american association of drilling...
TRANSCRIPT
IMPORTANT DISCLOSURES BEGIN ON PAGE
Shale maturations impact on and continued evolution of
the oil and gas industry business models
American Association of Drilling Engineers
July 16, 2019
25
Matt Portillo
Managing Director
Starting in 2017, waning inventors interest combined with decade of subpar equity performance increasingly
ramped industry pressure to shift business models.
Growth, which had dominated the focus since 2005, now shifted to returns. Unfortunately, there is no
perfect model as achieving one comes at the expense of the other.
Initially most focused on improving return on capital metrics; however, if spending plans were left unchecked,
buyside clients felt as though industry would continue to ramp supply at the expense of achieving these
targets. Upstream investors are now looking for moderate growth rates of 5-10% with a heavy focus on free
cash flow generation.
Additional demands on upstream have now been put into place, including the need to
□ Moderate base declines
□ Accelerate timeframe in which FCF generation is achieved
□ Payout additional capital to investors in the form of a dividend, in particular large caps, which implicitly
forces additional constraints on capital allocation
□ Have a renewed focus on corporate overhead and controllable cost cuts as the industry transitions to a
lower growth business model
□ Ultimately return excess free cash flow in the form of buybacks as opposed to the traditional route of
accelerating the drill bit
This transition, which started in the large cap space, has now been forced upon the SMID cap universe, and in
turn, broken the private equity business model as producers that do look to sell must meet accretive metrics
on FCF, base decline, EV/EBITDA, etc., a sea change from the traditional drill-and-flip model.
Setting The Stage: E&Ps’ Evolving Strategic Mindsets
2
The Last Decade of Shale
□ Primary focus was resource capture and resource delineation
□ Upstream management teams focused on growth and had limited focus on financial implications of capital
allocation
□ Market dominated by equity issuance, lack of capital discipline, and low rate of return investments
The Next Decade of Shale
□ Maturation of shale will drive efficient and capital-disciplined resource development
□ Growth is now an output, as companies focus on free cash flow generation and improving corporate &
financial metrics
□ Core resource depletion and M&A to be primary focus for US over next 5 years
Maturation to Drive Seismic Shift Of the Upstream Business
3Source: TPH Capital Markets, TPH Research
FCF presented for 20 oil-focused US E&P operators
-$25,000
-$20,000
-$15,000
-$10,000
-$5,000
$0
$5,000
$10,000
$15,000
Fre
e C
ash
Flo
w,
$M
M
Free Cash Flow Inflection: A Must for InvestorsEquity Issuance Addiction: Capital Markets Have Closed
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
Cum
ula
tive E
quit
y Iss
uance,
Billions
TPH Forecast--
Previous Upstream Business Model Led to Extreme Base Declines
4
Above is an example of an upstream coverage name that acquired undeveloped acreage at a
robust price, materially accelerated the drill bit to justify the transaction, and has significantly
outspent cash flow since inception
As investor attention has shifted away from Net Asset Value (NAV) and towards more sustainable
business models, this has left a large number of US upstream companies in a tough position
High base declines and the current forward curve will not allow a portion of the US public
upstream space to grow within cash flow
Crude Oil Natural Gas
Year mbpd Decline mmcfd Decline
2018 55 (63%) 135 (45%)
2019 21 (35%) 75 (29%)
2020 13 (25%) 53 (22%)
2021 10 (20%) 41 (18%)
2022 8 (17%) 34 (15%)
2023 7 (14%) 29 (13%)
2024 6 (12%) 25 (11%)2025 5 (11%) 22 (10%)0
10
20
30
