NBL
 Second Quarter 2017 Supplement
 August 2017
 2NBL
 2Q17 KEY HIGHLIGHTS
 Executing to plan while delivering significant strategic objectives
 Volumes and Costs In-line or Better than Guidance
 Continued to Deliver Strong Well Performance
 Achieved Substantial Drilling Efficiencies Across USO
 Accomplished Strategic Objectives
 • Volumes of 408 MBoe/d, in the upper half of guidance after adjusting for Marcellus close timing 
• Record U.S. onshore oil volumes, including 12 MBbl/d increase over 1Q17
 • Established record for second quarter gross sales volumes in Israel of 962 MMcfe/d
 • Exited the Marcellus upstream and sold Marcellus midstream business 
• Clayton Williams Energy acquisition expanded top-tier U.S. onshore oil portfolio 
• Completed the inaugural drop down transaction to NBLX for total consideration of $270 million
 • Progressed Leviathan within budget and on track for start-up by the end of 2019
 • Delaware Basin wells delivering above expectations, exhibiting longer plateau and flatter decline
 • DJ Basin horizontal volumes up 7% vs. 1Q17 on strong new well performance; record oil mix of 53%
 • 14 S. Gates Eagle Ford wells with avg. cum. production of 235 MBoe after 60 days (normalized to 7,000 ft)
 • Reduced drilling costs per lateral foot in 1H17 vs. 2016 by 20% - 30%
 • Set record individual well drilling time in Delaware Basin
 • Achieved lowest individual well drilling cost to date in Eagle Ford
 3NBL
 2Q17 ACTUALS VS. GUIDANCE
 In line and exceeding guidance for majority of items
 Financial and Operating Metrics 2Q Guidance 2Q Actuals
 Total Sales Volumes (MBoe/d)
 Original: 395 - 415
 Increased: 405 - 415
 408*
 Oil Sales Volumes (MBbl/d) 132 - 138 134*
 Natural Gas Liquids (MBbl/d) 67 - 72 67*
 Natural Gas (MMcf/d) 1,220 - 1,245 1,239*
 Organic Capital ($MM) 650 - 750 656**
 Equity Investment Income ($MM) 30 - 40 42
 Lease Operating ($/BOE) 3.65 - 3.90 3.34
 Gathering, Transportation & 
Processing ($/BOE)
 3.65 - 3.90 3.26
 DD&A ($/BOE) 15.00 - 15.90 13.56***
 Production Taxes (% Oil, NGL, Gas 
Revenues)
 3.8 - 4.2 3.7
 Marketing ($MM) 10 - 20 14
 Exploration ($MM) 40 - 60 30
 G&A ($MM) 95 - 110 103
 Interest, net ($MM) 85 - 95 96
 Earnings Reconciliation 2Q ($MM)
 GAAP Net Loss attributable to NBL (1,512)
 GAAP Net Loss attributable to NBL Before Tax (2,348)
 Adjustments to Net Loss, Before Tax 2,377
 Adjusted Net Income attributable to NBL, 
Before Tax
 29
 Current Tax Expense, Adjusted (34)
 Deferred Tax Benefit, Adjusted 29
 Adjusted Income Attributable to NBL****
 (Non-GAAP)
 24
 Adjusted EBITDAX 2Q ($MM)
 Adjusted Income Attributable to NBL**** 
(Non-GAAP)
 24
 Interest, net 96
 Current Tax Expense, Adjusted 34
 Deferred Tax Benefit, Adjusted (29)
 DD&A 503
 Exploration 30
 Adjusted EBITDAX**** (Non-GAAP) 658
 *Early close of Marcellus impacted 2Q17 production by 3 MBoe/d **Excludes acquisition and NBLX  funded capital ***Marcellus DD&A included for partial 
quarter until asset classified as held for sale in April.**** Non-GAAP reconciliation to GAAP measure available in 2Q17 earnings release
 4NBL
 U.S. ONSHORE
 Robust U.S. onshore liquids growth
 2Q17 Activity DJ Basin Delaware Eagle Ford Marcellus* Other Total
 Oil (MBbl/d) 57 15 12 2 2 88
 NGL (MBbl/d) 20 4 28 9 .5 61
 Gas (MMcf/d) 182 22 177 331 8 720
