Aug 3, 2016 - Record Company Sales Volumes of 427 MBoe/d. â« Record ... Offshore Major Project Start-Ups Contribute to
SECOND QUARTER 2016 SUPPLEMENTAL INFORMATION August 3, 2016
Energizing the World, Bettering People’s Lives ®
2Q16 Key Messages and Highlights Operational records and leading execution across the business Continuing to Drive Capital and Operating Efficiencies
Quarterly capital expenditures of $262 MM, significantly below low end of guidance
Reduced LOE on a BOE basis to $3.07, or 30% versus 2Q15
Record Company Sales Volumes of 427 MBoe/d
Record U.S. Onshore and 2Q Israel volumes
Every commodity above expectation
Enhanced Completions Driving 15% Pro-Forma U.S. Onshore Growth Versus 2Q15
3rd Noble operated Delaware completion the best well yet (more than 75% above type curve)
Eagle Ford wells, testing various lateral and cluster spacing designs, are outperforming type curves
DJ Basin and Marcellus continue to improve and outperform historical type curves
Offshore Major Project Start-Ups Contribute to 2H16 Capital Efficiency
Gunflint start-up represents 3rd GOM field to commence production in last 12 months
Alba compression project complete in West Africa
Outstanding Tamar Performance and Leviathan Moving Forward in Israel
Coal displacement strong contributor to 28% gas sales volume growth versus 2Q15
Leviathan progress realized across critical paths for sanction
Increased Full-Year Production Outlook With No Change in Capital 2
2Q16 Outperformance Versus Expectation Strong capital efficiency and cost control Financial and Operating Metric
2Q Guidance
2Q Actuals
Total Sales Volumes (MBoe/d)
405 - 415
427
Product Mix (Oil / NGL / Gas)
30% / 14% / 56%
29% / 15% / 56%
350 - 400
262
15 - 25
24
Lease Operating ($/Boe)
3.90 - 4.20
3.07
Transportation, Gathering ($/Boe)
2.90 - 3.10
2.97
16.00 - 16.50
15.99
Production Taxes (% Oil, NGL, Gas Revenues)
4.5 - 5.0
4.8
Marketing & Processing ($MM)
20 - 25
15
Exploration ($MM)
60 - 75
89*
100 - 110
107
75 - 85
78
Organic Capital ($MM) Equity Investment Income ($MM)
DD&A ($/Boe)
G&A ($MM) Interest, net ($MM)
*Includes $27 million related to expiration of Dolphin license (2011 discovery offshore Israel) 3
Active Portfolio Management Portfolio high-grading generating substantial cash flows $3.7 B of Cumulative Asset Monetizations $B 1.5 EMed, U.S. Onshore
U.S. Onshore, North Sea 1.0
0.5
0.0 2011
2012
Onshore
4
2013
2014
CONE MLP
Int'l
2015
Non-producing EMED assets
Established strong valuation marker for Tamar asset of $12.3 Billion, gross, with 3% working interest sale
$5.3 B of liquidity end of 2Q16
Creates deleveraging opportunity
Positioned for Additional Value-Creating Asset Monetization
Ecuador 2010
Accelerated value of long-dated DJ inventory
Focused Capital Allocation to Long-Term Core Assets
U.S. Onshore
U.S. Onshore
Ensuring Robust Liquidity and Supporting Balance Sheet
CONE MLP, U.S. Onshore, China
U.S. Onshore
Over $1 B of Divestment Proceeds Announced Year-to-Date
2016
Onshore midstream potential
EMED farm-downs
Delaware Basin: Third Noble Completion Best performing well ever drilled on NBL Permian position Outstanding NBL Operated CJ2101H Well Testing Slickwater and Higher Frac Intensity IP-30 of 2,541 Boe/d, more than 75% above type curve after 30 days
Soapy Smith and CJ2001H Outperformance Widening Versus Type Curve Accelerating Drilling and Completion Activity in 2H16; Drilling Program Includes Long Laterals Cum. MBoe
Soapy Smith 36 1H Calamity Jane 2001H Calamity Jane 2101H
NBL Acreage
Delaware Basin Well Performance Soapy Smith 36 1H
160
Completion Specifications
Calamity Jane 2001H
Soapy Smith
CJ 2001
CJ 2101
IP-30 (Boe/d)
728
1,599
2,541
80
Lateral Length (ft.)