40
50
60
2013 2014 2015 2016 2017 2018 2019 2020 2021
E&
P #
1:
Perm
ian C
rude O
il
PD
P,m
bpd
Legacy 2015 2016 2017 2018
Source: IHS Enerdeq, TPH Research
The Real Economics of ShaleThe prices needed for US public operators to maintain production flat while staying within
cash flow
5Source: TPH Research
$20
$30
$40
$50
$60
$70
$80
CDEV QEP SRCI MTDR OAS JAG CRZO SM WPX PXD APA WLL DVN PE ECA CPE MRO CLR XEC EOG CXO PDCE FANG NBL
$/bbl
WT
I
2019 WTI Breakeven
2020 WTI Breakeven
'19/'20 Average
Prepare Today for the Wants of Tomorrow
6Source: TPH Research
• We see investors seeking leverage metrics in the <1x
range for large cap names, and <1.5x for SMID cap
coverage at $50/bbl WTI
• EOG, COP, and PXD screen the best of large cap
names on Net Debt / EBITDA in 2019, while OXY, NBL,
and APA all crest over 2x
• On the SMID cap side, BRY, PDCE, and SRCI come in
below 1.5x, while CHK and WLL will end 2019 at 3x+
• For Gas names, COG is the clear standout on the low
end, and CNX and AR screen high
• Some names need to be monitored closely as large
scale maturities combined with muted FCF outlook
could be a tipping point: AR, QEP, RRC, and SM
appear worst off
• While this analysis does not factor in dividend
commitments, for those operators paying meaningful
amounts (OXY, APA, NBL) it will play a role in their
ability to use FCF to decrease debt levels
0.0x 1.0x 2.0x 3.0x 4.0x 5.0x
OXYNBLAPADVNCLRMROCXO
FANGEOGCOPPXD
CHKWLLQEPOASSM
MTDRCPE
CRZOECA
CDEVPE
WPXXECJAGBRY
PDCESRCI
VNOM
RRCAR
CNXEQTSWN
GPORCOG
TPHe Net Debt / EBITDA YE 2019
TPH Deck (WTI/HHUB/BRENT)
2019: 54.28/2.58/62.03; 2020: 50.68/2.63/56.97; 2021+: 50.69/2.73/57.00
Shift In the Big Three Cost Curves On the HorizonCore inventory depletion to cause cost curve to shift higher while also causing meaningfully
slower growth without higher commodity prices
7Previously published in Sept 2018
Source: DrillingInfo, IHS Enerdeq, TPH Research
Legend
Eq. Well Density
0 - 1
2 - 3
4 - 5
6 - 8
9 - 13
Region 1
Region 2
Region 3
• We see 6-8 years of core inventory left
in the Williston (and Eagle Ford)
• > $60 WTI will be needed to accelerate
Tier-2 development with acceptable
returns
Permian: The Biggest Gains Are Behind Us
8Source: IHS Enerdeq
Data comprised of all producing Hz wells in Martin, Howard,
Glasscock, Midland, Upton, and Reagan
0
5
10
15
20
25
30
35
40
6 M
o.
Cum
ula
tive P
roducti
on P
er
Late
ral
Fo
ot,
bo
e/f
t
Well Productivity Average Well Productivity P90 P50 P10
Completion optimization drove improvements
in productivity, but recent data suggests
gains have slowed
Historically, larger players may have been able to
overlook smaller shale plays, however, the
Permian’s scale makes it difficult to ignore, given
the long-term growth impact it can have
corporately.
We see material cost synergies, especially on
overhead, available to consolidators, which adds
materially to accretion given sometime bloated
cost structures of smaller E&Ps, and working as
an offset to premiums offered for deals.
Consolidating operatorship will be an important
factor in terms of “controlling your destiny” as
companies look to become more transparent on
long-term plans, something we view as an
important factor in CVX’s recent deal.
While we expect majors and the largest E&Ps
(XOM, RDS, BP and OXY) to primarily look towards
the large-caps and a few mid-caps to gain scale
(PXD, CXO, NBL, PE, WPX and XEC), we expect
our SMID-cap universe to employ “self-help” by
pursuing mergers of equals to garner more
investor attention (CPE, CRZO, JAG, MTDR, PDCE,
QEP and SM).
Crowded Basins = Potential Synergies
9
Permian Status: Crowded
Turning to a slide from our recent XOM Permian deep-dive, we see the 1mmboepd 2024 prod goal achievable on current
acreage, however, once this is met we only see inventory lasting until 2030-31 timeframe.
