclosure of probable and possible reserves. We have elected not to disclose the Company’s probable and possible reserves in our filings with the SEC. We use certain terms in this presentation, such as "net resources," that the SEC's guidelines strictly prohibit us from including in filings with the SEC. Investors are urged to consider closely the disclosures and risk factors in our Forms 10-K and 10-Q, File No. 1-07964, available from Noble Energy's offices or website, http://www.nobleenergyinc.com. These forms can also be obtained from the SEC by calling 1-800-SEC-0330.

For additional information – website www.nobleenergyinc.com

OverviewChuck Davidson

Chairman and CEO

5

What Differentiates Noble Energy?Ability to create long-term value

Diversified … but Focused Global Asset PortfolioAllows for optimal capital allocation for superior returns

Exploration-led GrowthProven track record, “game-changing” opportunities

Broad Lineup of Major Development ProjectsProvides sustainable, visible growth

Disciplined … yet Flexible Financial StrategyDesigned to support long-term growth

Organizational StrengthTalent and experience, “action-oriented” culture

6

Delivering ResultsFive years of performance*

Total Shareholder Return

Debt Adjusted Per Share Production Growth (CAGR)

Debt to Capital, Net of Cash

Exploration Resources Discovered

Competitive Cost Structure

Organic Free Cash Flow**

140%

6%

Improved 18 points

960 MMBoe

Top Quartile

$1.5 B

* Period ending 2009

** Term defined in appendix

7

Delivering ResultsConsistently building a stronger foundation

First Gas Sale in Israel

Patina Acquisition

Gunflint Discovery

GOM ShelfAsset Sale

W. Africa Discoveries Begin

Santa CruzDiscovery

RecordWattenbergProduction

2004 2005 2006 2008 2009 20102007

Tamar Discovery

USX Acquisition

IsabelaDiscovery DJ Basin

Acquisition

8

Industry OutlookOpportunities and challenges ahead

Demand for EnergyValue of oilOpportunities for global gas

Emerging TechnologiesStill much to learn

Regulation and AccessHydraulic fracing, Gulf incident

Service Industry CapabilitiesGrowing capacity and efficiency

Replenishing the WorkforceWindow of opportunity

9

Defined Action Plan for SuccessImplementation already underway

Maintain Underlying Production that Provides Base for Incremental Growth

Progress Major Development Projects to Sanction and Production

Maintain High-impact Exploration for Long-term Sustainable Future Growth

Continue to be Opportunistic in Extending the U.S. Onshore Set

Retain Financial Capacity to Support Business Success

10

Key Outcomes by 2015Substantially enhancing operational and financial performance

10% CAGR to 350 MBoe/d

14% CAGR to 1.6 BBoe5-Yr F&D of $11/Boe

Production

Reserves

Remains Balanced with LiquidsContribution Approaching 50%

$1.6 B Free Cash Flow* in 2015

Portfolio

Flexibility

BTax Cash Margin* Up 28% to $43/BoeROACE 17% in 2015

Cash Flow

Returns

* Term defined in appendix

11

Depth and Quality of OpportunitiesMaterial in scale and scope

Value of a Diversified PortfolioRetaining flexibility and balance

Exposure to Multiple “Company-maker” Prospects

Sustainability of Exploration Success Quality of processPortfolio depth

Confidence in and Visibility of Future GrowthMajor projects are real

Conference Themes to Listen for

Operations SummaryDave Stover

President and COO

13

Operating Strategy

Focus on Four Key RegionsU.S. Onshore, Deepwater GOM, Eastern Mediterranean, West Africa

Execute Major ProjectsDevelop recent exploration discoveriesConvert resources to reserves and production

Continue Exploration SuccessLeverage best-in-class processesFocus on key basins where NBL has a competitive advantage

Manage the PortfolioAcquire “bolt-on” assets in core operating areasDivest higher cost assets with limited development potential

14

Risked Resources (MMBoe)

* Includes 50 MMBoe from 2010 acquisition

Total Net Risked ResourcesNearly five times proved reserves

Proved Reserves* Risked Resources Unrisked Resources

Proved Reserves Discovered UnbookedUS Onshore New Plays Global Offshore Exploration

8,400

4,200

DeepwaterGOM

WestAfrica

Other

EasternMed

USOnshore

870

15

Unrisked Resource Growth Since 2008Substantial growth in opportunity set

0

2,500

5,000

7,500

10,000

2008 2010

Proved Reserves Discovered UnbookedUS Onshore New Plays Global Offshore Exploration

60% Increase

5,200

8,400

MMBoe

16

Total Proved Reserves Outlook Nearly doubles over the next five years

Converting Discovered Resources to Reserves

Expected Timing of Initial Reserve Bookings

Aseng and Galapagos –partially bookedU.S. Onshore – 2010 forwardTamar – 2010Alen (Belinda) – 2010Gunflint – 2011Diega / Carmen – 2013West Africa Gas – 2013

Proved Reserves (MMBoe)

2009 YE 2014 YEUS Onshore Deepwater GOM West AfricaEastern Med Other

14% CAGR

820

1,560

17

Production Outlook Growth driven by existing discoveries and identified plays

0

100

200

300

400

2010 2011 2012 2013 2014 2015Base Ongoing DevelopmentUS Onshore New Plays Major ProjectsGlobal Offshore Exploration

10% CAGR

MBoe/d

18

By Type

Total Capital Allocation2010 to 2015 organic capital averages $2.6 B per year

By Area

DeepwaterGOM

US Onshore

WestAfrica

OtherEastern

Med

OngoingDevelopment

MajorProjects

Exploration Success

Exploration

19

Volume ProfileMaintaining product balance … increasing liquids mix

Further Revenue Benefits from Liquids Increasing from 40% to 48%

US Gas

InternationalGas

Liquids

2010

US Gas

InternationalGas

Liquids

2015

20

Geo-Political Risk ProfileRisk factor remains balanced

International UnitedStates

International UnitedStates

2015

2010

Production

Source: PFC Petroleum Risk Manager

Cou

ntry

Ris

k Pr

ofile

NBL Portfolio

-

1.0

2.0

3.0

4.0

5.0

Uni

ted

King

dom

Can

ada

Uni

ted

Stat

esAu

stra

liaN

orw

ayC

ypru

sM

alay

sia

Isra

elQ

atar

Gab

onG

hana

Braz

ilC

olom

bia

Chi

naU

nite

d Ar

ab E

mira

tes

Con

go B

razz

aville

Thai

land

Nic

arag

uaAr

gent

ina

Viet

Nam

Egyp

tIn

dia

Equa

toria

l Gui

nea

Uga

nda

Ango

laAz

erba

ijan

Indo

nesi

aR

ussi

aLi

bya

Mex

ico

Alge

riaSa

udi A

rabi

aBo

livia

Cha

dIra

nYe

men

Ecua

dor

Iraq

Suda

nN

iger

iaVe

nezu

ela

Lower Risk

NBL Weighted Average Risk Factor 2010 = 4.12015 = 4.2

Higher Risk

21

Major Development Project Line-upInventory of growth drivers

Dee

pwat

er

Gul

f of M

exic

oEa

ster

n M

ed

Wes

t Afr

ica

Galapagos

Gunflint

Diega / Carmen

Alen

Tamar

Aseng

West Africa Gas

2010 2011 2012 2013 2014 2015

Development Timeline

LiquidsGas

Projects Operated by NBL Except for a Portion of Galapagos

22

Major Development ProjectsAdds > 100 MBoe/d and $1 B free cash flow in 2015

-1.2

-0.6

0.0

0.6

1.2

1.8

2010 2011 2012 2013 2014 2015-80

-40

0

40

80

120

Includes Galapagos, Gunflint, Tamar, Aseng, Alen, Diega/Carmen and WA Gas

$B MBoe/dNet Impacts

Note: Utilizing reference price case. See appendix* Term defined in appendix

ProductionAT Operating Cash Flow *

Investment

23

Major Development ProjectsDrive significant improvement in operating margins over time

Key ContributorsMore production from liquids and international gas pricesLong-lived and low cost major projectsHighly productive wells

$23.00

$31.00

Note: Utilizing reference price case. See appendix

$/Boe

40% Higher


Average Operating Margin

0

10

20

30

40

NBL Current Major Projects

*

24

Project ComparisonTamar vs. typical U.S. onshore shale gas play

Tamar – Phase 1 Low finding and development costsLong-lived, stable productionLong-term contract pricingMinimal repeat investment

Typical Shale Gas PlayHigh entry costsResource intensiveU.S. gas market exposureContinued capital requirements