 Total Sales (MBoe/d) 107 23 69 66 4 269
 Organic Capital** ($MM) 210 141 113 32 496
 Avg. Operated Rigs 2 4.5 1.5 8
 Wells Drilled 29 13 11 53
 Avg. Lateral Length (ft) 9,220 7,965 6,315 8,310
 Wells Completed 30 11 14 55
 Wells Brought Online 33 6*** 21 8 68
 Avg. Lateral Length (ft) 6,530 5,318 6,665 7,750 6,610
 DJ Basin
 Delaware 
Basin
 Marcellus*
 Eagle 
Ford
 2Q17 Key Highlights
 • 12 MBbl/d Increase in U.S. Onshore Oil Over 
1Q17, up 16%
 • Record U.S. Onshore Oil and NGL Volumes 
of 149 MBbl/d
 • Eagle Ford Production Ramp 60% in 2Q17 
vs. 1Q17, with Further Growth Anticipated 
in 3Q17
 • Encouraging Early Results From First 
Delaware Basin Simultaneous WCA Upper 
and Lower Completion
 • Expanded Confidence and Dataset in 
Enhanced Completions Across Wider Area 
of DJ Basin and Delaware Basin Acreage 
• Inaugural Drop Down to NBLX Completed
 • Currently Operating 7 Rigs (5 Delaware and 
2 DJ Basin)
 * Upstream Marcellus divestiture closed June 28, 2017  ** Excludes NBLX funded capital expenditures *** Excludes 2 CWEI wells brought online prior to transaction close
 5NBL
 DELAWARE BASIN
 Accelerating value in top-tier Southern Delaware position
 Delaware Basin Activity* 1Q17 2Q17
 Total Sales Volume (MBoe/d) 14 23
 Organic Capital** ($MM) 100 141
 Operated Rigs 3 4.5
 Wells Drilled 10 13
 Average Lateral Length (ft) 7,600 7,965
 Wells Completed 6 11
 Wells Brought Online 3 6
 Average Lateral Length (ft) 4,760 5,318
 118,000
 Net acres
 4,225
 Gross locations
 7,800 ft
 Average lateral Length
 2 BBoe
 Net unrisked resources
 Successful Integration of CWEI
 • CWEI transaction closed late April 2017
 • 7 MBoe/d average production contribution in 
2Q17 
First 10,000 Ft Laterals, Multi-Zone Test 
Commencing Production
 • 3-well multi-horizon pad targeting the Wolfcamp A 
Upper, Wolfcamp A Lower and 3rd Bone Spring
 • Timed with the 1st gathering facility coming online
 ~10-15
 ~20-25
 1Q17 2Q17 3Q17 4Q17
 Expected Wells Turned to Sales* 
* Includes CWEI activity as of April 25, 2017 forward.  ** Excludes NBLX funded 
capital expenditures
 64% Quarterly Increase Over 1Q17 
Volumes
 • NBL and CWEI results trending above type curve
 TX
 NBL Acreage
 Ward
 Reeves Pecos
 6NBL
 0
 50
 100
 150
 0 30 60 90 120
 Days on Production 
Wolfcamp B and C Well Results*
  Trigger 40 6H (WCB)  Longoria 11 #2H (WCC)
 WCB 1.1 MMBoe Type Curve WCC 0.9 MMBoe Type Curve
 DELAWARE BASIN
 Unlocking value across multiple stacked zones
 2Q17 Highlights
 • 1st Simultaneous Wolfcamp A Upper and Lower 
Completions Showing Consistent Performance 
 Additional simultaneous Upper and Lower 
Wolfcamp A completions test in CWEI acreage 
planned in 2H17
 • 2Q NBL Wolfcamp A Wells Avg. ~330 Boe/d per 1,000 
Lateral Feet (4 well avg.)
  2 CWEI wells online in 2Q, in-line with type curve
 • Under Managed Flowback, 1st 10,000 ft. Wolfcamp A 
Producing ~1,500 Boe/d Over Initial 60 Days with 
Flatter Decline
 • Second Operated Wolfcamp B Well Significantly 
Outperforming Expectations
 • Wolfcamp C Well on Track to Exceed 1.0 MMBoe 
Wolfcamp A Acquisition Type Curve 
 Brought online by CWEI late in 1Q
 • 2017 Technical Initiatives
  Optimizing stage and cluster spacing
  Laboratory core work for produced water test
 Cum. MBoe
 Cum. MBoe
 *Reflects Gross 3 Stream. Normalized to 7,500 ft.
