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OIL
Medium-Term
Market Report
2016
Market Analysis and Forecasts to 2021
Please note that this PDF is subject to
specific restrictions that limit its use and
distribution. The terms and conditions are
available online at http://www.iea.org/t&c
OIL
Medium-Term
Market Report
2016
Check out the new and improved Oil Market Report website!
The IEA has redesigned and improved its
online Oil Market Report (OMR), making it
easier for subscribers and non-subscribers to
get important information from the site.
The OMR site — https://www.iea.org/
oilmarketreport/ — now offers more powerful
search options and a fully indexed archive of
reports going back to 1990. The improved
OMR also features interactive graphics as
part of each monthly issue.
First published in 1983, the OMR provides the
IEA view of the state of the international oil
market, with projections for oil supply and
demand 6 to 18 months ahead. For more
information on subscribing to the OMR,
please visit https://www.iea.org/
oilmarketreport/subscription/.
Market Analysis and Forecasts to 2021
INTERNATIONAL ENERGY AGENCY
The International Energy Agency (IEA), an autonomous agency, was established in November 1974.
Its primary mandate was – and is – two-fold: to promote energy security amongst its member
countries through collective response to physical disruptions in oil supply, and provide authoritative
research and analysis on ways to ensure reliable, affordable and clean energy for its 29 member
countries and beyond. The IEA carries out a comprehensive programme of energy co-operation among
its member countries, each of which is obliged to hold oil stocks equivalent to 90 days of its net imports.
The Agency’s aims include the following objectives:
n Secure member countries’ access to reliable and ample supplies of all forms of energy; in particular,
through maintaining effective emergency response capabilities in case of oil supply disruptions.
n Promote sustainable energy policies that spur economic growth and environmental protection
in a global context – particularly in terms of reducing greenhouse-gas emissions that contribute
to climate change.
n Improve transparency of international markets through collection and analysis of
energy data.
n Support global collaboration on energy technology to secure future energy supplies
and mitigate their environmental impact, including through improved energy
efficiency and development and deployment of low-carbon technologies.
n Find solutions to global energy challenges through engagement and
dialogue with non-member countries, industry, international
organisations and other stakeholders.
© OECD/IEA, 2016
International Energy Agency
9 rue de la Fédération
75739 Paris Cedex 15, France
www.iea.org
IEA member countries:
Australia
Austria
Belgium
Canada
Czech Republic
Denmark
Estonia
Finland
France
Germany
Secure
Greece
Sustainable
Hungary
Together
Ireland
Italy
Japan
Korea
Luxembourg
Netherlands
New Zealand
Norway
Poland
Portugal
Slovak Republic
Spain
Sweden
Switzerland
Turkey
United Kingdom
United States
Please note that this publication
is subject to specific restrictions
that limit its use and distribution.
The terms and conditions are
available online at www.iea.org/t&c/
The European Commission
also participates in
the work of the IEA.
F OREWO RD
FOREWORD
The oil market has changed dramatically since we published the 2015 edition of our Medium Term Oil
Market Report (hereafter referred to ‘MTOMR’). A year later, after another twelve months of
relentless stock-building, the date of the re-balancing of the oil market has been pushed back to the
early part of 2017.
As a consequence of this prolonged market glut – the three consecutive years of stock building in
2014-2016 are exceeded in recent history only by the five consecutive years from 1994 onwards - oil
prices have fallen to levels last seen in 2003. Our analysis of the oil market fundamentals at the start
of 2016 is clear that in the short term there is unlikely to be a significant increase in prices.
Such has been the extraordinary volatility in oil markets that it has become more difficult than ever
to forecast even as soon as five years ahead. In taking on this task the analysts in our Oil Industry and
Markets Division have used as the starting point the regular updates published in our monthly Oil
Market Report and added to them our analysis of the key factors that make today’s response to a
price collapse so different from earlier episodes seen in 1986, 1998 and 2008.
Although oil priced at USD 30/bbl has already postponed huge swathes of investment in important
capacity projects both in 2015 and 2016, the eventual recovery in oil prices that will follow the rebalancing of the oil market will bring them back into play. The price of oil will not need to recover to
the USD 100/bbl level we saw from early in 2011 to mid-2014 to allow this to happen. Today, we are
in an era where abundant resources of oil can be brought to market at costs lower than thought
possible just a few years ago. This implies that although oil prices should start to rise gradually, the
availability of new supply will place a cap on how far and how fast they can go. That is unless there is
an unexpected growth spurt in demand or a major geopolitical incident.
The 2016 MTOMR takes into account the gradual slowdown in the rate of oil demand growth and the
intense competition amongst producers for their share of the market. We discuss the re-balancing of
the oil market and suggest the time period and pace during which oil stocks will fall and allow oil
prices to rise.
At this extraordinary juncture in the history of the oil industry the Report is more useful and timely
than ever and is required reading for all analysts and commentators.
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
3
© OECD/IEA, 2016
Dr. Fatih Birol
Executive Director
International Energy Agency
ACKNOWLEDGEMENTS
ACKNOWLEDGEMENTS
This publication was prepared by the Oil Industry and Markets Division (OIMD) of the International
Energy Agency (IEA). Its main authors are, Olivier Abadie, Toril Bosoni, Peg Mackey, Matthew Parry,
Kristine Petrosyan and Andrew Wilson. Valerio Pilia and Ryszard Pospiech provided essential research
and statistical support. Deven Mooneesawmy provided editorial assistance. Neil Atkinson, Head of
OIMD, edited the Report. Keisuke Sadamori, director of the IEA’s Directorate of Energy Markets and
Security, provided guidance.
Other IEA colleagues provided important contributions including Ali Al-Saffar, Chris Besson, Pierpaolo
Cazzola, Kate Dourian, Marc-Antoine Eyl-Mazzega, Nathan Frisbee, Tim Gould, Timur Guel, Jon
Hansen, Shelly Hsieh, Costanza Jacazio, Fabian Kesicki, Florian Kitt, Pharoah Le Feuvre, Christopher
McGlade, Ugbizi Banbeshie Ogar, Pawel Olejarnik, Toshiyuki Shirai and Shuwei Zhang
The IEA Communications and Information Office provided production assistance and support.
Particular thanks to Rebecca Gaghen and her team; Muriel Custodio, Adrien Chorlet, Astrid Dumond,
Greg Frost, Katie Russell, Bertrand Sadin and Therese Walsh.
4
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
© OECD/IEA, 2016
For questions and comments, please contact the Oil Industry and Markets Division.
For contact information, please see https://www.iea.org/oilmarketreport/contacts/.
T ABLE OF CONTENTS
TABLE OF CONTENTS
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
5
© OECD/IEA, 2016
FOREWORD ............................................................................................................................................. 3
ACKNOWLEDGEMENTS........................................................................................................................... 4
TABLE OF CONTENTS .............................................................................................................................. 5
OVERVIEW............................................................................................................................................... 9
1. DEMAND ........................................................................................................................................... 13
Summary ........................................................................................................................................... 13
Overview ........................................................................................................................................... 14
OECD demand ................................................................................................................................... 18
Non-OECD demand ........................................................................................................................... 23
Africa ............................................................................................................................................. 27
Asia ................................................................................................................................................ 27
Former Soviet Union ..................................................................................................................... 32
Latin America................................................................................................................................. 33
Middle East .................................................................................................................................... 34
2. SUPPLY .............................................................................................................................................. 41
Trends in global oil supply ................................................................................................................. 42
Non-OPEC supply overview ............................................................................................................... 44
United States ................................................................................................................................. 46
Canada ........................................................................................................................................... 50
Caspian .......................................................................................................................................... 53
Latin America................................................................................................................................. 55
Mexico ........................................................................................................................................... 56
North Sea ....................................................................................................................................... 58
Africa ............................................................................................................................................. 60
Asia ................................................................................................................................................ 61
Australia......................................................................................................................................... 62
Non-OPEC Middle East .................................................................................................................. 62
OPEC .................................................................................................................................................. 63
OPEC gas liquids supply ................................................................................................................. 76
3. CRUDE TRADE ................................................................................................................................... 83
Summary ........................................................................................................................................... 83
Overview and methodology .............................................................................................................. 84
Selected regional developments ....................................................................................................... 86
The Middle East to remain the world largest exporter ................................................................. 86
FSU to continue its pivot eastwards .............................................................................................. 87
OECD Americas to remain a net importer ..................................................................................... 88
Domestic refinery expansion to curb Latin American exports ...................................................... 90
African crude exports to be squeezed and marketing problems to continue .............................. 91
Non-OECD Asian imports to surge in line with demand growth ................................................... 91
OECD Europe to cut back imports in line with refinery rationalisation ........................................ 92
4. REFINING ........................................................................................................................................... 95
Summary ........................................................................................................................................... 95
Overview ........................................................................................................................................... 95
Refining sector outlook ..................................................................................................................... 96
T ABLE OF CONTENTS
Regional developments ..................................................................................................................... 97
OECD .............................................................................................................................................. 97
The Americas marginally adapt to lighter feedstocks ................................................................... 98
Asia Pacific: consolidation in still on the books ............................................................................. 98
Europe enjoys margins while they last.......................................................................................... 99
Non-OECD adds most of refining capacity .................................................................................. 101
China takes steps toward deregulation....................................................................................... 101
Other Non-OECD Asia a major contributor to growth ................................................................ 104
The Middle East continues with ambitious plans........................................................................ 104
Non-OECD Americas hit by macroeconomic woes...................................................................... 105
Russia digests the latest tax manoeuver ..................................................................................... 105
Africa expansion depends on Nigeria .......................................................................................... 106
Product supply balances.................................................................................................................. 107
OECD Americas ............................................................................................................................ 107
Russia ........................................................................................................................................... 108
The Middle East ........................................................................................................................... 108
China ............................................................................................................................................ 109
Other Asia .................................................................................................................................... 109
Non-OECD Americas .................................................................................................................... 110
Africa ........................................................................................................................................... 110
5. TABLES ............................................................................................................................................. 111
LIST OF BOXES
Box 1.1 Robust petrochemical demand set to hold through 2021 ...................................................... 16
Box 1.2 Escalating vehicle efficiencies underpin more subdued demand forecasts ........................... 19
Box 1.3 Oil price declines could drive reform of fossil fuel subsidies .................................................. 24
Box 1.4 Key Southeast Asian oil demand trends .................................................................................. 30
Box 1.5 Marine gasoil to seize bunker fuel market share .................................................................... 36
Box 2.1 Upstream spending set to take another hit in 2016 ................................................................ 43
Box 2.2 Non-OPEC outlook uncertainty: a wide range of possibilities ................................................ 45
Box 2.3 The rise, fall and rise again of US LTO ..................................................................................... 47
Box 2.4 Fading Russian resilience......................................................................................................... 52
Box 2.5 Guyana to join the oil club – Falklands Islands next?.............................................................. 56
Box 2.6 Iran unrestricted...................................................................................................................... 64
Box 3.1 Stock changes to influence crude oil trade over the medium-term ....................................... 85
Box 3.2 US exports to remain low ........................................................................................................ 89
Box 3.3 Renewed earnings brighten shippers prospects ..................................................................... 93
Box 4.1 Refining margins – where from here?..................................................................................... 99
Box 4.2 China teapot refineries .......................................................................................................... 103
Box 4.3 Nigerian downstream paradox.............................................................................................. 106
Figure ES 1 Global balance base case ................................................................................................... 10
Figure 1.1 Global oil demand growth, by product, 2001-21 ................................................................ 14
Figure 1.2 Cumulative US oil demand growth, 2001-21 ..................................................................... 18
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M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
© OECD/IEA, 2016
LIST OF FIGURES
T ABLE OF CONTENTS
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
7
© OECD/IEA, 2016
Figure 1.3 Non-OECD consumers lead gasoline demand growth, 2001-21 ........................................ 20
Figure 1.4 European oil demand, 2009-21 .......................................................................................... 21
Figure 1.5 OECD road transport demand, 2009-21 ............................................................................. 22
Figure 1.6 Relative non-OECD/OECD oil demand growth discrepancies, 2013-21 ............................. 22
Figure 1.7 Non-OECD oil demand mix, 2015 and 2021 ....................................................................... 23
Figure 1.8 Chinese oil demand, 2009-21 ............................................................................................. 28
Figure 1.9 Cumulative Indian oil demand growth, 2001-21................................................................ 29
Figure 1.10 Brazilian oil demand, 2009-21........................................................................................... 34
Figure 1.11 Cumulative demand growth, 2001-21 .............................................................................. 35
Figure 1.12 Oil based marine fuel consumption in international navigation ...................................... 36
Figure 1.13 Discount of natural gas delivered at United Kingdom National balancing
point to Rotterdam gasoil and fuel oil barge prices ......................................................... 38
Figure 2.1 Global liquids supply growth ............................................................................................... 42
Figure 2.2 Global liquids growth 2015-21 ............................................................................................ 42
Figure 2.3 Producer costs .................................................................................................................... 42
Figure 2.4 Oil capex by region .............................................................................................................. 43
Figure 2.5 Annual change in capex....................................................................................................... 43
Figure 2.6 Selected sources of non-OPEC supply changes, 2015-21 ................................................... 44
Figure 2.7 Non-OPEC production scenarios and impact on global inventories ................................... 46
Figure 2.8 US oil production ................................................................................................................. 46
Figure 2.9 US LTO production .............................................................................................................. 47
Figure 2.10 Spudded, completed horizontal wells and drilled, uncompleted inventory..................... 47
Figure 2.11 Average US shale play well performance .......................................................................... 48
Figure 2.12 Average daily production by shale play - 2015 production start year .............................. 48
Figure 2.13 Canada oil production ....................................................................................................... 51
Figure 2.14 Canada oil supply growth .................................................................................................. 51
Figure 2.15 Russian oil production ....................................................................................................... 52
Figure 2.16 Brent price index in USD vs roubles .................................................................................. 52
Figure 2.17 Kazakhstan oil production ................................................................................................. 54
Figure 2.18 Azerbaijan oil production .................................................................................................. 54
Figure 2.19 Brazil oil production .......................................................................................................... 55
Figure 2.20 Total non-OPEC Latin America oil production................................................................... 55
Figure 2.21 Mexico oil production ....................................................................................................... 57
Figure 2.22 North Sea oil production ................................................................................................... 58
Figure 2.23 Norway oil production ...................................................................................................... 59
Figure 2.24 UK oil production .............................................................................................................. 59
Figure 2.25 African oil production growth ........................................................................................... 60
Figure 2.26 China oil production .......................................................................................................... 62
Figure 2.27 Iran crude capacity scenarios ............................................................................................ 64
Figure 2.28 Selected crude oil export streams by quality .................................................................... 64
Figure 2.29 Iraq crude capacity ............................................................................................................ 69
Figure 2.30 UAE crude capacity............................................................................................................ 70
Figure 2.31 West African crude capacity.............................................................................................. 74
Figure 2.32 Global biofuels production 2014-21 ................................................................................. 78
Figure 2.33 Global examples of commercial-scale advanced biofuel plants ....................................... 82
Figure 3.1 Regional crude exports, yearly change ............................................................................... 83
T ABLE OF CONTENTS
Figure 3.2 Regional crude imports yearly change ................................................................................ 83
Figure 3.3 Global demand / supply balance......................................................................................... 85
Figure 3.4 Middle East export growth, 2015-21 .................................................................................. 87
Figure 3.5 FSU export growth, 2015-21 ............................................................................................... 87
Figure 3.6 Chinese crude imports, 2015 .............................................................................................. 92
Figure 3.7 Chinese crude imports, 2021 .............................................................................................. 92
Figure 3.8 Earnings on benchmark routes ........................................................................................... 93
Figure 3.9 Order book .......................................................................................................................... 93
Figure 4.1 Changes in regional demand and refining capacity ............................................................ 97
Figure 4.2 Regional cracking margins ................................................................................................... 99
Figure 4.3 Margin dynamics ................................................................................................................. 99
Figure 4.4 Europe middle distillates stocks ........................................................................................ 100
Figure 4.5 NWE ULSD barges crack vs Brent ...................................................................................... 100
Figure 4.6 Global y-o-y demand growth ............................................................................................ 100
Figure 4.7 OECD demand growth ....................................................................................................... 100
Figure 4.8 Share of imports in crude throughputs ............................................................................. 102
Figure 4.9. Nigeria oil sector at a glance ............................................................................................ 106
LIST OF MAPS
Map 1.1
Map 2.1
Map 2.2
Map 2.3
Map 3.1
Map 4.1
Map 4.2
Map 4.3
Global oil demand growth, by region, 2001-21 ..................................................................... 14
Iran oil and gas fields ............................................................................................................. 65
Iraq oil infrastructure ............................................................................................................. 68
Libya oil infrastructure ........................................................................................................... 73
Crude exports in 2021 and growth in 2015-21 for key trade routes ..................................... 84
Regional product supply balances in 2015 and 2021 - gasoline/naphtha ........................... 107
Regional product supply balances in 2015 and 2021 - gasoil/kerosene.............................. 108
Regional product supply balances in 2015 and 2021 - fuel oil ............................................ 109
LIST OF TABLES
8
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
© OECD/IEA, 2016
Table ES.1 Global balance summary .................................................................................................... 10
Table 1.1 Global oil demand, 2015-21 ................................................................................................. 13
Table 1.2 Global GDP growth forecast ................................................................................................. 15
Table 1.3 United States vehicle fuel economy, litres per 100 km ........................................................ 19
Table 1.4 Recent subsidy adjustments ................................................................................................ 25
Table 1.5 African oil demand, 2015-21 ................................................................................................ 27
Table 1.6 Former Soviet Union oil demand, 2015-21 .......................................................................... 33
Table 1.7 Middle East oil demand, 2015-21......................................................................................... 35
Table 2.1 Non-OPEC supply .................................................................................................................. 45
Table 2.2 Estimated sustainable crude production capacity ............................................................... 63
Table 2.3 Iran key IPC oil and gas projects ........................................................................................... 67
Table 2.4 Estimated OPEC condensate and NGL production ............................................................... 77
Table 4.1 Total demand and call on refineries ..................................................................................... 96
Table 4.2 Global refining capacity and runs ......................................................................................... 97
Table 4.3 Regional developments in capacity and runs ....................................................................... 98
O VERVIEW
OVERVIEW
Attempting to understand how the oil market will look during the next five years is today a task of
enormous complexity. Some certainties that have guided our past outlooks are now not so certain at
all: that oil prices falling to twelve-year lows will lead to a strong demand growth spurt; that oil prices
falling to twelve-year lows will lead to a mass shut-in of so-called high cost oil production; and not
least that oil prices falling to twelve-year lows will force the largest group of producing countries to
cut output to stabilise oil prices.
For some time now analysts have tried to understand when the oil market will return to balance. A
year ago it was widely believed that this would happen by the end of 2015 but that view has proved
to be very wide of the mark. In 2014 and again in 2015 supply exceeded demand by massive margins,
0.9 mb/d and 2 mb/d respectively, and for 2016 we expect a further build of 1.1 mb/d. Only in 2017
will we finally see oil supply and demand aligned but the enormous stocks being accumulated will act
as a dampener on the pace of recovery in oil prices when the market, having balanced, then starts to
draw down those stocks. Unless we see an even larger than expected fall in non-OPEC oil production
in 2016 and/or a major demand growth spurt it is hard to see oil prices recovering significantly in the
short term from the low levels prevailing at the time of publication of this report.
It is very tempting, but also very dangerous, to declare that we are in a new era of lower oil prices.
But at the risk of tempting fate, we must say that today’s oil market conditions do not suggest that
prices can recover sharply in the immediate future – unless, of course, there is a major geopolitical
event. Further, it is becoming even more obvious that the prevailing wisdom of just a few years ago
that “peak oil supply” would cause oil prices to rise relentlessly as output struggled to keep pace with
ever-rising demand was wrong. Today we are seeing not just an abundance of resources in the
ground but also tremendous technical innovation that enables companies to bring oil to the market.
Added to this is a remorseless downward pressure on costs and, although we are currently seeing
major cutbacks in oil investments, there is no doubt that many projects currently on hold will be reevaluated and will see the light of day at lower costs than were thought possible just a few years ago.
The world of peak oil supply has been turned on its head, due to structural changes in the economies
of key developing countries and major efforts to improve energy efficiency everywhere.
Since 2014 the non-OECD countries have used more oil than OECD countries and the gap will widen
in years to come. However, the rate of demand growth in the non-OECD countries is vulnerable to
being pared back as the cost of energy subsidies becomes a major burden and governments take
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
9
© OECD/IEA, 2016
In the meantime, our forecast for oil demand to 2021 is for annual average growth of 1.2 mb/d
(1.2%) which represents a very solid outlook in historical terms. Oil demand breaks through the
100 mb/d barrier at some point in 2019 or 2020. A major change from the 2015 MTOMR is the higher
base from which our forecast begins. In 2015 world oil demand increased by 1.6 mb/d (1.7%), one of
the biggest increases in recent years stimulated to a large extent by the rapid fall in oil prices that
began in the second half of 2014 and gained momentum in 2015. However, any expectations that the
most recent fall in oil prices to USD 30/bbl oil will provide further stimulus to oil demand in the early
years of our forecast and send annual rates of growth above 1.2 mb/d are likely to be dashed. In the
first part of 2016 we have seen major turmoil in financial markets and clear signs that almost any
economy you care to look at could see its GDP growth prospects downgraded.
O VERVIEW
action. This will probably not have an immediate impact on demand in the early part of this forecast,
but later on we might see that the reduction in expensive fuel subsidies in many countries, including
the fast-growing Middle East, does have a significant effect on growth. Also, rising energy use has
brought with it terrible environmental degradation, particularly in the fast-growing Asian economies,
and oil’s part in this is recognised by measures to limit vehicle registrations and use. Although
reducing subsidies and tackling pollution will affect the rate of demand growth, it should be stressed
that non-OECD Asia will still remain the major source of oil demand growth with volumes increasing
from 23.7 mb/d in 2015 to 28.9 mb/d in 2021.
Table ES.1 Global balance summary (million barrels per day)
2015
2016
2017
2018
2019
2020
2021
World Demand
94.4
95.6
96.9
98.2
99.3
100.5
101.6
Non-OPEC Supply
57.7
57.1
57.0
57.6
58.3
58.9
59.7
OPEC Crude*
32.0
32.8
33.0
33.0
33.2
33.5
33.6
OPEC NGLS etc
6.7
6.9
7.0
7.1
7.1
7.1
7.2
Total World Supply*
96.4
96.7
97.0
97.8
98.7
99.5
100.5
Implied Stock Change
2.0
1.1
0.1
-0.4
-0.7
-1.0
-1.1
*OPEC actual output in 2015. Assumes a post-sanctions increase for Iran in 2016 and adjusts for OPEC capacity changes thereafter.
Asia’s key role in the future demand picture is reflected in the rise in the region’s share of global oil
trade. By 2021 non-OECD Asia will be importing 16.8 mb/d of crude oil and products, a rise of
2.8 mb/d compared to 2015. The People’s Republic of China (hereafter ‘China’), remains central to
this growth, partly because of the underlying rise of oil demand but also due to its build-up of
strategic reserves which will reach at least 500 mb by 2020. A trade issue that has recently appeared
on the agenda is the possibility of US crude oil exports. The US is already a major exporter of oil
products (2.8 mb/d in 2015) and the lifting of the crude export ban potentially opens up another
trade opportunity. In our trade section we analyse why the economics mean that large volumes of
US crude oil will not move out of the region during the forecast period.
The continued rise in the global trade of oil will reach a peak at 37 mb/d in 2017 with the long-term
eastwards drift continuing. Crude oil will be processed through refineries in ever rising volumes,
although one of the most noticeable trends in the refining sector in the forecast period will be overcapacity. Our report points out that it is in Asia where most of the 5.3 mb/d of global spare refining
capacity will be found. Although products demand will continue to grow, it will not keep pace with
the expected increase in investment in new plant. The Middle East will consolidate its place as a
major refining centre and products exports will grow at a rate exceeded only by the US which will
process rising volumes of domestic crude over the period of the forecast as a whole.
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© OECD/IEA, 2016
However interesting and important oil demand trends are, the major focus in the next few months
will be on the supply side of the balance. In the year since the 2015 MTOMR was published, the
supply side has provided many surprises. By far the most significant has been the resilience of high
cost oil production and in particular that of light, tight, oil (LTO) output in the US. As oil prices
cascaded down from more than USD 100/bbl it was widely predicted at various milestones that the
extraordinary growth in total US crude oil production from 5 mb/d in 2008 to 9.4 mb/d in 2015
O VERVIEW
would grind to a halt and move rapidly into reverse. Growth certainly ceased in mid-2015 but the
intervening period has seen a relatively modest pull-back and total US crude oil production in early
February 2016 was still close to 9.0 mb/d, aided by expanding production in the Gulf of Mexico.
In our base case outlook, there is an element of the “straw breaking the camel’s back” and we expect
US LTO production to fall back by 600 kb/d this year and by a further 200 kb/d in 2017 before a
gradual recovery in oil prices, working in step with further improvements in operational efficiencies
and cost cutting, allows a gradual recovery. Anybody who believes that we have seen the last of
rising LTO production in the United States should think again; by the end of our forecast in 2021,
total US liquids production will have increased by a net 1.3 mb/d compared to 2015. Such has been
the element of surprise provided by the resilience of US oil production, and the wide divergence of
views as to the future, that we have added a High and Low Case to our non-OPEC production analysis
and plotted the impact on the global oil market balance of US LTO production falling by more than in
our base case or, conversely, less. The eventual outturn is one of the most important factors – if not
the most important – in assessing when the oil market will re-balance.
102
2.5
100
2.0
98
1.5
96
1.0
94
0.5
92
0.0
90
-0.5
88
-1.0
86
-1.5
84
-2.0
Implied Stock
Ch.&Misc to
Bal (RHS)
mb/d
mb/d
Figure ES 1 Global balance base case
Oil Demand
Oil Supply
-2.5
82
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
11
© OECD/IEA, 2016
Elsewhere, the determination of members of the Organisation of Petroleum Exporting Countries to
maintain and expand their market share has clearly been shown by the fact that at two ministerial
meetings following the historic November 2014 decision not to cut production to support oil prices,
ministers have resisted any temptation to change course. In mid-February some OPEC members and
Russia agreed to freeze production and they indicated that further policy initiatives may follow.
Rising oil production in 2015, notably from Iraq and Saudi Arabia, will now be joined by Iran, freed
from nuclear sanctions. Within the time frame of this forecast we do not expect a major increase in
the production capacity of either Iran or neighbouring Iraq due to political uncertainties, but this
outlook could, towards the end of the period, be revised. In other OPEC countries we are seeing one
of the downsides of low oil prices: massive economic retrenchment in countries such as Algeria,
Nigeria and Venezuela will reduce their ability to invest in the oil sector. It is not our role to analyse
political issues, but it is worth flagging up the potential implications for supply stability in countries
that have seen their income collapse dramatically. For OPEC as a whole oil export revenues slumped
from a peak of USD 1.2 trillion in 2012 to USD 500 billion in 2015 and, if oil prices remain at current
levels, this will fall in 2016 to approximately USD 320 billion
O VERVIEW
Another downside to low oil prices is the impact on investment. The IEA has regularly warned of the
potential consequences of the 24% fall in investment seen in 2015 and the expected 17% fall in 2016.
In today’s oil market there is hardly any spare production capacity other than in Saudi Arabia and
Iran and significant investment is required just to maintain existing production before we move on to
provide the new capacity needed to meet rising oil demand. The risk of a sharp oil price rise towards
the later part of our forecast arising from insufficient investment is as potentially de-stabilising as the
sharp oil price fall has proved to be.
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© OECD/IEA, 2016
In 2016, we are living in perhaps the first truly free oil market we have seen since the pioneering days
of the industry. In today’s oil world, anybody who can produce oil sells as much as possible for
whatever price can be achieved. Just a few years ago such a free-for-all would have been
unimaginable but today it is the reality and we must get used to it, unless the producers build on the
recent announcement and change their output maximisation strategy. The long-term consequences
of this new era are still not fully understood but this report aids the debate in shedding light on the
outlook for the next five years.
D EMAND
1. DEMAND
Summary
• Global oil demand will grow by 7.2 mb/d in the forecast period 2015-21, at an annual average
growth rate of 1.2%, half a percentage point below the previous comparable time period, 200915. From 94.4 mb/d in 2015, demand will reach 101.6 mb/d by 2021.
• Demand growth momentum is constrained by improved vehicle fuel efficiency and structural
changes to the Chinese economy. In China, the focus shifts to domestic demand and away from
an oil-intensive heavy manufacturing/export driven base, which triggers a notable deceleration in
oil demand growth.
• The stronger forecast versus the 2015 MTOMR is partly due to higher baseline numbers as well
as marginally more supportive underlying factors. Our 2020 forecast for global demand of
100.5 mb/d is 1.4 mb/d above the number published last year due to data revisions. These
changes raised the global demand baseline by 1.1 mb/d. Lower than expected oil prices during
2016-18 support marginally higher demand estimates. Towards the end of the forecast, more
rapid economic growth will provide additional support.
Table 1.1 Global oil demand (mb/d), 2015-21
OECD Americas
OECD Asia Oceania
OECD Europe
FSU
Other Europe
China
Other Asia
Latin America
Middle East
Africa
World
2015
2016
2017
2018
2019
2020
2021
2015-21
24.4
8.1
13.7
4.9
0.7
11.2
12.5
6.8
8.2
4.1
94.4
24.4
8.0
13.7
4.9
0.7
11.5
13.0
6.8
8.3
4.2
95.6
24.5
8.0
13.6
4.9
0.7
11.9
13.5
6.8
8.5
4.4
96.9
24.4
7.9
13.5
5.0
0.7
12.4
14.0
6.9
8.7
4.5
98.2
24.4
7.9
13.4
5.0
0.8
12.8
14.4
6.9
9.0
4.7
99.3
24.3
7.9
13.3
5.1
0.8
13.2
14.9
7.0
9.2
4.8
100.5
24.2
7.8
13.1
5.2
0.8
13.6
15.3
7.1
9.5
5.0
101.6
-0.1
-0.3
-0.5
0.3
0.1
2.5
2.8
0.3
1.3
0.9
7.2
• China saw great resilience in 2015 with oil demand expanding by 5.4% despite economic growth
falling to a 25-year low. As the structure of the economy changes demand growth is forecast to
slow – at least compared to the heady heights of recent years. Even so, in the period to 2021 oil
demand in China will grow by 2.5 mb/d.
• Pulled down by a relatively subdued gasoline demand forecast, oil product deliveries in the
United States will be essentially flat to 2021. Passenger vehicle efficiency gains of around 2% per
annum are a big factor.
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13
© OECD/IEA, 2016
• Our projections are highly vulnerable to uncertainties around oil prices, changing interest rates,
the pace of investment in oil supply and geopolitical issues.
D EMAND
mb/d
Figure 1.1 Global oil demand growth, by product, 2001-21
120
4%
100
3%
Naphtha
80
2%
Motor Gasoline
60
1%
Jet & Kerosene
40
0%
20
-1%
0
-2%
2001
2003
2005
2007
2009
2011
2013
2015
2017
2019
LPG
Gasoil/Diesel
Residual Fuel
Other Products
y-o-y Growth (RHS)
2021
Overview
Rising from 94.4 mb/d in 2015 to 101.6 mb/d in 2021, demand is forecast to climb by 1.2% per year,
or 1.2 mb/d, as economic activity gradually accelerates. This growth is sharply lower than the 1.7%
per annum seen in 2009-15. Two key factors curb the oil demand forecast: (a) relatively high
underlying vehicle efficiency assumptions; and (b) the structural change in the Chinese economy
away from its reliance on heavy industry/exports towards more services and domestic consumption.
Map 1.1 Global oil demand growth, by region, 2001-21
2003-09
2009-15
2015-21
Europe
FSU
32
-133
-179
138
-76
52
Asia/Pacific
969
Americas
Middle East
330
283
164
826
527
215
27
Africa
-1
127
104
155
Average global demand growth
(kb/d)
2003-09
882
1.1%
2009-15
1 478
1.7%
2015-21
1 199
1.2%
© OECD/IEA, 2016
This map is w ithout prejudice to the status of or sovereignty over any territory, to the delimitation of international frontiers and boundaries and to the name of any territory, city or area.
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© OECD/IEA, 2016
Strong gains in gasoil/diesel, LPG (including ethane) and gasoline dominate oil demand growth,
although the full scale of gasoil’s ascendancy – at just over 54% of projected global oil demand
growth – is magnified by the changes to fuel specifications in the shipping industry (see Marine gasoil
to seize bunker fuel market share). If, as we assume in our base case, the shipping industry complies
with legislation to curb global sulphur emissions, marine diesel use could rise by 2 mb/d, more than
offsetting the reduction in high sulphur fuel oil use. Prior to the marine fuel switch, gasoil’s share of
projected global growth is more muted – roughly the same as gasoline and LPG.
D EMAND
Our forecast contains some notable upside revisions compared to the 2015 MTOMR that are chiefly
attributable to upwardly revised baseline demand numbers and some marginally more supportive
forecast assumptions. The baseline figures were revised up following the publication of the 2015
edition of the IEA’s Annual Energy Statistics of Non-OECD Countries, which carried higher historical
assessments of non-OECD Asian and Middle Eastern oil demand, alongside the additional stimuli
provided by lower than expected crude oil prices. The more price-responsive oil consumers, such as
the United States, China and India, contributed the greatest to 2015 demand growth. Lower
underlying price assumptions from 2015-17 support higher oil product demand projections through
the first half of the forecast, before marginally higher economic growth assumptions take over in
2019-21.
Projections for economic growth in the nearer term have recently been downgraded, although the
outlook for later in our forecast period has held up better and has been revised upwards compared
to the 2015 MTOMR. The International Monetary Fund revised down growth projections for 2016
and 2017 first in October 2015 and again in January 2016. Global economic growth is still expected to
be higher in 2016-17, compared to 2015, but lower than previously expected.
Table 1.2 Global GDP growth forecast
2016
MTOMR 2016, based on
IMF January 2016
3.4%
IMF October 2015
3.6%
MTOMR 2015, based on
IMF January 2015
3.7%
2017
3.6%
3.8%
3.7%
2018
3.7%
3.9%
3.7%
2019
3.9%
4.0%
3.8%
2020
4.0%
4.0%
3.8%
Note source: International Monetary Fund, World Economic Outlook.
Amongst the factors contributing to a weaker outlook for economic growth are the recession in Brazil
which is exacerbated by political turmoil and allegations of corruption that reach the heart of the
business establishment. China’s structural rebalancing is contributing to lower demand for many
commodities leading to price falls, and in the United States the prospect of rising interest rates is
another factor that may dampen global economic growth and in turn feed through into lower growth
for oil demand. On the bright side, post-sanctions Iran should see stronger economic growth and
there are improved prospects in Argentina, India and much of Africa.
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A number of one-off supports also contributed strongly to the higher baseline oil demand numbers,
particularly in OECD Europe. The Turkish authorities, for example, upgraded their jet fuel demand
numbers after it became clear that some previously reported export flows were in fact domestic
demand. Other unique 2015 data supports included the post-recessionary bounce-backs that were
seen in many other European nations. Economic recovery on a scale not previously expected, a
consequence of much lower oil prices, also played a supportive role. Comparing the IMF’s World
Economic Outlook of January 2016 with their outlook a year ago, approximately three-tenths of a
percentage point has been added to the Euro zone 2015 economic growth estimate to +1.5%.
D EMAND
Entrenched efficiency gains put a ceiling above the global oil demand forecasts, of around 1.2% per
annum growth, from 2015-21. All of the key product segments play a role in efficiency gains, with the
largest improvements reserved for the transport sector (see Escalating vehicle efficiencies underpin
more subdued demand forecasts).
Even with efficiency improvements, however, the sheer scale of growth in vehicle fleets in
developing countries means that oil demand growth is unlikely to fall much below 1 mb/d before
2020. The forecast maintains support from recent price reductions, triggering renewed strength in
SUV sales, particularly in the two largest gasoline consumers – China and the United States – while
electric vehicle sales stuttered somewhat. In China, for example, economic growth in 2015 fell to a
25-year low while ‘new energy’ vehicle sales (i.e. electric, hybrid and fuel cell) came in at 330 190, a
mere 1.6% of total Chinese passenger vehicle sales, which themselves grew by 7.3%. The fast growth
recently seen in the market means that scrapping rates are low in comparison and the total Chinese
fleet expanded sharply as a consequence. This pattern will remain in place for some years to come.
Along with rising road transport fuel demand, the petrochemical – LPG (including ethane) and
naphtha – and air transport sectors will support continued global oil demand growth. Air transport
growth is supported by rapidly expanding emerging market flight schedules and, in the case of
petrochemicals, by capacity expansion plans (see Robust petrochemical demand set to hold through
2021). Other large consumers of oil, such as power generation, industry and space heating, are
forecast to see declining contributions to global oil demand, as they are displaced gradually by
natural gas and renewable energy and possibly by cheap coal.
Box 1.1 Robust petrochemical demand set to hold through 2021
A total of 11.5 mb/d of oil, or 13% of total demand, is directed towards the production of
petrochemicals out of which almost 90% is used as a feedstock and the rest for thermal energy. The
main feedstocks of the petrochemical industry are naphtha (50%), LPG (propane, butane and ethane)
(40%), recently also methanol (mainly in China) and to a minor extent diesel (gasoil).
About 70% of the oil is used in dedicated steam crackers – the key petrochemical process – which
converts oil products into a range of petrochemicals, most notably ethylene, the largest volume base
chemical. The products from the steam cracker are the precursors of most plastics, which are used, for
example, in packaging, buildings, textiles and the automotive industry.
The remaining 30% is used to a large extent in oil refining, where aromatics are produced from catalytic
reforming of naphtha and propylene mainly from the fluid catalytic cracking process. Both aromatics
and propylene are also used for the production of plastics, while aromatics also play an important role
for the production of synthetic textiles. In 2012, China started to produce olefins (ethylene and
propylene) from methanol, which is either produced domestically from coal gasification or imported.
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Traditionally, the US has been the largest petrochemical producer, accounting for a fifth of total
petrochemical sector oil consumption, with the Middle East being the second most important producer
(representing 15% of global oil consumption for petrochemicals). Given the surge in natural gas liquids
(NGLs) production over the past few years in the US and the existing availability of NGLs in the Middle
East, both regions rely mainly on relatively cheap ethane as a feedstock. Other important petrochemical
producers include the European Union (14% of petrochemical oil consumption), China (13%), Korea (8%)
and Japan (6%), where petrochemicals are largely produced from naphtha.
D EMAND
Box 1.1 Robust petrochemical demand set to hold through 2021 (continued)
While demand for petrochemicals is anticipated to increase by roughly 2 mb/d from 2015 to 2021, an
annual growth rate of almost 3%, this is neither equally shared amongst the different oil products nor
the world’s regions. LPG (including ethane) and methanol (driven by developments in China) will gain in
importance over the next six years, whereas the share of naphtha will drop. Growth will be led by the
United States, the Middle East and China; with Europe and OECD Asia experiencing slight declines.
The shale gas revolution has impacted the US petrochemical sector: with ethane prices above USD 10
per million British thermal unit (Mbtu), equivalent to US cents 80/gal, as recently as 2011, the US was
deemed an unprofitable location for the price-sensitive petrochemical industry. Ethane prices averaged
around USD 3 per Mbtu (US cents 20/gal) in 2015 as an oversupply of ethane depressed prices to a level
equivalent to the natural gas price as a consequence of ethane being rejected into the natural gas
stream. Currently, seven world-scale steam crackers are under construction on the US Gulf Coast and
together with mature projects and de-bottlenecking, ethylene capacity is projected to increase by
almost 40% in the United States from 2015 to 2021, increasing the demand for ethane by around
0.5 mb/d. Using cheap ethane for the production of petrochemicals was very profitable as the price of
the product (e.g. plastics) was determined by the most expensive plants in Europe and Asia using
naphtha. Since late 2014 naphtha prices, which are closely linked to the oil price, came down sharply
and significantly. While European crackers paid around USD 21 per Mbtu (USD 900 per tonne) in 2014
for naphtha, the price was only USD 11 per Mbtu (USD 460 per tonne) in 2015, which reduced the cash
cost in Europe and margins in the United States. This development continued at the start of 2016 and
led to a situation where, for the first time since the shale gas revolution, variable cash costs for ethylene
in the United States and Europe were on a similar level. This was not only driven by European naphtha
prices falling to around USD 7/Mbtu (USD 300 per tonne) at the start of 2016, but also due to co-product
prices (including for propylene, butadiene and aromatics) declining less than the oil price (steam
crackers running on naphtha produce significantly more co-products than ethane crackers).
The Middle East sees the second-largest increase in oil demand from petrochemicals, approaching
0.5 mb/d between 2015 and 2021, based on the availability of cheap feedstock and relative proximity to
major demand centres in Asia. Growing natural gas production, and with it natural gas liquids, provides
a ready source of cost competitive ethane that makes the region the cheapest ethylene producer
worldwide. However, as petrochemical production increases faster than ethane supply, a gradual shift
towards heavier feed-stocks is projected. The first naphtha cracker in Saudi-Arabia, operated by Dow
Chemical and Saudi Aramco, is expected to be in full production by the end of 2016. Saudi Arabia
currently accounts for roughly 60% of ethylene capacity in the Middle East, though the government
decision in January 2016 to increase ethane prices from USD 0.75 per Mbtu to USD 1.75 per Mbtu will
reduce margins as feedstock prices approach the levels seen in the US. Other countries in the region
that plan to increase petrochemical production include Oman, Qatar, Kuwait and Iran.
Oil demand from the petrochemical industry in the European Union, Japan and Korea is essentially
unchanged as those regions experience weak domestic demand and relatively high feedstock prices.
Production in Japan and Europe is predominantly coming from costly naphtha, which makes these
regions the highest cost producers in the world. The fall in oil prices since 2014 has provided European
and Asian crackers with some relief as variable cash costs fell significantly bringing ethylene cash costs
to a similar level across regions. However, the current low crude oil prices are merely delaying capacity
closures in Europe and the Far East.
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© OECD/IEA, 2016
In contrast to the United States and the Middle East, increased petrochemicals production in China is
not so much driven by supply factors but rather by the rapidly increasing demand for petrochemical
products and the desire to reduce imports. While China is planning to add several naphtha-based steam
crackers, oil demand growth is reduced by the use of coal as a comparatively cheap feedstock in coal-toolefins and methanol-to-olefins plants. Olefin production capacity from methanol-based projects is
currently somewhere around 10 Mt and is anticipated to more than double by 2021.