$0.50 / Mcf$0.25 / McfNet LOE

50%36%Assumed WI

4.5 MMcf/d250 MMcf/dGross Well Productivity

4 Bcf1.2 TcfGross Resource per Well

6005# Wells$1 B$1 BNet Investment

1.31.7Investment Efficiency**

$800 MM$1.4 BNet NPV

$1.05 / Mcf$0.50 / McfNet F&D Costs950 Bcf2.0 TcfNet Resources

Shale GasTamar Ph 1

** Defined as NPV10 / PV10 Investment

-600

-400

-200

0

200

400

600

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15Year

$MM

-300

-200

-100

0

100

200

300MMcfe/d

Tamar AT Cash Flow Shale Gas AT Cash FlowTamar Production Shale Gas Production

*


25

Onshore DivestmentHigh-grading the portfolio

Executing $554 MM in Non-Core Asset Divestitures

Expected to close in 3Q 20105,700 Boe/d net production29 MMBoe net proved reserves

Efficient Deal Structure Capturing NPV from Petro-Canada acquisition like-kind exchange

Maintaining Focus on Core Areas

Reallocating resources toward NBL competitive advantagesRedeploying capital to high-value, high-growth projects

26

Deepwater Gulf of MexicoMoratorium on deepwater drilling

Objective is to Provide Enhanced Safety and Environmental Protection and Reduce the Risk of Catastrophic Events

Six Month Suspension for Drilling from Floating Vessels in GOM

Waiting on results of Presidential Commission

Interior Department 30 Day Safety Report RecommendedRecertification of subsea blowout preventers (BOPs)Enhanced well control practicesRevised BOP intervention proceduresAdditional inspections for deepwater drilling operationsExpanded safety and training programs for rig workers

27

Deepwater Gulf of MexicoImpact of moratorium on NBL

Two Deepwater Operations Currently Impacted

In Discussions with Rig and Service Providers

Will Consider Near-term Capital Reallocation to Other Opportunities

Potential Project ImpactsGalapagos schedule can absorb 8 month rig delayGunflint looking at host platform options to offset delay10% additional rig cost requirements lower project returns by 1 - 2%One year delay on Gunflint and Galapagos decrease project AT NPV10 by $95 MM (~5%)

28

Operations Summary

Risked Resources Nearly Five Times Proved Reserves

Double Digit Average Annual Production Growth Through 2015

Reserves Increase 90% by 2015

Major Development Projects on Track

Portfolio Remains Well Balanced

Project ManagementKeith Elliott

VP Major Projects

30

Building on a Track Record of Successful Projects

Lost Ark2001

SS Tieback

Mari-B2004

Fixed Jacket/SS Tieback

Aseng2012FPSO

Tamar2012

SS Tieback

Gunflint2015 FPS/

SS Tieback

Lorien2004

SS Tieback

Swordfish2006

SS Tieback

Galapagos2011

SS Tieback

Alen2014

Fixed Jacket/SS Tieback

Producing

In Development

1990 2000 2010 2020

Raton2008

SS Tieback

31

Major Project Capital Expenditures

2010 - 2015 Cumulative Capital

0

3

6

9

12

Gross Net

$ B

Operated Non-Operated

32

Building to Achieve Excellence in ProjectsThree necessary elements

OrganizationalCapability

BusinessProcesses

Performance Management

ProjectsExcellence

33

Organizational CapabilityOver 2,700 total man years of industry experience

Galapagos Aseng Tamar Alen Gunflint

Man-years Experience

International Projects

Operations Readiness

Project Management

Flowlines and Risers

Subsea ProductionSystems

Deepwater Completions

Floating ProductionSystems

NBL Staff In-house Contract Staff

0 100 200 300 400 500 600 700

34

Organizational CapabilityIntegrating talent from across the industry

Organization Philosophy

NBL Employees Provide Senior Leadership

Access the Best Skills from Across Oil and Gas Industry

Deploy the Best Discipline Talent in Team

NBL Integrates Across Disciplines and Companies, Ensuring Alignment for Project Delivery

ProjectManager

SubsurfaceManager

EngineeringManager

InterfaceLead

ContractsManager

DrillingSupt

SubseaManager

TopsidesManager

SubsurfaceAdvisor

DrillingManager

ContractsManager

ProjectControls

Geoscience DrillingEngineer

ContractsAttorney

OperationsManager

DocumentControl

ReservoirEngineer

CompletionsEngineer

ContractsAnalyst

FlowAssurance

DrillingForeman

ContractsAttorney

ProductionEngineer

Environ.Advisor

SafetyAdvisor

RegulatoryAdvisor

EHSManager

NBL Employee

In-house Contractor

Project Organization Structure

35

Business ProcessesCreating project value – a staged approach

Project Value

Value is created by design, then realized through execution

Time

Execute Operate

PlanningEffort

ExecutionEffort

Design

Appraise Select Define Execute OperateProject Development Stages

36

Central Project Management Organization

The “Noble Way”

Focus on Front-end Loading

External Benchmarking and Performance Reviews

Internal Major Project Reviews

Global Contracting and Procurement

Business ProcessesLeveraging best practices across the portfolio

37

Performance ManagementUtilizing benchmarks to drive performance

Source: IPA

Subsea Cost BenchmarkExample: Aseng Subsea Systems

Ase

ng a

t San

ctio

n

Ase

ng a

t Pre

sent

Targ

et

Contingency $MM

80%

50%75% of projects lower

90% of projects lower10% of projects lower

25% of projects lower

Industry Benchmark for West Africa

38

Performance ManagementManaging project delivery risks

Cost/Schedule Delivery Risks are Identified

Regulatory approvalEquipment deliveryInstallation operations

Risk Mitigations are Identified and EnactedProbabilistic Modeling is AppliedRisk Management is Tracked via Risk RegisterRegular Reviews Track Performance and Identify and Address Emerging Concerns

Major Project Example

Source: AccumenProject Startup Date

Post Mitigation

Variation: 86

Variation: 67

Pre-RiskMitigation

Cum

ulat

ive

Prob

abili

ty

39

Performance ManagementApplying project management best practices

Projects are Tracked Against Capital and Schedule Commitments

Key Project Deliverables are Identified and Tracked

Performance Reporting Systems are an Integral Component of Business Unit Management Processes

Actions Required to Maintain Project Delivery are Communicated and Managed

On Schedule and Under Budget0.00%

20.00%

40.00%

60.00%

80.00%

100.00%

120.00%

As of March 31, 2010

Mon

thly

% P

rogr

ess

Cum. Plan 0.34% 1.02% 2.03% 6.83% 12.31% 23.38% 38.97% 60.82% 79.88% 90.57% 96.53% 98.28% 99.94% 100.00% 100.00%

Cum. Fcst 22.39% 38.81% 61.79% 80.93% 90.86% 96.83% 98.42% 99.94% 100.00% 100.00%

Cum. Actual 0.46% 1.32% 2.38% 4.31% 9.89% 21.96%

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2

2008 2009 2010 2011 2012

Monthly Progress

Expe

nditu

re (U

S$) M

illions

Gro

ss

Cum. PlanCum. FcstCum. Actual

Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q22008 2009 2010 2011 2012

Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Q1 Q2 Q3 Q4

Q1 Q2

2008 2009 2010 2011 2012

Aseng Schedule vs. Plan

Aseng Gross Expenditure vs. Plan

Cum. PlanCum. FcstCum. ActualM

onth

ly %

Pro

gres

sEx

pend

iture

(US$

) Mill

ions

Gro

ss

40

Major Projects Contracting and ProcurementCapturing the buyers’ market

Soft Market Conditions Enabling Favorable Pricing

Pricing is Captured for Significant Portions of 2011 - 2012 Projects

Strategic Sourcing Used Where Applicable

Opportunities to Standardize are Being Leveraged

-

50

100

150

200

250

300

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

2003

US

D b

illio

n

Total Field Development and Pipeline ConstructionActivity Levels

LNGOffshoreOnshore

Source: ODS Petrodata

41

Development Cycle TimesSignificant NBL advantage vs. industry averages

Industry Data Per Goldman Sachs 280

Discovery to Production (Years)

IndustryDeepwater Gas Projects FPSO Projects

On Stream

In Development

Noble EnergyGalapagos

Gunflint

7.0

9.1

4.1

6.5

3.2

8.1

5.1

9.0

12.3

11.1

10.6

Tamar

Alen

Aseng

42

Project ManagementConfident in our approach

Substantial Portfolio of World-class Operated Projects

Building Upon a Track Record of Successful Projects

Highly Capable Project Teams Applying Industry-wide Expertise Within an Independent’s Culture