 0
 50
 100
 150
 200
 250
 0 30 60 90 120
 Day on Production
 Wolfcamp A Well Results*
 2017 NBL AVERAGE 2017 CWEI AVERAGE
 NBL WCA 1.2 MMBoe Type Curve CWEI WCA 1.0 MMBoe Type Curve
 7NBL
 Ward
 NBL AcreageReeves
 Pecos
 Monroe Pad
  3-well pad with 10,000 ft laterals
  3rd Bone Spring, Wolfcamp A 
Upper and Wolfcamp A Lower
  Commencing production
 Wolfcamp C- Longoria 11 2H   
 First slickwater Wolfcamp C 
Wolfcamp A- Man O War 26 Unit C 8H 
& Man O War 26 1HA
  1st simultaneous WCA Upper and 
WCA Lower
  Consistent performance across both 
zones
 Calamity Jane Spacing Pilot
  7-well pad with 7,500 ft laterals
 - 3rd Bone Spring: 2
 - Wolfcamp A Upper: 3
 - Wolfcamp A Lower: 2
  Online end of 2017
 DELAWARE BASIN
 Strong 2Q17 results across top-tier quality acreage position
 Wolfcamp A- City of Pecos 2HB 
& Sheriff Woody 5H
  2Q legacy NBL wells
 Wolfcamp A- Collier APA 8 
& Trust State 242 1H
  2Q CWEI wells
 Wolfcamp A- Will Rogers 1H
  First 10,000 ft. lateral
 Wolfcamp B- Trigger 40 6H
  2nd Wolfcamp B
 8NBL
 DELAWARE BASIN
 Midstream integration a competitive advantage 
NBLX Supporting Growth Objectives
 • Expanding Capacity and Accelerating Build-Out of 
Central Gathering Facilities
 • 1st Gathering Facility (CGF) Online in Late July
  2nd facility online YE2017, planning for two in 2018
 • 3-Well Pad Targeting Upper and Lower WCA and 3rd 
Bone Spring with 10,000 ft. Laterals Tying Into 1st
 Facility
 • Initial Facility Connected to NBLX and Plains All 
American 50/50 JV Advantage Pipeline, Accessing 
Multiple Crude Oil Outlets
 • Water Strategy Designed to Optimize LOE
  NBL owned/operated frac ponds 
 Operated and 3rd party disposal options
  Recycling incorporated into facility design
 Pecos
 Ward
 Reeves
 NBL Acreage
 2017 CGFs
 Advantage 
Pipeline
 Daily Capacity Current 1H18
 Oil (MBl/d) 10 90
 Gas (MMcf/d) 20 160
 Produced Water (MBw/d) 15 210
 First 4 CGFs Materially Expand Capacity
 Billy Miner – First CGF Facility
 1H18 CGFs
 9NBL
 DJ BASIN
 Value optimization continues with focus on oil rich areas and enhanced completions
 CO
 352,000
 Net acres
 3,220
 Gross locations
 8,400 ft
 Average lateral Length
 2 BBoe
 Net unrisked resources
 DJ Basin Activity 1Q17 2Q17
 Total Sales Volume (MBoe/d) 107 107
 Organic Capital* ($MM) 205 210
 Operated Rigs 2 2
 Wells Drilled 27 29
 Average Lateral Length (ft) 8,840 9,220
 Wells Completed 36 30
 Wells Brought Online 14 33
 Average Lateral Length (ft) 9,970 6,530
 Strong Enhanced Completions Drive 7% 
Horizontal Volume Increase
 • New well wedge outperforming expectations
 • Vertical volumes of 11 MBoe/d impacted by reduced 
workover activity and higher line pressures outside of 
Wells Ranch and East Pony
 Leading Edge Completion Designs
 • Continuation of 1,800 lb/ft standard slickwater design 
• Optimizing stage and cluster spacing 
Activity in Low GOR Areas Increasing Oil 
Percentage 
• Combined Wells Ranch and East Pony volumes up 
13% from 1Q17 to 70 MBoe/d
 46%
 49% 50%
 52% 53%
