Credit Suisse Global Energy Research Team
Markets to Force Production “Discipline” Deflating CS Oil Price Forecasts: New Lows, an Extended Trough, and Lower End-Points September 8, 2015 Research Team Jan Stuart
[email protected] (212) 325-1013
Johannes Van Der Tuin Johannes,
[email protected] (212) 325-4556
CREDIT SUISSE SECURITIES RESEARCH & ANALYTICS
BEYOND INFORMATION™ Client-Driven Solutions, Insights and Access
DISCLOSURE APPENDIX AT THE BACK OF THIS REPORT CONTAINS IMPORTANT DISCLOSURES, ANALYST CERTIFICATIONS, AND THE STATUS OF NON-US ANALYSTS.US Disclosure: Credit Suisse does and seeks to do business with companies covered in its research reports. As a result, investors should be aware that the Firm may have a conflict of interest that could affect the objectivity of this report. Investors should consider this report as only a single factor in making their investment decision.
Oil Prices: Extending the Trough, Deflating the Recovery Slow re-balancing, high inventories and Opec are deflating our price forecast “Ah the … old days of simply ringing up Riyadh and taking a few barrels off the market”. We are a full year into the new oil world. We thought the low was in in the first quarter. But market force can only work so fast. The not so fast short-reaction function on the supply side became the US upstream -specifically the disparate universe of shale producers. Apparently the invisible hand did not think these guys heard the message of the first quarter. And one fast, painful “market correction” later, the new 10-year price lows of July & August may do the trick. We think (fear), however, that this is not it yet, and the first part of our new forecast involves oil prices through the end of this year averaging a few ticks below the current strip …
We keep prices low through the m iddle of next year, which should keep US upstream activity contained (depressed) through 2016. Thus curtailed, global supply should fall below demand next year for sure, and probably already in the fourth quarter (which is seasonally normal). This is a more-constructive-than-consensus fundamentals view, of which we have more confidence, thanks mostly to a better read on US supply.
Only in the 2018-’19 tim e-fram e do we foresee oil prices rising above $65/ b WTI and $70/ b Brent, the lower end of the range in which big, multibillion dollar oil projects (e.g. core deep water) attract Final Investment Decisions. And longer run we think that still higher prices will be required to fill the then still relentlessly widening wedge between EM driven demand growth and decline rates.
Further out, through 2017 we keep prices below $65/ b WTI, the level from which oil production growth from America’s best shale basins would again accelerate to a pace that in short order would tilt the global balance into surplus.
We could be wrong, in a number of ways: It is remarkably easy to compile bearish scenarios for either the near- or the short-term. But perhaps surprisingly, it is only slightly less easy to do the same with bullish scenarios.
Brent
WTI
Quarter-average WTI oil prices through 2016 and annual averages for 2017-’19 as per our new forecast, plotted from Q2-2015 actuals and history back to the m iddle of last year, and contrasted with the old forecast and futures ($ per barrel)
Actuals & CS Forecast
Actuals & CS Forecast
$100 $90
new
old
Futures
Actual
$80 $70 $60 $50
$40
Source: Credit Suisse Research, Bloomberg
Period
Prior Forecast
Futures
Period
WTI - Brent Prior Forecast
Futures
Period
Actuals & CS Forecast
Prior Forecast
Futures
2011
$
110.91
2011
$
95.11
2011
$
(15.80)
2012
$
111.68
2012
$
94.15
2012
$
(17.53)
2013
$
108.70
2013
$
98.05
2013
$
(10.65)
Q1-2014
$
107.87
Q1-2014
$
98.56
Q1-2014
$
(9.31)
Q2-2014
$
109.76
Q2-2014
$
102.99
Q2-2014
$
(6.77)
Q3-2014
$
103.59
Q3-2014
$
97.34
Q3-2014
$
(6.25)
Q4-2014
$
76.82
Q4-2014
$
72.94
Q4-2014
$
(3.88)
2014
$
99.38
2014
$
92.89
2014
$
(6.49)
Q1-2015
$
55.13
Q1-2015
$
48.57
Q1-2015
$
(6.56)
Q2-2015
$
63.37
Q2-2015
$
57.84
Q2-2015
$
(5.53)
Q3-2015f
$
49.50
$
62.00
$
51.46
Q3-2015f
$
45.00
$
60.00
$
46.96
Q3-2015f
$
(4.50) $
(2.00) $
Q4-2015f
$
48.00
$
71.00
$
53.00
Q4-2015f
$
43.00
$
67.00
$
48.34
Q4-2015f
$
(5.00) $
(4.00) $
(4.66)
2015f
$
54.00
$
62.88
$
55.74
2015f
$
48.60
$
58.35
$
50.43
2015f
$
(5.40) $
(4.52) $
(5.31)
Q1-2016f
$
51.00
$
72.00
$
55.12
Q1-2016f
$
46.00
$
67.00
$
50.15
Q1-2016f
$
(5.00) $
(5.00) $
(4.97)
Q2-2016f
$
57.00
$
74.00
$
56.66
Q2-2016f
$
54.00
$
71.00
$
51.28
Q2-2016f
$
(3.00) $
(3.00) $
(5.38)
Q3-2016f
$
60.00
$
78.00
$
57.85
Q3-2016f
$
57.00
$
75.00
$
52.19
Q3-2016f
$
(3.00) $
(3.00) $
(5.66)
Q4-2016f
$
64.00
$
80.00
$
58.93
Q4-2016f
$
59.00
$
75.00
$
53.18
Q4-2016f
$
(5.00) $
(5.00) $
(5.75)
2016f
$
58.00
$
76.00
$
57.14
2016f
$
54.00
$
72.00
$
51.70
2016f
$
(4.00) $
(4.00) $
(5.44)
2017f
$
65.00
$
80.00
$
61.21
2017f
$
60.00
$
75.00
$
55.15
2017f
$
(5.00) $
(5.00) $
(6.06)
2018f
$
70.00
$
80.00
$
63.76
2018f
$
65.00
$
75.00
$
57.74
2018f
$
(5.00) $
(5.00) $
(6.02)
2019f
$
70.00
$
80.00
$
65.42
2019f
$
65.00
$
75.00
$
59.58
2019f
$
(5.00) $
(5.00) $
(5.84)
Long-Term $
75.00
$
85.00
Long-Term $
70.00
$
80.00
Long-Term $
(5.00) $
(5.00)
(4.50)
1
Lower Prices, a Bit Longer Too … but NOT For-Ever-More As no producers chose to cut in 1H, markets have begun to force the issue … 2015 mid-summer’s nightmare: Deflating oil markets, macro ‘turbulence’, rising inventories and softer physical markets for crude oil benchmarks … Brent prom pt futures contract: on its way to the $30s? ($/ b)
What happened:
$140
Both WTI and Brent benchmarks set new lows
$130
The back end of futures curve did as well, and even more so
$120
Drivers: One part fundamental …
$110
Greater supply from Opec and resilient growth from non-Opec outside the US, out-weighed stronger H1-2015 oil demand growth And softer summer markets intensified worries about demand prospects … One part financial
$100
$90 $80 $70
$60
Speculative-flows, including many new sellers, play(ed) a large role – This mid-year oil price collapse was not simply a ‘capitulation’
$50
Last Price
UBB (2)
$40
BollMA (200)
LBB (2)
A manifest reset of expectations is new, as are the LT- new lows
$30 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15
Prom pt prices (Brent, $/ b) are back where they started, but LT is not …
Near term tightening turned looser this sum m er Brent futures (1-6, $/ b)
$80 $75
Recent High 5/5/2015
Actual
Trough 1/13/2015
Current
$8
Backwardation: Bullish
$6 $4
$70
$2 $65
$0
$60
-$2
$55
-$4
$50
-$6
$45 Nov-14
-$8
May-15
Nov-15
May-16
Nov-16
May-17
Source: Credit Suisse Research, Bloomberg
Nov-17
2012 2014 2011
D
J
F
M
A
M
2013 2015
J
J
Contango: Bearish A
S
O
N
D
2
$40s to $50s Set Up a Rising Call on US Crude in H2-2016 How s/d fundamentals rebalance: Demand growth stays broadly healthy; US and and other non-Opec roll; and Opec adds mostly only from Iran Maintaining above trend Global oil dem and growth In our base case this sum m er’s China -centric and EM driven turbulence affecting equity, FX and rates m arkets does not derail the global econom y, or the strong recovery of global oil dem and
In our base case, however, we raise Iran’s production by nearly 800 kb/ d next year after the breakthrough nuclear deal with the P5+German is consummated before the end of the year.
Inventories stop to grow this quarter and decline in Q4
In our central scenario we extend the recovery of oil demand growth across the Developed market economies (read the US and much of the EU) – which continues to make most of the difference this year:
Since a large supply surplus has persisted through all of 2015 global inventories have risen to record highs – which should act as a cushion to limit the impact of bullish event on markets in the near term
Global oil demand growth in 2015 remains on track for +1.8% yoy;
Stock building should slow down this quarter, however, and next year is a clean up year in our base case, which features supply deficits of more than 500 kb/d on average. Put different, we project a significant nearly 2 Mb/d increase in the call on Opec, or more pertinently, a greater than 1 Mb/ d increase in the call on US crude
Next year it fades marginally to ~1.7% as OECD oil demand expands a little more, while oil use across EM contributes only modestly below trend Critically gasoline and other consumer oriented transportation fuel demand drives most growth in both North America and Asia
Non-Opec supply growth is deflating and turns negative in 2016 US oil production, begins to decline yoy next quarter, and does not turn positive again until Q4-2016, as finally real low prices choke off enough capital for long enough to reduce activity across all shale basins in H2 of this year and H1 of next, in our base case. Outside the US, non-Opec growth this year has proved more resilient than we expected, averaging 520 kb/d in H1. We expect that to decelerate and turn negative in 2016, growth decelerates most in Canada, Brazil and the North Sea, but should remain resilient in especially Russia.
From our global oil supply/ dem and balance, the call on US crude (kb/ d) 11,000
10,000
9,000
8,000
Opec’s growth extends next year as Iranian exports rise
7,000
Between them, Iraq and Saudi Arabia, surprisingly, captured much of the crude oil demand growth outside the US this year. But Iraq has only modestly more running room in 2016 and we suspect that Saudi Arabia can broadly maintain its relatively high exports but will not grow them
6,000 Jan-13
Source: Credit Suisse Research
Call on US crude oil forecast US crude prd
Jul-13
Jan-14
Jul-14
US Crude oil
Jan-15
Jul-15
Jan-16
Jul-16
3
From 2017, Higher Prices Are Required to Fill the Gaps Given declines, and assuming ongoing demand growth, the US alone cannot supply the entirety of the gap opening up between demand and supply In H2-2016 our price deck inflects to spur US shale growth
Clearly this sum m er our view went out of fashion
The NT governor: Timing is of course rather tentative, but clearly our global oil s/d balance in the base case requires higher production from the US in the back end of next year. We kept the deck for 2017 fairly low, however, since we learned last year that US shale can grow extremely fast and in our view too fast at WTI $65 or higher – if industry investments stay within cash flow.
To put it mildly, the debate on the long run required oil price has intensified. A seemingly growing number are embracing the notion that flagging demand growth, relentless progress across north America’s shale basins and somehow growing sovereign oil production can ever more easily make up for decline rates, which the industry is in any case becoming structurally ever more adept at mitigating – whatever that means.
The key signpost for greater growth requirements are international declines. We harp on the point of global decline rates , simply because the demonstrable fact remains that more than half the world’s oil production is in decline. These decline rates should sooner or later accelerate in a climate of under-investment, which is the norm in the middle of a the industry’s deflation. We keep a close eye on signs of decline, and need to see them in 2016 The m arket for long-dated Brent futures clearly shows that at the very least a debate has begun to rage about what is the replacem ent cost of supply later this decade -- here Brent contract for m onth 36 (CO36, $/ b)
Beyond 2017 we think more expensive oil will be needed While we fully understand the industry’s ability to adapt, we also reckon that challenges that have built up over two decades remain: that rising activity will re-inflate the cyclical part of cost reductions, that simplifying and executing big projects remains a massive challenge and that access to good rocks is key. We still believe that the world will need to invest in higher cost upstream developm ents (e.g. Deep Water) to m eet dem and from 2017 forward 3,000
$110
2,000 $100
1,000 $90
0
$80
(1,000) (2,000)
$70 $60
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Last Price
UBB (2)
BollMA (200)
LBB (2)
$50 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15
Source: Credit Suisse Research, Bloomberg
US OPEC Global Growth yoy
Non-OPEC ex-US Processing gains, yoy
4
End of Decade Balances Sport Great Risks on Both Sides Currently, downside price risk dominates the narrative of the medium term – for good reason. Upside risks, however, should not be ignored. Downside price risk – in the shorter term :
Upside price risk – in the shorter term
First and foremost: today’s “Turbulence” across major markets has been deflating assets of all kinds across both DM and EM, and could evidently prove to be a harbinger of a major economic downturn -- for a great deal of context, insight and foresight please look up today’s compendium publication from our Fixed Income Research.
Is probably the more difficult to imagine, also given the extreme size of surplus inventory in the system. That said, there is very little if any spare capacity on the supply side. Indeed we suspect that Saudi Arabia – the sole custodian of any real spare capacity – is for all intents and practical/commercial purposes – running its upstream system at 30-year high plateau rates that are unlikely to rise in the next two years, since only the next 250 kb/d phase of the Shaiba field is ‘in the works’ at present.
“Macro Risk” appear to involve mostly China centric concerns about the EM universe. And clearly, even though our house view remains that policy makers will broadly muddle through and steer global IP, trade and Aggregate Demand higher into the year end and through next year, we learned in 2008 and in 1998 that “Turbulence” in markets can quickly translate into a type of sclerosis of activity in the ‘real economy’ which in turn can drag down oil demand fast. So if China’s growth were to deflate, and other Asian economies become affected and policy errors pop up and, activity would slow and affect the roughly 900 kb/d of oil demand growth that this year is coming from EM Asia and the 700 kb/d we project for next year – Less demand growth pushes the inventory clean up to the right on a time scale and all else equal depresses oil prices longer and extends the period of upstream cost deflation, all else equal QE to QT Equally, from these perspectives, the US Fed could usher in QT later this month and amplify bearish risk to our base case – which involves the first interest rate increase arriving in December.
Longer run familiar risk Demand side: substitution and efficiency gains accelerate, with or without a technology breakthrough, involving a massive acceleration of adopting new power trains in trucks and cars Supply: real competition to grow supply between the US Shale and key sovereigns including Saudi Arabia, Iraq/Iran and later Venezuela, Libya et al.
