whiplash: 2019’s changing fortunes - enercom dallas · 2019-02-27 · •infrastructure...
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Whiplash: 2019’s Changing Fortunes
Kathryn Downey Miller, CFAFebruary 28, 2019
BTU Analytics
BTU Analytics is a data-driven energy market analytics firm focused on providing clear and timely information to industry decision makers• Clientele is spread across private equity, producers, service companies,
power providers, midstream, traders, and marketers
Consulting capabilities include:• Natural gas, oil, and NGL market analysis• Infrastructure development analysis• Producer strategy advisory services
Products: • Upstream Outlook • E&P Positioning Report• Oil Market Outlook • Natural Gas Basis Outlook • Henry Hub Outlook Report• Production Scenario Analysis Tool 2
Volatility: 2019’s New Normal?
Source: BTU Analytics, Bloomberg.
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Entering Winter2018/2019 Today
WTI
$71
WTI
$55
WTI Midland
($12.85)
WTI Midland
$0.95
Waha
($3.60)
Waha
($0.55)
Henry
$4.60
Henry
$2.66
Key Takeaways
• Geopolitical risk returns – Venezuela, Iran, Saudi Arabia, Tweets all have potential to impact crude market’s precarious balance
• US production growth will be lumpy due to infrastructure timing. Historical pricing relationships will be change as today’s bottlenecks ease and new constraints emerge
• Permian Basin dominates US oil and gas production growth in 2019 and beyond, and new infrastructure timing will have significant pricing implications in 2019/2020
• Peak Appalachia is near, several producers have already grown to meet FT commitments on new projects and Appalachian gas is becoming the swing supplier of gas in the US market
• US natural gas demand growth gap approaching as LNG wave one crests in 2019
www.btuanalytics.com
Breakeven improvement stagnating, but prices do cover wellhead economics across all major basins
Source: BTU Analytics, Bloomberg. Available on Bloomberg terminals at BTUS <GO>.
$-
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
Jan-1
4
Jul-1
4
Jan-1
5
Jul-1
5
Jan-1
6
Jul-1
6
Jan-1
7
Jul-1
7
Jan-1
8
Jul-1
8
Jan-1
9
$/B
bl
WTI Price vs. Shale Play Wellhead Breakevens
Bakken Delaware Basin DJ Eastern Eagle Ford Midland Basin WTI
5
Global liquids market was long by over 1.5 MMb/d in 2H 2018, leading OPEC and partners to cut production by 1.2 MMb/d in 1H 2019. These cuts are necessary to balance global markets as shown by the oversupply once cuts expire in 2H 2019
-1.5
-1.0
-0.5
0.0
0.5
1.0
1.5
2.0
2.5
1Q 2014
3Q 2014
1Q 2015
3Q 2015
1Q 2016
3Q 2016
1Q 2017
3Q 2017
1Q 2018
3Q 2018
1Q 2019
3Q 2019
MM
b/d
Global Liquids Supply/Demand Balance
Source: BTU Analytics’ Oil Market Outlook (February 2019)
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US/Canadian incremental liquids growth in 2019 could meet all incremental global demand growth relative to December 2018, necessitating OPEC
production cuts or other supply disruptions for full year 2019
0.0
0.5
1.0
1.5
2.0
2.5
1Q 2019 2Q 2019 3Q 2019 4Q 2019
MM
b/d
Incremental Global Liquids Demand vs Incremental Liquids Production*
US/CN Other Demand
Implied oversupply without OPEC and
Russia production cuts
Note: Assumes status quo production from December 2018 i.e. no OPEC/Russia production cutsSource: BTU Analytics’ Oil Market Outlook (February 2019)
Should oil prices fall, US oil plays will be disproportionately impacted based on a combination of factors including breakevens, transportation costs, and
producer hedging portfolios
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
2018 2019 2020 2021
MM
b/d
Permian Oil
Base Case $60 WTI $50 WTI $40 WTI
0.00.20.40.60.81.01.21.41.6
2018 2019 2020 2021
MM
b/d
Bakken Oil
Base Case $60 WTI $50 WTI $40 WTI
0.00.51.01.52.02.53.03.5
2018 2019 2020 2021
MM
b/d
Eagle Ford Oil
