Long-term Outlook and U.S. Onshore Update 
November 16, 2016
 NBL 
Long-term Outlook 
Dave Stover 
2 
Chairman, President and CEO
 NBL 
3 Key Takeaways From Today 
Robust Growth in Oil, Total Production, and Cash Flow 
 2016 – 2020E:  U.S. onshore oil grows at a 23 – 29% CAGR*   
   DJ and Delaware increase to between 240 MBoe/d (base plan) and 300 MBoe/d (upside) 
   Total company volume CAGR of 8 – 12%** 
   Total company operating cash flow outpaces total volume growth by 3 - 4X 
Near-Term Sanction at Leviathan: Extending Growth Trajectory 
 More than doubling EMED gross capacity by 2020 
 EMED cash margins competitive with U.S. unconventional oil basins 
Fully Funded Capital Program with Improving Balance Sheet and 
Corporate Returns 
 Leviathan initial investment funded with EMED portfolio management 
 Remaining capital and dividend funded by operating cash flows 
 Return on average capital employed*** increases to 8 – 14% in 2020E  
 
3 
It’s all about value-added growth 
* Ranges used throughout the presentation represent base to upside plan outcomes.  See base and upside plan pricing in appendix.   ** Adjusted for divestitures  *** See appendix for definition of this non-GAAP measure.
 NBL 
Strategic Pillars and Focused Plan 
4 
Delivering leading returns and enhancing value 
* See appendix for definition of this non-GAAP measure 
High-Quality and Advantaged Portfolio  
 Over 7,000 U.S. onshore future drilling locations (avg. 
lateral length of 8,000 feet)  
 Over $2 Billion GOM and West Africa cumulative net free 
cash flow* 2016 – 2020E 
 In excess of 35 Tcf EMED gross natural gas resources to 
meet growing regional demand 
Industry-leading Operational Capabilities  
and Execution 
 Improving returns with drilling, completions, and  
infrastructure competitive advantages 
 Leverage major project successes and current cost  
environment for Leviathan 
Disciplined Capital Allocation and Robust 
Financial Capacity 
 Maintain flexibility and Investment Grade Credit Rating 
 Capital deployed based on best returns
 NBL 
Expanded Portfolio with Entry into Two Top-Tier U.S. Basins 
Materially De-Risked DJ Basin Development Environment 
Established Regulatory Framework for Israel’s Energy Future 
Increased Flexibility and Control over Marcellus Investment 
 
Produced 10 MMBoe Above 2016 Plan with $100 MM Less Capital 
Improved Returns with Technology Advancements and Structural  
Cost Savings 
Delivered Four Major Offshore Projects on Budget and on Schedule 
 
Proactive and Strategic Action to Manage within Cash Flows 
Portfolio Management and Midstream Increase Future Financial Capacity 
Investment Grade Credit Rating 
Recent Accomplishments Enhance Future Outlook 
5 
2015 and 2016 outcomes creating long-term value 
Operational 
Excellence 
Financial 
Strength 
Superior 
Portfolio
 NBL 
  
($1,750)
 ($1,350)
 ($950)
 ($550)
 ($150)
 $250
 $650
 -20% -10% 0% 10% 20%
 NBL 
Differentiated Performance Versus Peers 
NBL Delivering Top-Quartile Production Growth 2015 to 2016 within Cash Flow 
 One of 3 in peer group to grow production while reducing net debt* in 2016  
 One of 2 in peer group to generate volume growth on 50%+ lower capital expenditures  
6 
Maximizing value in low commodity environment 
  
Peers Include: APA, APC, CHK, CLR, COG, DVN, EOG, HES, MRO, MUR, PXD, RRC, and SWN       Source: Company filings, Cap IQ, Analyst Consensus, Thomson One and Noble Energy        
Proforma NBL for 2016 reflects Rosetta Resources Inc. merger (closed in July 2015) as if it were included for a full year 2015        * See appendix for definition of this non-GAAP measure 
 
-40%
 -20%
 0%
 20%
 40%
 60%
 -20% -10% 0% 10% 20%
 Pro Forma NBL NBL 
Estimated Production Growth vs. Net Debt* Reduction 2015 - 2016 
Production Growth while 
Reducing Net Debt* 
FY2015-FY2016E Production Growth 
N
 et
  D
 eb
 t*
  R
 ed
 u
 ct
 io
 n
  
 
Production Growth and 
Cash Flow Positive 
Pro Forma NBL 
Estimated Production Growth vs. Net Free Cash Flow* 2015 - 2016 
FY2015-FY2016E Production Growth 
2
 0
 1
 6
 E 
N
 et
  F
 re
 e 
C
 as
 h
  F
 lo
 w
 *
 NBL 
  
ROSE Merger: A Great Deal Gets Even Better 
Combined Texas Volumes Anticipated Between 165 and 195 MBoe/d by 2020,  
Up 80 - 120% Versus Merger Plan 
Generating Annual Net Free Cash Flow* 2018 Forward (Base Plan) 
Early Entry into Delaware Enhanced Acreage Value by up to $1.8 Billion 
Increased Texas Net Unrisked Resources by 50% to 1.5 BBoe 
Reduced 2016 Interest by $50 MM and Generated Over $80 MM in Annual G&A Synergies 
7 
Delivering value through early entry and activity acceleration 
Notes: 
Trading and transaction values adjusted for 
production value based on $35,000/BOE/d 
Median Delaware transaction $/acre in 2H16 
Permian equity multiples group: FANG, RSPP,  
SRAQ, PE, CPE, PXD, CXO, LPI, and EGN 
NBL Delaware Undeveloped 
Acreage Value 
$2.2 B 
Value Based 
on  
Permian 
Equity 
Multiples 
$1.4 B 
Value Based 
on  
Delaware 
Transactions 
$400 MM 
Value Allocated 
in 
NBL/ROSE 
Merger 
3.5 – 5.5X 
Value  
From  
Early Entry 
64 MBoe/d  
Delaware / EF Sales Volumes 
Growing 160 – 200% 2016 – 2020E 
165 - 195 MBoe/d 
90 MBoe/d  
* See appendix for definition of this non-GAAP measure 
2016  2020E 
Merger Plan 
2020E 
Current Plan  
Eagle Ford 
Delaware 
Upside
 NBL 
Focused Outcomes Through 2020 
DJ and Delaware Increase to 240 MBoe/d in Base  
Plan and 300 MBoe/d in Upside 
 Combined CAGR of 19–26%  
Approximately 75% of Total Company Capital to DJ, 
Delaware, and EMED 
Accelerate USO Activity to 13 Rigs (Base Plan) and 
Up to 16 Rigs (Upside) by 2020 
2020E Includes Full Year of Volumes from Leviathan 
 
