noble energy september 2013 presentation
TRANSCRIPT
Investor Meetings September 2013
2
Noble Energy Differential company with differential results
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
18%21%
24%
Five-Year Growth Outlook – 2012 to 2017Superior 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
DJ Basin
Eastern Med.
Other
Marcellus
U.S. Onshore
DW GOM
Eastern Med. West
Africa
New Ventures
Net Risked ResourcesStrong foundation for current and future growth
5
Net Risked Net Unrisked
Proved Reserves* Discovered UnbookedCore 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
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
Discretionary Cash Flow* OutlookGrowing a billion dollars per year
7
0
2
4
6
8
2012 2013 2014 2015 2016 2017
$ BDJ
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
38%33% 32%29%
25% 28%
YE 2011 YE 2012 2Q 2013Debt-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 2021JV Installment Payments Bonds
$MM
2013 2014 2019 2021 2022+
45% 44%
59%63%
Oil U.S. Gas Oil U.S. Gas
9
Commodity EnvironmentProactively hedged to reduce cash flow volatility
Oil Floor** Ceiling2013 $93.40 $105.682014 $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** Ceiling2013 $4.28 $5.212014 $3.85 $4.83
Note: Hedges include swaps, collars, 3-way collars
-15%
-5%
5%
15%
25%
35%
NBL F B D H G C I E A
2004 – 2012 Dividend GrowthPer Share
Investment Grade Peers*
N/A
10
NBL DividendCommitment to competitive payout
*Peers listed in appendixNote: N/A = No dividend paid
Over Last Eight Years, NBL’s Dividend Per Share has Grown at a 32% CAGR
0.050.08
0.14
0.22
0.330.36 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
2013
E
$/Share Dividends**
**Dividends adjusted for stock split as of May 2013.
2013 Volumes and Capital OutlookSubstantial growth in core areas
Production Outlook270 – 282 MBoe/d
20% Year Over Year Increase, Adjusting for Divestments
Invest $3.9 Billion in 2013 Accelerate onshore unconventional
horizontal programs
Complete Tamar and Alen
Exploration and appraisal drilling in DW GOM, Eastern Med and West Africa
Significant New Venture exploration
11
Note: From continuing operations
DJ Basin
Marcellus
DW GOM
WestAfrica
Eastern Med
New Ventures
Other
Capital Allocation By Area
Onshore Unconventional DevelopmentsContributing impactful growth
12
0
50
100
150
2012 2013 2014 2015 2016 2017
MBoe/d
54% CAGR
Marcellus
DJ Basin
0
100
200
2012 2013 2014 2015 2016 2017
MBoe/d
20% CAGR
Accelerating Horizontal Activity Levels Repeatable, low-risk investments
Capturing economies of scale
Improving EURs and Recovery Rates
Enhancing Performance Through Technology and Operational Efficiencies
DJ Basin Liquids Play Crude oil and NGLs represent ~ 65%
total production in 2013
Marcellus Development Approximately 65% of drilling activity
in wet gas area in 2013
0
20
40
60
80
100
120
1Q 11 2Q 11 3Q 11 4Q 11 1Q 12 2Q 12 3Q 12 4Q 12 1Q 13 2Q 13
DJ Basin-Vertical DJ Basin-Horizontal Marcellus
13
Core Onshore Unconventional Production1H 13 volumes up nearly 30% from 1H 12
Current Production ~ 125 MBoe/dMBoe/d
DJ BasinA premier oil play
Compares Favorably to Other Plays Oil in place now estimated at 74 MMBoe per section
Net Resources 2.1 BBoe 9,500 horizontal locations, 85% in oil window
Hz EURs continue to improve averaging 335 MBoe
Five Year Production CAGR Over 20% Oil production grows 3.5 times
Rapidly Accelerating Development Program with 500 Wells per Year Targeted in 2016
Technical and Operational Excellencein All Phases Exploration, drilling, completions and infrastructure
14
Niobrara is a Top Oil Resource PlaySuperior resources and low development costs
15
Source: Internal, Wood Mackenzie, External Company Presentations, Tudor Pickering
Oil Play Characteristics Well Characteristics
Depth(Feet)
Thickness (Feet)
OOIP(MMBoe / Section)
Avg. EUR
(MBoe)
Avg. Liquids
%
D&CCapital$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
Accelerating DJ Basin Development ProgramDouble 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. Colorado2012 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
DJ Basin 2013 OperationsFocused 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 AcreageGas WindowOil Window
230,000 Net Acres300 MMBoe NRR1,750 Locations
290,000 Net Acres1,400 MMBoe NRR
6,400 locations
120,000 Net Acres400 MMBoe NRR 1,350 Locations
Wells Ranch
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 WindowGWA Oil WindowEast Pony
DJ Basin Well EconomicsStrong returns over a broad price range
ROR Sensitivity to Oil Price**
18
* Utilizing reference price case. See appendix, 80% NRI.** NYMEX gas flat at $3.50/MMBtu in all cases, 80% NRI.
