3. Noble Energy … Unique. By Design.
Positioned for a decade of growth
Five Core Areas Delivering Outstanding Results
Production expected to more than double by 2017
Proven reserves projected to increase 114% over 5 years
Major Projects Generating Strong Cash Flows
Tamar and Alen contributors in 2013
Portfolio of High Return Reinvestment Opportunities
5.1 BBoe net risked discovered unbooked resources
Industry-Leading Exploration Program
Potential to add at least one new core area in next 2 years
Financial Strength to Assure Ability to Execute
Organizational Capacity to Manage a
Rapidly Growing Business
3
4. 18%
21%
24%
Five-Year Growth Outlook – 2012 to 2017
Superior long-term performance
4
Debt-Adjusted Growth per Share*
(CAGR)
ReservesProduction Cash Flow
Transparent Growth Profile
from Discovered Resources
Contributions from All
Operating Areas
Key Outcomes by 2017
Production 540 MBoe/d
Reserves 2.6 BBoe
ROACE* 17%
$7.4 B discretionary cash flow**
Expect Double-Digit Growth
Rates for Next Decade
* Term defined in appendix
** See appendix for referenced price case
5. DJ Basin
Eastern
Med.
Other
Marcellus
U.S.
Onshore
DW
GOM
Eastern
Med. West
Africa
New Ventures
Net Risked Resources
Strong foundation for current and future growth
5
Net Risked Net Unrisked
Proved Reserves* Discovered Unbooked
Core Area Exploration New Play Types
9.9
Total Resources (BBoe)
Discovered Unbooked 5.1 BBoe
Exploration 3.7 BBoe
18.8
* Proved reserves and resources adjusted for divestitures
6. Production Outlook
Strong diversified growth from discovered projects
6
0
100
200
300
400
500
600
2012 2013 2014 2015 2016 2017
MBoe/d
Base Onshore Horizontal Offshore Projects Exploration
17% CAGR
300 MBoe/d
116 MBoe/d
540 MBoe/d
Note: Base includes assets brought online through 2012. Remaining non-core divestitures assumed to occur 2013
7. Discretionary Cash Flow* Outlook
Growing a billion dollars per year
7
0
2
4
6
8
2012 2013 2014 2015 2016 2017
$ B
DJ
Basin
DW
GOM
West
Africa
OtherEastern
Med.
2012
DJ
Basin
DW
GOM
West
Africa
Other
2017
Marcellus
Marcellus
Eastern
Med.