8 
Accelerating high-margin growth 
  
 155 MBoe/d ** 
DJ, Delaware, and 
EMED Volume Growth   
300 
MBoe/d 
390 
MBoe/d 
** 2016 Tamar production volumes adjusted to reflect a reduction in working interest to 25%,  
 anticipated to be accomplished during plan period.  
Base plan for 2020 assumes Leviathan volumes at startup of a minimum 600 MMcf/d, gross.  Upside 
plan assumes 1 Bcf/d at startup.  NBL Leviathan working interest at startup assumed at 35%. 
DJ 
Delaware 
EMED 2016 – 2020E  
Total Company Capital* 
Other Offshore 
Other USO 
EMED 
Delaware 
DJ 
Base Plan 
~$12 B 
Upside Plan 
~$13.5 B 
* Excludes NBLX estimated capital expenditures  
2016  
Divestment 
Adjusted 
2020E  
Base Plan 
 
2020E 
Upside Plan
 NBL 
High-Margin Growth Accelerates Cash Flow Even Faster 
9 
ROACE* increases to 8 – 14% by 2020 
Total NBL
 Base Upside
 23% 
35% 
Total Company Operating Cash Flow 
Grows Even Stronger 
(2016 – 2020E CAGR) 
Total
 NBL
 U.S.
 Onshore
 Total
 NBL Oil
 U.S.
 Onshore
 Oil
 Base Upside
 Strong Total and Oil Volume Growth 
(2016 – 2020E CAGR)** 
8% 
12% 13% 
16% 
11% 
16% 
23% 
29% 
* See appendix for definition of this non-GAAP measure ** Adjusted for divestitures
 NBL 
Fully Funded Business Plan 
Operating Cash Flows Exceed Total 
Capital (Excluding EMED) and Dividend 
EMED Portfolio Management Self-Funds 
Leviathan Initial Phase  
Maintains Robust Financial Liquidity and 
Improves Balance Sheet 
Nearly $5 B Incremental Operating Cash 
Flow Upside with $10/Bbl WTI Increase 
 Accelerates growth outlook 
Midstream Provides Additional Future 
Proceeds / Acceleration 
10 
Significant growth while improving the balance sheet 
Sources Uses
 Cumulative Sources & Uses 
(2016 – 2020E) 
Upside 
Operating 
Cash Flow 
Operating 
Cash Flow 
 USO & Other 
Global Offshore 
Capital 
 EMED 
Capital 
Strengthen 
Balance Sheet 
 Dividends 
 Future EMED 
Proceeds 
2016 EMED 
Proceeds 
2016 Domestic 
Proceeds 
Base Plan  
Upside Plan 
Note: Sources do not include potential additional future proceeds from NBLX / CNNX. 
Additional 
Opportunities 
Upside 
Capital
 NBL 
Material Midstream Embedded Value 
11 
A growing portion of the NBL value opportunity 
NBLX and CNNX with Access to Premier  
U.S. Onshore Assets 
 NBLX and CNNX yields in top quartile of MLP valuations 
NBL Maintains Ownership and Control of 
Critical Midstream Assets 
 55% of NBLX LP units 
 32% of CNNX LP units 
Attractive Future Dropdown Potential 
 Substantial retained EBITDA in development companies 
 NBLX retains ROFR on all existing and future midstream 
assets 
MLP Ownership Provides Cost Advantage 
 Portion of midstream fees returned through LP 
ownership 
Additional Value Upside Potential 
 Future distributions, retained sponsor EBITDA growth, 
GP and IDR value growth 
 
0.0
 0.5
 1.0
 1.5
 2.0
 2.5
 Realized
 Cash*
 LP Units** Retained
 EBITDA
 Value***
 GP/IDR
 Value ****
 Total
 $2.5 B in Midstream Value to NBL 
NBLX CNNX Combined
 $ B 
* IPO proceeds plus drop-down proceeds and distributions made to NBL 
**Represents market value of LP units held by NBL as of 11/11/16 closing price 
*** EBITDA of retained asset and development company interest.  Applies potential future dropdown 
multiple of 7.5x and 10x to next 12 month 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 
****NBL owns 100% of the GP/IDRs of NBLX (assumed value of $75 MM today).  NBL owns 50% of the 
GP of CNNX (applies a 30X multiple to net annual incentive distributions)
 NBL 
Improved 2017 Outlook and Capital Plans 
12 
Delivering much more than original expectations 
* Excludes NBLX estimated capital expenditures  
300
 325
 350
 375
 400
 425
 Original 2017 
Outlook 
 2016 Divestments 
Impact 
Raised  
Expectations 
2017 Outlook 
MBoe/d 2017 Volumes Raised Nearly 10% From Original 
Expectations 
400 - 410 
390 
  2017 Preliminary Capital  
 
       $2.0 - $2.4 B* 
 
        65% DJ / Texas 
        25% EMED 
 
 
Other 
EMED 
Delaware 
DJ 
Eagle Ford 
Original Plans Assumed 2017E Volumes Could be Held  
at 390 MBoe/d for $1.5 B Capital, Excluding EMED 
 