D EMAND
Although restrained to a degree by lower oil prices, over the longer-term oil is facing increased
competition in the transport sector from hybrid, electric and natural gas-powered vehicles. Natural
gas is also making significant inroads into rail and marine transportation. This fuel-on-fuel
competition will play out only at the margin in the medium term. Alternatively-fuelled vehicles, not
including biofuels, trigger a net loss of 0.5 mb/d from road transport demand during 2015-21. In the
shipping industry, global efforts to cut emissions strengthen the case for natural gas as a bunker fuel,
though ship owners will have other options to reduce their footprint, including switching to lowersulphur marine diesel or installing scrubbers on vessels. A net 0.3 mb/d outflow from residual fuel oil
bunkers to natural gas is forecast for 2021, which, along with the 0.5 mb/d switch out of oil in the
road transport sector, takes the total transport fuel ‘loss’ to alternatively fuelled vehicles to
0.8 mb/d, 2015-21.
OECD demand
Falling oil prices have seen gasoline consumption in the United States - the world’s largest single
product market - grow strongly in 2015 to reach the highest level since 2007. However, a declining
medium-term trend is foreseen as prospective vehicle efficiency gains exceed the relatively muted
growth that is forecast across the vehicle pool of the United States. Rising by around 2% per annum
through the forecast (see Escalating vehicle efficiencies underpin more subdued demand forecasts)
the average efficiency of the vehicle fleet in the United States becomes the dominant factor in oil
demand growth there. Accordingly, gasoline demand in the United States will fall by around 0.5 mb/d
between 2015 and 2021, equivalent to an average decline rate of 1.0% per annum. Less strenuous
vehicle efficiency assumptions for the diesel fleet, meanwhile, underpin shallower decline rates for
diesel of around 0.4% per annum.
Figure 1.2 Cumulative US oil demand growth, 2001-21
2.0
LPG
1.5
Naphtha
0.5
Motor Gasoline
0.0
Jet & Kerosene
-0.5
Gasoil/Diesel
-1.0
Residual Fuel
-1.5
-2.0
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Other Products
Overall oil product demand in the United States is set to decline by approximately 0.1 mb/d, in the
period 2015-21, down to 19.3 mb/d by 2021. This essentially flat outlook contains sharply lower
estimates for gasoline and residual fuel oil demand offset by gains in LPG (including ethane) – as
additional petrochemical demand filters through – and flat gasoil/diesel and jet/kerosene demand.
With economic growth in the United States expected to be 2.6% per annum in 2016 and 2017,
according to the IMF’s January 2016 edition of the World Economic Outlook, before easing back to
+2% by 2020, our demand forecast essentially shows an average 4% per annum decline in oil
intensity. This efficiency gain is roughly half a percentage point above the previous 10-year average,
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© OECD/IEA, 2016
mb/d
1.0
D EMAND
caused chiefly by pending vehicle efficiency gains. Without these vehicle efficiency improvements
demand would obviously be higher: if the efficiency gain were only 3% this would add 1.4 mb/d to oil
demand.
Box 1.2 Escalating vehicle efficiencies underpin more subdued demand forecasts
Global oil demand in 2015 climbed by 1.7%, the highest rate in five years. During our forecast this rate
will slow dramatically, subject to any unforeseen demand shocks such as unseasonable weather.
Changes in oil intensity, i.e. the amount of oil required to produce a certain level of economic output,
are an important indicator of the underlying demand trend. In 2014, for example, the ratio was 1.20, but
in 2015 the global oil intensity was 1.28, calculated by global oil product demand of 94.4 mb/d divided
by real global GDP of USD 73.5 trillion. In 2015 therefore, we saw a 6.9% increase in oil intensity as
dramatically lower oil prices spurred additional oil purchases and sales of less efficient vehicles boomed
in the United States as part of a general increase in oil demand world-wide. Starting in 2016, we expect
underlying efficiency gains to return to more normal levels, averaging approximately 4% per annum in
the period to 2021.
Since the most recent peak in crude oil prices at USD 115/bbl in mid-2014, car drivers in the
United States have seen the national average retail gasoline price fall from USD 3.80/gal down to
USD 2.10/ gal at the end of 2015. This provided a major stimulus to transport fuel demand in the
United States, as more miles were driven and SUV sales rose; albeit with the former influence set to
wane through 2021 as the price stimulus eases. Data for 4Q15 showed an early glimpse of this, as
gasoline demand growth more than halved compared to the first nine months of the year. Potential tax
hikes, such as the USD 10/bbl oil import tax proposed by the Obama Administration in February, further
add to the downside. Through to 2021, prospective vehicle efficiency gains in the United States average
2%, acting as the dominant contributor to falling gasoline demand in the outlook. The efficiency gain
would have been even higher had it not been for the recent uptick in SUV sales, which act as a restrain
on future efficiency gains.
Incorporating the latest Corporate Average Fuel Efficiency Standards in the United States, the average
forecast vehicle efficiency gain is nearly four times faster than in the previous ten year period and this
will take out roughly 0.5 mb/d of prospective gasoline demand forecast from the United States, from
2015-21. On this assumption gasoline deliveries in the Unites States fall to a projected 8.6 mb/d by
2021, down to the level seen in 2001. Similar annual efficiency gains of 2% are assumed across the
global vehicle fleet underpinned by rapid technological advances, tightening government regulations
and, prior to 2015, higher oil prices encouraging prudent oil use via the purchase of more efficient
vehicles.
Table 1.3 United States vehicle fuel economy, litres per 100 km
New PLDVs
Average PLDVs
1995
9.5
10.8
2000
9.7
11.2
2005
9.5
11.7
2010
8.3
11.6
2015
7.7
11.0
2020
6.6
9.9
2025
5.2
8.7
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© OECD/IEA, 2016
Note source: PLDVs: Passenger Light-Duty Vehicles.
D EMAND
Box 1.2 Escalating vehicle efficiencies underpin more subdued demand forecasts (continued)
Mandated government efforts to curb oil use – i.e. fuel efficiency standards – play a key role
underpinning the efficiency gains that run through the forecast; though not in isolation, as resultant
investments in engine technology have a self-fulfilling impact across prospective transport fuel demand
as car producers adopt new technologies regardless of mandates. According to the IEA’s 2015 edition of
the World Energy Outlook fuel efficiency standards covered 34% of all road vehicles, as of 2014, up from
30% in 2005, and their coverage will continue to rise through 2021 as nearly 70% of new passenger car
sales are subject to fuel efficiency standards. Fuel economy standards for heavy-duty vehicles are less
widespread and, with the current low fuel price environment, the business case for as rapid efficiency
gains across the freight sector is diminished.
In Europe we see vehicle efficiency gains of around 2.4% per annum in 2015-21, alongside a total fleet
that is projected to decline. Over the period European gasoline demand falls by a net 265 kb/d. A similar
story applies to OECD Asia Oceania, with average efficiency gains of approximately 2.3%, offsetting an
only modestly rising vehicle fleet. Overall OECD gasoline demand contracts by roughly 0.9 mb/d in 201521, as strong efficiency gains (2.2% per annum) offset an only modestly expanding vehicle fleet.
In non-OECD countries, forecast efficiency gains are more muted. Non-OECD gasoline demand rises by
4.0% per annum while in the OECD countries it declines by 1.1%; for gasoil the non-OECD countries see
growth of 3.6% versus 0.6% for the OECD. For gasoline, the non-OECD gasoline fleet becomes roughly
1.6% more efficient, well below the OECD average. This is not to say, however, that sizeable efficiency
gains are in any way foreign to non-OECD nations. In China, for example, heightened efficiency gains will
be a key restraint on the Chinese demand forecast. In the years 2009-15 Chinese oil demand grew by
5.9% per annum but in the 2015-2021 period it will grow by only 3.4% per annum. The Chinese
government is under increasing pressure to tackle urban pollution and also reduce its oil import bill.
Lower prices are helping with the latter objective but energy efficiency improvements remain one of the
th
key goals of the 12 Five-Year Plan and a target was set for a reduction of 16% in overall energy
intensity.
Figure 1.3 Non-OECD consumers lead gasoline demand growth, 2001-21
OECD vs Non-OECD total products
OECD vs Non-OECD motor gasoline
16
14
50
mb/d
mb/d
60
40
12
10
30
8
20
6
4
10
0
2
2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021
OECD
0
2001 2003 2005 2007 2009 2011 2013 2015 2017 2019 2021
Non-OECD
20
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
© OECD/IEA, 2016
Efficiency gains are not confined to the transport sector, with the industrial, residential, petrochemical,
agricultural and commercial sectors of the economy also providing strong impetus. However, the
transport sector accounts for more than half of all global oil demand, and the improvements that are
expected to 2021 will be the main restraint on global oil demand growth.
D EMAND
Despite the VW emissions scandal, a combination of the long-term switch from gasoline to diesel in
European passenger vehicles and ongoing vehicle efficiency gains combine to reduce the European
gasoline demand at an average rate of 2.4%. The full consequences of the VW emissions scandal are
not yet, however, clear. By popular demand, more scrupulous testing methodologies will be
implemented, which will of course increase car production costs, but whether or not this will impact
all forms of propulsion is yet unclear. Overall, the key European oil consuming nations of Germany,
Italy, France, and the UK will all see sharp declines in gasoline demand, with the UK at the head of
the list.
In the UK, the dieselisation rate is lower than in other major European markets and thus there is a
larger gasoline market to lose. Although the VW debacle initially dampened the company’s diesel
sales in the UK, they have since solidified according to the Society of Motor Manufacturers, which
cited overall diesel sales holding up well, supported by robust commercial vehicle sales (+15% in
2015). The absence of any sizeable net-change in European petrochemical demand is also
noteworthy, although a small substitution towards LPG, from naphtha, would not come as a surprise
as the prices of these feedstocks adjusts.
Figure 1.4 European oil demand, 2009-21
16.0
mb/d
14.0
LPG
12.0
Naphtha
10.0
Motor Gasoline
8.0
Jet & Kerosene
Diesel
6.0
Other Gasoil
4.0
Residual Fuel
2.0
Other Products
0.0
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Focusing on the dominant transport sector, and in contrast to gasoline, the European diesel forecast
is essentially flat, as assumed vehicle efficiency gains roughly offset increases in the vehicle stock.
Notable laggards, where absolute contractions in diesel demand are foreseen, include Germany and
France, as weaker assumed expansions in vehicle fleets trim demand. Recent changes in the French
taxation structure have equalised the taxation treatment, having previously favoured diesel.
One notable exception to the otherwise stagnant European demand picture is Turkey. The country’s
rising population and strong underlying economic growth should see oil demand growth average
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© OECD/IEA, 2016
Such flat-to-weak European transportation fuel demand forecasts, coupled with projections of
relatively muted economic growth, feed the net 0.5 mb/d European demand decline to 2021. The
IMF’s World Economic Outlook in January 2016, citing average Euro Zone economic growth of 1.7% in
2016 and 2017, roughly half the global average. Furthermore, without the additional availability of
very cheap feedstock, such as the influx of ethane seen in the United States, or in non-OECD Asia, the
European petrochemical industry is generally forecast to be less competitive on the international
stage.
D EMAND
around 2.7% per annum to 2021. Transport fuels – notably gasoline (+4.3%), gasoil/diesel (+4.5%)
and jet fuel (3.9%) – lead Turkey’s upside. Turkey has a very low vehicle ownership rate – at just over
200 vehicles per 1 000 inhabitants, versus close to 800 in the United States – offering the potential
for strong gains in the transport sector.
Figure 1.5 OECD road transport demand, 2009-21
20
80%
70%
mb/d
15
60%
10
50%
40%
5
0
30%
2009
2015
2021
2009
OECD Americas
2015
2021
OECD Europe
Motor Gasoline
Diesel
2009
2015
2021
20%
OECD Asia Oceania
Gasoline to Diesel ratio (RHS)
In OECD Asia Oceania a decline of approximately 0.3 mb/d is foreseen to 2021, with lower demand
for most of the main product categories. Gasoline demand is forecast to contract by about 140 kb/d,
as sharp efficiency gains offset very modest projected increases across the vehicle stock. A sizeable
reduction in residual fuel oil demand is largely attributable to reductions in shipping demand, albeit
with a near offsetting gain for gasoil. Further declines in oil use in the Japanese power sector also
play a part but by 2015, according to data from the Federation of Electric Power Companies,
combined Japanese power-sector oil use was down to a negligible 0.1 mb/d. The Australian gasoline
demand forecast falls by 1.6% per annum to 2021, as annual efficiency gains of below 3% prove more
than sufficient to offset marginal gains in the Australian gasoline fleet. Similar arguments hold across
the region for gasoline. The Australian gasoil/diesel forecast moves counter to gasoline, with demand
rising by approximately 2.3% per annum to 2021, supported by an expanding Australian diesel fleet
which more than offsets an average efficiency gain of approximately 1.4%. A similar story surrounds
the Korean diesel forecast, which is projected to rise by around 1.4% per annum during 2015-21.
Figure 1.6 Relative non-OECD/OECD oil demand growth discrepancies, 2013-21
2.0
Non-OECD
22
1.0
1.5
mb/d
mb/d
1.5
OECD
1.0
0.5
0.5
0.0
0.0
-0.5
-0.5
2013 2014 2015 2016 2017 2018 2019 2020 2021
LPG
Naphtha
Motor Gasoline
Jet & Kerosene
2013 2014 2015 2016 2017 2018 2019 2020 2021
Gasoil/Diesel and Resfuel
Other Products
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2.0
D EMAND
Non-OECD demand
Global oil demand growth is overwhelmingly a non-OECD story to 2021 with Asia especially strong. In
the forecast period non-OECD countries see demand grow by 8.1 mb/d, versus a net-OECD decline of
0.9 mb/d. Stronger population growth – estimated at 1.1% per annum through 2021 (versus +0.5% in
the OECD) – is the main contributing factor.
Transport and petrochemicals dominate the growth forecast, with gasoil and gasoline accounting for
roughly three-quarters of the projected non-OECD expansion. Solid gains are also seen in LPG
(including ethane), naphtha and jet/kerosene. Although total product demand growth will average
2.6% per annum to 2021, the path will not be smooth. Non-OECD growth is likely to falls back in 2016
due to difficult economic conditions in a number of important non-OECD commodity-dependent
nations, such as Brazil and Russia; before re-accelerating in 2017 as underlying economic conditions
improve. Approaching 2020, the product split may evolve if the successful implementation of tighter
environmental standards on the global shipping fleet triggers some switching out of oil as a bunker
fuel to natural gas. Elsewhere in the oil balance, advances in solar, wind and hydro technologies have
improved the competitiveness of renewable fuels, particularly in power generation but also in the
industrial sector. Developing economies are better placed to introduce renewable technologies at an
early stage in their development.
Figure 1.7 Non-OECD oil demand mix, 2015 and 2021
Non-OECD Demand in 2021 - 56.4 mb/d
Non-OECD Demand in 2015 - 48.3 mb/d
GasDies
32%
GasDies
29.8%
Gasoline
21.6%
Naphtha
6.6%
JetKero
7%
Other
13.8%
LPG
11.1%
ResFuel
7%
Other
13%
Gasoline
23%
Naphtha
7%
LPG
11%
Against this backdrop, the dramatic fall in oil prices to USD 30/bbl is likely to provide only a modest
boost to non-OECD oil demand growth. Oil exporting countries in Latin America, the Former Soviet
Union and the Middle East are suffering economic difficulties and in some cases demand is inhibited
by geopolitical tensions. Net commodity importers, such as India, should continue to see strong
growth, benefiting from lower import bills, but even their short-term progress is capped as potential
export markets (to the net-commodity exporters, for example) suffer. Furthermore, the full extent of
recent crude oil price declines is unlikely to be felt in non-OECD economies. Firstly, many of these
countries saw the value of their own currencies fall versus the US dollar, negating the benefit of the
fall in the US dollar price of commodities. Secondly, lower crude oil prices have provided the
opportunity to decrease or even eliminate fuel subsidies. Saudi Arabia, for example, is under severe
budgetary pressure from falling crude oil prices and, effective 11 January 2016, the Kingdom hiked
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ResFuel
10.8%
JetKero
6.4%
D EMAND
gasoline prices (by between 50-and-67%), ethane (133%), transport diesel (+79%), industrial diesel
(+55%) and kerosene (+12%). Other countries, such as Oman, Bahrain and the UAE, are under similar
pressure, and have taken, or are planning to take, measures to raise domestic prices, thus choking off
demand growth.
China might have been expected to see oil demand react more sharply to lower crude and product
prices but, in the midst of a slowing macroeconomic picture, it is unlikely to do so. Far more
important to the Chinese oil balance is the evolution of its economy away from heavy
manufacturing/exports towards a more consumption-driven model. Although the Thirteenth FiveYear Plan (FYP) for 2016-20 is not published until March 2016, it is anticipated that strong measures
will be proposed to improve urban air quality, an issue which is causing major political controversy.
The previous FYP, covering the period 2011-15, targeted reducing Chinese total energy use by 16%
per unit of GDP alongside a 17% reduction in carbon dioxide emissions. The plan also set an
ambitious medium term target for non-fossil fuel energy consumption at 15% of the energy mix by
2020. Similarly tough targets are envisaged for the Thirteenth FYP, and coal consumption is likely to
be heavily targeted, which will have a knock on effect on diesel which fuels the transport used to
move coal around the country. Furthermore, China’s recently adopted policy not to pass through to
oil products reductions in crude oil prices below USD 40 per barrel further dampens the oil demand
outlook.
Box 1.3 Oil price declines could drive reform of fossil fuel subsidies
Fossil fuel subsidies encourage the wasteful use of energy, hinder investments in low-carbon
technologies and energy-efficient equipment and contribute to greenhouse-gas emissions. Fossil-fuel
subsidies can also cause financial losses to energy suppliers as a consequence of under-pricing energy
commodities, resulting in under-investment in energy supply. The main objective of these subsidies is
usually to hold down the cost of energy for poor households for social reasons or to redistribute
national wealth. In practice, however, subsidies often fail to bring much benefit to those really in need
and benefit those who can afford to consume more of the subsidised fuel, leading to a fiscal drain on
many vulnerable countries.
Based on the IEA’s 2015 World Energy Outlook, the value of fossil-fuel subsidies worldwide was
estimated at USD 493 billion in 2014, a USD 100 billion increase in real terms since 2009 when G20
members committed to “rationalise and phase out over the medium term fossil fuel subsidies that
encourage wasteful consumption.” However, this does not necessarily mean that efforts to reform fossil
fuel subsidies have stagnated. Without these reforms, the value of fossil-fuel subsidies would have been
24% higher – at USD 610 billion in 2014 – underscoring the importance of policy interventions.
Lower oil prices also provide a window of opportunity to make fossil fuel subsidy reforms without
having a major upward impact on end-user prices – or inflation – or provoking public opposition, while it
has direct implications for government budgets in the major oil and gas exporting countries, where the
fossil fuel subsidies have been prevalent.
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The recent fall in oil prices has encouraged fossil fuel subsidy reforms. Persistently high energy prices
between 2008 and mid-2014, which pushed the cost of subsidies to very high levels, made a case for
further subsidy reform in many countries experiencing rapid energy demand growth and thus increased
budgetary constraints. For example, starting in late 2012, India started increasing prices for diesel by
small amounts every month (about Indian Rupees 0.50, equivalent to USD 0.008 per litre), which led to
the complete phase-out of subsidies by October 2014. Malaysia also ended subsidies for gasoline and
diesel in December 2014 as part of a strategy to reduce its rising national debt and fiscal deficit.
Indonesia abolished subsidies on gasoline and capped the diesel subsidy in January 2015.
D EMAND
Box 1.3 Oil price declines could drive reform of fossil fuel subsidies (continued)
For those countries, fossil fuel subsidies represent the revenue foregone by pricing domestic energy
below international prices and thus lower oil prices could offer more incentive to reform subsidies and
ease budgetary pressure. Middle Eastern oil exporting countries for instance, are home to 40% of global
fossil fuel subsidies, and final data for 2015 is likely to confirm the October 2015 estimate made by the
IMF in their World Economic Outlook that these countries will accumulate a budget deficit of
USD 150 billion for the year. If oil prices remain lower for longer, these countries will have to consider
cutting domestic subsidies. Some have already taken action.
From August 2015, the United Arab Emirates deregulated gasoline and diesel prices, which are to be
adjusted monthly to track international levels, as part of the government’s strategy to diversify sources
of income, strengthen the economy and increase competitiveness. In January 2016, Oman raised the
price of gasoline and diesel, following the gas price increase for industrial consumers in January 2015
(+100%, to 0.041 Omani Rial per cubic metre, and 3% annual rises to follow). In December 2015,
effective January 2016, Saudi Arabia announced energy price increases including gasoline, gas, diesel,
kerosene and electricity. The gasoline price is to be raised by more than 50%. Similar moves are also
seen in Bahrain, Kuwait and Qatar.
Although the fiscal consideration is a driver for the subsidy reform, it can be promoted by a variety of
other factors, which vary from one country to another. The table below indicates the recent fossil fuel
subsidy reforms in selected countries.
Main fuels
subsidised
Recent developments (World Energy Outlook, 2015)
Angola
Gasoline, diesel,
kerosene,
electricity
In December 2014, reduced subsidies by increasing prices to AOA 90
(USD 0.83) per litre for gasoline and AOA 60 (USD 0.55) per litre for
diesel.
Bahrain
Gasoline, diesel,
kerosene,
electricity
In December 2015, announced gradual increase of diesel and
kerosene prices and, in January 2016, increased the price of gasoline.
China
LPG, natural gas,
electricity
Announced plans to group existing and new industrial gas consumers
under single pricing mechanism, February 2015
Ghana
LPG
Deregulated petroleum product prices, June 2015.
India
Kerosene, LPG,
natural gas,
electricity
Stopped diesel subsidies in October 2014, following similar reforms to
gasoline in 2010. Also introduced a new pricing formula for
domestically produced gas. In January 2015, introduced a cash
transfer scheme for residential LPG consumers to try to stop the
diversion of subsidised cylinders to commercial use.
Indonesia
Diesel, electricity
Abolished subsidies to gasoline (RON 88) and capped diesel subsidy,
January 2015. Increased price of non-subsidised 12-kg LPG canisters
by IDR 5 000 (USD 0.38), March 2015.
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Table 1.4 Recent subsidy adjustments
D EMAND
Box 1.3 Oil price declines could drive reform of fossil fuel subsidies (continued)
26
Main fuels
subsidised
Recent developments (World Energy Outlook, 2015)
Iran
Gasoline,
diesel,
kerosene, LPG,
natural gas,
electricity
In May 2015, increased the price of subsidised gasoline from
IRR 7 000 (USD 0.28) per litre to IRR 10 000 (USD 0.35) per litre.
Kuwait
Gasoline,
diesel,
kerosene, LPG,
natural gas,
electricity
In January 2015, increased the price of diesel to KWD 0.170
(USD 0.56) per litre. At the end of January 2015, cut back prices of
diesel and kerosene to KWD 0.110 (USD 0.36) following political
pressure. Postponed plans to remove subsidies on gasoline and
electricity.
Malaysia
LPG, natural
gas, electricity
Increased electricity tariffs by 15% on average, and resumed fuel cost
pass-through, based on international gas price movements, January
2014. In May 2014, increased natural gas prices by up to 26% for
certain users. In December 2014, abolished gasoline (RON95) and
diesel subsidies; prices are now set to track international levels.
Morocco
LPG
Abolished gasoline and fuel oil subsidies at the start of 2014 and
diesel subsidies at the start of 2015.
Oman
Gasoline,
diesel, natural
gas, electricity
In January 2016, the prices of gasoline RON 95 and RON 90 were
raised by 33% to 0.160 OMR (USD 0.42) per litre and by 23% to
0.140 OMR (USD 0.36) per litre, respectively. Diesel was raised 9.6%
to 0.160 OMR (USD 0.42) per litre. In January 2015, raised gas
prices for industrial consumers by 100%, to OMR 0.041 per cubic
metre (USD 3.01/MBtu). Introduced a 3% annual rise in gas prices for
industries.
Qatar
Gasoline,
diesel, natural
gas, electricity
In January 2016, increased gasoline prices by 33% to 1.30 QAR
(USD 0.36) per litre for RON 97 and by 35% to 1.15 QAR (USD 0.32)
per litre for RON 90.
Saudi
Arabia
Gasoline,
diesel,
kerosene,
natural gas,
electricity
In December 2015, announced numerous energy price hikes,
including gasoline, natural gas and electricity. Increased price of
gasoline by 50% to 0.9 SAR (USD 0.24) per litre for RON 95 and by
two-thirds to 0.75 SAR (USD 0.20) per litre for RON 91.
Thailand
LPG, natural
gas, electricity
In October 2014, increased the price of compressed natural gas for
vehicles by THB 1 (USD 0.03) per kilogramme. Ended subsidies for
LPG in December 2014.
UAE
Gasoline,
diesel, natural
gas, electricity
From August 2015, started adjusting fuel prices monthly to match
global prices.
Viet Nam
Natural gas,
electricity, coal
In March 2015, increased electricity tariffs by 7.5%.
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Table 1.4 Recent subsidy adjustments (continued)
D EMAND
Africa
Underpinned by rising populations, the medium-term outlook for African oil demand is for growth at
an average rate of 3.5% to 2021. Transport fuels lead the expansion although strong gains are also
foreseen across many of Africa’s fledgling industries. Africa is likely to remain a large user of oil in the
power sector with additional demand support coming from the large number of small diesel
generators held in readiness for breakdowns in grid-supplied electricity. Geopolitical issues, including
political strife in Libya and Sudan, will dampen demand growth to some extent.
Any energy forecast for Libya can only be speculative as long as the fight for control of the country
continues. No sustainable solution is in sight but as a place-holder we have allocated a 2.9% per
annum demand increase to 2021. A sustainable peace agreement would lead to a sharp increase in
conventional economic activity with the accompanying increase in fuel demand. Time will tell.
Nigeria also remains a volatile country with the new government led by President Buhari determined
to tackle corruption and incompetence in government and open up the economy to private
investment, including from abroad. With economic growth forecast to average around 4.3% through
to 2021, coupled with a near quadrupling in refinery runs and no concrete plans to further curb
product subsidies after 2012’s dramatic gasoline hike, prospective Nigerian demand growth averages
4% from 2016-21. Strong gains in Nigerian road transport and industrial demand drive the growth.
Table 1.5 African oil demand (mb/d), 2015-21
LPG
Naphtha
Gasoline
Jet/kerosene
Gasoil
Residual fuel oil
Others
Total
2015
0.4
0.0
1.0
0.3
1.5
0.5
0.3
4.1
2016
0.4
0.0
1.1
0.3
1.6
0.5
0.3
4.2
2017
0.4
0.1
1.1
0.3
1.7
0.5
0.3
4.4
2018
0.4
0.1
1.1
0.3
1.7
0.5
0.3
4.5
2019
0.4
0.1
1.2
0.4
1.8
0.5
0.3
4.7
2020
0.4
0.1
1.2
0.4
1.9
0.5
0.3
4.8
2021
0.5
0.1
1.3
0.4
2.0
0.5
0.3
5.0
2015-21
0.1
0.1
0.3
0.1
0.4
0.0
0.0
0.9
Projected to rise by approximately 3.2% per annum to 2021, the Egyptian oil demand forecast is also
contingent on the stability of the economy. The vulnerability of the tourism sector, which generates
about one-eighth of Egypt’s GDP, was seen after October’s attack on a Russian aircraft. The IMF
forecast in October 2015’s World Economic Outlook that the Egyptian economy would grow by
approximately 4.6% per annum in the period 2015-20. Another factor that will dampen the economy
is the widely held view that the Egyptian pound is overvalued; a correction would of course raise the
cost of imports.
Asia
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Supported by robust gains across the main transport fuels, non-OECD Asia will provide the majority
of the world’s medium-term demand growth, accounting for nearly three out of every four extra
barrels delivered globally to 2021. Roughly half the world’s population resides in the region but
accounts for only one-quarter of its oil demand; thus relatively strong economic growth should feed
through into rapidly rising per capita energy use from a low base.
D EMAND
China’s oil demand grew by 0.6 mb/d (5.4%) in 2015 – approximately double the estimate cited in
the 2015 MTOMR. Despite the economic structural shift that is certainly occurring, the economy
remains broadly supportive of sustained oil demand growth, particularly from the more consumerorientated lighter-end of the barrel. Such resilience looks harder to sustain in the near term in the
face of collapsing stock markets and concern about the growth of the underlying economy. We
assume that China’s average demand growth eases to 0.3-to-0.4 mb/d to 2021. The slow-down could
be greater, depending on the pace of closure of excess capacity in energy intensive industries,
notably coal, steel and cement.
Despite the generally weakening Chinese demand outlook, more consumer-focused gasoline demand
continues to rise sharply, adding approximately 6.8% per annum, 2015-21. The robust gasoline
numbers derive from strong growth in the Chinese vehicle fleet, with annual additions likely to be
just below 10% even against a background of a slowdown in the wider economy. Alongside this
growth in vehicle population are efficiency gains of approximately 2.3% per annum to 2021. In 2014
the average fuel efficiency of a newly sold passenger light duty vehicle in China was 7.1 litres of
gasoline per 100 kilometres (km); by 2021 the consumption will fall to 5.5 litres/100 km. In the longer
term, efficiency gains could be even higher if the State Council’s 5.0 litres/100 km target for 2020 is
actually achieved. It is these efficiency gains, which are replicated in other sectors of the Chinese
economy, coupled with government efforts to curb energy demand in order to satisfy tighter cleanair regulations that are paring back the rate of oil demand growth. Added to this are wider concerns
about overall economic growth.
Figure 1.8 Chinese oil demand, 2009-21
16.0
14.0
LPG
mb/d
12.0
Naphtha
10.0
Motor Gasoline
8.0
Jet & Kerosene
6.0
Gasoil/Diesel
4.0
Residual Fuel
2.0
Other Products
0.0
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Even though the rate of growth is slower, China will add 2.5 mb/d of additional demand to 2021, at
3.4% per annum. In the previous six-year period the average growth rate was closer to 5%. Until
recently, and it is still the case in some regions, the focus was on energy intensive, heavy
manufacturing industries requiring substantial quantities of industrial fuels. Now, there is a shift to a
more consumer-focused economy which will provide support for gasoline and jet fuel demand at the
expense of gasoil, fuel oil and ‘other products’ (including bitumen). Chinese gasoil demand growth
underperforms the previous six-year average by 1.3 percentage points, as diesel demand growth is
restrained by government curbs on industrial oil use while flat or possibly declining Chinese coal
demand (see the IEA’s Medium-Term Coal Market Report, 2015) reduces the requirement to move
larger volumes of coal across the country. This has an impact on the use of diesel locomotives and
trucks, the principle means of moving coal.
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2009
D EMAND
The Indian demand outlook is particularly favourable, with 1.1 mb/d of demand forecast to be added
to 2021, an average annual increase of 4.2%. Road transport fuels lead the Indian upside with a sharp
increase in vehicle fleets supporting growth in both gasoline and diesel. The recent removal of diesel
subsidies, and deliberate city-specific efforts to slow diesel sales, means that gasoline demand
growth potentially outpaces that for diesel. From December 2015 through to early January 2016, the
city of Delhi banned the registration of diesel-fuelled vehicles with an engine capacity greater than
2 000 cc in an attempt to tackle chronic air pollution and it is possible that similar measure will be
taken around the country.
The IEA’s transport model assumes double digit per annum percentage gains in the size of the Indian
gasoline fleet, easily offsetting the potential curbing of demand from vehicle efficiency gains.
Strenuous methods are, however, being adopted to curb Indian oil demand growth, which restrain
momentum. For example, vehicle fuel-efficiency standards mandate an average fuel economy per
new vehicle of 6.0 litres per 100 kilometres, falling to 5.5 litres by April 2017 and 4.8 litres in 2022-23.
Anecdotally, the incentive towards even more efficient vehicle purchases is raised as all new vehicles
will be required to carry obligatory efficiency ratings from 2H16, potentially adding a second-hand
premium to more efficient vehicles. Even so, these measures may at least be partly undone by
substantial road building programmes that will increase the number of vehicles – whether gasoline
or diesel – that undertake journeys.
Figure 1.9 Cumulative Indian oil demand growth, 2001-21
3.5
LPG
3.0
Naphtha
mb/d
2.5
2.0
Motor Gasoline
1.5
Jet & Kerosene
1.0
Gasoil/Diesel
0.5
Residual Fuel
0.0
-0.5
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Other Products
Other important non-OECD Asian demand centres, such as Indonesia, Pakistan and Malaysia, are also
forecast to grow sharply to 2021 with strong population growth and low vehicle ownership rates
being the key factors. Indonesia, the world’s fourth most populous country, will add another
20 million people between 2015 and 2020, according to UN projections, and more than half the
population will be 30 years old or less. Indonesia offers strong upside for transport fuels with
gasoline demand forecast to grow by a relatively conservative 4.4% per annum to 2021 as a rapidly
expanding middle-class buying vehicles outweighs any efficiency gains that are locked into the global
vehicle stock.
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For the relatively developed countries in the region - Thailand, Hong Kong and Singapore - oil
demand growth rates will naturally be lower. In Thailand, for example, oil product demand will grow
by approximately 1.4% per annum to 2021 as gains in the transport sector remain hamstrung by
D EMAND
already high levels of traffic congestion in major cities such as Bangkok. Similar problems restrain the
forecast for Singapore, although IMF projections of trade growth expanding by around 4.6% per
annum in the period 2017-20 (World Economic Outlook, October 2015) support a strong bunker fuel
market, a major contributor to both the Singapore economy and oil demand.
Box 1.4 Key Southeast Asian oil demand trends
Oil demand in the 10 countries of Southeast Asia (SEA-10; Brunei, Cambodia, Indonesia, Lao, Malaysia,
Myanmar, Philippines, Singapore, Thailand and Vietnam) has risen progressively, from 5.4 mb/d in 2011
to 5.8 mb/d in 2013. Oil remains the largest contributor to total primary energy demand (TPED) in 2013
at 36%, followed by gas at 22%, and coal at 15%. Between 2016 and 2021, oil demand in the SEA-10
region is expected to increase at a compound annual growth rate of approximately 3.1% per annum,
while the share of oil in TPED begins to slow with continued fuel switching from oil to coal and gas in
power generation and industry, improvements in efficiency in the transport sector and policies to
enhance fuel diversification away from the traditional reliance on oil and gas (see World Energy Outlook
Special Report on the Southeast Asia Energy Outlook 2015, IEA, 2015).
As in most of the world, the transport sector is the key driver for oil demand in SEA-10. Transport
accounted for roughly a half of total oil demand in the region in 2013 and is expected to increase to 55%
by 2021 as rising incomes, relatively low oil product prices and limited public transport options
contribute to strong growth in private vehicle ownership across the region. The growth rate in demand
could slow if fossil fuel subsidies are phased out, fuel economy standards are tightened, and more mass
transit projects come online. Nevertheless, oil is expected to remain the dominant transport fuel
through 2021.
The share of oil in power generation stood at 6% in 2013 but is expected to decline to 3% in 2021 as the
region’s generation mix increasingly shifts to coal (43% by 2021), alongside growth in gas-fired
generation (37% by 2021) and renewable energy generation (16% by 2021). At present diesel-fired
generation still makes up 55% of the generation mix in Cambodia and 13% in Indonesia, where many of
the 6 500 inhabited small islands continue to rely on small-scale diesel-fired generation for electricity. In
order to meet projected electricity demand growth in SEA-10 of 3.9% p.a. on average most countries
plan to add significant coal capacity over the next five years and replace rural and remote dieselgeneration sets with renewable off-grid solutions.
Oil for agriculture and non-energy use (such as feedstock for chemical and petrochemical plants) is
projected to retain a steady average of around 7% of the share of TPED in SEA-10 between 2013 and
2021.
Transport sector –sustaining demand
Recent trends in vehicle sales in key southeast Asian markets
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SEA-10s transport sector oil demand is projected to increase by 20% between 2010 and 2021, rising at
an annual rate of 2%. Despite the substantial growth, the projected growth rate of the transport sector’s
energy demand in Southeast Asia is expected to be slower than the historical trend (5.3% per year
between 1990 and 2010) due to the build-up of vehicle stocks in some countries, modal shifts within the
major cities of the region, and changes to fuel pricing and vehicle efficiency.
D EMAND
Box 1.4 Key Southeast Asian oil demand trends (continued)
At present, most passenger vehicles in ASEAN countries are motorised two-wheeled drivers (2Ws),
hence large consumers of gasoline as opposed to diesel. In Indonesia, motorcycles account for
approximately 82% of the vehicle fleet of 85 million (passenger cars in the region account for 9.5 million,
or 11%). 9.5 million). In Vietnam, a full 95% of passenger vehicles are 2Ws. This implies a future shift to
larger four-wheel vehicles as income rises across the region which will increase demand for motor-fuels.
Vehicle sales will continue on an upward trajectory over the long term, despite the fluctuation of short
term vehicle sales in the past couple of years as economic growth slowed in ASEAN’s biggest markets for
motor vehicles – Indonesia, Malaysia and Thailand. Having reached a record high of 3.6 million units sold
in 2013, the sale of motor vehicles in ASEAN decreased by 9.9% in 2014 and has just started to recover
in the second half of 2015 after currency depreciation, high household debt, and rising inflation
contributed to a steep drop in vehicle purchases in these three key countries that make up some 86% of
total motor vehicle sales in ASEAN. As of October 2015, four-wheel motor vehicle sales in Indonesia are
still 16.1% lower compared to the year before, 4.1% lower in Thailand and a marginal 2.9% higher in
Malaysia. Elsewhere in ASEAN, the share of vehicle sales is smaller but nevertheless growing strongly as
countries enter the middle-income country bracket.
Fuel economy standards
As of 2015, fuel economy standards for light duty vehicles (LDV) are being developed in Indonesia,
Philippines, Thailand and Vietnam. Vietnam has submitted fuel economy standards for LDV and
motorcycles for approval by the Ministry of Transport, while Thailand is in the process of defining
automotive fuel economy standards. The Philippines and Indonesia are conducting baseline calculations
to set fuel economy standards and cost-benefit analyses on fuel quality and fuel economy, respectively.
The implementation of fuel economy standards for LDV and heavy duty vehicles (HVD) could save some
446 billion liters of diesel and 134 billion liters of gasoline in the four ASEAN countries between 2012
and 2035, according to the Global Fuel Economy Initiative.
Changing transport fuel mix
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A number of Southeast Asian governments are also supporting the use of biofuels and biodiesel
blending. In 2013, the Malaysian government built 35 biodiesel blending facilities across the country to
support the implementation of the biodiesel B5 programme (5% biodiesel blending in automotive fuel),
which was upgraded to the bio-diesel B7 programme (7% biodiesel blending) by late 2014. Malaysia
expects the B7 program to offset 667.6 million litres of diesel with 575,000 tonnes of biodiesel each
th
year, according to the 11 Malaysia Plan Strategy. Thailand has also set a target of 20% for biofuels in
transport fuel use by 2036 while Indonesia has mandated minimum percentages of ethanol and
biodiesel blending for transport in a Ministerial Regulation since 2008, and which have been revised
upward in subsequent years. The latest regulation mandates a 15% blending of biodiesel for transport
fuels in 2015 (unfulfilled). Indonesia is now gearing up to meet a 20% share, and a longer-term increase
to 30% by 2025. Given current oil prices, satisfying this regulation may prove challenging. The regulation
also mandates a 1% blending of ethanol for transport Public Service Obligation (PSO, i.e. subsidised fuel
for road vehicles) and 2% in transport non-PSO in 2015, increasing to 20% in 2025. So far little activity
has been seen in the Indonesian ethanol market and the IEA is cautious over plans to expand its reach.
Indonesia is aiming for 2% biofuel blend for aviation fuels starting in 2016, with further plans to
mandate blending up to 3% by 2020 and 5% by 2025.
D EMAND
Box 1.4 Key Southeast Asian oil demand trends (continued)
The City of Jakarta is taking the lead in promoting fuel switching in the process of purchasing
Compressed Natural Gas (CNG) vehicles, with 450 TransJakarta CNG buses and 800 CNG minibuses
delivered by the end of 2013 and a further 1 000 buses and 3 000 minibuses by the end of 2014. The city
council is also planning to convert all official cars to CNG, as well as 3 000 bajaj (three-wheeled taxis)
each year to CNG. (IEA IDR 2015).
In the Philippines, the Department of Energy (DOE) has been encouraging the use of LPG as an
alternative automotive fuel since 2006, and has developed five sets of standards for the use of the fuel.
As of the end of 2011, the Philippines DOE has established 19 052 units of auto-LPG taxis and 217
refilling stations across the country. The Philippines also introduced an Energy Efficient Electric Vehicles
(E-Trike) project, which aims to replace 100 000 traditional gasoline-fuelled tricycles with electric
powered tricycles nationwide by 2018 and reduce petroleum consumption in the transport sector by
2.8% (or 89.2 million litres) per year. The transport sector accounted for over 33% of the Philippines
total final energy consumption in 2013.
Increasing demand for aviation fuel from low cost carriers
SEA-10 has one of the fastest growing aviation markets in the world. The capacity of short-haul low cost
carriers (LCCs) and full service carriers (FCCs) in SEA-10 has expanded significantly over the last ten
years. Whereas LCCs increased eight-fold from 25 million seats to almost 200 million seats between
2004 and 2014, full service carriers (FSC) have seen capacity expansion of 45% with seats increasing
from 180 million to 260 million.
This trend is expected to continue with the implementation of the ASEAN Open Skies Agreement at the
end of 2015 which may lead to a further expansion of the market share of LCCs’ which grew from only
5% in 2004 to 25% in 2014. The 22 LCCs based in Southeast Asia added 60 aircrafts in 2014 alone, or 12%
of the overall fleet of 540 aircrafts. In the previous year, the LCC fleet grew by 20%. Indonesia’s aviation
growth potential is particularly noteworthy. According to the Ministry of Transport, the number of
aircraft operating in Indonesia has risen from 962 to 1 319 between 2008 and 2012, while air passengers
have nearly doubled from 41.5 to 77.2 million between 2008 and 2013. By 2034, the International
Aviation Transport Agency (IATA) projects that Indonesia will triple to become the world’s sixth largest
market for air travel with around 270 million passengers flying in and out of the country, which will
contribute to a significant increase in aviation fuel demand over the projection period.
According to the Centre for Asia Pacific Aviation (CAPA), in 2015 Southeast Asia is the only region in the
world that is buying as many new aircrafts as are currently active. This trend is not expected to last and
will lead to restructuring in service provisions and fleet contracting strategies to reduce overcapacity in
the future which will slow aviation fuel demand growth in the long-term. Accordingly, jet fuel demand in
the region is forecast to expand by around 3% per annum, 2015-21.
Former Soviet Union (FSU)
32
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Although oil demand prospects across the economies of the FSU have been dampened by the
region’s macroeconomic travails, the latest data has, if anything, been surprisingly resilient. Down by
0.1 mb/d in 2015 to 4.9 mb/d, total FSU oil deliveries stood 0.2 mb/d above the forecast made in the
2015 MTOMR. A major factor was that in the face of sharply contracting FSU economic activity, the
value of many regional currencies fell heavily. Big currency depreciations meant that dollars earned
from exports bought many more rubles at home – about 60% more in 2015 – providing some support
to industrial activity.