* Term defined in appendix
21% CAGR
8. 38%
33% 32%
29%
25%
28%
YE 2011 YE 2012 2Q 2013
Debt-to-Cap Net Debt-to-Cap
Robust Financial Position
Positioned to fund long-term growth plans
$4.7 Billion of Liquidity
$0.7 B cash on hand
$4.0 B unused revolver
Debt-to-Capital Ratio,
Net of Cash 28%
Total Debt $4.1 B
Investment Grade Rating
with Stable Outlook
Moody’s Baa2
S&P BBB
8
Favorable Leverage
Excludes $324 MM FPSO lease liability amortized over 15 years
Well-Managed Maturity Profile
0
400
800
1,200
1,600
2013 2015 2017 2019 2021
JV Installment Payments Bonds
$MM
2013 2014 2019 2021 2022+
9. 45% 44%
59%
63%
Oil U.S. Gas Oil U.S. Gas
9
Commodity Environment
Proactively hedged to reduce cash flow volatility
Oil Floor** Ceiling
2013 $93.40 $105.68
2014 $94.78 $99.04
** Based on Calendar Nymex strip on 6/28/13
Hedge Positions
~ 15% of Volumes Tied to Unhedged U.S. Natural Gas
~ 50% of Liquids Priced Using Brent or LLS Index
2013 2014*
* Calculated using 2013 mid-range guidance
Gas Floor** Ceiling
2013 $4.28 $5.21
2014 $3.85 $4.83
Note: Hedges include swaps, collars, 3-way collars
10. -15%
-5%
5%
15%
25%
35%
NBL F B D H G C I E A
2004 – 2012 Dividend Growth
Per Share
Investment Grade Peers*
N/A
10
NBL Dividend
Commitment to competitive payout
*Peers listed in appendix
Note: N/A = No dividend paid
Over Last Eight Years, NBL’s Dividend Per Share has Grown at a 32% CAGR
0.05
0.08
0.14
0.22
0.33
0.36 0.36
0.40
0.46
0.55
0.00
0.15
0.30
0.45
0.60
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013E
$/Share Dividends**
**Dividends adjusted for stock split as of May 2013.
11. 2013 Volumes and Capital Outlook
Substantial growth in core areas
Production Outlook
270 – 282 MBoe/d
20% Year Over Year Increase,
Adjusting for Divestments
Invest $3.9 Billion in 2013
Accelerate onshore unconventional
horizontal programs
Complete Tamar and Alen
Exploration and appraisal drilling in DW
GOM, Eastern Med and West Africa
Significant New Venture exploration
11
Note: From continuing operations
DJ Basin
Marcellus
DW
GOM
West
Africa
Eastern
Med
New
Ventures
Other
Capital Allocation By Area
12. Onshore Unconventional Developments
Contributing impactful growth
12
0
50
100
150
2012 2013 2014 2015 2016 2017
MBoe/d
54% CAGR
Marcellus
DJ Basin
0
100
200
2012 2013 2014 2015 2016 2017
MBoe/d
20% CAGR
Accelerating Horizontal
Activity Levels
Repeatable, low-risk investments
Capturing economies of scale
Improving EURs and
Recovery Rates
Enhancing Performance
Through Technology and
Operational Efficiencies
DJ Basin Liquids Play
Crude oil and NGLs represent ~ 65%
total production in 2013
Marcellus Development
Approximately 65% of drilling activity
in wet gas area in 2013
13. 0
20
40
60
80
100
120
1Q 11 2Q 11 3Q 11 4Q 11 1Q 12 2Q 12 3Q 12 4Q 12 1Q 13 2Q 13
DJ Basin-Vertical DJ Basin-Horizontal Marcellus
13
Core Onshore Unconventional Production
1H 13 volumes up nearly 30% from 1H 12
Current Production ~ 125 MBoe/d
MBoe/d