2017E Plan Estimates 405 MBoe/d on $1.65 B Capital, 
Excluding EMED 
Over 70% of Total Capital Allocation to 
U.S. Onshore 
2017E USO Average Rigs Increased to 7, 
More Than 2X 2016 Rigs 
 DJ (2-3), Delaware (3), Eagle Ford (1) 
Commencing Leviathan Development 
 ‘17 capital primarily funded by ‘16 Tamar sell-down 
 
372
 NBL 
2017 Preliminary Volume Outlook 
~15%* U.S. Onshore Oil Growth in 2017E 
 Up ~25%* 2H16 to 2H17E 
Total U.S. Onshore Volumes Increasing Approx. 4%, 
Adjusted for Divestments 
 Combined Texas volumes up ~35% over 2016 
 DJ Basin horizontal volumes delivering growth exiting 2017 
13 
Providing growth on a divestment-adjusted basis 
400 – 410 
350
 375
 400
 425
 Reported 
2016 
Marcellus 
JV Impact 
Other USO Tamar 3.5% Adjusted 
2016 
2017E 
MBoe/d 
Combined 18 MBoe/d Divest 
400 
2017 Volumes Up From 2016 
After Divestment Impacts 418 
90 - 92   
MBbl/d 
2H17E  
U.S. Onshore Oil Volumes 
2H16 to 2H17E up ~20 MBbl/d  
 
~72* 
 MBbl/d 
2H16  
 
210 - 215 
MBoe/d 
2H17E  
DJ Basin, Delaware, and Eagle Ford Volumes 
2H16 to 2H17E up over 40 MBoe/d  
 
170  
MBoe/d 
2H16  
 
*  Adjusted for divestitures
 NBL 
Combination Provides Competitive Advantages 
U.S. Onshore 
 Deep inventory of locations in high-return,  
low-cost basins 
 Contiguous acreage in multiple stacked  
pay resource plays 
 Significant capital efficiency gains with  
sustainable cost reductions 
Eastern Mediterranean  
 Long-life assets with strong realizations  
and low maintenance capital 
 World-class projects in substantially undersupplied  
regional market 
Other Global Offshore 
 Oil-levered assets 
 Substantial annual cash flow contributor 
14 
Premier, high-quality unconventional and offshore assets
 NBL 
Other Global Offshore Oil-levered Assets 
Leading Operational Capability and Major Project Execution  
 Big Bend, Dantzler, Gunflint, and Alba compression all online in 2015-2016 
$2.1 - $2.7 B Net Free Cash Flow* 2016-2020E 
Additional Future Development Opportunities 
 Katmai GOM development through subsea tieback  
 Upside from additional West Africa liquid discoveries and gas monetization 
15 
Cash generation supports DJ and Texas growth 
0.0
 0.6
 1.1
 1.7
 2.2
 2.8
 0
 40
 80
 120
 2016 2017E 2018E 2019E 2020E
 GOM and West Africa Volumes  
and Cash Flow Outlook 
 West Africa  GOM
  Cumulative Net Free Cash Flow* - Base  Cumulative Net Free Cash Flow* - Upside
 MBoe/d $ B 
* See appendix for definition of this non-GAAP measure
 NBL 
EMED: World-class Resources in a High-Demand Region 
Tamar 10 Tcf (Producing) and Leviathan 22 Tcf Gross 
Recoverable Resources 
 Tamar supplying up to 60% of Israel power generation 
Leviathan Sanction On Track for YE 2016 / Early 2017 
 Up to 450 MMcf/d sales under contract totaling ~$12 B gross 
revenues 
 Expected sales volumes in 2020 of a minimum of 600 MMcf/d 
and up to 1 Bcf/d, gross 
Expanding Ultimate Gross Capacity to Over 4 Bcf/d 
 Tamar current capacity 1.2 Bcf/d, upside expansion to 2 Bcf/d 
 Leviathan ultimate capacity of 2.1 Bcf/d 
 Regional deficit 4 Bcf/d currently, growing to 9 Bcf/d 
EMED Portfolio Management Planned to Support 
Upcoming Development 
 Tamar 3.5% sell-down closing 4Q16, additional 7.5% planned 
 Leviathan 10% farm-down assumed over plan 
 
16 
Exceptional assets, margins, and growth
 NBL 
Streamlined Exploration Program 
Progressing Long-Cycle Exploration Potential 
 Differential offshore exploration capabilities in discovering 
and monetizing resources 
 Disciplined focus on highest-quality opportunities and 
value potential 
 Targeting new core area post Leviathan start up 
U.S. Onshore Short-Cycle Opportunities 
 Leveraging geoscience expertise in support of business 
development activities 
 Evaluating new resource play potential 
 
17 
Building and maturing portfolio for significant future value
 NBL 
U.S. Onshore Update 
Gary Willingham 
18 
Executive Vice President, Operations
 NBL 
U.S. Onshore Top Tier Acreage in Premier Basins 
19 
Complementary assets driving growth and value  
Delaware 
352,000 net acres 
3,220 gross locations 
8,400’ average lateral length 
2 BBoe net unrisked resources 
Eagle Ford 
Marcellus 
363,000* net acres 
1,900 gross locations 
8,000’ average lateral length 
20 Tcfe net unrisked resources 
DJ Basin 
40,000 net acres 
1,675 gross locations 
7,500’ average lateral length 
1 BBoe net unrisked resources 
35,000 net acres 
360 gross locations 
7,600’ average lateral length 
460 MMBoe net unrisked resources 
* Reflects Marcellus acreage post JV separation 
One of the Largest Independent 
U.S. Onshore Producers 
 Combined ~7 BBoe net unrisked resources 
Industry Leading Operating 
Capabilities and Execution 
 Drilled over 1,600 horizontal wells  
Differentiated Ability in Sharing 
Learnings Across Basins 
Leveraging Midstream 
Infrastructure Advantage 
Excellent Safety and Stewardship 
Performance
 NBL 
Recent U.S. Onshore Accomplishments 
20 
2015 and 2016 actions enhance long-term value 
Added Positions in Two Top-Tier U.S. Basins 
Enhanced Wells Ranch IDP in the DJ Basin through Acreage Exchange 
Focused Activity within Liquids Plays 
 