An lengthy interruption in flow would in our view ‘trump’ inventories even now. Nor is such an interruption unthinkable in today’s North Africa or the Middle East On the demand side real oil consumption growth in the US appears to be accelerating, and such growth may even accelerate a bit cyclically across parts of Europe too, which could be compounded if the Turbulence across EM were to lift …Needless to say it is still easier to imagine that growth across EM would accelerate over the medium term
‘Call on US crude’ in our base case (Mb/ d)
yoy, Mb/d Demand Grow th Other Supply Opec Supply other non-Opec Call on US Crude Implied stock change
2015 +1.7 +1.6 +1.0 +0.6 +0.1 +0.7
2016 +1.6 -0.6 +1.0 -0.6 +1.2 -0.6
2017 +1.1 -0.1 +0.3 -0.1 +0.9 -0.7 5
Table of Contents PAGE
I.
Oil Supply
II.
Oil Demand
7
24
III. Oil Inventories
31
IV. Balances
38
V.
Oil Market Positioning
42
VI. NGLs and Natural Gas
45 6
Oil Supply: US, Other non-Opec and Sovereigns
A Slow Motion Response to a Lower “Call on US Crude”
The good news: US crude oil (and NGLs) supply began to fall in Q2
But markets will need time to become persuaded this is real. And while we are persuaded, it is still not at all clear what is the momentum or the next inflection point for US crude oil. These charts plot history and reflect our base case forecast. We drive our model, uniquely, by plugging $50/b WTI prices through the corporate models of the higher echelon producers in the key shale basins. And assuming they stay in cash-flow, then only 3 of 14 can grow output in 2016. Our base case assumes they set the tone for each basin in 2016. US crude would fall 200 kb/d in 2016, after growing 700 kb/d this year. US crude oil and NGLs production began to roll over (monthly, by type, kb/d)
Shale production too should track lower next year, before inflecting (fcst, kb/d)
13,000
13,000
11,000
11,000
9,000
9,000
7,000
7,000
5,000
5,000
3,000
3,000
1,000 Jan-09
Jan-10
Jan-11
Conventional
Jan-12
GoM
Jan-13
Shale Crude
Jan-14
Jan-15
1,000 Jan-11
6,000
5,000
5,000
4,000
4,000
3,000
3,000
2,000
2,000
1,000
1,000
Permian Midland
Jan-11
Jan-12
Permian Delaware
Jan-13
Nio brara
Jan-14
Gassy Plays
Source: CS Research, EIA
0 Jan-09
Jan-15
Eagle Ford
Bakken
Jan-14 GoM
Jan-15
Shale Crude
Jan-16 NGLs
All others should track down well into next year (kb/d)
6,000
Jan-10
Jan-13
Conventional
Within the shale universe, only the Permian is still growing (kb/d, to Sept)
0 Jan-09
Jan-12
NGLs
Jan-10
Permian Midland
Jan-11
Jan-12
Permian Delaware
Jan-13 Nio brara
Jan-14
Jan-15
Gassy Plays
Jan-16
Eagle Ford
Bakken
8
Assumptions and Why/How We Could Be Wrong Our old models said that production-growth should reduce at $70/b, we now model that >$65/b invites too much US growth to accommodate in 2016 or … Roughly put, our most recent work still says that $50/b WTI is not sustainable, aggregate US shale oil production would decline unless masses of outside capital continue to stream into the sector; at $55-60 WTI cash-flows allow for production to stabilize; and more than that should allow for net growth of crude oil and NGLs production. In a sense, today’s $65/b equals the 2014 $85-90/b range after cost reductions and efficiency/productivity gains. Thus, $65/b WTI would get too much growth in that in our central global s/d scenario it lead to over-supply next year and fits only well into 2017. Assumptions of the US supply forecast:
How we could be wrong – if history is a guide:
$50 WTI in 2016 is in line with our price deck, but not quite the $54 WTI 2016 average we now forecast. We expect, however, that prices will first track lower and inflect only later next year.
Still more capital flows into the sector, extending the era of it outspending cash flows. Such would effectively inflate production relative to our base case for significant segments of the E&P universe (especially the shale).
– Meanwhile, budgets and spending commitments and bank redeterminations of key debt and other factors are all digested in the next few months. Strategies and tactics are set up before the end of this year during which time the commodity is likely to stay broadly ‘depressed’
Drilling & completions outstrip even the expectations/guidance of the upper echelon firms we modeled
– So activity will likely calibrate to a $50 or lower spending environment Access to still more outside capital should be shut off for all but the good – And others should in fact have even less capital available to drill next year than in H2 of 2015 (or than levels commensurate with $50 cash flows), if indeed some loans get called and/or some credit is not rolled over, and of course if it takes time to resuscitate activity after bankruptcies. That said, we are effectively modeling the key oily shale basins (Permian, Eagle Ford, Niobrara and Bakken) as if the better-in-class do all the work
Source: Credit Suisse Research, EIA
How we could be wrong to the other side: The month-over-month decline trajectory reflected in the new EIA numbers released last week is not moderated and in fact starts to steepen as activity declines further in the second half and cannot pick up in H1 of next year A warm winter deflates gas markets and NGLs counts wither Conventional production declines accelerate Gulf of Mexico performance is poorer and its new facility startups come online late and/or under perform at least initially The rest of the E&P universe active in the shale basins, performs, in its aggregate, materially more poorly than the firms we built our forecast around
9
Signposts of US Oil Production Sure listen to earnings calls and analyst days about the near-term future of the industry. But aside from listening to the guidance of the E&P entities, the service sector which does all the work, and nowadays does gets much less, yields valuable reality checks about real future activity and its impact. And the US onshore service sector says it is in for a long and painful extension of an already long and painful ride down – link to Jim W’s note of today. Key data points we like watching include rig counts If we are correct then the horizontal rig count that targets oil should soon begin to fall all over again And even the small upturn in the Permian should resume its decline
The US drilling rig count has fallen by more than half 1200
Oil Rigs, Hz
1100 1000
In addition, states like North Dakota report on completions of oil producing wells and track well shut-ins – which helps explain btw that the June over May and the July over June upturn in the Bakken shale had more to do with mandated well completions than with a general resurgence of activity – and allows one to discover that given the number of completions the net new production was decidedly under-whelming
900 800 700
2011 2014
600
2012 2015
2013
500 400 300
D
The US drilling rig count has fallen by more than half 2,200
J
F
M
A
M
J
J
A
S
O
N
D
Horizontal oil rig counts, even the bump in the Permian should turn south 450
All Rigs
Horizontal Oil Rig Count
400
2,000
350
1,800
300
1,600
250
1,400
2011 2014
1,200
2012 2015
200
2013
150
100
1,000
Permian Eagle Ford
50
800
D
J
F
M
A
M
J
J
A
S
O
N
Source: CS Research, Baker Hughes rig count report
D
0 F-11
A-11
F-12
A-12
F-13
A-13
Bakken Other F-14
A-14
F-15
A-15
10
US Production Momentum – EIA Shale Productivity Report We like this tool. It is timely, internally consistent and gives a complete picture of all the key shale basins. We use it to forecast Q3-2015 trajectories. Shale production growth is fading
Because the rig count has plunged by half
The below chart clearly shows the acceleration of growth of US shale oil production in 2014
With fewer than 800 rigs drilling for oil in the four big plays in February new oil additions fell below legacy decline, for the first time in 5 yrs
Equally clearly, that growth has begun to roll
US oil supply is probably slipping mom
The data are imperfect but the idea is clear Changes of aggregate oil production from the Bakken, Eagle Ford, Niobrara and Permian shale basins (through April, Kb/d) 2000
mom 3ma (rhs)
Net ch an ge (yoy, 3mm a)
Decline of th e base (yoy)
New growth (yoy, 3mma)
1500
400
300
1000
500
Oil Rigs
Kb/d
1200
400
1000
300
800
200
600
100
400
200
500
100
0
-500 Jan-10
The monthly count of rigs drilling for oil in these plays set against: new well output, legacy decline, and the implied month-over-month delta of US shale oil supply (through June, Kb/d)
0
Jan-11
Jan-12
Jan-13
Jan-14
Source: Credit Suisse Research, EIA
Jan-15
-100 Jan-16
0 -100 Jan-10
200 Implied Growth (mom , rhs)
New Well Output
Legacy Decline
Rig C ount (rh s)
Jan-11
Jan-12
Jan-13
Jan-14
0 Jan-15
11
Outside the US: non-Opec Is Resilient but Not Impervious Simple charts to indicate what production is doing in key non-Opec areas Where is the growth? Where is it not? Who is in decline? Charts of oil supply (i.e. all liquids including NGLs and biofuels) by month through July 2015 US all oil (Mb/d)
Non-Opec total (Mb/d) 58
4
14
5
YoY, Mb/d (rhs)
YoY, Mb/d (rhs)
non Opec 56
3
54
13
4
US all oil
12
3
11
2
10
1
2
52
1
50
0
Jan-13
Jul-13
Jan-14
Jul-14
Jan-15
Russia (Mb/ d) 11.0
1.00
Russia
0.75
10.8
0.50
10.7
0.25
10.6
0.00
10.5
-0.25
Jan-13
0
Jan-13
Jul-13
Jan-14
Jul-14
Jan-15
Jul-15
Braz il (Mb/ d) YoY (Mb/d) (rhs)
10.9
9
Jul-15
Jul-13
Jan-14
Jul-14
Jan-15
Jul-15
3.1
3.0 YoY (Mb/d) (rhs)
3.0
2.5
Brazil
2.9
2.0
2.8
1.5
2.7
1.0
2.6
0.5
2.5
0.0
2.4
-0.5
Jan-13
Source: Credit Suisse Research, IEA, EIA, JODI, Country Data, WoodMac
Jul-13
Jan-14
Jul-14
Jan-15
Jul-15
12
Non Opec (cont’d) Simple charts to indicate what production is doing in key non-Opec categories Where is the growth? Where is it not? Who is in decline? Charts of oil supply (i.e. all liquids including NGLs and biofuels) by month through July 2015 China (Mb/d)
Canada (Mb/d) 4.75
2.0
4.4
0.75
YoY (Mb/d) (rhs)
YoY (Mb/d) (rhs)
Canada
4.50
1.5
4.25
China
4.3
0.50
1.0
4.00
0.5
3.75
0.0
3.50
-0.5
Jan-13
Jul-13
Jan-14
Jul-14
Jan-15
0.25
4.1
0.00
4.0
Jul-15
-0.25
Jan-13
North Sea (Mb/ d) 3.1
4.2
Jul-13
Jan-14
Jul-14
Jan-15
Jul-15
Mexico (Mb/ d) 2.0
3.0
1.5
2.9
2.9
1.0
2.8
0.25
2.8
0.5
2.7
0.00
2.7
0.0
2.6
-0.25
-0.5
2.5
YoY (Mb/d) (rhs) North Sea
3.0
2.6
Jan-13
Jul-13
Jan-14
Jul-14
Jan-15
Jul-15
0.75 YoY (Mb/d) (rhs) Mexico
0.50
-0.50
Jan-13
Source: Credit Suisse Research, IEA, EIA, JODI, Country Data, WoodMac
Jul-13
Jan-14
Jul-14
Jan-15
Jul-15
13
Signposts: Our “Declining Production Tracker” OPEC and Non-OPEC seasonally adjusted decline tracker (mom rhs, yoy lhs)
3 mma mom % change
4%
3 mma yoy % chane
2.0%
Non-OPEC seasonally adjusted decline tracker (mom rhs, yoy lhs)
3 mma mom % change
4%
3 mma yoy % chane
1.5%
1.5% 2%
1.0%
2%
1.0% 0.5%
0.5% 0%
0.0%
0%
0.0% -0.5%
-0.5% -2%
-1.0% J-10
J-11
J-12
J-13
J-14
3 mma mom % change
3 mma yoy % chane
J-12
J-13
J-14
J-15
4.0%
2%
2.0%
0%
0.0%
-2%
-2.0%
-4%
-4.0%
-6%
-1.0% J-11
Note: Includes Russia, Mexico, Kazakhstan, Brazil, Canada, Azerbaijan, Norway, Colombia, Indonesia, US GoM, UK, Egypt, Malaysia, Argentina, Thailand, Equitorial Guinea, Australia
OPEC seasonally adjusted decline tracker (mom rhs, yoy lhs)
4%
-2% J-10
J-15
2.0%
A look at production in those regions/countries most vulnerable to decline. We include this in our weekly “The Flowing Oil Chartbook”
-6.0% J-10
J-11
J-12
J-13
J-14
J-15
Note: Includes Angola, Nigeria, Algeria, Ecuador, Venezuela