 2Q16 3Q16 4Q16 1Q17 2Q17
 Oil Mix Continues to Increase
 * Excludes NBLX funded capital expenditures
 Weld
 Wells 
Ranch
 East
 Pony
 NBL Acreage
 10NBL
 40
 50
 60
 70
 2Q16 3Q16 4Q16 1Q17 2Q17
 Wells Ranch and East Pony Volumes
 0
 20
 40
 60
 80
 100
 120
 1Q17 2Q17 3Q17E 4Q17E
 DJ Basin Production Volumes
 2017 Wedge Horizontal Base Vertical Base
 DJ BASIN
 2017 horizontal volume outlook exceeds expectations
 Affirmed 2017 Volume Outlook
 • 2017 Horizontal Outlook Raised with Fewer 
Wells on Strong New Well Performance 
 4Q17 horizontal volumes anticipated up 
~8% YoY
 • Robust New Horizontal Wedge Performance 
Supports NBLX’s Strong Outlook
 • Record Wells Ranch and East Pony Combined 
Volumes in 2Q
 • 2Q17 Total Basin Liquids Volumes Up 6%, 
Natural Gas Down 11% from 1Q17
 • NBL Vertical Production Expected to Continue 
to Decline Due Primarily to Economic Decisions
  Deferred workover activity
  No material cash flow impact as verticals 
have higher gas mix (65-75%) and 
significantly higher LOE
 MBoe/d
 MBoe/d
 11NBL
 0
 50
 100
 150
 200
 250
 0 30 60 90 120 150
 Days on Production
 2017 Wells Ranch Performance*
 2017 Well Ranch (21 Wells w/ avg
 1,900 lb/ft)
  Wells Ranch 1.0 MMBoe Type
 Curve (1,400 lb/ft)
 0
 20
 40
 60
 80
 100
 120
 140
 0 30 60 90
 Days on Production
 2017 East Pony Performance*
 2017 East Pony Wells (26 wells w/ avg 1,500 lb/ft)
 East Pony 570 MBoe Type Curve (1,400 lb/ft)
 DJ BASIN
 Enhanced completions continue to highlight value-focused capital program
 2Q17 Highlights
 • 11 Wells Ranch and 22 East Pony Wells 
Commenced Production in 2Q
 • Shadow Pad (13 wells in Wells Ranch) Tested 
Standard 1,800 lbs/ft Proppant  
 Avg. 10,500 ft lateral and over 1,100 Boe/d 
per well for more than 100 days
 • 3 Additional Pads Utilizing 1,800 lbs/ft in Wells 
Ranch Online Before YE17
 • Continued Strong Performance at East Pony 
with Enhanced Completions
  Balance of 2017 activity focused on federal 
leases with lower proppant concentration
 • Utilizing Advanced Analytics to Optimize 
Completions 
 Integrating complex technical reservoir 
modeling with actual results
  Model expected future outcomes:
  Drives real-time enhanced 
completions variations given 
subsurface changes across acreage 
position
 Cum. MBoe
 *Reflects Gross 3 Stream
 Wells Ranch Normalized to 9,500 ft., East Pony Normalized to 7,500 ft. 
Cum. MBoe
 12NBL
 1,500 ft.
 NBL mapping coordinates, inspection 
and integrity-testing radius exceeded 
1,000 ft. requirement
 7,500
 flowline integrity tests 
field wide YTD
 30
 GPS surveyors added to expedite 
flowline mapping process
 45,000
 man hours on timely 
execution
 DJ BASIN
 COGCC Notice to Operators – ensuring safety of people, protection of the environment and integrity of operations
 • Assembled a multi-disciplinary team to implement the Notice to 
Operators (NTO) issued by the Colorado Oil and Gas Conservation 
Commission (COGCC) on May 2, 2017
  Inspections and GPS of off-pad flowline locations within 1,500 ft. 