 
Enhanced Completions Delivering Increase in Per Well Recovery Across 
USO and Adding to Economic Inventory 
Increased Drilling Efficiency within the DJ Basin by Over 75% since 2014 
 
 
Reduced USO Unit Lease Operating Expenses by 33% since 2014, 
Creating Sustainable Advantage 
Accelerated Value of Long-dated Inventory in DJ Basin 
Operational 
Excellence 
Financial 
Strength 
Superior 
Portfolio
 NBL 
0
 25
 50
 75
 100
 Near Term Focus Areas BTAX ROR 
0
 1,000
 2,000
 3,000
 4,000
 5,000
 6,000
 7,000
 <$40/Bbl
 <$2/Mcf
 Base Plan
 Pricing
 Gross Identified
 Locations
 USO Gross Inventory  
Leading U.S. Onshore Economics 
21 
Extensive and high-quality inventory with competitive returns 
Over 7,000 Future Drilling Locations, 
More than 60% with at Least 10% BTAX 
Rate of Return at $40/Bbl and $2/Mcf 
 8,000 ft. lateral avg. 
 Over 20 years of drilling inventory 
Eagle Ford Delaware DJ Marcellus 
BTAX PV10 or Greater 
Base Returns Reflective of Current Type 
Curves 
 30%-95% returns within focus areas 
 Upside potential from further improvements 
 $10 WTI increase provides significant upside 
 
Upside Price Base Price 
DJ Basin Delaware Eagle Ford Marcellus* 
Commodity price assumptions provided in appendix.  * Marcellus upside price assumes $0.50 Henry Hub increase 
Wells ROR %
 NBL 
U.S. Onshore Outlook Through 2020 
Peer-leading oil volume growth within cash flow 
Accelerating Activity Levels and Growth  
2016 – 2020E 
 USO sales volume 13-16%* CAGR 
 USO oil volume 23-29% CAGR 
Unit Operating Cash Flow Margin**  
Increases 2– 3X  
90% of USO Capital Focused on DJ Basin, 
Delaware and Eagle Ford 
22 
* Adjusted for divestitures   ** See appendix for definition of this non-GAAP measure  
*** Excludes NBLX estimated capital expenditures  
Upside Base 
Base Plan 
~$9 B 
Upside Plan 
~$10.5 B 
Estimated USO Capital*** 2016-2020 
2.8 
2016 
Growing Average Rig Count 
7 
2017E 
13-16 
2020E 
~70 
MBbl/d 
2016 
Over 2X USO Oil Volume Growth 
80-85 
MBbl/d 
2017E 
160-195 
MBbl/d 
2020E 
2016 2017E 2020E 
USO Sales Volumes 
255 
MBoe/d * 
260 - 270 
MBoe/d 
410-465 
MBoe/d
 NBL 
Delaware Basin: Long-term Growth Engine for the USO Portfolio 
23 
1 BBoe in the heart of the Delaware 
0
 100
 200
 300
 400
 500
 600
 A NBL B C D E F G H I
 2016 Delaware Basin Operator Average 
 24 Hour Test Rate per 1,000 ft  
Boe/d per 
1,000 ft. 
Source: Well test rate analysis by KLR Group, report dated 10/20/16; 
Peers include EOG, CVX, PE, OXY, APA, BHP, REN, APC, MTDR 
Materially Increasing Type Curves, Gross 
Locations and Resources 
Accelerating into Full Development Mode 
Initial Results Confirm High Quality Acreage 
Position and Value Potential 
Transferring Unconventional Expertise from 
Other USO Basins 
Reeves 
Ward 
Pecos 
Loving Winkler NBL Acreage 
Delaware Basin 
 40,000 net acres; 70% Oil 
 1,675 gross locations avg. 
7,500 ft. lateral length 
 1 BBoe net unrisked 
resources 
 65% Avg. WI
 NBL 
0
 25
 50
 75
 100
 2016 2017E 2020E
 Delaware Sales Volumes 
0
 200
 400
 600
 800
 1,000
 2016 2017E 2020E
 Delaware Capital** $MM 
Delaware Outlook to 2020 
24 
Total Sales Volumes 70-85% CAGR 2016-2020E 
Oil Volumes Grow to 50-70 MBbl/d by 2020E 
Net Free Cash Flow* Positive Beginning in 2018 
Unit Operating Cash Flow Margin* Increases 3 – 4X 
2017 Estimated Capital More than Triples in 2016 
 Approximately 35 new wells online in 2017 
Tremendous growth and value acceleration 
MBoe/d 
Upside Base Upside Base 
0.5 
2016 
Average Operated Rig Count 
~15 Wells on Avg. per Rig per Year 
3 
2017E 
5-7 
2020E 
* See appendix for definition of this non-GAAP measure    ** Excludes NBLX estimated capital expenditures
 NBL 
0
 100
 200
 300
 400
 500
 0 100 200 300 400
 Cum.  
MBoe 
Days on Production 
Well Results Improving with Enhanced Completions  
Gen 1 Gen 2 Gen 3 WCA Current Type Curve Gen 4
     NBL 
New Completion Techniques Delivering Enhanced Results in the Delaware 
25 
Faster learning curve accelerates value creation 
Note: Gross 3 stream normalized to 7,500’ lateral 
Generation 1 
700 lbs/ft 
X-Link Fluid 
Generation 2 
1200 lbs/ft 
Hybrid Fluid 
Generation 3  
1500+ lbs/ft 
Hybrid Fluid 
Generation 4 
2000+ lbs/ft 
Slickwater 
ROSE 
Leveraging Learnings from Across USO 
to Optimize Completions  
 Quickly transitioned to slickwater, high 
intensity completions 
 Optimizing well placement to maximize 
total resource development 
Significant Improvements from Initial 
NBL Wells  
 Stronger well performance with higher 
proppant loading and shorter stages 
Testing Higher Proppant Concentration 
Upside 
 Up to 5,000 lbs/ft proppant results 
expected early 2017
 NBL 
Merger
 Plan
 3rd BS &
 Wolfcamp
 A Locations
 Wolfcamp
 Other
 Locations
 EUR Uplift Current
 Net Unrisked Resources (MMBoe) 
Enhanced Delaware Basin Type Curves 
26 
Rapidly improving ultimate recovery 
Net Unrisked Resource Increased by 145% to 1 BBoe 
Wolfcamp A Type Curve Raised to 1.2 MMBoe for 
7,500 ft. Lateral Length 
 Up 20% per lateral foot 
 Base well design includes 2,000 lbs/ft proppant, and 
slickwater 
Approximately 75% of Locations Generate at Least a 
10% BTAX Rate of Return at $40/Bbl or Below 
  