We view this as a clear signal that the company needs M&A in order to maintain the Permian’s production profile. And just
to illustrate that need further, we estimate that XOM’s Permian production could have a ~45% PDP decline profile in 2030,
meaning that if the asset was left to decline, the company would lose over 400,000bpd or around 10% of corporate
production.
While slower activity is another alternative, we also view this as unlikely given XOM’s significant investment in other
verticals of the Permian such as in-basin infrastructure, long-haul takeaway and gulf coast refining and chemicals
expansions.
We also see several risks to our forecast that we outline in this slide, which would be alleviated by near-term M&A.
The Majors Need Inventory
10
0
1,000
2,000
3,000
0
100
200
300
400
YE Invento
ry
Well
s P
er
Year
S Eddy N Eddy Pecos Loving YE Inventory
0
500
1,000
1,500
2,000
0
50
100
150
200
250
YE Invento
ry
Well
s P
er
Year
Midland Martin Glasscock Reagan YE Inventory
TPHe Completion Cadence (10-12 years of inventory)
M&A Should Drive Behavioral Change on Capital AllocationIn general, the larger a company becomes, growth must be balanced with shareholder returns, and increased
focus on moderating declines, accelerating free cash flow, and increasing capital efficiency is required
11Source: TPH Research
0
5
10
15
20
25
30
35
40
CXO/RSPP CHK/WRD FANG/EGN ECA/NFX OXY/APC
Recent Peak Rigs Current Rigs Target Rigs
Growing Up Is Hard to Do
12
As E&P companies transition from old to new, we expect improved shareholder
engagement, index fund inflow, and enhanced interest in the E&P equity space
Excessive equity issuance
Endless acquisitions
Outspending cash flow
Low or negative return on
capital
No dividends, no buybacks
Maturation to new business
model
Limited equity issuance
Buybacks & Dividends
Self-financed growth
Industry consolidation
OldYou are Here
New
Crude Macro
2019 Outlook: WTI Averages Upper End Of $50-55/bbl
□ While prices have been extremely volatile year-to-date as robust supply cuts interplay with weakening demand, we
maintain our view that WTI averages around the upper end of our $50-55/bbl forecast originally set in January.
□ From the current spot price of ~$60/bbl, we see downside risk into Q4’19 as market moves towards oversupply with
dynamics worsening in 2020 absent further OPEC supply intervention.
2020 Outlook: WTI Could Fall Below $50/bbl
□ Hard to paint a constructive view on crude prices absent further supply disruptions or a huge pick up in global demand.
□ Our current forecast calls for non-OPEC liquids supply growth of 2.4mmbpd (U.S. 1.6-1.7mmbpd) y/y which comfortably
outpaces our demand growth forecast of 1.5mmbpd.
□ Given the U.S. is the swing factor, crude may have to move below $50/bbl WTI to cut upstream capex and slow U.S.
growth given most E&Ps have budgeted for $50-55/bbl WTI.
□ Our 2020 macro outlook remains similar to that of 2019: taking a conservative view is the most prudent course.
2019 Supply
□ Global volumes have undershot our expectations primarily driven by strong adherence to OPEC compliance (>100%) and a
significant reduction in Iran and Venezuela production (down ~900mbpd combined since Dec-18).
□ Brazil remains a big swing factor and could continue to underwhelm expectations with the next few quarters being
critical to global supply growth.
□ U.S. volumes continue to track in-line with TPH expectations, flat q/q in Q1, up ~800mbpd e/e in 2019.
2019 Demand
□ Concrete real time data is hard to come by, but demand seems to be the biggest culprit for downside risk in 2019.
□ The U.S. / China trade war and slowing global economies have impacted demand for crude and lighter liquids products.
□ We are lowering our 2019 growth forecast from 1.1mmbpd to 900mbpd (of which 400mbpd is made up of NGLs).