D EMAND
For the future, assuming FSU currencies do not deteriorate too much more in 2016, oil demand
forecasts have been refocused on weaker macroeconomic underpinnings, with the IMF in January
2016’s World Economic Outlook forecasting zero GDP growth. This justifies the IEA’s own forecast of
a 0.2% decline in FSU oil demand in 2016.
After two tough years in 2015 and 2016, the outlook for FSU oil product demand brightens to 2021,
supported by an improving macroeconomic backdrop and the general expectation that oil prices will
likely rise, as well as higher prices for other commodities important to the region. For example,
higher copper prices will benefit countries such as Kazakhstan. With oil demand falling for two
successive years in 2015 and 2016, Russia is forecast to gradually recover supported by economic
growth that averages around 1.4% per annum in the period 2017-20, according to the IMF’s October
2015 World Economic Outlook. The key Russian oil demand supports, post-2016, will be the
petrochemical and jet fuel markets, as now entrenched efficiency gains across the Russian road
vehicle fleet curb both prospective gasoline and diesel demand.
Table 1.6 Former Soviet Union oil demand (mb/d), 2015-21
LPG
Naphtha
Gasoline
Jet/kerosene
Gasoil
Residual fuel oil
Others
Total
2015
2016
2017
2018
2019
2020
2021
2015-21
0.5
0.4
1.2
0.4
1.0
0.5
1.0
4.9
0.5
0.5
1.2
0.3
1.0
0.4
1.0
4.9
0.5
0.5
1.2
0.3
1.0
0.4
1.0
4.9
0.5
0.5
1.2
0.3
1.0
0.4
1.0
5.0
0.5
0.5
1.2
0.4
1.0
0.4
1.1
5.0
0.6
0.6
1.2
0.4
1.1
0.3
1.1
5.1
0.6
0.6
1.2
0.4
1.1
0.3
1.1
5.2
0.1
0.2
0.0
0.0
0.1
-0.2
0.1
0.3
Latin America
Regional demand growth rises only modestly to 7.1 mb/d in 2021. Demand is stalled at 6.8 mb/d in
2015-17 as the economy stutters, particularly in Brazil, Venezuela and Argentina. Falling commodity
prices, not just for oil, have reduced import revenues, which, along with governance issues in some
counties – notably Brazil – have dampened economic activity. The IMF’s January 2016 World
Economic Outlook cited a decline of around 0.3% for GDP in 2015 for their “Latin America and the
Caribbean” regional definition, this at a time when oil demand eases back by 0.8% in our non-OECD
Latin American region. Looking ahead to 2016, the IMF envisages a further decline in economic
activity of around 0.3%, before picking up in 2017 to 1.6%.
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© OECD/IEA, 2016
Having risen by around 4% per annum over the previous five-year period, gasoline demand growth in
Brazil will ease back substantially over the medium-term. Slower growth in the vehicle pool,
alongside a near 2% per annum efficiency gain, combines to restrain Brazilian gasoline demand
growth. Rising only modestly, from an estimated 1.0 mb/d in 2015 to 1.1 mb/d in 2021, Brazilian
gasoline demand growth averages 1.0% per annum, down sharply on the previous six-year trend of
6.3% per annum.
D EMAND
Figure 1.10 Brazilian oil demand, 2009-21
mb/d
3.5
3.0
LPG
2.5
Naphtha
2.0
Motor Gasoline
Jet & Kerosene
1.5
Gasoil/Diesel
1.0
Residual Fuel
0.5
Other Products
0.0
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
Brazilian biofuels, which are included in IEA Oil Market Report definitions of gasoline/diesel demand,
play an increasingly important (and likely to rise) role in Brazilian oil demand. In 2015, for example,
hydrous ethanol consumption rose by around 40% due to federal tax increases for non-biofuel
gasoline, which complimented by favourable changes in regional taxation in some states, increased
competitiveness with gasoline at the pump. When considering other factors such as the widespread
utilisation of flex-fuel light passenger vehicles, which account for over 90% of vehicle registrations,
and the central nature of biofuels to Brazil’s Intended Nationally Declared Contribution, which
includes an expansion of biofuel consumption as a key decarbonisation measure. Biodiesel growth
potential is associated with a gradual increase in the biodiesel blending mandate from the current 7%
to 10% within the next three years, while the National Council of Energy Policy has already
authorised the sale and voluntary use of higher biodiesel blends of between 20-30% depending on
their end use. Based on these factors growth in biofuels consumption over the medium-term can be
expected, although this will be sensitive to tax and mandate changes. However, the current
economic downturn will offset some increased demand for its duration. Both light passenger vehicle
sales and gasoline-C, containing a 27% blended share of ethanol, saw a pronounced decline in 2015.
The latter offsetting an expected increase in blended ethanol from the increased blending mandate.
Outside of Brazil, the Latin American oil product demand forecasts generally remain relatively
subdued, restrained by comparatively weak gasoil/diesel projections versus gasoline. The forecast
gains in the scale of the non-Brazilian Latin American diesel fleet roughly match the assumed average
per annum efficiency gains. Modest gains, meanwhile, are forecast in non-Brazilian Latin American
gasoline demand, supported by fleet increases (+3.3% per annum) roughly double projected
efficiency gains.
The Middle East has been heavily affected by falling oil export revenues: the region’s OPEC members
saw revenue fall by USD 325 billion in 2015 and this has led to initiatives to curb fuel subsidies.
Regional oil demand forecasts are therefore pared back from recent higher levels. An exception will
be post-sanctions Iran, as the benefits from greater economic freedom likely exceed the downside
from lower oil prices. Oil demand growth across Iran will rise by an average 2.6% per annum to 2021
as trade grows, industrial activity picks up, and transportation fuel demand increases. Jet fuel
demand forecasts will be particularly strong, rising by a forecast 2.9% per annum to 2021, as
34
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Middle East
D EMAND
international travel opens up. Other Middle Eastern jet fuel markets will expand: in the
United Arab Emirates jet demand will increase by 3.7% per annum 2015-21 on the back of growing
tourism. Air passenger visits to the country will likely rise, as nearly 40% of the world’s population
live within a four-hour flight time. The International Air Transport Association has forecast Middle
Eastern air passenger demand rising by around 4.9% annually through 2034; efficiency gains to the
airplane stock likely curb jet fuel demand growth to around 3.2% per annum to 2021 for the Middle
East as a whole.
The oil demand forecast for Iraq shows 3.2% per annum growth to 2021, supported by upbeat
macroeconomic assumptions. The IMF’s World Economic Outlook, October 2015, forecast average
GDP growth of 7.5%, to 2020. The downside risks are obvious: the presence of ISIS forces in
significant parts of the country and the spill-over effect from the Syrian civil war.
Table 1.7 Middle East oil demand (mb/d), 2015-21
LPG
Naphtha
Gasoline
Jet/kerosene
Gasoil
Residual fuel oil
Others
Total
2015
1.3
0.1
1.6
0.5
2.2
1.5
1.1
8.2
2016
1.3
0.1
1.6
0.5
2.2
1.5
1.1
8.3
2017
1.3
0.1
1.6
0.5
2.3
1.5
1.1
8.5
2018
1.4
0.1
1.7
0.6
2.4
1.5
1.1
8.7
2019
1.5
0.1
1.7
0.6
2.4
1.5
1.1
9.0
2020
1.6
0.2
1.8
0.6
2.8
1.3
1.1
9.2
2021
1.6
0.2
1.8
0.6
2.8
1.3
1.1
9.5
2015-21
0.4
0.1
0.2
0.1
0.7
-0.2
0.1
1.3
With Kuwait determined to invest heavily through the current lower oil price environment, oil
product demand growth in the country should remain relatively strong at about 3% per annum to
2021. Although not all of Kuwait’s current USD 93 billion investment plans will see the light of day,
with 29 infrastructure projects pencilled in by 2020, much of it will. Supporting robust gasoil demand,
via the additional construction-spend, jet fuel demand could also rise significantly if plans to expand
the Kuwaiti International Airport are completed in time.
Figure 1.11 Cumulative demand growth, 2001-21
10
OECD
8
mb/d
6
China
4
Other Asia
2
0
Middle East
-2
Others
-4
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35
© OECD/IEA, 2016
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
D EMAND
Saudi Arabia will see relatively low oil demand growth of approximately 1.8% to 2021. As recently as
2014, before oil prices began their relentless slide, oil demand grew by 6% The IMF, for example,
towards the end of 2015 warned that the Kingdom could deplete its financial buffers in less than five
years if oil prices were to stay low. Such fears triggered an ambitious December budget that
announced hikes in domestic fuel prices, alongside sizeable government spending cuts, removing two
of the key supports behind the previously robust Saudi Arabian oil demand trend. The finance
ministry highlighted that infrastructure and transport spending would be cut by more than 50%,
potentially delaying the planned new metro lines and regional rail projects. Furthermore, dramatic
subsidy cuts, such as those implemented in January 2016 (see Oil price declines could drive further
reform on fossil fuel subsidies), curb prospective Saudi Arabian oil demand growth. Other lagging
Middle Eastern economies, through the forecast period, include the geopolitically hamstrung
economies such as Syria and Yemen. The existence of this last category adds an additional layer of
uncertainty to the Middle Eastern demand forecast, as a surprisingly quick resolution of their
problems would rapidly result in much more supportive macroeconomic conditions and in turn
higher oil demand.
Box 1.5 Marine gasoil to seize bunker fuel market share
The largest inter-product demand switch over the forecast is expected to result from a broad tightening
in the legislation regulating the emission of pollutants from ships. As shippers react to these changes, it
is expected that 2.0 mb/d of demand will switch from residual fuel oil to gasoil. The repercussions of this
switch will be acutely felt across product markets and throughout the global refined product supply
chain.
International shipping is regulated by legislation set by the International Maritime Organisation (IMO)
under its International Convention for the Prevention of Pollution from Ships (MARPOL). Since its
adoption in 1973, MARPOL set regulations aimed at preventing and minimizing pollution from ships. The
next major set of legislation set to be included under the framework is due to come into force on
1 January 2020 and sets out a global cap limiting the sulphur oxide (SOx) emissions from ships to 0.5%
from the 3.5% currently permitted. However, although this is current policy, it is subject to a fuel
availability study due to be conducted by the IMO and published before 1 January 2018. Depending on
the outcome of this study, the introduction of the global cap could be deferred to 2025. Regardless of
the IMO decision, the European Union has decided to introduce a 0.5% SOx limit in its territorial waters
which fall outside of Emission Control Areas (ECAs) in 2020.
Figure 1.12 Oil based marine fuel consumption in international navigation
4.50
4.00
mb/d
3.50
Gasoil
3.00
2.50
2.00
1.50
1.00
Residual Fuel Oil
0.50
0.00
36
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
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2000
D EMAND
Box 1.5 Marine gasoil to seize bunker fuel market share (continued)
The tighter legislation essentially outlaws vessels from burning fuel containing more than 0.5% sulphur
unless they install on-board abatement technology to de-sulphurise engine emissions before reaching
the atmosphere. Therefore, the other option is for vessels to switch to a fuel with a sulphur content of
less than 0.5%. Due to the safety aspects of light distillates, middle distillates are favourable with marine
gasoil the preferred option due to its ability to be used in engines previously fuelled by residual fuel oil.
One of the concerns and possible reason for a delay, behind a global sulphur cap regards the uncertainty
of how it will be enforced. Currently, both direct and indirect methods are used to monitor compliance
in ECAs. These include in-port verification of bunker fuel paperwork and the monitoring of vessel
smokestack emissions at sea using aeroplanes and, more recently, drones. There are also large
differences between the penalties imposed on non-compliant vessels in ECAs. The penalties imposed in
North America are more severe than elsewhere. The US coastguard has the power to seize vessels found
to be in breach of regulations with the owners liable to be heavily fined.
The enforcement in Northwest Europe is less clear with each EU state responsible for policing its own
waters. Since there is no global organisation tasked with controlling and enforcing vessels in
international waters, the introduction of a global cap will likely raise similar issues to those in EU waters.
Nonetheless, all major shippers and the bodies which represent them such as the International Chamber
of Shipping have stated that they will comply with the new regulations, suggesting limited large scale
non-compliance with a global cap in 2020.
Global international marine bunker demand is expected to remain broadly flat over the projection
period. This includes vessels on international voyages and does not include domestic shipping
consumption, which is included under domestic demand. The lack of growth is in contrast to the solid
growth posted over the past couple of decades which was driven by global economic growth. Demand
growth is expected to be curbed going forward by two main factors. Firstly, increasing vessel efficiency,
which will come from the move towards larger vessels improving economies of scale economics, and
also from the increasing efficiency of engines. Secondly, from the steady encroachment of liquid natural
gas (LNG) in the marine fuel market. These are expected to offset the positive effects of vessels
travelling faster which, as bunker prices have fallen over the past 12 months to currently sit at 13-year
lows, has seen the end-of slow steaming which had been common over 2012-14.
In 2015, the global oil product bunker market was dominated by residual fuel oil, accounting for 81% of
the market, marine gasoil the rest. This was a change to 2014 when, upon the introduction of tighter
MARPOL legislation limiting the SOx emissions of vessels to 0.1% in ECAs located in Northwest Europe,
North America and the Caribbean, 0.1 mb/d switched from residual fuel oil to gasoil. Additionally, the
Chinese administration has recently decided to designate three non IMO-affiliated ECAs located in the
Pearl River, Delta, Yangtze River Delta and Bohai Bay, which will limit SOx emissions to less than 0.5%.
The timing of this implementation is uncertain but will likely come into force before 2020 with the ECA
in the Yangtze River delta due to be inaugurated on 1 April 2016.
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Although the default response from shippers to the legislation will be to switch to low sulphur fuels, onboard abatement technology will have a large role to play in helping shippers and refiners meet the
challenge of the tighter legislation. Such technology is often referred to as scrubbers since they
essentially scrub the sulphur from a vessel’s emissions with the resulting highly sulphurous waste
disposed of safely in port. Despite these systems costing around USD 3 – USD 5 million , there are
several uncertainties associated with them. Firstly, if MARPOL legislation proceeds along the same lines
as has legislation regulating the emissions from terrestrial motor vehicles, then future legislation can be
expected to impose limits on pollutants such as nitrous oxide (NOx) and particulate matter. There is no
certainty that scrubbers can clean emissions to future compliance levels. Secondly, the decision to install
a scrubber is essentially a function of how long a vessel will spend in an ECA and its expected lifespan
(payback time).
D EMAND
Box 1.5 Marine gasoil to seize bunker fuel market share (continued)
Therefore, a scrubber will likely make good financial sense on a new build once the global cap is
introduced but will make less sense for a vessel with only 10 years of its life remaining. Thirdly, the units
are expensive and, while much of the equipment can be installed at sea, it nonetheless requires vessels
to be taken out of service of a period of time which adds further to the cost. These drawbacks are
therefore expected to limit the adoption of scrubbers before 2020.
The final way for vessel owners to comply with the global sulphur cap is by switching to a completely
new fuel. The main alternative fuel is LNG which, although used to power the natural gas carrier fleet for
a number of decades, is rare among other vessel classes. Currently, LNG accounts for a small share of
the global bunkering market but is expected to soar over the next five years so that by 2021 it will
replace approximately 0.3 mb/d of oil-based bunker fuel. Nonetheless, in order for LNG to become the
bunker fuel of the future and to further increase its market share it must overcome several obstacles:
• Underdeveloped legislation. There is no globally recognised set of regulations which govern how LNG
must be handled in port and on board vessels. Slow progress is being made, a number of major ports
have introduced regulations for LNG bunkering, and in the case of the port of Rotterdam, have
introduced incentives for vessels to bunker with LNG.
• Nascent infrastructure. Although infrastructure is currently being built out at a number of major
bunkering terminals in ECA’s, and especially at terminals previously connected to pipeline gas
networks, it has not proliferated smaller terminals due to the cost of transporting the LNG there.
• On board difficulties. To remain in a liquid state, natural gas must be stored at -162°C; this requires
the installation of insulated tanks which are larger than tanks on a normal vessel which takes up
valuable cargo space. LNG-powered vessels are also 20% - 40% more expensive to construct than a
comparable vessel running on oil and it is extremely expensive to retro-fit an existing vessel to run on
LNG.
• Low oil prices. Following the recent collapse of bunker prices to 13-year lows, the economics of LNG
bunkering have significantly eroded. By early-January 2016, natural gas was being traded at a small
premium to fuel oil with gasoil’s premium standing at less than USD 2/MBtu. If these economics
persist over the coming years, they will significantly reduce the adoption of LNG bunkering.
Figure 1.13 Discount of natural gas delivered at United Kingdom national
balancing point to Rotterdam gasoil and fuel oil barge prices
20
$/MBtu
15
Fuel oil
10
5
Gasoil
0
38
Jul-2013
Jan-2014
Jul-2014
Jan-2015
Jul-2015
Jan-2016
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© OECD/IEA, 2016
-5
Jan-2013
D EMAND
Box 1.5 Marine gasoil to seize bunker fuel market share (continued)
Despite these hurdles, recent adopters of the fuel have included a number of ferries in Northern Europe
running on fixed routes where LNG bunkering infrastructure is available at both ends of the voyage,
while recent reports indicate that a number of cruise ship operators have also begun to seriously
investigate the option of building LNG powered vessels. Nonetheless, these companies, together with
ferry operators are often making the choice to run on LNG to express their ‘green’ credentials rather
than for economic factors. It is also noteworthy that a number of newly constructed and ordered vessels
are being designed with the future possibility of installing LNG tanks with these ‘dual fuel’ vessels
capable of switching between oil and LNG.
It is expected that the majority of shippers will revert to burning marine gasoil upon the introduction of
the global cap. As was seen in 2015, when faced with tighter environmental legislation, the majority of
shippers decided upon the less capital intensive option and switched to compliant fuels when sailing in
ECAs. Many shippers, especially cargo vessels, added a fuel surcharge to pay for the more expensive low
sulphur fuel and a similar trend is expected in 2020.
Despite the assumption that upon the immediate introduction of the global SOx cap, marine gasoil
demand is forecast to soar by 2.0 mb/d to reach 2.7 mb/d in 2020, this is expected to be peak demand
over the medium-term with demand set to fall by 0.1 mb/d in 2021. It is assumed that post-2020,
scrubber adoption will increase as vessel owners are faced with concrete pricing signals in futures
markets. The basis for this is expected to be spread between gasoil and residual fuel oil, which will
widen significantly as gasoil oil demand surges while fuel oil demand collapses. The shipping sector is
cash-strapped and a scrubber requires a significant capital investment which may be uneconomic to
install and run before the introduction of a global cap which may limit their adoption. As 2020
approaches, and forward curves better reflect reality, if there is a strong pricing signal – gasoil holding a
high premium over fuel oil, there will undoubtedly be an increase in scrubber installation. Moreover,
considering the time taken to install a scrubber, firstly in dry dock and then at-sea, it is likely that not all
orders will be able to be fulfilled by end-2019 which will see some ‘spill over’ into 2020 and beyond.
By the end of the forecast, marine consumption is expected to account for 8% of total gasoil demand.
The surge in 2020 will likely translate into a significant price increase, potentially to levels that could
force consumers out of the market.
On the other hand, global fuel oil demand is projected to collapse, below 5 mb/d in 2020, as fuel oil
bunker demand plummets. In 2014, before the tighter regulations in ECAs, bunker demand accounted
for 43% of global fuel oil demand; this is then projected to fall to 24% in 2020 before a slight uptick to
25% in 2021 as scrubber installation continues to rise. Considering the polluting nature of fuel oil and
the raft of environmental legislation tightening controls on many sectors, fuel oil is running out of uses.
Over the past decade, its demand for power generation has fallen as it has been replaced by cleaner
natural gas while its use in the developing world in the industrial and agricultural sectors is on the
decline. The price of fuel oil is expected to plummet in tandem with demand. This will in turn put
pressure on cracks and simple refiners with high fuel oil yields. Conversely, it could become more
attractive to modern, complex refiners who have the secondary units capable of upgrading fuel oil into
higher value lighter products.
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Global refiners will be put under enormous strain by the shifting product slate. If refiners ran at similar
utilisation rates to today, they would be unlikely to be able to produce the required volumes of gasoil. If
they increased throughputs to produce the required gasoil volumes, margins would be adversely
affected by the law of diminishing returns. In order to increase gasoil output, less valuable products at
the top and bottom of the barrel would be produced in tandem which would likely see cracks for these
products weaken and weigh margins down.
D EMAND
Box 1.5 Marine gasoil to seize bunker fuel market share (continued)
Therefore, the global refinery system requires significant investment in order to fill the projected
distillate demand. If refiners are to meet this challenge, they have two main investment paths: Firstly, to
invest in secondary units such as crackers, visbreakers and cokers to refine the fuel oil into middle
distillates. The upshot would be that fuel oil would move to become more of a refinery feedstock than a
finished product. Secondly, by constructing desulphurisation units which could de-sulphurise fuel oil to
the required 0.5% level. The drawback is that these units are more expensive than upgrading units.
Presently there is little demand for fuel oil desulphurisation units, with global capacity estimated to be
less than 0.1 mb/d.
One wild card is China. Historically, Chinese refiners have generally only produced products for the
domestic market which left them with spare refining capacity. In future, if they chose to hike runs they
could supply extra middle distillates for international markets which would go some way to meeting the
forecast demand surge. In 2015, for example, when domestic gasoil demand was stagnant, China hiked
its gasoil exports to over 0.2 mb/d.
A mass switch of bunker fuels from fuel oil to marine gasoil will have global repercussions. Regions such
as Other Asia, home of Singapore, one of the world’s largest bunkering hubs, will switch from a net
gasoil exporter to an importer while Europe will become even shorter of middle distillates and the FSU
will struggle to find markets for the overhang of fuel oil produced there. As regions flip from being netexporters to net importers, infrastructure will have to be constructed and adapted. This will involve the
reconfiguration of storage tanks to hold clean products rather than fuel oil, the construction and
reversal of pipelines to take the middle distillates to coastal bunkering terminals while new bunker
barges will be required as economies of scale are used to transport gasoil on larger and larger vessels,
ports will have to be dredged and adapted to take larger ships.
40
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© OECD/IEA, 2016
Environmental legislation concerning marine emissions will undoubtedly be tightened over the next
decade but presently the uncertainty over timing is preventing both refiners and end-consumers from
taking efficient long-term business decisions. As the uncertainty clears over the next couple of years it
will become apparent how the industry will react to changes and, in doing so, will answer the
fundamental question of whether the sulphur will be stripped out of bunker fuel at the point of
production or the point of end-use.
S UPPLY
•
Global oil capacity growth will slow considerably over 2015-21, to 3.3 mb/d. Lower oil
prices are eroding the world’s supply capacity, with spending cuts curbing growth in new
output from both OPEC and non-OPEC. Non-OPEC production, including biofuels, accounts
for 2.0 mb/d or 60% of the increase, OPEC crude capacity rises by 800 kb/d, while OPEC
natural gas liquids grow by 475 kb/d.
•
Global exploration and production spending is expected to decline for a second straight
year in 2016. A drop of 17% follows on from a 24% reduction in upstream spending in 2015.
The sharpest cuts are planned for the United States.
•
Spending cuts are have been partly offset by cost reductions across the supply chain.
Upstream costs, as measured by the Bureau of Labor statistics for foreign and US companies
operating in the US, continued to fall through 2015. By end-year, the cost of drilling new
wells had fallen by nearly 26% since its peak in June-2014.
•
After a projected decline of 0.6 mb/d in 2016, non-OPEC supply will hold steady in 2017
and recover from 2018. By 2021, non-OPEC supplies will reach 59.7 mb/d, 2.0 mb/d higher
than in 2015. While non-OPEC supply surprised with its resilience in 2015, overall production
estimates for 2020 are 0.4 mb/d lower than those presented in the 2015 MTOMR.
•
The Americas continue to dominate the growth picture through 2021. The United States
remains the number one source of supply growth, adding 1.3 mb/d over the forecast period,
followed by Brazil (+0.8 mb/d) and Canada (+0.8 mb/d). US light tight oil (LTO) is expected to
decline through 2017, before an expected rebound in prices resets growth from 2018. In all,
US LTO reaches 5.0 mb/d in 2021, up 770 kb/d versus 2015.
•
Despite a significant increase in production in 2015, Russia will see the steepest output
declines over the medium term. Non-OPEC’s largest crude and condensate producer defied
earlier expectations by setting a new supply record in 2015, but by 2021, supplies are likely
to be 275 kb/d lower due to accelerated field decline, capital expenditure constraints and
stronger fiscal pressures.
•
OPEC crude oil production capacity rises by only 800 kb/d by 2021 as lower oil prices force
the re-consideration of development projects in the early period of the forecast. Modest
growth is concentrated solely in the low-cost Middle East, with Iran, Iraq and the
United Arab Emirates (hereafter referred to ‘UAE’) dominating the OPEC expansion.
•
Iran, now free of nuclear sanctions, emerges as the biggest source of growth within OPEC
over the six-year forecast period. The higher capacity will not, however, allow Iran to reclaim
its rank as OPEC’s second biggest crude oil producer after Saudi Arabia. That position is
maintained by Iraq through 2021 despite a marked slowdown in its capacity building.
M EDIUM -T ERM O IL M ARKET R EPORT 2016
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2. SUPPLY
S UPPLY
Trends in global oil supply
Lower prices are cutting into the world’s oil production capacity, with spending curbs slowing growth
from both OPEC and non-OPEC producers. After expanding by a hefty 2.4 mb/d in 2014, global oil
supply grew by a further 2.6 mb/d in 2015. In contrast with 2014 however, when non-OPEC
producers accounted for the entire increase, last year’s growth was more evenly distributed. With
non-OPEC output on track to decline in 2016, OPEC will increase its market share, but only briefly. As
non-OPEC growth resumes from 2018, and with little new OPEC capacity scheduled to come on line,
the pendulum swings the other way. In all, global oil capacity growth slows considerably over 20152021, to a total of 3.3 mb/d, or 550 kb/d per annum. Non-OPEC producers, including biofuels,
account for 2.0 mb/d or 60% of the increase, OPEC natural gas liquids grow by 475 kb/d, or 14% of
total gains, while OPEC crude capacity rises by 800 kb/d over the forecast period. Assuming Iran
returns to post-sanctions capacity in 2016, global supplies are set to grow by 4.1 mb/d by 2021. That
is a sharp decrease from growth of more than 11 mb/d over the previous six-year period.
Figure 2.1 Global liquids capacity growth
3.0
2.5
2.0
1.5
1.0
0.5
0.0
-0.5
-1.0
Figure 2.2 Global capacity growth 2015-21
5.0
4.0
mb/d
mb/d
3.0
2.0
1.0
0.0
2014
2015
OPEC
2016
2017
2018
Non-OPEC
2019
2020
2021
World
*2014 -15 shows actual output growth. 2016 assumes Iran ramp-up.
OPEC capacity increases thereafter.
-1.0
OPEC
Crude
Biofuels
Non-OPEC
NGLs
US LTO
Total
Non-conv
Proc. gains
Drilling oil and gas wells
42
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© OECD/IEA, 2016
Oil companies are slashing upstream exploration and production spending, and oil at USD 30 /bbl is
forcing the industry to better manage its costs and operate more efficiently. Major oil producers and
independents alike are taking advantage of the industry downturn to renegotiate contracts and
commercial terms. Many of the new projects in the pipeline that are moving towards completion are
coming in at significant discounts, with tenders
Figure 2.3 Producer costs (Jan 2006 = 100)
awarded below initial budgets. Upstream costs,
as measured by the Bureau of Labor Statistics
140
for foreign and US companies operating in the
130
US, continued to fall through 2015. By end-year,
120
the cost of drilling new wells had fallen by
110
nearly 26% since its peak in June 2014. Major
new project developments outside of the US are
100
also seeing sharp reductions in cost levels. For
90
Source: US Bureau of Labour
example, Statoil reported early this year it had
80
cut development costs at its Johan Castberg
2006
2008
2010
2012
2014
discovery by nearly half compared with
Oil and gas field machinery and equipment mfg
estimates from 2013.
Support activities for oil and gas operations
S UPPLY
Box 2.1 Upstream spending set to take another hit in 2016
Oil companies will cut deep into their exploration and production budgets in 2016 although investment
of around USD 330 billion is still significant. After a 24% drop in global oil capital expenditures (capex) in
2015, a further decline of 17% is expected in 2016. As companies continue to review investment plans
and implement any spending decisions, the drop could be even steeper. Offshore projects and
exploration activities are curbed the most, and for all sectors the steepest cuts are expected in the
United States.
Figure 2.4 Oil capex by region
600
150
Source: Rystad Energy
100
400
USD billion
USD billion
500
Figure 2.5 Annual change in capex
300
60%
Source: Rystad Energy
40%
50
20%
0
0%
200
-50
-20%
100
-100
-40%
0
2002
America N
Middle East
-150
2006
America S
Russia
2010
Europe
Asia
2014
Australia
Africa
2003
America N
Australia
Asia
2007
2011
America S
Middle East
Africa
-60%
2015
Europe
Russia
World (RHS)
The United States will see the biggest reduction in investment as it did last year but North America as a
whole remains the biggest upstream spender - contributing 29% of global exploration and production
(E&P) budgets this year. In the United States, companies invested heavily to build acreage,
accumulating debt when oil prices were around USD 100/bbl. Oil at USD 30/bbl prompted major shale
companies such as Continental, Hess and Noble to slash 2016 capital expenditures in early January by
between 40% and 66%. Bucking the trend, Pioneer announced in January that it would invest between
USD 2.4 billion and USD 2.6 billion this year, a slight increase from 2015.
Big investment cuts have also affected Canadian oil sands projects under development, rather than
those already sanctioned. As such, capex is expected to see further reductions in 2016 while operational
expenditures (opex) increase modestly, in line with rising production.
Spending cuts have not been limited to marginal barrels. Lower prices have triggered cuts in both capex
and opex, even in areas such as the Middle East that remain profitable at prices well below USD 30/ bbl.
Regional capex was cut 13% in 2015, led by Iraq, which is under severe budgetary strain. By contrast,
Saudi Arabia is sticking with its long-term investment plans, despite cost cutting. One case that stands
out is Russia, where the depreciation of the rouble has allowed companies to maintain spending.
M EDIUM -T ERM O IL M ARKET R EPORT 2016
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In Europe, both the United Kingdom (hereafter referred to as ‘UK’) and Norway saw sharp spending
cuts last year, of 31% and 20%, respectively. Investments will be lowered further this year. While overall
spending levels are down sharply in the near-term, some new developments due on stream later in the
forecast period are still attracting capital. Partly offsetting spending, both on new developments and for
existing assets, producers are making strides to cut costs. In UK, the industry was expected to cut
operating expenses by 22% this year. In Norway, significant cost reductions have been made to new
projects. For example, Statoil’s Johan Castberg capex plans were lowered by nearly half since 2013 and
the first phase of Johan Sverdrup is benefitting from a 12% decline in planned spending. In Brazil,
embattled Brazilian Petrobras recently made deeper cuts to its previously announced 2015-2019
business plan, with the company announcing a further 25% drop in capex this January.
S UPPLY
Non-OPEC supply overview
Non-OPEC producers in 2015 surprised with their resilience to collapsing oil prices. The fruits of many
years of costly investment and determined cost-cutting at existing projects brought 1.4 mb/d of new
supplies to the market. While we see in 2016 a third consecutive year when oil supply exceeds oil
demand, the collapse of oil prices has gone some way to stall relentless non-OPEC supply growth.
After hitting an all-time high annual growth rate of nearly 3 mb/d at the end of 2014, non-OPEC
growth had come to a halt by the end of 2015 with the sharpest correction coming from the US. After
having underpinned a 60% increase in total US supplies in only four years, LTO production gains came
to an abrupt halt last year and is expected to drop by nearly 600 kb/d in 2016 and a further 200 kb/d
in 2017.
Expectations that supply and demand will gradually rebalance by 2017, with a corresponding
recovery in oil prices from around USD 30/bbl, should see US LTO production growth resume in 2018.
Combined with continued increases from the Gulf of Mexico – often overlooked in the media focus
on LTO - and natural gas liquids (NGLs), the US regains its spot as the number one source of nonOPEC supply growth in the medium-term. Production will grow by a net 1.3 mb/d to reach 14.2 mb/d
by 2021. The US is followed by Brazil and Canada (adding 0.8 mb/d each), where, despite numerous
challenges, multiple projects commissioned at a time of far higher prices are due to come on stream.
kb/d
Figure 2.6 Selected sources of non-OPEC supply changes, 2015-21
1 400
1 200
1 000
800
600
400
200
0
- 200
- 400
In all, after an expected decline of 0.6 mb/d in 2016, non-OPEC supply growth is forecast to stall in
2017 before recovery sets in from 2018. By 2021 total output is projected to average 59.7 mb/ d,
2 mb/d higher than in 2015 – a gain of roughly 0.3 mb/d per annum.
44
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Despite a significant upward adjustment since our 2015 report, Russia is expected to see the steepest
output declines in the medium-term. Non-OPEC’s largest crude and condensate producer defied
earlier expectations by setting a supply record in 2015, helped by the weaker rouble and lower taxes
that protected companies from falling oil prices. Output is nevertheless expected to shrink by
275 kb/d to 10.8 mb/d in 2021, due to declining production in mature fields and anticipated delays in
the commissioning of the new fields resulting from capex constraints and fiscal pressures. Output will
also fall in a number of other countries where mature field decline and a lack of new investment will
take its toll over the forecast period. China, Mexico, Colombia, Egypt and Oman are leading
examples.
S UPPLY
Table 2.1 Non-OPEC supply (mb/d)
OECD
Americas
Europe
Asia Oceania
Non-OECD
FSU
Europe
China
Other Asia
Americas
Middle East
Africa
Non-OPEC ex PG and biofuels
Processing Gains
Global Biofuels
Total-Non-OPEC
Annual Change
Changes from last MTOMR*
2015
23.8
19.9
3.5
0.5
29.3
14.0
0.1
4.3
2.7
4.6
1.3
2.3
53.1
2.2
2.3
57.7
1.4
1.1
2016
23.3
19.4
3.3
0.5
29.2
13.9
0.1
4.3
2.7
4.6
1.2
2.3
52.4
2.3
2.4
57.1
-0.6
0.1
2017
23.3
19.4
3.3
0.6
29.0
13.8
0.1
4.2
2.7
4.7
1.2
2.3
52.3
2.3
2.5
57.0
-0.0
-0.5
2018
23.8
19.9
3.3
0.7
29.0
13.8
0.1
4.2
2.7
4.8
1.2
2.3
52.8
2.3
2.5
57.6
0.6
-0.6
2019
24.4
20.6
3.2
0.7
29.0
13.8
0.1
4.2
2.6
4.9
1.2
2.2
53.4
2.3
2.6
58.3
0.7
-0.5
2020
25.0
21.1
3.2
0.7
28.9
13.8
0.1
4.1
2.6
5.0
1.1
2.1
53.9
2.4
2.7
58.9
0.6
-0.4
2021
25.8
21.8
3.3
0.7
28.8
13.8
0.1
4.1
2.5
5.1
1.1
2.1
54.6
2.4
2.7
59.7
0.8
2015-21
2.0
1.9
-0.2
0.2
-0.5
-0.2
-0.0
-0.2
-0.2
0.6
-0.1
-0.3
1.5
0.2
0.4
2.0
0.3
*Excluding Indonesia
Box 2.2 Non-OPEC outlook uncertainty: a wide range of possibilities
The outlook for non-OPEC oil production for the next six years is uniquely hard to call in today’s volatile
market. Our base case is that after a decline of 600 kb/d in supplies in 2016, output stagnates in 2017,
before a tightening oil market balance and subsequent price recovery resets growth from 2018.
However, such is the volatility of the sector as many producers fight hard to maintain operations even
when prices are close to breakeven – or lower – it is prudent to consider other possibilities.
In a high non-OPEC production case, producers manage to avoid mass shut-ins even if crude oil prices
fail to rise significantly in the near term from today’s USD 30/bbl. This means that non-OPEC production
proves more resilient than envisaged for a second year running. Already in 2015, a number of key
producers raised output volumes, following robust investments over previous years and to compensate
from the drop in revenues due to the oil price collapse. While such a production surge is not sustainable
over time absent an increase in spending and activity, companies could perhaps manage to sustain
levels a while longer. In this scenario, total non-OPEC production falls by only 200 kb/d in 2016 and
continues to fall in 2017 as any oil price recovery is pushed back due to continued stock builds.
In a low non-OPEC production case, producers finally have to shut in large swathes of production.
Production falls by a sharper 1 mb/d in 2016 and by a further 0.8 mb/d in 2017. In this scenario, global
inventories continue to swell in 2016, but at a lesser pace, while a sharp stock draw is foreseen in 2017.
Any price rebound could thus come earlier and be steeper than in our base case scenario.
M EDIUM -T ERM O IL M ARKET R EPORT 2016
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The chart below shows the impact on the oil supply demand balance (with no changes to projected oil
demand or to OPEC output levels) of these two cases as well as our central base case. It is clear that in
the high non-OPEC production case the period when the oil market returns to balance is extended well
into 2018 thus implying that oil prices will stay considerably lower for longer.
S UPPLY
Box 2.2 Non-OPEC outlook uncertainty: a wide range of possibilities (continued)
This will have a major disincentive impact on investors, and the recovery in US LTO output in particular
could be delayed compared with our base case scenario. Conversely, in the low non-OPEC production
case global inventories start to draw by the end of 2016, leading to an earlier and sharper rebound in
crude oil prices. This should in turn encourage high-cost producers back to the market and provide a
signal to longer term investors that a more sustainable market has returned.
The two additional cases are illustrative and serve to demonstrate the extraordinarily wide range of
market outcomes possible in today’s oil market even during the relatively short six-year outlook.
mb/d
Figure 2.7 Non-OPEC production scenarios and impact on global inventories
104
3.0
102
2.0
100
1.0
98
0.0
Implied stock
change (RHS)
Stock change - high
supply (RHS)
Stock change - low
supply (RHS)
World demand
96
-1.0
Global supply
94
-2.0
High supply case
-3.0
Low supply case
92
2014
2015
2016
2017
2018
2019
2020
2021
United States
Though a significant production decline is forecast for the near-term, the US remains the largest
source of non-OPEC supply growth in the medium-term. Total supplies are projected to expand by
1.3 mb/d over the forecast period, to an average of 14.2 mb/d in 2021.
14
12
10
8
6
4
2
0
LTO
2009
2011
Gulf of Mexico
2013
NGLs
2015
2017
Other liquids
2019
2021
Other crude and cond.
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
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46
Figure 2.8 US oil production
mb/d
The main focus on non-OPEC production has
fallen on US LTO production. A 70% drop in the
US rig count since 2014 has been partly offset
by significant productivity improvements. The
number of uncompleted wells, or the frack-log,
is still substantial, but without an uptick in
drilling activity, US LTO output is forecast to fall
further. Drilling activity will continue to decline
in the near term and supply will follow. We
forecast a decline in US LTO production of
nearly 600 kb/d in 2016, and 200 kb/d in 2017
before an expected rebound in prices resets
growth from 2018. In all, US LTO reaches
5.0 mb/d in 2021, up 770 kb/d on 2015.
S UPPLY
Long lead time projects in the Gulf of Mexico, and further increases in natural gas liquids (NGL)
production will add to growth throughout the forecast period. The Gulf of Mexico lifts output by
about 500 kb/d from the 1.5 mb/d achieved in 2015, while NGL supplies should increase by a total of
670 kb/d, to reach 3.9 mb/d in 2021. Other conventional oil supplies, including in Alaska, Texas and
California, are expected to fall from current levels.
Box 2.3 The rise, fall and rise again of US LTO
After five years of remarkable growth, oil’s rout slammed the brakes on US LTO in 2015. Preliminary
estimates show production on a declining trend since mid-year, and slipping below the year earlier level
for the first time in December. Despite its slowdown, LTO remained a key contributor to non-OPEC
supply growth in 2015, accounting for more than 40% of the 1.4 mb/d total increase.
At an average 4.3 mb/d last year, tight oil production was roughly ten times higher than in 2010. Such an
unprecedented surge required enormous effort, with more than 55 000 new wells drilled over the
period. At the 2014 peak, more than 1 500 drilling rigs were running concurrently in the US, compared
with an average of 103 drilling rigs operating in Saudi Arabia. By early 2016, the number of US drilling
rigs had dropped to just 440.
Figure 2.9 US LTO production
Figure 2.10 Spudded, completed horizontal
wells and drilled, uncompleted inventory
2000
6.0
5.0
4000
1500
4.0
mb/d
5000
3000
1000
3.0
2.0
2000
500
1000
1.0
0
0.0
2010
Bakken
2012
2014
Eagle Ford
2016
W. Texas
2018
Niobrara
2020
Other LTO
Jan-11
Jan-12
DUC (RHS)
Jan-13
Jan-14
Spudded
0
Jan-15
Source: Rystad Energy
Completed
Oil production has not fallen nearly as quickly as the rig-count alone would suggest. Data from Rystad
Energy shows the number of well completions exceeding the number of new wells drilled in early 2015,
resulting in the number of uncompleted wells, or the frack-log, being reduced from its peak of around
4 600 wells at the end of 2014 to around 4 000 wells one year later.
With increased experience, well performance improved. Preliminary data suggest that initial production
rates in the Bakken and Eagle Ford plays increased by 12% over 2015 compared to the average of the
previous five years. In West Texas, the advance in initial production was an even more impressive 23%.
This resulted from improved practices, but also from a regrouping by the industry into areas that had
yielded the best performing wells in the past. In many cases, Estimated Ultimate Recovery (EUR) has
equally improved, but at a significant cost, as gains stem from higher complexity well completions.
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Current oil prices do not create an incentive for E&P companies to increase activity levels in the near
future, which is reflected in budget announcements to date. As such, we are assuming 2016 well
completion activity similar to 2015 exit rates, concentrated in the best performing real estate.
S UPPLY
Box 2.3 The rise, fall and rise again of US LTO (continued)
A continuation of reduced well costs, made possible by a combination of best practices, more efficient
rigs, and a severe squeeze on prices charged by service and material suppliers, will help to support
drilling activity. Per well cost savings in the 25-30% range are widely reported in quarterly corporate
filings.
However, cost deflation and high quality drilling sites will probably not be enough to help some
participants. Access to sustainable financing will remain important as ever. The willingness of banks to
finance oil and gas producers is being put to the test, as seen in a comparison of funding levels between
the first and second halves of 2015. In the first half, US E&P companies raised USD 38.5 billion between
1
debt and equity offerings, while in the second half that number fell to USD 7.8 billion.