3 Stream 
EUR 
(MBoe) 
Lateral 
Length (ft.) 
Lateral 
Spacing (ft.) 
Commodity Mix % 
(Oil / NGL / Gas) 
Well Costs 
($MM) 
BTAX Rate of Return Gross 
Locations Base Upside 
3rd Bone Spring 920 7,500 1,320 70 / 15 / 15 6.3 90% 155% 215 
Wolfcamp A 
(Lower & Upper) 
1,200 7,500 880 70 / 15 / 15 8.5 75% 125% 695 
Wolfcamp B 1,135 7,500 880 70 / 15 / 15 8.6 40% 65% 385 
Wolfcamp C 900 7,500 880 70 / 15 / 15 8.8 15% 30% 380 
400 
1,000 
Near 
Term 
Focus 
Well economics based on 100% WI, 75% NRI. Well costs and economics fully burdened with upstream capital and midstream costs.
 NBL 
Delaware Stacked Pay Running Room 
27 
High-quality Stacked Targets Across Position 
 Pay interval more than 3,400 ft thick 
Increased Locations by 40% to 1,675 from Merger Plan 
 Drillable footage up more than 100% including longer  
lateral lengths 
 Increased confidence in Wolfcamp A downspacing 
 Added Wolfcamp B and C locations to development plan 
Additional 485 Potential Locations in Other  
Prospective Zones 
 
Additional opportunities to be unlocked 
Targeted Wells per Section  NBL Peer Range 
Development Plan 
3rd Bone Spring 4 4-7 
Wolfcamp A Upper & Lower 12 7-15 
Wolfcamp B 6 6 
Wolfcamp C 6 4-6 
Gross Inventory 1,675 
Potential Upside 
1st Bone Spring & Avalon 4 6-16 
2nd Bone Spring 4 4-6 
Total Inventory 2,160 
Top TVD 
7,950’ 
8,800’ 
9,000’ 
9,600’ 
10,400’ 
10,700’ 
10,950’
 NBL 
 -
  400
  800
  1,200
  1,600
 Wolfcamp A Planned Well Cost 
Progressing Delaware to Development Mode 
28 
Planning Infrastructure for Long-Term 
Development 
 Designed to maximize flexibility, scalable to 
development pace  
 Planning build-out for multiple gathering facilities 
First NBLX Facility Startup by 2Q17  
 Facility design incorporates produced water 
recycling and integrated water wells and ponds 
Optimized Drilling and Completion Design 
Yielding Significant Cost Efficiencies 
 Target $8.5 MM for 7,500 ft. lateral well 
 Multi-well pads with long lateral development 
realizes up to  $1.5 B in net D&C savings 
Driving significant capital and operating cost efficiencies 
$/lateral ft. 
Merger Case 
5,000’ Lateral 
Target 
7,500’ Lateral
 NBL 
Delaware Basin Impactful Near-Term Catalysts 
29 
Focused on long laterals, pad drilling and multi-zone testing 
Reeves 
Ward NBL Acreage 
NBLX Gathering Facilities 
 First Online by 2Q17 
 Second Online by Year-End 
Wolfcamp B 
 7,300 ft lateral 
 3,000 lbs/ft completion 
 Online 4Q16 
Multi-Zone Development 
 7-well pad with 7,500 ft 
laterals 
-  3rd Bone Spring: 2 
-  Wolfcamp A Upper: 3 
-  Wolfcamp A Lower: 2 
 Online 4Q17 
High Intensity Completions 
 Testing 3,000 lbs/ft to 
5,000 lbs/ft  
 Online 4Q16 
Multi-Zone Development 
 3-well pad with 10,000 ft 
laterals 
 3rd Bone Spring, Wolfcamp A 
Upper and Wolfcamp A Lower 
 Online 2Q17
 NBL 
0
 10
 20
 30
 40
 50
 60
 70
 80
 90
 0% 20% 40% 60% 80% 100%
 Wellhead  Liquids %  
NBL 
High EUR and High Liquids Mix  
DJ Basin: Foundational Asset of the USO Portfolio 
30 
Source: RS Energy; 2015 2 Stream data; Peers include: PDCE, APC, XOG, ECA, SYRG, BCEI, WLL, and BBG 
Large, high-quality, contiguous acreage position 
DJ Basin Average Operator EUR vs. Liquids % 
Creating Differential Value with Long Laterals, 
Midstream Advantage and High Liquids Content 
Increasing Type Curves in Focus Development Areas 
Enhancing Capital Efficiency through Technology 
and Sub-surface Expertise 
DJ Basin 
 352,000 net acres, 70% Liquids 
 3,220 gross locations, avg. 8,400 ft. 
lateral length 
 2 BBoe net unrisked resources 
 79% Avg. WI 
NBL Acreage 
IDP Areas 
Low GOR 
Mid GOR 
High GOR 
East  
Pony 
Wells 
Ranch 
Mustang 
Greeley 
Crescent 
Bronco 
Weld  
W
 el
 lh
 ea
 d
  Bo
 e
 /f
 t
 NBL 
0
 50
 100
 150
 200
 2016* 2017E 2020E
 DJ Basin Sales Volumes 
0
 250
 500
 750
 1,000
 1,250
 1,500
 2016 2017E 2020E
 DJ Basin Capital** $MM 
DJ Basin Outlook to 2020 
31 
Total Sales Volume 11-16%* CAGR 2016-2020E 
Near-Term Focus on Wells Ranch, East Pony and  
Mustang Areas 
Continued Expansion of Necessary NBLX and Third-party 
Infrastructure to Support Growth 
2017E Capital Includes 2-3 Drilling Rigs with ~130 Wells 
Commencing Production 
 2017 program delivers same lateral footage as 9 rigs in 2014 
Solid growth from advantaged position 
MBoe/d 
* Adjusted for divestitures ** Excludes NBLX estimated capital expenditures  
Upside Horizontal Upside Base Vertical 
2 
2016 
Average Rig Count 
2-3 
2017E 
5-6 
2020E 
~50 Wells on Avg. per Rig per Year
 NBL 
0
 50
 100
 150
 200
 0 50 100 150 200 250 300
 Days on Production 
Wells Ranch, East Pony and  
Mustang Per Well Production 
2014 2015 2016
 Technical Expertise Driving Evolution of DJ Basin Completion Designs 
32 
Enhanced completions increasing ultimate recovery 
2016 
Plug-&-Perf Completion,  
Monobore 
Slickwater Fracs: 1,000+ lbs/ft 
2015 
Openhole Completion 
Slickwater Fracs: 650-750 lbs/ft 
 