Key Takeaways
14
Demand: 900mbpd annualized growth, revised 200mbpd lower since our January 2019 update given soft start to the year with slower
manufacturing data, weaker emerging market growth, and negative trade war impacts
Supply Considerations:
□ Overall OPEC production remains ~flat through 2H’19 with Saudi Arabia potentially cutting production further to maintain market
balance, as some sources suggest, and Iraq and Nigeria being pushed to lower production closer to compliance levels
□ Russia: Few months of volatility given Druzhba pipeline contamination, but expect move to ~100% compliance as issues subside
□ United States: Expect production to grow ~800mbpd e/e or ~1.4mmbpd y/y crude & ~2.0mmbpd y/y total liquids
□ Canada: Government curtailments of 150mbpd expected to reduce to 95mbpd, with growth deferred to 2020
□ Brazil: Production expected to grow ~225mbpd e/e (growth has disappointed thus far in 2019 and production ramp on new
platforms remains a concern)
□ Price Outlook: 2019 forecast remains in-line with our expectations published in January of $50-55/bbl WTI
For prices to remain closer to today’s $60 level, we suspect the market is pricing in further global supply risk or material
pickup in demand in 2H’19
Hard to paint a constructive picture for 2020 given material gap in forecasted supply vs. demand additions
2019 Implied Market Balance
15
OECD Implied Market Balance vs 5-yr Norms: (Undersupplied) / Oversupplied
(2.0)
(1.0)
0.0
1.0
2.0
Sep-17 Dec-17 Mar-18 Jun-18 Sep-18 Dec-18 Mar-19 Jun-19 Sep-19 Dec-19
Imp
lied
Mark
et
Bala
nce v
s 5
-yr
Norm
s, m
mb
pd
Actuals TPHKey Growth Drivers:
US +1.6mmbpd e/e (~800mbpd crude)Brazil +225mbpd e/e
Implied Balance vs Norms Swinging From ~300mbpd Undersupplied In May
To ~370mbpd Oversupplied In Dec
Source: TPH Research, IEA
Not So Rosy 2020 Outlook
16Source: TPH Research, IEA
We forecast total supply growth of +2.4mmbpd and demand growth of +1.5mmbpd - a significant market
imbalance despite a robust demand forecast
□ U.S. growth alone can fulfill total demand requirements
Our supply forecast is primarily driven by the U.S., Norway, and Brazil, two of which are offshore production
driven (i.e. volumes are price agnostic)
Despite an extension of OPEC+ cuts into Q1’20, we remain uncertain as to whether deeper cuts are probable, given
significant volume reductions by Saudi Arabia, with countries like Iraq and Nigeria, for example, desiring volume
growth, and finally the return to full operations of the Druzhba pipeline allowing Russia to open the taps
Against that backdrop, the key balancing item is U.S. production growth
□ With most E&Ps disciplined in their capital spending, to drive further discipline and lower growth WTI prices
may need to fall <$50/bbl
-
200
400
600
800
1,000
1,200
1,400
1,600
1,800
United States Brazil Norway Canada Australia
Biggest 2020 Supply Growth Drivers (mbpd)
Combined supply growth
of ~2.4mmbpd or 1.6x
our 1.5mmbpd demand
forecast
2020 Supply 2020 Demand
17
Q1’19 Global Oil Demand Growth (y/y mbpd) TPHe 2019 Global Oil Demand Growth (y/y mbpd)
Downgrading 2019 Demand Outlook To Just +900mbpd
Source: TPH Research, IEA
Horrendous start to 2019. There weren’t many bright spots in the Q1’19 data, which showed global
demand rising just +309mbpd y/y, starkly behind the IEA’s +1.2mmbpd full-year demand estimate. For us,
the biggest red flag was the weak gasoline figure against a pretty easy comp in Q1’18.
But things should pick up for the rest of 2019. We reduce our 2019 growth estimate to +900mbpd from
+1.1mmbpd previously, which is still much better than the Q1’19 average. NGL demand should pick up due
to cracker start-ups later in the year. Diesel demand will increase given a much easier comp. And gasoline
will likely improve after the Q1’19 price spike has moderated.