Type Curves
BT Economics* GWA Gas Window
GWA Oil Window East Pony
EUR (MBoe) 435 335 345Liquids (%) 45% 65% 85%Well Cost ($MM) $4.5 $4.5 $4.9NPV10 ($MM) $3.6 $3.9 $6.0ROR (%) 65% 70% 109%Payout (Years) 1.4 1.3 1.0
Reference Price
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 Average 1 MMBoe Type Curve
► 11 Wells Online and Performing Above Expected Type Curves
► EURs Average Above 750 Thousand Barrels Equivalent
Extended-Reach Laterals – Wells RanchMaximizing value per horizontal foot drilled
19
Northern Colorado NiobraraLeveraging expertise to unlock new opportunity
20
Wyoming Nebraska
Lilli Plant
East Pony
* Rolling 3 day average
Keota/LNG Plant
Greater Wattenberg
Superior Economics inEast Pony 45,000 net acres
Producing 80% oil, 5% ngl
Three Well 80-Acre Pilot Yielding Best Resultsto 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 Average80-Acre Pilot335 MBoe Type Curve
Optimizing DJ Basin Resource RecoveryContinuously 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 Acre660’
330’
40 Acre
40 Acre330’
330’
21
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
DJ Basin Midstream InfrastructureDevelopment 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
GWANorthern ColoradoEstimated NBL Capacity
Gross Operated Oil
0
100
200
300
400
500
Jan-12 Jul-12 Jan-13 Jul-13
MMcf/d
Gross Operated ProductionEstimated 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
Marcellus ShaleSignificant 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
Marcellus 2013 OperationsFocusing near term in wet gas areas
Increase NBL-Operated Wet Gas Rig Count to Five andTarget 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
OHPA
WV
MD
CONSOL Operated452,000 Gross Acres
NBL Operated176,000 Gross Acres
SW PA WetEUR 5.6 Bcfe
C PA DryEUR 4.4 Bcfe
SW PA DryEUR 7.0 Bcfe
WV DryEUR 5.0 Bcfe Dry Gas
NBL Activity
Wet Gas
26
NBL-Operated Wet Gas ActivityAccelerating drilling and completions in liquid-rich areas
SHL1,3,6 Producing
WFN1: 7-well PadCompleting
WEB 4: 11-well Pad Producing
SHL 8: 11-well PadProducing
Marshall County
Washington County
Greene County
Majorsville
OH PA
WV
MD
Dry GasWet Gas
NBL JV Area
Majorsville
WFN6: 8-well PadDrilling
SHL17: 6-well PadDrilling
PENS1: 9-well PadDrilling
OXF1: 6-well PadDrilling
NORM 1: 6-well PadCompleting
Marcellus Shale EconomicsAttractive 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 $90/Bbl
27
Note: Well costs includes gathering* Utilizing reference price case, see appendix
Single Well Economics*(5,000 Foot Lateral)
0%
20%
40%
60%
5 6 7 8Well Cost ($MM)
Targeted Costs
Current Costs
BT ROR
Dry Wet
0
2
4
6
8 GasNGLCondensate
$/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
Marcellus Gas MarketingProcessing 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 CapacityAdditional 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
Global Offshore Major ProjectsMeaningful 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
Major Deepwater Project Line-upMultiple new sanctions targeted in 2013
Appraisal, Development TimelinePrimarily LiquidsPrimarily Gas
Sanctions through cooperation with partners and governments
Wes
tA
fric
aD
eepw
ater
GO
MEa
ster
n M
edite
rran
ean
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
Deepwater Gulf of MexicoProven 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
Deepwater Gulf of MexicoLong-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
Rio Grande Area – Big Bend and TroubadourProgressing 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
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’sTower
Tubular Bells Kodiak
1st Appraisal Well
Existing Facilities
Titan
Gunflint
Mississippi Canyon PlayProven play with running room, close to existing infrastructure
35
Subsalt Miocene Oil Play
Five Prospects with Combined Gross Mean Resourcesof Over 600 MMBoe
LouisianaLouisiana
Mississippi CanyonMississippi Canyon
Mississippi Canyon Play
Anticipated WI33% – 45%
Gross ResourceP75 – P25 (MMBoe)
Dantzler 50 – 220
Hagerman 46 – 222
Madison 20 – 80
Silvergate 23 – 114
Shuriken 10 – 75
HornMountain
Pompano
NaKika
Blind Faith
Thunder Hawk
Existing Facilities
Silvergate
Madison
Shuriken
Hagerman
Dantzler