2014 
Openhole Completion 
Gel Fracs: 750-1000 lbs/ft 
Reflects Gross 3 Stream, Normalized to 9,500 
Enhanced Completion Designs Driving 
Improved Well Productivity  
 2016 well performance 15% above 2015 
Achieving Higher Ultimate Recoveries 
and Value through Controlled Flow-
 back 
Current Well Design Benefits 
 Enhanced near wellbore rock stimulation 
 Increased entry points through cluster 
spacing 
 Monobore and slickwater cost savings 
Testing Higher Proppant Upside 
 Up to 2,500+ lbs/ft proppant 
Cum. 
MBoe
 NBL 
DJ Basin Type Curves 
33 
Significant improvement in per well recovery 
Well economics based on 100% WI, 80% NRI. Well costs and economics fully burdened with upstream capital and midstream costs. 
*Other includes 14,000 lower tier East Pony acreage. 
  
3-Stream 
EUR 
(MBoe) 
Lateral 
Length (ft.) 
Commodity Mix % 
(Oil / NGL / Gas) 
Well Costs 
($MM) 
BTAX Rate of Return Gross 
Locations 
Net Acreage 
Base Upside 
Wells  Ranch 1,000 9,500 40 / 30 / 30 5.9 40% 60% 540 78,000 
East Pony 570 7,500 75 / 10 / 15 5.4 45% 70% 160  30,000* 
Mustang 975 9,500 40 / 30 / 30 6.2 30% 45% 910 75,000 
Bronco 900 7,500 20 / 30 / 50 5 15% 25% 640 36,000 
Greeley Crescent 900 9,500 30 / 30 / 40 5.9 20% 35% 510 32,500 
Other* 480 9,500 65 / 15 / 20 5.6 20% 35% 460 100,500 
Wells Ranch Type Curve Raised to 1 MMBoe for 9,500 ft Lateral 
Base Well Design Includes 1,400 lbs/ft Proppant and Slickwater 
Enhanced Completions Delivering Longer Plateau Production 
Approximately 75% of Locations Generate at Least a 10% BTAX 
Rate of Return at $40/Bbl or Below 
20% 
Wells Ranch East Pony Mustang 
EUR Increase per Lateral Foot  
from 2013 Analyst Day 
Near 
Term 
Focus 
15% 
20%
 NBL 
0
 25
 50
 75
 100
 125
 150
 0 25 50 75 100 125 150 175 200
 Days on Production 
Wells Ranch Type Curve 
2,500 lbs/ft Completions
 Current Type Curve (1,400 lbs/ft)
 2013 Type Curve (700 lbs/ft)
 DJ Basin: Wells Ranch Development Area 
34 
Cum.  
MBoe 
Creating more value in core IDP 
Increased Acreage Position to 78,000 Net 
Acres through Acreage Exchange 
 540 remaining locations 
Drilling Long Laterals in Less than 6 Days and 
Short Laterals in Less than 4 Days 
Advantaged Midstream Position with Noble 
Midstream Central Gathering Facility and 
Proximity to Grand Parkway 
Testing Higher Proppant Concentration 
Upside 
 Early performance of recent wells testing up to 
2,500 lbs/ft are experiencing higher initial rates 
Gross 3 Stream, Normalized to 9,500 ft 
NBL Acreage 
2,500 lbs/ft 
Wells
 NBL 
0
 50
 100
 150
 200
 250
 0 100 200 300
 Days on Production 
Mustang Type Curve 
Moser Wells
 Current Type Curve
 2013 Type Curve
 DJ Basin: Mustang IDP 
35 
75,000 Highly Contiguous Net Acres 
 910 remaining locations, over 90%  
long laterals 
 Predominately rural farm lands 
Extending Enhanced Completion Success 
Beyond Wells Ranch and East Pony 
 19 Moser wells materially outperforming 
type curve; 14 used enhanced completions 
Noble Midstream Gathering Facility 
Planned Operational by Year-end 2017 
 Applying learnings from prior facility design 
Full Development Mode in 2018 
 