Source: Credit Suisse Research
14
Opec the-Regulator-that-Left; Or, What’s Next? Here is what we wrote in January: “Oil exporters probably did not think markets would react this badly and seem to want an intervention. Indeed such pressure is building. Saudi Arabia has been very clear, however, that it wants markets “to go stabilize themselves”. And we think that the question [remains]: ‘What might persuade the Kingdom to sanction an Opec-led intervention’?” Note that we don’t have to change much to this phrasing … Put differently, until Saudi Arabia says ‘enough’, the noise about Opec acting is just that, noise. The question is political. When will the pressure from constituents in the kingdom or pressure from other producers sway the Saudi top, or can it? Financially, the kingdom remains in good shape: it built up reserves of about $750 billion through October of last year; its sovereign debt is still a measly 3% of GDP; and its younger generation of rulers has demonstrated that it can and will tap debt markets, who knows, might even un-peg the currency – Put different, while reserves have shrunk to ~$650 billion, according to tallies by Reuters and Bloomberg, the simple arithmetic of dividing that number by an estimate of the per-month burn-rate of reserves we think is an all but useless exercise for the next year or so Nonetheless, the current low-oil-price strategy hurts the Kingdom as well and comes back to the question: “What is the next phase in the Saudi oil strategy” Another gauge of support? The Saudi Tadawul All Share Index’s 52 weeks
Many Opec members are evidently not in Saudi Arabia’s fortunate financial position. Only Qatar, Kuwait, Angola and the UAE (in order) have by most estimates a lower budget break-even oil priced than does the Kingdom. At the other extreme, Iran appears to require the highest oil price, but stands to get an infusion of cash next year Questionable relevance in the shorter term of cost -curve type exercises when gauging changes in sovereign producer behavior : Ranges of Opec governm ent budget break -even-prices – for com pleteness’s sake ($/ b)
$180
Venezuela Iraq Nigeria Algeria
$160 $140 $120
SA
$100 $80 $60
$40
Mb/d $20 1
Source: Credit Suisse, Bloomberg
5
9
13
17
21
25
29
33
37 15
Opec: Surprises and Behavior of Key Members Simple charts to indicate what production is doing in key Opec categories Where is the growth? Where is it not? Who is in decline? Charts of total oil supply, by month through June 2015 Iraq has broadly grown exports in line with our high expectations
Libya has underperformed, we project a 2016 average of 400 kb/d YoY, Mb/d (rhs)
2.0
3
YoY, Mb/d (rhs)
4.5
Libya
3
Iraq
1.6
2
4.0
2
1.2
1
3.5
1
0.8
0
3.0
0
0.4
-1
2.5
-1
-2
2.0 Jan-10
0.0 Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Iran rem ains ham strung by sanctions in 2015, but we add 800 kb/ d in ‘16 YoY, Mb/d (rhs)
4.8
2
-2
Jan-11
Jan-12
Jan-13
Jan-15
Saudi Arabia surprisingly ratched up to its com m ercial m axim um YoY, Mb/d (rhs)
12.5
Iran
2.0
Saudi Arabia
4.4
12.0
1.5
11.5
1.0
11.0
0.5
10.5
0.0
10.0
-0.5
1
4.0
0
3.6
-1
3.2 Jan-10
Jan-14
-2
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Source: Credit Suisse Research, IEA, JODI, Country Data, WoodMac
9.5 Jan-10
-1.0
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
16
Moving Parts of Oil Supply in and from Saudi Arabia Exports from the kingdom fell in May and appear to have risen little if at all since then But for global markets to tighten these exports need to stay down, ideally decline – especially since the kingdom’s domestic refining is picking up Crude production (MMb/d)
Crude exports (MMb/d)
11
8.5 2009
10
8.0
2012
2010 2011
9
2012
7.5
2013
7.0
2014
2013
8
2014
6.5 2015
2015
7
6.0 dec
feb
apr
jun
aug
oct
dec
dec
Crude direct burn (kb/d)
feb
apr
jun
aug
oct
dec
Crude refiner intake (MMb/d)
1000 2009 2012 2013 2014 2015
900
2.50 2.25
800 700
2011
2.00
600
2013
500
1.75
400
1.50
300 200
2014
1.25
2015
100
1.00
0
jan
feb
mar
apr
may
jun
jul
aug
sep
oct
nov
dec
Source: Credit Suisse Research, Thomson Reuters and JODI
dec
feb
apr
jun
aug
oct
dec
17
Iran Post Sanctions Goes to the Status Quo Ante In our view, structurally changing that status quo, to drive oil production meaningfully higher than old averages will take time and is not likely before 2020 Sanctions relief remains on track. Our base case includes crude oil production rising, quickly, to pre-sanction averages of 3.8 Mb/d We add + 400 kb/d of crude oil production to the 2015 average of 2.9 Mb/d in January 2016 and another 400 kb/d in April – Now that the US administration has the critical minority of the Senate on side, the next hurdle is likely to be the putting in place of the inspection regime – which the EIEA can in principle sign off on in mid December at its next scheduled meeting on this issue – And this sign off is the catalyst, we think, for Iran effectively ramping up its oil sales Also critical is our assumption – for lack of real intelligence to the contrary – that NIOC can actually ramp up its oil production within six months by 800 kb/d Though many like to cite ‘experts’ cautioning about loss of capacity we rather expect that Iran’s industry is more capable than many presume
In 2017 and beyond NIOC and its foreign partners should be able to resuscitate the pace of expansion of gas and condensate production from the super giant South Pars reservoir it ‘shares’ with Qatar Beyond next year, we plot fairly mundane declines on crude oil production from what are on balance ageing set of resources To some degree those declines are balanced by rising condensate flows from South Pars
We could be wrong, of course There remains a risk (fast diminishing) that the nuclear deal cut with the P5 + Germany falls apart or is broken up. – ‘Hardliners’ in Washington and Tehran and Tel Aviv remain desperately unhappy with the prospects of a rapprochement between the US and Iran and may prove more resourceful than we assume – Should the deal be stranded, Iran’s oil exports would still rise, we think, as the sanctions regimes international partners would likely go their own way. But exports would rise less smoothly and perhaps to a lower plateau Or, Iran’s oil minister proves correct and he can attract masses of foreign interest in developing the country’s huge reserves much faster
Nor is all this only ‘bearish’ We think that oil markets wrongly only look at the downside of the Iran deal Greater international interactions with a developed economy of some 80 million well educated citizens enriched by the prospect of instantly higher revenue and a $100 billion cash injection cannot but ramp up activity Its 1.8 Mb/d oil economy has not grown fast in the last few years, but should grow meaningfully faster in the next few – Its gasoline imports, for instance, were tracking well north of 200 kb/d before sanctions, should rise fast from the current ~40 kb/d pace
18
Iraq’s Export Trajectory Remains Wobbly Production potential but many, many ‘above ground’ issues to resolve In fact, we remain surprised at how little disruption risk markets seem to see Stability: after a change of government in Baghdad any improvement toward greater stability and security can, generously, at best be characterized as ‘tenuous’ –
Baghdad has less money and faces a growing list of ‘demands’ on that revenue
–
Already it cannot sustain the compact made with the KRG, which in recent months has had to resort to selling its oil independently – which is once again leading to the odd interruption of exports from the north
–
Baghdad’s struggle with IS/Daesh is proving very difficult. It has not regained much ground lost, and this year continues to lose new ground.
–
Nor has the government made much headway in re-negotiating its all-important joint-venture contracts that govern the expansion of oil production and exports from the southern fields, beyond the recently completed expansion to roughly 3.5 Mb/d of capacity
We have penciled in only modestly growing oil production next year and indicate a very shallow decline for 2017 that hinges on whether or not the JVs can ramp up their development efforts significantly, soon. The “hopeful” production potential of “yester-year”. Note: the companies have since lowered plateau commitments and renegotiated fees. We include this table merely to illustrate that Iraq is a large source of low cost production
Iraq production volumes (including Kurdistan), 4.5
4 YoY, Mb/d (rhs)
4.0
3
Iraq
3.5
2
3.0
1
2.5
0
2.0 Jan-10
-1 Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
Field Rumaila West Qurna-1 Zubair Majnoon Halfaya Qayara West Qurna-2 Badra Gharaf Najma
Jan-16
Total, MBD
Source: Credit Suisse, Petro-logistics
Fee Plateau Partners ($/bbl) commitment BP/CNPC 2 2850 Qurna-1 1.9 2325 Eni/Oxy 2 1125 Shell/Petronas 1.39 1800 CNPC/Petronas 1.4 535 Sonangol 5 120 Lukoil/Statoil 1.15 1800 Gazprom/TPAO 5.5 170 Petronas/Japex 1.49 230 Sonangol 6 110 11065
19
A Reminder: Observed Declines on Declining Fields Average yoy decline rates across the declining fields of different countries (from 2003-’13)
Source: Credit Suisse Research, Woodmac
20
Global Oil Supply Decomposed (Levels) Curtailing non-Opec production after a record 2014 surge, for a low in 2016 Most of the 2015 deceleration comes in the US, though growth elsewhere reduces some as well. Non-Opec turns down for real next year Supply of all liquids by region and key economy (kb/d) Oil Supply in kbd
1Q14
2Q14
3Q14
4Q14
2014
1Q15
2Q15
3Q15E
4Q15E
2015E
1Q16
2Q16E
3Q16E
4Q16E
2016E
2017E
Global Oil
92,100
92,430
92,900
94,290
92,940
94,560
95,540
95,010
95,110
95,060
94,930
95,330
95,220
96,080
95,390
96,360
Opec all oil
36,450
36,340
36,650
36,620
36,510
36,580
37,800
37,800
37,690
37,470
38,080
38,530
38,540
38,570
38,430
38,710
Non Opec
53,600
53,860
54,150
55,600
54,310
55,900
55,470
55,080
55,330
55,440
54,740
54,500
54,500
55,380
54,780
55,470
Non Opec EX us
41,770
41,280
41,190
42,190
41,610
42,390
41,710
41,600
42,170
41,970
41,950
41,670
41,360
41,820
41,700
41,250
North Am erica
19,510
20,130
20,450
21,070
20,290
21,230
21,000
20,890
20,750
20,960
20,390
20,090
20,450
20,880
20,450
21,510
US Canada Mexico South Am erica Venezuela Brazil Argentina Columbia
11,830 4,310 2,860 8,160 2,700 2,630 640 1,000
12,580 4,160 2,830 8,190 2,660 2,720 620 970
12,960 4,210 2,760 8,330 2,610 2,890 630 990
13,410 4,440 2,710 8,530 2,660 3,010 630 1,010
12,700 4,280 2,790 8,300 2,660 2,810 630 990
13,510 4,560 2,650 8,580 2,690 3,030 630 1,030
13,760 4,120 2,540 8,510 2,710 2,970 630 1,020
13,480 4,300 2,580 8,440 2,610 3,020 620 990
13,150 4,540 2,530 8,460 2,620 3,030 630 1,000
13,470 4,380 2,580 8,500 2,660 3,010 630 1,010
12,790 4,580 2,490 8,450 2,610 3,020 630 1,010
12,830 4,290 2,400 8,540 2,620 3,090 630 1,000
13,140 4,340 2,430 8,440 2,540 3,100 620 980
13,560 4,400 2,380 8,510 2,530 3,160 620 990
13,080 4,400 2,420 8,480 2,570 3,090 630 990
14,220 4,450 2,270 8,390 2,620 3,070 660 890
4,330
4,170
4,080
4,360
4,230
4,360
4,450
4,140
4,390
4,340
4,200
4,310
4,020
4,260
4,200
3,870
1,900 940
1,780 860
1,870 680
1,940 860
1,870 840
1,940 890
1,920 970
1,840 770
1,990 840
1,920 870
1,840 820
1,830 890
1,750 710
1,890 780
1,830 800
1,620 740
14,150
14,030
13,970
14,100
14,060
14,290
14,260
14,230
14,300