2,790
4,109
4,859
40
Product Mix % (Oil / NGL / Gas)
68 / 16 / 16
49 / 26 / 25
57 / 22 / 21
Fluid
Slickwater
Hybrid Gel
Slickwater
Proppant (lbs./ft.)
1,800
1,700
3,000
Cluster Spacing (ft.)
60
60
40
Target Interval
Wolfcamp A
Wolfcamp A
Wolfcamp A
Calamity Jane 2101H
120
NBL 700 MBoe Type Curve
0 0
30
60
Days on Production 5
Note: Normalized to 5,000’ lateral and gross three-stream volumes.
90
Eagle Ford: Impressive Results Continue in Gates Ranch Increase in recovery from enhanced completions 32% Eagle Ford Volume Increase from 1Q16 Production History Supports Downspacing to at least 750’ from 1,000’ at South Gates Ranch (Row 4) Gates North Wells Tracking Above 3 MMBoe Type Curve, More Than 3X Planned Type Curve Continuous Drilling and Completion Program in 2H16 Cum. MBoe
Gates South 1,000’ Spaced Gates South 500’ Spaced Gates North
Gates Ranch Lower Eagle Ford Performance Gates South 1,000' Spaced
Completions Post Acquisition
400 Gates South 500' Spaced
Gates South 1000’ Wells
Gates South 500’ Wells
Gates North Wells
Well Count
8
8
2
Avg. IP-30 (Boe/d)
4,827
3,999
2,565
Avg. Lateral Length (ft.)
5,528
7,056
4,281
Product Mix % (Oil / NGL / Gas)
16 / 46 / 38
18 / 44 / 38
19 / 45 / 36
Proppant (lbs./ft.)
2,200
2,000
2,000
Cluster Spacing (ft.)
20
40
20
Target Interval
Lower EF
Lower EF
Lower EF
Gates North
300
NBL Gates South Type Curve (3 MMBoe EUR)
200 100
0 0
30
60
Days on Production 6 Note: Normalized to 5,000’ lateral and gross three-stream volumes.
90
DJ Basin: Enhancing Margins Standout quarter for DJ Basin capital and operating cost optimization Over 40% Reduction in Well Costs Since Early 2015
Including enhanced completion (1,000 lbs/ft), costs down 37%
Greater Than 50% of Cost Reductions Sustainable
2016 drilled lateral length average of 7,300’ up 18% from 2015 Nearly all monobore drilling in 2Q16 Fluid design changes and infrastructure optimization
Reduced Drilling Cost Per Total Foot to by Nearly 20% Versus 1Q16 and 35% Versus 2015 Focused Current Activity in Wells Ranch and East Pony
$MM 8.5
Wells Ranch Long Lateral Well Cost $8.2 $3.4MM Savings Breakdown: 62% Completion 25% Drilling 13% Facilities
7.5 6.5 5.5
$5.2
$4.8
4.5 3.5
1Q15
Structural
Cyclical
2Q16 Standard
Sand, Stages
2Q16 Enhanced
DJ Basin Drilling Cost Per Foot $/Total Ft. $160
$140
$120
$104 $85 $69
$80 $40 $0 2014
7
2015
1Q16
2Q16
DJ Basin: Enhanced Completions Optimizing well results with higher proppant concentration and slickwater Well Outperformance Versus Historical Type Curve by 35% in East Pony and 15% in Wells Ranch Enhanced completions include higher proppant (> 1,000 lbs/ft), slickwater and tighter clusters
Delivering Production Expectations Despite Fewer Equivalent First Gas Sales Than Original Plan Experiencing longer cycle times and cleanup periods with bigger jobs
Higher Percentage of Enhanced Completions Turned Online in 2H16
8
Note: Normalized to 4,500’ lateral; gross two-stream 2013 analyst day type curve converted to gross three-stream
Marcellus: Outstanding Well Performance Exceeding production goals with fewer completions Operated Rich Hill 23 Pad Produced 95 MMcf/d After 6 Months From 8 Wells
Average lateral length >10,000’