14. DJ Basin
A premier oil play
Compares Favorably to Other Plays
Oil in place now estimated at 74 MMBoe per section
Net Resources 2.1 BBoe
9,500 horizontal locations, 85% in oil window
Hz EURs continue to improve averaging 335 MBoe
Five Year Production CAGR Over 20%
Oil production grows 3.5 times
Rapidly Accelerating Development Program
with 500 Wells per Year Targeted in 2016
Technical and Operational Excellence
in All Phases
Exploration, drilling, completions and infrastructure
14
15. Niobrara is a Top Oil Resource Play
Superior resources and low development costs
15
Source: Internal, Wood Mackenzie, External Company Presentations, Tudor Pickering
Oil Play Characteristics Well Characteristics
Depth
(Feet)
Thickness
(Feet)
OOIP
(MMBoe /
Section)
Avg.
EUR
(MBoe)
Avg.
Liquids
%
D&C
Capital
$MM
Lateral
Length
(Feet)
Net*
F&D
($/Boe)
NBL Nio Oil Window
– Standard Length
5,500-8,200 250-350 65-73 335 65% $4.5 4,500 $16.79
NBL Nio Oil Window
– Extended Reach
5,500-8,200 250-350 65-73 750 65% $8.3 9,100 $13.83
NBL East Pony
– Standard Length
5,500-8,200 250-350 90 345 85% $4.9 4,500 $17.75
Eagle Ford Oil 4,000-8,000 200-300 30-50 450 65% $6.0 5,500 $16.67
Bakken 7,000-11,000 75-150 10-15 600 86% $9.5 10,000 $19.79
* 80% NRI assumed
0
5
10
15
20
Niobrara Eagle Ford Bakken
$/BOE Net Present Value at 10%
0%
20%
40%
60%
Niobrara Eagle Ford Bakken
Before Tax Returns
Source: Credit Suisse
16. Accelerating DJ Basin Development Program
Double activity in two years
Additional 1,100 Wells Over
Next Five Years vs. 2011 Plan
500 wells per year by 2016, more
than double 2012 level
16
Horizontal Wells
0
1,000
2,000
3,000
0
150
300
450
600
2011 2012 2013 2014 2015 2016 2017
Cum
Wells
Wells
GWA N. Colorado
2012 Cum 2011 Cum
-500
0
500
1,000
2013 2014 2015 2016 2017
$MM
2011 Analyst Conference 2012 Analyst Conference
Free Cash Flow*
Cum $2.4 B
Dramatic Improvements in
Economic Value Over 2011 Plan
Production up 35%
Free cash flow up $900 MM
* Term defined in appendix
17. DJ Basin 2013 Operations
Focused on oil window with superior economics
Accelerating Development
Target 300 horizontal wells spud
Currently operating 10 rigs
Delineating New Areas of
Northern Colorado
Robust economics with 85% liquids
Horizontal DJ Production Up
100% from 2012
Increasing Recoveries via
Downspacing and
Extended-reach Laterals
Investing $1.7 Billion or
45% of Total Capital Program
17
Wyoming Nebraska
Greater
Wattenberg
Northern
Colorado
NBL Acreage
Gas Window
Oil Window
230,000 Net Acres
300 MMBoe NRR
1,750 Locations
290,000 Net Acres
1,400 MMBoe NRR
6,400 locations
120,000 Net Acres
400 MMBoe NRR
1,350 Locations
Wells Ranch
18. 0%
40%
80%
120%
160%
$70 $80 $90 $100
BT ROR
WTI Crude Oil ($/Bbl)
0
250
500
750
0 12 24
Boe/d
Months
GWA Gas
Window
GWA Oil
Window
East Pony
DJ Basin Well Economics
Strong returns over a broad price range
ROR Sensitivity to Oil Price**
18
* Utilizing reference price case. See appendix, 80% NRI.