Employing Project Management Best Practices to De-risk Delivery and Performance

Capturing Supply Chain Opportunities for Added Value

Gulf of MexicoJohn Lewis

VP U.S. - Southern Region

44

Building on Successful Track Record

Two Major Development Projects

Additional Follow-on Potential to Existing Discoveries

Large Resource Opportunity Set Captured

Flexibility to Adapt to Changing Environment

Gulf of MexicoOngoing development with substantial exploration

45

Offshore Evolution of Noble EnergyA successful history

378 MMBoe89 MMBoeGross Resources Found

2007 - 20102001 - 2006

95 MMBoe15 MMBoeAverage Gross Discovery Size

4 of 8 – 50%6 of 11 – 55%Success Rate

50-300 MMBoe10-50 MMBoeProspect Size

Subsalt Structural Mini-basin AmplitudesPredominant Prospect Type

Long-term Legacy Assets

Medium-term High-rate Production

Primary Focus

46

Deepwater GOM Resource InventorySubstantial growth in opportunity portfolio

Focus on Subsalt Miocene for Long-term Growth

Amplitude Plays for Medium-term Impact

Significant Investments in Seismic

Net Unrisked Resource Potential Over 2 BBoe

Average prospect 130 MMBoe gross

0.0

0.5

1.0

1.5

2.0

2.5

2005 2006 2007 2008 2009 2010

Amplitude SubsaltOn-block resources only

Includes high bids from Lease Sale 213

BBoe

Net Unrisked Resources

330% Increase

47

Deepwater GOM Lease InventoryMajority of acreage acquired last three years

0

20

40

60

80

100

120

2010 2012 2014 2016 2018 2020

M Acres


488,000 Net Acres (119 Lease Blocks)

Expiration Date

48

Deepwater GOM Prospect InventoryFocus on subsalt Miocene


0 - 100

101 - 200

201 - 530

0 - 100

101 - 200

201 - 530

Structure AmplitudeProspect Gross Size (MMBoe) 41 Prospects

2.1 BBoe Net Unrisked Mean Resources

550 MMBoe Net Risked Mean Resources

49

0

50

100

150

200

250

Deepwater GOM Amplitude Prospect InventoryCompares well to industry discoveries

Industry DiscoveriesNBL PortfolioNBL Discoveries

Industry Success Rate 38%, Avg. Size 25 MMBoe

NBL Success Rate 53%, Avg. Size 26 MMBoe

Industry discovery data from Wood Mackenzie

Gross Unrisked Resources (MMBoe)

Galapagos (130 MMBoe)

50

0

100

200

300

400

500

600 Industry Success Rate 31%, Avg. Size 163 MMBoe

NBL 2 Discoveries, Avg. Size 130 MMBoe

Deepwater GOM Subsalt Prospect InventoryCompares well to industry discoveries

Industry DiscoveriesNBL PortfolioNBL Discoveries

Industry discovery data from Wood Mackenzie

Gross Unrisked Resources (MMBoe)

51

Deepwater GOM EconomicsDevelopment scenarios by prospect size

200 MMBoeSubsalt Miocene

100 MMBoeSubsalt Miocene

50 MMBoe Amplitude Play

Prospect Size and Class

$18.50$24.25$21.00$19.50F&D ($/Boe)

$2,175$875$1,000$600AT NPV10 ($MM)

35%27%33%43%AT ROR (%)

Success Case Economics

$20.25$27.25$24.00$25.00F&D ($/Boe)

$650$250$275$150AT NPV10 ($MM)

30%22%27%28%AT ROR (%)

Risked Economics

33%33%33%33%Chance of Success (%)

Individual Project Economics

7 Well Stand Alone Spar

6 Well Stand Alone Spar

6 Well SubSea Tieback

4 Well SubSea Tieback

Development Scenario


52

Deepwater GOM Exploration ValueOver $4 billion risked present worth to NBL

Total Portfolio

Stand Alone

Subsalt Miocene

Subsea Tieback

Subsalt Miocene

Subsea Tieback

Amplitude Play

Development Scenario

Primary Prospect Type

40%60%80%Average Chance of Drilling

$14,000$7,000$3,000$4,000Success Case AT NPV10 ($MM)

$4,000$2,100$900$1,000Risked AT NPV10 ($MM)

Prospect Class Totals

2,1001,330420350Total Net Unrisked Mean Potential (MMBoe)

4112920Number in NBL’s Portfolio

Note: Utilizing reference price case. See appendix Includes high bids from Lease Sale 213

53

NBL Operated with 37.5% WI2008 discovery

Complex Subsalt Miocene Reservoir

Over 550 Feet Net Oil Pay Encountered

High-quality SandsPorosity 20-26%Permeability 200-1,000 mD

Gunflint DiscoveryNBL’s largest GOM find to-date

Louisiana

Mississippi Canyon

948

Tubular Bells

Devil’sTower

Kodiak

Gunflint

949

904

54

Gunflint Appraisal ProgramDetermining ultimate size of reservoir

Gross Resources of 70 to500+ MMBoe

2-3 additional wells to fully evaluate

Confirm Reservoir Continuity

Scale Development PlanEconomically viable with existing discovered resources

Miles

0 1 2

Miles

0 1 2

Miles

0 1

Miles

0 1 2

Salt

Discovery Well

1st Appraisal Well

Appraisal Areas

55

Gunflint Production Outlook250 MMBoe gross scenario

0

35

70

105

140

2015 2016 2017 2018 2019Gross Net

MBoe/d

56

250 MMBoe Gross

Stand Alone FacilitySeven subsea wells

Economic SummaryNet resources 70 MMBoeNet capital $1 BF&D $15/Boe AT ROR 30%AT NPV10 $945 MM

Gunflint Mean Resource EconomicsProject payout in approximately one year


$B Cum $B

-0.4

-0.2

0

0.2

0.4

0.6

0.8

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

Investment AT Cash Flow Cum AT Cash Flow

2008 2010 2012 2014 2016 2018


*

57

Galapagos Subsea DevelopmentTargeting initial production in 2011

Upper and Middle Miocene Discoveries

130 MMBoe Gross Resources, 29% Average WI

Sanctioned Development Flowing to NaKika

Multiple Low-risk Follow-on Opportunities

Louisiana

Mississippi Canyon

NaKika

Santiago23.25% WI

Santa Cruz23.25% WI

562 563

606

519

Isabela33.33% WI

58

NaKika

Isabela

Santiago

Santa Cruz

Galapagos Field LayoutSubsea tieback development

59

Galapagos Production OutlookSustained production plateau

0

6

12

18

2011 2012 2013 2014 2015 2016 2017Base Case Upside Recoveries

Net Production

MBoe/d

Dev

elop

men

t wel

l @ Is

abel

a

Dev

elop

men

t wel

l @ Is

abel

a /

Slee

ve S

hift

@ S

anta

Cru

z

60

130 MMBoe Gross Resources

Upside recoveries adds 65 MMBoe

Initially Three Well Subsea Tieback

Base Case Economic Summary

Net resources 37 MMBoeNet capital $405 MMF&D $11/Boe AT ROR 47%AT NPV10 $760 MM

Galapagos Project EconomicsStrong cash flow and returns

-250

-150

-50

50

150

250

350

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017-1.3

-0.8

-0.3

0.3

0.8

1.3

1.8

Base AT Cash Flow Upside Recoveries Cash Flow

Investments Base Cum AT Cash Flow

Upside Recoveries Cum AT CF


Cum $B$MM


*

61

Galapagos Additional Resource PotentialComplementary follow-on upside

Four Offsets Identified To-date

Oil and gas potential40 MMBoe gross mean resource potential

Shallow Zone UpsideDiscovered in Santa CruzConfirmed as oil in Santiago25 MMBoe gross mean resource potential

MC 562 MC 563

MC 518 MC 519

Isabela

Santiago

Santa Cruz

Discoveries

Prospects

Shallow Zones

Well Locations

62

Louisiana

Swordfish Subsea DevelopmentHigh-return amplitude project

Operated by NBL with 85% WI

Subsea Tieback to Neptune

Initial Production Late 2005

Three Wells Currently Producing 12 MBoe/d Net

Evaluating Additional Potential in Area

Viosca Knoll

873

961

917

962

Neptune

Swordfish85% WI

63

Swordfish Production HistoryStable flow rates delivered

0

4

8

12

16

2005 2006 2007 2008 2009 2010 2011Oil Gas

Net Production MBoe/d

64

43 MMBoe Gross

Three Well Subsea Tieback

Economic SummaryNet resources 33 MMBoeNet capital $348 MMF&D $9.30/Boe LOE $3.60/Boe AT ROR 74%AT NPV10 $425 MM

Swordfish Project EconomicsAn asset to replicate


$MM Cum $MM


-200

-100

0

100

200

300

400

-400

-200

0

200

400

600

800


2005 2006 2007 2008 2009 2010 2011

*

65

Swordfish Development AreaFurther exploitation opportunities

Additional Near-by Amplitudes


Same Reservoir as Swordfish

Reprocessing Seismic

20 to 45 MMBoe Gross Resources

VK 873

VK 917

VK 961 VK 962

Gas

Prospects

Oil

Well Locations

Recent Sidetrack

66

Deep Blue ProspectSidetracking updip

Louisiana

Green Canyon

Tahiti

Deep Blue

Constitution

Tonga

Caesar

Heidelberg

723 724

768767

679

Operated by NBL with 33.75% WI

Subsalt Miocene Target

Original Well Encountered Hydrocarbons

Multiple high-quality reservoirsWater – oil contacts 32 net feet of pay

67

Deep Blue Potential RemainsResults to-date reducing risk

Salt

Updip Sidetrack

Pg Increased from 30% to 50%

Targeting Resources of 90 – 200 MMBoe Gross

68

Deepwater GOM Portfolio Candidates for next phase of exploration


Amplitude

Subsalt Miocene

Dirac

Spearfish

Troubadour

Big Bend

Floreana

Santiago

Silvergate

Genovesa

Continuum

Talon 3

Palladium

GunflintNess Deep

Deep Blue

HagarmanRed Tack

69

Deepwater GOM Risked Production OutlookDevelopment and exploration growth contributors