Dantzler Prospect – Mississippi Canyon 738/782High-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
1
3
3
3
3
3
0
200
400
600
800
2012 2013 2014 2015 2016 2017
MMBoe
Deepwater Gulf of MexicoStrategic 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 UnriskedMean Resources
37
Gross Unrisked Resource Exposure(Number of Prospects)
West AfricaHigh-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 Resultswith Inventory Prospectivity
38
* See appendix for referenced price case
BiokoIsland
Cameroon
Block O45% WI
Block I40% WI
YoYoMining License
50% WI
Equatorial Guinea
Tilapia PSC50% WI
Alba Field34% WI
Methanol Plant 45% WILPG Plant 28% WI
Aseng
Alen
West Africa – Core OperationsLegacy 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
Aseng FieldBreakthrough 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
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
Eastern MediterraneanGrowing demand driving near-term value
Tamar Having Significant Impactfor All Stakeholders
Natural Gas the Fuel of Choice for Israel Total demand grows at 15% CAGR 2012 – 2017
Leviathan Expected to SupplyDomestic 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 Testin 2014
42
Eastern MediterraneanSubstantial natural gas driving near-term value
43
Leviathan40% WI
Dolphin40% WI
Mari-B, Noa, Pinnacles47% WI
Cyprus70% WI
Tamar36% WI
Dalit36% WI
AOT47% WI
Tanin47% WI
Karish47% 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
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 DemandSupports 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
Tamar ProjectLong-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
Leviathan DevelopmentField scale involves multiple development phases
Resource Estimated at 18 TcfGross, 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 Drilledand Evaluated
GOM OCS Block Outline, 24 Blocks
#1 Drilledand Evaluated
#4 Drilled and Evaluated
#2 Plugged
Leviathan Sell Down ProposalBringing 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 SharingUp to $322 Million, and Drilling Carry of $16 Million $802 MM total implied price including revenue sharing
Woodside is Australia’s Largest Producer of LNGwith 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
Cyprus-A DiscoveryTransforming 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 06/01/13DST to Follow
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
StructuralHigh
Leviathan Deep Prospect
50
Global Exploration PortfolioSubstantial 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
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
NicaraguaParaiso
52
Offshore Nicaragua – Paraiso ProspectWorld-class exploration opportunity
CI: 200m
10km
Carbonate Reservoir Target Gross Unrisked Mean
Resources 210 – 1,220 MMBoe (P75 – P25)
25% Geologic Chance of Success
Results Anticipated by YE 13
53
Falkland IslandsFrontier basin with 10 MM acres of running room
Note: Only Cretaceous prospects are shown
Top 10 Targets Contain 7 BBblGross Unrisked Potential Additional play types with 6 BBoe
gross unrisked potential
Initial 3D Seismic Acquisition Completed Processing to commence 2H 13
Image Cretaceous deepwatersystems
Additional 3D anticipated late 13 / early 14
Additional Exploration Drilling Targeted for 2014
Loligo
ToroaDarwin DiscoveryBorders & Southern
Falkland Islands
Scotia
West Falkland
EastFalkland
Argentina
ChileScotia
Sierra LeoneNew 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-08B30% WI
SL-08A30% WI
Guinea
Liberia
Great Basin
Wilson Project
Elko County, N.E. NevadaNext 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
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3D Acquisition
Noble EnergyPositioned for a decade of growth
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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
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.
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Appendix
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Defined Terms and Price Assumptions
Term DefinitionDebt 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, SWNCHK, CLR, COG, NFX, RRC
Product Price DeckWTI ($/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
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