complete May 30
  Flowline integrity testing and permanent abandonment of 
inactive off-pad lines complete June 30
 Noble Actions in Colorado
 13NBL
 0
 100
 200
 300
 400
 500
 600
 0 20 40 60 80 100
 Days on Production
 South Gates Cumulative Production
 3,500 MBoe Type
 Curve
 2017 Wells
 EAGLE FORD SHALE
 Achieving targeted value and production ramp on strong execution
 TX
 Eagle Ford Activity 1Q17 2Q17
 Total Sales Volume (MBoe/d) 43 69
 Organic Capital ($MM) 166 113
 Operated Rigs 2 1.5
 Wells Drilled 13 11
 Average Lateral Length (ft) 6,940 6,315
 Wells Completed 17 14
 Wells Brought Online 6 21
 Average Lateral Length (ft) 5,740 6,665
 33,000
 Net acres
 360
 Gross locations
 7,600 ft
 Average lateral Length
 460 MMBoe
 Net unrisked resources
 Activity Focused in Highly-prolific South 
Gates Ranch Row 4
 • Wells demonstrating flatter declines versus type curve
 • 18 South Gates wells to commence production in 2H17
 Record Quarterly Sales Volume of 69 
MBoe/d
 $50 Million Divestiture of Non-core 
Klotzman Acreage Accelerates Value
 • 60% increase over 1Q17
 • 1,900 net acres, fully developed
 • ~500 net Boe/d
 NBL Acreage
 Dimmit
 Webb
 Cum. MBoe
 Reflects Gross 3 Stream, Normalized to 7,000
 Gates 
Ranch
 L&E
 Briscoe
 Ranch
 14NBL
 0
 25
 50
 75
 100
 2017E 2018E 2019E 2020E
 IDR Distributions
 LP Distributions
 $MM
 (1) Includes distributions, IPO and drop down proceeds. Invested capital includes proportionate contribution through IPO and drop down of additional interests. (2) Represents NBL’s 50.1% 
ownership of NBLX LP unit at market value as of 7/31/17 closing price. (3) Estimates average 2018-2020 EBITDA of retained assets and development company interest.  Applies potential future 
drop down multiple of 7.5x and 10x to EBITDA. EBITDA is a Non-GAAP metric that cannot be easily reconciled to GAAP metric at this asset level. See appendix for definition of this non-GAAP 
measure.  (4) Estimates 100% NBL ownership of NBLX GP IDR average cash flows 2018-2020 at 25x to 35x multiple. (5) NBL owns 100% of the GP Holdings of NBLX. Assumes 20% NBLX 
distribution growth and units outstanding remain flat.
 Substantial Growth in Cash Flow Distributions(5) to NBL
 $556 MM
 received to date IPO proceeds, 
distributions and drop down proceeds
 $817 MM
 NBL ownership of LP units(2) 
> $1.5 B
 combined retained EBITDA(3)  
and GP value(4)
 ~2.4x Payout
 on NBL invested capital 
contributed to NBLX(1)
 MATERIAL EMBEDDED MIDSTREAM VALUE
 NBLX offers significant operating and financial efficiencies
 • First Initial Drop Down Transaction Valued at $270 MM, Generated $245 
MM Cash to NBL; Attractive Future Drop Down Potential Remains
  Anticipate significant growth in Delaware and DJ Basin throughput 
and volumes
  Substantial existing opportunities with sponsor retained East Pony 
gas gathering and processing
 Key Highlights
 15NBL
 EASTERN MEDITERRANEAN
 Fueling over 60% of Israel power generation and growing
 Israel 1Q17 2Q17
 Net Gas Sales (MMcfe/d) 274 275
 Gross Gas Sales (MMcfe/d) 956 962
 Organic Capital ($MM) 115 143
 2Q17 Key Highlights
 • Record Second Quarter Gross Sales Volumes
 962 MMcfe/d 
 Achieved several daily records in June and July
 • Resilient 2Q17 Price Realizations of $5.34/Mcf
 • Continued Exceptional Reliability with 99.9% Uptime 
Since Start-up
 • Tamar 8 Development Well Brought Online in April, 
Flowed at ~270 MMcf/d