0

15

30

45

60

75

2010 2011 2012 2013 2014 2015Base DevelopmentGalapagos Exploration-tiebacksGunflint

Net ProductionMBoe/d

2010 – 2015 Capital$4.1 B

Exploration

OtherDevelopment

Gunflint

Galapagos

70

Gulf of MexicoConverting resources to value

Maintaining Existing Base Production

Two Significant Development Projects with $1.7 B AT NPV10

Executing Strategy to Create Legacy Assets

Over 2 BBoe Net Unrisked Potential Resources Captured

Working Options to Mitigate Moratorium Impacts

U.S. OnshoreTed Brown

SVP U.S. – Northern Region

72

Strong Existing Cash Flows

Organic Growth Coupled with Opportunistic Asset Purchases

Significantly Expanded Acreage Position

Large and Growing Inventory of Low-risk Development Projects

Additional New Play Potential

U.S. Onshore Broad portfolio of liquid-rich opportunities

73

U.S. Onshore Multi-year inventory of projects

Cody Shale

Central DJ Basin Wattenberg

Tri State

Iron Horse

Piceance

Haynesville ShaleGranite Wash

Cleveland Sand

Gas

Liquids

74

U.S. Onshore Net Risked ResourcesOver three times current reserves

Total Net Risked Resources of 1.6 BBoe

0

200

400

600

800

DJ Basin Piceance Cody Shale Iron Horse Tri State Haynesville Other

Proved Reserves Discovered Unbooked New Plays

MMBoe


75

Discovered Unbooked Opportunity SetSubstantial value in low-risk portfolio

* Does not include horizontal potentialNote: Utilizing reference price case. See appendix

4797167,400+Total

5662200Haynesville

691562,300+Tri State

101147500+Iron Horse

128204900+Piceance

1251473,500DJ Basin Vertical*

Net Risked Resource (MMBoe)

Net UnriskedResource (MMBoe)

Location Inventory

76

U.S. Onshore FootprintA foundation of growth for NBL

0

40

80

120

2004 2005 2006 2007 2008 2009 2010

Gas Liquids

0.0

1.0

2.0

3.0

2004 2005 2006 2007 2008 2009 2010

Developed Undeveloped

Production Contribution Up 420%Liquid stream increased 8 times

2010 exit rate 17% higher than 2009

Captured Acreage Up Five-fold1.5 million acres undeveloped

MBoe/d

MM Acres

Net Production

Net Acreage

77

U.S. Onshore Production OutlookSignificant contributor for the future

0

50

100

150

2010 2011 2012 2013 2014 2015PDP Other Haynesville Tri StatePiceance Petro-Canada DJ Basin

Net ProductionMBoe/d

2010 - 2015 Capital$7 B

Piceance

DJ BasinTri State

Haynesville

Other

Production Growing Over 40%

Increasing Liquid Contribution to 45%

Activity Focused on DJ Basin

78

Industry Wattenberg Field ProductionReinventing a true resource play

0

200

400

600

800

1,000

1970 1974 1978 1982 1986 1990 1994 1998 2002 2006

Codell NiobraraJ sandSussex ShannonD sandOther

20 AcreDensity

Codell Refrac

CodellSussex

D&J Sands

NiobraraMMcfe/d

79

Wattenberg Field – DJ BasinNBL’s largest onshore asset

391,000 Net Acres

Currently Producing 53 MBoe/d50% liquids

Expanding Activity Level6 to 8 rigs by mid 2010

10+ Year Project Inventory

Continued Efficiency Gains

Strong Horizontal Niobrara Results

Additional Zone Potential

MMBoeTotal Net Risked Resources

617Total192New Plays120Discovered Unbooked305Proved Reserves

NBL operated drilling rig

80

Wattenberg Field MarginsBenefits from liquids and low-cost operations

Lifting Cost

Transportation

Production Taxes

Cash Margin

Cash Margin of $42/Boe Using $75 Oil, $5 Gas

Cash Flow Positive at $20 Oil, $0 Gas

$41.70

($3.35)($1.90)($2.90)

$49.85

$5.00$75.00

$49.50Operating Cash Margin ($/Boe)

($3.90)Production Tax($1.90)Transportation($2.90)Lifting Costs

$58.20Net Realized Price ($/Boe)

$6.00NYMEX Gas ($/MMBtu)$85.00NYMEX Oil ($/Bbl)

81

Wattenberg Efficiency Improvements Advancing the vertical well program

Application of Latest Technology

Record drill timesContinual enhancement in stimulation design

Production Increase from Well-head Automation

3,600 wells automated by YE 2010Early results 3-5% production uplift per well

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

-95 -75 -55 -35 -15 5 25 45 65 85

Days

0

50

100

150

200

250

300

350Mcf/d Bbl/d

0

2

4

6

8

2005 2006 2007 2008 2009 RecordWell

40% Decrease

Spud-to-Spud Drilling TimeDays

82

Horizontal Development Potential Enhancing the value of Wattenberg

Increase Field Recoveries

Improve Well Productivity

Lower Finding and Development Costs

Unlock Significant Resource Potential

83

Wattenberg Horizontal NiobraraLeading the evolution of a new play

2004/2005 – Initiate Niobrara Completions

Over 4,700 vertical wellbores to-date

2008 – Extensive Data Gathering Vertical cores and reservoir characterization

2009 – First Four Horizontal Wells With Strong Results

2010 – Seismic and Additional Drilling

Target 14 additional wells

Shoot 75 square miles of 3D seismicSeismic Shoot

Horizontal Well

Thunderhead

70 RanchGemini

Wells Ranch

84

Wattenberg Horizontal NiobraraSubstantial improvement over vertical development


$3,114$306AT NPV10 ($M)35%4059

$655

Vertical Codell/Niobrara

Horizontal Niobrara

64%AT ROR (%)290Gross EUR (MBoe)585IP (Boe/d)

$3,500Well Cost ($M)

0200400600800

1,0001,200

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 Days

Boe/dWell Production

Gemini 500+ MBoe

Four Hz Well Avg.290 MBoe

Avg. Vertical Well40 MBoe

85

Wattenberg Horizontal NiobraraEarly stage development results

Further Opportunity for Improvement on Well Costs and EURsDrill times reduced 17% to-date

Further completion design enhancements

Extended lateralsNote: Utilizing reference price case. See appendix

0

75

150

225

300

150 200 250 300 350 400 450 500EUR (MBoe)

AT ROR (%)

$3.0 MM

$3.5 MM

$4.0 MM

Horizontal Niobrara Economics

Well Costs

86

Wattenberg Horizontal NiobraraPotential within vertically-developed area

Well Development Currently at 32 and 20 Acre Spacing

Analyze Offset Vertical Well Drainage and Fracture StimulationNiobrara vertical draining less than 10 acre spacing

Selected Gemini Location – January 2010 SpudOperated by NBL with 100% WI

32 Acre Density-20 wells

Historical

20 Acre Density-32 wells

Original

XBHLSHL

G E M I N I

1 Square Mile

New Opportunity

87

Wattenberg – Gemini Horizontal WellBest well in the field’s history

4,000 ft Lateral with 16 Stage Fracture Stimulation

Produced 60 MBoe During First 60 Days

10 Times Production and EUR Enhancement

F&D Costs 25% Lower

0200400600800

1,0001,200

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57

Well ProductionBoe/d

Days

Gemini500+ MBoe

Offset Vertical Well

88

Niobrara Reservoir CharacteristicsWidespread distribution

Extensive Geologic Control

Strong Matrix Contribution from High Porosity Chalks

Success Not Limited to Natural Fracture Systems

NBL Acreage

Well Locations

89

350 ft

Niobrara Reservoir PotentialNew technology in a mature field

Seismic Unlocking Next Steps in Development

Integrating with Logs, Microseismic, Tracers

Employing Proven Horizontal Completions

Evaluating Multi-laterals – Codell Application

Can Identify Fracture Swarms

Gives Ability to Steer Wells Within Maximum Porosity

90

Production Influenced by Faults and Fractures

Completion Design Optimized in Real Time

Growing NBL Database Contributes to Wellbore Optimization and Production

NBL Niobrara Horizontal Image Log Interpretation

Niobrara Horizontal ApplicationLeveraging logging technology to identify fracture swarms

