noble energy analyst conference -...
Post on 27-Mar-2018
216 Views
Preview:
TRANSCRIPT
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
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
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
* Term defined in appendix
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
*
* Term defined in appendix
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
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
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
Includes high bids from Lease Sale 213
488,000 Net Acres (119 Lease Blocks)
Expiration Date
48
Deepwater GOM Prospect InventoryFocus on subsalt Miocene
Includes high bids from Lease Sale 213
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
Note: Utilizing reference price case. See appendix
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
Note: Utilizing reference price case. See appendix
$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
* Term defined in appendix
*
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
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
Note: Utilizing reference price case. See appendix
Cum $B$MM
* Term defined in appendix
*
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
Note: Utilizing reference price case. See appendix
$MM Cum $MM
* Term defined in appendix
-200
-100
0
100
200
300
400
-400
-200
0
200
400
600
800
Investment AT Cash Flow Cum AT Cash Flow
2005 2006 2007 2008 2009 2010 2011
*
65
Swordfish Development AreaFurther exploitation opportunities
Additional Near-by Amplitudes
Operated by NBL with 85% WI
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
Includes high bids from Lease Sale 213
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
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
Note: Utilizing reference price case. See appendix
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
Note: Utilizing reference price case. See appendix
$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
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
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
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
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
Investment AT Cash Flow Cum AT Cash Flow
$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
Operated by NBL with 40% WI
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
Investment AT Cash Flow Cum AT Cash Flow
$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
Operated by NBL with 45% WI
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
Investment AT Cash Flow Cum AT Cash Flow
$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
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
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
~$0.5 /MMBtuShipping Cost
~$1.5 /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 $7.7
LNG markets in southern Europe typically paying prices above 50% of crude oil energy
equivalent LNG markets in Asia
typically paying prices at around 90% of crude oil
energy equivalent
150
Global Gas Summary
NBL’s Discovered Resources Positioned to Compete in Global Gas Markets
Location and reservoir quality contribute to low cost developments
Exploration Program Provides Exposure to Significant Additional Gas Resources
Expected to Provide Substantial Growth Second Half of the Decade
Timed to meet growing global gas demand
Project participation based on strategic partnerships
152
Exploration and Geoscience ExcellenceFocus on discovering substantial resources
Solid Track Record of Value Creation
Balanced and Extensive Global Portfolio
Continuous Improvement Effort
Robust Investments in Technology
Attracting Outstanding Talent
Building a Unique Culture
153
Exploration Resources DiscoveredSignificantly exceeding reserves and production
Discovered 275% of Cumulative Production Since 2005
Represents 1.2 Times Current Reserves
Low Finding Costs
0
25
50
75
100
2005 2006 2007 2008 2009
Success Rate%
0
125
250
375
2005 2006 2007 2008 2009 20100
300
600
900
1,200
Predicted Discovered Cumulative Discovered
Resources DiscoveredMMBoe Cum MMBoe
0
2
4
6
8
2005 2006 2007 2008 2009 5YrAvg
Finding Cost per Boe$/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.
This 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
This area intentionally left blank.
163
Subsalt Depth ImagingGunflint 2006 – narrow azimuth 3D, wave equation migration
This area intentionally left blank.
164
Subsalt Depth Imaging Gunflint 2008 – narrow azimuth 3D, beam migration
This area intentionally left blank.
165
Subsalt Depth Imaging Gunflint 2010 – wide azimuth 3D with NBL proprietary RTM
This area intentionally left blank.
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
This area intentionally left blank.
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
This area intentionally left blank.
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
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
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
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
top related