** NYMEX gas flat at $3.50/MMBtu in all cases, 80% NRI.
Type Curves
BT Economics*
GWA Gas
Window
GWA Oil
Window East Pony
EUR (MBoe) 435 335 345
Liquids (%) 45% 65% 85%
Well Cost ($MM) $4.5 $4.5 $4.9
NPV10 ($MM) $3.6 $3.9 $6.0
ROR (%) 65% 70% 109%
Payout (Years) 1.4 1.3 1.0
Reference Price
19. 0
200
400
600
800
1,000
1,200
0 30 60 90 120 150 180 210 240 270 300
Boe/d
Days
750 MBoe Type Curve Well Average1 MMBoe Type Curve
► 11 Wells Online and Performing Above
Expected Type Curves
► EURs Average Above 750 Thousand
Barrels Equivalent
Extended-Reach Laterals – Wells Ranch
Maximizing value per horizontal foot drilled
19
20. Northern Colorado Niobrara
Leveraging expertise to unlock new opportunity
20
Wyoming Nebraska
Lilli Plant
East Pony
* Rolling 3 day average
Keota/LNG Plant
Greater
Wattenberg
Superior Economics in
East Pony
45,000 net acres
Producing 80% oil, 5% ngl
Three Well 80-Acre Pilot
Yielding Best Results
to Date
Approximately 80 Well
Program in 2013
Delineation with East Pony and
appraisal of western acreage
0
200
400
600
800
1,000
0 90 180 270 360
Boe/d*
Days
27 Well Average
80-Acre Pilot
335 MBoe Type Curve
21. Optimizing DJ Basin Resource Recovery
Continuously learning from pilot program
Entire Niobrara / Codell Section Productive
B Bench Wells Unaffected by Tighter Spacing
Minimum 16-Well (40-acre) Development per Section
Testing Additional High Density Patterns with
Potential for 32 Wells per Section
80 Acre
40 Acre
660’
330’
40 Acre
40 Acre
330’
330’
21
22. Integrated Development Plans (IDP)
Optimizing ultimate resource recovery
22
Economies of Scale Driven by Central
Gathering and Processing Facilities
Decreasing Capital and Lease Costs
Reduced Surface and Environmental
Impact and Enhanced Safety Culture
Life-cycle Water Management Program
Wells Ranch IDP
Continue testing downspacing, multi-zone, and
long laterals
Approximately 1,000 drilling locations remain
Connecting multi-well EcoNodes to Central
Processing Unit
23. DJ Basin Midstream Infrastructure
Development plans aligned with infrastructure build-out
2323
GWA Gross Operated Gas
0
20
40
60
80
100
Jan-12 Jul-12 Jan-13 Jul-13
MBbl/d
GWA
Northern Colorado
Estimated NBL Capacity
Gross Operated Oil
0
100
200
300
400
500
Jan-12 Jul-12 Jan-13 Jul-13
MMcf/d
Gross Operated Production
Estimated Capacity
Gas Processing Expansions of 900 MMcf/d
DCP LaSalle to be completed 2H 2013, Lucerne 2 finished 2H 2014
Front Range Express NGL Pipeline (80-100 MBbl/d) by 3Q 2013
Additional Oil Takeaway Capacity Through Pipeline Expansions and Rail
White Cliffs expanding by 80 MBbl/d
In-field oil gathering system (50-80 MBbl/d) by 3Q 2013
Rail terminal (>60 MBbl/d) by 3Q 2013
Infield Pipelines for Flow Assurance and Reduce Truck Traffic and Costs
24. Marcellus Shale
Significant scale and growth
24
Large Acreage Position within Marcellus Fairway
50% of 628,000 gross JV acres
87% HBP allowing for development flexibility
Average NRI of ~88%
Net Risked Resources of 10 Tcfe
Rapid Growth Underway
Approximately 120 wells in 2013, up over 35% from 2012
Aligned with JV Partner – CONSOL Energy
Activity focused on wet gas areas
Common focus on EHS and operational improvements
25. Marcellus 2013 Operations
Focusing near term in wet gas areas
Increase NBL-Operated Wet
Gas Rig Count to Five and
Target 80 Wells
Developing Majorsville and
delineating new areas in W. Virginia
Non-Operated Dry Gas
Program Drilling ~ 40 Wells
Focus in SW PA high EUR area
Targeting Year-End 2013
Net Production in Excess of
210 MMcfe/d
Nearly 100% increase from YE
2012
Leveraging Best Practices
on Drilling and Completions
25
VA
OH
PA
WV
MD
CONSOL Operated
452,000 Gross Acres
NBL Operated
176,000 Gross Acres
SW PA Wet
EUR 5.6 Bcfe
C PA Dry
EUR 4.4 Bcfe
SW PA Dry
EUR 7.0 Bcfe
WV Dry
EUR 5.0 Bcfe Dry Gas
NBL Activity
Wet Gas
26. 26
NBL-Operated Wet Gas Activity
Accelerating drilling and completions in liquid-rich areas
SHL1,3,6
Producing
WFN1: 7-well Pad
Completing
WEB 4: 11-well Pad
Producing
SHL 8: 11-well Pad
Producing
Marshall County
Washington County
Greene County
Majorsville
OH
PA
WV
MD
Dry Gas
Wet Gas
NBL JV Area
Majorsville
WFN6: 8-well Pad
Drilling
SHL17: 6-well Pad
Drilling
PENS1: 9-well Pad
Drilling
OXF1: 6-well Pad
Drilling
NORM 1: 6-well Pad
Completing
27. Marcellus Shale Economics
Attractive today with potential to improve
Targeting 20% Cost
Improvement
Optimizing drilling and
completions
Obtaining fit-for-purpose rigs
Price Uplift for Wet Gas
Value over $7 per Mcf realizing
$3.50/Mcf and $90/Bbl
27
Note: Well costs includes gathering
* Utilizing reference price case, see appendix
Single Well Economics*
(5,000 Foot Lateral)
0%
20%
40%
60%
5 6 7 8
Well Cost ($MM)