WYCO

Grover

LilliGreeley

Bull Canyon

Wattenberg

Orientation ofNatural Fractures

91

Central DJ Basin NiobraraSignificant acreage position outside Wattenberg

360,000 Net AcresLow entry cost $350 per acre

Estimated OOIP 20 – 30 MMBoeper Section

Niobrara hydrocarbons self-sourcingThermal maturity Organic-rich

Recovery of 5% Yields 1.0 – 1.5 MMBoe per Section

130 Square Miles of 3D Seismic Planned for 2010

Drill 9 Horizontal Wells 2H 2010

WYWYCOCO

Silo

NENECOCO

Existing 3D Shoot

2010 Horizontal Well

Seismic Shoot

Grover

Lilli

92

Extensive Horizontal Niobrara OpportunityCombined Wattenberg and Central DJ Basin

Built Premier Acreage PositionTotal 750,000 net acres

Net Unrisked Resource Potential of 1.1 BBoe at 5% Recovery

Competitive Advantage Basin knowledge

Operating capabilities

Wattenberg

WYWYCOCO

NENECOCO

Grover

Lilli

Note: Assumes 160-acre well density and 290 MBoe per well

55050%

36033%27525%

Net Risked Potential (MMBoe)

Prospective Acreage

93

Continuing to Explore WattenbergAdditional prospective zones

Current Exploration ProgramEvaluating additional formationsThree wells currently producing 1,200 Bbl/d

Greenhorn Shale/Limestone (Cretaceous)

Self sourcing rock similar to Niobrara300 ft gross thicknessRecompletion potential

Horizontal Codell (Cretaceous)Strong potential where not depletedMulti-lateral upside with Niobrara

Wattenberg Field

Niobrara Carbonates (300+ ft pay)Oil, Condensate, Gas

Codell Sandstone (10 to 30 ft pay)

J Sand Tight Gas(10 to 60 ft pay)

Plainview Gas

94

Over 2.5 MM Net Acres with Substantial Resource Potential

40% Production Growth by 2015

Liquid Percentage Growing to 45%

1 BBoe of Net Unrisked Horizontal Niobrara Potential in DJ Basin

Applying Best-in-class Technology and Operating Practices

U.S. Onshore Enhancing value for NBL

Eastern MediterraneanRodney Cook

SVP International

Susan CunninghamSVP Exploration

96

Eastern MediterraneanWorld-class potential

Best-in-class Operating Reliability

Leading Operated Position in the Levantine Basin

World-class Discovery Being Developed

Significant Exploration Potential

97

Eastern MediterraneanExisting asset position

Eastern Mediterranean

Haifa

Tel Aviv

Tamar 36% WI

Mari-B 47% WI

Dalit 36% WI

Noa47% WI

98

Israel OperationsLow cost with improving margin

Safe, Reliable OperationsOver one million man hours without an OSHA recordableOver 99.9% reliability since inception in 2004

Outstanding Field PerformanceAdding 50 - 100 Bcf gross to recoverable reserves

Low-cost StructureLOE $0.22/McfDD&A $0.50/Mcf

Price Realizations Above $4/Mcf

Net Production

0

40

80

120

160

2004 2005 2006 2007 2008 2009 2010

MMcf/d

99

Mari-B OperationsInvesting to increase operational flexibility

Ensure Deliverability of 600 MMcf/d

Two additional wells availablein 3Q 2010Compression project expected online by 2Q 2011

Prepare Mari-B as Strategic Storage Facility

Operational flexibility for TamarSecurity of supply for Israel

Compression Module

Platform Platform RigRig

100

2009 World’s Largest Gas Discovery Tamar resources estimate increasing by 33 percent

Studies on Core Samples Confirm Reservoir Quality and Gas Content Better than Previously Estimated

Lower shale content resulting in higher net sand ratioIncrease in average porosity

Netherland, Sewell Updated Analysis Estimates Mean Recoverable Gas at 8.4 Tcf

101

Tamar Reservoir Superior quality and connectivity

Excellent PropertiesClean sand with permeability one darcy and porosity 25%Natural gas >99% methane

Excellent Lateral and Vertical Connectivity

Similar sand units between wells can be traced on seismicExtensive sand/sand contact across faultsIdentical contacts and gas/water pressure gradients in both the discovery well and the 3.4 mile offset appraisal well

Well LogThin Section

102

Tamar Well CompletionsOff the shelf, proven technology

Completions Designed to Flow 250 MMcf/d

Among the highest natural gas well rates in the world

Open-hole Gravel Pack Lowers Screen Erosion Risk

Tubing and Wellhead Built for 30-year Life

Water depth = 5500 ft

Open HoleGravel PackC Sand

A Sand

B Sand

SCSSV

7” Tubing

Gauge Press &Temp

Water depth = 5500 ft

Open HoleGravel PackC Sand

A Sand

B Sand

SCSSV

7” Tubing

Gauge Press &Temp

103

Tamar Field LayoutPhase 1 with 850 MMcf/d deliverability

Water depth 5,000 feet and 60 miles offshore

Subsea production system, no production platform

Natural gas treatment and measurement handled at onshore receiving terminal

Dual 16-inch flow lines to onshore terminal

104

Tamar Update Progress on markets and regulatory items

Contracting Underway for New ResourcesProjected revenue of $11 B for less than 25% of resourcesStrong price base linked to oil products

Identified Customer Base Covers Remaining Phase 1 Capacity

New industries and potential customers Flexible price structure to meet customer needs

Permitting and Regulatory Issues Moving AheadExpect royalty rate to remain unchanged on existing production and known discoveries

105

Tamar Timeline Fast-track development

Project Phase 2010 2011 2012

Front-end Engineering

Order Critical Path Equipment

Detail Design and Engineering

Onshore Construction

Equipment Manufacturing

Commissioning and First Production

Drilling and Completions

Offshore Installation

Fast-track Enabled by Subsea Development, Proven Technology, Gas Quality, Committing to Critical Long Leads Prior to Sanction

~25% of Capital Committed

106

Tamar EconomicsSteady cash flow stream with expansion upside

Phase 1 – Low-cost Development with Sustained Rates

Capital $2.8 B gross, $1 B netCapacity 850 MMcf/d grossF&D $0.50/McfLOE $0.25/McfAT NPV10** $1.4 B

Phase 2 – Upside at Low Incremental Cost

Capacity raised to 1.2 Bcf/dgross with long production plateauIncludes development of Dalit~30% upside on Phase 1 AT NPV10

-600

-400

-200

0

200

400

600

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020-2.0

-1.5

-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

Capex AT Net CF Cum AT Net CF

Phase 1 Development

$MM Cum $B

Cum AT Cash FlowAT Cash FlowCapex

*Term defined in appendix** After royalty and income tax

*

107

Tamar BenchmarkingWorld-class discovery and development

Largest Conventional Gas Discovery in 2009

Fast-track Deepwater Subsea Development Online in Less thanFour Years After Discovery

* Wood Mackenzie estimated commercial plus technical reserves on a 2P basis (associated plus non-associated gas)

1.5

7.3

2.0 2.0

2.5

7.0

5.5

2.0

1.7

4.4-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2009 2011 2013 2015 2017 2019 2021 2023 2025 2027 2029

Source: Wood Mackenzie Upstream Insight

Top Ten Conventional Gas Discoveries of 2009

Start-up date

Water depth (ft)

Bubble size denotes Wood Mac’s 2P estimate (Tcf) *

NSAI estimate of recoverable resources (8.4 Tcf)

OPEC countries

Tamar7.3

108

NBL Operates ~3 MM Gross Acres

20 Prospects and Leads Identified with Gross Unrisked Potential Greater than 30 Tcf

Net unrisked resources 9 Tcf

Leviathan Prospect Expected to Spud 4Q 2010

Additional 3D Seismic Planned Later this Year

Evaluating Options toExpand Drilling Program

Eastern Mediterranean ExplorationLeading acreage position in a emerging basin

3D Prospects3D Prospects

DiscoveriesDiscoveries

3D Survey 3D Survey

Tamar 36% WI

Dalit 36% WI

Leviathan 40% WI

Cyprus A100% WI

109109

Multiple Opportunities in Levantine BasinAdditional Tamar sand prospects

110110

Leviathan ProspectSeismic characteristics similar to Tamar

Both Have AVO and Seismic Flat Event

111111

Leviathan ProspectMean resources twice the size of Tamar

80,000 Acres Aerial Extent 24,000 Acres

16 Tcf* Gross Mean Resource 8.4 Tcf

50% Pre-drill Pg 35%* Unrisked

112112

Multiple Opportunities in Levantine BasinHigh-risk deeper potential

113

Electricity Markets in IsraelNatural gas fueling Israel’s future

Electricity Generated by Natural Gas Expected to Increase 70%Higher utilization of current gas-fired generation capacity New gas-fired generation capacity to satisfy growing domestic electricity demand

Electricity Generation and Fuel Mix

Source: IEC, NBL estimates

2009: 53 Terawatt Hours 2013: 62 Terawatt Hours

Coal

Natural Gas

Fuel Oil/ Diesel

Coal

Natural Gas

Fuel Oil/ Diesel

114

0

200

400

600

800

2010 2015 2020 2025 2030

MMcf/d

Industrial - New Projects

Industrial - Existing Projects*

Industrial Gas Markets in IsraelSignificant room for growth

Source: Poten and Partners* Existing demand/projects and new projects that are in an advanced stage. Industrial market includes desalination, commercial, refinery, chemicals and other industrial plants.