14,270
14,400
14,370
14,310
14,460
14,380
14,550
10,830
10,790
10,700
10,860
10,790
10,950
10,970
10,990
11,040
10,990
11,080
11,110
11,130
11,180
11,120
11,240
1,780 890
1,710 880
1,750 870
1,800 790
1,760 860
1,800 870
1,750 840
1,730 820
1,800 770
1,770 830
1,790 850
1,730 830
1,710 790
1,790 820
1,750 820
1,840 770
28,800
28,790
28,710
28,660
28,740
28,800
30,000
30,060
29,870
29,680
30,320
30,780
30,850
30,850
30,700
30,740
11,510
11,490
11,660
11,350
11,500
11,400
12,080
12,250
12,250
12,000
12,150
12,120
12,120
12,060
12,110
12,210
Iran
3,720
3,640
3,460
3,580
3,600
3,510
3,680
3,600
3,590
3,590
4,150
4,550
4,550
4,550
4,450
4,400
UAE
3,620
3,700
3,790
3,720
3,710
3,740
3,800
3,790
3,770
3,780
3,740
3,810
3,810
3,870
3,810
3,780
Kuw ait Iraq Qatar
3,170 3,230 2,020
3,100 3,330 1,980
3,110 3,190 1,980
3,100 3,490 1,920
3,120 3,310 1,980
3,200 3,500 1,940
3,060 4,020 1,920
2,990 4,120 1,910
3,010 3,950 1,940
3,060 3,900 1,930
3,080 3,950 1,910
3,030 4,000 1,900
2,980 4,150 1,900
3,020 4,150 1,900
3,030 4,060 1,900
3,110 3,960 1,930
Europe Norw ay United Kingdom FSU Russia Kazakhstan Azerbaijan Middle East Saudi Arabia
Africa
8,260
8,220
8,620
8,590
8,420
8,360
8,300
8,180
8,260
8,270
8,190
8,190
8,150
8,190
8,180
8,490
Nigeria
2,370
2,420
2,350
2,330
2,370
2,350
2,300
2,320
2,340
2,330
2,300
2,300
2,300
2,300
2,300
2,300
Algeria
1,500
1,540
1,560
1,490
1,520
1,520
1,460
1,440
1,440
1,460
1,410
1,390
1,380
1,370
1,390
1,340
410
260
620
640
480
360
410
380
390
380
390
390
390
390
390
810
1,660
1,650
1,760
1,770
1,710
1,820
1,830
1,840
1,840
1,830
1,840
1,870
1,880
1,880
1,870
1,730
Libya Angola Sudan Asia Indonesia China India
260
280
270
260
270
270
260
260
260
260
260
260
260
260
260
250
8,890
8,910
8,740
8,990
8,880
8,940
9,030
9,070
9,080
9,030
8,990
9,060
9,000
8,930
8,990
8,800
840
840
840
820
840
810
840
900
940
870
940
960
960
960
960
900
4,210
4,220
4,150
4,310
4,220
4,250
4,340
4,310
4,330
4,310
4,270
4,290
4,290
4,280
4,280
4,250
890
880
860
890
880
890
860
870
860
870
870
860
850
840
850
820
Source: IEA, JODI, Country Data, BP Statistical Review of World Energy 2014, Petrologistics, Credit Suisse Research
21
Global Oil Supply Decomposed (Changes, yoy) Y-o-Y Grow th by quarter ('000 b/d) Global Oil Opec all oil
36,510
-210
-710
-250
570
130
1,460
1,150
1,070
1,500
730
750
890
-795
-155
Non Opec
54,310
1,840
2,200
2,030
2,250
2,290
1,610
930
-280
-1,160
-970
-570
50
1,335
2,090
Non Opec ex US
41,610
440
430
300
420
620
430
410
-20
-440
-40
-240
-360
135
400
North Am erica
20,290
1,610
2,140
1,810
1,930
1,720
870
440
-320
-840
-900
-440
130
1,435
US Canada Mexico South Am erica Venezuela Brazil Columbia Argentina
12,700 4,280 2,790 8,300 2,660 2,810 990 630
1,400 260 -50 220 20 160 -10 0
1,770 400 -40 180 -40 210 -40 -10
1,740 180 -120 210 -90 330 -30 -10
1,830 270 -170 400 -10 360 0 -10
1,670 250 -210 430 -10 410 30 -10
1,180 -30 -290 320 50 250 50 10
520 90 -170 110 10 130 0 0
-250 110 -180 -70 -40 20 0 0
-710 20 -150 -140 -90 -10 -20 0
-930 170 -150 20 -90 120 -20 0
-340 40 -150 0 -80 70 -10 0
410 -140 -150 50 -80 130 -20 0
1,200 260 -30 55 -30 0 65 -20
Europe
4,230
70
-50
0
110
30
290
60
40
-160
-140
-120
-130
1,870 840
70 30
-30 -10
80 -70
90 0
40 -50
140 100
-30 90
40 -20
-90 -70
-90 -80
-90 -60
-100 -70
Norw ay United Kingdom FSU
1Q14 1,640
2Q14 1,500
3Q14 1,790
4Q14 2,830
Y-o-Y Grow th
2014 92,940
1Q15 2,460
2Q15 3,110
3Q15E 2,110
4Q15E 830
1Q16 370
2Q16E -210
3Q16E 210
4Q16E 970
2013 570
2014 1,945
2015E 2,120
2016E 335
2017E 965
955
965
275
1,130
-660
690
360
-265
-450
1,875
670
-510
1,060
1,690 280 -95 255 -30 270 -20 -5
775 100 -215 195 5 200 20 0
-390 25 -150 -15 -85 80 -15 -5
1,140 50 -150 -95 50 -20 -100 30
-150
35
105
-140
-325
-100 -75
50 -15
50 30
-95 -70
-210 -60
14,060
70
-20
-40
-120
140
230
260
200
110
110
80
160
245
-25
205
115
165
Russia
10,790
60
20
-50
0
120
170
300
190
140
140
130
140
150
10
195
135
120
Kazakhstan Azerbaijan
1,760 860
-40 0
-20 -30
0 0
-30 -70
20 -20
40 -40
-20 -50
0 -10
-20 -30
-10 -10
-10 -30
-20 40
60 10
-20 -25
10 -30
-15 -5
90 -50
Middle East
28,740
870
570
-330
280
-10
1,210
1,350
1,210
1,520
780
790
990
-310
345
945
1,015
40
Saudi Arabia
11,500
590
340
-250
-230
-100
580
590
890
750
40
-130
-190
-245
115
495
115
100
Iran
3,600
110
140
0
30
-210
40
140
10
640
870
950
960
-220
70
-5
855
-50
UAE
3,710
-40
60
90
150
120
100
0
50
10
10
10
100
250
60
70
30
-25
Kuw ait Iraq Qatar
3,120 3,310 1,980
170 60 40
-80 130 -10
-120 10 -30
10 440 -70
30 280 -80
-50 690 -60
-130 930 -70
-90 460 20
-130 450 -30
-30 -20 -20
0 30 -10
10 200 -50
-45 40 25
-5 160 -20
-60 590 -45
-35 160 -30
85 -105 30 310
Africa
8,420
-1,080
-1,200
190
170
110
80
-440
-330
-180
-110
-20
-70
-620
-485
-150
-95
Nigeria
2,370
-20
120
150
10
-20
-120
-40
10
-50
0
-20
-40
-80
65
-40
-25
0
Algeria
1,520
120
40
40
-50
20
-90
-120
-60
-110
-70
-60
-70
-50
40
-60
-75
-45
480
-1,160
-1,240
-20
240
-50
150
-240
-250
30
-20
10
0
-485
-545
-100
10
420
1,710
-160
-200
-20
20
150
180
80
70
30
40
30
30
20
-90
120
35
-135
Libya Angola Sudan Asia Indonesia
270
140
110
10
-60
10
-20
-20
-10
-10
0
0
0
70
50
-10
0
-10
8,880
-130
-120
-50
60
50
110
330
90
50
30
-80
-150
-85
-60
145
-35
-190
840
-40
-40
-30
-40
-40
0
60
120
140
110
60
20
-40
-40
40
80
-60
China
4,220
-20
-10
50
50
40
120
150
20
10
-50
-10
-50
55
20
85
-25
-30
India
880
0
0
-20
10
0
-10
10
-30
-20
-10
-20
-30
-10
-5
-10
-15
-30
Source: IEA, JODI, Country Data, BP Statistical Review of World Energy 2014, Petrologistics, Credit Suisse Research
22
Oil Demand
The Demand Side – Macro Environment Is Not Bad Worries galore, yet global growth remains the most likely outcome 2014 was a materially worse year for global oil demand growth than we anticipated. In our data too, growth will only reach 1% this year. Most importantly oil demand is not cratering, nor is the global macro environment taking a dramatic turn for the worse (See the latest Global Cycle Note). We observed a month ago that global industrial production had declined sharply through the first nine months of 2014. But in the below picture it is clear that indeed the momentum trough was reached in August and that growth resumed (indeed accelerated into year-end)
Significantly, other measures of global activity, all based on real data show no great deterioration (quite the opposite), which should come as a surprise to the many who still fear that sharply falling oil prices are a symptom of a great economic malaise To the right, below is a track of global oil demand growth for the same time period. No surprise to us that it too is trending up (not sideways or down) Quantitative tightening from the federal reserve could add to turbulence (See the latest Global Money Note). We expect Chinese growth to continue its downward trend, but not collapse. See the latest Global Strategy Note from FID released today. Longer history and real/ relevant m easures of activity: Global Goods Dem and, Production and Trade – in which Goods Demand is Adjusted IP Components from (C + I + G - M)
Global oil dem and growth (SA, 3m m a of m onthly data on a LN scale)
11.50 11.45 11.40 11.35 11.30 J-08
Credit Suisse Research, IEA, EIA, JODI, Country Data
J-09
J-10
J-11
J-12
J-13
J-14
J-15
J-16
24
Back to Our Base Case: Upward Trends in All Regions Weakness last year was concentrated in the OECD, but US has upside These trend charts reflect monthly data (through November for nearly all bigger economies), which we seasonally adjusted and trend normalized (LN) No debate that oil demand across Emerging Markets grows less fast
It is clear too, however, that even in EM Asia ex-China fears seem overblown
10.90
9.5
10.80
9.4
10.70 9.3 10.60 9.2
10.50 10.40
9.1 J-08
J-09
J-10
J-11
J-12
J-13
J-14
J-15
J-16
J-08
J-09
J-10
J-11
J-12
J-13
J-14
J-15
J-16
Upside to the cyclical upturn in the US world’s biggest oil market
Weakness was concentrated in DM, which deflated yoy in 2014
10.0
10.90 10.85
9.9
10.80 10.75
9.8
10.70
9.7
10.65 J-08
J-09
J-10
J-11
J-12
J-13
J-14
J-15
J-16
Source: Credit Suisse Research, IEA, EIA, JODI, Country Data
J-08
J-09
J-10
J-11
J-12
J-13
J-14
J-15
J-16
25
We Worry Less Than Most About Oil Demand in China While China’s economic growth has slowed, oil demand continues to expand and its composition suggests oil use is shifting from industry-led to consumer-led China’s oil dem and (3m m a of m onthly data, kb/ d)
China’s diesel dem and inched up (Kb/ d m onthly, 12 m m a (lhs), % yoy (rhs)
11,500 11,000
10,500 10,000 9,500
9,000 8,500
adjusted demand
3mth average
8,000 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15
Gasoline dem and continues to surge (Kb/ d, 12 m m a (lhs), % yoy (rhs) 2,750
60%
2,500
50%
2,250
40%
2,000
30%
1,750
20%
1,500
10%
1,250
0%
1,000 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15
-10%
Source: Credit Suisse Research, NBS
3,750
60%
3,500
50%
3,250
40%
3,000
30%
2,750
20%
2,500
10%
2,250
0%
2,000 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15
-10%
China oil dem and by product as supplied by the bigger refiners (Kb/ d, yoy) China's oil product demand adjusted for gasoline and diesel inventory shifts kb/d 2014 2014ytd July* 2015 ytd Gasoline 2,183 2,394 2,388 2,675 Kerosene 454 503 519 605 Diesel 3,377 3,276 3,435 3,343 MD 3,831 3,779 3,954 3,948 Fuel oil 676 654 562 555 LPG 793 837 855 976 Naphtha 1,064 1,083 1,084 1,151 "Drive" 6,014 6,173 6,343 6,623 "Burn" 2,533 2,575 2,501 2,682 Total 8,547 8,748 8,843 9,305 * three month rolling average. "Drive" = gasoline + diesel + kerosene
July* 2,721 606 3,391 3,996 546 992 1,150 6,717 2,688 9,405
YoY change July* 2015 ytd 13.9% 11.8% 16.7% 20.3% -1.3% 2.0% 1.1% 4.5% -2.8% -15.1% 16.0% 16.6% 6.1% 6.2% 5.9% 7.3% 7.5% 4.2% 6.4% 6.4%
26
Oil Demand Upside in the US Gasoline tailwinds without as yet much ‘friction’ from efficiencies/substitutes In our view US oil demand is the most likely to surprise consensus this year
The stacked bar chart on the left shows that already in 2014 real growth of transportation fuels accelerated modestly – The ‘disappointment’ relative to our forecast of net 200 kb/d (~1%) of growth last year was driven mostly by contracting LPG burn In 2015 our forecast for only about 150 kb/d of total growth has cautiously assumed only very slightly accelerating gasoline demand growth and moderating growth of diesel consumption. In addition we subtract in the ‘other’ category The charts to the right clearly suggest that a follow through on the late 2014 mini-trends of rising vehicle miles traveled and deteriorating car fleet efficiency holds upside promise for the ~9 Mb/d US gasoline market … US oil dem and growth by product (annual averages in kb/ d, yoy)
2012/11
2013/12
2014/2013
VMT and Fuel Efficiency
2015E/2014E
27
500
260
300
255
100
250
-100
245
25
23
-300
Others***
LPGs**
Fuel oil
-500
Jet fuel
Diesel*
Gasoline
21
240 235 230 225
19
Vehicle Miles of Travel, United States (Bn Miles, SA, 3mma)
17
New Car Fleet Average (weighted, mpg, 3mma)
15
220 '00 '02 '04 '06 '08 '10 '12 '14
'07 '08 '09 '10 '11 '12 '13 '14
Source: IEA, JODI, National Statistical Agencies, BP Statistical Review of World Energy 2014, Petrologistics, Credit Suisse Research
27
Short-Term Signals: Refiner Margins, Broadly OK Still US East Coast 6-3-2-1 ($/ b) (Brent based) 2013
$20
NW Europe 20-6-11-3 ($/ b) (Brent based)
2014