Figure 2.11 Average US shale play well
performance
800
Source: Rystad Energy
300
600
200
400
b/d
b/d
400
Figure 2.12 Average daily production by shale
play - 2015 production start year
100
200
0
0
0
2011
2
4
2012
6
8
10 12 14 16 18
cummulative months on production
2013
2014
2015
Source: Rystad Energy
1
3
Bakken
Permian Delaw
5
7
11 13 15 17 19
cummulative months on production
Eagle Ford
Niobrara
Permian Midland
9
For 2016 as a whole, we expect a 50% reduction in tight oil well completions, compared to 2015. As
such, production is forecast to decline by nearly 600 kb/d, as new wells are not nearly enough to offset
natural decline of more than 1 mb/d expected from existing tight oil wells this year. Commodity hedges
held by some operators, combined with a concentration on the best prospects and a similar focus on
quality by financiers should prevent supply from falling more rapidly. A tighter global oil supply-demand
balance late in 2016 and into 2017 suggests prices should rise, allowing US LTO to rebound. But as the
service industry and associated supply chain has scaled back considerably, it may not be able to facilitate
an immediate response in production to higher prices. We’ve assumed a six month minimum delay
between global oil prices reaching a growth threshold of around USD 60/bbl, and a corresponding
increase in drilling activity due to the time it would take to re-staff and prepare equipment for the
return to service. The likely result is that in 2017 LTO production will fall by a further 200 kb/d before
drilling activity picks up. Growth, however, is expected to be slower than the industry experienced
during the 2010-2014 cycle, due to a combination of more subdued oil prices, a downsized supply chain
and a focus on the most productive acreage.
1
Financial Times, 7 January
48
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E&P companies will remain burdened with debt. Even at peak activity levels and with oil prices in the
USD 100 /bbl range, debt increased as operators outspent income to build acreage positions and
evaluate their holdings.
S UPPLY
Box 2.3 The rise, fall and rise again of US LTO (continued)
Some companies should be able to improve cash flow by drilling an inventory of top-tier well locations,
so long as financing remains available. By 2018, we foresee year-on-year supply growth of roughly
250 kb/d. Higher well costs are likely by this time, as the service industry will have re-structured to
match the current business climate, though higher oil prices should be able to compensate.
Escalating oil prices through the remainder of the outlook will result in greater drilling activity each year,
but even in 2021, when growth recovers to around 550 kb/d, the US tight oil well count should be
significantly lower than in 2014. The industry will be in position to operate more profitably in this
second phase than in the first. Core acreage is likely to be better understood, and the inventory of prime
well locations in the key tight oil plays look sufficient to last through the medium-term outlook. A tighter
focus on the best prospects should allow the sector to deliver greater profits by drilling fewer, but better
performing wells. While a saturation of some key acreage, such as Karnes county in Eagle Ford, is
possible towards the end of the forecast period, technology improvements and cost deflation suggest
that 2015 average per-well production rates can be maintained through 2021.
Good economics in top tier Bakken and Eagle Ford acreage will support continued drilling there for some
time. We foresee a decrease in Bakken and Eagle Ford production in the near term, followed by a return
to 2015 levels by 2020. West Texas is likely to be a larger driver of supply growth over the medium term.
Horizontal activity there was just hitting its stride in 2014, and further gains in production per well and
well drilling speed/cost are likely. In addition, the geology of the region is well known from the long
history of vertical drilling activity. Up to five primary layers of producing reservoirs exist in the region,
compared to two in Bakken and one in the Eagle Ford. The potential number of drilling sites and
associated production in West Texas is therefore quite large. As a result, we foresee a smaller
production decrease here relative to other unconventional oil plays in 2016-17, followed by growth
towards the end of the decade to levels nearly twice as large as seen in 2015.
Together, the Bakken, Eagle Ford shale and West Texas made up the lion’s share (estimated at 80%,
assuming only half of West Texas crude supply is LTO) of US LTO production in 2015. Certainly plays
outside of these regions will continue to contribute, but based on our understanding of the economics
of those plays today, it is unlikely they will displace any of the leaders during our outlook.
A slew of projects will underpin growth in the US Gulf of Mexico
As US LTO production growth declines, supply from the Federal Waters Offshore in the Gulf of
Mexico (GoM) is on an upward trajectory. GoM posted an annual gain of 140 kb/d to reach
1.54 mb/d last year, the highest level since 2010. Production will continue to increase through 2019,
and then taper off. By 2021 the GoM is expected to add a net 0.5 mb/d.
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The strong GoM production growth follows the commissioning and ramping up of several new
projects. Notably, Anadarko’s Lucius spar reached its full capacity of 80 kb/d in July, only six months
after reporting first oil. Chevron’s Jack/St Malo project, which started production in December 2014,
was producing nearly 70 kb/d in June. Output from the first stage of development is expected to
climb to 94 kb/d in 2016, before a second stage takes production to 190 kb/d by 2019. Increases also
came from Hess’s Tubular Bells field, which delivered 30-35 kb/d in 2015. Chevron’s 75 kb/d Big Foot
project, however, is now expected to start-up in 2018 after installation troubles derailed a 2015
planned start-up.
S UPPLY
In other highlights, Llog Exploration announced that output at its Delta House floating production
system (FPS), brought on-line in 2Q15, had reached its nameplate capacity of 80 kb/d in early 2016.
Llog had brought the facility’s ninth well on production, with two additional wells on track to be
added by year-end 2016. The FPS is designed for a peaking capacity of 100 kb/d of oil and 240 mcf/d
of gas. The company’s Son of Bluto 2 and its Marmalard development are tied back to the LLOG
operated Delta House FPS. Marmalard started production in April 2015 and produced 7 kb/d in July,
while son of Bluto 2 reported first output in July.
Anadarko reported first oil from its Heidelberg unit, identical to its Lucius spar facility that
commenced production in 2015 with a design capacity of 80 kb/d, this January, “significantly ahead
of schedule and favourable to budget” according to a company statement. Royal Dutch Shell is
developing the Stones field using a floating production, storage and offloading (FPSO) vessel, which is
currently under construction in Singapore. Output from the initial phase of development, scheduled
to start in 2016, is expected to average 50 kb/d. Royal Dutch Shell also took a final investment
decision on its Appomattox project in July 2015, with first production expected by the end of the
decade. The giant four-column semi-submersible platform will be among the largest facilities in the
region, with a capacity of 175 kboe/d.
Other notable projects include Hess’s Stampede field, due to start up in 2018. The project includes
output from the Pony and Knotty Head fields and it will have a capacity of 80 kb/d. BP is expected to
award contracts to build a 60 kb/d production facility to develop its fast-tracked Hopkins discovery in
the Green Canyon area in the first quarter of 2016, targeting first output in 2018. BP is also aiming to
lift output at its Thunder Horse platform, thought to be one of the most prolific fields in the GoM,
over 2016 and 2017. The projects should add an additional 65 kb/d.
Towards the end of the forecast period, a lack of new project start-ups sees GoM output flatten out,
but nevertheless inch higher, hinging on whether new projects are sanctioned in time. Major oil
companies already delayed taking final investment decision (FID) on several projects since oil prices
dropped, including Vito (Shell), Moccasin and Buckskin (Chevron), Hadrian North (ExxonMobil) and
Mad Dog phase II (BP). A 27% drop in exploration capex for the US offshore in 2015, excluding the
Artic, followed by a projected 46% decline in 2016, according to Rystad Energy, could see output fall
much sharper beyond the medium-term horizon.
Canada
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Despite its high investment and operating costs, Canadian oil sands remain a key contributor to nonOPEC supply growth in the medium-term, adding nearly 800 kb/d by 2021. The long lead-time from
investment decision to first commercial production means that projects where significant capital has
been invested will continue to operate and proceed to completion. While some companies are
currently running with negative operating cash costs, no major shut-ins or plant closures have been
announced to date. By 2021, Canadian oil output is forecast to average 5.2 mb/d, of which bitumen
output from Alberta (including material upgraded to synthetic crude) accounts for nearly 3.4 mb/d,
or two-thirds of total supplies.
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Figure 2.14 Canada oil supply growth
6
300
5
200
4
kb/d
mb/d
Figure 2.13 Canada oil production
100
3
0
2
-100
1
0
2014
Bitumen
2015
2016
Synthetics
2017
2018
Alberta L&M
2019
2020
NGLs
2021
Other
-200
Bitumen
2014 2015 2016 2017 2018 2019 2020 2021
Synthetics
Alberta L&M
NGLs
Other
Total
A number of new projects recently commissioned or nearing completion will drive this growth.
Amongst the key contributors is Imperial Oil’s Kearl expansion project which was completed in June
2015 doubling the plant’s capacity to 220 kb/d. The company added another 40 kb/d of output to its
Cold Lake in situ operations during 2015, by developing the nearby Nabiye area. ConocoPhillips and
Total brought on a second phase at their joint Surmont project last year, adding up to 118 kb/d of
capacity, as it ramps up through 2017. By the end of 2017, Suncor is expected to complete the first
180 kb/d of capacity at Fort Hills. Suncor said that construction costs – estimated at USD 13.5 billion had fallen by about 5% as competition for labour and materials had eased. Canada Natural Resources
Limited is adding 125 kb/d of output to its Horizon mining and upgrading capacity as Phase 2B and 3
are commissioned over 2016 and 2017. Lastly, Cenovus is building out its Foster Creek and Christina
Lake projects, adding more than 100 kb/d of capacity once the phases under construction are
completed. Subsequent phases of development were recently put on hold however, with FID
expected only by 2018-2019.
Royal Dutch Shell’s decision to take a USD 1.5 billion write-down by shelving its Carmon Creek project
in October 2015 has little impact on our earlier projections. The project, which would have produced
80 kb/d, was in its early stage of planning and was already excluded from our forecast.
A consortium consisting of ExxonMobil, Chevron, Suncor, Statoil and Nalcor is also developing the
Hebron heavy oil field offshore Newfoundland and Labrador. The project, which will have a
production capacity of as much as 150 kb/d, is expected to start up in early-2018.
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While producers are making efforts to improve efficiencies and costs have come down over the last
year, new oil sands projects remain amongst the world’s most expensive sources of oil supplies.
Heightened environmental concerns, a lack of pipeline access to new markets and the unknown
impact of the victory by the New Democratic Party in Alberta’s elections last year are causing
companies to slow development. As such, we are likely to see continued capacity increases the near
term, with growth slowing considerably, if not coming to a complete stand still, after the projects
under construction are completed.
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Box 2.4 Fading Russian resilience
Russia, the world’s largest crude and condensate producer, defied expectations in 2015 by setting
another post-Soviet supply record. Producers managed to overcome the twin challenges of lower oil
prices and international sanctions and lifted output by 150 kb/d. A 30% depreciation of the rouble
versus the USD and lower taxes partially offset falling oil prices in 2015. This enabled Russian companies,
with the majority of their costs in roubles, to focus on projects able to lift output in the near-term.
Despite 2015’s unexpected production increase, we still expect Russia to see steep production declines
over the medium term. Output will decline by 275 kb/d to 10.8 mb/d in 2021, due to accelerating
decline rates in mature fields and delays in the commissioning of new projects resulting from capex
constraints, stronger fiscal pressure and the expected ongoing impact of economic sanctions.
Russia’s production growth in 2015 resulted mainly from investments made in new fields in recent
years, which have now reached plateau levels. Amongst these, Rosneft’s Vankor, Uvat and
Verkhnechonsk fields ramped up to around 450 kb/d, 195 kb/d and 170 kb/d respectively, while Surgut’s
Talakan field produced around 155 kb/d last year. The majority of the growth came from new
condensate projects, while higher drilling led to a stabilisation of decline rates at a number of mature
fields. This was possible as companies maintained or even increased rouble capex spending arising from
the accumulation of dollars earned from exports priced at nearly USD 100/bbl in the period to mid2014.
Figure 2.15 Russian oil production
Figure 2.16 Brent price index in USD
vs roubles
1.4
11.00
1.2
10.75
1.0
10.50
0.8
10.25
0.6
10.00
0.4
9.75
0.2
9.50
0.0
Jan 14
mb/d
11.25
2015
2016 2017
Current data
2018
2019 2020
MTOMR 2015
2021
Jul 14
Jan 15
Brent - USD
Jul 15
Jan 16
Brent - RUB
While Brent priced in USD lost nearly 70% if its value from January 2014 to January 2016, Brent priced in
roubles declined by only 30%. Moreover, Russia’s oil taxes eased due to the fall in oil prices, particularly
for new projects. To further help the industry, operating costs have fallen. Most companies, with the
exception of Lukoil, re-prioritised their investments towards mature fields, and some (like Rosneft,
which is highly indebted) are selling stakes in producing assets or divesting completely.
Russia’s liquids output is likely to remain near record high levels of more than 11 mb/d in 2016,
especially as Novatek’s Yarudeyskoe field ramped up to plateau production of 70 kb/d early in the year.
In the medium term, however, sustaining this level will prove challenging, though based on current
resources and known plans, Russia could well produce over 11.2 mb/d by 2021 if the pricing and
taxation environment remain favorable.
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So far, the impact of western sanctions on current production has been minimal. The sanctions primarily
target longer-term production from tight oil and especially Arctic and deep offshore resources. Even
without sanctions these higher cost projects would probably not have withstood the pressure of the
lower price outlook.
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Box 2.4 Fading Russian resilience (continued)
Condensate production will continue to grow, driven mainly by Novatek but also by Gazprom developing
the Achimov layers, expected to add 170 kb/d by 2021. New greenfield projects are likely to add
between 500 kb/d and 600 kb/d by 2021. In particular, Taas-Yuriakh second stage (Rosneft), Novoport
(Gazpromneft), Trebs & Titov (Bashneft, Lukoil), Srednebotuobinskoe (Rosneft), Suzun (Rosneft), East
Messoyakha (Rosneft and Gazpromneft) or Filanovskoe (Lukoil) are all expected to produce in a range of
60-100 kb/d by 2021. Amongst the companies, Gazpromneft, Bashneft and Novatek are expected to
post the highest production growth over the period.
However, the ability of Russian companies to maintain current capex levels, and thus ensure necessary
investments in mature fields and new projects, is challenged by four factors:
• the lower oil price environment and a price recovery that is expected to be longer and softer than
Russian stakeholders have so far anticipated;
• higher fiscal pressures, which seem inevitable in light of the Russian government’s budgetary
problems and the wider economic recession;
• the current priority, if maintained, of high dividend payments per share especially as about 60% of
production is now undertaken by state-controlled companies;
• continued high indebtedness of Rosneft, which is Russia’s leading producer with over one-third of
total output, which can be partly offset by asset sales, but the huge pre-payments (over
USD 30 billion) will necessarily impact free cash flow.
With recessionary pressures growing, the government has again changed the fiscal rules governing the
oil and gas sector, reinforcing tax instability and uncertainty for investors. The Russian budget for 2016
was calculated assuming a USD 50/bbl average oil price with a 3% deficit. This outlook is now highly
unlikely to be realised and there is a growing likelihood that the decision to maintain the oil export duty
at 42% in 2016, instead of the initially planned cut to 36%, could be extended into 2017 when it had
been planned to cut it to 30%. Unless the economic backdrop improves, the possibility of further
taxation changes for 2017 cannot be ruled out. These could negatively affect companies’ investment
plans – currently in a range of RUB 200 billion - and have a downward impact on output growth and
possibly on output itself. Already, the launch of several greenfield projects has been delayed.
Decline rates in mature regions, representing still over three quarters of total liquid output are expected
to accelerate to over 3%/year from ~ 1.5%/year in 2015 as the current stabilisation rate is not expected
to be sustained. Lukoil has already cut brownfield drilling by over 30% in 2015 and saw sharp decline
rates of over 25% in Western Siberia.
Inflation is likely to offset some of the downward pressure on lifting costs and companies’ export
netbacks are affected by higher transportation costs and additional taxation. A fundamental issue will
be whether hard-to-recover reserves, in particular in mature fields, will be developed as the potential is
very large. The average recovery factor for mature fields is relatively low compared to the US (in the
order of 25% for Russia compared with about 35-45% in the US) and it can be improved using enhanced
oil recovery techniques. Another negative factor is that many rigs will reach the end of their natural lives
during the forecast period – it is thought that 60% of Russia’s rigs are more than 20 years old.
Lower oil prices have curbed the outlook for Kazakhstan’s oil production in the medium term. Our
earlier forecast was for production to attain nearly 2 mb/d in 2020, but now it is expected to reach
1.8 mb/d by 2020 and close to 1.9 mb/d in 2021. The mighty Kashagan field, thought to hold up to
30 billion barrels of oil is expected to resume operations in early 2017. Shortly after production
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Caspian
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commenced in September 2013 faulty pipelines forced the North Caspian Operating Company, a
consortium consisting of Eni, Exxon Mobil, Royal Dutch Shell, Total, CNPC, Inpex and Kazakh state-run
company KazMunaiGas (KMG), to halt production. Resumption of production will be partly offset by
declining supplies from mature fields.
Investments in Kashagan have been colossal: the USD 44.5 billion spent by August 2014, excluding
USD 2 billion associated with the 2013 shutdown, makes it one of the most expensive oil projects
ever undertaken. Consortium officials anticipate the project attaining its 370 kb/d capacity by the
end of 2017, but in view of the delays so far, we project a slower ramp-up, with peak capacity only
reached by 2019. Meanwhile, the FID for Tengizchevroil’s project in western Kazakhstan has been
delayed, which is likely to push the start-up beyond the time horizon of this Report. The expansion,
also named the Future Growth Project, could increase daily production volumes by 250-300 kb/d of
oil equivalent, stemming declines at existing operations. Tengizchevroil produced 530 kb/d in 2015.
Kazakhstan, facing financial stress and a near-term reduction in crude oil production, plans to
privatise parts of KMG, including the mainly state-owned refineries. In light of difficult economic
conditions and the sharp depreciation of the Kazakh tenge currency, KMG plans to cut investment in
production drilling by 21% to USD 282 million in 2016, resulting in a drop by more than a third in the
number of producing wells. KMG expects its crude oil output to fall by 3% from current levels by
2020 as a combination of natural declines and as investment cuts take their toll.
Figure 2.18 Azerbaijan oil production
2.0
1000
1.8
900
kb/d
mb/d
Figure 2.17 Kazakhstan oil production
1.6
800
700
1.4
600
1.2
500
1.0
400
2015
2016 2017
Current data
2018
2019 2020
MTOMR 2015
2021
2015
2016 2017
Current data
2018
2019 2020
MTOMR 2015
2021
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The forecast for neighbouring Azerbaijan, meanwhile, is largely unchanged since last year’s MTOMR,
with total volumes slipping by 140 kb/d over the six-year period to 700 kb/d in 2021. Azeri oil
production in 2015 was provisionally estimated at 835 kb/d, 20 kb/d lower than in 2014 and well
below the peak of 1.05 mb/d reached in 2009. The majority of the decline stems from the AzeriChirag-Deepwater Gunashli (ACG) complex, operated by BP, already down 200 kb/d from its 2009
peak of around 830 kb/d. There will be some offset from the Shah Deniz gas project which is
expected to be fully on stream towards the end of the decade. Shah Deniz, also operated by BP,
produced 7.2 billion standard cubic meters (bcm) of gas and 50 kb/d of condensates during the first
nine months of 2015. The second Shah Deniz phase will add a further 16 bcm of gas per year.
Shah Deniz 2 is now over 50% complete in terms of engineering, procurement and construction, and
remains on target for first gas in 2018.
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Latin America
The outlook for Brazilian oil supplies has been marginally downgraded since the last MTOMR, as
Petrobras grapples not only with lower oil prices, but also a corruption scandal, delays in tendering
and procuring production units, huge debts and wider economic and political woes. Even so Brazilian
oil supply will rise from 2.5 mb/d in 2015 to 3.4 mb/d in 2021, as it seems – at least for now, that new
production facilities will more than offset declines at some producing fields.
In June 2015, Petrobras cut its 2020 production target from 4.2 mb/d to 2.8 mb/d and slashed its
2015-2019 investment plan by 37% to USD 130 billion. In January 2016, Petrobras presented a
revised five-year investment plan cutting spending again this time to USD 98 billion. The turmoil at
Petrobras is causing delays to the tendering and completion of contracted works. Petrobras is still
waiting for the deployment of the first of 12 FPSOs intended for the pre-salt developments, each
with a capacity to produce 150 kb/d.
More than five years after Petrobras officially awarded a USD 3.46 billion contract to Engevix for the
fabrication of eight replica FPSO hulls, no unit has entered operations, showing that Brazilian yards
are still struggling to deliver on their orders. The most advanced vessel, the P-66, is expected to start
production in the Lula South field in 2017. Besides the eight replica floaters, Petrobras ordered the
construction of four twin FPSOs for the Buzios pre-salt with Brazilian contractors, also facing delays.
Uncertainty around the completion and deployment of these facilities is clearly a major factor in
judging how Brazil can increase its production during our forecast period.
Figure 2.20 Total non-OPEC Latin America oil
production
3.5
5.5
3.0
5.0
2.5
4.5
mb/d
mb/d
Figure 2.19 Brazil oil production
2.0
4.0
1.5
3.5
1.0
3.0
0.5
2.5
2015
2016 2017
Current data
2018
2019 2020
MTOMR 2015
2021
2015
2016 2017
Current data
2018
2019 2020
MTOMR 2015
2021
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Despite all the logistical and institutional problems, oil production is on the rise. Four FPSOs ramped
up production in 2015 and four new units are due on stream in 2016. The Cidade de Marica FPSO,
leased by Petrobras to work in the Lula Alto pre-salt field in the Santos basin, was completed at the
very end of 2015 and is due to start production in the first quarter of 2016. It can produce 150 kb/d
of oil and 6 mcm/d of natural gas. Its replica, the Cidade de Saquarema FPSO, which will go to work
at the Lula Central field, is being completed and will start operation by the end of 2016. A consortium
consisting of Petrobras, Royal Dutch Shell, Total, CNOOC and CNPC is on track to start up extended
well tests using a 50 kb/d FPSO at the Libra field – which is thought to hold 8 billion bbls of oil, at the
end of 2016 or early 2017.
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Total Colombian oil production, averaging close to 1 mb/d last year, is forecast to decline by nearly
200 kb/d by 2021. Ecopetrol, the national oil company, slashed its capex budget by 39% for 2016, to
USD 4.8 billion, compared with USD 7.86 billion budgeted for 2015 and less than half the
USD 10.6 billion spent in 2014. Ecopetrol set its production target for 2016 at 755 kboe/d, slightly
below 2015 output levels.
After a slight increase in output foreseen for 2016 and 2017, Argentinian production is also projected
to decline. While state-owned YPF, Chevron and ExxonMobil have made progress in their
Vaca Muerta and Loma Campana shale developments, total LTO output stood at 25 kb/d in October
2015, up 5 kb/d from a year earlier. We forecast LTO output to continue rising over the period, to
reach 65 kb/d in 2021. Total Argentinian oil production is expected to decline marginally over the
forecast period, from 630 kb/d in 2015 to 590 kb/d in 2021.
Box 2.5 Guyana to join the oil club – Falklands Islands (Malvinas) next?
ExxonMobil, and its partners Hess (30%) and Nexen (25%), are moving ahead with the fast-track
development of its groundbreaking, deep-water Liza project off Guyana discovered last year. In early
January, the US major contracted a drillship for the project to further evaluate the field’s potential.
Exxon is reportedly looking to lease an FPSO with capacity of around 60 kb/d of oil for the first phase of
the project, which is targeted as early as 2018. While the full-field development plan is still being drawn
up, industry officials say it could be based on a larger FPSO with the capacity to handle 150-200 kb/d.
The US supermajor has yet to release a resource estimate for the find, but has called it significant. Also
in January this year, UK explorer Tullow Oil and Canadian independent Eco Atlantic Oil & Gas signed an
agreement with the government of Guyana for exploration rights to a deep-water offshore block
adjacent to Exxon’s Liza discovery. While significant uncertainty still surrounds the start-up date of the
Liza field and potential production levels from Guyana, we have included Guyana in our forecast for the
first time from 2021, with an expected ramp-up thereafter.
The development of the Sea Lion discovery, off the Falklands Islands, meanwhile, is not yet included in
this forecast. Premier Oil is reportedly still looking for a partner to help fund the USD 2 billon
development, which targets a 2019 start-up at 50-60 kb/d. But if Premier Oil takes a decision in 2016, as
planned, the Falklands could still make the club before the end of the decade.
Mexico
The historic opening up last year of Mexico’s upstream sector is expected to stall the decline in
Mexico’s oil production from the peak of 3.83 kb/d reached in 2004, but not in the short term. While
output will see continued declines in the near term, new fields coming on stream over the latter
years of the forecast period will offset field decline. Last year was particularly bad, as an explosion at
the offshore Abkatun Pol Chuc complex compounded the effects of decline at mature fields, causing
oil output to drop by 200 kb/d year on year (y-o-y), to 2.6 mb/d. The drop in oil prices leads us to
take a more pessimistic view on Mexican oil production than in last year’s MTOMR, with total oil
production on course to fall over the coming three years before stabilising at around 2.4 mb/d from
2018.
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Pemex is undergoing a major overhaul in line with the government’s energy sector reforms but in the
meantime, the company started producing oil and gas from the delayed Ayatsil-Tekel project in
March 2015 after installing three of the six wellhead platforms planned for the area. The
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In June of last year, Pemex reported its largest
oil find in five years in the Gulf of Mexico. The
discovery included four new fields in shallow
water in the Gulf of Mexico with the potential
for daily production of at least 200 kb/d of oil
and 170 million cubic feet of gas. According to
Pemex, the wells, located close to the mature
Cantarell field, could begin production within
sixteen months.
mb/d
USD 6 billion project, which includes a new-build VLCC-size FPSO facility and a network of five
platforms, will be an important source of growth as output climbs towards a plateau towards the end
of the decade of 136 kb/d. The future involvement of foreign companies gave Pemex the opportunity
to allocate the difficult project – involving
producing and upgrading/blending 11 degrees
Figure 2.21 Mexico oil production
API sour crude – to prospective partners,
3.0
causing delays in the tendering of the FPSO and
another unit and also to any significant ramping
2.8
up of production.
2.6
2.4
2.2
2.0
1.8
1.6
2015
2016 2017
Current data
2018
2019 2020
MTOMR 2015
2021
Mexico’s upstream regulator, the National Hydrocarbons Commission (NHC), is moving forward with
reforms that will end Pemex’s upstream monopoly. A year after the launch of Round One of the
historic upstream reform, three tenders have been completed with increasing success as the
government adjusted the terms to boost their appeal. On 15 December, NHC awarded all the
25 onshore mature blocks on offer in the north, central and southern regions. The licensing round,
which was the third since the opening, was designed to attract smaller companies and local
independents, and several local firms were amongst the winners.
The first and second tenders, both for shallow water areas, awarded only 14% and 60% of the blocks
on offer, respectively. In the first phase, two out of 14 exploration blocks in the Salina del Istmo and
Mascupana areas of the Southeastern Basin offered for bidding, were awarded. Having eased the
terms and conditions from the first phase, in the second phase the NHC awarded three out of five
blocks on offer. All the blocks were for development and production in shallow waters of the Gulf of
Mexico, with all but one having proven reserves. The winners offered government revenue takes
ranging from 70-83.5%, compared with the government’s minimum requirement of around 35%.
The biggest test will come in 2016, however, when the government will try to secure longer-term
investments. A tender for 10 deep water blocks, each expected to draw USD 4.4 billion of investment
and holding more than 10 billion barrels of oil equivalents of prospective resources, will be launched
in the third quarter of this year and expected to interest major oil companies, if the terms are
deemed competitive and the oil price outlook is looking more encouraging.
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The outlook for Mexico is clearly dependent on continued political support for the controversial
changes to the long-standing ban on the involvement by foreign companies in the upstream oil
sector. The early 2016 collapse in oil prices to USD 30/bbl will not help the investment outlook but
even if prices had remained at significant higher levels, progress would likely have been slow.
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North Sea
mb/d
The outlook for the North Sea, including supplies from Norway, the UK, Denmark, the Netherlands
and Germany, meanwhile has counter-intuitively improved since the last update. Following years of
high investments into new field developments and to improve field reliability, the North Sea posted a
second consecutive year of production growth in 2015. Gains totalling 150 kb/d from 2014 followed
the start-up of a number of new fields and exceptionally low planned and unplanned outages, both in
Norway and in the UK. While several new fields
Figure 2.22 North Sea oil production
are on track to be commissioned over the
forecast period, continued decline at mature
3.5
1.4
fields and a return to more normal shutdown
3.0
1.2
levels are expected to see output fall back from
2.5
1.0
recent highs – until Statoil starts up its major
2.0
0.8
Johan Sverdrup projects towards the end of the
1.5
0.6
decade.
1.0
0.4
0.5
0.2
Norwegian oil production surprised to the
0.0
0.0
upside in 2015, posting a second consecutive
-0.5
-0.2
year of growth. Following gains of 50 kb/d in
-1.0
-0.4
2014, total oil output expanded by a further
2011
2013
2015
2017
2019
2021
55 kb/d last year, to 1.94 mb/d – a five year
UK
Norway
Other
Ann. Change (rhs)
high. The start-up of new projects, such as
Gudrun, Knarr and the redevelopment of Eldfisk, added to supplies, while field reliability seems to
have improved with fewer outages and downtime than in previous years.
New projects are on track for start-up in 2016. In November, the Norwegian Petroleum Directorate
granted consent to start production at the Lundin-operated Edvard Grieg field, expected to ramp up
to 80 kb/d by 2017. Oil and gas output from the nearby Ivar Aasen field, adding 45 kb/d, which will
also be processed on the Edvard Grieg facility, is scheduled to start up in late 2016.
First oil from Eni’s troubled Goliat project, however, is running nearly two years behind schedule and
will start up by the end of 1Q16. Goliat is the world’s largest cylindrical platform and Norway’s first
development in the Barents Sea. This achievement has, however, seen costs climb to NOK 48.6 billion
(USD 5.9 billion), 52% more than the budget set out in the 2009 development plan. Construction
difficulties and cost overruns are also affecting the Martin Linge development. The project is running
26% over budget, to USD 4.7 billion, and engineering delays led Total and partners Petoro and Statoil
to postpone the start-up of the field by one year to early 2018. The Statoil-operated Gina Krog field is
still on track to come on stream in 2017.
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Despite these developments coming on stream, field decline is expected to take output lower from
2016 until the Johan Sverdrup mega-project comes on line towards the end of 2019. The field will be
developed in several phases by Statoil, Lundin Norway, Petoro, Det Norske Oljeselskap and Maersk
Oil. Phase 1 has a production capacity in the range of 315-380 kb/d, with first oil planned for late
2019. A second phase could bring production up to 550-650 kb/d, accounting for some 40% of total
oil production from the Norwegian continental shelf.
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In all, Norway’s oil production is forecast to slip from 1.9 mb/d in 2015 to a low of 1.7 mb/d in 2019,
before the start-up of Johan Sverdrup lifts output to 1.8 mb/d in 2020 and back to 1.9 mb/d in 2021.
Figure 2.23 Norway oil production
Figure 2.24 UK oil production
2.0
1000
950
900
1.8
kb/d
mb/d
1.9
1.7
850
800
750
1.6
700
1.5
650
1.4
600
2015
2016 2017
Current data
2018
2019 2020
MTOMR 2015
2021
2015
2016 2017
Current data
2018
2019 2020
MTOMR 2015
2021
Despite the drop in oil prices, expectations for UK oil production have been raised since last year’s
MTOMR. Total output is forecast to reach 980 kb/d in 2018 before falling back to 900 kb/d by 2021,
50 kb/d lower than an upwardly revised 2015 starting point. Record high capital investment of GBP
14.8 billion paid dividends in 2015, with a slew of new project start-ups, improved field reliability and
a drop in field decline rates at existing fields.
According to provisional data, UK oil production in 2015 posted its first annual gain since 1999, rising
by 90 kb/d to 950 kb/d. Notable contributions to growth came from new projects, such as Nexen’s
Golden Eagle and BP’s Kinnoul projects, which started up in November and December 2014,
respectively. The two fields had added 93 kb/d by September 2015. Further gains are coming from
EnQuest’s Alma and Galia fields, which started producing at the end of 2015. Premier Oil started up
production at its Solan field, located West of Shetland, in January 2016 and it will reach a plateau
production level of 24 kb/d. The company’s 50 kb/d Catcher field is expected to come online in 2017.
Itacha, meanwhile, is developing the Harrier and Stella fields as part of its Greater Stella Area project.
Production will be at an average annual rate of 30 kb/d, with first oil expected in the second quarter
of 2016. EnQuest has brought forward the Kraken and Kraken North developments, both of which
are scheduled to begin production in 2017, producing a peak output of 55 kb/d.
The start-up of Statoil’s Mariner Field project, meanwhile, has slipped from 2017 to 2018. The project
will eventually comprise 80 production wells with a plateau output of 55 kb/d. Dana Petroleum is
developing the Western Isles fields (Barra and Harris) with peak production estimated at 40 kb/d.
The project is running two years late and at least USD 400 million over budget.
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BP is spending GBP 3 billion to redevelop its Schiehallion and Loyal fields west of Shetland. Field
production at Schiellallion, which was first commissioned in 1998, was suspended in early 2013, and
the FPSO is being replaced by a new 130 kb/d capacity vessel. The redevelopment project, named
Quad 204, will extend the production at the field beyond 2035. Start-up is expected in 2017, with
peak production above 100 kb/d reached in 2018.
S UPPLY
BP is also undertaking the re-development of its Clair field, equally located west of Shetland, with the
next phase focused on Clair Ridge. The Clair Ridge development will produce an estimated 640 mb of
oil over a 40 year period, with peak production expected to be more than 100 kb/d. BP is planning to
spend GBP 4.5 billion to install two new bridge-linked platforms and 36 new wells will be drilled
(26 production wells and 10 water injection wells) to maintain reservoir pressure. The project is set
to come on stream in 2017 or 2018.
Lower oil prices are forcing the UK industry to take action to improve efficiency throughout its
operations. According to industry body Oil & Gas UK (OGUK), these efforts will lead to a 22% drop in
operating expenditure on the UK continental shelf this year. In addition, the UK industry is targeting a
50% reduction in drilling costs to ensure the basin remains globally competitive.
Despite expected cost savings, OGUK warns that with exploration at its lowest level since the 1970s
and fewer new projects gaining approval, capital investment is expected to drop from a peak of
GBP 14.8 billion in 2014 by GBP 2-4 billion in each of the next three years. The average capital
expenditure in the UK sector of the North Sea in the past 10 years has been GBP 8 billion. Final
investment decisions for Chevron’s Rosebank and BG’s Jackdraw projects have been delayed, with
start-up, if the projects get the go-ahead, after 2021. Given current prices further projects could be
deferred and companies might decide to shut and decommission some marginal fields.
Africa
Total non-OPEC African oil production looks set to decline by 260 kb/d over the forecast period, to
average 2.1 mb/d in 2021, as new projects, notably in Ghana and Congo, fail to offset declines
elsewhere. Lower prices, unrest in Sudan and
delays relating to infrastructure, logistics and
Figure 2.25 African oil production growth
politics have curbed our outlook for growth
150
from the region compared with last year’s
MTOMR.
100
50
60
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© OECD/IEA, 2016
kb/d
New supplies are nevertheless expected to
come from Ghana and Congo, and, towards the
end of the decade, from Uganda. Total launched
(50)
Phase 1 at its Moho Bilondo project in Congo in
(100)
December, adding 40 kb/d to total production.
2015 2016 2017 2018 2019 2020 2021
The company will complete the Moho Nord
Egypt
Eq. Guinea
Congo
extension in 2016, adding another 100 kb/d of
Gabon
Ghana
Uganda
oil output. Eni is also developing assets in
Other
Non-OPEC Africa
Congo, reporting first oil from its Nene Marine
field in January 2015. While output from the
first phase of the project is expected to yield only 7.5 kb/d, the company plans to bring on the second
phase contributing 40 kb/d in the second half of 2016. Longer term, development of the field will
occur in several stages and Eni expects the project to reach a production plateau of 140 kb/d. Eni’s
Litchendjili gas project, expected to start up imminently, will yield 20 kb/d of crude, condensates and
gas liquids. Lastly, Chevron sanctioned its Lianzi project, which straddles the Angolan border, in late
2015. The project will reach plateau production of 40 kb/d, of which 20 kb/d goes to Congo.
S UPPLY
In Ghana, Tullow is on track to bring its Tweneboa-Enyenra-Ntomme (TEN) project online in mid2016. The project will reach plateau production of around 80 kb/d in 2017. Tullow’s Jubilee project
was producing over 100 kb/d in 2015, but a new gas off-take project will enable increased
production. The Eni-operated Offshore Cape Three Points (OCTP) block is expected to see first oil in
2017 and first gas in 2018. Its peak capacity of 80 kboe/d is expected to be reached in 2019.
Developments in Uganda and Kenya are not moving ahead as quickly, however. Constraints relating
to infrastructure, logistics and politics mean that oil will not appear before 2020 from Uganda and
after 2021 for Kenya.
Uganda found 6.5 billion barrels of oil in the Albertine Basin near its border with the Democratic
Republic of Congo but commercial production continues to be postponed because of licensing
delays. Of the three companies involved in the Albertine Basin development only CNOOC has been
given a production license for the Kingfisher field with Tullow and Total still waiting for the green
light. Kenya’s push to start oil production by 2017 will be delayed by at least five years according to
the detailed design and construction timeline for the proposed crude oil pipeline connecting Uganda
and local oil fields to Lamu Island in Kenya. Kenya and Uganda have now settled on the route for the
oil pipeline, but long delays will stretch deadlines set by both governments for first oil, not now
expected until 2022.
Pipeline constraints are also limiting Niger’s ambitions to more than triple oil production from less
than 20 kb/d currently to around 70 kb/d over the next three years. Niger now processes all its crude
at its 20 kb/d Zinder refinery. CNPC is reportedly working on a planned link to carry crude to the
Chad-Cameroon pipeline which would allow Niger crude access to export markets. With little
apparent progress, we exclude any increase from Niger, and in particular from the Tenere and Bilma
projects, in these projections.
Prospects for Chad have also dimmed, with Glencore cutting spending and drilling due to lower
prices. Oil production in Chad will thus slip from current levels, pegged at around 120 kb/d in 2015.
We must inevitably take a cautious view of any likely increase in output from Sudan and South
Sudan. Although an international peace agreement is nominally in place, the political situation
remains fragile. Oil-rich South Sudan has lost nearly a third of its production since conflict erupted at
the end of 2013, with rebels shutting in production at oil fields in Unity State, on the border of
Sudan. Current output is estimated at around 150 kb/d, mostly from the Upper Nile state. The
government and companies are suggesting it might be possible to raise output to pre-conflict levels
of around 245 kb/d, but the oilfields are apparently damaged, and it would take time to repair them.
Output from Sudan is estimated at around 100 kb/d.
Oil output in Asia’s largest non-OPEC producer, China, has proven resilient in 2015, increasing by
110 kb/d to 4.3 mb/d, despite lower prices, spending cuts and an ongoing corruption scandal. While
2015’s increase largely stemmed from higher output from CNOOC’s offshore projects, growth in the
medium term will mainly come from the large Changqing and Yanchang fields. Changqinq output is
expected to increase from just shy of 500 kb/d in 2015 to 570 kb/d in 2021. Supplies from the
country’s largest oil field, Daqing, meanwhile, will decline over the medium term. PetroChina
announced in 2014 that it would curb output at the field in 2015 by 30 kb/d and a further 26 kb/d
M EDIUM -T ERM O IL M ARKET R EPORT 2016
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Asia
S UPPLY
China’s coal-to-liquids capacity is set to grow
from 50 kb/d currently to 170 kb/d in 2020,
from capacity in operation or under
construction. Announced plans are more
ambitious, with identified projects planned for
2021 totalling nearly 600 kb/d.
Figure 2.26 China oil production
4.4
4.3
mb/d
through 2020. Rapidly rising water content at
Daqing make crude extraction increasingly
challenging despite intensive secondary and
tertiary recovery activities. We forecast output
at the field to drop to 650 kb/d in 2021, from
765 kb/d in 2015. As such, overall Chinese oil
production is expected to decline by roughly
200 kb/d by 2021, to 4.1 mb/d.
4.2
4.1
4.0
3.9
3.8
2015
2016 2017
Current data
2018
2019 2020
MTOMR 2015
2021
New field developments lifted Malaysia’s oil production to an estimated 710 kb/d in 2015, nearly
60 kb/d higher than in 2014. The key contributor has been the Gumusut-Kakap field, which started
up in September 2014. Output of the field’s Kimani crude grade ramped up to around 50 kb/d by
mid-2015, and new gas handling and injection systems installed late in the year will allow the field to
ramp up towards peak output of 90 kb/d in 2016. Some new supplies also came from Lundin’s 15
kb/d Bertam field, which started up last year. Petronas meanwhile has approved the development
plans – revised after costs were cut by 30% - for the offshore Ophir oil field under a Risk Sharing
Contract granted in 2014. Facilities for the Ophir field include three production wells, a well head
platform and a leased FPSO vessel that will see production from this marginal field come on stream
late in 2016. New field developments and recent investments in oil fields using enhanced oil recovery
(EOR) techniques is expected to lift total oil production by 45 kb/d over the forecast period to reach
760 kb/d on average in 2021.
Australia
A reassessment of liquids output assumed from Australian LNG and other gas projects since last
year’s MTOMR has lowered the outlook for Australian oil supply for 2019-2020 by nearly 200 kb/d.
Australian oil production is nevertheless expected to grow by 240 kb/d to 620 kb/d in 2021, with
condensates and other NGLs contributing most of the growth.
Non-OPEC Middle East
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Along with its 2016 budget, Oman announced some details of its 2016-2020 development plan,
which is intended to diversify the economy away from hydrocarbons and into the manufacturing,
mining, transport and tourism sectors. The plan seeks to cut the oil industry’s contribution to GDP to
22% from 44% today and that of natural gas to 2.4% from 3.6% and it assumes an average 2016 oil
price of USD 45/bbl, USD 55/bbl for 2017-2018 and USD 60/bbl for 2019/2020, with average oil
output flat at around 990 kb/d. Oman, which saw production increase to a record 1 mb/d in 2015, is
expected to see declines through the forecast period, to 875 kb/d in 2021. Output in Yemen and
Syria continues to be restricted by war and for this reason we make no assumptions about the
recovery of production to 2021.
S UPPLY
OPEC
Lower oil prices will take a toll on OPEC crude oil production capacity, with growth expected to rise
by only 800 kb/d by 2021 as capital intensive projects are put on the back burner in the early years of
the forecast. Through to the end of 2016, capacity stays roughly flat with few upstream
developments expected. Modest growth – concentrated solely in the low-cost Middle East - returns
in 2017, assuming that oil prices begin to recover and allow for new investment.