Targeted
Costs
Current
Costs
BT ROR
Dry Wet
0
2
4
6
8
Gas
NGL
Condensate
$/Mcf
1,050
MMBtu
2% shrink
50 Bbl/MMcf NGLs at 55% WTI
Dry Gas
$7.10
$3.60
1,130 MMBtu residue gas (includes ethane)
15 Bbl/MMcf condensate at 80% WTI
Wet Gas
10% shrink
28. Marcellus Gas Marketing
Processing capacity and firm transportation captured
Firm Transportation
Capacity secured for volumes
through late 2014
Strategy to own FT for up to 50%
of production and sell remaining to
counterparties with FT
28
0
100
200
300
400
Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14
MMcf/d Gross Majorsville Processing
Gross Wellhead Production Processing Capacity
Additional Capacity Option
0
100
200
300
400
Dec-12 Apr-13 Aug-13 Dec-13 Apr-14 Aug-14 Dec-14
MMcf/d Net Firm Capacity
Production Firm Commitment Planned 2013 Adds
Processing
230 MMcf/d of processing capacity
at Markwest Majorsville facility
Option for additional 120 MMcf/d
Industry gas processing capacity
will increase 2.5 times to 4.6 Bcf/d
by 2015
29. Global Offshore Major Projects
Meaningful new production and sanctions targeted
Exploration Success has Delivered Strong Cash
Flow and Substantial Value
Strong Track Record of Major Project Delivery
4 major projects online within budget cost and timeframe from
2011 - 2013
Tamar and Alen in 2013
Additional Discoveries Providing Substantial
Long-term Growth
Rio Grande area and Gunflint in DW GOM lead to new
production in late 2015
West Africa fields to utilize existing infrastructure
Continued natural gas market expansion and exports from
Eastern Mediterranean fields
29
30. 30
Major Deepwater Project Line-up
Multiple new sanctions targeted in 2013
Appraisal, Development Timeline
Primarily Liquids
Primarily Gas
Sanctions through cooperation with partners and governments
West
Africa
Deepwater
GOM
Eastern
Mediterranean
Gunflint
Carla / Diega
Alen
Tamar
2012 2013 2014 2015 2016 2017
Leviathan Phase 1
Rio Grande
First Production April 2013
Tamar Phase 2
Leviathan – export
First Production June 2013
All projects operated by NBL
2018
31. Deepwater Gulf of Mexico
Proven performance and impactful exploration portfolio
Strategic Approach has Delivered Strong Cash Flow
and Substantial Value
Galapagos Project Continues to Perform Above
Expectations
Point Forward BT NPV10 $1.4 billion
Targeted Sanctions in 2013 for Rio Grande Area and
Gunflint Lead to New Production Late 2015
High-Quality Exploration Portfolio with Oil Focus
and Running Room
Dantzler results by end of 2013
Multiple prospects planned for 2014 drilling
31
32. Deepwater Gulf of Mexico
Long-lived producing assets and high-impact exploration potential
32
Louisiana
Lorien
Ticonderoga
Acreage
Producing
Discovery
2013-2014 Prospects
Swordfish
Isabela
Gunflint Santa Cruz
South Raton
Raton Santiago
Big Bend
Yunaska
Sailfish
Madison
Palladium Dantzler
Troubadour
33. Rio Grande Area – Big Bend and Troubadour
Progressing development for near-term impact
NBL Operated Development
Big Bend 54%, Troubadour 60% WI
Discovered Resources of
Between 50 – 100 MMBoe
75% oil
Targeting Project Sanction
in 2013
Planned subsea tie-backs to existing
infrastructure
Assessing multiple host facilities
First Production Anticipated
Late 2015
33
Troubadour
Big Bend
Troubadour
Big Bend
34. Discovery Well
2nd Appraisal Well
Gunflint Major Project Development
Planned tie back with sanction targeted in 2013
Mississippi Canyon 948/992
NBL operates with 31% WI
Discovered Resources of
Between 65 – 90 MMBoe
P75 to P25 gross resources
High-quality reservoirs
Additional exploration potential remains
in three-way structure to the north
Subsea Design / FEED Ongoing
Assessment of nearby facilities as
production host
First Oil Anticipated for
End of 2015
34
Devil’s
Tower
Tubular
Bells Kodiak
1st Appraisal Well
Existing Facilities
Titan
Gunflint
35. Mississippi Canyon Play
Proven play with running room, close to existing infrastructure
35
Subsalt Miocene Oil Play
Five Prospects with Combined
Gross Mean Resources
of Over 600 MMBoe
LouisianaLouisiana
Mississippi CanyonMississippi Canyon
Mississippi Canyon Play
Anticipated WI
33% – 45%
Gross Resource
P75 – P25 (MMBoe)
Dantzler 50 – 220
Hagerman 46 – 222
Madison 20 – 80
Silvergate 23 – 114
Shuriken 10 – 75
Horn
Mountain
Pompano
NaKika
Blind Faith
Thunder Hawk
Existing Facilities
Silvergate
Madison
Shuriken
Hagerman
Dantzler
36. Dantzler Prospect – Mississippi Canyon 738/782
High-impact opportunity in 2013
36
NBL Operated with 65% WI
Anticipated Spud Following
Troubadour
Results expected by year-end 2013
50 – 220 MMBoe (P75 – P25) gross
unrisked resources
Offset Well with Oil Shows and 1,200 ft.
of Significant Sand in Target Section
1,000 ft.