2015
$15 $10 $5 $0 J
F
M
A
M
J
J
A
S
O
N
$20
J
D
SING 6-2-3-1 ($/ b) (Dubai Fateh based)
2013
2013
$16 $14 $12 $10 $8 $6 $4 $2 $0 F
M
A
M
2014
J
J
A
2015
S
O
N
D
J
D
J
US Gulf Coast 3-2-1 ($/ b) (LLS based))
2014
$30
2015
2013
2014
2015
$25 $15
$20 $15
$10
$10 $5
$5
$0 $0
-$5 J
F
M
A
M
J
J
A
S
O
N
D
J
Source: Credit Suisse Research, the BLOOMBERG PROFESSIONAL™ service
F
M
A
M
J
J
A
S
O
N
28
Global Oil Demand Growth (YoY) Decomposed Growth remains on track to both outperform nearly all expectations as well as the upward revised 2014 pace – all because developed economies are using more oil OECD oil demand is responsible for a projected 700 kb/d swing in oil demand growth this year; which more than compensates for what seems to be a cyclical, 150 kb/d downturn in expected demand growth across EM economies. But the 2.1% yoy pace of growth achieved in the first half will likely slowdown to ~1.4% in the second half. 1,000 b/d
Base 1Q14
92,610
1.3%
0.7%
45,670
0.0%
-1.7%
Emerging Markets 46,940
2.5%
3.0%
Global OECD
OECD Americas
by year (2013-16)
by quarter (2014 - 2016)
2014
%
2Q14
3Q14
"norm"
4Q14
1Q15 2Q15E 3Q15E 4Q15E
1Q16E
2Q16E
3Q16E
4Q16E
2013
2014 2015E 2016E 2010-14
0.9%
1.6%
2.2%
2.0%
1.7%
1.3%
1.5%
1.9%
1.6%
1.7%
1.5% 1.1% 1.8% 1.7%
1.8%
-0.9%
-0.3%
1.8%
0.8%
0.8%
0.3%
0.3%
1.2%
0.5%
0.6%
0.0% -0.7% 0.9%
0.6%
-1.7%
2.8%
3.5%
2.6%
3.1%
2.5%
2.4%
2.7%
2.6%
2.8%
2.8%
3.0%
2.7%
4.1%
3.0%
2.7%
by year in kb/d 2013 2014E 2015E 2016E 1320 1020 1661 1594 4 -334
412
289
1316 1354 1248 1305
24,130
0.4%
-0.5%
0.3%
1.0%
1.4%
1.4%
1.3%
0.2%
0.7%
1.5%
0.7%
0.9%
1.6% 0.3% 1.1% 1.0%
-1.8%
367
75
254
235
Canada
2,400
1.1%
-1.6%
2.3%
1.7%
-2.0%
-4.0%
-2.2%
-3.0%
-2.0%
1.0%
-0.8%
-0.6%
-1.2% 0.9% -2.8% -0.6%
0.2%
-28
21
-67
-15
Mexico
2,010
-4.8%
-5.3%
-3.8%
-2.1%
-4.2%
-3.4%
-1.7%
-2.3%
0.3%
-1.3%
-2.6%
-0.6%
-0.5% -4.0% -2.9% -1.1%
-0.6%
-11
-84
-58
-21
USA
19,090
1.0%
0.3%
0.6%
1.4%
2.4%
2.6%
2.0%
0.8%
1.2%
1.8%
1.3%
1.3%
2.1%
1.4%
-2.1%
397
153
369
269
6,690
3.1%
1.4%
2.1%
2.0%
0.9%
-1.8%
0.2%
1.3%
1.5%
2.6%
2.2%
2.0%
3.9% 2.1% 0.2% 2.1%
4.9%
243
140
10
138
3,170
5.5%
4.6%
4.3%
4.6%
0.4%
-5.0%
-1.7%
0.7%
0.8%
3.0%
2.2%
1.7%
4.8%
5.4%
138
143
-45
60
760
1.3%
-8.5%
-2.1%
-1.4%
2.0%
2.0%
2.0%
2.0%
3.0%
3.0%
3.0%
3.0%
3.0% -2.7% 2.0%
3.0%
4.0%
22
-21
15
23
14,270
-0.8% -3.1% -0.9% -0.7%
4.4%
0.5%
0.7%
1.1%
-0.1%
1.0%
0.6%
0.6%
-1.8% -1.4% 1.6% 0.5%
-2.3%
-267 -199
233
77
France
1,650
-5.3%
-5.8%
-1.3%
-1.6%
2.6%
-0.5%
-0.9%
-0.1%
0.9%
-1.2%
-1.5%
-1.5%
-1.5% -3.5% 0.3% -0.8%
-2.5%
-26
-60
5
-14
Germany
2,400
1.2%
-7.6%
0.6%
-0.3%
6.6%
-3.5%
-1.1%
-0.5%
-4.6%
3.3%
0.4%
0.5%
1.9% -1.6% 0.3% -0.2%
-0.1%
46
-39
8
-4
Italy
1,220
-3.4%
-2.0%
-3.1%
-2.7%
2.2%
5.5%
0.7%
0.7%
0.7%
0.7%
1.0%
1.0%
-8.1% -2.8% 2.2%
0.8%
-4.5%
-110
-35
27
10
UK Oth Europe
1,510 7,490
1.4% -0.5%
-2.4% -1.4%
-0.9% -0.8%
2.8% -0.9%
3.2% 4.8%
1.7% 0.9%
0.7% 1.5%
0.7% 2.0%
0.3% 1.0%
0.2% 1.1%
0.3% 1.1%
0.3% 1.1%
-1.6% 0.2% 1.5% -2.0% -0.9% 2.3%
0.3% 1.1%
-2.7% -2.4%
-25 -151
3 -67
23 170
4 81
FSU
4,730
8.7%
3.1%
1.4%
3.2%
0.0%
0.0%
-2.0%
-2.0%
0.0%
-2.0%
0.0%
1.0%
2.3% 4.0% -1.0% -0.2%
2.4%
103
181
-49
-11
Mideast
South America Brazil Argentina Europe
0.8%
1.9%
4.7% -1.4% 1.9%
8,310
3.9%
4.3%
2.1%
5.8%
0.9%
3.9%
2.7%
2.6%
3.1%
3.0%
3.0%
3.0%
2.5% 4.0% 2.5% 3.0%
4.3%
197
318
211
257
Saudi Arabia
3,340
6.1%
13.3%
8.8%
9.1%
3.8%
5.8%
3.0%
3.0%
3.1%
3.0%
3.0%
3.0%
2.3%
3.0%
7.1%
70
288
131
104
Iran
2,090
-0.7%
-4.7%
-3.4%
6.7%
-6.9%
-0.4%
0.0%
0.0%
2.0%
2.0%
2.0%
2.0%
4.4% -0.7% -1.8% 2.0%
1.2%
89
-14
-38
41
Iraq
619
7.7%
0.1%
-11.5% 13.3%
4.6%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
7.2%
3.0%
13.2%
40
-40
7
19
Africa
3,870
0.6%
3.8%
7.7%
3.0%
3.4%
2.8%
4.5%
4.3%
4.4%
4.5%
4.5%
4.3%
4.6% 3.7% 3.7% 4.4%
3.8%
164
136
144
178
Asia-Pac
30,610
0.9%
1.6%
0.9%
1.5%
2.6%
3.6%
2.8%
2.2%
2.2%
2.5%
2.3%
2.2%
1.7% 1.2% 2.8% 2.3%
3.1%
512
368
857
721
China
10,590
-1.6%
2.0%
3.8%
5.6%
6.2%
6.3%
4.4%
3.9%
3.3%
3.3%
3.4%
3.3%
2.2%
2.5%
5.2%
3.3%
6.4%
224
256
547
369
India
3,850
1.6%
3.9%
4.2%
3.3%
5.1%
6.9%
5.0%
4.5%
4.1%
4.0%
4.0%
4.0%
1.1%
3.2%
5.4%
4.0%
3.7%
41
121
207
163
Indonesia
1,870
12.2%
9.8%
-1.4%
0.7%
-0.7%
-0.9%
2.9%
0.3%
0.0%
0.0%
0.0%
0.0%
4.0%
5.0%
0.4%
1.5%
5.3%
68
89
8
28
Japan
4,350
0.7%
-4.7%
-8.8%
-5.9%
-5.4%
-1.2%
-0.7%
-2.7%
-2.0%
-0.9%
-1.6%
-1.6%
-3.0% -4.5% -2.7% -1.5%
-1.2%
-141 -206 -116
-64
South Korea
2,340
0.6%
0.5%
1.9%
-0.9%
5.5%
0.4%
0.9%
2.1%
3.1%
3.2%
1.6%
1.5%
0.3%
2.2%
2.4%
0.8%
34
10
15
39
Australia
1,080
0.0%
-0.1%
0.0%
0.0%
2.0%
-1.4%
-0.1%
0.6%
1.0%
1.0%
1.0%
1.0%
0.5% -0.1% 0.2%
1.0%
1.7%
6
-1
3
11
Thailand
1,280
0.5%
2.8%
0.9%
-0.9%
-0.1%
-0.2%
2.5%
2.5%
3.0%
3.0%
3.0%
3.0%
2.7%
3.0%
3.7%
34
10
15
39
Source: Credit Suisse Research, IEA, EIA, JODI
9.4% 1.9%
0.5% 0.8%
3.9% 1.1%
1.2%
OECD growth, watch EU Expected in the US, less so from Europe Europe’s oil use remains on track to grow by1.5%, which would be a sharp (410 kb/d) turn-around from the -1.4% decline featured in 2014 In the US, oil consumption should grow by 370 kb/d, 2.5 x last year’s pace EM Asia improves, but … Anticipated slowing down is in evidence in Latam and Mideast We forecast that H2 growth decelerates in Asia, notably China, where data in H1 have surprised to the upside All this could turn ugly fast if the macro turns south 29
Inventories
Inventories Are the Bottom Line and Should Stop Rising Commercial oil inventory in the OECD has been tracking up ever further into record territory … in our view this stops and turns this quarter We focus here on the inventories we can measure of the more important commercial stocks of crude oil and products in what are often called the Developed Market economies belonging to the OECD. In addition, there are several categories of sizeable inventories that the market has at least some visibility on, for instance downstream and crude oil stocks in China, independent storage in Singapore and ARA and South Africa, as well as stocks in Saudi Arabia and of course the aggregate of oil cargoes in transit aboard tankers at sea. Suffice it to say that all these stocks have risen a lot . How big is the measurable surplus? In the OECD alone there are at least 200 million barrels too many – Expressed in days of demand cover, we plot in the chart below left the number of days of forward oil demand in the OECD against a five year moving average as well as yoy. At the end of July, OECD stocks held nearly six days more stocks than normal and in August that likely did not go down by more than a fraction, while the yoy surplus was also at its widest, at six days. By both measures there would appear to be some 250 million too many barrels in inventory. – Similarly, in simple nominal terms commercial OECD inventory should add up to some 2960 million barrels at the end of August, about 220 Mbs more than normal for August. Both these measures are somewhat inflated since the IEA is now counting some 20 Mbs of Asia Pacific inventory it was not counting before. So in our base case, it would take more than a half a year to drain the surplus OECD commercial oil stocks in days of demand-cover, peak in August; as does the forecast nominal count driven by our global s/d model
10
64
8
62
6
60 58
4
56
2
54
0
52
3000
1,000 bs
66
2900
2800 2700
-2
50 yoy diff of cover (rhs) 5 year MA
48 46 J-06
J-07
J-08
J-09
J-10
Days cover of demand
-4
-6 J-11
J-12
J-13
J-14
J-15
J-16
2600
OECD commercial oil inventory 5 yr avg projected
2500 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15
Source: IEA, Joint Oil Data Initiative, National Statistical Agencies, Credit Suisse Research
31
Looking Through the Second Half of 2015 Inventories are clearly in surplus in the US and in other regions inventory is now ample too
Arguably, some part of this inventory simply supports the massive new production infra-structure built out in and around the new shale provinces; Yet another part goes to support higher refinery runs in North America, and elsewhere
Total OECD Europe stocks surpass 5 year average
1050 1,000 bs
The US holds about three quarters of the OECD surplus
1000 950
Inventories are a neat, albeit backward looking signal
900
We watch out for clearly visible massive crude oil inventory to morph into downstream excesses
850
Commercial Oil Stocks 5-yr average
800 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15
As do OECD Asia total inventories
Delta driven by USA 1400 1,000 bs
1,000 bs
460 440 420 400
Commercial Oil Stocks
1300
5-yr average
1200
380 360
Commercial Oil Stocks
1100
5-yr average
340 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15
Source: Credit Suisse Research, IEA, EIA
1000 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15
32
In the US Worries About Containment in the Near Term
In the US, the worry is that refiner maintenance will undermine what little fundamental strength remains under crude markets. We worry a bit less than most. Inventory Surplus to 5 Year Norm by category in million barrels (Mbs)
High crude oil refinery runs have been a support, but they will fall (Mb/d)
200
17
LPG Products (ex LPG)
160 Crude Oil
16
Total
120
15
80
14
40
0 May-14
Jul-14
Sep-14
Nov-14
Jan-15
Mar-15
May-15
prior 5yr range
prior 5yr avg
2014
2015
13
Jul-15
D
Keep an eye on rising middle distillate inventories (diesel and Hating oil, Mbs) 180
J
F
M
A
M
J
J
A
S
O
N
D
There is a lot of room left to build stocks, even if production in the US does not fall much more, and refiners take down runs for maintenance and imports remain relatively high… Actual and projected crude oil inventories in PADD III
390 160
Million Barrels
340 140
120
100
5 yr range
5 yr average
2014
2015
J
F
M
A
M
J
J
240 190
80
D
290
A
S
Source: Credit Suisse Research, EIA
O
N
D
140 Jan-13
Jan-14
Jan-15
Jan-16E 33
High Frequency Signals: US weekly inventories
In the near term, US crude oil inventories will likely rise again as refiner demand wanes in Oct/Nov – but we think the bounce will be modest and accommodated PADD I – IV “East of Rockies” crude inventories (Mbs)
450 425 400 375 350 325 300 275 250
5 year average
PADD III “East of Rockies” crude inventories (Mbs)
2014
275
2015
5 year average
2014
2015
250 225 200 175 150 125 100 J
F
M
A
M
J
J
A
S
O
N
D
J
F
M
A
M
J
J
A
S
O
N
D
US inventories surpluses, a weekly plot relative to their 5 year average -- IF our central case is correct then this surplus should very soon, this m onth or next, start to fall (Mbs)
PADDs I – IV “East of Rockies” gasoline cover (days)
200 LPG
26
Products (ex LPG)
24
5 yr range
5 year average
2014
2015
160 Crude Oil Total
120
22
80
20
40
18 D
J
F
M
A
M
J
J
A
S
Source: Credit Suisse Research, EIA
O
N
D
0 May-14
Jul-14
Sep-14
Nov-14
Jan-15
Mar-15
May-15
Jul-15
34
Tactical Indicators – US Storage Capacity Shell crude storage capacity (thousands of barrels) I Refineries Tank Farms (excluding SPR) Of which at Cushing, OK Tankers, Barges and Pipes SPR (Crude only) Total (excluding SPR):
In Operation Idle 17,443 4,908 --22,351
1,894 1,148 --3,042
Working crude storage capacity (thousands of barrels) Refineries Of which is likely to be max fill in reality
II In Operation Idle 23,166 142,063 84,969 -165,229
PADDs III
1,213 2,716 147 -3,929
II
15,408
18,877
75,006
4,006
34,756
148,053
13,082
17,375
58,037
3,461
29,405
121,359
3,974
117,253
210,614
13,139
27,899
372,879
71277
4279
15636
130,000
20,878