400
250
50
200
150
250
100
0
200
400
600
800
1,000
NGLs NaphthaGasoline Jet Diesel Fuel oil Other
2019e g
lobal dem
and g
row
th b
y
pro
duct (m
bpd)
2019e:+900mbpd
-
Cutting 2019 demand growth outlook to +900mbpd due to lower contributions from gasoline and diesel
208
189
205
4253
152
248
0
200
400
600
800
1,000
NGLs NaphthaGasoline Jet Diesel Fuel oil Other
Q1'1
9 g
lobal dem
and g
row
th b
y
pro
duct (m
bpd)
YTD'19:+309mbpd
-Very weak gasoline demand growth in Q1'19 against a manageable comp
-
-
-
-
-
18
NGLs12%
Naphtha6%
Gasoline27%
Jet8%
Diesel29%
Fuel oil7%
Other11%
Despite making up just 12% of total global demand...
523
(101)
157
266
339
(219)
139
(300)
(200)
(100)
0
100
200
300
400
500
600
NGLs Naphtha Gasoline Jet Diesel Fuel oil Other
2018 g
lobal dem
and g
row
th b
y
pro
duct (y
/y,
mbpd)
...NGLs accounted for nearly half of global oil demand growth in 2018
NGLs Contributing Disproportionate Share To Global Demand
Growth
Source: TPH Research, IEA
Share Of Global Demand (%) Share Of Global Demand Growth (%)
NGLs more than pulling their weight on global demand. We continue to marvel at how much of global
“oil” demand isn’t really oil. Natural gas liquids (NGLs), which made up 12% of global oil demand in 2018,
accounted for a whopping 47% of global growth last year. This has negative implications for refiners, who
typically don’t benefit when ethane and propane demand/prices increase.
-10%
-8%
-6%
-4%
-2%
0%
2%
4%
6%
0
100
200
300
400
500
1Q19 2Q19 3Q19 4Q19
Q/Q
Ch
an
ge I
n C
overa
ge C
ap
ex (
%)
Q/Q
Pro
dcu
tion
Gro
wth
(m
bp
d)
Q/Q Production (Left Axis) Q/Q Capex (Right Axis)
0
100
200
300
400
1Q19 2Q19 3Q19 4Q19
U.S. Capex And Production Thoughts
Upstream Capex And Production Thoughts U.S. Crude Quarterly Supply Growth (mbpd)
U.S. Upstream Capex Trends U.S. NGL Quarterly Supply Growth (mbpd)
19Source: TPH Research, IEA
While we aren’t expecting a material change to 2019
spending programs, the 2020 outlook still has a wide range
of potential outcomes. If our current imbalance forecast is
accurate, oil prices will need to fall to force slower U.S.
supply growth absent an additional round of cuts to OPEC+
production.
For reference, our current upstream coverage models
forecast capex down 9% in ‘19 and down 3% in ‘20. Based
on operator conversations, $50 WTI is the breaking point
for additional spending cuts, with the vast majority of our
coverage going ex-growth by $45/bbl. From a sensitivity
perspective, our aggregate maintenance capex for oil
names would be $51B vs. modeled $61B in 2020.