LouisianaLouisiana
Mississippi CanyonMississippi Canyon
LouisianaLouisiana
Mississippi CanyonMississippi Canyon
Dantzler
Offset Well
with Oil Shows
37. 1
3
3
3
3
3
0
200
400
600
800
2012 2013 2014 2015 2016 2017
MMBoe
Deepwater Gulf of Mexico
Strategic approach to value creation
Initial Deepwater Focus on
Amplitude Plays
Captured Material Subsalt
Miocene Prospects
Applied Learnings from NBL
and Industry Operations
60% Deepwater Exploration
Success Rate Since 2003
Maturing Over 30 Prospects
with 1.6 BBoe Net Unrisked
Mean Resources
37
Gross Unrisked Resource Exposure
(Number of Prospects)
38. West Africa
High-impact core area
Leading Operator in the Doula Basin
Liquid Projects Producing 45 MBbl/d and
Generating ~$1.2 Billion BT Annual Cash
Flow* by 2014
Aseng and Alen Major Projects Online and
Provide Regional Infrastructure for Future
Developments
Progressing Plans to Monetize Existing
Natural Gas Resources
Integrating Recent Well Results
with Inventory Prospectivity
38
* See appendix for referenced price case
39. Bioko
Island
Cameroon
Block O
45% WI
Block I
40% WI
YoYo
Mining License
50% WI
Equatorial Guinea
Tilapia PSC
50% WI
Alba Field
34% WI
Methanol Plant 45% WI
LPG Plant 28% WI
Aseng
Alen
West Africa – Core Operations
Legacy of strong production and cash flow creation
39
Long-life Alba Asset
Approx. 18 MBbl/d and 240
MMcf/d, net
Gas sales to Methanol and LNG
Substantial Exploration and
Major Project Successes
Aseng – online November 2011
Alen – ramping to full operations
Progressing Diega / Carla
discoveries and assessing
development options
Gas monetization – ongoing
planning and evaluation
Continuing Exploration
40. Aseng Field
Breakthrough execution and operations increases project value
NBL Operated with 40% WI
Total Cumulative Production of Over 35 MMBbls Since
Startup Late 2010
Currently Producing Approximately 50 MBbl/d
Average 17 MBbl/d net
Strong Field and Facility Uptime
Excellent Safety Performance
Aseng FPSO Hub Provides for Other Liquid
Developments
Operating costs improve $25 MM / year gross after Alen full operations
40
41. Alen Condensate Project
Bringing high-value liquids to production
41
NBL Operated with 45% WI
Gas-cycling and reinjection project
Commenced Production Late 2Q 13
Start-up ahead of schedule
Ramping to Full Operations
Utilizing Aseng FPSO for Storage
and Offloading
Facilities to Provide Hub for Future
Gas Monetization
42. Eastern Mediterranean
Growing demand driving near-term value
Tamar Having Significant Impact
for All Stakeholders
Natural Gas the Fuel of Choice for Israel
Total demand grows at 15% CAGR 2012 – 2017
Leviathan Expected to Supply
Domestic Markets in 2016
Strategic Partner Selected Adding
Substantial Value to Leviathan
Advancing Regional and LNG Export
Options
Cyprus Discovery Supports Long-term
Growth Profile
Plans for Levant Basin Deep Oil Test
in 2014
42
43. Eastern Mediterranean
Substantial natural gas driving near-term value
43
Leviathan
40% WI
Dolphin
40% WI
Mari-B, Noa,
Pinnacles
47% WI
Cyprus
70% WI
Tamar
36% WI
Dalit
36% WI
AOT
47% WI
Tanin
47% WI
Karish
47% WI
Seven Discoveries
Approximately 38 Tcf gross resources
13 Tcf net, 2.2 Tcf net booked
reserves
Tamar Commenced Operation
in April 2013
Growing Regional Market
Potential
Cyprus Appraisal Currently
Drilling
Results anticipated in 3Q13
Plans for flow test
44. 0
500
1,000
1,500
2,000
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
MMcf/d
Electricity Industrials Announced Coal Conversion
Israel Natural Gas Demand
Supports faster and earlier development of discovered resources
Natural Gas is The Fuel of Choice
Shift to base load with less swing
Strong electricity and industrial demand
Potential for converting coal-fired electricity generation
44
Annual Average Natural Gas Demand
Demand Swing
(lower swing % over time)
15% CAGR
2012 – 2017
Source: Poten and Partners, Noble Energy estimates
45. 45
Tamar Project
Long-term value for all stakeholders
Tamar Online with Peak Deliverability
Up to 1 Bcf/d
First production 2.5 years from sanction – industry
leading cycle time
10 Tcf gross (NBL 36% WI)
Near 100% Field and Facility Uptime
World-class reliability
Initial Capacity Already Contracted