72,940
624,238
IV 21,598
V 52,170
US Total 455,427
IV
V
US Total 73%
Of which at Cushing, OK
V
4837
33972
21,893
168,599
SPR (Crude only)
IV In Operation Idle 4,614 15,966 --20,580
160 76 --236
V In Operation Idle 39,207 33,660 --72,867
1,050 1,269 --2,319
US Total In Operation Idle 173,717 7,122 438,982 12,444 84969 147 173333 na 727000 0 786,032 19,566
US Total
70,812
Volumes in transit *
70,812 727,000
Total (excluding SPR):**
2,805 7,235 --10,040
I
Tank Farms (excluding SPR)
IV
PADDs III In Operation Idle 89,287 242,385 --727,000 331,672
339,928
727,000
(*) Note: Volumes estimates based on March 4, 2015 note by EIA (**) Note: Total assumes a level of max fill at refineries below the EIA working capacity number
Crude Oil Stocks (thousands of barrels) 8/28/2015 Standard EIA stock number Crude storage capacity utilization (thousands of barrels) 8/28/2015 Standard EIA stock number "Head Room" PADD I - IV East of Rockies
I 16,230
I
II 140,097
II 74%
83%
PADDs III 225,332
PADDs III 66%
103%
72%
148,041
"Head Total shell Total Room" till capacity operable Total working Three week (incl. idle shell working Current capacity is average # of weeks 8/28/2015 capacity) capacity capacity * inventories full build till full PADD I - IV "East of Rockies" (excluding SPR): 557,079 539,832 551,298 403,257 148,041 622 238 (*) Note: has been adjusted to account for oil in transit as well as a level of max fill at refineries below the EIA working capacity number
Source: Credit Suisse Research, EIA
35
OECD Commercial Inventories Mbls End month
July(e) surplus/deficit June
July
Aug
Sep
Oct
Nov
Dec
Jan
Feb
Mar
Apr
May
June
July(e)
Crude oil
1,030
Products
1,630
1,012
999
1,002
1,034
1,021
1,041
1,054
1,092
1,146
1,154
1,168
1,166
1,660
1,717
1,726
1,672
1,686
1,668
1,684
1,649
1,648
1,668
1,714
1,730
All oil
2,660
2,672
2,717
2,729
2,706
2,707
2,709
2,738
2,741
2,793
2,823
2,882
Crude oil
526
515
507
509
535
540
549
572
597
621
634
Products
840
861
877
887
855
859
868
860
838
839
858
Gasoline
251
248
243
242
234
248
269
274
276
264
Mid distillate
187
190
196
202
183
189
204
201
192
1,366
1,376
1,384
1,396
1,390
1,399
1,418
1,432
Crude oil
326
320
312
315
315
307
319
Products
563
564
590
582
567
577
567
Gasoline
85
84
88
87
84
88
Mid distillate
249
254
268
266
250
889
883
902
897
Crude oil
177
177
180
Products
227
236
251
Gasoline
24
23
Mid distillate
55
57
405
412
YoY
June
5yr
YoY
5yr
mbls
%
mbls
%
mbls
mbls
1,173
161
+15.9
170
+16.9
136
149
1,764
104
+6.2
56
+3.3
100
51
2,896
2,937
265
+9.9
226
+8.3
236
201
626
621
615
100
+19.4
114
+22.6
95
109
878
903
921
60
+7.0
57
+6.6
63
61
261
251
251
248
1
+0.3
-1
-0.4
0
2
196
197
204
212
220
30
+15.6
9
+4.2
25
9
1,435
1,459
1,492
1,505
1,525
1,536
160
+11.6
170
+12.5
158
170
314
322
347
350
343
343
357
38
+11.9
31
+9.6
17
12
593
592
595
590
604
601
606
42
+7.4
6
+0.9
38
3
90
102
106
102
95
92
92
94
10
+11.4
3
+3.3
7
1
256
251
261
257
260
262
281
275
278
24
+9.4
12
+4.6
27
13
882
884
886
907
914
942
940
947
944
963
80
+9.0
37
+4.0
55
15
178
184
174
173
167
173
178
170
198
201
200
23
+13.2
25
+14.0
23
28
258
250
250
232
231
219
214
221
232
226
237
2
+0.7
-6
-2.5
-1
-13
23
23
22
23
21
23
24
23
24
25
25
24
1
+4.2
-1
-4.5
1
0
61
59
56
58
56
57
58
57
58
59
59
61
4
+7.6
-3
-4.3
4
-2
431
436
434
424
405
399
392
392
391
431
427
437
25
+6.1
18
+4.4
22
15
OECD
N. Am erica
All oil Europe
All oil Asia Pacific
All oil
Source: Credit Suisse Research, IEA
36
Balances
Oil Macro – Global Balances (Supply) Supply Global YoY Growth, net mb/d YoY Growth, % Non OPEC YoY Growth, net YoY Growth, % North America YoY Growth, net YoY Growth, % South America YoY Growth, net YoY Growth, % Europe YoY Growth, net YoY Growth, % FSU YoY Growth, net YoY Growth, % Russia YoY Growth, net YoY Growth, % Africa YoY Growth, net YoY Growth, % Mideast YoY Growth, net YoY Growth, % Asia YoY Growth, net YoY Growth, %
mb/d
mb/d
mb/d
mb/d
mb/d
mb/d
mb/d
mb/d
mb/d
Processing gain OPEC YoY Growth, net mb/d YoY Growth, % Opec Crude Oil YoY Growth, net mb/d YoY Growth, % Saudi Arabia YoY Growth, net mb/d YoY Growth, % Opec non-crude YoY Growth, net mb/d YoY Growth, %
2012 90.4 2.4 2.7%
2013 91.0 0.6 0.6%
Q1-'14 Q2-'14 Q3-'14 Q4-'14 92.1 92.4 92.9 94.3 1.6 1.5 1.8 2.8 1.8% 1.7% 2.0% 3.1%
2014 92.9 1.9 2.1%
Q1-'15 Q2-'15 Q3-'15E Q4-'15E 2015E Q1-'16E Q2-'16E Q3-'16E Q4-'16E 2016E 94.6 95.54 95.0 95.1 95.1 94.9 95.33 95.2 96.1 95.4 2.5 3.1 2.1 0.8 2.1 0.4 (0.2) 0.2 1.0 0.3 2.7% 3.4% 2.3% 0.9% 2.3% 0.4% -0.2% 0.2% 1.0% 0.4%
50.9 0.8 1.7% 16.5 1.2 8.1% 4.6 0.0 -0.6% 3.9 -0.3 -6.1% 13.6 0.1 0.4% 10.6 0.1 1.0% 2.2 -0.1 -4.4% 1.5 -0.2 -12.9% 8.6 0.1 1.8%
52.2 1.3 2.6% 17.9 1.4 8.7% 4.6 0.1 1.3% 3.8 -0.2 -4.0% 13.9 0.2 1.8% 10.8 0.1 1.4% 2.2 0.0 -1.2% 1.3 -0.1 -8.1% 8.5 -0.1 -1.1%
53.6 1.8 3.6% 19.0 1.6 9.2% 4.7 0.2 3.3% 3.9 0.1 1.9% 13.9 0.1 0.5% 10.8 0.1 0.6% 2.3 0.1 5.9% 1.3 -0.1 -3.9% 8.4 -0.1 -1.5%
54.3 2.1 4.0% 19.8 1.9 10.5% 4.9 0.3 5.4% 3.8 0.0 0.9% 13.9 0.0 -0.2% 10.8 0.0 0.1% 2.3 0.1 2.3% 1.3 0.0 -2.4% 8.4 -0.1 -0.7%
55.9 2.3 4.3% 20.7 1.7 9.0% 5.1 0.4 9.1% 3.9 0.0 0.5% 14.1 0.1 1.0% 10.9 0.1 1.1% 2.3 0.0 0.2% 1.3 0.0 -3.6% 8.5 0.0 0.6%
53.9 2.2 4.3% 19.6 2.1 12.2% 4.8 0.2 3.7% 3.7 0.0 -1.3% 13.8 0.0 -0.1% 10.8 0.0 0.2% 2.3 0.1 3.8% 1.3 0.0 -0.2% 8.4 -0.1 -1.4%
54.1 2.0 3.9% 19.9 1.8 10.0% 5.0 0.3 6.6% 3.7 0.0 -0.1% 13.8 0.0 -0.3% 10.7 0.0 -0.5% 2.3 0.0 1.9% 1.3 0.0 -2.0% 8.3 -0.1 -0.7%
55.6 2.2 4.2% 20.6 1.9 10.3% 5.1 0.4 7.8% 3.9 0.1 2.9% 13.9 -0.1 -0.9% 10.9 0.0 0.0% 2.3 0.0 -2.1% 1.3 0.0 -3.5% 8.5 0.1 0.7%
55.5 1.6 3.0% 20.43 0.9 4.4% 5.0 0.3 5.9% 4.00 0.3 7.5% 14.0 0.2 1.6% 11.0 0.2 1.6% 2.2 0.0 -2.0% 1.2 -0.1 -7.2% 8.53 0.1 1.3%
55.1 55.3 55.4 0.9 -0.3 1.1 1.7% -0.5% 2.1% 20.4 20.2 20.4 0.4 -0.3 0.7 2.2% -1.6% 3.4% 5.1 5.1 5.1 0.1 0.0 0.2 2.2% -0.3% 4.1% 3.7 4.0 3.9 0.1 0.0 0.1 1.6% 0.7% 2.5% 14.0 14.1 14.1 0.3 0.2 0.2 1.9% 1.4% 1.5% 11.0 11.0 11.0 0.3 0.2 0.2 2.8% 1.7% 1.8% 2.1 2.2 2.2 -0.1 -0.1 -0.1 -5.4% -4.4% -2.9% 1.2 1.1 1.2 -0.1 -0.1 -0.1 -9.8% -10.9% -7.9% 8.6 8.6 8.6 0.3 0.1 0.1 3.9% 1.0% 1.7%
54.7 -1.2 -2.1% 19.9 -0.8 -4.1% 5.1 -0.1 -1.0% 3.8 -0.2 -4.2% 14.2 0.1 0.8% 11.1 0.1 1.3% 2.2 -0.1 -3.5% 1.1 -0.2 -12.6% 8.5 0.0 0.5%
54.5 -1.0 -1.7% 19.51 -0.9 -4.5% 5.1 0.1 1.9% 3.85 -0.2 -3.8% 14.1 0.1 0.8% 11.1 0.1 1.3% 2.2 -0.1 -2.7% 1.1 -0.1 -6.0% 8.55 0.0 0.3%
54.5 -0.6 -1.0% 19.9 -0.4 -2.2% 5.1 0.1 1.2% 3.6 -0.1 -3.3% 14.1 0.1 0.6% 11.1 0.1 1.2% 2.1 0.0 0.1% 1.1 -0.1 -4.9% 8.5 -0.1 -1.0%
55.4 0.1 0.1% 20.3 0.1 0.6% 5.2 0.1 2.3% 3.8 -0.1 -3.5% 14.2 0.2 1.1% 11.2 0.1 1.2% 2.2 0.0 0.2% 1.1 0.0 -4.1% 8.5 -0.2 -1.8%
54.8 -0.7 -1.2% 19.9 -0.5 -2.5% 5.1 0.1 1.1% 3.8 -0.1 -3.7% 14.2 0.1 0.8% 11.1 0.1 1.2% 2.2 0.0 -1.5% 1.1 -0.1 -7.0% 8.5 0.0 -0.5%
2017E 96.4 1.0 1.0% 55.5 0.7 1.3% 21.0 1.0 5.2% 5.0 -0.1 -1.8% 3.5 -0.3 -8.0% 14.3 0.2 1.1% 11.2 0.1 1.1% 2.2 0.1 3.2% 1.1 0.0 0.4% 8.3 -0.2 -2.2%
2.1
2.1
2.1
2.2
2.1
2.1
2.1
2.3
2.1
2.1
2.1
2.1
2.2
2.1
0.0
0.0
2.2
2.2
37.5 1.5 4.3% 31.6 1.2 3.9% 9.8 0.4 3.8% 5.8 0.3 6.2%
36.7 -0.8 -2.1% 30.6 -1.1 -3.4% 9.6 -0.2 -1.9% 6.1 0.3 4.6%
36.4 -0.2 -0.6% 30.2 -0.5 -1.5% 9.7 0.5 5.9% 6.3 0.2 4.1%
36.3 -0.7 -1.9% 30.1 -0.9 -2.9% 9.7 0.3 3.0% 6.3 0.2 3.3%
36.6 -0.3 -0.7% 30.3 -0.5 -1.5% 9.8 -0.3 -3.2% 6.3 0.2 3.5%
36.6 0.6 1.6% 30.3 0.4 1.2% 9.5 -0.3 -2.6% 6.3 0.2 3.3%
36.5 -0.2 -0.4% 30.2 -0.4 -1.2% 9.7 0.1 0.6% 6.3 0.2 3.6%
36.6 0.1 0.4% 30.4 0.2 0.8% 9.6 -0.1 -0.7% 6.1 -0.1 -1.7%
37.80 1.5 4.0% 31.59 1.5 5.1% 10.2 0.6 6.0% 6.22 -0.1 -1.1%
37.8 1.1 3.1% 31.5 1.2 4.1% 10.4 0.6 6.0% 6.3 -0.1 -1.4%
37.7 1.1 2.9% 31.4 1.1 3.8% 10.4 0.9 9.0% 6.2 -0.1 -1.1%
37.5 1.0 2.6% 31.3 1.0 3.4% 10.2 0.5 5.1% 6.2 -0.1 -1.3%
38.1 1.5 4.1% 31.8 1.4 4.6% 10.3 0.7 7.2% 6.2 0.1 1.5%
38.53 0.7 1.9% 32.26 0.7 2.1% 10.3 0.0 0.1% 6.27 0.1 0.8%
38.5 0.7 2.0% 32.3 0.7 2.3% 10.3 -0.1 -1.3% 6.3 0.0 0.4%
38.6 0.9 2.4% 32.3 0.9 2.7% 10.2 -0.2 -1.7% 6.3 0.0 0.4%
38.4 1.0 2.6% 32.2 0.9 2.9% 10.2 0.1 0.9% 6.3 0.0 0.8%
38.7 0.3 0.7% 32.3 0.1 0.3% 10.3 0.0 0.0% 6.4 0.2 2.7%
Source: Credit Suisse Research, IEA, JODI, EIA, NBP, ANP
38
Oil Macro – Global Balances (Demand) Demand Global YoY Growth, net mb/d YoY Growth, %
2012 90.27 0.9 1.1%
2013 91.6 1.3 1.5%
Q1-'14 Q2-'14 Q3-'14 Q4-'14 91.8 91.6 92.8 94.2 1.1 0.6 0.9 1.5 1.3% 0.7% 0.9% 1.6%
2014 92.6 1.0 1.1%
Q1-'15 Q2-'15 Q3-'15E Q4-'15E 2015E Q1-'16E Q2-'16E Q3-'16E Q4-'16E 2016E 93.8 93.39 94.4 95.4 94.3 95.2 95.18 95.9 97.1 95.9 2.0 1.8 1.6 1.3 1.7 1.4 1.8 1.6 1.6 1.6 2.2% 2.0% 1.7% 1.3% 1.8% 1.5% 1.9% 1.6% 1.7% 1.7%
2017E 97.0 1.1 1.2%
OECD YoY Growth, YoY Growth, Americas YoY Growth, YoY Growth, Europe YoY Growth, YoY Growth, Asia Pacific YoY Growth, YoY Growth,
net mb/d %
46.0 -0.5 -1.2% 23.7 -0.4 -1.5% 14.1 -0.4 -2.9% 8.2 0.2 3.0%
46.0 0.0 0.0% 24.1 0.4 1.6% 13.8 -0.2 -1.7% 8.1 -0.1 -1.5%
45.8 0.0 0.0% 23.9 0.1 0.4% 13.2 -0.1 -1.1% 8.7 0.1 0.6%
44.7 -0.8 -1.7% 23.7 -0.1 -0.5% 13.6 -0.5 -3.3% 7.5 -0.2 -2.4%
45.8 -0.4 -0.9% 24.3 0.1 0.3% 14.0 -0.2 -1.1% 7.5 -0.3 -4.3%
46.4 -0.2 -0.3% 24.6 0.2 1.0% 13.7 -0.1 -0.7% 8.1 -0.3 -3.5%
45.7 -0.3 -0.7% 24.1 0.1 0.3% 13.6 -0.2 -1.6% 7.9 -0.2 -2.4%
46.6 0.8 1.8% 24.3 0.3 1.4% 13.8 0.6 4.5% 8.5 -0.1 -1.3%
45.1 0.3 0.8% 24.0 0.3 1.4% 13.6 0.1 0.4% 7.4 0.0 -0.7%
46.2 0.4 0.8% 24.6 0.3 1.3% 14.1 0.1 0.5% 7.5 0.0 0.0%
46.5 0.1 0.3% 24.6 0.0 0.2% 13.8 0.1 1.0% 8.1 -0.1 -0.8%
46.1 0.4 0.9% 24.4 0.3 1.1% 13.8 0.2 1.6% 7.9 -0.1 -0.7%
46.7 0.1 0.3% 24.4 0.2 0.7% 13.8 0.0 -0.3% 8.5 0.0 -0.1%
45.6 0.5 1.2% 24.4 0.4 1.5% 13.7 0.1 0.9% 7.5 0.1 0.7%
46.4 0.2 0.5% 24.8 0.2 0.7% 14.1 0.1 0.4% 7.5 0.0 -0.2%
46.8 0.3 0.6% 24.9 0.2 0.9% 13.9 0.1 0.4% 8.0 0.0 -0.3%
46.4 0.3 0.6% 24.6 0.2 1.0% 13.9 0.0 0.4% 7.9 0.0 0.1%
45.9 -0.5 -1.0% 24.8 0.2 0.8% 13.8 -0.1 -0.7% 7.3 -0.6 -7.0%
Non-OECD YoY Growth, net mb/d YoY Growth, % Former Soviet Union YoY Growth, net mb/d YoY Growth, % China YoY Growth, net mb/d YoY Growth, % Other emerging Asia YoY Growth, net mb/d YoY Growth, % South America YoY Growth, net mb/d YoY Growth, % Mideast YoY Growth, net mb/d YoY Growth, % Africa YoY Growth, net mb/d YoY Growth, %
44.3 1.5 3.5% 4.4 0.1 2.3% 10.1 0.4 4.1% 11.4 0.4 3.3% 6.3 0.3 4.7% 7.8 0.3 3.6% 3.6 0.1 2.7%
45.6 1.3 3.0% 4.5 0.1 2.3% 10.3 0.2 2.2% 11.8 0.4 3.6% 6.5 0.2 3.9% 8.0 0.2 2.5% 3.7 0.2 4.6%
46.0 1.1 2.5% 4.6 0.4 8.7% 10.2 -0.2 -1.6% 12.2 0.4 3.3% 6.4 0.2 3.1% 8.0 0.3 3.9% 4.0 0.0 0.6%
46.9 1.4 3.0% 4.6 0.1 3.1% 10.5 0.2 2.0% 12.2 0.4 3.8% 6.6 0.1 1.4% 8.4 0.4 4.3% 3.9 0.1 3.8%
47.0 1.3 2.8% 4.8 0.1 1.4% 10.6 0.4 3.8% 11.8 0.2 1.9% 6.8 0.1 2.1% 8.6 0.2 2.1% 3.7 0.3 7.7%
47.8 1.6 3.5% 4.9 0.2 3.2% 11.0 0.6 5.6% 12.2 0.2 1.4% 6.9 0.1 2.0% 8.3 0.4 5.8% 3.9 0.1 3.0%
46.9 1.4 3.0% 4.7 0.2 4.0% 10.6 0.3 2.5% 12.1 0.3 2.6% 6.7 0.1 2.1% 8.3 0.3 4.0% 3.9 0.1 3.7%
47.2 1.2 2.6% 4.6 0.0 0.0% 10.8 0.6 6.2% 12.5 0.3 2.5% 6.5 0.1 0.9% 8.0 0.1 0.9% 4.1 0.1 3.4%
48.3 1.5 3.1% 4.6 0.0 0.0% 11.2 0.7 6.3% 12.7 0.5 3.8% 6.5 -0.1 -1.8% 8.8 0.3 3.9% 4.0 0.1 2.8%
48.2 1.2 2.5% 4.7 -0.1 -2.0% 11.1 0.5 4.4% 12.2 0.4 3.2% 6.9 0.0 0.2% 8.8 0.2 2.7% 3.8 0.2 4.5%
49.0 1.2 2.4% 4.8 -0.1 -2.0% 11.4 0.4 3.9% 12.5 0.3 2.6% 7.0 0.1 1.3% 8.5 0.2 2.6% 4.1 0.2 4.3%
48.2 1.2 2.7% 4.7 0.0 -1.0% 11.1 0.5 5.2% 12.5 0.4 3.0% 6.7 0.0 0.2% 8.5 0.2 2.5% 4.0 0.1 3.7%
48.5 1.3 2.7% 4.6 0.0 0.0% 11.2 0.4 3.3% 12.8 0.4 2.8% 6.6 0.1 1.5% 8.3 0.2 3.1% 4.3 0.2 4.4%
49.6 1.3 2.6% 4.5 -0.1 -2.0% 11.5 0.4 3.3% 13.1 0.4 2.8% 6.7 0.2 2.6% 9.0 0.3 3.0% 4.1 0.2 4.5%
49.6 1.3 2.8% 4.7 0.0 0.0% 11.4 0.4 3.4% 12.5 0.3 2.8% 7.0 0.1 2.2% 9.1 0.3 3.0% 4.0 0.2 4.5%