 
Planning out the next development area 
Gross 3 Stream, Normalized to 9,500 ft 
Cum. 
MBoe 
Moser Wells 
NBL Acreage
 NBL 
0
 100
 200
 300
 400
 500
 600
 NBL A B C D E F G H I
 2016 Operator Average 24 Hour Test Rate per 1,000 Ft.  
Eagle Ford: 2017 Growth Driver for the USO Portfolio 
Highly Prolific Wells with Exceptional Economics 
Significant Cash Flow Generator 
Testing New Completion Designs on Large Upper 
Eagle Ford Inventory 
Potential Dropdown of Eagle Ford Infrastructure 
to NBLX 
36 
Unlocking new resource potential 
Boe/d per 
1,000 ft. 
Source: Well test rate analysis by KLR Group, report dated 10/20/16;  
Peers include EOG, SWFT, PVA, DBN, MRO, BHP, COP, PXD, EP   
Eagle Ford 
 35,000 net acres; 60% Liquids Mix 
 360 gross locations avg. 7,600 ft. 
lateral length 
 460 MMBoe net unrisked resources 
 100% WI 
L&E 
Gates 
Ranch 
Briscoe 
Ranch 
Dimmit  
Webb 
NBL Acreage
 NBL 
0
 25
 50
 75
 100
 2016** 2017E 2020E
 Eagle Ford Sales Volumes 
0
 100
 200
 300
 400
 500
 2016 2017E 2020E
 Eagle Ford Capital $MM 
Eagle Ford Outlook to 2020 
37 
Total Sales Volume 15% CAGR 2016-2020E 
Net Free Cash Flow* Positive Every Year in 
Base Plan 
Commencing Production on ~40 Wells in 2017 
2017E Capital Focused on Gates Ranch 
Solid production and cash flow contributions 
MBoe/d 
* See appendix for definition of this non-GAAP measure   ** Adjusted for divestitures 
0.3 
2016E 
Average Rig Count 
1 
2017E 
2 
2020E 
~30 Wells on Avg. per Rig per Year
 NBL 
Eagle Ford Type Curves 
38 
Highly productive wells providing reliable cash flow to the business 
Optimizing South Gates Ranch Value with Move to 750 foot Lateral Spacing 
 Type curve captures higher initial rates and accelerates payout to 1-2 years 
Remaining Lower Eagle Ford Type Curves up 60%* 
Base Well Design Includes 2,000 lbs/ft Proppant and Hybrid Gel 
Half of the Locations Generate at Least a 10% BTAX Rate of Return at $40/Bbl or Below 
 Potential for further improvement with high intensity completion applied to Upper Eagle Ford 
  
3 Stream 
EUR 
(MBoe) 
Lateral Length  
(ft.) 
Lateral Spacing 
(ft.) 
Commodity Mix % 
(Oil / NGL / Gas) 
Well Costs 
($MM) 
BTAX Rate of Return 
Gross 
Locations 
Base Upside 
South Gates Ranch 
Lower Eagle Ford 
3,500 7,000 750 12 / 44 / 44 9.0 95% 150% 22 
North Gates Ranch 
Lower Eagle Ford 
2,200 7,300 750 20 / 40 / 40 9.5 75% 135% 26 
Other Lower Eagle 
Ford 
1,200 7,900 400-600 39 / 34 / 27 9.5 35% 60% 83 
Upper Eagle Ford 1,000 7,600 600-750 30 / 37 / 33 9.5 15% 25% 229 
Well economics based on 100% WI, 75%-81% NRI. Well costs and economics fully burdened with upstream capital and midstream costs.  
 
* Compared to ROSE Merger, on a normalized basis  
Near 
Term 
Focus
 NBL 
Unlocking Upper Eagle Ford with Optimized Drilling and Completions 
39 
Significant opportunities within existing area 
Identified Several Keys to Success Based on 
2014 Pilot Learnings 
 Deeper landing zone, wider spacing 
Existing L&E Upper Eagle Ford Well 
Performance Consistent with Lower Eagle Ford 
3 Pilots Testing Enhanced Completions as well 
as Optimized Spacing and Landing 
 Briscoe Ranch Upper Eagle Ford tests online in 
Late 2016 
 L&E wells online in 1H2017 
 North Gates development pilot planned for 
2H2017  
Future Development  
600-750’ 
Upper EF 
Lower EF 
1
 8
 0
 -2
 7
 0
  Ft
 . 
7
 0
 -1
 2
 0
  F
 t.
  
L&E 
Gates 
Ranch 
Briscoe 
Ranch 
Dimmit  
Webb 
NBL Acreage
 NBL 
0.0
 0.5
 1.0
 1.5
 2.0
 2.5
 3.0
 3.5
 4.0
 0 100 200 300 400
 Days on Production 
Recent Majorsville Enhanced Completions  
Well Performance 
Enhanced Completions
 Current Type Curve
 2013 Type Curve
 Marcellus: Gas Optionality within the USO Portfolio 
40 
Core operated position in premier gas play 
Contiguous, Held By Production Acreage 
Supporting Long Lateral Development  
 High net revenue interest ~85% 
High-quality Retained Acreage with Both Liquids 
and Dry Gas Opportunities 
Future Development Advantaged with CONE 
Midstream (CNNX) Ownership 
Marcellus 
 363,000* net acres 
 1,900 gross locations avg. 
8,000 ft. lateral length 
 20 Tcfe net unrisked resource 
 100% WI 
* Reflects Marcellus acreage post JV separation 
NBL Acreage 
Cum.  
Bcfe 
PA 
WV 
Gross 3 Stream, Normalized to 8,000 ft
 NBL 
0
 100
 200
 300
 400
 500
 600
 Marcellus Sales Volumes 
0
 100
 200
 300
 400
 500
 2016 2017E 2020E
 Marcellus Capital $MM 
Marcellus Outlook to 2020 
41 
Total Sales Volumes Average between 420 – 450 MMcfe/d 
2016-2020E 
Net Free Cash Flow* Positive throughout Forecast  
Period 
Unit Operating Cash Flow Margin* Increases 2 – 3X 
2017 Estimated Capital Allocated to Bring Online 
Drilled Uncompleted Wells 
Substantial volume on minimal capital 
MMcfe/d 
0 
2016 
Average Operated Rig Count 
~20 Wells on Avg. per Rig per Year 
0 
2017E 
1 
2020E 
* See appendix for definition of this non-GAAP measure  
2016 
Reported 
 