  Resource implications higher than 10 Tcfe gross 
recoverable
 • Booked Initial Leviathan Proved Reserves of 550 
MMBoe, Net
 500
 600
 700
 800
 900
 1,000
 1,100
 1Q 2Q 3Q 4Q
 2014 2015 2016 2017
 MMcfe/d
 1.1 Bcfe/d 
Gross 
Peak 
Capacity
 Historical Tamar Gross Sales Volumes
 AOT
 47% WI
 Tamar
 32.5% WI
 Tamar SW
 32.5% WI Tel Aviv
 Ashdod
 Israel
 Egypt
 Cyprus
 35% WI
 Leviathan
 39.7% WI Dor
 Discovery
 Existing Pipeline
 Planned Pipeline
 Sanctioned
 NBL Interests
 Producing
 16NBL
 LEVIATHAN MAJOR PROJECT
 Progressing towards first gas sales by end of 2019
 15%
 complete with Phase I development 
100%
 of building permits submitted
 Drilled L5
 well to total depth of 17,200 ft
 Project Phase 2017 2018 2019
 Sanction
 Order Critical Path Equipment
 Detail Design and Engineering
 Pipeline Manufacturing
 Equipment Manufacturing
 Commissioning and First Gas
 Drilling and Completions
 Offshore Platform Installation
 Drilling, Manufacturing, and Onshore Construction 
Underway
 17NBL
 OTHER GLOBAL OFFSHORE
 Exceptional operational and safety performance
 2Q17 Key Highlights
 • Strong Well Performance at Big Bend, Dantzler 
and Gunflint Fields in the Gulf of Mexico Led to 
Average Sales Volumes of 27 MBoe/d
  81% oil contribution
 • Neptune Spar Life Extension Granted Through 
YE2019 by U.S. Coast Guard
  First GOM spar extension in the industry
 • Maintained 99% Uptime at Aseng and Alen in 
West Africa and at Neptune in the Gulf of Mexico
  Operatorship at Gunflint drove uptime to 
87% up from 73% in 1Q17
 • Executed Unitization Agreement Over the Alba 
Field with Partners of Block D, Reducing NBL 
Working Interest from 35% to 33%
  Zero liftings at Alba field in 3Q17 (10 MBoe/d 
impact)
 Gulf of Mexico Equatorial Guinea
 1Q17 2Q17 1Q17 2Q17
 Oil (MBbl/d) 24 22 18 22
 Equity Method (MBbl/d) 2 2
 NGL (MBbl/d) 2 2
 Equity Method (MBbl/d) 6 4
 Gas (MMcf/d) 23 16 244 231
 Total Sales (MBoe/d) 30 27 66* 66*
 Organic Capital ($MM) 9 0 1 16
 * Produced volumes differ from sales in Equatorial Guinea due to the timing of liftings. Produced volumes were 70 MBoe/d in 1Q17 and 66 MBoe/d in 2Q17.
 18NBL
 SURINAME EXPLORATION PROSPECT
 Testing high potential prospect in late 2017
 Guyana
 Suriname
 Block 54
 Araku
 Oil Prospect in Cretaceous Rock
 • Significant Recent Discoveries Offshore 
Guyana Prove Working Hydrocarbon System
  Onshore Suriname Tambaredjo field 
producing oil
 • Block 54 Offshore Suriname
  NBL 20% WI, non op.
  Proprietary 3D survey completed 
 Multiple play types
 • Araku Prospect Targeted for 4Q17
  500+ MMBoe gross potential
  3,200 ft water depth
  ~8,000 ft target depth
  ~$10 MM net well cost
  Primary risk: hydrocarbon phase
 Tambaredjo
 Liza & Payara
 Oil Discovery
 NBL Interests
 Oil Prospect
 19NBL
 0
 75
 150
 225
 300
 375
 450
 Original
 FY17E
 Divested Original FY17E
 Excluding
 Divested
 Updated
 3Q17E
 Updated
 4Q17E
 (~75)
 UPDATED 2017 GUIDANCE
 U.S. onshore oil, total oil and total company full year volumes at midpoint or upper half of original guidance*
 * Pro-forma for divestments  ** Excludes NBLX funded capital expenditures
 • FY17 Sales Volumes on Track with Original 
Guidance After Adjusting for Marcellus and Other 
Non-Core Divestitures
  Original assumed 72 MBoe/d in 3Q and 80 
MBoe/d in 4Q for Marcellus (82% gas, 14% 
NGL, 4% oil)
 • 25 - 30 MBbl/d Increase in Oil Volume 4Q17 vs. 