50.3 1.4 2.8% 4.9 0.0 1.0% 11.8 0.4 3.3% 12.8 0.3 2.8% 7.1 0.1 2.0% 8.7 0.3 3.0% 4.3 0.2 4.3%
49.5 1.3 2.7% 4.7 0.0 -0.2% 11.5 0.4 3.3% 12.8 0.3 2.8% 6.8 0.1 2.1% 8.8 0.3 3.0% 4.2 0.2 4.4%
51.1 1.6 3.2% 4.5 -0.2 -3.6% 11.6 0.0 0.4% 13.4 0.5 4.2% 7.2 0.4 5.9% 9.4 0.6 6.7% 4.3 0.1 2.0%
net mb/d % net mb/d % net mb/d %
Source: Credit Suisse Research, IEA, JODI, EIA, NBP, ANP
39
Oil Macro – Global Balances (Inventories) Balance, stocks Implied inventory change Reported oil inventory: OECD stock change OECD inventory (billion barrels) Cover, days demand 'Call on Opec & stocks" YoY Growth, net mb/d YoY Growth, % 'Call on Saudi & stocks" YoY Growth, net mb/d YoY Growth, %
2012 0.2
2013 -0.6
0.2 -0.3 2.67 2.58 58.4 56.3 31.5 31.2 -0.3 -0.3 -0.9% -1.0% 9.6 10.2 -1.1 0.6 -10.3% 5.8%
Q1-'14 Q2-'14 Q3-'14 Q4-'14 0.3 0.8 0.1 0.1 0.1 2.59 57.9 29.9 -1.0 -3.1% 9.4 0.0 0.4%
2014 0.3
0.8 0.7 -0.2 0.4 2.66 2.73 2.71 2.71 58.1 58.9 58.1 58.1 29.2 30.2 30.2 29.9 -1.8 -1.4 -1.0 -1.3 -5.8% -4.4% -3.2% -4.2% 8.8 9.7 9.4 9.3 -0.6 -1.2 -1.6 -0.9 -6.5% -11.3% -14.7% -8.5%
Source: Credit Suisse Research, IEA, JODI, EIA, NBP, ANP
Q1-'15 Q2-'15 Q3-'15E Q4-'15E 2015E Q1-'16E Q2-'16E Q3-'16E Q4-'16E 2016E 0.7 2.2 0.6 -0.3 0.8 -0.3 0.2 -0.7 -1.0 -0.5 0.9 2.79 62.0 29.5 -0.4 -1.2% 8.7 -0.7 -7.2%
1.1 2.90 62.7 29.6 0.4 1.2% 8.2 -0.6 -6.8%
0.6 2.95 63.5 31.0 0.7 2.4% 9.8 0.1 0.7%
-0.3 2.92 62.6 31.8 1.6 5.2% 10.7 1.3 13.6%
0.6 2.92 62.6 30.5 0.6 1.9% 9.4 0.0 0.3%
-0.1 2.92 64.0 32.1 2.6 8.7% 10.5 1.8 21.2%
0.0 2.92 62.9 32.3 2.7 9.2% 10.3 2.0 24.9%
-0.4 2.88 61.7 35.2 4.2 13.6% 13.2 3.3 34.2%
-0.8 2.81 60.2 35.4 3.7 11.6% 13.3 2.6 24.6%
2017E -0.6
32.6 32.9 2.2 0.3 10.6% 11.3% 10.7 10.9 1.4 0.2 14.4% 1.5%
40
Oil Market Positioning
Money Flows and Positioning: Sidelining Fundamentals When fundamentals get trumped: The summer melt-down was not only about length bailing out. New sellers flocked to both Brent and WTI futures – including the long-end … Positioning in Managed Money (spec category) is very short WTI In the below positioning snapshot for Tuesday 24 August, net length of the MM category is at a 52-week low. Brent positioning is below average, and the combined position is extremely short as well, and that’s for a 52-week span during which it mostly paid to be short … Given the extent and sharpness of the collapse in oil futures we find it at least interesting that there remain a fair number of long MM positions in WTI and Brent contracts (~250,000 contracts for each)
400,000 350,000
300,000 250,000
200,000
Long MM positions
Speaking in a relative sense, more length has come out of the WTI complex
150,000
Shorts
In Brent, however, only about half the long position that was built up from November 2014 through May 2015 has come out …
100,000
More interesting still is the sharp increase in short MM positions since June Clearly waves of speculative selling have come through these markets
Thousands
350 300
250
500 400
200 300
Hi
Average
100
50 Brent MM (contracts)
WTI MM (contracts)
Long MM positions
300,000
Shorts
250,000 200,000 150,000 100,000 50,000
0
0
350,000
Low
200
100
0 Jan-13Apr-13 Jul-13 Oct-13 Jan-14Apr-14 Jul-14 Oct-14 Jan-15Apr-15 Jul-15
400,000
600
Current
150
50,000
Brent Longs added through end-May and have only half left; its shorts arrived already a year ago, left early this year and returned from in May this year
Net-Length of the Managed Money categories is very short Thousands
WTI Longs began to leave in May, shorts piled in from end-June forward
Total Crude MM (contracts)
Source: CS Research, Bloomberg CFTC, ICE
0 Jan-13Apr-13 Jul-13 Oct-13Jan-14 Apr-14 Jul-14 Oct-14 Jan-15Apr-15 Jul-15
42
Money Flow: Selling the Long-Dated Futures Signals from futures – selling down to a lower “new normal” meets buyers Clearly the view that $50 is the new normal is being embraced by speculators with deep pockets. A proxy for future ‘normal’ we think is the long-dated futures market, which has surprising depth and sees a fair amount of daily volume. Go three years out, and not much of that will be commercial either. Brent month 36 (three year out), sold off hard and zig-zagged wildly
In WTI new sellers have gradually raised their game at the long end …
$110
$74
30,000
$100
$70
25,000
$90
$66
20,000
$80
$62
15,000
$70
$58
$60
Last Price
UBB (2)
BollMA (200)
LBB (2)
$50 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15
Emerging two-way trading around puts “oil’s new normal” in play
We have written before that Brent or WTI three year out contracts or the December 2018 contract currently are a fair indicator of what prices replacement barrels will require to be developed. From that perspective it was, we think, significant that long-dated prices did not fall below $65 Brent for any length of time even in the depths of the GFC in early 2009, or earlier this year. That the long end was sold, in the case of Brent all the way down to below $60/b and WTI below $55 was we think more signficant still than the prompt price setting new lows This was also the single biggest “surprise” relative to our January forecast We will be keeping a close eye on the signals coming from the far end of the curve and note, with glee, that it is attracting buyers now as well Source: CS Research, Bloomberg
WTI December 2018 $/b WTI Z18 Open Interest
$54 $50 Jan-15
10,000
5,000
Mar-15
May-15
Jul-15
0 Sep-15
But more aggressive selling has come from speculative selling of Brent 36 $79
30,000
$75
25,000
$71
20,000
$67
15,000
$63
Brent December 2018 $/b Brent z18 Open Interest
$59 $55 Jan-15
10,000
5,000
Mar-15
May-15
Jul-15
0 Sep-15
43
US Natural Gas… A Tale of Two Time-Frames
US Gas: We See Less Medium- or Longer-Term Upside Supply this year is at best flat-lining and probably trending lower, that matters in the shorter term as demand growth for next winter is baked in … Rig counts across the US upstream have fallen and momentum of growth, no surprise, has faded. Nor is activity as yet picking up.
We are headed into an interesting winter 2015-’16, featuring demand growth between 3-5 Bcf/d clashing with lower yoy supply: – Depending on weather, storage will likely deplete to much less than normal
But the shale resource remains fantastic and pricesignals will quickly revive activity. We see activity and production picking up from late this year forward But at more than $3.50-$4 /MMBtu there’d be too much growth given the pacing of demand-capacity adds and the still evolving efficiency of producers
Required supply through the end of the decade can come from the Northeast at $3.75 / MMBtu (or less) We cut our price deck from the middle of next year forward Critically, we drive two-thirds of our required supply growth from the northeast shale basins We project ~20 Bcf/d of US natural gas demand growth, of which 9 Bcf/d are indigenous to the US (power-generation and industry mostly) and the balance involves exports to Mexico and LNG
Source: Credit Suisse Research, Bloomberg
Natural Gas Prices & Forecasts (Actual bidweek & Henry Hub futures)
Period 2011 2012 2013 Q1-2014 Q2-2014 Q3-2014 Q4-2014 2014 Q1-2015 Q2-2015 Q3-2015f Q4-2015f 2015f Q1-2016f Q2-2016f Q3-2016f Q4-2016f 2016f Q1-2017f Q2-2017f Q3-2017f Q4-2017f 2017f 2018f Long-Term
Actuals & CS Forecast $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $
4.03 2.80 3.67 4.90 4.56 4.07 3.96 4.37 2.96 2.67 2.90 3.20 2.93 4.30 4.10 3.50 3.70 3.90 3.70 3.30 3.40 3.60 3.50 3.60 3.75
Prior Forecast
$ $ $ $ $
2.80 2.70 2.90 3.20 2.90 -----
$
4.20 -----
$
4.50 --
$
4.50
Current Futures
$ $ $ $ $ $ $ $ $ $ $ $ $ $ $
2.77 2.94 2.84 3.20 3.04 3.11 3.25 3.15 3.48 3.21 3.27 3.40 3.34 3.42 3.78 45
The Short Term: We Model Storage Fill of Only ~3.9 Tcf Contrary to consensus, we find much less yoy production growth To model end of injection-season storage fill, we assess the YoY shifts in the individual components of supply and demand (including trade) for the period March through October. Summing these shifts yields a one number residual of the underlying YoY difference in Bcf/d, which is either negative (bullish natural gas prices) or positive (bearish natural gas prices). We then use a history of weekly degree day totals for each of the last 15 injection seasons, which yields weather driven injection tracks. We eliminate the extremes at either end average the remaining thirteen for our central or weather normalized base-case forecast of end-of-season storage. The most important forecast component is the year-over-year growth of dry gas production, which we project will decelerate from 5.4 Bcf/d in April to +0.6 Bcf/d in October; thus averaging 2.0 Bcf/d this injection season. The shifts in trade are in line with recent trends: Imports from Canada are no longer falling; Exports to Mexico should on average grow by +0.8 Bcf/d.
We model a -2.6 Bcf/d residual, which is the sum of the underlying changes in supply and demand. That bullish residual yields a below consensus projected end of season storage fill of than 3.85 Tcf 4,000
Bcf
We plugged in -0.1 Bcf for the LNG component to reflect a 1 Bcf/d jump in exports in October – because even if a tanker does not leave, there will be a drain on supply or a diversion from storage just to fill and test facilities.
3,600
The key demand-variable: Gas burn for power generation is up +3.3 Bcf/d yoy, partly because coal fired power is coming off line, but mostly due to price.
3,200
3877
Summer range
Avg Track
Storage was filling fast in Q2, but momentum is slowing 4000
3877
Bcf
2,800
3500
Summer 2015 Residual (yoy in Bcf/d) CS Base Case Production 2.5 Imports/(exports) LNG -0.1 Mex Exports -0.8 Canada 0.0 Demand Power Gen 3.3 Industrial 0.7 Other 0.2 "Residual" (2.6)
2,400
3000 2500
2,000
10 yr range
2000
2015e 1500
2014-'15 10 yr avg
1000
2013-'14 500 Oct-14
1,600
Dec-14
Feb-15
Apr-15
Jun-15
Aug-15
Oct-15
1,200 Apr
May
Source: DoE Energy Information Agency, Bloomberg, Credit Suisse Research
May
Jun
Jul
Aug
Sep
Oct
46
Next Winter Should Set Up Fundamentally Different If we are correct, then the aggregate of shifts in the underlying fundamentals would be a 7 Bcf/d (bullish) difference from last winter … As a reminder, to model end of injection-season storage fill, we assess the YoY shifts in the individual components of supply and demand (including trade) for the period November through March. Summing these shifts yields a one number residual of the underlying YoY difference in Bcf/d, which is either negative (bullish natural gas prices) or positive (bearish natural gas prices). We then use a history of weekly degree day totals for each of the last 15 injection seasons, which yields weather driven injection tracks. We eliminate the extremes at either end average the remaining thirteen for our central or weather normalized base-case forecast of end-of-season storage.
We model a -7 Bcf/d residual, which is the sum of the underlying changes in supply and demand. That bullish residual yields a below consensus projected end of season storage fill of less than 3.8 Tcf 4,000 14-yr range 3,500
The most important forecast component is the year-over-year growth of dry gas production, which we project will fall to -0.5 Bcf/d in November and 4.3Bcf/d by next March.
3,000
– Production should then rebound to +2.5 Bcf/d of growth by year-end 2016 as well.