Compelling Economics to Convert from Fuel Oil to Natural Gas

New Gas-enabled Demand

13% CAGR

115

0.0

0.5

1.0

1.5

2.0Bcf/d

Electricity Industrial

Natural Gas Demand Outlook in IsraelRobust long-term demand growth

Source: Historical - NBL; Forecast - Poten and Partners

Gas Demand Growth to-date Driven by Conversion from Fuel to Gas-fired Electricity Generation

10% CAGR

30% CAGR

2004 2010 2015 2020 2025 2030

116

0

0.3

0.6

0.9

1.2

2010 2011 2012 2013 2014 2015 2016 2017

Bcf/d

Imports NBL Operations

Natural Gas Supply Outlook in Israel Supplied by current offshore discoveries

Expected 2012 Demand Fully Covered >35 Years by Existing Offshore Discoveries

117

Eastern MediterraneanWorld-class potential

Mari-B Capable of High Deliverability Through 2012

Tamar Development on Track for 2012 Start upResources increased to 8.4 Tcf gross, 2.6 Tcf net

Significant Exploration Potential on NBL AcreageGross mean resources greater than 30 Tcf in Tamar sandsPotential deep play

Israel Natural Gas Demand Forecasted to Grow 10% CAGR through 2020

West AfricaRodney Cook

SVP International

119

West AfricaBuilding long-term value

Existing Core Assets Providing Strong Cash Flows

Initial Major Projects Focused on Liquid Developments

Additional Upside in Under-explored Basin

Progressing Regional Gas Monetization Plans

120

West AfricaKey position for NBL

West Africa

BiokoIsland

Cameroon

Block O45% WI

Block I40% WI

YoYoMining License

50% WI

Alba Field34% WI

Methanol Plant45% WI

LPG Plant28% WI

Equatorial GuineaTilapia PSC

50% WI

121

Alba Field Core existing asset with strong cash flows

Current Net Volumes 240 MMcf/d, 21 MBbl/d

2009 Net Reserves 65 MMBblLiquids, 942 Bcf Natural Gas

Natural Gas Commercialized with LPG Processing and Sales to Methanol and LNG Plants

Low Unit CostsLOE $3.40/BoeDDA $2.15/Boe

-100

0

100

200

300

400

2009 2010 2011 2012 2013 2014 2015 2016 2017-1.0

0.0

1.0

2.0

3.0

4.0


$MM Cum $B

Includes Alba field and LPGNote: Utilizing reference price case. See appendix* Term defined in appendix

*

122

West Africa – Operated DiscoveriesSetting the stage for growth

300 MMBoe Net Discovered105 MMBbl liquids and 1.2 Tcfnatural gas

Project LineupAseng – sanctioned, first oil mid 2012Alen (Belinda) – FEED underway, sanction expected late 2010Carmen and Diega – appraisal drilling being plannedGas monetization – ongoing evaluation and planning

BiokoIsland

Block O

Block I

Felicita

Diega

Alen

Yolanda

Aseng

Carmen

YoYo

YoYo

Tilapia

Equatorial Guinea

Cameroon

123

Aseng Project Provides hub for future expansions

Project Sanctioned in 2009


Remains on Schedule and on Budget

All Major Contracts Awarded and Development Drilling in Progress

Resource Estimate Increased to 220 MMBoe Gross, 67 MMBoe Net

First Production Expected Mid 2012

Initial rate 50 MBbl/d gross, 17 MBbl/d net (includes cost recovery)

124

Aseng Drilling and Subsurface PlanResource estimate growing with development

39 MMBbl Net Liquid Resource for Oil Recovery Phase

170 Bcf net gas resource

Five Producers, Three Water Injectors and Two Gas Injectors

Pressure Maintenance System to Maximize Recovery

Reservoir Quality Requires Fewer Wells

Horizontal Well Design Improves Recovery and Productivity

Water Injector

Gas Injector

Producer

125

Aseng – World-class Reservoir High performance capacity

Thin Section

Avg. Porosity 26%Avg. Permeability 5 Darcy

High Per Well Rates Give Additional Production Potential

Shallow Production Declines

API Oil Gravity 30 Degrees

0

20

40

60

80

Year 1 Year 2 Year 3 Year 4 Year 5

MBbl/dGross Production

126

Aseng Field LayoutFPSO development

Production Centers

Injection Manifold

3,000 feet water depthTwo, four-slot manifoldsFour risersGas lift provided in umbilicals

127

Aseng FPSO Infrastructure for additional developments

80 MBbl/d oil treating capacity120 MBbl/d total fluids production 150 MBbl/d water injection170 MMcf/d gas production 1.6 MMBbl storage

128

Aseng FPSORefabrication underway

Vessel arrives in Singapore Shipyard March 30, 2010

Initial Topsides – April 8, 2010 Current Topsides – May 12, 2010

129

All Major Contracts Awarded FPSO, drilling and completions and subsea infrastructure

Project Phase 2009 2010 2011 2012

FPSO Engineering & Fabrication

Project Sanction

Drilling and Completion

FPSO Delivery and Installation

Subsea Fabrication and Deliver

First Production

Subsea Installation

Final Commissioning

Aseng Development ScheduleOn schedule and on budget

130

Aseng EconomicsStrong cash flow contributor

Economics SummaryNet Resources 39 MMBbl

Net Capital $510 MM

F&D $13/Bbl

LOE $19/Bbl (includes FPSO lease cost of $10.50/Bbl )

AT ROR 32%

AT NPV10 $535 MM

-400

-300

-200

-100

0

100

200

300

400

2009 2011 2013 2015 2017 2019-1,200

-900

-600

-300

0

300

600

900

1,200


$MM Cum $MM

Note: Utilizing reference price case. See appendix * Term defined in appendix

*

131

Alen Project Liquid-rich development

Front End Engineering Design Study Initiated 1Q 2010

Project Sanction Expected Late 2010


Resource Estimate at 247 MMBoe Gross, 89 MMBoe Net

First Production Expected End of Year 2013

Initial rate 30,000 Bbl/d gross, 15,000 Bbl/d net (includes cost recovery)

Gross Capital Estimate $1.1 – 1.5 B

132

Alen Drilling and Subsurface PlansGas-cycling project

34 MMBbl Net Liquid Resources

334 Bcf net gas resources

Three Producers, Three Water Injectors

Gas-cycling Increases Liquids Recoveries

Preparing for Future Gas Sales

Utilize Aseng FPSO for Liquid ExportPlatform

ProducerWater Injector

133

Alen – High Quality ReservoirStrong performance capacity

Thin Section Gross Condensate Production

0

25

50

Year 1 Year 2 Year 3 Year 4 Year 5

MBbl/d

High Per Well Rates

Shallow Production Declines

API Condensate Gravity 50 Degrees

Avg. Porosity 24%

Avg. Permeability 2 Darcy

134

Alen Platform DesignDesigned as regional gas hub

Platform water depth 250 ft

30 - 40,000 Bbl/d oil handling

350 - 400 MMcf/d gas reinjection

Deck weight 9,000 tons

Operating weight 10,000 tons

Quartering for 50 persons

135

Alen Development TimelineProgressing toward sanction

First Production

Hookup and Commission

Subsurface Infrastructure and Delivery

Development Drilling and Completions

Central Production Platform

Well Head Platform

Project Sanction

Plan of Development and FEED Work

2011 2012 2013Project Phase 2010

136

Alen EconomicsStrong cash flow contributor

Economics SummaryNet Resources 34 MMBbl

Net Capital $620 MM

F&D $18/Bbl

LOE $8/Bbl

AT ROR 30%

AT NPV10 $446 MM

-500

-400

-300

-200

-100

0

100

200

300

400

500

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020-1,000

-750

-500

-250

0

250

500

750

1,000


$MM Cum $MM

Note: Utilizing reference price case. See appendix * Term defined in appendix

*

137

West Africa Production OutlookSubstantial liquid growth

2010 - 2015 Capital$2.6 B

Alba

Exploration

Aseng

Alen

Development Diega

0

25

50

75

100

2010 2011 2012 2013 2014 2015

Alba Gas Alba Liquids Aseng Alen Diega

MBoe/dNet Production

138

West Africa – ExplorationMeaningful potential with multiple play types

Continuing to Mature Deeper Oil Opportunities

High Grading Additional Gas Prospects

Cameroon 3D Seismic Acquisition

Net Unrisked Resources of 370 MMBoe

1.5 MM gross acres in Douala basinPreviously under-explored area

Block O

Block I

Tilapia

Equatorial Guinea

Cameroon

YoYo

139

Equatorial Guinea ExplorationMaturing multiple oil prospects

Sofia and Regina – Block IAVO Supported Miocene Channel Sand

120 MMBoe Gross Unrisked Resources

Pg 50%

Adjacent to Aseng FPSO

Regina

Sofia NE

Carla – Block OLower Miocene Channel Sands

45 MMBoe Gross Unrisked Resources

Pg 25%

Adjacent to Alen

This area intentionally left blank.