Iran, Iraq and the UAE will dominate OPEC’s capacity expansion. Nuclear-related sanctions were
lifted on Iran in January and it will take advantage of this freedom to boost capacity by 340 kb/d to
3.94 mb/d by 2021– to emerge as OPEC’s biggest source of growth. This assumes that Tehran gains
access to capital and provides sufficiently attractive terms for international oil companies (IOCs) to
tap its vast oil fields. The capacity gain will not, however, be enough to allow Iran to reclaim its spot
as OPEC’s second biggest crude oil producer after Saudi Arabia. Iraq retains that position through
2021.
During 2015, Iraq, including the Kurdistan Regional Government (KRG), managed to post an
impressive year-on-year (y-o-y) capacity gain of 500 kb/d despite lower oil prices and a costly war
against the Islamic State of Iraq and the Levant (ISIL). But these challenges are set to slow
development from this year onwards, with growth of 270 kb/d by 2021. The UAE is expected to post
a similar capacity gain. The only Middle East producer to show a slight decline in capacity is Qatar,
where multi-billion dollar enhanced oil recovery (EOR) schemes are being deferred.
As for the rest of OPEC, declines in capacity are expected in Africa, Latin America and Indonesia,
which re-joined the group at the end of 2015. Algeria posts the biggest loss - 170 kb/d over the sixyear period – as a lack of investment pushes ageing oil fields into decline. Capacity is forecast to sink
by 70 kb/d in Nigeria, where costly deep water projects are being postponed and in Venezuela where expensive heavy oil upgrader projects are on hold.
Algeria
Angola
Ecuador
Indonesia
Iran
Iraq
Kuwait
Libya
Nigeria
Qatar
Saudi
Arabia
UAE
Venezuela
OPEC
2015
2016
2017
2018
2019
2020
2021
1.15
1.81
0.56
0.69
3.6
4.35
2.83
0.4
1.91
0.68
1.12
1.81
0.55
0.71
3.6
4.35
2.87
0.4
1.9
0.67
1.09
1.77
0.55
0.71
3.7
4.36
2.91
0.43
1.84
0.66
1.06
1.81
0.55
0.69
3.75
4.4
2.93
0.46
1.75
0.66
1.04
1.78
0.55
0.67
3.8
4.45
2.94
0.49
1.78
0.66
1.01
1.76
0.54
0.65
3.9
4.53
2.9
0.53
1.85
0.66
0.99
1.8
0.53
0.63
3.94
4.62
2.88
0.59
1.85
0.66
201521
-0.17
-0.02
-0.03
-0.06
0.34
0.27
0.05
0.19
-0.07
-0.02
12.26
12.31
12.43
12.45
12.44
12.39
12.33
0.07
2.93
2.46
2.97
2.46
3.02
2.44
3.07
2.43
3.12
2.45
3.17
2.44
3.2
2.42
0.27
-0.04
35.64
35.72
35.89
36.02
36.17
36.34
36.44
0.8
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Table 2.2 Estimated sustainable crude production capacity (mb/d)
S UPPLY
Box 2.6 Iran unrestricted
Relieved of nuclear sanctions on 16 January,
Iran is now positioned to substantially boost
supply during the medium term. In our base
case scenario, crude oil production capacity is
forecast to rise by 340 kb/d to 3.94 mb/d by
2021 – around 1 mb/d above current output.
Figure 2.27 Iran crude capacity scenarios
4.5
High
Base
Low
4.0
mb/d
It is difficult, however, to evaluate the real
3.5
state of Iran’s infrastructure and production
capacity. IOCs have had limited access to
3.0
Iranian data and only Chinese companies have
tapped the country’s oil fields during recent
years. Our assessment is that Iran made
2.5
2020
2010
2012
2014
2016
2018
considerable progress in preparing its oil
network well before sanctions were eased,
which set the stage for a swift increase in
Note source: Actual production 2010-15, capacity thereafter
supply. Flows from Iranian oil fields should rise
from a current rate of 3.0 mb/d towards pre-sanctions output of 3.6 mb/d by mid-2016.
Under the guidance of Bijan Zanganeh, the technocrat minister of petroleum serving his second term,
Iranian oil field engineers performed well workovers, ensured that processing units were in good
condition and tested delivery systems. If anything, some of the country’s core oil fields – such as Ahwaz,
Marun and Gachsaran - may have been refreshed under sanctions. Shutting in big volumes of oil may
have enabled pressure to rise – leaving the fields capable of a quick increase in production.
Contributions from smaller fields such as Karanj, Parsi and Raq-e-Safid may also be possible.
Just days after sanctions were suspended Tehran issued orders for an immediate 500 kb/d production
increase and vowed to add a further 500 kb/d in the following six months. Iran has set an output target
of around 5 mb/d for the end of the decade, although this appears to be aspirational. The country’s first
500 kb/d increment is expected to be made up of 60% Iranian Heavy, 30% Iranian Light and new, heavy
West of Karun crude – due to make its debut in the second quarter of 2016 - the remainder.
Figure 2.28 Selected crude oil export streams by quality
4.0
3.5
Nowruz-Soroush
% Sulphur
Dorud
Arab Heavy
3.0
2.5
Basrah Light
Foruzan
Iran Heavy
BCF-17
2.0
Bahregan
1.5
Arab Medium
Isthmus
Siri
Urals
Iran Light
1.0
15.00
20.00
25.00
API
Kirkuk
Arab Light
30.00
35.00
Lavan Blend
40.00
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Marketers from the National Iranian Oil Co (NIOC) have also primed their post-sanctions sales drive
although the current over-supply in global markets will make this more difficult. To speed the process,
NIOC may resort to competitive pricing and credit terms, as it did under sanctions, and may be open to
crude-for-product swaps.
S UPPLY
Box 2.6 Iran unrestricted (continued)
Over the medium term, Iran’s investment climate, political stability and the confidence levels it can instil
in the international banking and oil sectors will be key drivers of supply growth. Under our low case
scenario, the threat of snap-back sanctions - if Iran violates terms of the nuclear accord - dampens
outside investment and capacity rises by only 150 kb/d to reach 3.75 mb/d by 2021. Our high case
scenario assumes there is no re-imposition of sanctions and foresees a significant influx of foreign cash
and technology that boosts capacity by 500 kb/d over the six-year period to 4.1 mb/d.
Roughly 50% of Iran’s output is from fields that are more than 70 years old and in urgent need of
rehabilitation through new technology. NIOC has managed to maintain reservoir pressure through gas
re-injection but will be looking for alternative enhanced oil recovery (EOR) techniques, which it hopes to
obtain with the help of foreign oil companies. This would free up more gas for power generation,
industry and export.
Under its own steam, Iran could raise production beyond 3.6 mb/d once it regains full access to capital
markets and acquires more advanced technology. Sanctions relief will free up billions of dollars of frozen
assets.
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Map 2.1 Iran’s oil and gas fields
S UPPLY
Box 2.6 Iran unrestricted (continued)
Iranian Central Bank Governor Valiollah Seif has said USD 32 billion of funds would be released postsanctions. Some believe the amount may be as much as USD 100 billion. However attractive Iran’s
resources, Western oil companies and banks are unlikely to rush in at the start – especially given
corporate belt-tightening in the world of USD 30/bbl oil. It will take the IOCs a significant amount of time
to complete contract negotiations and due diligence.
With the help of foreign cash and technology, Iran could push capacity up towards the 4 mb/d mark by
the end of the decade. Sustainable capacity of 4 mb/d is most likely to be achieved after 2021, assuming
sanctions remain suspended. Efficient oil field management would be needed to upgrade processing
facilities to handle more water and to rehabilitate existing gas injection facilities and wells. Pipelines,
wells and other surface facilities would also have to be built.
Maintaining output at the 4 mb/d level would also require the rehabilitation of older fields and the
further development of giants such as Azadegan and Yadavaran. Iran’s aim is to increase output by
700 kb/d from these fields as well as Yaran that straddle the border with Iraq. Roughly 160 kb/d is
expected to come online in 2016, with another 500 kb/d flowing in 2021.
China National Petroleum Corp (CNPC) developed the first phase of the onshore North Azadegan oil field
and it is believed to have priority when it comes to tapping the second phase. Commissioning is
underway and the field is expected to produce an initial 75 kb/d. China’s Sinopec is at work on the first
phase of development at Yadavaran, which is expected to pump 85 kb/d.
To lure the IOCs, Tehran has hammered out a much improved version of its former buy-back investment
contract. The new upstream contract and details of 70 projects were unveiled at a conference in Tehran
in late November. While the new Iran Petroleum Contract (IPC) is a vast improvement on the unpopular
buy-back model – which compensates foreign companies with production – potential investors are still
waiting to see the fine print.
Their appetites may be dampened by the possibility of a re-imposition of sanctions should the nuclear
accord unravel. In the case of US companies, there is an additional drawback due to Washington’s nonnuclear related sanctions which remain in place.
Priorities for development are joint fields, such as South Azadegan, which borders Iraq, and offshore
Farzad and Foroozan, which are shared with Saudi Arabia. In the last two cases, the deteriorating
political relationship between Iran and Saudi Arabia may raise doubts as to their viability. Not included
on the list of 70 projects were some of Iran's biggest oil fields such as Marun and Gachsaran.
For now, Iran’s production capacity limitations are most probably surface-related – production units,
flow lines, trunk pipelines and gas compression facilities. Service companies and equipment suppliers
will be needed to help sustain capacity at around 3.6 mb/d. They could potentially help boost capacity
towards 3.8 mb/d – a level that is reached in 2019 under our base case scenario.
Iran’s investment in field management was hard hit by sanctions as was exploration work for which
foreign expertise will be needed. Data about recovery rates and natural decline in Iran are scarce.
However, industry sources estimate that Iran’s recovery rates range between 15% and 40% depending
on the fields, with an average of around 20% - lower than elsewhere in the region. In Saudi Arabia,
Kuwait and Iraq, the average recovery rate is closer to 35%-40%.
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Looking further ahead, Iran will also strive to reclaim its spot as OPEC’s second biggest crude oil
producer after Saudi Arabia – a post now occupied by Iraq. But with Iraq now pumping more than
4 mb/d, Tehran will have its work cut out. Indeed, Iraq is expected to maintain its lead through the
forecast period.
S UPPLY
Box 2.6 Iran unrestricted (continued)
Table 2.3 Iran’s key IPC oil and gas projects
Greenfield Projects – Oil
Reserves (billion bbl)
Production ('000 b/d)
25.6
50
South Azadegan -- Phase 2
Oil Fields Package*
16.7
0
Golshan/Ferdowsi
4.5 / 31.7
0
Darquain Phase 3
2.6
0
Changuleh
2.4
0
1.7 – 4.2
0
Ahwaz-Bangestan
31.6
150
West of Iran Package**
15.7
160
Mansuri-Bangestan
15.1
70
South Pars Oil Layer
Brownfield Projects – Oil
Soroosh
14.2
50
Ab-Teymour
12.2
50
Doroud
11.0
70
Nowrooz
4.2
30
Salman
4.1
50
Foroozan
3.4
40
Reserves (Bcf)
Production (MMcf)
57,068
0
Greenfield Projects – Gas
North Pars
Kish
55,000
0
Gas Fields Package (a)
42,834
0
22,500 / 8,800
0
South Pars Phase 11
20,129
0
Khami Fields (eight fields)
13,000
0
Golshan/Ferdowsi
Farzad A/Farzad B
10,488/12,501
0
Balal Gas Field
6,250
0
Exploration Basin/Sub-basin
Block
No. of Blocks
Central Iran
Kavir
1
Moghan
Moghan
1
Bamdad/Mahan/Parsa
3
Sarakhs/Dusti/Raz
3
Eastern Iran
Sistan
1
Taybad
Taybad
1
Gulf
Kopeh Dagh
Dezful/Zagros
Abadan
1
Timab/Zahab
2
Fars/Zagros
Tudej
1
Caspian Sea
Block 24/26/29/Sardar eJangal
4
--
18
Lorestan/Zagros
Total No. of Exploration Blocks
*Sohrab, Arvand, Band-e Karkeh, Jofayr, Sepehr, Susangerd
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**Aban, Paydar, West Paydar, Danan, Cheshmeh Khosh, Dalpari, Naft-Shahr, Sumar, Deloran
S UPPLY
After posting extraordinary growth in oil production in 2015, it will be a challenge for Iraq to increase
output substantially in 2016. The lower oil price environment has forced the government to ask
foreign contractors to cut costs by as much as 50% which is expected to slow capacity building. Away
from Baghdad, the KRG is struggling to pay its oil field investors. Production capacity in OPEC’s
second biggest producer is projected to expand to 4.62 mb/d by 2021, for annual average growth of
45 kb/d. As ever, there are risks to this outlook: to the upside given Iraq’s massive, low-cost reserve
base and budgetary pressure to turn up the taps and to the downside given the country’s myriad
financial, economic, institutional and security hurdles.
Map 2.2 Iraq’s oil infrastructure
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Iraq managed to smash production records in 2015 and into 2016 even as it battled against Islamist
militants and grappled with a severe budget crunch. Low oil prices have offered every incentive to
ramp up output and Iraq achieved a y-o-y production increase in 2015 of 650 kb/d, second only to
the 920 kb/d rise in total liquids production in the United States.
S UPPLY
Iraqi growth during 2015 was split fairly evenly between the south, controlled by the federal
government, and the north – where the KRG has taken charge. That pattern is set to change over the
forecast period, with southern Iraq – the country’s oil heartland - providing the bulk of the
expansion. But the country’s prized oil fields will come nowhere close to realising their potential
unless a long-delayed mega-project to supply water sees the light of day. This is unlikely to happen
during the forecast period.
Flows of Basra crude from the southern fields have risen steadily following the commissioning in mid2015 of a new system to separate heavy and light oil and the construction of more storage tanks at
the Fao terminal. Some heavy crude from oil fields such as West Qurna-2, Halfaya and Gharraf had
been shut in to maintain the quality of Basra Light. These newly developed fields - unlike the more
mature fields of Rumaila, West Qurna-1 and Zubair - are not in desperate need of water and could
see higher production over the next six years.
Supplies of northern crude also rose substantially after the KRG increased deliveries through its own
pipeline link to Turkey. The KRG had agreed at the end of 2014 to ship 550 kb/d via the federal
government's State Oil Marketing Organisation (SOMO) in exchange for the resumption of budget
payments from Baghdad. But since mid-2015, the KRG has steadily increased independent oil sales
and cut allocations to SOMO amid an escalating row over export rights and budget payments. The
KRG now controls all northern oil sales.
Most of the exports to the Turkish port of Ceyhan are from fields under the control of the KRG, with
the federal government's North Oil Co (NOC) contributing supplies from the Kirkuk field's Baba dome
and the adjacent Jambour field. Apart from the KRG's Taq Taq and Tawke oil fields and the Kirkuk oil
field's Khurmala dome, the Kurds are also managing Kirkuk's Avana dome and the nearby Bai Hassan
oil field, formerly operated by NOC. Industry sources say the capacity of the KRG's independent
pipeline to the Turkish border has risen to at least 750 kb/d.
Figure 2.29 Iraq crude capacity
mb/d
Although 2015 was a successful year for oil
output, Iraq’s costly battle with ISIL, whose
fighters still control major parts of the north,
has forced the oil ministry to cut back on
investment
in
new
production
and
infrastructure projects around Basra. While the
federal government has moved to improve
contract terms for IOCs at work in the south,
security issues and Baghdad's cumbersome
decision-making process have increased the
cost of business. Although foreign contractors
operate far from areas of conflict with ISIL,
skirmishes between rival tribes and the resulting
military response are raising tension in the
south.
5.0
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
0.5
0.0
2010
2012
2014
2016
2018
2020
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IOCs in charge of the southern mega-projects have spent tens of billions of dollars to raise capacity
by more than 1 mb/d to well above 3 mb/d since the Iraqi expansion got underway in 2010. To
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support project economics, it is crucial for the companies – especially given industry-wide cost
cutting – to be repaid almost immediately for their work performed under service contracts. Further
growth is expensive and the IOCs need assurance of repayment. To maximise output from oil fields
such as Rumaila – the country’s biggest producer - West Qurna-1 and Zubair, it is crucial to get a
long-delayed water injection scheme, which underpins Iraq’s massive upstream expansion, up and
running. To that end, Iraq's oil ministry is in talks with ExxonMobil and PetroChina to revive the
project. Exxon and PetroChina each hold a 25% stake in West Qurna-1.
In northern Iraq, Kurdish Peshmerga and Iraqi forces have had some success in pushing back ISIL but
the costly fight has put the KRG budget under enormous strain. The KRG is struggling to pay foreign
investors developing the region’s oil fields and investment has slowed considerably – even at the
biggest foreign-operated oil fields of Taq Taq and Tawke.
The UAE also posts a solid increase in capacity by 2021– a rise of 270 kb/d to 3.2 mb/d – although it
is cutting costs and optimising development plans in response to lower oil prices.
While the UAE’s reserves look even more attractive in a low oil price environment, corporate belt
tightening may make it challenging for foreign companies to commit to investing in capacity building.
For that reason, Abu Dhabi National Oil Co (Adnoc) will find it difficult to secure new partners for its
major onshore oil concession. Negotiations with IOCs concerning more than half of the 40% stake to
be held by foreign investors have dragged on for years.
Figure 2.30 UAE crude capacity
3.4
3.2
mb/d
The new 40-year production-sharing pact covers
the development of 15 of the emirate’s onshore
oil fields accounting for more than half its
output. Abu Dhabi has only awarded 18% of a
planned 40% in the new Abu Dhabi Co for
Onshore Petroleum Operations (Adco) —Total,
with 10%, Japan’s Inpex (5%), and South Korea’s
GS Energy (3%). Adco now produces around
1.6 mb/d and the official target is to reach
1.8 mb/d by 2018. Adco has said that most of its
development projects should be commercially
viable even at an oil price of USD 20/bbl.
3.0
2.8
2.6
2.4
2010
2012
2014
2016
2018
2020
In the medium term, the offshore Upper Zakum field – one of the world’s largest – will provide the
most significant expansion to UAE capacity. Production from the technically challenging field is
expected to rise by more than 150 kb/d by 2018 after the completion of a USD 10 billion project. Zakum
Development Co (Zadco), the joint venture that operates the field, is held 28% by Exxon, 12% by Jodco
and 60% by Adnoc.
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Abu Dhabi is meanwhile making initial
preparations for the contest over its offshore Adma-Opco concession that expires in 2018. Adnoc
holds 60% in the joint-venture, with international partners - BP (14.67%), Total (13.33%) and Japan’s
Jodco (12%) – holding the remainder. It operates a group of offshore oil fields including the crucial
Lower Zakum and Umm Shaif. Umm Lulu, which started up in 2014 – more than a year behind
schedule - and Nasr, which began pumping in 2015, will also be among the fields in the concession.
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The sharp decline in oil prices has Saudi Arabia facing a severe budget crunch and its response has
been spending cuts and unprecedented reforms to energy and utility subsidies. Even so, it is expected
to follow through with crucial projects to sustain capacity near its official 12.5 mb/d target through the
forecast period.
Saudi Aramco has slowed some projects, taken some marginal ones off the drawing board and
sought discounts from contractors. But critical output additions at the Shaybah oil field that pumps
Arab Extra Light and at the Khurais oil field, an Arab Light producer, are still due to come online and
hold capacity above 12.3 mb/d through 2021. Saudi Arabia’s aim is to stabilise, rather than increase,
oil output capacity as it seeks to develop non-associated and unconventional gas reserves.
Budget cuts have, however, reportedly slowed the pace on the estimated USD 3 billion Khurais oil
project. Work to expand capacity at the field by 300 kb/d to 1.5 mb/d began at the end of 2015 and
completion is now expected to be delayed by about a year to 2018. A 250 kb/d upgrade at Shaybah is
reportedly on schedule and due for commissioning in early 2016. It is expected to raise capacity to
1 mb/d by the first quarter of 2017. These new capacity additions will help compensate for natural
decline rates and allow Saudi Aramco to reduce production at Ghawar, the world’s biggest oil field.
Ultimately this may allow for better reservoir management and recovery rates.
Capacity could also be boosted from the offshore oil fields of Zuluf, Safaniyah (the world’s largest
offshore field) and Marjan – which could add around 600 kb/d between them. Such a costly
programme would, however, have to be launched in the early part of the forecast period in order to
deliver.
Saudi Arabia is meanwhile giving serious consideration to a share offering of Saudi Aramco, the
world’s largest oil company, or its subsidiaries. The bold move was under study even before the price
of oil began its descent in mid-2014.
Kuwait continues to push ahead with plans to boost crude oil capacity, although the closure of the
400 kb/d Neutral Zone shared with Saudi Arabia is frustrating near-term growth. Capacity is forecast
at 2.88 mb/d in 2021, up 50 kb/d compared to 2015. Kuwait for now has been sustaining robust
production levels at the giant Burgan oil field and raising output elsewhere to compensate for lost
output arising from the Neutral Zone operational disagreement that began in late 2014. Capacity is
expected to rise from late 2016, assuming a resolution to the dispute, before easing by the end of the
forecast period. An official capacity target of 4 mb/d by 2020 looked ambitious even before the
Neutral Zone closure and the oil price collapse.
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Aware that foreign technology and project management skills are vital to tapping its geologically
complex reserves, Kuwait is continuing to negotiate enhanced technical services agreements (ETSAs)
with IOCs. BP, Royal Dutch Shell and Total are reportedly in talks with Kuwait Petroleum Corp (KPC)
for deals that cover the Burgan onshore oil field, a water management programme and development
of the Ratqa heavy oil field near the northern border with Iraq. The plan is to pump around 80 kb/d
from Ratqa by 2018 and increase production to 120 kb/d by 2025. At Burgan, one of the world’s
largest oil fields, a planned water injection scheme is expected to hold production steady at 1.7 mb/d
beyond 2020.
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Major oil companies such as Total, Exxon, BP and Chevron have previously looked at working with
Kuwait on enhanced oil recovery projects. Kuwait has struggled for decades to make progress in its
upstream oil and gas sector: vigorous domestic opposition to foreign involvement has previously led
to lengthy delays in project approvals.
Oil services firm Schlumberger at the end of 2015 meanwhile submitted the lowest bid for three
contracts valued at USD 4.3 billion to build and operate oil and gas production facilities at the East
Raudhatain, West Raudhatain, West Sabriya and Umm Niqa fields.
Qatar’s crude oil production capacity dips to 660 kb/d by 2021, down 20 kb/d from the start of the
forecast period as lower oil prices slow investment. Oil output in Qatar has been trending downward
since hitting a peak of 860 kb/d in 2008. In the meantime Qatar has become the world’s largest LNG
exporter. In response to lower oil prices, Qatar Petroleum (QP) is renegotiating production-sharing
contracts, slashing spending and cutting jobs.
QP has reportedly asked Danish Maersk to halt further spending at the 300 kb/d al Shaheen field –
which accounts for nearly half of Qatari output - ahead of the mid-2017 expiry of its productionsharing contract. QP is seeking to secure more favourable terms at its largest producing oil field and
some of the world’s leading oil companies, including Total, are interested. Eight firms have been prequalified to bid. Total already operates the 25 kb/d offshore al-Khaleej field and other majors such as
Exxon, ConocoPhillips and Shell are also involved in Qatar. Maersk was not given the option to
renew, but is expected to bid to stay on at the technically challenging field. The terms and contract
structure for al-Shaheen will set the standard for the tender process for the 100 kb/d Idd al-Shargi,
operated by Occidental, and due to expire in 2019.
It can be very costly to develop Qatari oil fields due to their complex geology, yet a multi-billion dollar
plan to double the 45 kb/d, offshore Bul Hanine field is reportedly going ahead.
The direct targeting of Libya’s oil infrastructure by Islamist militants and ongoing political chaos make
the country’s medium term capacity prospects look very uncertain. It will be a challenge merely to
sustain production in the near term as an end-2015 UN-sponsored deal between Libya’s two rival
governments has failed so far to create stability. There is potential for capacity to grow gradually
from 400 kb/d in 2015 to 590 kb/d in 2021 but this is necessarily speculative.
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Libyan oil production had managed to recover briefly despite post-civil war armed conflict and chaos
that followed the overthrow of Muammar Gaddafi in 2011. But capacity is unlikely to surpass the
1 mb/d mark that was seen briefly in October 2014 or come anywhere close to the 1.6 mb/d that was
attained prior to 2011. As of February 2016, only two of seven onshore crude export terminals were
in use – the 120 kb/d Marsa el-Brega and the 140 kb/d Marsa el-Hariga. A power struggle between
the officially recognised government in the east and the so-called Libya Dawn administration in
Tripoli – as well as the Petroleum Facilities Guards and other armed factions- have halted operations
at strategic oil terminals and fields.
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Map 2.3 Libya’s oil infrastructure
In early 2016, militants linked to ISIL attacked and set fire to oil storage tanks at the Ras Lanuf and
nearby Es Sider terminals. Both ports, which together can handle 560 kb/d of exports, have been
shut-down since December 2014 – a substantial set back to production. The Waha Oil Co, the biggest
producer in the Sirte Basin oil heartland, as well as Sirte Oil Co, Zueitina Oil Co and Harouge Oil
Operations have shut in production. An attack by militants in March 2015 badly damaged surface
facilities at some of their fields. As a result, Libya’s National Oil Corp (NOC) is relying heavily on oil
produced in the east by the state Arabian Gulf Oil Co (Agoco) and the Sarir and Mesla fields have
pumped as much as 300 kb/d.
Lower oil prices are meanwhile forcing spending cuts. Energy revenues dropped by about 50% in
2015 to around USD 34 billion and are set to decline further in 2016. Even so, Sonatrach insists it will
carry through with a USD 90 billion, 2015-19 oil and gas investment scheme. Algeria holds more than
USD 130 billion in foreign reserves, a financial cushion that allows welfare programmes to continue.
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Algeria’s new team of top oil and gas officials – led by minister of energy Salah Khebri and Sonatrach
head Amine Mazouzi - is working to manage a steep drop in energy earnings and lure investment to
stem declines at ageing oil fields. Within OPEC, Algeria is expected to post the largest loss in capacity,
which sinks by 170 kb/d to just below 1 mb/d in 2021. Despite its notable resources, exploration and
development of new Algerian oil fields has ground to a halt. Sonatrach has struggled to drum up
foreign interest in recent energy auctions and the collapse of oil prices forced the postponement of
the late-2015 licensing round. In a bid to secure capital and technology, Algiers might therefore opt
to negotiate deals directly with IOCs. The Bir Sebaa and Bir Msana oil fields started pumping last
summer – adding roughly 30 kb/d of output – but more new projects are needed to stabilise
production. Sonatrach has said it will strive to halt declines at mature oil fields such as Hassi
Messaoud, its largest producer.
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The oil price collapse is causing particular pain for Nigeria, where a new government led by President
Muhammadu Buhari was elected in April 2015. Production capacity is expected to decline by 70 kb/d
over the forecast period to 1.85 mb/d as investment slows in the country’s high-cost deep water
projects and large-scale oil theft and pipeline sabotage in the Niger Delta oil heartland continues
unabated. Buhari has vowed to stamp out corruption in the Nigerian National Petroleum Corp
(NNPC) and put an end to oil theft, which he estimates at around 250 kb/d. Africa’s biggest producer
relies on oil exports for nearly 60% of government revenue. As output slows and oil prices collapse,
state revenue is declining – leaving NNPC unable to pay the foreign partners at work in Nigeria’s
fields. NNPC's joint ventures account for roughly 60% of the country’s overall crude production.
Investment in capital intensive deep water projects had already slowed due to the long-running
deadlock over the Petroleum Industry Bill (PIB). The Buhari government has come up with a new
draft PIB that would split NNPC into two separate entities, sell assets to raise cash and list at least
30% of the state company.
mb/d
Nigeria’s biggest projects due online during the forecast period are the 225 kb/d Bonga SW-Aparo
deep water fields and the 200 kb/d offshore, deep water Egina. They appear unlikely to start up
before 2020. Shell was expected to take a final
investment decision on the Bonga SW-Aparo
Figure 2.31 West African crude capacity
project in 2014, but has delayed the decision on
3.00
the estimated USD 12 billion scheme.
Angola Nigeria
Companies may be hoping to achieve lower
2.50
development costs that reflect the decline in oil
2.00
prices.
1.50
Oil’s sharp drop has also hit growth prospects in
Angola, with capacity in Africa’s second largest
1.00
producer expected to hover around the
0.50
1.80 mb/d level over the forecast period. A
90 kb/d capacity expansion was forecast in the
0.00
2015 MTOMR. The country’s ageing offshore oil
2010
2012
2014
2016
2018
2020
fields need continuous support from new and
costly projects to offset steep declines. Since output peaked in 2008, Luanda has struggled to stem
the drop. Oil from new developments lifted production slightly in 2015 as Exxon's Kizomba satellites
and ENI’s Cinguvu field came on line. But further growth is not expected during the forecast period as
low oil prices force companies to delay or abandon prohibitively expensive projects.
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Even before the oil price rout, Angola’s official 2 mb/d target looked unachievable given the technical
problems besetting its deep water projects. Higher pumping rates are crucial to Angola as oil exports,
half of which are shipped to China, account for around 80% of state revenues. The biggest oil
development on the drawing board is Total’s USD 16 billion Kaombo, the last project to be
sanctioned before the price collapse. Sonangol has reportedly adjusted the terms of the productionsharing contract in response to lower oil prices and construction costs. First oil is expected in 2018 –
about a year behind schedule – and at its peak, the ultra-deep water field is expected to pump
230 kb/d.
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High costs have, however, led Maersk to delay the 100 kb/d Chissonga project. The 2015 start-up of
Chevron’s USD 5.6 billion Mufumeria Sol – with peak output of 150 kb/d - was pushed into 2016 but
Chevron did progress in 2015 with its Lianzi project – shared with Congo – that is due to pump
40 kb/d. Cobalt International Energy sold its 40% stake in the potentially complex presalt Cameia
development to Sonangol for USD 1.75 billion.
Oil output capacity in Venezuela is expected to slip to 2.42 mb/d by 2021 from 2.46 mb/d, as the oil
price slump leaves Caracas desperately short of cash to fund its expansion. Even before the most
recent bout of oil price weakness, Venezuela’s economy was severely distressed and the potential for
political conflict is increasing following the victory by opposition parties in December’s congressional
elections. Many OPEC nations produce heavy crudes that sell at a discount to international
benchmark Brent. Typically the value of Venezuela’s composite basket of crude oil is USD 7/bbl
below Brent, so the country is being hit even harder by low prices.
In line with other international companies, Petroleos de Venezuela (PDVSA) cut its capital spending
for 2016 in response to lower oil prices, with reported investment of USD 15 billion running 63%
below the 2015 level. The cutbacks in investment will affect PDVSA’s efforts to boost production –
especially from the Orinoco extra-heavy belt, which accounts for just under half the country’s output.
Major operational and organisational hurdles must be overcome and the country’s mature oil fields –
many of them with steep decline rates - are being neglected. Chronic project delays have pushed
development plans far behind target and more than half a dozen companies have already given up on
Orinoco. Even when oil prices were above USD 100/bbl for several years, PDVSA’s foreign partners
were slow to expand their export-oriented projects as the company struggled to fund its
investments.
To save money, PDVSA plans to increase purchases of lighter crude oil from Algeria, Nigeria and
Russia to dilute extra-heavy Orinoco crude and make it more attractive to foreign refiners and for
processing at home. The imported crude is cheaper than the naphtha PDVSA had been buying to use
as a diluent. To finance the lighter crude imports, PDVSA is reportedly delaying investment in new
upgrader projects in the Orinoco belt as well as a deep conversion refinery.
Caracas is supplying roughly 500 kb/d to China, which has loaned Venezuela more than USD 50 billion
in exchange for future crude shipments. Companies from China and Russia are also invested in joint
venture projects in the Orinoco Belt.
Ecuador has managed to hold production steady for the past several years partly by offering major
service companies incentives to squeeze out more oil from mature fields in its core eastern region.
When oil prices collapsed, these set per barrel fee-based contracts became loss-makers for Quito and
Petroamazonas began to renegotiate. A Schlumberger-led consortium has agreed to the new terms
at the mature 70 kb/d Auca oil field and will invest an initial USD 1.1 billion to raise production by
20 kb/d within three years.
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Ecuador, heavily reliant on oil exports for state revenue, is reeling from low prices. At USD 30/bbl, its
benchmark Oriente crude is selling around USD 5/bbl below production costs. Petroamazonas, which
pumps nearly 80% of the country’s oil, has slashed spending and has warned that output is likely to
suffer as a result. By 2021, production capacity in OPEC’s smallest producer is forecast to decline to
530 kb/d – down 30 kb/d from 2015.
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Crucial to the sustainability of Ecuador’s capacity is the successful development of the billion-barrel
Ishpingo-Tambococha-Tiputini oil block in the Amazon rain forest that contains about a fifth of
Ecuador’s total reserves of 8 billion barrels. These heavy oil fields, located within a UNESCO’s world
biosphere reserve, are unlikely to be pumping substantial quantities before 2018. The collapse in oil
prices has forced Petroamazonas to seek foreign help and China’s Sinopec is reportedly in the frame. Oil’s
sharp drop also led Canada’s Ivanhoe Energy to suspend its Pungarayacu extra-heavy oil project, located in
Block 20. Petroamazonas is for now in charge of the challenging block, situated along the eastern edge of
the Andes. Early drilling showed an API gravity of between 8-9 degrees, so the oil would have to be
upgraded to move it.
Capacity in Indonesia is expected to slip to 630 kb/d in 2021 from 690 kb/d at the start of the forecast.
Since peaking above 1.6 mb/d in the 1990s, crude oil production in OPEC’s only Asian member has
decreased steadily due to chronic under-investment. But the Banyu Urip field in East Java that started
up in 2015 will help offset some of the decline in the country’s ageing oil fields. The Exxon-operated
project, the largest in Indonesia, will account for roughly 20% of Indonesia’s overall production once
it hits target output of 165 kb/d in 2016. Capacity could even rise towards the 200 kb/d mark. Further
support comes from the offshore Bukit Tua field that Malaysia’s Petronas started up in 2015. The
East Java field is expected to pump 20 kb/d of oil and up to 50 MMscf/d of gas.
OPEC gas liquids supply
Low oil prices are also slowing growth in OPEC’s condensate and NGL output as projects are
deferred. Production capacity of condensate and other natural gas liquids and non-conventional
resources is forecast to rise by 475 kb/d to 7.15 mb/d by 2021 as many countries focus on natural gas
developments. Iran, now released from nuclear sanctions, accounts for 57% of the total growth.
Saudi Arabia, Angola and Qatar also post notable gains over the forecast period.
Iran’s drive to raise output from the massive South Pars gas field is motivated by a surging internal
requirement for natural gas and momentum will accelerate as it gains more access to funds. Iranian
NGL capacity is estimated at 990 kb/d by 2021, equating to growth of 258 kb/d over the forecast
period. Long delayed projects at South Pars are being fast-tracked, though a large proportion of the
volume is likely to be for internal use – including petrochemicals.
The expansion of South Pars, which has 24 phases, had been frustrated by rigorous financial
sanctions that restricted Iran’s access to equipment and technology crucial for developing
infrastructure. Early 2016 saw the inauguration of phases 15-16, which are expected to bring on
75 kb/d of condensate and 30 kb/d of other gas liquids in 2018. Iran launched the South Pars
Phase 12 project in 4Q14, which includes 75 kb/d of condensate capacity and 30 kb/d of NGLs. Iran’s
South Pars field is a geological extension of Qatar’s North Field.
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Qatari condensate, natural gas liquids and non-conventional capacity – mostly from the North Field –
is due to increase by 63 kb/d to just above 1.25 mb/d by 2021. The USD 10 billion Barzan field, the
last big project to come online since Doha’s 2007 moratorium on further development of the North Field,
has been delayed until later in 2016. Originally due to start up in 2014, the offshore project – owned 93% by
QP and the remainder by Exxon - is expected to add 50 kb/d that will be earmarked for the domestic
market.
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Saudi Arabia, holder of OPEC’s largest NGL capacity, is expected to increase production by around
165 kb/d to just under 2 mb/d by 2021. The 275 kb/d Shaybah NGL development, which includes
190 kb/d of ethane, is running more than a year behind schedule due to technical issues. Completion
of the scheme, which will supply feedstock to the domestic market, was originally scheduled for mid2014. Further condensate capacity will come online from the Wasit gas megaproject – which involves
development of the Hasbah and Arabiyah fields. But it, too, has also been hit with delays due to
technical snags.
In the UAE, the fate of the USD 10 billion Bab gas field project is unknown after Shell decided to exit
the complex sour gas field project that it was to develop with Adnoc. Shell won a tender in 2013 for a
40% stake in Bab.
Angola is expected to increase gas liquids capacity by 70 kb/d to 140 kb/d in 2021 following the long
awaited start-up of Angola LNG in January 2016. The USD 12 billion project had been beset with
technical problems and was shut in the spring of 2014 after a gas leak at the 5.2 mt/y liquefaction
plant, which includes production of 50 kb/d of NGLs.
Table 2.4 Estimated OPEC condensate and NGL production (kb/d)
Country
Algeria
Angola
Ecuador
Indonesia
Iran
Iraq
Kuwait
Libya
Nigeria
Qatar
Saudi Arabia
UAE
Venezuela
Total OPEC NGLs*
Non-Conventional**
Total OPEC
2015
469
70
0
133
732
86
310
35
494
1,192
1,830
856
205
6,412
265
6,677
2016
471
79
0
133
835
90
310
40
473
1,202
1,881
868
200
6,582
271
6,854
2017
466
105
0
133
878
90
307
45
476
1,231
1,920
875
195
6,722
271
6,993
2018
464
118
0
133
932
95
305
50
459
1,253
1,943
882
185
6,818
271
7,089
2019
454
128
0
128
965
95
300
60
444
1,246
1,963
881
180
6,843
274
7,117
2020
444
138
0
123
983
100
297
70
429
1,250
1,985
885
170
6,873
275
7,149
2021
439
140
0
121
990
105
297
75
415
1,255
1,995
884
160
6,876
275
7,152
2015-21
-30
70
0
-12
258
19
-13
40
-78
63
165
28
-45
464
11
475
* Includes ethane.
** Includes gas-to-liquids (GTLs).
Biofuel supply
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Global biofuels production increased in 2015 by 2% versus 2014 to 2.3 mb/d, accounting for around
4% of world road transport fuel. Production was over 60 kb/d higher than forecast in the 2015
MTOMR, underpinned by a positive year for ethanol production in the United States and Brazil, aided
by good harvest yields for corn and sugar cane biofuel feedstocks respectively.
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Figure 2.32 Global biofuels production 2014-21
Volumetric
3.0
2.5
mb/d of oil equivalent
2.5
mb/d
2.0
1.5
1.0
0.5
0.0
2014
2015
2016
United States biofuels
OECD Europe biofuels
2017
2018
2019
2020
Brazil biofuels
Rest of world biofuels
2021
Adjusted for energy content
5%
2.0
4%
1.5
3%
1.0
2%
0.5
1%
0.0
0%
2014 2015 2016 2017 2018 2019 2020 2021
World biofuels, energy adjusted
As % of global road transport demand
Note source: IEA (2015) Monthly Oil Data Service (database); MAPA (Ministério da Agricultura, Pecuária e Abastecimento), Ministério da
Agricultura – Agroenergia; US EIA, Petroleum & Other Liquids.
Despite a low oil price environment biofuels mandates proved effective in protecting the industry
from direct competition with lower-priced gasoline and diesel. However, cheaper petroleum
products have compromised biofuel blending economics and limited opportunities for discretionary
blending above mandated levels; the latter principally effecting export driven markets e.g. biodiesel
trade from Argentina and Indonesia. Despite falling oil prices, mandates and supportive biofuel
policies have actually been strengthened in key markets such as Brazil and India. Lower crude oil and
products prices have also allowed the reduction or removal of fossil fuel subsidies in countries such
as Indonesia and Malaysia, aiding biofuels competitiveness.
Our medium-term forecast for global biofuels production sees an increase to 2.7 mb/d in 2021. This
represents an upward revision compared to the MTOMR 2015 based on more positive prospects in
Brazil, where biofuels are a central component of its Intended Nationally Determined Contribution, in
addition to anticipated growth in biofuel markets in non-OECD Asia. In countries such as Thailand,
India and Indonesia growing fuel demand coupled with enhanced policy support for the consumption
of domestically produced biofuels is evident. A downside risk for biofuels in the short-term is the
potentially disruptive impact on crops and harvest conditions from temperature and precipitation
changes as a result of the strong 2015-16 El Niño weather event.
In the United States , the largest global producer of fuel ethanol, lower motor gasoline prices in 2015
contributed to an increase in demand by around 2.5% y-o-y and consequently resulted in a higher
volume of ethanol blended. As a result, ethanol production rose to around 950 kb/d and should
stabilise at near this level over 2016 before gradually decreasing to 890 kb/d in 2021 due to
improved vehicle fleet efficiency. It is not anticipated that this will be counteracted by significant
increases in the market penetration of E15 and E85 ethanol blends over the forecast period. The
Environmental Protection Agency’s final Renewable Fuel Standard (RFS 2) annual volume
requirement allocations for 2014-16 are reductions on statutory levels previously established, but
still allow for continued growth in renewable fuel production. The ethanol industry could also be
boosted by export prospects to China and other non-OECD Asia countries in 2016.
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Regional outlook
S UPPLY
Biodiesel production in the United States rose slightly to 85 kb/d in 2015, boosted by a good soybean
harvest. RFS 2 requirements for biomass-based diesel were established up until 2017 with annual
volume requirements increasing y-o-y. Biodiesel is also eligible to contribute to the RFS 2 advanced
biofuel category. Furthermore, the extension of the USD 1/gallon blenders’ tax credit for two years
to retrospectively cover 2015 and also the calendar year 2016 provides increased certainty for
producers for the year ahead. As a result of this more favourable policy environment biodiesel
production is revised up to 110 kb/d in 2021.
Post revision, California’s Low Carbon Fuel Standard (LCFS) was re-introduced in September 2015.
Due to the reduction of the required fuel carbon intensity values within the scheme it will be
challenging to utilise corn ethanol from the United States to achieve compliance from 2016, meaning
sugar cane ethanol imports or advanced biofuels are likely to be utilised to achieve compliance.
Ethanol production in Brazil had a strong year with a record output of just over 510 kb/d; achieved
due to a combination of a good sugar cane crop and optimal harvest conditions. A significant y-o-y
increase in hydrous ethanol consumption of around 40% 2 occurred due to federal tax increases for
gasoline 3 increasing competitiveness at the pump. As a result, some producers have announced
proposals for investment in new and expanded production capacity. An increase in blended
anhydrous ethanol consumption in 2015 due to the higher 27% mandate did not materialise due to a
contraction in gasoline-C consumption.
The central role of biofuels within Brazil’s decarbonisation initiatives 4 sees production increase over
the medium-term to around 675 kb/d in 2021, an upward revision on our 2015 MTOMR. However,
2016 may see a slight reduction in production due to the rebound in international sugar prices in late
2015 potentially favouring a higher share of sugar production at the expense of ethanol.