(9%)
(3%)
(10%)
(8%)
(6%)
(4%)
(2%)
0%
2019 2020
TPH Upstream Coverage Expected Capex
If demand is the problem,
then we’ll have to see 2020
capex cuts
+1.4mmbpd y/y
+670mbpd y/y
Gas Macro
Gas prices expected to average <$2.50/mmbtu in 2020 as we see gas basins needing to go ex-growth for a
multi-year period
With the LNG air pocket poised to hit in 2021 and 2022, we expect pricing to remain depressed ($2.25-
$2.50), as associated gas growth is sufficient to meet incremental demand
2023-2024 pricing could snap back materially with upwards of 8bcfd of potential LNG adds
Annual snapshots
2019: We see supply and demand adds being roughly equal in 2019, however, the 2bcfd oversupply inherited from 2018 is expected to push
inventories back to the 5-year average by the end of injection season
2020: Market enters the year oversupplied on GCX ramp, but H1 weighted LNG adds pull market near balance by Q3; however Q4 PHP in-
service returns the market to oversupply
2021/2022: A lack of new LNG projects coming on materially reduces demand growth, with associated gas growth sufficient to meet
incremental demand until phase 2 of LNG in 2023; gas basins likely required to go ex-growth to maintain market balance
If We Had Just One Page on US Gas Macro
21
Exit 2018:
+2.0bcfd
Q1’19
+1.5bcfd
Q2’19
+2.0bcfd
Q3’19
Balanced
market
Q4’19
+2.0bcfd
Exit 2019:
+2.0bcfd
Q1’20
+2.0bcfd
Q2’20
+1.5bcfd
Q3’20
+0.5bcfd
Q4’20
+2.0bcfd
peak storage
3,673bcf-1% vs. 5-yr avg
peak storage
4,249bcf+14% vs. 5-yr avg
Over/under supply progression (seasonally adjusted):
2019
2020
FY’19
+1.1bcfd
FY’20
+1.6bcfd
Source: TPH Research
Supply
Associated gas growth steady at ~3bcfd
8.7bcfd avg gas supply growth in ’17/’18,
expected to moderate to an avg of ~4.5bcfd
’19-’22
Associated gas forecast to grow at ~3.0bcfd
from 2019-2022; by 2020 expected to be ~50%
of total gas growth
Gas directed growth expected to taper from an
avg of 6.2bcfd in ’17/’18 to annual avg of
2.2bcfd going forward at strip pricing; we see
pricing falling to price out gas directed growth
Supply growth projections (e/e):
□ 2019: 4.8bcfd
□ 2020: 4.4bcfd
□ 2021: 5.0bcfd
□ 2022: 4.7bcfd
It’s a supply problem
22
1.3
(1.7)
7.8
9.6
4.8 4.4 5.0 4.7
(4.0)
(2.0)
-
2.0
4.0
6.0
8.0
10.0
12.0
2014 2015 2016 2017 2018 2019 2020 2021
bcf
d
Associated Other
Supply growth by year (e/e)
2.9 2.0 0.4
10.7
4.1
5.3
2.6 2.5
(4.0)
(2.0)
0.0
2.0
4.0
6.0
8.0
10.0
12.0
2015 2016 2017 2018 2019 2020 2021 2022
bcf
d
Exports (LNG + Mex) Other
Demand growth by year (e/e)
(6.0)
(4.0)
(2.0)
-
2.0
4.0
6.0
8.0
10.0
2015 2016 2017 2018 2019 2020 2021 2022
bcf
d
annual s/d balance
rolling s/d balance
Supply/demand balance
Demand
Keeping up but losing (export) steam
7.4bcfd avg demand growth in ’18/’19
Above normal heating and cooling demand
boosted 2018, in addition to coal retirements
Since 2015 Mexican and LNG exports have
accounted for nearly 50% of demand growth
Export growth to remain strong through ’20 but
taper considerably in ’21/’22
Demand growth projections
□ 2019: 4.1bcfd
□ 2020: 5.3bcfd
□ 2021: 2.6bcfd
□ 2022: 2.5bcfd
Supply/demand balance
Bad and getting worse
Gas market has gotten progressively looser
since associated growth began to ramp in 2016
Since 2015, avg demand growth has been
~4bcfd, exports accounting for ~50%
With limited LNG growth in ’21/’22, balance is
expected to materially worsen
Market has been 2-3bcfd oversupplied since
H2’18 production ramp
With storage expected to fill in 2020, market
will be forced into balance in ’21/’22
Restoring balance likely means material price
weakness in order to generate incremental
demand and/or supply reductions
Source: TPH Research, IHS Markit, EIA, Bloomberg