Base Case $60 WTI $50 WTI $40 WTI
Note: Includes $7.50/bbl of cash leakage to cover corporate costs like SG&A and interest. Source: BTU Analytics’ Cash Flow Production Tool (July 2018) and BTU Analytics’ Upstream Outlook (August 2018)
A buildup of Permian DUCs should allow for accelerated growth once infrastructure arrives and soften the impact of drilling slow downs expected
throughout 2019
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1,000
2,000
3,000
4,000
5,000
6,000
7,000
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
# Ho
rizon
tal W
ells
Permian Wells Drilled vs Wells to Sale
DUCs & COBs Wells Drilled Wells Turned to Sale
Note: DUC = Drilled Uncompleted; COB = Completed on BacklogSource: BTU Analytics’ Upstream Outlook (January 2019)
Rapid development of debottlenecking projects and new pipelines will eliminate bottlenecks for Permian crude, significantly improving differentials with bottleneck risks
moving to downstream markets
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7.0
8.0
9.0
Jan-1
0
Jan-1
1
Jan-1
2
Jan-1
3
Jan-1
4
Jan-1
5
Jan-1
6
Jan-1
7
Jan-1
8
Jan-1
9
Jan-2
0
Jan-2
1
Jan-2
2
Jan-2
3
Jan-2
4
MM
b/d
Permian Oil vs Regional Demand and Pipelines
Existing Pipe + Refining EPD NGL Conversion & BridgeTex ExpansionCactus II EPICGray Oak Permian Gulf Coast PipelineWink to Webster Production Projection (No Constraints or Completion Delays)
Note: Pipeline capacities are based on current design capacities and does not include expansion capacity on EPIC, Gray Oak, PGC of ~935 Mb/d. Also does not include JupiterMLP’s proposed 1 MMb/d pipeline. Does not currently include potential inbound supply from MidcontinentSource: BTU Analytics’ Oil Market Outlook (February 2019)
Potential for consolidation
of projects
Proposed Liberty Pipeline or reversals from Cushing could add supply to basin boosting long haul
utilization to Gulf Coast.
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16.0
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20.0
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Jan-10Jan-11
Jan-12Jan-13
Jan-14Jan-15
Jan-16Jan-17
Jan-18Jan-19
Jan-20Jan-21
Jan-22Jan-23
Bcf/
d
Permian Dry Gas Production vs Takeaway
Local Demand Transwestern El PasoNNG NGPL Eastbound*Mexico ** Old Ocean & N TX Expansion ONEOK W TX ReversalGCX Permian Highway Whistler PipelinePermian Global Access Dry Gas Production sans Shut-ins/Flaring
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Plenty of Permian pipe has been proposed, and it will be needed to support long term development from the Permian. New projects will increase connectivity to Gulf Coast
demand and increase the Permian’s sphere of influence
Note: * Eastbound capacity is based on pipeline diameters and maximum daily flows. ** Mexico pipeline capacity is risked by timing of downstream pipeline bottlenecks in Mexico to connect inbound US supply to demand centers and based on expected outbound Permian flowsSource: BTU Analytics’ Upstream Outlook (January 2019)
Company Pipelines Capacity (Bcf/d)
Official ISD Estimated ISD FID
ONEOK ONEOK West Texas Reversal 0.45 N/A 1/2019 YesKinder/Targa/DCP Gulf Coast Express 1.92 10/2019 10/2019 YesKinder/EagleClaw Permian Highway (PHP) 2.00 3Q 2020 11/2020 Yes
Targa/NextEra/White Water/MPLX LP Whistler 2.00 4Q 2020 12/2020 No
Tellurian Permian Global Access Pipeline 2.00 4Q 2022 1/2023 No
Williams Blue Bonnet Pipeline 2.00 4Q2020 N/A No
Marcellus and Utica production growth, once dictated by infrastructure build-out, will move to become the marginal gas supply in the US and with production dictated by
macro supply and demand factors
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5
10
15
20
25
30
35
40
45
20142016
20182020
20222024
Bcf/
d
BTU Analytics Appalachia Production Forecast
NE Appalachia SW Appalachia Pipeline Takeaway Capacity