3Q17 Driven By:
 • Resumption of Alba field liftings
 • ~115 2H17 U.S. onshore wells online
 • Marcellus Divestment Drives Margin Expansion
  U.S. Onshore oil mix grows to over 40% from 
~30%
  Lowers FY17 unit operating expenses
 • Organic Capital Expenditures** Expected at the 
Upper End of $2.3 B to $2.6 B Guidance for FY17
  Accelerated midstream and Leviathan spend
  75% allocated to U.S. Onshore, 20% to EMED
 Total Company Sales Volume GuidanceKey Highlights
 MBoe/d
 415-425
 340-350
 380-390
 340-350
 25
 75
 125
 1Q 2Q 3QE 4QE
 2017 USO Oil Trajectory*
 MBbl/d
 20NBL
 Third quarter and fourth quarter guidance
 SALES VOLUME GUIDANCE
 Sales Volume
 Crude Oil and 
Condensate 
(MBbl/d)
 Natural Gas 
Liquids (MBbl/d)
 Natural Gas 
(MMcf/d)
 Total Equivalent 
(MBoe/d)
 Low High Low High Low High Low High
 Third Quarter 2017
 United States Onshore 86 91 58 61 390 405 209 219
 United States Gulf of Mexico 18 20 1 2 10 20 21 25
 Israel - - - - 285 305 47 50
 Equatorial Guinea 12 14 - - 215 235 48 53
 Equatorial Guinea - Equity method 
investment
 2 3 6 6 - - 8 9
 Total Company 120 126 65 70 910 950 340 350
 Fourth Quarter 2017
 United States Onshore 102 108 68 71 465 480 248 258
 United States Gulf of Mexico 20 23 1 2 15 25 24 28
 Israel - - - - 235 265 40 43
 Equatorial Guinea 20 23 - - 210 235 56 61
 Equatorial Guinea - Equity method 
investment
 1 2 6 6 - - 7 8
 Total Company 147 152 75 80 945 985 380 390
 21NBL
 * Excludes NBLX funded capital expenditures
 Capital & Cost Metrics
 3Q 2017 4Q 2017
 Low High Low High
 Capital Expenditures* ($MM)
 Total Company Organic Capital 625 725 600 700
 Cost Metrics
 Lease Operating Expense ($/BOE) 4.50 4.75 4.25 4.50
 Gathering, Transportation & Processing ($/BOE) 3.00 3.25 3.00 3.25
 Production Taxes (% Oil, Gas, NGL Revenues) 4.3 4.7 4.3 4.7
 Marketing ($MM) 10 20 10 20
 DD&A ($/BOE) 15.00 16.00 15.00 16.00
 Exploration ($MM) 30 50 40 60
 G&A ($MM) 95 110 95 110
 Interest, net ($MM) 85 95 85 95
 Other Items Guidance
 Equity Investment Income 30 40 30 40
 Average outstanding shares – diluted 480 490 480 490
 CAPITAL AND COST GUIDANCE
 Third quarter and fourth quarter guidance
 22NBL
 Forward-Looking Statements and Other Matters
 This presentation contains certain "forward-looking statements" within the meaning of federal securities laws. 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. Such forward-looking statements may include, but are not limited to, future financial and operating results, and other 
statements that are not historical facts, including 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 and uncertainties 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 businesses 
that are discussed in Noble Energy's most recent annual reports on Form 10-K, respectively, and in other Noble Energy reports on file with the Securities and Exchange 
Commission (the "SEC"). These reports are also available from the sources described above. 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 any forward-looking statements should circumstances or 
management’s estimates or opinions change.
 The SEC 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 unrisked 
resources”, “type curve”, “MMBoe type curve”, or “MMBoe gross potential” which 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.nblenergy.com.
 This presentation also contains certain historical 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 see the Noble Energy’s respective earnings release for reconciliations of the differences between any historical non-GAAP measures used in this 
presentation and the most directly comparable GAAP financial measures.
 This presentation also contains a forward-looking non-GAAP financial measure, EBITDA (earnings before interest, taxes, depreciation and amortization). Due to the forward-
 looking nature of the aforementioned non-GAAP financial measure, management cannot reliably or reasonably predict certain of the necessary components of the most 
directly comparable forward-looking GAAP measures at this asset level.  Accordingly, we are unable to present a quantitative reconciliation of such forward-looking non-GAAP 
financial measure to its most directly comparable forward-looking GAAP financial measure. Amounts excluded from this non-GAAP measure in future periods could be 
significant. Management believes the aforementioned non-GAAP financial measure is a good tools for internal use and the investment community in evaluating Noble Energy’s 
overall financial performance. This non-GAAP measure is broadly used to value and compare companies in the crude oil and natural gas industry.