140

West AfricaBuilding long-term value

Alba Generating Significant Cash Flows

High-deliverability Reservoirs in Major Project Discoveries

Increasing Liquid Production 150% by 2014

Resuming Exploration Late 2010

Progressing Gas Monetization

Global GasTerry Gerhart

VP Global Gas Monetization

142

Global Gas Outlook

13 Tcf Gross Gas Resources Discovered by NBL and Partners

West Africa 4 Tcf, Eastern Mediterranean 9 Tcf

Additional Gas Resources Expected from Ongoing Exploration

Created Interdisciplinary Team to Evaluate Development Options

Global supply and demand assessments

Market alternatives

Evaluating investment options

Targeting Mid to Late Decade Delivery of New Volumes

143

Global Gas Demand Expected to Grow Substantially

World Gas Demand to Increase by 36% from 2010 to 2030

Cost Effective in New Power Generation vs. Competing Fuels

70% Capacity Increase is Needed to Meet Anticipated LNG Demand Growth

20

30

40

50

60

2010 Capacity UnderConstruction

Planned 2020 Capacity

Source: Poten & PartnersSource: Poten & Partners

Other

2020LNG

Demand

Almost full capacity

6% Overcapacity

2010LNG

Demand

Nigeria

Australia

Bcf/d

Source: IEASource: IEA

250

290

330

370

410

450

2007 2010 2013 2016 2019 2022 2025 2028

1.5% CAGR

Bcf/d Global Gas Demand Global LNG Capacity

144

Major Companies Building Global Gas Portfolios

Australia CBM

US Shale Gas

145

Planned LNG ProjectsNBL’s projects are cost competitive

Arctic

AustraliaCBM

AustraliaConventional

North Africa

West Africa

Relative Upstream plus LNG plants Cost

NBL range of upstream plus

LNG plant costs

Source: Poten & Partners

146

Equatorial Guinea and Cameroon Studying gas export options with governments

Significant Gas Resources to Monetize

Working with EG in Effort to Create Gas Hub Based on LNG Export

Expanding existing plantLow cost, secure location to build new plants

SNH / GdF Suez Studying Feasibility of a LNG Plantin Cameroon

Current phase of study will conclude late 2010 or early 2011

BiokoIsland

Cameroon

Alba Field

LNG Plant

Equatorial Guinea

Block O

Block I

YoYo

Tilapia

Possible KribiLNG Plant

147

West Africa LNGWell placed to target global LNG markets

Counter SeasonalMarkets

Fallback position is theUS markets

~$1.4 /MMBtuShipping/Regas

~$0.8 /MMBtuShipping Cost



EG/Cameroon

LNG shipping to premium oil-indexed markets in Asia is competitiveLNG shipping to new South

American markets is low costPrices at a premium to Henry Hub

LNG markets in southern Europe typically paying prices above 50% of crude oil energy

equivalent

LNG markets in Asia typically paying prices at around 90% of crude oil

energy equivalent

Forecast Netback to Upstream: $2.8 to $9.6

148

Key Markets Accessible from Eastern MediterraneanMultiple export options

Existing Pipeline

Planned Pipeline

Current Gas Discoveries Expect to Fulfill Israel Demand

Significant New Gas Discovery Will Trigger Gas Export Projects

Close Proximity to Oil-linked Markets

149

Eastern Mediterranean LNG Well placed to target global premium LNG markets

~$1.4 /MMBtu Shipping Cost

~$0.3 /MMBtu Shipping Cost Forecast Netback to

Upstream:$3.6 to $7.7

LNG markets in southern Europe typically paying prices above 50% of crude oil energy

equivalent LNG markets in Asia

typically paying prices at around 90% of crude oil

energy equivalent

150

Global Gas Summary

NBL’s Discovered Resources Positioned to Compete in Global Gas Markets

Location and reservoir quality contribute to low cost developments

Exploration Program Provides Exposure to Significant Additional Gas Resources

Expected to Provide Substantial Growth Second Half of the Decade

Timed to meet growing global gas demand

Project participation based on strategic partnerships

Exploration Susan Cunningham

SVP Exploration

152

Exploration and Geoscience ExcellenceFocus on discovering substantial resources

Solid Track Record of Value Creation

Balanced and Extensive Global Portfolio

Continuous Improvement Effort

Robust Investments in Technology

Attracting Outstanding Talent

Building a Unique Culture

153

Exploration Resources DiscoveredSignificantly exceeding reserves and production

Discovered 275% of Cumulative Production Since 2005

Represents 1.2 Times Current Reserves

Low Finding Costs

0

25

50

75

100

2005 2006 2007 2008 2009

Success Rate%

0

125

250

375

2005 2006 2007 2008 2009 20100

300

600

900

1,200

Predicted Discovered Cumulative Discovered

Resources DiscoveredMMBoe Cum MMBoe

0

2

4

6

8

2005 2006 2007 2008 2009 5YrAvg

Finding Cost per Boe$/Boe

154

0

500

1,000

1,500

2,000

0

400

800

1,200

1,600

0

550

1,100

1,650

2,200

0

100

200

300

400

US Onshore Eastern Med

Deepwater GOM West Africa

Net Unrisked (MMBoe) Net Risked (MMBoe)

Global Exploration PortfolioA substantial inventory of opportunities in four key basins

2,0006,000MMBoe

Net Unrisked

Net Risked

Total Resources

155

Global Exploration PortfolioSubstantial worldwide resource exposure

0

500

1,000

1,500

2,000

0

400

800

1,200

1,600

0

550

1,100

1,650

2,200

0

100

200

300

400

Additional High Impact

0

800

1,600

2,400

Includes high bids from Lease Sale 213Net Unrisked (MMBoe) Net Risked (MMBoe)

US Onshore Eastern Med

Deepwater GOM West Africa

156

U.S. Exploration OverviewOnshore tight rock approach

Identify the OpportunityCollect the Right Data

Appropriate combination of technologies early in the program

Comprehensive Evaluation From Regional to Micro ScaleIntegration of analysis and data

Address the Key Uncertainties‘Sweet Spot’ characteristics

Apply Disciplined Exploration ProcessRobust technology and organization capacityLeverage knowledge and ideas Probabilistic assessment of opportunities from basin to well recoveryEstablish pilot program to test uncertainties Learnings leveraged and integrated into full program

157

U.S. Onshore – Tight Rock ApproachBuilding the regional picture

Thermal Maturation ModelThermal Maturation Model 3D Seismic3D Seismic

Reconstruct Basin History

Analyze Fault and Fracture Systems

Potential Fields DataPotential Fields Data

Data licensed from GETECH Processing by Wintermoon

Technologies

Identify and Map Sweet Spot Characteristics

High Grade Target Areas

158

U.S. Onshore – Tight Rock ApproachUtilizing unconventional geophysics

Investigate Fracture SystemsCharacterize Lateral ChangesFacilitate Multi-discipline IntegrationImpact Well Design and CompletionLook Deep to Understand Total PotentialThis area intentionally left blank.


159

U.S. Onshore – Tight Rock ApproachComprehensive well evaluation

Data Collection in Pilot Drilling PhaseWhole core analysis Image logsElemental capture spectroscopyFluid, pressure, temperature samplingMicro-seismic

Whole Core FMI / Image Log ECS Log Micro-Seismic

160

U.S. Exploration OverviewOffshore deepwater approach

Identify the OpportunityFocus on large subsalt prospects

Comprehensive Evaluation from Regional to Prospect ScaleCombine advanced rock property analysis, subsalt imaging interpretation and geologic models

Apply Disciplined Exploration Process

Apply Disciplined Appraisal Process Evaluate key uncertainties for sanctionEstablish well location options and wellbore data requirements

161

Offshore Deepwater Imaging Technology decreases risk

Acquisition – Wide vs. Narrow AzimuthMulti-vessel wide azimuth increases seismic illumination Reduces noise and false-inferred geologic imaging

Processing – RTM Depth Migration AlgorithmsReverse Time Migration (“RTM”) has fewer assumptions and approximationsHandles steep salt edges, horizon dips and complicated wave fronts

What NBL is Doing DifferentlyProprietary input on processing Enhanced subsurface models and work flow

162

Subsalt Depth ImagingComplex salt creates challenges

Example – 3D Image Over Gunflint Discovery


163

Subsalt Depth ImagingGunflint 2006 – narrow azimuth 3D, wave equation migration


164

Subsalt Depth Imaging Gunflint 2008 – narrow azimuth 3D, beam migration


165

Subsalt Depth Imaging Gunflint 2010 – wide azimuth 3D with NBL proprietary RTM


166

Continuum Prospect – Green Canyon 774Subsalt Miocene target

NBL Operated with 100% WI

Water Depth 4,875 Feet

Proposed Well Depth 33,000 Feet

Gross Mean Resources 250 MMBoe

Pg 30%Target Well Location

167

International Exploration OverviewRunning room with initial success

West AfricaBasin opening discovery in 2005Continue exploration with increased focus on oil prospects