Source: BTU Analytics (updated 1/2019)
Pipeline ConstrainedUS Marginal Supply
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-10%
0%
10%
20%
30%
40%
50%
COG AR RRC EQT CNX SWN GPOR Average BasinGrowth
Average Production Growth YoY and Producer Guidance
15 - '16 16 - '17 17 - '18 High Case '18 - '19 Low Case '18 - '19
Appalachian producer guidance indicates a shift from rapid growth in previous years to significantly slower growth in 2019
Source: BTU Analytics’ Gas Basis Outlook, Bloomberg production data, investor materials (updated 2/2019)
Actual Production
Growth
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Significant inventory depletion of gas focused shale plays over the next decade will drive the marginal cost of gas production higher without
continued efficiency improvements
0
4,000
8,000
12,000
16,000
20,000
Appalachia SW Appalachia NE Haynesville Cotton Valley Fayetteville
Gas Focused Remaining Locations by Breakeven
Sub $2.00 $2.00-$3.00 $3.00-$4.00 $4.00-$5.00 Over $5.00 2019-2024 Drilling Forecast
Note: Assumes futures strip of 12/31/2018; 5-yr wellhead oil average of $50.14/BblSource: BTU Analytics’ E&P Positioning Report
Due to constraints, Permian associated gas has pressured adjacent basins, depressing prices, and forced supply to compete for limited demand in the
Upper Midwest. However, now new supply is converging on Northern Louisiana at Perryville
Source: BTU Analytics’ Gas Basis Outlook (updated 2/2019)
Appalachia
Growing SCOOP/STACK
OK
Limited Demand Market
Perryville
Permian
Appalachia
Displaced Rockies
W. CanadaPe
rmia
n
OK/Permian
Permian Permian
Growing Demand
With the start of Midship, MEP and Gulf Crossing will allow increased flows into Northern Louisiana
Source: BTU Analytics’ Gas Basis Outlook (updated 2/2019)
Tolar
Waha
Bennington
PerryvilleCarthage
Katy HSC
STX
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Midship capacity will help SCOOP and STACK producers, but congestion unlikely to be completely alleviated as volumes grow to fill capacity
Source: BTU Analytics, Genscape, Updated December 12, 2018
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0.8
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1.2
1.4
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Midship Capacity ONEOK Reversal Pipeline Bottlenecks Volume Growth in 2019 Spare Capacity
Bcf/
d
Oklahoma Capacity Changes in 20191.44 Bcf/d
0.45 Bcf/d
0.34 Bcf/d
0.3 Bcf/d
0.35 Bcf/d
More supply can get to Northern Louisiana, but a bottleneck is emerging in the middle of Louisiana
Source: BTU Analytics’ Gas Basis Outlook (updated 2/2019)
Tolar
Waha
Bennington
PerryvilleCarthage
Katy HSC
STX
Flows from Northern LA are creeping towards full utilization. Expansion projects could add up to 1 Bcf/d of additional corridor capacity, BTU assumes
expansions likely entered service in 4Q2018 or 1Q2019
-20%
0%
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40%
60%
80%
100%
-2.0
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Jan-1
5Ju
l-15
Jan-1
6Ju
l-16
Jan-1
7Ju
l-17
Jan-1
8Ju
l-18
Pipe
line
Uti
lizat
ion
Bcf/
d
North LA to South Flows versus Capacity
CGT ANR TGP
Trunkline TGT GulfSouth
Acadian Capacity Utilization
Note: Pipeline capacities based on maximum north or southbound observed flows and compressor station capacitiesSource: BTU Analytics, SONRIS, Data as of Dec. 31, 2018
The Gulf Coast will continue to play a larger role in the US demand mix, but ‘LNG Gap’ is ahead
0.0
30,000.0
60,000.0
90,000.0
120,000.0
0.0%
10.0%
20.0%
30.0%
40.0%
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
TX a
nd L
A %
of T
otal
US
Dem
and
Louisiana and Texas Demand
Other Industrial LNG Mexican Exports TX and LA % of US Demand
Source: BTU Analytics’ Henry Hub Outlook (January 2018)
Exports Drive Shift in US Demand Dynamics
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