2016   
   Adjusted for 
   JV Separation 
2017E 
 
 
2020E
 NBL 
Marcellus Type Curves 
42 
Prolific wells contributing steady cash flow to the USO business 
Well economics based on 100% WI, 85% NRI. Well costs and economics fully burdened with upstream capital and midstream costs.  
* Marcellus upside price assumes $0.50 Henry Hub increase **Utica stacked acreage not reflected in total acreage 
Enhanced Completions Significantly Improving EURs 
 Base well design includes 2,000 lbs/ft proppant and slickwater 
 Testing 3,000 lbs/ft proppant in 2017 
 Long laterals improving well economics 
Near Term Focus on DUCs and High Value Inventory within 
Majorsville, Moundsville and North Nineveh 
  
3 Stream 
EUR 
 (Bcfe) 
Lateral Length 
(ft.) 
Commodity Mix % 
(Oil / NGL / Gas) 
Well Costs 
($MM) 
BTAX Rate of Return Gross 
Locations 
Net Acreage 
Base Upside* 
Majorsville 17.5 8,000 5 / 20 / 75 8.0 40% 50% 80 33,000 
Moundsville 
Marcellus 
14 8,000 17 / 39 / 44 8.0 30% 40% 60 10,000 
North Nineveh 16 8,000 0 / 0 / 100 8.0 40% 55% 40 11,000 
West Virginia Wet 13 8,000 0 / 15 / 85 8.0 20% 30% 250 35,000 
Moundsville Utica 21 8,000 0 / 0 / 100 12.8 55% 75% 60 15,000** 
Other Marcellus 11-14 8,000 0 / 10 / 90 8.0 15% 25% 1400 274,000 
67% 
Majorsville 
EUR Increase per Lateral Foot  
from 2013 Analyst Day 
Near 
Term 
Focus
 NBL 
U.S. Onshore Update Summary 
43 
Enhancing confidence in long-term growth and value potential 
Robust and Focused Outcomes Through 2020 
 90% of USO capital focused on DJ Basin, Delaware and Eagle Ford 
 USO oil volume 23-29% CAGR 
High Quality, High Margin Assets with Running Room 
 Combined 7 BBoe net unrisked resources 
 Over 7,000 gross locations with average lateral length of 8,000 feet 
 BTAX rates of return of 30% to 95% at base pricing; material upside in higher price environment 
Demonstrating Technical and Operational Leadership in All Areas 
 Significantly raising type curves across all basins 
 Industry leading well results in every area
 NBL 
3 Key Takeaways From Today 
Robust Growth in Oil, Total Production, and Cash Flow 
 2016 – 2020E:  U.S. onshore oil grows at a 23 – 29% CAGR*   
   DJ and Delaware increase to between 240 MBoe/d (base plan) and 300 MBoe/d (upside) 
   Total company volume CAGR of 8 – 12%** 
   Total company operating cash flow outpaces total volume growth by 3 - 4X 
Near-Term Sanction at Leviathan: Extending Growth Trajectory 
 More than doubling EMED gross capacity by 2020 
 EMED cash margins competitive with U.S. unconventional oil basins 
Fully Funded Capital Program with Improving Balance Sheet and 
Corporate Returns 
 Leviathan initial investment funded with EMED portfolio management 
 Remaining capital and dividend funded by operating cash flows 
 Return on average capital employed*** increases to 8 – 14% in 2020E  
 
44 
It’s all about value-added growth 
* Ranges used throughout the presentation represent base to upside plan outcomes.  See base and upside plan pricing in appendix.   ** Adjusted for divestitures  *** See appendix for definition of this non-GAAP measure.
 NBL 
 Appendix 
45
 NBL 46 
Period Base Plan Upside Plan 
WTI, Brent 
($/Bbl) 
Henry Hub 
($/Mcf) 
WTI, Brent 
($/Bbl) 
Henry Hub 
($/Mcf) 
2017 $50 $3 $60 $3 
2018 $55 $3 $65 $3 
2019 $55 $3 $65 $3 
2020 $56 $3 $66 $3 
’17-’20 Avg $54 $3 $64 $3 
Price Deck Assumptions 
Note:  Ranges of production and cash flow throughout the presentation represent base 
to upside plan outcomes
 NBL 
Defined Terms 
47 
Defined Terms and Divestment Adjustments Term Definition 
Operating Cash Flow GAAP Net cash provided by operating activities 
Operating Cash Flow 
Margin 
(Revenue less lease operating expenses, production taxes, transportation, 
marketing, and processing) divided by sales volumes 
Net Free Cash Flow Operating cash flow less organic cash capital less dividend 
Net Debt Total debt less cash and cash equivalents 
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 
EBITDA Earnings before interest, taxes, depreciation and amortization 
 
Period Divestment Adjustments 
2016 Divestment 
Adjustment 
2016 FY estimated reported volumes (418) less Tamar announced (4.5) less 
Marcellus JV impact (8.5) less DJ-Greeley Crescent (2.5) less Other USO (2.5).    
418 – 18 = 400 MBoe/d 
Tamar Planned 
Divestiture 
2016 divestment adjustment less anticipated Tamar additional sell-down to 25% WI 
(9.5).  46 – 14 = 32 MBoe/d
 NBL 
Forward-Looking Statements and Other Matters 
48 
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,” “estimate,” 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 (“SEC”). 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. 
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”, “gross natural gas 
resources”, and “EUR” or “estimated ultimate recovery”. 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. 
This presentation also contains certain forward-looking non-GAAP financial measures, including return on average capital employed, net free cash flow, operating cash flow margin, 
EBITDA and net debt. Due to the forward-looking nature of the aforementioned non-GAAP financial measures, management cannot reliably or reasonably predict certain of the 
necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, we are unable 
to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Amounts 
excluded from these non-GAAP measures in future periods could be significant. Management believes the aforementioned non-GAAP financial measures 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.