2,500
The shifts in trade add up too: Imports from Canada should barely fall, but we plugged in -0.4 Bcf/d of LNG exports and a full 1 Bcf/d of incremental exports to Mexico.
2,000
Base load demand growth is assessed in line with capacity-of- use growth across different industrial sectors and replacement of coal-fired power generating capacity in the power sector.
As a result of all this, storage at the end of next winter projects to barely 1 Tcf, and in the case of a cold winter too little gas would be available – clearly higher prices will need to curb some of these fundamental trajectories…
2015-'16 fcst
Actual
1,500
1,000
Winter 2015-'16 Residual (In Bcf/d) CS Base Case Production Imports/(exports) LNG Mex Exports Canada Demand Power Gen Industrial Other
"Residual"
500 Nov-15
Source: DoE Energy Information Agency, Bloomberg, Credit Suisse Research
Dec-15
(2.7) (0.4) (1.0) (0.1) 1.7 1.1 0.1 (7.0)
Jan-16
Feb-16
Mar-16
47
Our Natural S&D Gas Balance Through 2018
(Bcfd) Gross Gas Production Conventional** Offshore (GOM)** Unconventional** North East Marcellus Utica Haynesville Oil and/or NGLs driven Eagle Ford Permian Niobrara Bakken Other Shale Coalbed Methane Dry Gas Production* Extraction Loss + Processing Shrink Canadian Imports (Net) Mexican Exports (Net) LNG Imports (Net) Total Supply Industrial Electric Power Res/Comm Other (Lease Fuel, Pipeline Distribution) Total Demand
2012 80.7 43.9 4.2 36.8 7.8 7.7 0.2 9.8 13.8 4.0 4.4 4.7 0.7 1.1 4.2 65.7 15.1 5.4 -1.7 0.4 69.8 19.8 24.9 19.3 5.9 69.8
2013 82.2 40.8 3.6 41.4 11.6 11.2 0.4 7.7 15.4 5.3 4.8 4.4 1.0 2.8 3.9 66.7 15.5 5.1 -1.8 0.3 70.3 20.3 22.3 22.5 6.5 71.7
Q1/2014 Q2/2014 Q3/2014 Q4/2014 85.2 86.2 86.9 91.2 41.7 41.0 39.3 42.6 3.3 3.5 3.5 3.4 43.5 45.1 47.6 48.6 14.3 15.0 16.2 17.5 13.4 13.9 14.6 15.6 0.9 1.1 1.5 1.9 6.6 6.7 6.6 6.5 16.4 17.6 18.3 18.9 5.8 6.4 6.6 6.8 5.2 5.6 5.9 6.1 4.3 4.5 4.5 4.6 1.1 1.2 1.4 1.5 2.8 2.4 3.3 2.6 3.4 3.4 3.3 3.2 67.8 69.3 71.3 73.3 17.4 16.8 15.6 17.9 5.6 4.6 4.8 5.4 -1.8 -2.0 -2.2 -2.0 0.1 0.2 0.1 0.1 71.7 72.1 74.0 76.9 22.9 20.0 19.7 21.3 19.7 21.1 27.3 21.1 45.2 13.8 8.3 26.7 7.3 6.3 6.5 7.1 95.2 61.3 61.7 76.2
2014 87.4 41.1 3.4 46.2 15.7 14.4 1.3 6.6 17.8 6.4 5.7 4.5 1.3 2.8 3.3 70.4 16.9 5.1 -2.0 0.1 73.7 21.0 22.3 23.5 6.8 73.6
Q1/2015 Q2/2015 Q3/2015 Q4/2015 90.0 91.0 91.2 91.9 40.0 39.1 36.6 38.2 3.4 3.7 3.6 3.5 50.1 50.7 51.0 50.2 18.4 19.0 19.1 19.6 16.1 16.5 16.4 16.9 2.3 2.6 2.7 2.6 6.6 6.8 6.7 6.7 19.6 19.8 19.3 18.7 7.1 7.2 7.0 6.6 6.3 6.4 6.4 6.3 4.7 4.7 4.5 4.4 1.5 1.5 1.5 1.4 2.7 2.5 3.2 2.7 2.7 2.7 2.6 2.6 73.6 73.5 72.8 72.1 16.4 17.5 18.4 19.8 5.8 5.1 4.8 5.1 -2.3 -2.8 -3.0 -3.1 0.4 0.1 0.1 -0.3 77.4 75.9 74.6 73.8 22.7 20.0 19.9 22.3 23.1 25.4 31.0 23.1 43.7 12.4 7.4 27.7 7.8 6.7 6.7 7.3 97.3 64.4 65.0 80.4
Source: EIA, Bloomberg, Credit Suisse Research
2015 91.0 38.5 3.5 50.5 19.0 16.5 2.5 6.7 19.4 7.0 6.3 4.6 1.5 2.8 2.7 73.0 18.0 5.2 -2.8 0.1 75.4 21.2 25.7 22.8 7.1 76.8
Q1/2016 Q2/2016 Q3/2016 Q4/2016 90.6 91.1 90.9 94.1 37.3 36.5 34.0 35.6 3.4 3.6 3.5 3.5 50.0 51.0 53.4 55.0 20.1 20.6 21.8 23.0 17.4 17.7 18.4 19.1 2.7 3.0 3.4 3.9 6.6 6.8 7.0 7.1 18.3 18.5 19.2 19.9 6.4 6.5 6.8 7.1 6.3 6.4 6.7 6.9 4.2 4.2 4.3 4.3 1.4 1.4 1.5 1.5 2.5 2.6 3.1 2.7 2.4 2.4 2.4 2.3 70.0 70.9 72.6 74.2 20.6 20.1 18.3 19.8 5.6 4.6 5.0 5.3 -3.2 -3.3 -3.3 -3.2 -0.5 -0.5 -0.5 -1.0 71.8 71.7 73.7 75.4 23.8 20.9 20.6 22.2 24.7 24.1 30.3 24.3 35.7 13.1 7.5 27.7 7.8 6.7 6.7 7.3 92.1 64.8 65.0 81.5
2016 91.7 35.8 3.5 52.3 21.4 18.1 3.2 6.9 18.9 6.7 6.6 4.2 1.4 2.7 2.4 71.9 19.7 5.1 -3.3 -0.6 73.2 21.9 25.9 21.0 7.1 75.9
Q1/2017 Q2/2017 Q3/2017 Q4/2017 95.4 97.2 97.1 100.7 35.2 34.5 32.0 33.7 3.3 3.5 3.4 3.4 56.9 59.2 61.7 63.6 24.2 25.6 26.9 28.2 19.8 20.6 21.4 22.2 4.4 4.9 5.5 6.0 7.3 7.5 7.6 7.8 20.6 21.3 22.0 22.8 7.5 7.8 8.2 8.5 7.2 7.5 7.8 8.2 4.3 4.4 4.4 4.5 1.5 1.5 1.6 1.6 2.6 2.7 3.0 2.7 2.2 2.2 2.1 2.1 74.6 76.8 78.5 80.5 20.8 20.4 18.6 20.2 5.6 4.6 5.0 5.3 -3.5 -3.8 -3.8 -3.6 -1.5 -2.0 -2.0 -3.0 75.2 75.6 77.7 79.2 24.5 21.6 21.3 22.9 25.5 26.8 33.0 25.7 36.0 13.1 7.5 27.7 8.0 6.9 6.9 7.5 94.1 68.4 68.6 83.8
2017 97.6 33.8 3.4 60.3 26.2 21.0 5.2 7.6 21.7 8.0 7.7 4.4 1.6 2.8 2.2 77.6 20.0 5.1 -3.7 -2.1 76.9 22.6 27.8 21.1 7.3 78.7
2018 104.8 32.3 3.2 69.3 31.6 24.2 7.4 8.3 24.8 9.5 9.0 4.6 1.7 2.8 1.9 84.6 20.3 5.1 -4.4 -4.0 81.3 23.3 28.6 21.1 7.5 80.5
48
NGLs De-Linked and Re-Linked
Surging Supplies Have Collapsed NGL Markets Going forward, we think that Ethane stays connected to Henry Hub gas while LPGs and heavier NGLs should (re-)connect with global oil The key for Ethane remains the overwhelmingly large cut of this precious liquids in the Marcellus and Utica. Its use is limited and infrastructure expensive. In our view, new demand is expensive and takes time to build out leading to a structurally oversupplied market, barring a lasting supply shift. In a similar way, LPG prices fell to new record lows – on a relative-to-WTI/naphtha basis – this year. Surging supplies have simply saturated North American capacity-of-use. Infrastructure and export capacity build-out is underway, however. So, different to Ethane, international oil-linked chemical and utility markets are a fairly in-expensive tanker voyage away.
NGL Prices & Forecasts (Actual bidweek) NGL NGL Ethane As % of Propane Butane Pentane Composite As % of Composite As % of Period
(cts/gl)
Ngas
(cts/gl) (cts/gl) (cts/gl) Mt Belvieu
2013
27
99%
101
137
217
Q1-2014 Q2-2014
32 29
89% 88%
125 106
132 124
Q3-2014 Q4-2014
24 21
79% 73%
103 71
2014 Q1-2015
27 19
83% 87%
Q2-2015 Q3-2015f
19 19
Q4-2015f 2015f 2016f
Excruciatingly simple S&D dynamics Field supply of NGLs is surging in line with natural gas production from the Utica, Marcellus and Eagle Ford plays especially. However, given expensive transport and storage, demand for ethane and propanes especially is rather limited and requires large investment on long lead times to expand
WTI
Northeast
WTI
$30.78
32%
$25.74
26%
224 223
$34.48 $31.62
34% 31%
$29.44 $26.58
29% 26%
3000
121 90
210 139
$29.17 $21.43
31% 32%
$24.13 $16.39
25% 25%
2500
101 54
117 63
199 125
$29.18 $17.06
32% 35%
$24.14 $12.02
26% 25%
2000
96% 95%
48 32
59 54
127 102
$17.06 $14.05
29% 31%
$12.02 $9.01
20% 20%
1500
22 20 27
95% 93% 95%
31 41 42
51 57 64
97 113 122
$14.35 $15.63 $18.16
33% 32% 34%
$9.31 $10.59 $13.12
22% 22% 24%
1000
2017f 2018f
24 26
95% 98%
57 70
71 77
136 147
$19.79 $22.06
33% 34%
$15.72 $17.98
26% 28%
Long-Term
27
98%
83
92
158
$24.73
35%
$20.65
30%
Source: EIA, Bloomberg, Credit Suisse Research
LPG S&D trends point to growing pressure to export – and we exclude the m ore flexible supply of LPGs from refiners (Kb/ d)
field supply
domestic demand
exports
500 0 Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
Jan-15
50
Details of the composition of our NGLs forecast Clearly all American NGLs prices have hit lows relative to history and relative to oil or gas markets. And a representative composite Northeast NGLs barrel has fallen to below 30% of WTI prices. We expect only a slow and tentative recovery of the major components of that composite barrel’s worth in Mount Belvieu, TX, by next year. And that over time, by 2018 the composite reaches 33% again. The story is worse when considering net backs to Northeast producers, whose cost of transport of ethane especially has eroded the value of that NGL barrel to barely 20% of WTI. – A recovery to that Northeast netback hinges on transport infrastructure. We assume that propane’s transport costs should fall to ~4 cents/gallon after next year. And that even for Northeast producers the composite barrels worth reaches near 30% of WTI again in the longer run.
History and assumptions and linkages and our forecast of the different components of US NGLs 2014 Location
Unit
Natural Gas
Henry Hub
$/MMBtu share
Ethane
Mt Belvieu
cts/gl
57%
(as % of Ngas) (ref as % of WTI) Propane
Mt Belvieu
cts/gl
23%
(as % of WTI) Butane (+iso)
Mt Belvieu
cts/gl
11%
(as % of WTI) Pentane
Mt Belvieu
cts/gl
9%
(as % of WTI) NGL Composite
Mt Belvieu
(as % of WTI) NE NGL Composite*
$/b
100%
2017
2018
Q1
Q2
Q3
Q4
Avg
Q1
Q2
Q3
Q4
Avg (e)
2015 Q1
Q2
Q3
Q4
Avg (e)
2016 Q1
Q2
Q3
Q4
Avg (e)
Avg (e)
LR LR
$4.90
$4.56
$4.07
$3.96
$4.37
$2.96
$2.67
$2.77
$3.20
$2.90
$4.30
$4.10
$3.50
$3.70
$3.90
$3.70
$3.30
$3.40
$3.60
$3.50
$3.60
$3.75
32
29
24
21
27
19
19
19
22
20
30
29
24
26
27
26
23
24
25
24
26
27
89%
88%
79%
73%
83%
87%
96%
95%
95%
93%
95%
95%
95%
95%
95%
95%
95%
95%
95%
95%
98%
98%
13%
12%
10%
13%
12%
16%
13%
18%
22%
17%
27%
22%
18%
18%
21%
18%
16%
17%
18%
17%
17%
16%
125
106
103
71
101
54
48
32
31
41
33
39
48
49
42
57
57
57
57
57
70
83
52%
44%
45%
45%
47%
46%
33%
30%
30%
35%
30%
30%
35%
35%
33%
40%
40%
40%
40%
40%
45%
50%
132
124
121
90
117
63
59
54
51
57
55
64
68
70
64
71
71
71
71
71
77
92
55%
51%
53%
56%
54%
55%
41%
50%
50%
49%
50%
50%
50%
50%
50%
50%
50%
50%
50%
50%
50%
55%
224
223
210
139
199
125
127
102
97
113
104
122
129
133
122
136
136
136
136
136
147
158
93%
91%
93%
88%
91%
108%
89%
95%
95%
98%
95%
95%
95%
95%
95%
95%
95%
95%
95%
95%
95%
95%
$34
$32
$29
$21
$29
$17
$17
$14
$14
$16
$17
$18
$18
$19
$18
$20
$19
$20
$20
$20
$22
$25
34%
31%
31%
32%
32%
35%
29%
31%
33%
32%
37%
34%
32%
33%
34%
34%
32%
33%
33%
33%
34%
35%
$29
$27
$24
$16
$24
$12
$12
$9
$9
$11
$12
$13
$13
$14
$13
$16
$15
$16
$16
$16
$18
$21
29%
26%
25%
25%
26%
25%
20%
20%
22%
22%
26%
24%
24%
24%
24%
27%
26%
26%
26%
26%
28%
30%
NE ethane transport assumption
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
NE propane transport assumption
15
15
15
15
15
15
15
15
15
15
15
15
15
15
15
5
5
5
5
5
5
5
$101
$103
$95
$67
$91
$49
$60
$45
$43
$49
$46
$54
$57
$59
$54
$60
$60
$60
$60
$60
$65
$70
(as % of WTI)
WTI
Cushing
Source: EIA, Bloomberg, Credit Suisse Research
51
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Rating
Versus universe (%)
Of which banking clients (%)
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