Eastern MediterraneanTrend opening discovery in 2009Follow-up exploration to recommence late 2010Shooting additional 3D

New VenturesFocus on high-impact plays worldwideLeveraging core competencies

168

West Africa ApproachSeismic inversion for net gas sand prediction

Established Track Record of Success

Adjusting Seismic, Reservoir and Geochemical Models

Focus on Additional Oil Prospects

Integrating New Cameroon Seismic

Example: Alen Field, Equatorial Guinea

# 2

# 3,4

# 1

14 m

iles

169

West Africa ApproachCameroon prospectivity

1,600 Square Miles of 3D Seismic Acquired

Data Processing During 2010

Multiple Plays Identified on Existing 3D and 2D

Planning for 2011 Drilling Program

Yo-Yo

Tilapia

Cameroon

170

Tilapia Block – Offshore Cameroon

NBL Operated with 50% WI

Water Depth 1,800 Feet

Proposed Well Depth 12,000 Feet

Gross Mean Resources 275 MMBoe

Pg 20%

Cameroon – Bwabe ProspectAmplitude-supported Oligocene target

3D Limit

Line C3D acquired in 2010 to

infill older 2D coverage


171

New Ventures ApproachFocus on high-impact plays worldwide

Example: Offshore NicaraguaMassive carbonate platform170,000 acresGross mean resources of 1 BBoe(based on 2D)NBL operated with 100% WI

Nicaragua

36 km

172

New Ventures Example Offshore Nicaragua – Tyra lead

Isolated Pinnacles 3,000-6,000 Acres Each

Multi-stage Reef Growth

Analagous to Both Large Present Day and Ancient Producing Reefs

36 km

Seism

ic Lin

e

Seism

ic Lin

e


173

Exploration and Geoscience ExcellenceDiscovering next phase of legacy projects

Discovered 960 MMBoe Over Last Five Yearsat Very Low Cost

Global Exploration Portfolio Increased to 6 BBoe Net Unrisked (2 BBoe Net Risked)

Applying Exploration Processes to Unconventional, Tight Rock Plays

Sizeable New Opportunities in Early Stages

Appropriately Leveraging Best Technology

Disciplined Approach to Exploration, Appraisal and Development Programs

Financial ReviewKen Fisher

SVP and CFO

175

Financial StrategyEnsure capital structure to support business

Continue to Deliver Sustained Growth, High Shareholder Returns

Fund Organic Exploration Program

Develop “Long-cycle”, Long-life Major Projects

Proactively Manage Portfolio ExposuresCommodity priceHenry Hub and differentials Liquids and gasDomestic and internationalCredit and event risk

Ensure “Fire Power” for Opportunistic Business Development

e.g., Petro-Canada

176

Exploration Capital SpendingContinuing commitment to organic value creation

0

200

400

600

800

2007 2008 2009 2010

Drilling & Completions Seismic Leasehold

$MM

177

0.0

1.0

2.0

3.0

2007 2010*Corporate US Onshore Other IntlDeepwater GOM Intl Major Projects

66%

34%

Short Cycle / Flexible Projects

Long Cycle / Committed

Projects

66%

34%

Capital SpendingMaterial shift to long cycle, long life major projects

*Includes FPSO capital lease amount of $234 MM

1.7

2.7

$B

178

Financial Position – 1Q 2010Remains strong with $2.5 billion liquidity

Favorable Leverage to Peers

$1 B Cash on Hand

$2.5 B Liquidity

Total Debt $2.4 B

Strong Ratios:

Debt-to-book capital: 27%

Net debt-to-book capital: 17%

Note: Total debt and debt related metrics includes the Aseng FPSO lease NBL Peers

Debt-To-Cap Ratio

NBL Peers

Net Debt-To-Cap Ratio

Well Managed Maturity Profile

0

200

400

600

800

1,000

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Afte

r 20

20

Revolver Bonds

2012 Revolver Matures;Balance as of 3/31/2010

$MM

* Peers as of Q4 2009 including APA, APC, CHK, COG, DVN, EOG, FST, MUR, NFX, PXD, PXP, RRC, SWN, TLM

36%27%

32%

17%

179

Capital Structure ApproachRobust to ensure delivery of value

Ensure Strong Liquidity to Deliver High Return Growth Robust to commodity price cyclesSupports long cycle capital commitments Funds exploration success, new business development particularlyin “down markets”Ensures resource access and host government / partner confidence

Keep a “Conservative” Balance Sheet and Retain Investment Grade Rating

Continue Proactive Risk Management Across the BusinessCommodity hedging program Insurance programCredit managementEnterprise Risk ManagementCash Flow at Risk (CFAR)

Manage Portfolio for Value

180

VolumesMaintaining geographic balance… growing liquids, international gas

2004

2007

2010

2015

Total MMBoeUnited StatesInternational

39 73 ~79 ~12858% 56% 55% 63%42% 44% 45% 37%

LiquidsUS GasIntl Gas

181

Commodity Hedging – U.S. Gas

2010 2011 2012

NBL Peers NBL Peers NBL Peers

NBL as of 4/29/2010

2010 ~70% Hedged in $5.95 - $6.72 Range

2011 ~50% Hedged via Swaps, Collars and 3-way Collars with Downside Protection at ~$5.78

2012 ~10% Hedged via 3-way Collars $4.75 / $5.50 / $7.92

Peers include APA, APC, CHK, COG, DVN, EOG, FST, MUR, NFX, PXD, PXP, RRC, SWN, TLM

~70%

41%~50%

19%~10% 8%

182

NBL Peers

Commodity Hedging – Global Oil

NBL Peers NBL Peers

NBL as of 4/29/2010

2010 ~40% Hedged via Swaps and Collars with Downside Protection at ~$65.48

2011 ~25% Hedged via Collars and 3-way Collars with Downside Protection at ~$79.00

2012 ~5% Hedged with Swaps at $91.84

Peers include APA, APC, CHK, COG, DVN, EOG, FST, MUR, NFX, PXD, PXP, RRC, SWN, TLM

~40% 39%

~25% 25%

~5%14%

2010 2011 2012

183

Cash Flow at RiskA framework for capital structure planning

Interest & PrincipalPayments

Illustrative Example

Prioritization of Cash Needs Dividends

Ongoing Maintenance

CAPEX

Growth CAPEX

Potential Stress

Operating Cash FlowStrategic CAPEX

Revised Operating Cash Flow Distribution, Levers Include (e.g.):

Commodity HedgingCapital Structure ChangesPortfolio ChangesOthers (e.g. Contracting, etc.)

Higher Probability of Funding Strategic CAPEX

Cash Flow Probability Distribution(Monte Carlo)

- CommodityPrice Scenarios

- Business Outcomes

Sustaining CAPEX

2

1Lower Probability of Funding Strategic CAPEX

Pre-CFAR Operating Cash Flow Distribution

184

*Cash plus revolver availability

Financial ProjectionsWell positioned to fund business

2008 2009 2010 2011 2012 2013

$1.4

$1.6

Liquidity*

($B)

2008 2009 2010 2011 2012 2013 2008 2009 2010 2011 2012 2013

% Debt to Cap

<30%

<35%

2008 2010 2011 2012 20132009

185

Financial Summary

Continued Strong Financial Discipline

Proactively Managing Capital Structure and Business Risks

Well Positioned to Fund Exploration and Major Project Growth

Will Maintain Ample Liquidity and Conservative Balance Sheet

Closing Remarks / Q&AChuck Davidson

Chairman and CEO

187

Conference Themes Presented Today

Depth and Quality of OpportunitiesMaterial in scale and scope

Value of a Diversified PortfolioRetaining flexibility and balance

Exposure to Multiple “Company-maker” Prospects

Sustainability of Exploration Success Quality of processPortfolio depth

Confidence in and Visibility of Future GrowthMajor projects are real

Appendix

18

Inflated at 2%Inflated at 2%2013+

$5.75$84.505-Year Average

$85.00

$82.50

$80.00

Crude Oil WTI ($/Bbl)

$5.502011

$6.002012

$5.002010

Natural Gas HH ($/Mcf)Period

Price Assumptions

19

Defined Terms

Discretionary cash flow less capitalFree Cash FlowRevenue less lease operating expenses, production taxes, transportation, and income taxes

Operating Cash Flow

Revenue less capital, lease operating expenses, production taxes, transportation, and income taxes

AT Cash Flow

Revenue less lease operating expenses, production taxes, transportation, and DD&A

Operating Margin

Revenue less lease operating expenses, production taxes, and transportation

Definition

BTax Cash Margin

Term

Cash Flow from Operations less non-acquisition capital

Organic Free Cash Flow

$8.8 B less $7.3 B* = $1.5B2005 to 2009 Organic Free Cash Flow

Definition / CalculationTerm

* Capital excludes 2007 acquisition of W. Oklahoma assets for $292 MM

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