Cost advantaged with ability to produce into dry gas system without processing
Strong Non-Operated Pad Performance
GH53 pad with 9 wells on production has averaged 80 MMcf/d over the first 60 days
GH46 GH53
GH46 pad with 12 wells has averaged 117 MMcf/d over the first 90 days
4,000 3,000
80
2,000 40
1,000
0
0 0
30
60
90
Wellhead Gas Equiv. 9
RHL23
120
120
150
180
Avg. Casing Pressure
Average Casing Pressure (PSI)
Wellhead Gas (MMcfe/d)
RHL23 Pad Production Performance
2Q16 Ending Marcellus DUC Count of 79 Provides Options and Flexibility into 2017
Offshore Major Project Execution Gunflint and Alba compression contribute to 2H16 capital efficiency
GOM Gunflint Oil Development Commenced Production in Mid-July
10
Project capital below budget
Commenced Production in Mid-July from the Compression Platform at the Alba Field in Equatorial Guinea
Subsea tie-back to third party Gulfstar One facility
Enhances full field recovery; sustaining field production of approximately 200 MBoe/d, gross
Field ramping to minimum gross production of approximately 20 MBoe/d (5 MBoe/d net)
Project executed on time and on budget
Several technical firsts and accomplishments
Converted approximately 70 MMBoe from PUD to PDP
Israel: Robust Demand and Exceptional Performance Record 2Q sales volumes and cash flows 2Q16 Israel Natural Gas Sales Volumes of 276 MMcf/d, Net Represents nearly 30% growth over 2Q15
Coal Power Dispatch in Israel Down 22% versus 2Q15 More displacement expected in 2H16 as power producers comply with the Government’s mandate
Tamar Net Sales Volumes
MMcf/d 350
1.1 Bcf/d Gross Peak Capacity
300 250 200 150 1Q
MW 4,500
Average Coal Dispatch
4,000 3,500
% of 2015 100% 85%
(8%) (14%)
3,000
80% 70%
(22%)
(20%)
2,500
60% 50%
2,000
40%
1,500
30%
1,000
20%
500
10%
-
Q1
2015 11
90%
Q2
2016
Q3
Q4
Cumulative % of 2015 Coal
Source: Historical data from IEC; 3Q16 and 4Q16 coal dispatch based on NBL estimates
2Q 2014
3Q 2015
4Q
2016
Sale of 3% Tamar Working Interest Establishes $12.3 B Gross Valuation Remaining 7-8% working interest expected to be sold over 3-year Leviathan funding period
Significant Progress Toward Leviathan Sanction 100 MMcf/d contracted to domestic market POD approved Entered FEED
Israel: Leviathan Road Map to Sanction Momentum on critical project work streams continues
Initial Capacity: 1.2 Bcf/d
12
Strong 2H16 Operational Lineup Enhanced 2016 outlook and strong positioning for 2017 28 MBoe/d Volume Increase, DivestitureAdjusted, or 10 MMBoe, With No Change to Total Capital Accelerating Texas Program
MBoe/d 420
405 400 390 390
Exit with substantial momentum in Eagle Ford with several completions near year-end
380
Doubling of first oils in the Delaware Basin versus 1H16
360
2015 ProForma Divestitures
Original
Prior
Current
Full-Year 2016 Guidance
Incremental production history and new well results
Offshore Major Project Start-Ups Contribute to 2H16 Cash Flows
415
Continuous 2 rig drilling program for majority of 2H16
Progressing Enhanced Completions in the DJ Basin
2016 Full-Year Production
Expected lower capital going forward
3Q Seasonal Demand Peak in Israel Positioning For Significant Offshore Cost Savings With Leviathan Sanction
2016 Full-Year Capital
$MM 4,000 3,000
3,048
2,000
1,500