IEC exercised option for additional natural gas
beginning in 2015
Expansion to 1.5 Bcf/d Targeted for 2015
Compression at Ashdod onshore terminal
and system optimizations
46. Leviathan Development
Field scale involves multiple development phases
Resource Estimated at 18 Tcf
Gross, 6 Tcf Net
Flow back test confirms high
quality reservoir
Phased Development
Accelerates Value Recognition
Initial Phase Includes Pre-
Investment in Upstream for
Export Project
750 MMcf/d for domestic and
850 MMcf/d for export
Phase 1 sanction targeted for 2013
Progressing for Initial Sales to
Domestic Market in 2016
46
#5 Planning
#3 Drilled
and Evaluated
GOM OCS
Block Outline,
24 Blocks
#1 Drilled
and Evaluated
#4 Drilled
and Evaluated
#2 Plugged
47. Leviathan Sell Down Proposal
Bringing in a strategic partner with LNG expertise
NBL Selling 9.66% Interest
Continue as upstream operator with 30% working interest
Cash Payments Totaling $464 Million, Revenue Sharing
Up to $322 Million, and Drilling Carry of $16 Million
$802 MM total implied price including revenue sharing
Woodside is Australia’s Largest Producer of LNG
with Over 25 Years of Experience
Designed, constructed and commissioned 5 LNG trains
Strong relations with Asian markets
Best practice focus on safety, integrity and reliability
Finalize Definitive Agreements in 2013
Awaiting final export rule approvals
47
48. Cyprus-A Discovery
Transforming Cyprus to an energy exporting country
Resource Estimated at
5 – 8 Tcf Gross
Appraisal Well and Test
in 3Q 13
Progressing Development
Concept Evaluation
Domestic market supply
MOU signed for potential
LNG project
Block 12 3D Seismic
Survey Acquired
Seismic processing in progress
Potential exploration drilling in
late 2014
48
GOM OCS
Block Outline,
10 Blocks
GOM OCS
Block Outline,
10 Blocks
A-1 Discovery
A-2 Spud 06/01/13
DST to Follow
49. Gross Unrisked Resource
Potential Estimated at 3.7 BBoe
Drillship for Deep Oil Prospect
Expected to Arrive Early 2014
Potential exists under each of existing
discovered gas fields
High-Liquid Karish Discovery
Encouraging for Basin
Identified thermogenically sourced
hydrocarbons
Higher condensate yield than previous
discoveries (7 -10 Bbls per MMcf)
Mesozoic Oil Play in Levant Basin
A play with step-change potential
49
Structural
High
Leviathan Deep Prospect
50. 50
Global Exploration Portfolio
Substantial worldwide resource exposure
Inventory of Prospects at Highest Level in Company History
Past successes delivering new material production
Pursuing additional core area and new venture opportunities
Exploration Inventory of 3.7 BBoe Net Risked Resources
Testing Significant Resources in the Next Two Years
DW GOM, N. E. Nevada, Nicaragua, Falkland Islands, Mesozoic oil
in the Eastern Mediterranean
New Discoveries Additive to Double-Digit Growth Profile
Relentlessly Focused on Exploration
51. Nicaragua
Carbonate and clastic plays
1.8 Million Acres in Two Lease Blocks
NBL operated
Initial Farm-Out Pending Final
Approvals
Continuing negotiations on additional farm-out
Multiple Oil Prospects and Leads
Identified on 3D Seismic
3,050 square miles
2.7 BBoe gross resources
Paraiso Prospect Currently Drilling
5151
3D Seismic
Nicaragua
Paraiso
53. 53
Falkland Islands
Frontier basin with 10 MM acres of running room
Note: Only Cretaceous prospects are shown
Top 10 Targets Contain 7 BBbl
Gross Unrisked Potential
Additional play types with 6 BBoe
gross unrisked potential
Initial 3D Seismic Acquisition
Completed
Processing to commence 2H 13
Image Cretaceous deepwater
systems
Additional 3D anticipated late 13 /
early 14
Additional Exploration Drilling
Targeted for 2014
Loligo
Toroa
Darwin Discovery
Borders & Southern
Falkland Islands
Scotia
West
Falkland
East
Falkland
Argentina
Chile
Scotia
54. Sierra Leone
New West Africa entry
1.4 Million Gross Acres
Participation Interest
30% NBL
55% Chevron (Operator)
15% ODYE
10% GoSL (Carried)
Focus on Cretaceous-Age
Reservoir Systems
Water Depth Range
20 – 4,000 meters
Recently Completed 2D
Seismic Program
Processing ongoing
54
Sierra Leone
SL-08B
30% WI
SL-08A
30% WI
Guinea
Liberia
55. Great Basin
Wilson
Project
Elko County, N.E. Nevada
Next growth possibility in U.S.