Biodiesel production in Brazil increased to 70 kb/d in 2015 with production prospects improved due
to an increase in the biodiesel blending mandate to 7%. As such production is forecast to gradually
increase to almost 90 kb/d by 2021, although the downturn in the Brazilian economy may dampen
growth, as; of course, it might for all conventional and non-conventional products. Upside potential
is associated with an increase in the biodiesel blending mandate to 10% which could come into force
within the next three years, while the National Council of Energy Policy has already authorised the
sale and voluntary use of higher biodiesel blends of between 20-30% depending on their end use. 5
(Biofuels International, 2015).
In 2015, OECD-Europe biodiesel production of around 230 kb/d was steady versus 2014 levels.
France, Germany and the Netherlands remained the key producer countries. Over the medium-term
biodiesel demand is anticipated to rise slowly to around 260 kb/d in 2020 in accordance with the
need to satisfy the European Union’s (EU) target of a 10% share for renewable sources in the
transport fuels market in 2020. Prospects for higher levels of growth will be dampened however due
to stagnating EU diesel demand and the European Commission’s 7 percentage point (pp) limit on the
contribution of biofuels produced from starch-rich, sugar and oil crops towards the target that was
introduced in 2015.
2
January – November data (Brazilian Sugarcane Industry Association, 2015).
3
Federal taxes: Contribution for Intervention in Economic Domain (CIDE) and Contribution to the Social Integration Program (PIS) and
Contribution for Financing Social Security (COFINS), more favourable state level taxation developments for ethanol comparative to gasoline also
evident in certain states.
5
Brazil’s INDC outlines that the share of biofuels in the energy mix will be maximised through stimulating biofuel supply and consumption.
20% for captive fleets and public pumps and 30% for transport, agriculture and industrial users.
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4
S UPPLY
OECD-Europe ethanol production reached around 90 kb/d in 2015 and should continue to grow
modestly to around 120 kb/d over the medium-term. Higher growth is inhibited by declining gasoline
demand, a general lowering of production capacity in the EU and the introduction of the
aforementioned 7 pp limit for conventional biofuels within the EU transport target. Key producer
countries include France, Germany, Spain and the United Kingdom.
More favourable biofuels policies have been introduced in Spain, where the biofuels mandate will
progressively increase to 8.5% by 2020, while gradual tightening of the required emissions reduction
percentages within Germany’s Climate Protection Quota should stimulate additional biofuel demand
moving towards 2020. In France, the current favourable taxation policy for ethanol and growing fuel
supply infrastructure for E10 should result in a gradual increase in consumption; E85 fuel supply
infrastructure is also increasing, although from a low base.
Forecasting conventional biofuels production in the EU post-2020 becomes uncertain with the expiry
of the Renewable Energy Directive and Fuel Quality Directive targets of 10% renewable energy in
transport, and a 6% reduction in the greenhouse gas intensity of vehicle fuels. However,
conventional biofuels will play only a limited role in the EC’s policies for transport decarbonisation in
the period up to 2030, posing a downside risk to the EU market.
Several countries in non-OECD Asia should see continued growth in biofuels production over the
medium-term. In China, the world’s third largest fuel ethanol producer, production of 49 kb/d in
2015 is forecast to increase to around 60 kb/d by 2021, primarily as a result of increasing gasoline
demand. With no announced plans to increase blend rates beyond E10, any future ethanol
consumption growth in China beyond this level will depend on extending E10 standards to additional
provinces. Construction of new corn-based ethanol production is not currently permitted, but a large
corn inventory has led to proposals to construct further corn ethanol facilities which are under
consideration by the National Development and Reform Commission, representing upside potential
to the forecast. China increased fuel ethanol imports tenfold during 2015 and may continue to be a
promising export partner for ethanol producing countries during 2016 and beyond.
Ethanol production in India is anticipated to step-up significantly from 11 kb/d in 2015 to around
35 kb/d in 2021 as a result of new measures to strengthen the ethanol blending programme and
meet the 5% blending mandate. These include the introduction of a more attractive pricing
mechanism for ethanol procurement from sugar mills and excise duty exemption for fuel ethanol
used for gasoline blending. Capacity is already in place to expand fuel ethanol production and the
changes above may result in diversion from industrial to fuel ethanol production, improving
compliance with mandated blending levels. However, meeting the more ambitious 10% ethanol
blending target announced will require additional investment in production capacity and actions to
mitigate procedural barriers relating to inter-state permits, taxes and levies and constrained ethanol
storage capacity at refineries which may hamper growth.
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In Thailand ethanol industry production of 22 kb/d in 2015 is expected to continue to increase in
accordance with the Alternative Energy Development Plan by over one third to 36 kb/d by 2021,
characterised by an expanding share of E-20 and E-85 ethanol blends and an increase in the planted
sugarcane area. Market expansion has been achieved through a range of subsidies e.g. for ethanol
fuel distribution infrastructure, and tax incentives for flexible fuel vehicles.
S UPPLY
The most significant developments in global biodiesel production are anticipated in Indonesia.
Production dipped in 2015 to 29 kb/d due to an absence of financial support from delays in fully
implementing the B15 biodiesel programme. However, a range of policies to stimulate domestic
consumption, including the introduction of a plantation fund to utilise levies on crude palm oil
exports to fund subsidisation of domestic biodiesel consumption, can be expected to support an
increase in production in the region of 120 kb/d by 2021. Further increases to B20 and B30 blending
mandates proposed for the medium-term offer further upside potential if fully implemented.
In Malaysia the introduction of a B7 biodiesel mandate resulted in production of around 12 kb/d in
2015. An anticipated increase in the blending mandate to B10 alongside an upward trend in diesel
consumption should see production rise with anticipated growth to around 22 kb/d by 2021. Higher
production could be achieved by a move to B15 as outlined in the 11th Malaysia Plan that runs from
2015-2020.
Biodiesel production in Argentina dipped to 36 kb/d in 2015. Over the medium-term a rebound in
production to just over 50 kb/d can be anticipated. Export opportunities to the United States may be
promising with production from a number of plants eligible to qualify for Renewable Identification
Numbers under the RFS 2 programme.
Advanced biofuels
Advanced biofuels using non-food agricultural residue and waste feedstocks, such as cellulosicethanol and renewable diesel, have undergone a notable scale-up with seven new commercial-scale
plants using biomass wastes and agricultural residue feedstocks commissioned over 2014-15,
bringing the total number of facilities to ten. Key factors evident in delivering these initial projects
include access to a secure local feedstock supply; achieving value from co-products produced e.g. the
use of lignin for electricity and co-generation 6, and public sector financial support to assist with high
investment costs in some cases.
6
Co-generation refers to the combined production of heat and power.
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The ability of these plants to demonstrate the economic and technical feasibility of commercial-scale
production will shape future deployment prospects in the advanced biofuels industry. Demonstration
of successful operations will provide opportunities for technology licensing, standardisation of plant
and process design and reduce future investment risk. If delivered the visible project pipeline could
see 40-50 kb/d of advanced biofuel production annually by 2021. However, some of these recently
commissioned plants will need time to scale-up production to rated capacity. Reasons for this include
technical challenges, such as ensuring suitable pre-treatment of higher volume of feedstocks to
remove contaminants that compromise processes and fuel quality.
S UPPLY
Figure 2.33 Global examples of commercial-scale advanced biofuel plants
Cellulosic ethanol, which accounts for the majority of newly commissioned facilities, is still in the
early stages of development and therefore entails higher production costs. Recent industry cost
projections indicate a breakeven crude oil price for cellulosic ethanol to be competitive with gasoline
in the region of USD 100-130/bbl, although this may be lower when low and no-cost feedstocks are
available. As such, reducing production costs is a key challenge for the cellulosic ethanol industry in
the medium-term and beyond.
Significant potential in the sector to reduce both production and investment costs has been
identified however. This is associated with factors such as technological learning, obtaining additional
value from co-products, delivering higher yields and more favourable financing conditions for plants
not considered first of a kind. Achieving this potential will leave the industry in a more robust
position to compete in a low oil price environment and improve prospects for expansion.
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Strengthened policy support, including dedicated advanced biofuel quotas and financial de-risking
measures, is likely to be required to facilitate investment and accelerate a significant scale-up in
production, therefore enabling identified investment and production cost reduction potential.
Current examples include policies to establish defined reductions in the lifecycle carbon intensity of
transportation fuels, such as California’s Low Carbon Fuel Standard programme, and the advanced
biofuels quota within the RFS 2 in the United States, and due for introduction in Italy from 2018. In
addition, the residual 3 pp share within the 10% EU renewable energy in transport target which
cannot be met from conventional biofuels will also provide an opportunity for an enhanced
contribution from advanced biofuels.
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3. CRUDE TRADE
Summary
•
The global trade in crude oil is yet to peak and will climb steadily to hit 37 mb/d in 2017 as
consuming economies take advantage of low prices to build inventories while US imports are
set rebound as production there slows. Thereafter, traded volumes decline as refiners are
forecast to draw inventories and as US production rebounds.
•
Global crude trade will continue to be globalised but most of the growth over the forecast
is in medium-length trade flows. Long distance flows between the Atlantic and Pacific basins
will see minimal growth due to more pessimistic production estimates for the Americas.
•
As a direct consequence of OPEC’s decision to defend market share, the Middle East will
remain the main crude exporting region throughout the forecast. By 2021 it will account for
54% of inter-regional crude exports, a rise of 3% on 2015.
•
Despite the end-2015 lifting of the US crude export ban, no significant volumes of
US crudes are expected to reach markets outside the OECD Americas over the mediumterm due to the expectations that spreads between US crudes and comparable regional
benchmarks will not cover freight costs.
•
Global trade will continue its shift eastwards to non-OECD Asia. By 2021 the region will
import 16.8 mb/d, a rise of 2.8 mb/d on 2015. Non-OECD will surpass the OECD in terms of
its share of global imports in 2021, one year later than previously forecast, as the OECD’s
import requirement is now seen higher due to lower production prospects from within its
ranks.
Figure 3.2 Regional crude imports yearly change
2 000
2 000
1 500
1 500
1 000
1 000
kb/d
500
500
0
0
- 500
- 500
-1 000
-1 000
-1 500
Africa
2015 2016 2017
FSU Latin America
-1 500
2018 2019 2020 2021
2015 2016 2017 2018
Middle East OECD Europe OECD Americas OECD Asia Oceania Other Asia
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2019 2020
Other Europe
2021
China
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kb/d
Figure 3.1 Regional crude exports, yearly change
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Overview and methodology
The global trade in crude oil is yet to peak and is forecast to climb steadily to a record 37 mb/d in
2017 as the import requirement of the OECD Americas increases. Thereafter, crude trade is forecast
to decline slowly as stock draws reduce refiners’ need to import crude; as a number of refineries in
exporting countries are commissioned and as rebounding production sees OECD American imports
fall. Accordingly, by 2021 inter-regional crude trade is projected at 35.5 mb/d, 0.1 mb/d lower than in
2015.
Despite this forecast being similar to the 2015 MTOMR, where it was projected to ease by 0.3 mb/d
over 2014-20, both the beginning and end of the forecast have been raised by over 2 mb/d.
Accordingly, trade in 2020 is now seen at 36.0 mb/d, 2.2 mb/d higher than presented in last year’s
Report. The reasons for this are threefold: firstly, global oil demand has been revised upwards
following robust growth in 2015; secondly, expectations of supply in net exporting regions such as
the Middle East and FSU are now seen higher; and thirdly, projections of oil output in net-importing
regions are now seen lower, thereby increasing their import requirements.
Map 3.1 Crude exports in 2021 and growth in 2015-21 for key trade routes
(million barrels per day)
Global trade will continue its shift eastwards to non-OECD economies in Asia. By 2021 non-OECD Asia
will import 16.8 mb/d, a rise of 2.8 mb/d on 2015. China will account for more than half of this
growth as it commissions new refining capacity and fills its strategic reserves with a minimum of
500 mb by 2020. By 2021 China will import 8.5 mb/d, consolidating its position as the world’s largest
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Note source: Excludes intra-regional trade. Red number in brackets denotes growth in period 2015-21
* Includes Chile.
** Includes Israel. The statistical data for Israel are supplied by and under the responsibility of the relevant Israeli authorities. The use of
such data by the OECD and/or the IEA is without prejudice to the status of the Golan Heights, East Jerusalem and Israeli settlements in the
West Bank under the terms of international law.
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importing country and the non-OECD as a whole will import 18.3 mb/d of crude, 2.9 mb/d more than
in 2015, to account for 52% of global imports. Nonetheless, the non-OECD overtakes OECD in terms
of crude import volumes one year later than previously predicted and results from the increased netimport requirement of the OECD due to lower supply prospects.
Box 3.1 Stock changes to influence crude oil trade over the medium-term
Crude oil trade will be influenced to a large extent by changes in crude inventories over the mediumterm. In 2015-2017 volumes of crude traded will grow by more than demand as consuming nations build
crude inventories. Accordingly, over this period, global oil inventories are projected to rise by an average
1 mb/d as supply outstrips demand. This trend will then be reversed over the remainder of the period as
demand exceeds supply and inventories will draw by approximately 0.8 mb/d. As refiners draw their
feedstock inventories, this will decrease their requirement to import crude.
Global inventories have surged since supply began to outstrip demand in 2014. Trade in crude oil soared
by 1.4 mb/d in 2015 as inventories were built in consuming regions, including OECD Europe, China and
Other Asia, rather than closer to the wellhead. Further evidence comes from tanker tracking data
showing that shipments on Saudi Arabia’s Vela fleet rose markedly as production increased and was
imported by consuming countries which added these volumes to inventories. Considering that these
crude stocks are already located in net-importing regions, the expectation is that they will not be reexported before being processed by refiners. There is the possibility, however, that refiners in places
such as China, OECD Europe and the US could increase product exports as they draw crude inventories.
102
2.5
100
2.0
98
1.5
96
1.0
94
0.5
92
0.0
90
-0.5
88
-1.0
86
-1.5
84
-2.0
82
Implied Stock
Ch.&Misc to
Bal (RHS)
mb/d
mb/d
Figure 3.3 Global demand / supply balance
Oil Demand
Oil Supply
-2.5
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
In 2014-2017, global oil inventories are projected to rise by over 1.5 billion barrels. However, by 2021,
not all of these volumes will have been drawn down. By end-2016, approximately 200 mb of crude will
have been added to government-controlled strategic inventories, particularly in China and India and
these will only be drawn down in the event of a market disruption. Other volumes have been added to
newly-constructed commercial storage facilities, chiefly located in non-OECD as the region becomes the
centre of oil demand growth, and in the US as logistics adjust to rising LTO production.
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As a direct consequence of OPEC’s 2014 decision to defend market share rather than price, the
Middle East will strengthen its position as the world’s largest exporting region, underpinned by longterm supply contracts. By the end of the forecast, the region will have a 54% share of the global
export market, a rise of 3% on 2015. Nonetheless, Africa will remain the key swing exporter
considering its geographical position and that a large proportion of its exports, notably from Nigeria
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and Angola, are sold on the spot market. However, its exports are seen to decrease over the forecast
as supply growth is curbed while African crude demand will increase as new refinery projects are
commissioned. Accordingly, the region’s share of the export market is expected to slip to 15% in
2021 from 17% today. In contrast to last year’s Report, and following more upbeat expectations of
Russian supply, the FSU will retain its position as the world’s second largest exporter remaining
remarkably stable at between 6.7 mb/d and 6.9 mb/d throughout the medium-term which will see its
share of the export market remain steady at close to 20%.
The inter-regional trade in crude oil and marketed condensate has been modelled as a function of oil
production, demand growth and refinery supplies being allocated on the basis of refinery capacity
expansion. OPEC crude production has been modelled using a similar methodology to the 2015
MTOMR where OPEC will no longer fulfil its role as the ‘swing supplier’ and balance the market, but
will continue its recent policy to defend market share. Considering the recent steep changes in global
inventories and expectations for further significant changes across the medium-term, adjustments
have been made to the model to account for implied global stock changes. Historical trade data are
benchmarked against official trade data for OECD countries (published in the IEA Monthly Oil Data
Service), customs information for large non-OECD consumers and producers and tanker tracking
information.
Selected regional developments
The Middle East to remain the world’s largest exporter
Exports from the Middle East are expected to increase by 1.1 mb/d to 19.2 mb/d in 2021 as
production from low-cost OPEC producers remains strong over the forecast. Accordingly, by 2021 the
region is expected to account for 54% of the export market, a rise of 3% on 2015. This increase is a
direct result of the Saudi-led OPEC policy to defend market share. Nonetheless, the largest source of
incremental export growth is Iran which, following the early-2016 easing of international sanctions, is
projected to supply nearly 1 mb/d more to the market in 2021 than in 2015. The bulk of the increase
will come in 2016 when 0.6 mb/d is projected to reach Mediterranean and Asian markets by midyear. Otherwise, smaller capacity increases are expected to come from Iraq, Kuwait and the United
Arab Emirates. Over the forecast a number of refinery projects will be commissioned in the region,
these include Saudi Arabia’s Jizan plant, Kuwait’s Clean Fuels Project and Oman’s Duqm refinery.
As the Middle East increases its exports, its customer base will change. Attention will focus more on
the developing world, especially in Asia. Other Asia will retain its position as the Middle East’s main
customer and by 2021 will import 6.1 mb/d of crude from the region, accounting for 32% of the
region’s exports, 3 percentage points higher than in 2015. China will also remain an important
market, buying 4.7 mb/d in 2021, 1.1 mb/d higher than current levels. Moreover, this represents the
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There will also be a change in how the region exports its crudes over the medium-term. The United
Arab Emirates and Oman are exploiting their strategic location outside of the Strait of Hormuz by
developing terminals to which Middle Eastern producers can ship crude to be stored before being
sent to customers. In 2014, the UAE commissioned the 1.5 mb/d Abu Dhabi Crude Oil Pipeline to
bypass the Strait and has since expanded storage at the line’s endpoint at Fujairah. Meanwhile, in
Oman, the Ras Markaz storage hub is under construction and due to be opened in 2017. When
complete, this facility will have around 200 mb of tank space making it one of the world’s largest
hubs.
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highest absolute growth across all inter-regional trade flows. In contrast, OECD Asia Oceania will
decrease its imports in line with refinery rationalisation across the region and amid efforts from
governments to diversify the imports away from the Middle East. Accordingly, in 2021 the region will
import 4.0 mb/d from the Middle East, 1.0 mb/d lower than in 2015, the steepest contraction across
all trade flows. The Middle East will retain its customer base in OECD Europe with the region set to
import remain at 2.4 mb/d across the medium term, underpinned by the return of Iranian crude to
the Mediterranean and recent supply contracts between Middle Eastern producers and central
European refiners.
Figure 3.4 Middle East export growth, 2015-21
Figure 3.5 FSU export growth, 2015-21
China
China
Oth Asia
Oth Asia
OECD Eur
Oth Eur
Africa
L. America
L. America
Mid East
Oth Eur
OECD Am
FSU
Africa
OECD Am
OECD AO
OECD AO
OECD Eur
-1.00
-0.50
0.00
mb/d
0.50
1.00
1.50
-0.40
-0.20
0.00
mb/d
0.20
0.40
FSU to continue its pivot eastwards
Crude exports from the FSU will remain remarkably stable throughout the forecast period, oscillating
between 6.7 mb/d and 6.9 mb/d with a larger proportion of volumes heading to Pacific Rim
economies. However, this masks the contrasting fortunes between the region’s main producers.
Russian crude exports hit record highs in 2015 as the weak rouble insulated the oil industry from the
effects of plunging dollar crude prices. However, exports are not going to be sustained at these levels
over the medium-term partly due to the impact of international sanctions. Russia is expected to see
production slow by 275 kb/d as decline rates at mature fields accelerate and new projects are
delayed as capex is cut.
Over the medium term, the region will continue to pivot eastwards supported by the expansion of
infrastructure. At the forefront of this will be Russia which has designs for its East Siberia–Pacific
Ocean (ESPO) crude grade to replace Dubai as an Asian benchmark, with the latter grade suffering
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In contrast, Kazakhstan’s oil output is projected to rise by 160 kb/d over the forecast. The Caspian
Pipeline Consortium (CPC) pipeline is expected to ship the vast majority of exports over the next few
years. Although the line’s capacity will nearly double to 67 million tonnes per year (1.3 mb/d) flows
will not reach capacity until later in the forecast once production from the super-giant Kashagan field
resumes and as Tengiz Phase 3 is commissioned. Meanwhile, flows through the Baku–Tbilisi–Ceyhan
(BTC) pipeline could well be lower in years to come, considering that 140 kb/d less crude is expected
to be shipped from Azerbaijan in 2021 than currently as output declines at the Azeri-ChiragDeepwater Gunashli (ACG) complex.
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from reduced liquidity in recent years. For Russia to achieve this, the capacity of the ESPO pipeline
will be expanded for a second time to 1.6 mb/d by 2020 with 1 mb/d heading to the Kozmino
terminal – the end of the pipeline – while 0.6 mb/d will be shipped to China via an enlarged Daqing
Spur. ESPO blend has a specific gravity of 34.7o and sulphur content of 0.5% which is lighter and
sweeter than Urals which saw it quickly gain market share in Pacific basin markets. ESPO is sold at a
premium to Urals and this has incentivised producers to send more lighter, sweeter western Siberian
oil eastwards, which in turn has seen the quality of Urals deteriorate. As Russia struggles to stem
decline rates at mature fields in western Siberia over the coming years, it can be expected that this
trend will continue.
The FSU is expected to export a combined 2.5 mb/d to Asian markets in 2021. China will take a large
proportion of this oil and is seen increasing its imports from the FSU by 0.3 mb/d to 1.2 mb/d in
2021. Indeed, in 2014 China became the largest buyer of Russian crude, surpassing Germany. The
backbone of the relationship between the two countries is the long-term supply deal between
Rosneft and CNPC to supply 0.6 mb/d of crude via the ESPO pipeline and by using crude swaps with
Kazakhstan. Rosneft is also a partner with CNPC in a refinery project at Tianjin, it has reportedly
agreed to supply around 180 kb/d of crude to the plant while it has signed other supply agreements
with Sinopec (200 kb/d) and ChemChina (50 kb/d). Elsewhere, Rosneft has agreed to ship 120 kb/d of
ESPO crude to the Dung Quat refinery in Viet Nam and has signed a deal to supply 200 kb/d of crude
to Essar’s Vadinar refinery over 10 years. All told, Other Asia is seen to import 0.8 mb/d in 2021, a
rise of 0.3 mb/d on 2015. Regardless of more oil heading to Asia, exports to mature markets in OECD
Asia Oceania are set to decline by 0.2 mb/d over the forecast as refinery capacity there is expected to
fall. Considering the volumes due to be supplied in long-term deal outlined above, the liquidity of the
ESPO spot market, delivered at Kozmino, is expected to be reduced which could hamper Russia’s
long-term aim of the grade becoming an Asian benchmark.
Despite the shift eastwards, Europe will remain the FSU’s main market in 2021 accounting for
3.9 mb/d, approximately 57% of the total FSU exports but 0.3 mb/d lower than 2015. Although
Russia will continue to divert oil eastwards, European refiners will require less FSU crudes in 2021 as
throughputs are expected to fall in line with refinery rationalisation. There is not expected to be an
uptick in exports through the Druzhba pipeline as many central European refiners continue their
recent policy of diversifying supply sources. This has seen refineries in both Poland and Hungary
import extra volumes from the Middle East. Russia will continue to push as much crude as possible
through the Northern ports of Primorsk and Ust Luga while an uptick in Russian exports via
Novorossiysk is not expected considering increased competition from higher Middle Eastern exports
and the extra volumes of crude which are expected to reach Mediterranean markets from
Kazakhstan.
OECD Americas to remain a net importer
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Even as crude production in the region increases by 1.9 mb/d by 2021, the OECD Americas is
projected to remain a net importer throughout the medium term. Nonetheless, its net import
requirement is projected to drop to 2.9 mb/d from the current 3.5 mb/d. This is larger than
presented in last year’s Report and results from slower production growth as producers across the
region struggle with an extended period of low oil prices.
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Even though the Obama Administration in December 2015 lifted the decades-old ban on the export
of US crude oil, shipments outside the region will only inch up by 0.1 mb/d. Mexico’s oil exports will
decline in tandem with falling production. Only Canada is expected to see a notable uptick in
shipments as producers increasingly target Asian markets. However, these Canadian volumes are not
dependent on the construction of either Kinder Morgan’s 525 kb/d Northern Gateway or
TransCanada’s 890 kb/d Trans-Mountain Express pipelines to evacuate Albertan heavy oil eastwards.
Rather, crude will follow existing routes to Asian markets where small volumes have already reached
OECD Asia Oceania, China and Other Asia.
Box 3.2 US exports to remain low
Despite the recent lifting of the US crude oil export ban, projections of regional exports are lower than
those presented in last year’s Report due to a more pessimistic regional production profile and the
prevailing assumption that the large scale export of US crude will remain uneconomic.
For large-scale exports to be viable US crudes must be priced at a discount to competing grades
sufficient to cover the cost of moving it to market. For example, for a transatlantic cargo heading to
Europe, Louisiana Light Sweet (LLS) must be about USD 2.60/bbl cheaper than Brent but since the lifting
of the export ban the price of LLS has actually moved to a small premium (USD 0.20/bbl) over Brent. This
makes exports uneconomic. Moreover, up until the post-2008 surge in LTO production, US benchmark
WTI historically was valued at a premium to Brent due to its lower sulphur content and higher light and
middle distillate yields. According to shipping data, to mid-February only one US crude cargo has moved
outside North America (US producers have long been permitted to export crude to Canada under
license), and considering the underlying economics, this was largely symbolic.
The lifting of the ban represents a safety valve for the US supply chain. Considering the need for
US crudes to be sold at significant discounts to other global benchmarks, the main driver which could
lead to an increase in export is storage capacity coming under pressure but at the end of 2015 there was
approximately 100 mb of spare capacity remaining in the US. Over the medium-term, US inventories are
unlikely to reach capacity considering that domestic crude production growth is expected to slow while
refiners will likely continue to operate at high utilisation rates and export significant volumes of
products. Nonetheless, short-term imbalances in the US supply chain, especially on the Gulf Coast, could
see the price of domestic crudes weaken in comparison to benchmark grades.
A similar situation has played out over the past year concerning US condensate exports. In late-2014 it
was announced that US condensate could be exported without license provided it was first processed
through a distillation tower. Despite initial predictions that a flood of US condensate would arrive on
international markets, so far the reality has been very different. The economics have so far not
supported large volumes of shipments with international markets currently saturated by competing
volumes from the Middle East, Russia and Australia. According to IEA data, only about 25 kb/d of
condensate has been exported to OECD Asia Oceania, significantly lower than expected while Europe
has imported two cargoes with no exports to the non-OECD.
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Nonetheless, the necessary infrastructure remains in place to export crude oil. There are a multitude of
exit points along the Gulf Coast including Houston, Corpus Christi, and Brownsville. Meanwhile, there
have been discussions about reconfiguring the Louisiana Offshore Oil Port (LOOP) to be able to export
crude as well as import it.
C RUDE T RADE
Box 3.2 US exports to remain low (continued)
There is a strong possibility that the US could export light, sweet oil to elsewhere in the OECD Americas.
It currently exports about 450 kb/d to Canadian refineries, while in future it could export similar oil to
Mexico. The US remains net short of heavy crude and it has long been mooted that it could engage in
swap deals with Mexico and receives crudes such as Maya in return. Considering the short shipping
distances across the US Gulf, these economics would be easier to support than transatlantic shipments.
Considering the above, US exports to destinations outside the OECD Americas are now seen at about
100 kb/d in 2021. Condensate exports to OECD Asia Oceania are now projected to double to 50 kb/d in
2021 but remain significantly below levels projected in last year’s Report. Other Asia is projected to take
about 20 kb/d of condensate with a similar amount heading to OECD Europe. Additionally, exports to
Latin America will also increase slowly as producers, notably Venezuela, require light oil to blend with
heavier grades. The shorter shipping times may make the trade viable and volumes shipped would likely
back out African imports.
Looking forward, the bulk of the region’s imports will be heavy crude from Latin America since OECD
American refiners are projected to remain net-short of heavy crude over the forecast. A significant
increase in volumes of Canadian crude imported by the US is not foreseen due to the lack of new
pipeline projects due to be completed over the medium term. Therefore, the region will import
1.8 mb/d of Latin American oil in 2021, a drop of 0.2 mb/d on 2015. A similar picture will prevail for
Middle Eastern imports which will drop by 0.1 mb/d to 1.4 mb/d in 2021. Despite the longer shipping
times from the Middle East, long-established relations between US refiners and Middle Eastern
producers will see grades from the region play an important role in US refining, particularly on the
Gulf Coast.
As increased volumes of heavy oil from Alberta oil move east to refiners in the Montreal region,
Canadian imports are set to fall. These will likely be long-haul heavy oil from the Middle East while
some West African oil could also be backed out. Nonetheless, there will still be room for West African
oil in the region. US domestic crude oil prices have recently improved in relation to Brent with WTI
trading close to parity. When the cost of transporting US crude by train to refineries in the
Atlantic Coast region is taken into account – typically the cost is around USD 12/bbl – it is
unsurprising that there has been an uptick in West African arrivals into PADD 1 and this is likely to
continue into the future. Consequently, the OECD Americas are expected to import 0.3 mb/d of West
African crude in 2021, 0.1 mb/d less than in 2015.
It is also noteworthy that in late-2015, the US government announced plans to sell off nearly 60 mb
from the Strategic Petroleum Reserve, which contains 695 mb of mainly light, sweet crude. The sale
will take place in 2018–2025 which equates to a draw down rate of about 20 kb/d. Although this
crude is of similar quality to that imported from West Africa, the slow drawdown is not expected to
materially affect import volumes in the final years of the forecast.
Latin America will see its exports fall by close to 0.5 mb/d over the medium term as producers
struggle with an extended period of low crude prices and as domestic refining projects increase
regional demand for crude. As the import requirement of the OECD America’s remains higher than
previously presented, exports to the region, particularly from Venezuela, will remain relatively
constant and slip by a minor 0.2 mb/d. Exports to Asia will remain at 1.2 mb/d across the forecast as
complex refiners in India and China continue to import significant volumes of heavy crudes from
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Domestic refinery expansion to curb Latin American exports
C RUDE T RADE
Venezuela, the latter underpinned by existing oil for loans deals. These flows will be underpinned by
the expansion of the Panama Canal, currently due for completion in mid-2016. This will allow the
passage of 1 mb Suezmax vessels. As exports from Latin America fall, OECD Europe will decrease its
imports from the region with competition being felt from other regions, notably the FSU and the
Middle East.
African crude exports to be squeezed and marketing problems to continue
Africa is expected to see a significant 0.6 mb/d drop in its exports over the forecast, the steepest
absolute decline by a major crude exporting region. This will stem from two factors; lower
production prospects and increasing regional refinery activity. Regional crude production is set to
decline by 0.4 mb/d over the forecast with the low oil price environment seen curbing production
prospects in Nigeria, Algeria and Angola. In non-OPEC producers such as Sudan, South Sudan and
Chad, production prospects have also been dimmed. We have assumed a modest recovery in
production in Libya but, clearly, this is highly speculative. Towards the end of the outlook, the
ambitious Dangote refinery project in Nigeria is expected to start-up. However, crude runs are only
expected to reach 300 kb/d in 2021 with the full 500 kb/d nameplate capacity not reached until after
the period of this forecast. Dangote will process Nigerian crude and thus reduce the volumes
available for export.
West African producers are expected to have problems marketing their crudes over the next couple
of years. At the start of 2007 combined shipments from Angola and Nigeria to the United States
exceeded 2 mb/d but recently this figure has slumped at times to only 200 kb/d due to the relentless
rise of US LTO production. A large proportion of West African crude is sold on the spot market and
from time to time loading programmes are not fully sold leading to excess barrels being stored on
tankers. Considering that low prices, oversupply and high stocks are projected to prevail until at least
early-2017, this situation could recur and West African producers may be forced to cut prices to sell
barrels. The fact that leading African producers sell large volumes into the spot market means that
they have become swing producers. However, they have the geographical flexibility to sell oil east or
west as demand requires. Customers for African crude will remain relatively similar over the forecast.
When and if Libyan production rises, incremental volumes are expected to be shipped to traditional
European markets likely backing out similar light, sweet crudes from West Africa.
In all, imports of African crude to OECD Europe are set to decline by 0.5 mb/d but it will still remain
Africa’s largest market, accounting for 2.2 mb/d in 2021. By 2021, Chinese imports of African crudes
are set to inch up by 0.2 mb/d to about 1.5 mb/d with the bulk of these coming from Angola.
Meanwhile, Other Asia will also maintain its imports at current levels of about 1 mb/d across the
forecast.
Non-OECD Asian imports to surge in line with demand growth
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As the centre for oil demand growth shifts further eastwards over the forecast, non-OECD Asia will
increase its imports by a significant 2.8 mb/d. China will account for the majority of this growth,
importing 1.7 mb more in 2021 as its imports hit 8.5 mb/d. This means that it will consolidate its
position as the world’s largest importing country with additional upward momentum coming as
China fills its crude strategic petroleum reserve with a minimum 500 mb by 2020. Despite China’s
recent efforts to diversify its crude imports, by 2021, in percentage terms, the slate of refiners there
will look remarkably similar to what it did in 2015. Notably, Middle Eastern imports will account for
C RUDE T RADE
55% of total imports in 2021, compared to 53% in 2015. The projected role of Middle Eastern
imports is also a reflection on the complexity of the refineries which will be commissioned over the
forecast, which are expected to run predominantly on sour crudes. Chinese imports of Latin
American crudes are expected to remain at about 800 kb/d across the forecast, underpinned by
flows from Venezuela under the existing oil for loans deals. Nonetheless, considering growth
elsewhere, Latin American grades will only account for 9% of Chinese imports, 3% lower than
currently.
Figure 3.6 Chinese crude imports, 2015
Africa
FSU
Figure 3.7 Chinese crude imports, 2021
Latin America
Middle East
Others
As Other Asia expands refinery capacity, with new projects due to be commissioned in India,
Viet Nam and Malaysia, imports will surge by 1.1 mb/d with the region set to import extra supplies
from the FSU (+0.3 mb/d) and Africa (+0.1 mb/d), the former underpinned by long-term supply deals.
Imports from the Middle East, however, are set to soar by 0.9 mb/d. One reason for this has been
the swift loss of the Asian premium which until 2015 saw Asian refiners competing for supplies
having to pay more than their counterparts in the Atlantic Basin. Following OPEC’s decision to defend
market share official selling prices have been aggressively cut for all regions, with Middle Eastern
producers unable to command the traditional Asian premium in the face of tough competition from
suppliers.
OECD Europe to cut back imports in line with refinery rationalisation
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Shipments to OECD Europe are set to be cut by 1.0 mb/d to 8.8 mb/d in 2021 as another tranche of
European refinery capacity is shuttered over the forecast. The decline will take place even though
North Sea supplies will be falling. The region is expected to remain reliant on crude from the FSU,
principally medium-sour Russian Urals delivered via the Druzhba pipeline and Baltic ports. However,
Europe will diversify its crude slate with Middle Eastern crudes set to increase their market share to
27% from 24%. Poland and Hungary have signed supply contracts with producers such as Iraq,
Saudi Arabia and Iran. Moreover, in 2016 Iranian imports to the region are expected to increase as
Greece, France, Italy and Turkey hike their purchases following the easing of international sanctions.
This is expected to be at the expense of competing grades from the Middle East and the FSU. Despite
declining production in the North Sea, the region is still expected to export crude outside Europe
with sporadic shipments heading to North America and Asia although the volumes will fall from
nearly 200 kb/d in 2015 to only 50 kb/d in 2021.
C RUDE T RADE
Box 3.3 Renewed earnings brighten shippers prospects
Low crude prices have been a boon for vessel owners. On one hand, increased exports have supported
freight rates, which ended 2015 on an exceptional note. On the other hand, the price of bunker fuel, the
principal operational cost component, has collapsed in tandem with benchmark crudes to as low as
USD 104 /tonne. The combination of these factors boosted earnings to highs unseen since 2008, IEA
calculations show, providing a stimulus for owners to invest in new tonnage.
Figure 3.8 Earnings on benchmark routes
140
120
Source: IEA calculations, SSY, Argusmedia
160
140
120
100
80
60
40
20
0
Source: IHS Maritime
mln DWT
'000 USD/day
100
Figure 3.9 Order book
80
60
40
20
0
2007
2009
VLCC MEG - Asia
2011
2013
Suezmax WAF - UK
2015
LR1 MEG - Japan
2005
2007
ULCC
Aframax/LR2
Total %
2009
2011
2013
VLCC
Panamax/LR1
50%
45%
40%
35%
30%
25%
20%
15%
10%
5%
0%
2015
Suezmax
MR/Handy
Crude carriers in particular got a much-needed shot in the arm. Vessel owners, particular for the
Suezmax vessels and larger Very Large Crude Carriers, were left with a big tonnage hangover partially
arising from lower shipments to the US as domestic production increased. Longer term perspectives for
the crude trade looked grim as of the 2015 edition of the Report, particularly as traded crude volumes
were set to shrink on growing refining capacity in Asia and in the Middle East. The outlook has partially
changed as the crude oil price collapse has hit North American production and increased the region’s
import requirement in the first part of the forecast by 0.5 mb/d by end-2017. In the second half of the
forecast, crude trade is projected to resume previous trends and inch down, remaining about flat over
the whole forecast period, giving way to increased product trade.
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A further stimulus to vessel earnings could come from the resurgence of floating storage. With current
demand and supply balances projecting stocks to continue building over 2016, this increases the
likelihood of logistical bottlenecks at key terminals or inventory levels testing storage capacity limits.
When oil prices were weak following the 2008 collapse, the following year or so saw 132 vessels
chartered for storage, mainly as speculative plays betting on rising prices. For this to be repeated we
need a steepening of the forward price curves to make the activity profitable, but if oil supply and
demand fundamentals weaken further this could happen leading to a significant number of storage
charters. This would, in turn, tighten vessel market fundamentals and lead to a firming of rates.
C RUDE T RADE
Box 3.3 Renewed earnings brighten shippers prospects (continued)
Even without a floating storage take-off, the crude fleet responded to higher earnings, and by early 2015
began growing again across vessel classes, initially supported by falling scrappage rates. Then, by early
2016, on ever-growing earnings, the vessel order book reached its highest level since 2011, standing at
16% of the total fleet. The 1-mn-bbl Suezmax class is leading the way, with its order book standing at
20% of current tonnage, supported also by the Panama Canal expansion. The overall dire financial state
of many shipyards, suffering from a depressed dry bulk market, keeps newbuild prices in check, further
incentivizing new orders.
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In contrast to crude carriers, the outlook for product tankers was already in better shape, as global
product trade is set to increase as refining capacity moves closer to the wellhead in the Middle East,
Africa and Asia, setting the stage for longer haul product trade to demand centres in Asia and Europe.
Consequently, larger tanker classes (Aframaxes/LR2 and Panamaxes/LR2) are set to grow the most, with
the current order book at around 18% of the current fleet, a stunning increase compared with only 10%
a year ago. In a shipping industry facing an uncertain future, the move towards product trade appears to
be the only relatively stable trend.
R EFININ G
4. REFINING
Summary
• Global crude distillation (CDU) capacity is expected to increase by 7.7 mb/d from 2016 to 2021,
to 105 mb/d. Reflecting demand side developments, non-OECD regions, essentially China and the
Middle East, account for over 90% of these additions. North America is the only region in the
OECD where capacity grows, with new units designed to handle local condensate or light tight oil.
• The continued decline in oil prices has affected cash flows of the oil companies and thus raised
the likelihood of delays for many projects. Annual capacity additions average 1.3 mb/d through
2021, despite some 1.7 mb/d of projects deferred beyond the forecast range of this report.
• Excess refining capacity is expected to rise by over 1 mb/d to 5.3 mb/d in 2021, after a
temporary dip in 2016. Most of the spare capacity is, counter-intuitively, not in the OECD, where
rationalisation has been going on for some few years. Nearly two-thirds of global spare capacity is
now found in non-OECD countries, where refineries are under-utilised for various reasons,
ranging from war and conflict to poor state of equipment making profitable operations
impossible.
• Margins – especially hydroskimming – found support in 2015 from soaring gasoline-driven
demand. Hydroskimming margins were at their highest since 2006, as crude oil prices plummeted
to 2003 levels. This helped push refinery runs a whopping 2.0 mb/d above the previous year. Not
only were capacity additions below the impressive 1.6 mb/d demand growth in 2015, but there
was also a mismatch in product supply and demand as the latter was mostly about strong gasoline
consumption, while new refineries coming online were set up for higher diesel yields. While in
recent months margins have drifted lower, the expected dip in 2016 spare capacity may become
the next supportive factor.
• Global trade in oil products continues to outpace crude oil. Net exports of oil products from the
United States almost double by the end of the decade, while the Middle East comes second in
terms of rate of growth. The Russian ‘tax manoeuvre’, which aims to lower refinery runs and free
crude oil for exports, works, with product exports decreasing. India’s position as a major net
product exporter is almost completely eroded. China returns to being a net product importer as
the refinery capacity glut is offset by rising demand.
Overview
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What is good for the upstream usually is not good for the downstream, and the opposite is usually
true. When high oil prices boost the bottom lines of the oil majors, refining’s contribution looks far
from stellar. Since the start of the oil price slide in 2014 though, refiners have boosted their
profitability by not fully passing on the gains from lower crude prices to the consumers. Even simple
refining margins worldwide were mostly in positive territory in 2015, which was an important factor
in pushing refinery runs up by 2 mb/d compared with 2014. The increase in runs was more than the
demand growth at 1.6 mb/d and more than the net capacity growth of 1.3 mb/d. This means that
refineries on average achieved higher capacity utilisation rates.
R EFININ G
In contrast to much of the previous decade, margins in 2015 were essentially supported by light
distillates – gasoline and naphtha, a role that was previously taken up by diesel. This resulted from
higher diesel supply as the new capacity coming online, especially in the Middle East, was aimed at
the traditionally strong European diesel import market, while gasoline was the product that showed
higher demand growth thanks to lower prices in the US, and also increased vehicle ownership in
China and India. In addition, high octane components for gasoline blending were in short supply,
which reinforced the gasoline crack. This was most likely a result of refineries utilising their less
sophisticated marginal capacity, but also because, in the case of the US, the increasing use of LTO
and Canadian diluted bitumen in refinery feedstocks resulted in output of low octane components.
While the high refinery margins provided a welcome respite from the endless sector pessimism,
especially in Europe, the big question for the coming years is how long this period of margin
renaissance will last (See Box 4.1 Refining margins – where from here?).