Associated gas growth forecast to exceed demand growth
With just 0.6bcfd of annual LNG growth expected in 2021 and 2022, we forecast total
demand growth of ~2.5bcfd annually
Associated gas expected to grow 3.1bcfd in 2021 and 3.4bcfd in 2022, outpacing total
demand adds
Supply/demand imbalance puts the call on coal-to-gas switching and PDP declines in
gassy basins in order to balance the market; we estimate the imbalance to be 2.6bcfd in
2021 and 2.4bcfd in 2022, inclusive of the inherited 2bcfd oversupply exiting 2020
However, phase 2 of the LNG build-out could see nearly 5bcfd of incremental LNG adds in
2023 and 2.7bcfd in 2024
To maintain market balance in 2023, we estimate ~4bcfd of gas directed production
growth will be required, followed by an incremental 2-3bcfd on 2024
2021 & 2022: The LNG air pocket
23
LNG project backlog
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
2019 2020 2021 2022 2023 2024
LNG Mex. Exp. PowerIndustrial Fuel gas/loss Associated gas growthOther gas growth
0
2
4
6
8
10
12
Jan-1
7
Apr-
17
Jul-
17
Oct-
17
Jan-1
8
Apr-
18
Jul-
18
Oct-
18
Jan-1
9
Apr-
19
Jul-
19
Oct-
19
Jan-2
0
Apr-
20
Jul-
20
Oct-
20
Jan-2
1
Apr-
21
Jul-
21
Oct-
21
Jan-2
2
Apr-
22
Jul-
22
Oct-
22
US L
NG
Export
s, b
cfd
LNG Feedgas
TPHe LNG build up Associated gas growth vs. demand
2019 bcfd
Corpus 2 0.6
Elba 1-6 0.2
Cameron 1 0.6
Elba 7-10 0.1
Freeport 1 0.7
2019 total 2.2
2020
Cameron 2 0.6
Cameron 3 0.6
Freeport 2 0.7
Freeport 3 0.7
2020 total 2.5
2021
Corpus 3 0.6
2021 total 0.6
2022
Sabine 6 0.6
2022 total 0.6
2023
Calcasieu 1-9 1.4
Plaquemines 1-9 1.4
Driftwood 1 1.4
Corpus mid-scale 1 0.6
2023 total 4.9
2024
Golden Pass 1-2 1.4
Driftwood 2 0.7
Corpus mid-scale 2 0.6
2024 total 2.7
Projects with positive FID
Projects without FID
Source: TPH Research, Bloomberg
Investors continue to push for a moderation of growth in order to drive improvements
in other relevant financial metrics
The industry must show line of sight to FCF generation in a sustained low-price
commodity environment, a likely pressure point for capital allocation
Core inventory depletion is growing as a topic of interest, and in addition to a need for
additional scale, should drive industry consolidation
Over the next 7 years we expect >70% of production growth to come from the Permian;
however, US aggregate production growth should start to slow, trending towards
500mbopd/year in 2025
The wide-adoption of best-in-class completion optimization has driven significant
productivity gains over the last 5 years; however, recent trends have appeared to
plateau
The demand for full cycle returns, free cash flow generation, moderation of growth,
and cash distributions to shareholders has caused a shift in the private equity market
(~35% of total US onshore Hz rigs)
Last Ten Years Will Not Reflect the Next Ten For Shale
24
25
Analyst Certification
We, Matt Portillo and Jake Roberts, do hereby certify that, to the best of our knowledge, the views and opinions in this research report accurately reflect our personal views about the company and its securities. We have not nor will we receive direct or indirect compensation in return for expressing specific recommendations or viewpoints in this report.
Important Disclosures
The analysts above (or members of their household) do not own any securities mentioned in this report.
For detailed rating information, distribution of ratings, price charts and disclosures regarding compensation policy and investment banking revenue, please visit our website at www.TPHco.com/Disclosures or request a written copy of the disclosures by calling 713-333-2960 (United States).