Tight Oil Play with Core Area Scale
350,000 net acres
190 – 1,400 MMBoe (P75 – P25)
gross unrisked resources
55% geologic chance of success
Two 3D Surveys Completed to Date
Phased Pilot Test Program to
Determine Viability
Drill vertical wells in 2H 2013
Production results in less
than 12 months
55
3D
Acquisition
56. Noble Energy
Positioned for a decade of growth
56
Diversified and Focused Asset Portfolio
Offers stability and superior returns
Sustainable Industry-leading Exploration Program
Yields significant discovered resources
Competitive Advantage in Delivering Major Projects
Building a track record of outstanding execution
Fully Integrated Financial and Risk Strategy
Ensures ability to support business value creation
Organizational Capacity to Deliver Results
57. Forward-looking Statements and
Non-GAAP Measures
This presentation contains certain “forward-looking statements” within the meaning of the federal securities law. Words such as “anticipates,”
“believes,” “expects,” “intends,” “will,” “should,” “may,” and similar expressions may be used to identify forward-looking statements. Forward-looking
statements are not statements of historical fact and reflect Noble Energy’s current views about future events. They include estimates of oil and
natural gas reserves and resources, estimates of future production, assumptions regarding future oil and natural gas pricing, planned drilling
activity, future results of operations, projected cash flow and liquidity, business strategy and other plans and objectives for future operations. No
assurances can be given that the forward-looking statements contained in this presentation will occur as projected, and actual results may differ
materially from those projected. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number
of risks and uncertainties that could cause actual results to differ materially from those projected. These risks include, without limitation, the
volatility in commodity prices for crude oil and natural gas, the presence or recoverability of estimated reserves, the ability to replace reserves,
environmental risks, drilling and operating risks, exploration and development risks, competition, government regulation or other actions, the ability
of management to execute its plans to meet its goals and other risks inherent in Noble Energy’s business that are discussed in its most recent
Form 10-K and in other reports on file with the Securities and Exchange Commission. These reports are also available from Noble Energy’s offices
or website, http://www.nobleenergyinc.com. Forward-looking statements are based on the estimates and opinions of management at the time the
statements are made. Noble Energy does not assume any obligation to update forward-looking statements should circumstances or management's
estimates or opinions change.
This presentation also contains certain historical and forward-looking non-GAAP measures of financial performance that management believes are
good tools for internal use and the investment community in evaluating Noble Energy’s overall financial performance. These non-GAAP measures
are broadly used to value and compare companies in the crude oil and natural gas industry. Please also see Noble Energy’s website at
http://www.nobleenergyinc.com under “Investors” for reconciliations of the differences between any historical non-GAAP measures used in this
presentation and the most directly comparable GAAP financial measures. The GAAP measures most comparable to the forward-looking non-GAAP
financial measures are not accessible on a forward-looking basis and reconciling information is not available without unreasonable effort.
The Securities and Exchange Commission requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a
company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic
and operating conditions. The SEC permits the optional disclosure of probable and possible reserves, however, we have not disclosed our probable
and possible reserves in our filings with the SEC. We use certain terms in this presentation, such as “net risked resources” and “gross mean
resources.” These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are
subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with
the SEC. Investors are urged to consider closely the disclosures and risk factors in our most recent Form 10-K and in other reports on file with the
SEC, available from Noble Energy’s offices or website, http://www.nobleenergyinc.com.
57
59. 59
Defined Terms and Price Assumptions
Term Definition
Debt Adjusted per Share
Calculations
Normalizes growth funded through debt by converting the change in debt into an equivalent
amount of equity shares using an average stock price. The equivalent shares are netted with
total shares outstanding which impacts the per share calculations of reserves, production and
cash flow.
Discretionary Cash Flow Cash Flow from Operations excluding working capital changes plus cash exploration
expense
Free Cash Flow Operating Cash Flow less Organic Cash Capital
Return on Average Capital
Employed (ROACE)
Earnings before interest and tax (EBIT) plus asset impairments and unrealized mark to
market derivatives divided by average total assets plus impairments less current liabilities
Peers – Investment Grade
– Non-Investment Grade
APA, APC, DVN, EOG, HES, MRO, MUR, PXD, SWN
CHK, CLR, COG, NFX, RRC
Product Price Deck
WTI ($/Bbl) $90 through 2019 then increased at 2% per year
Brent ($/Bbl) $100 through 2019 then increased at 2% per year
Henry Hub ($/Mcf) $3.50 in 2013
$4.00 in 2014
$4.25 in 2015
$4.50 in 2016
$4.75 in 2017
+ $0.25 per year to 2022