Refining sector outlook
In principle, current installed refining capacity of 97 mb/d is sufficient to cover the world demand in
refined products well beyond our forecast date as the 2021 demand for refined products will only
reach 87.4 mb/d. Almost one-sixth of global oil demand is met by fuels by-passing the refining sector,
which exacerbates the excess capacity issue. Biofuels, coal-to-liquids and gas-to-liquids products,
additives, direct burning of crude oil mainly in power generation, and, most importantly, liquefied
petroleum gases, naphtha and ethane coming from natural gas fractionation plants “eat up” the
refiners’ market share, which is set to marginally decline between now and 2021.
Table 4.1 Total demand and call on refineries
Total liquids demand
of which biofuels
Total oil demand net of biofuels
2015
2016
2017
2018
2019
2020
2021
94.4
95.6
96.9
98.2
99.4
100.4
101.5
2.3
2.4
2.5
2.5
2.6
2.7
2.7
92.1
93.2
94.4
95.6
96.8
97.7
98.8
of which CTL/GTL and additives
0.8
0.8
0.8
0.8
0.8
0.9
0.9
direct use of crude oil
0.9
0.9
0.8
0.8
0.8
0.8
0.8
Total oil product demand
90.5
91.6
92.8
94.0
95.1
96.1
97.2
of which fractionation products
Refinery products demand
Refinery market share
9.0
9.2
9.4
9.6
9.7
9.7
9.8
81.5
82.4
83.4
84.4
85.5
86.4
87.4
86.3%
86.1%
86.1%
86.0%
86.0%
86.0%
86.1%
Still, the industry is likely to add nearly 8 mb/d of capacity to 2021. This is partly to address the
geographic mismatch between the available capacity and growing demand, and partly to satisfy
some crude oil exporters’ ambitions to also become product exporters. Globally, capacity additions
for 2016 are limited to 0.5 mb/d, less than half of projected demand growth, but the pace will pick up
afterwards to average 1.5 mb/d over the next five years, exceeding average demand growth. One
uncertainty concerning the forecast is to what extent these projects will be delayed due to capital
constraints as oil companies deal with lower oil prices.
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The regional split of capacity additions remains similar to many previous editions of this Report.
More than 90% of the capacity will be built in non-OECD, primarily in Asia and in turn mainly in China,
R EFININ G
and also in the Middle East. In China, an apparent desire to better control refinery plans will likely
cap expansions, while the rest of Asia struggles to secure financing for new projects. Latin America
and the FSU add only limited primary distillation capacity, with the latter focused on secondary
investments. In the OECD countries, Europe and Asia Oceania are still more about shutdowns than
capacity additions, although the pace is slowing compared with the 2010-2015 period. The Americas
continue to invest in the processing of the light streams generated by rising LTO production, adding
0.8 mb/d of distillation capacity over the period, the majority in condensate splitters.
Table 4.2 Global refining capacity and runs
2015
2016
2017
2018
2019
2020
2021
Total capacity
97.2
97.7
99.0
100.3
101.8
103.6
104.9
Refinery runs
79.9
80.7
81.3
82.0
82.7
83.4
85.4
Estimated spare capacity
4.2
3.7
4.0
4.0
4.4
5.1
5.3
While CDU capacity expands by almost 8 mb/d through 2021, refinery runs are forecast to increase
by only 5.6 mb/d. More than 1 mb/d of demand growth will be met by growing biofuels, CTL/GTL and
higher output of NGL fractionation products. Thus, the spare capacity (which we estimate based on
an assumed 86% utilisation rate), first dips in 2016 due to relatively low capacity additions, but rises
thereafter to eventually stand 1.1 mb/d higher in 2021 than in 2015. Upgrading and desulphurisation
capacity will each add 4.0 mb/d over 2016-21, and it is worth noting the high level of upgrading to be
added in the short term, not to mention the impressive 1.5 mb/d added in 2015 (See Table 4 in
Section 5)
Figure 4.1 Changes in regional demand and refining capacity
3.0
Demand
2.5
Capacity
mb/d
2.0
1.5
1.0
0.5
0.0
-0.5
-1.0
OECD Americas OECD Europe
OECD Asia
Oceania
FSU
China
Other Asia
Non-OECD
Americas
Middle East
Africa
Regional developments
OECD
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The OECD’s refining capacity in total is scheduled to grow by 0.4 mb/d, after a 2.6 mb/d shutdown
over 2009-2015. This is a combination of North America adding LTO processing capacity, Europe with
no net change in its capacity, and Asia Oceania shutting down another 0.3 mb/d of capacity (taking
into account only announced shutdown plans). If refining margins fall again, Europe will be the most
vulnerable to capacity shut downs, as Asia Oceania will have already completed a large adjustment.
R EFININ G
The Americas marginally adapt to lighter feedstocks
The Americas are expected to add 0.8 mb/d of new capacity over the next five years, nearly all of it
in the US. However, the major oil companies seem to be reducing their US presence: Exxon is selling
its Chalmette, LA and Torrance, CA refineries to PBF Energy, and Total is looking to sell half of its Port
Arthur, TX facility. But there are a few small expansions, mostly CDU capacity to accommodate a
growing diet of LTO. Eleven projects totalling 440 kb/d will come online over 2016-2021. Condensate
splitters too are proving a popular asset to cash in on growing supply with six units adding a
combined capacity of 370 kb/d planned in Texas oil export terminals. This continues the trend of the
last couple of years when four condensate splitters were completed (210 kb/d), together with five
small CDU expansions (150 kb/d). The shuttered 500 kb/d Hovensa refinery in the Virgin Islands, a
joint venture between Hess Corporation and Venezuela’s state Petroleos de Venezuela S.A., was
bought to be turned into a storage facility.
North West Resources’ 50 kb/d Sturgeon refinery is the only project in Canada where work has
started, although the launch could be delayed to 2018. Mexico, which is arguably the most in need in
this region to increase its domestic supply of products, has no major expansion planned apart from a
minor project at Pemex’s Tula Hidalgo refinery but there was an announcement in December 2015 of
a USD 23 billion plan for secondary unit investments in all six Mexican refineries.
Table 4.3 Regional developments in capacity and runs
Total capacity
Runs
2015
2021
Change
2015
2021
North America
21.9
22.6
0.8
18.9
Europe
16.0
15.9
0.0
13.6
FSU
7.7
7.9
0.2
China
13.2
15.3
Other Asia
20.1
Middle East
9.3
Latin America
Utilisation rates
Change
2015
2021
19.5
0.5
87%
86%
13.1
-0.4
85%
83%
6.2
6.2
0.0
82%
78%
2.2
11.0
12.7
1.7
83%
83%
21.0
0.9
16.4
17.1
0.7
82%
82%
11.6
2.3
6.9
9.2
2.3
74%
79%
5.9
6.5
0.6
4.7
5.1
0.4
80%
79%
Africa
3.3
4.1
0.8
2.1
2.6
0.5
65%
64%
World
97.2
104.9
7.7
79.9
85.4
5.6
82%
81%
Note source Regional groupings in this table are geographical, with no reference to OECD affiliation.
Asia Pacific: consolidation in still on the books
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For Asia Pacific, consolidation is the key word, and it takes two forms: shutdown of capacity and
mergers. The only addition in the region is a 140 kb/d condensate splitter in South Korea’s Hyundai
Daesan refinery, scheduled for 2017. In Australia, 2015 saw the shutdown of BP’s 100 kb/d Bulwer
Island refinery. In Japan, Petrobras turned its 100 kb/d Okinawa refinery into an import terminal,
after failing to find a buyer. The Phase II ordinance of the Ministry of Economy, Trade and Industry,
requiring a higher refinery upgrading ratio (secondary units compared with primary distillation), will
result in more shutdowns. At the same time, two mergers are expected to take place: Idemitsu
Kosan, Japan’s number two refiner, announced in November 2015 a merger with Showa Shell. And,
more recently, JX Holdings and Tonen General Sekiyu, first and third in terms of capacity, also
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announced a merger which would control half of the domestic market. If these succeed, there will be
only three large refiners left in Japan. In addition, there are local refinery mergers, such as the linking
of the refineries of Tonen General and Cosmo Oil in Chiba. Altogether, refining companies have
announced more than 400 kb/d of capacity reductions by early 2017: Cosmo Oil would cut 100kb/d
in Chiba and 63 kb/d in Yokkaichi, while JX would reduce by 121 kb/d, Idemitsu Kosan/Showa Shell by
54 kb/d and Tonen General by 72 kb/d.
Europe enjoys margins while they last
2015 was a remarkable year for European refiners, with strong cracking and hydroskimming margins
at levels that were last seen a decade ago. European refiners ran at full speed, with crude runs
reaching 12.1 mb/d, 0.65 mb/d above the 2014 level. It is hardly surprising that no new plant
shutdown was announced beyond those planned earlier: in Switzerland, Tamoil’s 57 kb/d plant
closed in 2015, and, in 2016, Total will shut down its La Mède, France plant and reduce capacity at its
Lindsay site in the UK. There was no announcement of new upgrading investment such as those
announced in 2014 by Exxon, Total and Neste. Kuwait Petroleum sold its 88 kb/d refinery at
Rotterdam to Gunvor, who decided to reduce capacity and exit lubricants production. In Turkey,
SOCAR’s 214 kb/d greenfield Aliaga refinery is considered on track to start up in 2018.
Box 4.1 Refining margins – where from here?
Even though the crude oil prices lost another 10 dollars over the course of the last quarter of 2015,
refining margins started drifting down from their peak of recent years. Figure 4.2 shows the
7
development of cracking margins in North-West Europe (Brent), Singapore (Tapis ) and US Gulf coast
(50/50 blend of Maya and Mars).
16
14
12
10
8
6
4
2
0
Jan-14
Figure 4.3 Margin dynamics
50
40
30
USD/bbl
USD/bbl
Figure 4.2 Regional cracking margins
20
10
0
- 10
- 20
Jul-14
NWE
Jan-15
Dubai
Jul-15
USGC
Jan-16
Jan-09
Jan-07
Jan-11
Global range ex US Midcon
Dubai (Cracking)
WTI (Coking)
Jan-15
Jan-13
Urals (Cracking)
Bakken (Cracking)
Tapis cracking margins were used instead of Dubai as the August 2015 Dubai crude assessments were thought to be heavily affected by
trading actions of Petrochina and Sinopec. See Middle East oil price benchmark is patched up, full fix elusive,
http://www.reuters.com/article/column-russell-crude-asia-idUSL3N13R1XV20151202 .
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Box 4.1. Refining margins – where from here? (continued)
More interestingly though, the refining margins in the US midcontinent, which tend to be in the league
of their own in double-digit margins territory, compressed down to the levels of “average mortals”, a
very rare occurrence for the last five years, and a first-time for the LTO crudes such as Bakken
(Figure 4.3).
Much in line with the gasoline support for the margins observed most of last year, margins
deteriorations started after the end of summer driving season, while middle distillates failed to pick up
the baton as they should do during the northern hemisphere winter. As previously high refining margins
had pushed the refinery runs above the demand globally, the product markets were entering the winter
with already high stocks. Latest available stocks data by the time of writing this report, for December
2015, showed a new seasonal record of middle distillates stocks in OECD Europe. Mild winter weather
added to the downward pressure for diesel cracks. Even 10 ppm ULSD cracks in North-West Europe, the
world’s biggest diesel importing region, went to single digits, first time since the days of massive diesel
floating storage builds in 2009, recording the lowest monthly average cracks since 2003.
Figure 4.5 NWE ULSD barges crack vs Brent
320
30
300
25
USD/bbl
mb
Figure 4.4 Europe middle distillates stocks
280
260
20
15
10
240
5
220
0
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Range 2010-2014
2009
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
2015
2010-2014 range
2009
2015
2016
Despite lower prices, demand growth had slowed down in the last quarter. Globally, diesel demand was
flat year-on-year (y-o-y) in the fourth quarter, while it in fact declined in the OECD countries. Gasoline
y o-y demand growth was lowest in the last quarter, and in OECD, it went to y-o-y decline in December.
Figure 4.6 Global y-o-y demand growth
Figure 4.7 OECD demand growth
1.2
1.0
1.0
0.8
mb/d
mb/d
0.8
0.6
0.6
0.4
0.4
0.2
0.0
0.2
-0.2
1Q2015
2Q2015
Gasoline
100
3Q2015
Diesel
4Q2015
-0.4
Jan-15
Mar-15
Gasoline
May-15
Jul-15
Jet Kerosene
Sep-15
Nov-15
Diesel
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0.0
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Box 4.1. Refining margins – where from here? (continued)
Does this mark the beginning of the end of margin renaissance? Will the industry soon be back to its
more habitual “survival” mode? There are a few potential developments that favour a positive answer
to this question.
• Capacity expansions vs demand. Current forecast of capacity expansions over the next five years are
about 2 mb/d higher than expected demand growth for refined products. This adds to the spare
capacity and will represent a significant pressure on margins in the future. In 2016, when capacity
additions are lower, at about half of the expected annual demand growth, the possible tightening of
product markets may not materialise due to product stocks overhang.
• Crude oil prices. Whether the crude prices have already reached the bottom or there is still room for
more downward correction, they are expected to resume the upward trajectory as global balances
start tightening next year. Refinery margins may deteriorate if product prices struggle to keep up with
crude price movement.
• Parallel margin economics. Some refiners enjoy higher margins from domestic sales than from trading
on international markets, due to advantaged crude prices at home (which is the case for some crude
oil exporters) or to product price floors set up by national governments (such as in China). This can
result in a situation when higher domestic revenues effectively subsidize margins from international
trade, capping potential upside for refiners in other regions, especially in trading hubs, which set the
prices and define the margins.
• Higher upstream earnings absorbing losses from downstream. If and when crude prices firm, the
accounting of major oil companies may again see the traditional pattern of higher upstream profits
offsetting losses from low-margin downstream. In these circumstances, vertically integrated oil
companies do not immediately rush to cut refinery runs, which perpetuate depressed product cracks.
In other words, the capacity of some major players to absorb negative margins is a factor on
downward pressure for refining earnings.
Of course, if capacity additions come in lower than the forecast in this Report, and/or demand growth
turns out higher, margins may yet rebound from the very recent low levels and stay firmer than the
current assumptions imply.
Non-OECD adds most of refining capacity
Non-OECD’s refining sector is developing in a two-speed manner. China, India, some smaller South
East Asian economies and the Middle East are effectively trying to catch up and overtake their
demand growth. Elsewhere, in FSU, Latin America and, to an extent, Africa, financing and project
management constraints and, at times, less than stellar demand growth put brakes on future
developments.
The major change in China this year has been the opening up of the crude import quota system to
the independent refineries. With a few exceptions, such as Dongming Petrochemicals, these
relatively small and unsophisticated plants, colloquially called teapot refineries, most of them in
Shandong province, used to run at around 35% of capacity on a diet of straight run fuel oil and
bitumen. The largest have been awarded quotas and licences to import and refine crude oil under a
number of conditions, which include shutting down a share of their overall capacity and investing in
upgrading units to meet the China V products specifications. The import quotas awarded for 2015
amount to 1.4 mb/d for 11 independents, and correspond to a closure of roughly 0.5 mb/d nominal
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China takes steps toward deregulation
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capacity that essentially had not really been utilised. Other steps in the deregulation concern the
right to import own equity crude from international assets, but this has so far only been awarded to
two independents. Local governments seem to be supportive of small refiners’ initiatives to construct
new distillation units. Around 400 kb/d of new capacity came online in 2015 with a unit size below
100 kb/d. This trend is unlikely to last past 2016, as this seems to be a way for teapot refiners to
qualify for import licences with more modern CDUs built to run crude oil rather than processed
feedstocks (see Box 4.2 China’s teapot refineries). Most likely, this will not mean a net addition to the
overall capacity base, but rather, effectively, a replacement of old and polluting capacity by cleaner
units.
At the same time, there is a noticeable slowdown in the pace of new capacity development by
Chinese majors as they announce delays to big projects due to concerns about the ability of the
market to absorb their output, as well as financial constraints from lower revenues in the current oil
price environment. Also, some of the downstream capex had to be earmarked for compliance with
stricter fuel emissions specifications as the China V standard, which requires lower sulphur content,
was extended to all of Eastern China (not only the major cities and river deltas) two years earlier than
initially scheduled. The rest of the country will have to be compliant by 2017, one year earlier than
scheduled. This implies an increase in investment requirements particularly in hydrotreating capacity.
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In 2015, the majors completed only one project, the 70 kb/d expansion of Sinopec Jiujiang refinery,
while the independent refining sector added a net 170 kb/d. 2016 will see limited expansions, with
the largest (100 kb/d) for an independent refiner, Yatong Petrochemical. Two large refineries are
planned to start in 2017, CNOOC’s 200 kb/d Huizhou refinery – delayed by one year, and Petrochina’s
260 kb/d Anning/Kunming refinery, which is
currently experiencing administrative hurdles
Figure 4.8 Share of imports in crude throughputs*
due to a non-updated building permit forcing
100%
it to temporarily stop construction.
PetroChina will also complete the 100 kb/d
80%
expansion of its Renqui (Huabei) refinery.
Other large refinery projects, such as
60%
Sinopec’s 200 kb/d Luoyang expansion and
Sinopec/Kuwait Petroleum Corporation’s
40%
300 kb/d Zhanjiang refinery have slipped to
2019
and
2020,
respectively.
20%
Petrochina/PDVSA’s Jieyang JV has been
0%
delayed from 2018 to 2021 and reduced in
North America
Europe
China
India
size as PDVSA suffers from a difficult financial
situation, while the Petrochina/Qatar
2010
2015
2021
Petroleum 300 kb/d Taizhou project is now
only expected to be completed after the *Imported from other regions, intra-regional flows count as domestic
forecast period.
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Box 4.2 China’s teapot refineries
The term “teapot refineries” has come to cover a wide range of refineries that run independently of
Chinese major oil companies. In its most widely used sense teapots include not just small backyard
refineries running mostly on processed feedstocks and producing sub-standard fuels, but also all the
refineries that are not owned by Chinese vertically integrated oil companies, regardless of their size or
complexity. For the purposes of this report, we only include refiners with CDUs of less than 30 kb/d in
our teapot statistics. In addition, since teapot refineries usually run at very low utilisation rates of 3040%, we tend to discount most of that unused capacity in our country total for China. Thus, the teapot
refineries are only a subset in the wider independent refining sector.
There have been interesting developments for both tiers of the independent sector. Teapots have
managed to replace some of their fuel oil feedstocks by crude supplied by the major players. By the end
of 2015, 11 independent refiners promised to improve their operations and were awarded quotas to
refine crude oil for a total of 1.4 mb/d. Some of these refiners were granted an import licence, to the
tune of 800 kb/d, which allows them to directly import crude without having to go through national
companies as intermediaries. A number of independent refiners even received product export quotas.
The rest still have to rely on state companies’ oil imports. How will this change the Chinese downstream
sector? Or, to re-phrase the question: if a complete liberalization of the sector happens, will
independent refiners remain competitive or be driven to consolidation? There are factors that do not
augur well for the sector.
• Their small size, resulting in lower efficiency. The average estimated size of 120 independents is still
only 30 kb/d. Yet, they compete with large Chinese companies, which operate refining sites of more
than 150 kb/d capacity on average. Some teapots trade in specialised local niches such as asphalt. If a
teapot refiner starts running crude oil rather than processed feedstocks, it has to build very smallscale secondary units to be able to bring gasoline and diesel to specifications. They would do so only if
they benefit from a niche market where they can sell the products at a good margin. But why would
not one of the four large companies try to profit from such niche markets?
• Limited and costly logistics. Most teapots do not have pipeline access to a large port to import crude
cheaply. The situation is even worse for products, which means they will have to fight for local
product sales with their large competitors rather than export. It may be more profitable today, but
can hardly be so in the long run. This smaller size is also a handicap when importing crude, as refiners
will have to limit their purchases to small cargoes and relatively short haul sources in order to save on
inventory in transit costs.
• Teapots running crude will mostly yield fuel oil and gasoil. Given the above constraints on cargo
sourcing, the smaller refiners will likely only use heavy crudes, which will yield more middle distillates
than light distillates, with a high fuel oil residue proportion. This mix is far from ideal as China’s market
is driven by gasoline growth.
• Overall low utilisation rates in the country. Even Chinese majors run at relatively low rates compared
to their peers in other countries. They may target to increase their run rates by either taking the
teapots’ share in the domestic market or exporting more, both of which may signify negative
developments for the teapots. Given that the Chinese refining sector is increasing its reliance on
imported crude oil (Figure 4.8), the economics of long-haul crude import/product export may not be
that convincing.
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• Targets for anti-pollution activists. Most of the small teapots are located within city limits,
contributing to local pollution and are an easy target in the fight to improve local air quality.
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Box 4.2 China’s teapot refineries (continued)
Thus, consolidation and restructuration could be the fate of most of the independent refining industry in
China. Having said that, some independent refiners may take these steps towards liberalisation as a
chance to radically change their business strategy and become fully-fledged refining/petrochemical
entities of considerable scale, sometimes even spanning international borders. For example, in early
February 2016, a small and relatively unknown Chinese independent refiner, Hengyuan Petrochemical
from Shandong, purchased Shell’s 150 kb/d Port Dickson refinery in Malaysia, to feed its Chinese units
with feedstocks. One of the reasons for Shell selling the site was the refinery’s inability to meet Euro-4
and Euro-5 fuel specifications, something that didn’t deter the Chinese independent buyer, used to
working with processed feedstocks and mostly focused on petrochemical products.
Other Non-OECD Asia a major contributor to growth
In non-OECD Asia, the capacity additions are estimated at 1.2 mb/d over the period 2016-21.
However, this is based on reasonably conservative assumptions that most of the additions
(0.75 mb/d) will take place in India, with only two large projects elsewhere coming to fruition: a
second refinery in Viet Nam, Nghi Son, in 2018, and Petronas’s 300 kb/d Rapid project in Malaysia,
in 2020.
The main start-up in 2015 was Indian Oil’s Paradip refinery, and the Byco refinery in Pakistan – the
relocation of Petroplus’s Milford Haven, UK, refinery dismantled in 2006 8– also ramped up. In
Singapore, the 100 kb/d Jurong Aromatics condensate splitter started up at end-2014, but stopped
operations in mid-2015, with the owner in receivership. In India, the first additions or expansions on
the list are still Nagarjuna’s 120 kb/d Cuddalore project in 2016, followed by BPCL’s 120 kb/d Kochi
plant, and IOC’s Panipat, Koyali and Barauni refineries, BPCL’s Bina and Mumbai refineries, HPCL’s
Mahul and Bathinda and Mangalore refineries. And a number of other projects could still develop. In
Indonesia, Saudi Aramco and Pertamina have concluded a heads of agreement for joint ownership,
operation and upgrading of the 350 kb/d Cilacap refinery, but the larger plan calling for expansions
and upgrades at the other Indonesian refineries does not seem to have progressed. In Chinese Taipei,
CNPC’s Ta-lin refinery is planned to expand by 150 kb/d in 2016 to partly compensate for the 2015
shutdown of the old Kaohsiung refinery.
The Middle East continues with ambitious plans
In the Middle East, after the start-up of three large refineries in Saudi Arabia and the UAE in the past
few years, the pace of additions will slow and depend largely on developments in Iran. Total
additions over 2016-2021 reach 2.3 mb/d, raising capacity to 11.6 mb/d, or 11% of the global total.
8
Byco Petroleum also purchased Murco’s 135 kb/d Milford haven refinery units, shuttered in 2014, to also eventually relocate and restart
in Pakistan.
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Saudi Arabia should complete the 50 kb/d expansion of Rabigh in 2017, but completion of the
greenfield Jizan refinery, still slated for 2018, could well be delayed, in particular because of its
proximity to the Yemen border. Qatar is due to complete its 136 kb/d Ras Laffan condensate splitter
in 2016. In Kuwait, plans for the start-up of the Clean Fuels Project – the merger and expansion of
the Mina Abdullah and Mina al-Ahmadi refineries –are on track for 2019. However, the closure of the
200 kb/d Shuaiba refinery, initially due to follow the completion of the Clean Fuel Project, was
recently advanced to 2017. Otherwise, the last tenders for the building of the 650 kb/d Al-Zour
refinery have finally been awarded, but this still makes the announced 2019 completion too
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optimistic. Oman’s 230 kb/d Duqm refinery is still planned for 2021, with tenders just sent out, but
the expansion of the Sohar refinery is expected around 2017. In the UAE, the IPIC Fujairah refinery is
not showing any signs of progress.
The largest uncertainties regarding refinery expansions in the region come from Iraq and Iran. Iraq
has close to 1 mb/d of projects for completion over the forecast period, in addition to repairs to
refineries damaged by conflict e.g. Baiji. It is hard to be optimistic when vital upstream investments
have to be pared, and when no construction whatsoever has started. Only one refinery project, the
200 kb/d Karbala project, is expected to be completed by 2021. In Iran there are much more
concrete plans, the vast majority of which are condensate splitters linked to the development of
huge gas fields like South Pars. The most advanced is the 360 kb/d Persian Gulf Star, with three
120 kb/d phases scheduled to come on-stream between end-2016 and 2019. Another important
project is the 480 kb/d Siraf plant, designed as eight independent units of 60 kb/d each, at an
estimated cost of USD 2.8 billion. This whole project is likely to be developed in stages, especially
because the supply of condensate to feed both this and the Persian Gulf Star project needs to catch
up. The first phase could start up in 2019.
Non-OECD Americas hit by macroeconomic woes
In the non-OECD Americas, 560 kb/d of new distillation capacity is expected to be added in the 20152021 period. The final start-up of the expanded Colombian Cartagena refinery at the end of 2015 will
allow the plant to use more local feedstocks. The upgrading of the Barrancabermeja refinery,
meanwhile, has been delayed and is expected to be completed only at the end of the forecast period.
In Brazil, the dire economic situation and major organisational and governance problems at
Petrobras reduced the downstream capital allocation and froze almost all downstream projects. Only
the first 115 kb/d train of the Pernambuco Abreu e Lima refinery could be completed this year, with
the second train put on hold and tentatively scheduled for 2018. Petrobras’ Comperj refinery is only
expected to be completed by the end of the forecast period, compared with an earlier plan of 2017.
Similarly, Venezuela’s grand plans appear more and more unlikely to come to fruition as the country
goes through an economic crisis. There is still hope that the 90 kb/d expansion of Puerto de la Cruz
refinery can be completed by 2018 and the 40 kb/d expansion of Santa Ines completed by 2020.
In the FSU, there are few plans to add capacity, as the focus in Russia is to invest in upgrading units.
Over 1.1 mb/d of upgrading capacity additions are planned over the period 2016-2021. However,
construction of some of these units is experiencing delays, which prompted the Russian Government
to delay the Euro 4 gasoline ban by six months, until July 1, 2016. In 2015, Russia saw a mixture of
additions – the new Novatek 70 kb/d condensate splitter in Ust-Luga, a 60 kb/d expansion in Lukoil’s
Volgograd refinery, while a number of old CDUs were retired at Rosneft’s Syzran and
Novokuibyshevsk refineries. Overall, this represented a net 70 kb/d reduction of CDU capacity, but
more CDUs can be mothballed due to lower margins. Crude runs in 2015 were 2.4% below the 2014
level. Otherwise, in terms of future CDU capacity additions, the only significant project is the
140 kb/d expansion of Tatneft’s Nizhnekamsk refinery, expected to be completed in 2017. In
Kazakhstan, Pavlodar is undergoing an expansion, which we assume will be delayed to 2018. An
expansion of the Chimkent plant had been envisaged at the end of 2014, but there has not been any
noticeable progress since. Kazakhstan’s government announced that they are considering the
privatisation of three refineries and any new plans will depend of the outcome of the process.
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Russia digests the latest tax manoeuver
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Africa expansion depends on Nigeria
In Africa, capacity additions are estimated at 0.8 mb/d over 2016-2021, but most of it hinges on the
completion of Nigeria’s giant Lekki project that its owner and main backer, businessman Aliko
Dangote, is still insisting will come online in 2018. Due to its scale and complexity, we assume a
completion date closer to the end of the forecast period and a more gradual ramp up. Although not
an addition per se, it will be interesting to see if the new management of the Nigerian National
Petroleum Corporation succeeds in restoring the country’s 450 kb/d of refining capacity back to
health (see Box 4.3. Nigerian downstream paradox). Latest official data show the plants ran at a
combined 5% utilisation capacity in 2015.
Box 4.3 Nigerian downstream paradox
Last year, Nigerian refineries operated at no more than 5% of their combined 450 kb/d capacity,
processing only 1% of the country’s oil output. Thus, local refineries provided only a miniscule
proportion of the country’s products demand. Newly elected President Buhari has shown a
determination to reform the petroleum industry but the continued slide in oil prices makes the task
more complicated. To make matters worse, the rehabilitation programme for the three refineries has
been hampered by the refusal of many of the original equipment manufacturers to participate in the
rehabilitation projects on cost and security grounds. There are concerns about the quality of the work
done by alternative contractors and testing of the revamped plants was hampered by militant activity in
the Niger Delta that closed the pipelines carrying feedstocks to the refineries.
Figure 4.9. Nigeria’s oil sector at a glance
2.5
Total oil output
mb/d
2.0
1.5
1.0
0.5
Lekki planned capacity
Total demand
Refinery capacity
Refinery runs in 2015
0.0
Algeria had ambitious plans, but is set to record its largest ever trade deficit in 2016 at USD 14
billion, and the downstream sector is probably not the government’s main priority. Only minimal
expansions in existing refineries are expected to be completed. In Egypt, the Midor Alexandria
expansion is still on the books for 2018, together with Qalaa Holdings’ Mostorod project planned as
an upgrading expansion of the Cairo oil refinery. Expected demand growth could absorb a few other
plans but they are unlikely to take off in the near term. In Angola, Sonangol’s 120 kb/d refinery
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Local businessman Aliko Dangote’s 650 kb/d Lekki refinery project has excited many in Nigeria and
abroad as an answer to the country’s downstream problems. It is supposed to come onstream in 2018
but a rapidly escalating budget - initial costs of USD 5 billion have ballooned to USD 9 billion - and the
depreciation of the naira have caused problems.
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remains slated for 2019, although there was little sign of progress in 2015. In Uganda, decisions
regarding the start-up of the upstream field and the export pipeline are still under discussions, and
the proposed refinery at Hoima will likely be delayed.
Product supply balances
In world oil trade, products flows continue to grow faster than crude oil flows, and this trend will
continue for the next five years. Increased self-sufficiency in the US has been an important factor,
backing out imports from the Middle East and West Africa, but so have the ambitions of some crude
oil exporters, especially in the Middle East, to process more crude oil at home. Regionally, East of
Suez increases its imports of not only crude oil, but also oil products, as the increasingly long and less
dynamic Atlantic region looks east for new potential markets.
Map 4.1 Regional product supply balances in 2015 and 2021 - gasoline/naphtha (kb/d)
Here, trade is dominated by the US, the world’s biggest refiner, and now one of the largest crude oil
producers. From intra-regional exports of diluents such as pentanes to Canada, and LPG and
transport fuels to Mexico, to exports of fuels to Latin America, Europe, Africa, and even Asia, refiners
in the US are expanding their markets. The sheer size of the country, the concentration of refining
capacity in the Midwest and the Gulf of Mexico, capacity constraints on the Colonial product pipeline
and Jones Act limitations mean that the Atlantic coast will keep importing gasoline from Europe,
even if the US is about to become a net gasoline exporter. However, the US gasoline exports will not
be sufficient to cover the net import requirements of Canada and especially Mexico, and the region
as a whole will remain a net importer of gasoline though the volumes will be substantially reduced.
Another light end product, LPG, that saw its North American balance swing sharply from 300 kb/d of
imports in 2013 to 300 kb/d of exports in 2015, will have more moderate growth in exports. Shale-
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OECD Americas
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enabled increased US availability of LPG will be offset by Mexico’s higher import requirement. Middle
distillate exports are set to increase with higher refinery output but moderate demand growth. In
early 2016, the first long-haul ethane shipment to Norway from the US arrived, and further
shipments are planned to Grangemouth ethane cracker in the UK. Even though lower oil prices
eroded most of the advantage of ethane cracking margins vs naphtha, INEOS, owner of both
crackers, has not abandoned the strategy of importing ethane from the US expecting the economics
to improve soon.
Map 4.2 Regional product supply balances in 2015 and 2021 - gasoil/kerosene (kb/d)
Russia
Russian refineries are expected to decrease runs as a result of recent tax changes, now favouring the
export of crude oil over the export of straight-run fuel oil and naphtha. At the same time, demand
growth will rebound, after stumbling in the current recession. This will lower Russian oil product
exports, and the country will cede its position as one of the biggest exporter of refined products to
the United States (currently, Middle East exports are higher in volume than Russia’s, but they are
dominated by LPG and naphtha from NGL fractionation). Diesel will continue to dominate the export
flows, while naphtha will see a contraction due to higher internal consumption. Fuel oil exports will
also decline as refineries increase the depth of processing.
The Middle East
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Close to 1 mb/d of new capacity has been added in the Middle East in the past couple of years, and
another 2 mb/d or so is expected in the next five years. This is well above the projected demand
growth and will thus result in reduced product imports and increased exports from the region. As for
the transport fuels, gasoline and diesel will turn to net exports only at the end of the period as the
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demand in these categories of fuels will outstrip supply growth for most of the period. Petrochemical
feedstocks exports such as naphtha and LPG will increase, feeding the growing petrochemical
industry in Asia. Kerosene exports, for which Middle East remains the most important supplier to
global markets, first of all to Europe, are also set to increase.
China
Projected capacity additions in China roughly match forecast demand growth over the next five
years, but if extremely underutilised teapot capacity is shut down, the net additions will be below the
overall demand growth by 400 kb/d. This implies China turning again into a net product importer,
unless Chinese refineries increase utilisation rates in order not to have to import products, which we
see as unlikely. The biggest products deficits are expected to be in the light ends category, namely,
LPG and naphtha for petrochemical feedstocks, a combined 1 mb/d of net imports, which are
essentially refinery by-products, and hence, do not justify higher refinery runs. At the same time,
domestic demand growth will also erode the excess of gasoline and diesel that Chinese refiners have
been exporting recently.
Map 4.3 Regional product supply balances in 2015 and 2021 - fuel oil (kb/d)
Indian product balances show perhaps the most striking change over the next five years. As the
country’s demand crosses the 5 mb/d threshold for the first time later in the forecast period, the
refinery capacity additions fall significantly behind, and even with very high utilisation rates of close
to 100%, the country’s total net product export position is all but eroded. The detail though is
perhaps less dramatic. The country will still export middle distillates, albeit at lower volumes, and it is
the growing appetite for LPG and some other non-fuel products that almost completely offsets the
exports. Even with the assumption of increased refinery runs Indonesian product output growth falls
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
109
© OECD/IEA, 2016
Other Asia
R EFININ G
behind the robust demand growth and the country’s net product imports cross the 1 mb/d mark.
Gasoline imports dominate the flows, of which Indonesia remains, interestingly, the world’s largest
net importer (followed by Mexico). With the exception of Singapore, all countries in the South-East
Asian block increase their import requirements due to higher demand.
The biggest impact on the trade flows though will come from the implementation of the lower
sulphur cap on maritime bunkers, for which Singapore remains the biggest market. It either
continues to receive a few hundred thousand barrels a day of fuel oil from Russia and the Middle
East, if the sulphur cap is delayed, or addressed via scrubbers (see Box 1.5 Marine gasoil to seize
bunker fuel market), or starts importing diesel instead.
Non-OECD Americas
Brazil’s new refinery capacity addition plan is now officially curtailed and only a 115 kb/d unit is
projected to come online before 2021. However, the impact of the current recession, and also of
higher local bioethanol production means that demand for refined products is in decline. Thus, the
product trade balance improves substantially. In the rest of Latin America, capacity additions roughly
match demand growth, each at about 250 kb/d for the five year period. The continent remains an
important market for US gasoline, and, increasingly, diesel exports.
Africa
110
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
© OECD/IEA, 2016
Despite expected capacity additions in Angola, Nigeria and Egypt, African imports will still grow,
especially to North and East Africa. The continent will be shorter in gasoline and diesel, while
continuing to export some light ends, especially to Latin America. East Africa is a growing market for
Indian and Middle East refineries, while West and North Africa will continue to be supplied by Europe
and the United States.
T ABLES
5. TABLES
Table 1 World Oil Supply and Demand Table 1
WORLD OIL SUPPLY AND DEMAND
(million barrels per day)
1Q15 2Q15 3Q15 4Q15 2015
1Q16 2Q16 3Q16 4Q16 2016
2017 2018 2019
2020
2021
OECD DEMAND
Americas
24.2
24.1
24.7
24.5
24.4
24.4
24.2
24.6
24.7
24.4
24.5
24.4
24.4
24.3
24.2
Europe
13.5
13.5
14.1
13.6
13.7
13.4
13.7
13.9
13.6
13.7
13.6
13.5
13.4
13.3
13.1
8.7
7.6
7.8
8.3
8.1
8.6
7.6
7.8
8.3
8.0
8.0
7.9
7.9
7.9
7.8
46.1 45.9 45.7
45.4
45.2
Asia Oceania
Total OECD
46.4 45.3 46.7 46.3 46.2
46.4 45.4 46.4 46.5 46.2
NON-OECD DEMAND
FSU
4.6
4.9
5.0
5.0
4.9
4.7
4.8
5.0
4.9
4.9
4.9
5.0
5.0
5.1
5.2
Europe
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.7
0.8
0.8
0.8
China
11.0
11.3
11.3
11.2
11.2
11.2
11.6
11.6
11.7
11.5
11.9
12.4
12.8
13.2
13.6
Other Asia
12.4
12.6
12.3
12.8
12.5
13.0
13.0
12.8
13.3
13.0
13.5
14.0
14.4
14.9
15.3
Latin America
6.6
6.8
6.9
6.8
6.8
6.6
6.8
6.9
6.9
6.8
6.8
6.9
6.9
7.0
7.1
Middle East
7.6
8.3
8.6
8.1
8.2
7.8
8.4
8.8
8.2
8.3
8.5
8.7
9.0
9.2
9.5
4.1
4.1
4.0
4.1
4.1
4.3
4.2
4.1
4.3
4.2
4.4
4.5
Africa
4.7
4.8
5.0
Total Non-OECD
47.1 48.6 48.7 48.7 48.3
48.1 49.6 50.0 49.9 49.4
50.8 52.2 53.7
55.0
56.4
Total Demand1
93.5 93.9 95.4 94.9 94.4
94.6 95.0 96.4 96.5 95.6
96.9 98.2 99.3 100.5 101.6
OECD SUPPLY
Americas
20.0
19.6
20.0
19.9
19.9
19.6
19.3
19.3
19.6
19.4
19.4
19.9
20.6
21.1
Europe
3.4
3.5
3.3
3.6
3.5
3.5
3.4
3.2
3.4
3.3
3.3
3.3
3.2
3.2
3.3
Asia Oceania
0.4
0.4
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.6
0.7
0.7
0.7
0.7
Total OECD
21.8
23.8 23.5 23.9 24.0 23.8
23.6 23.1 23.0 23.4 23.3
23.3 23.8 24.4
25.0
25.8
13.8
NON-OECD SUPPLY
FSU
14.0
14.0
13.9
14.0
14.0
14.0
14.0
13.9
13.8
13.9
13.8
13.8
13.8
13.8
Europe
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
China
4.3
4.4
4.3
4.3
4.3
4.3
4.3
4.3
4.3
4.3
4.2
4.2
4.2
4.1
4.1
Other Asia
2.8
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.7
2.6
2.6
2.5
Latin America
4.6
4.5
4.5
4.6
4.6
4.5
4.6
4.6
4.7
4.6
4.7
4.8
4.9
5.0
5.1
Middle East
1.3
1.3
1.2
1.2
1.3
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.2
1.1
1.1
Africa
2.3
2.3
2.3
2.3
2.3
2.3
2.3
2.3
2.3
2.3
2.3
2.3
2.2
2.1
2.1
29.0 29.0 29.0
28.9
28.8
Processing Gains2
Total Non-OECD
2.2
2.2
2.2
2.2
2.2
2.3
2.3
2.3
2.3
2.3
2.3
2.3
2.3
2.4
2.4
Global Biofuels
1.8
2.4
2.6
2.4
2.3
1.9
2.4
2.7
2.4
2.4
2.5
2.5
2.6
2.7
2.7
57.0 57.6 58.3
58.9
59.7
7.1
7.2
Total Non-OPEC3
29.5 29.3 29.2 29.3 29.3
57.4 57.5 57.9 57.9 57.7
29.2 29.1 29.1 29.1 29.2
57.0 56.9 57.1 57.2 57.1
OPEC
Crude3
31.2
32.2
32.4
32.4
OPEC NGLs
6.6
6.7
6.7
6.8
32.1
6.7
Total OPEC3
37.7
38.9
39.1
39.1
38.7
Total Supply
95.1 96.3 97.0 97.1 96.4
6.8
6.8
6.9
6.9
6.9
7.0
7.1
7.1
Memo items:
Call on OPEC crude + Stock ch.4
29.5 29.8 30.8 30.2 30.1
30.8 31.2 32.5 32.3 31.7
32.8 33.4 33.9
34.5
34.8
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
111
© OECD/IEA, 2016
1 Measured as deliveries from refineries and primary stocks, comprises inland deliveries, international marine bunkers, refinery fuel, crude for direct burning,
oil from non-conventional sources and other sources of supply.
2 Net volumetric gains and losses in the refining process and marine transportation losses.
3 Total Non-OPEC excludes all countries that were members of OPEC at 1 January 2016.
Total OPEC comprises all countries which were OPEC members at 1 January 2016.