Price Target Methodology
TPH research ratings and price targets are designed for those with a long-term investment horizon ("investor research"). From time to time, TPH may provide a recommendation with a short-term investment horizon ("trading research") which may lead to trading research containing different recommendations or ratings that could result in short-term price movements contrary to the recommendation in the firm’s investment research. Price targets are developed using the stock's forward price-to-earnings ratio as a primary valuation metric. Target prices are typically 20-25x forward price-to-earnings for oil service companies, with validation of this range is driven by examination of EBITDA multiples and price-to book value metrics. For North American E&P companies, we value proved reserves by assessing the net present value of current production. For probable and possible reserves, we attempt basin-by basins analysis of the reserves, with the key variable being the timing of drilling. Our risked 3P NAV consists of a bottom up cash flow model of the current reserves and resources with any appropriate risking as well as adding in a risk adjusted value for exploration prospects. Other businesses such as downstream or gas and power are generally valued on a DCF or multiple basis. We also adjust for items such as G&A, current net debt position and decommissioning liabilities where appropriate.OTHER DISCLOSURESTrade Name Tudor, Pickering, Holt & Co. is the global brand name for Tudor, Pickering, Holt & Co. Securities, Inc. (TPHS), Tudor Pickering Holt & Co Advisors, LP (TPHA), Tudor, Pickering, Holt & Co. Securities – Canada, ULC (TPHC), and Tudor, Pickering, Holt & Co. International, LLP (TPHI).Legal Entities Disclosures U.S.: TPHS is a member of FINRA and SIPC. Canada: TPHC is a member of IIROC and CIPF. U.K.: TPHI is authorised and regulated by the Financial Conduct Authority. Registered in England & Wales No. OC349535. Registered Office is 20 Grafton Street, London W1S 4DZ.Canada The information contained herein is not, and under no circumstances is to be construed as, a prospectus, an advertisement, a public offering, an offer to sell securities described herein, or solicitation of an offer to buy securities described herein, in Canada or any province or territory thereof. Any offer or sale of the securities described herein in Canada will be made only under an exemption from the requirements to file a prospectus with the relevant Canadian securities regulators and only in the relevant province or territory of Canada in which such offer or sale is made. The information contained herein is under no circumstances to be construed as investment advice in any province or territory of Canada and is not tailored to the needs of the recipient. To the extent that the information contained herein references securities of an issuer incorporated, formed or created under the laws of Canada or a province or territory of Canada, any trades in such securities must be conducted through a dealer registered in Canada. No securities commission or similar regulatory authority has reviewed or in any way passed judgment upon these materials, the information contained herein or the merits of the securities described herein and any representation to the contrary is an offense. In accordance with the Canadian AntiSpam Legislation, Tudor, Pickering, Holt & Co. Securities – Canada, ULC (“TPH Canada”) has implied consent from you as a member of the investment community with whom we have already established a relationship through business discussions or dealings, or your email address was made available to TPH Canada. However, if you are Canadian and wish to stop receiving ANY emails from TPH Canada (and its affiliated companies), please send an email to [email protected]. Please note that this does not apply if you are an existing client and IIROC or ASC rules and regulations require us to continue to send you critical email communications.
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RESEARCH
TRADING
SALES
Houston
Rusty D’Anna
713-333-2982
Mike Bradley
713-333-2968
John Hurd
713-333-2951
David Orr
713-333-3985
Houston - (800) 507-2400
Scott McGarvey
Seth Williams
New York - (800) 507-2400
Jason Barber
New York
James [email protected]
Harry Grist
212-610-1654
Oil Service
Byron Pope
713-333-7690
George O’Leary
713-333-2973
Taylor Zurcher
713-333-2974
Dhruv Kharbanda
713-333-3854
E&P - Canada
Aaron Swanson, CFA*
403-705-7827
Jordan McNiven, CFA*
403-705-7828
Matthew Murphy, CFA*
403-705-7842
Jenna Weir, CFA*
403-705-7843
Refiners / Chemicals
Matthew Blair, CFA
303-300-1916
Jillian Moss
713-333-3980
Katherine Webb
303-300-1919
E&P – USA
Matt Portillo
713-333-2995
Jeoffrey Lambujon
713-337-7549
Sameer Panjwani
713-333-2996
Jamaal Dardar
713-333-3926
Oliver Huang
713-333-3929
Jake Roberts
713-337-7544
Midstream
Colton Bean
713-333-2966
Matthew Taylor, CA, CFA*
403-705-7841
Crawford Kob
713-333-7685