4 Equals the arithmetic difference between total demand minus total non-OPEC supply minus OPEC NGLs.
T ABLES
Table 1a
TableWORLD
1a World
Supply
Demand:
Changes
Medium Term
OIL Oil
SUPPLY
ANDand
DEMAND:
CHANGES
FROMfrom
LASTlast
MEDIUM-TERM
REPORT
(million barrels per day)
ReportReport
1Q14 2Q14 3Q14 4Q14 2014
1Q15 2Q15 3Q15 4Q15 2015
2016 2017 2018 2019 2020
OECD DEMAND
Americas
0.0
0.1
0.2
-0.1
0.0
0.2
0.1
0.4
-0.1
0.1
0.1
0.1
0.0
0.0
Europe
0.0
0.0
0.0
0.1
0.0
0.5
0.3
0.5
0.2
0.3
0.4
0.4
0.4
0.4
-0.1
0.4
Asia Oceania
0.0
0.0
0.0
0.1
0.0
0.2
0.2
0.1
0.0
0.1
0.1
0.1
0.1
0.1
0.0
Total OECD
0.1
0.1
0.2
0.1
0.1
0.8
0.6
0.9
0.1
0.6
0.7
0.6
0.5
0.4
0.3
NON-OECD DEMAND
FSU
0.0
0.0
0.1
0.1
0.1
0.1
0.3
0.3
0.3
0.2
0.2
0.2
0.2
0.1
0.1
Europe
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
China
Other Asia
Latin America
Middle East
0.2
0.2
0.1
0.4
0.2
0.6
0.7
0.6
0.3
0.6
0.6
0.7
0.9
1.0
1.1
-0.1
0.0
-0.1
-0.1
-0.1
-0.2
0.0
0.0
0.0
0.0
0.1
0.2
0.3
0.4
0.3
0.1
0.0
0.0
0.1
0.1
0.0
-0.1
-0.1
-0.2
-0.1
-0.2
-0.3
-0.3
-0.4
-0.4
-0.1
0.0
-0.2
0.0
-0.1
-0.3
0.0
-0.2
0.0
-0.1
-0.2
-0.3
-0.3
-0.3
-0.2
Africa
0.1
0.0
0.0
0.0
0.0
0.0
0.0
-0.1
0.0
0.0
0.0
0.0
0.0
0.1
0.1
Total Non-OECD
0.2
0.3
0.0
0.5
0.2
0.2
0.8
0.5
0.4
0.5
0.5
0.6
0.8
1.0
1.0
Total Demand
0.2
0.5
0.2
0.6
0.4
1.0
1.4
1.4
0.5
1.1
1.1
1.2
1.3
1.4
1.3
-0.6
OECD SUPPLY
Americas
0.2
0.3
0.3
0.7
0.4
0.5
0.1
1.1
0.5
0.5
-0.4
-0.7
-0.7
-0.5
Europe
0.0
0.0
0.0
0.1
0.0
0.1
0.4
0.2
0.2
0.2
0.1
0.1
0.0
0.0
0.1
Asia Oceania
0.0
0.0
0.0
0.0
0.0
-0.1
-0.1
0.0
0.0
-0.1
-0.1
-0.1
-0.2
-0.2
-0.2
Total OECD
0.2
0.3
0.3
0.8
0.4
0.5
0.4
1.3
0.6
0.7
-0.4
-0.8
-0.8
-0.7
-0.7
-0.1
-0.1
0.0
0.0
0.0
0.1
0.1
0.2
0.3
0.2
0.4
0.4
0.4
0.4
0.4
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.1
NON-OECD SUPPLY
FSU
Europe
China
0.0
0.0
0.0
0.1
0.0
0.1
0.2
0.2
0.1
0.2
0.1
0.0
0.0
0.0
Other Asia
0.0
0.0
0.1
0.1
0.1
0.1
0.1
0.0
0.0
0.0
0.0
0.1
0.1
0.1
0.1
Latin America
0.0
0.0
0.0
0.0
0.0
0.2
0.0
0.0
0.0
0.0
-0.1
-0.2
-0.3
-0.3
-0.2
Middle East
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
Africa
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.1
-0.1
-0.1
-0.1
Total Non-OECD
0.0
0.0
0.1
0.3
0.1
0.5
0.4
0.4
0.5
0.4
0.5
0.2
0.1
0.0
0.1
Processing Gains
0.0
0.0
0.0
0.0
0.0
-0.1
0.0
-0.1
0.0
-0.1
-0.1
0.0
-0.1
-0.1
-0.1
Global Biofuels
0.0
0.0
0.1
0.1
0.1
0.0
0.1
0.0
0.1
0.1
0.1
0.1
0.2
0.2
0.3
Total Non-OPEC
0.2
0.3
0.5
1.2
0.5
0.9
0.8
1.6
1.2
1.1
0.1
-0.5
-0.6
-0.5
-0.4
Crude
0.0
0.0
0.0
0.0
0.0
OPEC NGLs
0.0
0.0
0.0
0.0
0.0
-0.1
-0.1
0.0
0.0
0.0
-0.1
0.0
0.0
0.1
0.1
Total OPEC
0.0
0.0
0.0
0.0
0.0
Total Supply
0.2
0.3
0.4
1.2
0.5
0.2
0.7
OPEC
Memo items:
112
0.1
0.2
-0.2
-0.6
-0.1
-0.1
-0.6
0.0
1.2
1.7
1.8
1.8
1.7
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
© OECD/IEA, 2016
Call on OPEC crude + Stock ch.
T ABLES
Table 2
SUMMARY OF GLOBAL OIL DEMAND
Table 2 Summary of Global Oil Demand
1Q15 2Q15 3Q15 4Q15
2015
1Q16 2Q16 3Q16 4Q16
2016
2017
2018
2019
2020
2021
Demand (mb/d)
Americas
Europe
Asia Oceania
24.2
13.5
8.7
24.1
13.5
7.6
24.7
14.1
7.8
24.5
13.6
8.3
24.4
13.7
8.1
24.4
13.4
8.6
24.2
13.7
7.6
24.6
13.9
7.8
24.7
13.6
8.3
24.4
13.7
8.0
24.5
13.6
8.0
24.4
13.5
7.9
24.4
13.4
7.9
24.3
13.3
7.9
24.2
13.1
7.8
Total OECD
46.4
45.3
46.7
46.3
46.2
46.4
45.4
46.4
46.5
46.2
46.1
45.9
45.7
45.4
45.2
Asia
Middle East
Latin America
FSU
Africa
Europe
23.4
7.6
6.6
4.6
4.1
0.7
23.8
8.3
6.8
4.9
4.1
0.7
23.6
8.6
6.9
5.0
4.0
0.7
23.9
8.1
6.8
5.0
4.1
0.7
23.7
8.2
6.8
4.9
4.1
0.7
24.1
7.8
6.6
4.7
4.3
0.7
24.6
8.4
6.8
4.8
4.2
0.7
24.4
8.8
6.9
5.0
4.1
0.7
24.9
8.2
6.9
4.9
4.3
0.7
24.5
8.3
6.8
4.9
4.2
0.7
25.5
8.5
6.8
4.9
4.4
0.7
26.4
8.7
6.9
5.0
4.5
0.7
27.3
9.0
6.9
5.0
4.7
0.8
28.1
9.2
7.0
5.1
4.8
0.8
28.9
9.5
7.1
5.2
5.0
0.8
Total Non-OECD
47.1
World
93.5
of which:
19.3
US50
8.1
Euro5
11.0
China
4.8
Japan
3.9
India
3.4
Russia
3.2
Brazil
2.9
Saudi Arabia
2.5
Korea
2.4
Canada
1.9
Mexico
1.8
Iran
65.1
Total
69.6
% of World
Annual Change (% per annum)
1.5
Americas1
3.2
Europe2
-1.4
Asia Oceania3
Total OECD
1.4
Asia
4.3
Middle East
-1.0
Latin America
0.2
FSU
-1.1
Africa
2.1
Europe
5.4
Total Non-OECD
2.1
World
1.8
Annual Change (mb/d)
Americas
0.4
Europe
0.4
Asia Oceania
-0.1
Total OECD
0.6
Asia
1.0
Middle East
-0.1
Latin America
0.0
FSU
0.0
Africa
0.1
Europe
0.0
Total Non-OECD
1.0
World
1.6
48.6
93.9
48.7
95.4
48.7
94.9
48.3
94.4
48.1
94.6
49.6
95.0
50.0
96.4
49.9
96.5
49.4
95.6
50.8
96.9
52.2
98.2
53.7
99.3
55.0
100.5
56.4
101.6
19.2
8.0
11.3
3.9
4.0
3.6
3.2
3.5
2.3
2.3
1.9
1.9
65.1
69.3
19.7
8.3
11.3
3.9
3.9
3.8
3.2
3.6
2.4
2.4
2.0
1.8
66.2
69.4
19.4
8.0
11.2
4.3
4.1
3.6
3.2
3.1
2.6
2.4
2.0
1.9
65.7
69.2
19.4
8.1
11.2
4.2
4.0
3.6
3.2
3.3
2.4
2.4
2.0
1.8
65.5
69.4
19.4
8.0
11.2
4.6
4.2
3.5
3.0
2.9
2.6
2.3
1.9
1.9
65.5
69.2
19.3
8.0
11.6
3.7
4.3
3.5
3.1
3.4
2.4
2.3
2.0
1.9
65.4
68.9
19.7
8.2
11.6
3.9
4.0
3.7
3.2
3.8
2.4
2.4
2.0
1.9
66.7
69.2
19.7
8.0
11.7
4.3
4.3
3.5
3.2
3.1
2.5
2.3
2.0
1.9
66.6
69.0
19.5
8.1
11.5
4.1
4.2
3.6
3.1
3.3
2.5
2.3
2.0
1.9
66.1
69.1
19.5
8.0
11.9
4.0
4.4
3.6
3.1
3.4
2.5
2.3
2.0
1.9
66.7
68.9
19.5
7.9
12.4
4.0
4.6
3.6
3.1
3.4
2.5
2.3
2.0
2.0
67.4
68.6
19.5
7.8
12.8
3.9
4.8
3.7
3.1
3.5
2.5
2.3
2.0
2.0
67.9
68.4
19.4
7.7
13.2
3.9
4.9
3.7
3.1
3.6
2.5
2.2
2.0
2.1
68.4
68.0
19.3
7.6
13.6
3.8
5.1
3.8
3.2
3.6
2.5
2.2
2.1
2.1
68.9
67.9
1.6
0.9
-0.4
1.0
4.9
2.2
-0.1
0.7
1.7
4.8
3.0
2.0
1.5
2.0
1.2
1.6
6.0
2.1
-1.2
-1.9
2.1
2.5
3.0
2.3
-0.5
0.7
-0.7
-0.2
3.3
3.8
-2.3
-1.7
4.2
3.4
2.1
1.0
1.0
1.7
-0.4
1.0
4.6
1.8
-0.8
-1.0
2.5
4.0
2.6
1.7
0.5
-0.1
-1.4
0.0
2.9
2.5
-1.2
1.7
4.2
2.3
2.2
1.1
0.2
1.0
-0.6
0.3
3.3
0.7
-0.4
-1.6
4.2
3.7
1.9
1.2
-0.3
-1.5
0.2
-0.6
3.7
3.0
0.2
-0.2
4.3
1.3
2.7
1.1
0.9
0.4
-0.1
0.6
4.1
0.6
1.6
-0.7
3.6
2.8
2.6
1.6
0.1
-0.1
-1.3
0.1
3.5
1.7
0.1
-0.2
4.1
2.5
2.4
1.2
0.3
-0.4
0.0
-0.2
3.8
2.1
0.5
1.0
3.7
2.3
2.8
1.4
-0.3
-0.8
-0.6
-0.4
3.6
2.9
0.8
1.3
3.6
1.8
2.9
1.3
0.0
-0.9
-0.6
-0.5
3.4
2.8
0.9
1.5
3.5
1.8
2.8
1.2
-0.3
-0.7
-0.7
-0.6
3.0
2.5
0.7
1.1
2.9
1.6
2.4
1.1
-0.5
-1.4
-0.4
-0.5
2.9
2.6
1.2
1.5
3.2
1.6
2.5
1.1
0.4
0.1
0.0
0.5
1.1
0.2
0.0
0.0
0.1
0.0
1.4
1.9
0.4
0.3
0.1
0.7
1.3
0.2
-0.1
-0.1
0.1
0.0
1.4
2.2
-0.1
0.1
-0.1
-0.1
0.8
0.3
-0.2
-0.1
0.2
0.0
1.0
0.9
0.2
0.2
0.0
0.4
1.0
0.1
-0.1
-0.1
0.1
0.0
1.2
1.6
0.1
0.0
-0.1
0.0
0.7
0.2
-0.1
0.1
0.2
0.0
1.1
1.0
0.1
0.1
0.0
0.1
0.8
0.1
0.0
-0.1
0.2
0.0
0.9
1.1
-0.1
-0.2
0.0
-0.3
0.9
0.3
0.0
0.0
0.2
0.0
1.3
1.0
0.2
0.0
0.0
0.3
1.0
0.0
0.1
0.0
0.2
0.0
1.3
1.5
0.0
0.0
-0.1
0.0
0.8
0.1
0.0
0.0
0.2
0.0
1.1
1.2
0.1
-0.1
0.0
-0.1
0.9
0.2
0.0
0.1
0.2
0.0
1.4
1.3
-0.1
-0.1
0.0
-0.2
0.9
0.2
0.1
0.1
0.2
0.0
1.4
1.3
0.0
-0.1
0.0
-0.2
0.9
0.2
0.1
0.1
0.2
0.0
1.4
1.2
-0.1
-0.1
-0.1
-0.3
0.8
0.2
0.0
0.1
0.1
0.0
1.3
1.1
-0.1
-0.2
0.0
-0.2
0.8
0.2
0.1
0.1
0.2
0.0
1.4
1.1
0.1
0.3
0.2
0.6
0.9
-0.2
-0.2
0.2
-0.1
0.0
0.7
1.4
0.1
0.5
0.2
0.7
0.8
-0.2
-0.2
0.3
0.0
0.0
0.7
1.4
0.2
0.4
0.1
0.7
0.7
-0.3
-0.2
0.2
0.0
0.0
0.5
1.2
0.2
0.4
0.0
0.6
0.4
-0.3
-0.3
0.1
0.0
0.0
0.0
0.6
0.1
0.4
0.1
0.7
0.7
-0.2
-0.2
0.2
0.0
0.0
0.5
1.1
0.1
0.4
0.1
0.6
1.0
-0.3
-0.3
0.2
0.0
0.0
0.6
1.2
0.0
0.4
0.1
0.5
1.2
-0.3
-0.3
0.2
0.0
0.0
0.8
1.3
0.0
0.4
0.1
0.4
1.4
-0.3
-0.4
0.1
0.1
0.0
1.0
1.3
-0.1
0.4
0.0
0.3
1.5
-0.2
-0.4
0.1
0.1
0.0
1.0
1.4
0.0
-0.2
0.1
0.0
0.1
0.1
0.0
0.1
Revisions to Oil Demand from Last Medium Term Report (mb/d)
Americas
0.2
0.1
0.4
-0.1
0.1
Europe
0.5
0.3
0.5
0.2
0.3
Asia Oceania
0.2
0.2
0.1
0.0
0.1
Total OECD
0.8
0.6
0.9
0.1
0.6
Asia
0.4
0.7
0.6
0.4
0.5
Middle East
-0.3
0.0
-0.2
0.0
-0.1
Latin America
0.0
-0.1
-0.1
-0.2
-0.1
FSU
0.1
0.3
0.3
0.3
0.2
Africa
0.0
0.0
-0.1
0.0
0.0
Europe
0.0
0.0
0.0
0.0
0.0
Total Non-OECD
0.2
0.8
0.5
0.4
0.5
World
1.0
1.4
1.4
0.5
1.1
Revisions to Oil Demand Growth from Last Medium Term Report (mb/d)
World
0.8
1.0
1.2
-0.1
0.8
0.3
* France, Germany, Italy, Spain and UK
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
113
T ABLES
Table 3
WORLD OIL PRODUCTION
(million barrels per day)
Table 3 World Oil Production
1Q15 2Q15 3Q15 4Q15
2015
1Q16 2Q16 3Q16 4Q16
2016
2017
2018
2019
2020
2021
6.85
6.99
7.09
7.12
7.15
7.15
OPEC
Crude Oil
Saudi Arabia
Iran
Iraq
UAE
Kuwait
Neutral Zone
Qatar
Angola
Nigeria
Libya
Algeria
Ecuador
Venezuela
Indonesia
Total Crude Oil
Total NGLs1
Total OPEC2
NON-OPEC3
OECD
Americas
9.77
2.82
3.50
2.84
2.70
0.20
0.67
1.77
1.81
0.37
1.11
0.55
2.39
0.67
10.29
2.85
3.94
2.87
2.72
0.09
0.66
1.76
1.77
0.46
1.11
0.55
2.43
0.70
10.27
2.87
4.24
2.92
2.76
0.04
0.64
1.77
1.80
0.38
1.12
0.53
2.40
0.69
10.16
2.89
4.27
2.89
2.76
0.04
0.67
1.76
1.84
0.40
1.11
0.54
2.38
0.69
10.12
2.86
3.99
2.88
2.74
0.09
0.66
1.76
1.80
0.40
1.11
0.54
2.40
0.69
31.16 32.21 32.43 32.38 32.05
6.59 6.66 6.70 6.76 6.68
6.77
6.82
6.88
6.94
37.75 38.87 39.13 39.14 38.73
19.99 19.60 20.05 19.95 19.90
19.61 19.29 19.29 19.58 19.44
19.37 19.88 20.56 21.14 21.82
12.76
2.66
4.56
0.01
13.00
2.56
4.04
0.01
13.01
2.60
4.43
0.01
12.93
2.59
4.42
0.01
12.92
2.60
4.36
0.01
12.53
2.58
4.48
0.01
12.43
2.56
4.28
0.01
12.30
2.50
4.48
0.01
12.47
2.52
4.58
0.01
12.43
2.54
4.46
0.01
12.35
2.47
4.55
0.01
12.70
2.38
4.79
0.01
13.13
2.39
5.03
0.01
13.63
2.42
5.09
0.01
14.23
2.41
5.16
0.01
Europe
3.41
3.49
3.34
3.57
3.45
3.50
3.35
3.18
3.36
3.35
3.32
3.26
3.17
3.19
3.28
UK
Norway
Others
0.91
1.93
0.57
1.01
1.93
0.55
0.88
1.91
0.55
1.02
2.01
0.55
0.95
1.94
0.55
1.00
1.96
0.54
0.95
1.87
0.53
0.84
1.81
0.52
0.95
1.89
0.52
0.94
1.88
0.53
0.93
1.89
0.50
0.98
1.79
0.49
0.98
1.71
0.48
0.93
1.78
0.48
0.90
1.91
0.47
0.42
0.44
0.50
0.48
0.46
0.50
0.49
0.49
0.50
0.49
0.56
0.66
0.67
0.67
0.69
0.35
0.08
0.36
0.09
0.42
0.09
0.39
0.09
0.38
0.09
0.40
0.09
0.40
0.09
0.40
0.09
0.41
0.09
0.40
0.09
0.47
0.09
0.57
0.09
0.58
0.09
0.58
0.09
0.60
0.09
United States
Mexico
Canada
Chile
Asia Oceania
Australia
Others
Total OECD
NON-OECD
Former USSR
Russia
Others
Asia
China
Malaysia
India
Others
Europe
Latin America
Brazil
Argentina
Colombia
Others
Middle East4
Oman
Syria
Yemen
Others
Africa
Egypt
Equatorial Guinea
Sudan
Others
Total Non-OECD
Processing Gains5
Global Biofuels
TOTAL NON-OPEC2
TOTAL SUPPLY
23.82 23.54 23.89 24.00 23.81
23.60 23.13 22.96 23.43 23.28
23.25 23.80 24.41 25.00 25.79
14.05 13.97 13.91 13.98 13.98
14.04 13.96 13.87 13.84 13.93
13.82 13.79 13.81 13.80 13.75
11.02
3.03
7.05
4.29
0.75
0.87
1.15
11.03
2.94
11.04
2.88
11.13
2.84
11.06
2.92
11.18
2.84
11.11
2.83
11.06
2.79
11.01
2.81
11.09
2.82
10.99
2.79
10.94
2.73
10.90
2.72
10.85
2.79
10.78
2.83
7.09
7.02
7.08
7.06
7.02
7.00
6.98
6.99
7.00
6.91
6.86
6.78
6.72
6.65
4.36
0.72
0.86
1.15
4.34
0.67
0.87
1.14
4.33
0.70
0.88
1.17
4.33
0.71
0.87
1.15
4.30
0.72
0.85
1.14
4.30
0.73
0.83
1.13
4.30
0.73
0.83
1.12
4.29
0.73
0.85
1.12
4.30
0.73
0.84
1.13
4.23
0.74
0.83
1.11
4.20
0.76
0.82
1.08
4.18
0.76
0.80
1.05
4.15
0.77
0.78
1.02
4.13
0.76
0.77
0.99
0.14
4.61
0.14
4.54
0.14
4.54
0.14
4.56
0.14
4.56
0.13
4.54
0.13
4.56
0.13
4.59
0.13
4.65
0.13
4.59
0.13
4.68
0.12
4.79
0.11
4.89
0.10
4.98
0.10
5.14
2.54
0.63
1.03
0.41
2.50
0.63
1.03
0.38
2.56
0.63
0.98
0.37
2.54
0.63
1.00
0.39
2.53
0.63
1.01
0.39
2.55
0.63
0.99
0.37
2.59
0.63
0.97
0.37
2.63
0.63
0.96
0.37
2.71
0.62
0.95
0.37
2.62
0.63
0.97
0.37
2.74
0.63
0.93
0.38
2.89
0.63
0.90
0.38
3.03
0.61
0.87
0.38
3.16
0.60
0.85
0.37
3.36
0.59
0.83
0.36
1.31
1.26
1.24
1.24
1.26
1.21
1.20
1.19
1.19
1.20
1.17
1.16
1.16
1.14
1.12
0.99
0.03
0.11
0.19
1.00
0.03
0.04
0.19
1.01
0.03
0.02
0.19
1.01
0.03
0.02
0.19
1.00
0.03
0.05
0.19
0.98
0.02
0.02
0.19
0.97
0.02
0.02
0.19
0.96
0.02
0.02
0.19
0.96
0.02
0.02
0.19
0.97
0.02
0.02
0.19
0.93
0.02
0.02
0.20
0.92
0.02
0.02
0.21
0.91
0.02
0.02
0.21
0.89
0.02
0.02
0.21
0.88
0.02
0.02
0.21
2.34
2.32
2.30
2.30
2.32
2.30
2.30
2.31
2.34
2.31
2.33
2.28
2.21
2.14
2.06
0.72
0.29
0.11
1.22
0.72
0.29
0.11
1.21
0.73
0.29
0.10
1.18
0.72
0.29
0.10
1.19
0.72
0.29
0.10
1.20
0.71
0.29
0.09
1.20
0.70
0.28
0.09
1.22
0.70
0.28
0.09
1.25
0.69
0.28
0.09
1.29
0.70
0.28
0.09
1.24
0.67
0.28
0.09
1.29
0.64
0.25
0.08
1.31
0.62
0.22
0.07
1.30
0.60
0.21
0.07
1.27
0.58
0.19
0.06
1.23
29.50 29.32 29.16 29.30 29.32
2.24
1.82
2.24
2.38
2.24
2.59
2.24
2.40
2.24
2.30
57.38 57.48 57.88 57.94 57.67
95.13 96.34 97.01 97.08 96.40
29.23 29.15 29.08 29.14 29.15
2.27
1.90
2.27
2.39
2.27
2.75
2.27
2.41
2.27
2.36
57.01 56.94 57.05 57.25 57.06
29.04 29.00 28.95 28.86 28.82
2.29
2.46
2.32
2.52
2.35
2.60
2.37
2.67
2.39
2.70
57.04 57.65 58.31 58.90 59.70
114
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
© OECD/IEA, 2016
1 Includes condensates reported by OPEC countries, oil from non-conventional sources, e.g. Venezuelan Orimulsion (but not Orinoco extra-heavy oil),
and non-oil inputs to Saudi Arabian MTBE. Orimulsion production reportedly ceased from January 2007.
2 Total OPEC comprises all countries which were OPEC members at 1 January 2016.
Total Non-OPEC excludes all countries that were OPEC members at 1 January 2016.
3 Comprises crude oil, condensates, NGLs and oil from non-conventional sources.
4 Includes small amounts of production from Jordan and Bahrain.
5 Net volumetric gains and losses in refining and marine transportation losses.
T ABLES
TABLE 3A: Selected Non-OPEC Upstream
Project Start-Ups
Table 3a
SELECTED NON-OPEC UPSTREAM PROJECT START-UPS
Project
Peak
Capacity
(kbd)
Start
Year
OECD Americas
Country
Project
Peak
Capacity
(kbd)
Start
Year
UK
Cragganmore
20
2019
USA
Delta House
80
2015
UK
Mariner
75
2019
USA
Lucius
80
2015
UK
Cheviot
20
2020
USA
Gunflint/Freedom
30
2016
OECD Asia Oceania
USA
Heidelberg
80
2016
Australia
North Rankin and Gorgon Liquids
40
2015
USA
Stones
50
2016
Australia
Prelude
30
2016
USA
Big Foot
65
2017
Australia
Wheatstone
40
2016
USA
Kodiak
20
2017
Australia
Ichthys
120
2017
USA
Point Thomas
25
2017
FSU
USA
Tahiti 2
60
2017
Russia
Vladimir Filanovsky
150
2016
USA
Hopkins
55
2018
Russia
Messoyakha
90
2018
USA
Stampede
80
2018
Russia
Trebs and Titov
100
2016
USA
Appomattox
150
2020
Russia
Tass-Yuriakh
90
2015
USA
Vito
80
2021
Russia
Novoportovskoye
100
2016
Canada
Cold Lake Ph 14-16
40
2015
Russia
Srednebotuobinskoe
110
2014
Canada
Kearl 2
110
2015
Russia
Suzun
90
2016
Canada
Surmont
118
2015
Russia
Yamal Mega project
90
2016
Canada
Christina Lake Ph F
50
2016
Russia
Rogozhnikovskoye Severnoye (North)
50
2015
Canada
Foster Creek Ph G
30
2016
Russia
Yarudeyskoe
65
2015
Canada
Hangingstone
20
2016
Kazakhstan
Kashagan phase 1a (restart)
375
2017
Canada
Fort Hills ph 1
160
2017
Azerbaijan
West Chirag Oil
100
2014
Canada
Horizon ph 2B
45
2017
Azerbaijan
Shah-Deniz 2
90
2019
Canada
Horizon ph 3
80
2017
Asia
Canada
Hebron
150
2018
India
Mumbai High
50
2018
Canada
Jackfish expansion
20
2018
India
Heera South
35
2014
Canada
White Rose Extension Project
50
2018
India
B-127
15
2017
Canada
Pike 1A
35
2019
India
Manik
40
2020
Canada
Pike 1B
35
2020
India
Barmer Hill
40
2015
Mexico
Ayatsil-Tekel-Utsil
110
2018
Malaysia
Bertam
15
2015
Mexico
Ayin
60
2018
Malaysia
Gumusut
120
2015
Mexico
Pemex Shallow water finds
150
2018
Brazil
OECD Europe
Latin America
Cidade de Itaguaí FPSO (Iracema Norte)
150
2015
Denmark
Hejre
35
2017
Brazil
P-61 (Papa Terra)
95
2015
Denmark
Hibonite
15
2019
Brazil
Atlanta EPS
45
2016
Norway
Edvard Grieg
80
2015
Brazil
Cidade de Caraguatatuba (Lapa)
100
2016
Norway
Ekofisk extension
50
2015
Brazil
Cidade de Marica (Lula Alto)
150
2016
Norway
Eldfish extension
40
2015
Brazil
Cidade de Saquarema (Lula Central)
150
2016
Norway
Knarr
50
2015
Brazil
Libra pilot
45
2017
Norway
Goliat
80
2016
Brazil
P-66 (Lula Sul)
150
2018
Norway
Ivar Aasen
50
2016
Brazil
P-68 (Lula Ext. Sul)
150
2018
Norway
Gina Krog
70
2017
Brazil
Tartaruga Verde/Tartaruga Mestica
150
2018
Norway
Gina Krog
70
2017
Brazil
P-67 (Lula Norte)
150
2019
Norway
Martin Linge
45
2018
Brazil
Berbigao/Sururu (Iara)
140
2020
Norway
Kristin
75
2019
Brazil
P-69 (Lula Oeste)
150
2021
Norway
Njord
50
2019
Brazil
Buzios Phase 1-4
600
2018-21
Norway
Johan Sverdrup
350
2020
Guyana
Liza
60
2021
UK
Alma/Galia
20
2015
Africa
UK
Kinnoul
40
2015
Congo
Nene Marine
35
2015
UK
Monarb
35
2016
Congo
Moho North
125
2016
UK
Schiehallion (Quad 204)
100
2016
Congo
Lianzi
20
2015
UK
Solan
20
2016
Congo
Litchendjili
10
2016
UK
Catcher
45
2017
Ghana
Tweneboa-Enyera-Ntomme
80
2016
UK
Clair Ridge
90
2017
Ghana
OTCP
30
2018
UK
Kraken
50
2017
Uganda
Albert Basin (Kingfisher)
35
2020
UK
Western Isles
30
2017
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
115
© OECD/IEA, 2016
Country
T ABLES
Table 3b Start-Ups
TABLE 3B: Selected OPEC Upstream Project
Selected OPEC upstream project start-ups
Peak
Capacity
(kbd)
Country Project
Start
Year
Crude Oil Projects
Country
Project
Peak
Capacity
(kbd)
Start
Year
NGL & Condensate Projects
Algeria
Bir Sebaa/Bir Msana
30
2015
Angola
Mafumeira Sul Phase 2--Block 0
10
2016
Angola
Cinguvu/Nzanza
20
2015
Iran
Pars 15 & 16
30
2016
Angola
Sangos/N'Goma
40
2015
Iran
South Pars 15-16 (condensate)
75
2016
Angola
Lianzi (Congo-Brazzaville)
23
2015
Qatar
Barzan condensate
50
2016
Angola
Cabaca Norte-1
40
2016
Saudi
Hasbah (Wasit)
30
2016
Angola
Cabaca SE
40
2016
Saudi
Shaybah NGL (non-associated)
275
2016
Angola
Block 0 Offshore
150
2016
UAE
Shah Sour Gas - condensate
25
2015
Angola
Mostrado, Cola, Salsa, Manjericao, Cari
80
2018
UAE
Shah Sour Gas - NGL
25
2015
Angola
Kaombo (Gindunga, Canela, Gengibre)
230
2018
Angola
Malange
50
2019
Angola
Chissonga (Block 16)
100
2020
Ecuador
ITT (Ishpingo-Tambococha-Tiputini)
160
2018
Iran
North Azadegan (Phase 1)
75
2016
Iran
Yadavaran (Phase 1)
85
2016
Kuwait
Ratqa
80
2018
Nigeria
Bonga NW
45
2016
Nigeria
Erha North 2
50
2016
Nigeria
Etim/Asasa
60
2016
Nigeria
Uge
80
2018
Nigeria
Zabazaba/Etan
120
2018
Nigeria
Bonga SW & Aparo
225
2020
Nigeria
Egina
200
2020
Saudi
Shaybah Expansion
250
2016
Saudi
Khurais Expansion
300
2017
UAE
Nasr
65
2015
UAE
Satah al Razboot (SARB)
100
2019
116
(Mafumeira Sul)
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
T ABLES
Table 3c MTOMR – WEO Non-OPEC supply comparison
Table 3c
Non-OPEC supply - MTOMR and WEO definitions
(million barrels per day)
Calculation
2005
2010
2015
2016
2017
2018
2019
2020
2021
Medium Term Oil Market Report definitions
48.9
51.8
57.7
57.1
57.0
57.6
58.3
58.9
59.7
Processing gains
2.0
2.1
2.2
2.3
2.3
2.3
2.3
2.4
2.4
Global biofuels
0.6
1.8
2.3
2.4
2.5
2.5
2.6
2.7
2.7
NON-OPEC SUPPLY
NON-OPEC PRODUCTION
(excl. processing gains and biofuels)
1
46.3
47.9
53.1
52.4
52.3
52.8
53.4
53.9
54.6
Crude
2
40.7
41.7
45.4
44.6
44.3
44.6
45.0
45.4
46.1
of which: Condensate
3
1.6
2.3
2.8
2.7
2.8
2.9
3.0
3.1
3.1
Tight oil
4
0.0
0.6
4.6
4.1
3.8
4.1
4.4
4.9
5.5
Un-upgraded bitumen
5
0.4
0.7
1.4
1.6
1.7
1.8
2.0
2.1
2.3
NGLs
6
4.5
5.0
6.2
6.3
6.5
6.6
6.7
6.7
6.8
Syncrude (Canada)
7
0.5
0.8
1.0
1.0
1.0
1.0
1.1
1.1
1.1
CTL, GTL, kerogen oil and additives1
8
0.5
0.5
0.5
0.5
0.5
0.6
0.6
0.6
0.6
World Energy Outlook definitions
NON-OPEC PRODUCTION
(excl. processing gains and biofuels)
46.3
47.9
53.1
52.4
52.3
52.8
53.4
53.9
54.6
44.8
45.4
45.6
45.3
45.2
45.3
45.3
45.2
45.1
38.7
38.1
36.6
36.2
36.0
35.8
35.6
35.4
35.1
6.2
7.3
9.0
9.1
9.3
9.5
9.7
9.8
10.0
1.5
2.5
7.5
7.1
7.1
7.5
8.1
8.7
9.5
=5+7
1.0
1.5
2.4
2.5
2.7
2.9
3.1
3.2
3.4
Tight oil
=4
0.0
0.6
4.6
4.1
3.8
4.1
4.4
4.9
5.5
CTL, GTL, kerogen oil and additives1
=8
0.5
0.5
0.5
0.5
0.5
0.6
0.6
0.6
0.6
=1
Conventional
Crude oil
Natural gas liquids (total)
=2-3-4-5
=3+6
Unconventional
EHOB (incl. syncrude)2
1 CTL = coal to liquids; GTL = gas to liquids.
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
117
© OECD/IEA, 2016
2 Extra-heavy oil and bitumen
T ABLES
Table 4 World Refinery Capacity Additions
Table 4
WORLD REFINERY CAPACITY ADDITIONS
(thousand barrels per day)
2015
2016
Refinery Capacity Additions and Expansions
OECD Americas
OECD Europe
OECD Asia Oceania
FSU
Non-OECD Europe
China
Other Asia
Latin America
Middle East
Africa
2017
2018
2019
240
100
214
40
364
-57
-232
-68
401
-258
-318
46
23
140
244
450
210
417
327
-75
630
270
306
30
52
Total World
1,328
459
1,355
Upgrading Capacity Additions
2
OECD Americas
OECD Europe
OECD Asia Oceania
FSU
Non-OECD Europe
China
Other Asia
Latin America
Middle East
Africa
Total World
143
82
-36
215
116
176
421
173
184
1,473
2020
2021
Total
1
127
20
254
40
45
218
147
851
781
-44
-295
236
50
270
260
205
50
106
440
192
33
705
120
300
464
40
453
530
200
100
280
755
2,167
1,211
558
2,321
786
1,255
1,530
1,787
1,335
7,720
55
128
182
148
240
375
176
410
182
31
85
20
34
80
29
221
50
876
590
163
-41
57
829
95
430
149
133
107
244
670
1,140
40
1,101
329
410
584
127
4,060
Desulphurisation Capacity Additions3
OECD Americas
OECD Europe
OECD Asia Oceania
FSU
Non-OECD Europe
China
Other Asia
Latin America
Middle East
Africa
Total World
60
21
271
20
324
242
190
290
1,419
35
-170
114
35
-56
268
73
97
98
152
102
48
200
95
425
60
209
64
425
194
74
739
42
296
10
80
107
45
500
640
750
757
194
1,304
40
492
1,424
321
306
1,665
182
4,145
118
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
© OECD/IEA, 2016
1 Comprises new refinery projects or expansions to existing facilities including condensate splitter additions. Assumes zero capacity creep.
2 Comprises gross capacity additions to coking, hydrocracking, residue hydrocracking, visbreaking, FCC or RFCC capacity.
3 Comprises additions to hydrotreating and hydrodesulphurisation capacity.
4 New OECD members Chile and Israel are stil l accounted for in Latin America and Middle East, respectively. Estonia and Slovenia have no refineries
T ABLES
Table 4aChanges from last Medium Term
Table 4a World Refinery Capacity Additions:
WORLD REFINERY CAPACITY ADDITIONS:
Report
Changes from Last Medium-Term Report
(thousand barrels per day)
2014
2015
2016
2017
2018
35
-57
-6
-138
-54
-258
-163
46
190
100
99
20
50
30
-30
-115
70
-15
214
325
10
-163
-405
-70
10
5
30
70
-165
-178
-130
54
205
-520
16
440
-108
-110
383
-1,052
66
-225
957
-115
82
20
-50
20
82
-17
142
197
128
112
-85
-33
-150
85
50
-80
66
-107
20
-125
85
-80
20
286
-46
5
-35
21
-170
-30
72
Refining Capacity Additions and Expansions
OECD Americas
OECD Europe
OECD Asia Oceania
FSU
Non-OECD Europe
China
Other Asia
Latin America
Middle East
Africa
Total World
-50
2019
2020
Total
1
271
-315
-71
-22
625
300
464
-10
365
30
691
400
-30
302
51
1,149
1,277
Upgrading Capacity Additions2
OECD Americas
OECD Europe
OECD Asia Oceania
FSU
Non-OECD Europe
China
Other Asia
Latin America
Middle East
Africa
Total World
-112
-207
20
53
22
139
-25
379
80
80
-104
22
135
-82
48
72
-104
-52
20
437
Desulphurisation Capacity Additions3
OECD Americas
OECD Europe
OECD Asia Oceania
FSU
Non-OECD Europe
China
Other Asia
Latin America
Middle East
Africa
Total World
-149
32
275
131
-40
70
5
-78
48
529
-100
17
-209
-82
95
-65
-241
18
-88
80
-100
45
-45
122
-30
297
-35
58
-12
140
-30
421
209
100
309
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
119
© OECD/IEA, 2016
1 Comprises new refinery projects or expansions to existing facilities including condensate splitter additions. Assumes zero capacity creep.
2 Comprises stand-alone additions to coking, hydrocracking or FCC capacity. Excludes upgrading additions counted under 'Refinery Capacity Additions
and Expansions' category.
3 Comprises stand-alone additions to hydrotreating and hydrodesulphurisation capacity. Excludes desulphurisation additions counted under
'Refinery Capacity Additions and Expansions' category.
T ABLES
Table 4b Selected refinery crude distillation project list
Table 4b
SELECTED REFINERY CRUDE DISTILATION PROJECT LIST
OECD Americas
Canada
Mexico
United States
United States
United States
United States
United States
United States
United States
United States
Project
North West Redwater Partnership - Edmonton
Petroleos Mexicanos - Tula Hidalgo
Castleton Commodities - Corpus Christi
Magellan - Corpus Christi
Valero Energy Corp. - Houston
Targa Resources Partners LP - Houston
Marathon Petroleum Co. LLC - Robinson
Flint Hills Resources - Corpus Christi
CHS Inc - McPherson
The Three Affiliated Tribes - Thunder Butte
Petroleum Serv.
Alon Refining - Bakersfield
Martin Midstream Partners - Corpus Christi
Centurion Terminals - Brownsville
Gravity Midstream - Corpus Christi
Calumet Montana Refining - Great Falls
ExxonMobil Refining & Supply Co. - Beaumont
Valero Energy Corp. - St. Charles
Valero Energy Corp. - Port Arthur
Holly Corp. - Woodscross
United States
United States
United States
United States
United States
United States
United States
United States
United States
OECD Europe
France
Total SA - La Mede
Turkey
Socar - Aliaga/Izmir
United Kingdom Total SA - Lindsey Oil Refinery
OECD Asia Oceania
Japan
Showa Shell - Unknown
Japan
Cosmo Oil Co. Ltd. - Yokkoaichi
Japan
Cosmo Oil Co. Ltd. - Chiba
Japan
JX Energy - Unknown
Japan
Taiyo Oil Co. Ltd. - Uknown
Japan
Fuji Oil Co. Ltd. - Unknown
Japan
Idemitsu Kosan Co. Ltd. - Ichihara, Chiba
Japan
Tonen General + Kyokuto - Unknown
South Korea
HyunDai Oil Refinery Co. - Daesan
China
China
Yatong petrochemical - Dongying
China
CNOOC - Zhongjie
China
CNOOC - Shandong Haihua
China
CNOOC - Taizhou
China
Dragon aromatics - Zhangzhou, Fujian
China
PetroChina - Kunming/Anning
China
CNOOC - Huizhou
China
PetroChina - Renqui, huabei
China
CNOOC - Daxie Island, Zhejiang
China
Sinopec - Cangzhou
China
Sinopec - Hainan
China
Huajin Petchem - Lianoning
China
Sinochem - Quanzhou
China
PetroChina - Qingyang
China
Sinopec - Luoyang
China
Sinopec - Shanghai Gaoqiao
China
Sinopec - Jingmen
China
Sinopec/KPC - Zhanjiang
China
PetroChina/PDVSA - Jieyang
FSU
Kazakhstan
Kazmunigas - Pavlodar
Russia
TAIF - Nizhnekamsk
Russia
Rosneft - Ryazan
Russia
Tatneft/Taneko - Nizhnekamsk
120
Capacity
(kbd)
Start
Year
50
40
100
100
90
35
30
16
15
15
2018
2019
2016
2016
2016
2016
2016
2016
2016
2016
65
50
50
35
20
20
20
15
15
2017
2017
2017
2017
2017
2017
2018
2018
2018
-158
214
-100
2016
2018
2016
-34
-63
-100
-121
-13
-13
-20
-72
140
2016
2016
2016
2016
2017
2017
2017
2017
2017
100
70
60
60
37
260
200
100
40
30
100
80
60
30
200
140
100
300
200
2016
2016
2016
2016
2016
2017
2017
2017
2017
2017
2018
2018
2018
2018
2019
2019
2019
2020
2021
50
36
10
140
2018
2016
2016
2017
Country
Project
Other Asia
Chinese Taipei
Chinese Petroleum Corp. - Kaohsiung
Chinese Taipei
Chinese Petroleum Corp. - Ta-Lin
India
Nagarjuna oil Co - Cuddalore
India
BPCL - Kochi, Ambalamugal
India
Indian Oil Co. Ltd. - Barauni
India
Indian Oil Co. Ltd. - Koyali, Gujarat
India
HPCL - Mahul, Mumbai
India
BPCL - Bina
Mangalore Refinery & Petrochemicals Ltd. - Mangalo
India
India
BPCL - Mumbai
India
HPCL/MITTAL (HMEL) - Bathinda (GGSR)
India
Indian Oil Co. Ltd. - Panipat
Malaysia
Petronas - Rapid
Papua New Guinea Puma - Port Moresby/Napa Napa
Viet Nam
Petro vietnam/KPC/Idemitsu Kosan - Nghi Son
Middle East
Bahrain
Bahrain Petroleum Co. - Sitra
Bahrain
Bahrain Petroleum Co. - Sitra
Iran
National Iranian Oil Co. - Persian Gulf Star Refinery
Iran
National Iranian Oil Co. - Persian Gulf Star Refinery
Iran
National Iranian Oil Co. - Siraf (Assaluyeh)
Iran
National Iranian Oil Co. - Persian Gulf Star Refinery
Iran
National Iranian Oil Co. - Abadan
Iran
National Iranian Oil Co. - Siraf (Assaluyeh)
Iran
National Iranian Oil Co. - Abadan
Iraq
Qaiwan - Baizan
Iraq
INOC-ORA - Karbala
Kuwait
Kuwait National Petroleum Co. - Shuaiba
Kuwait
Kuwait National Petroleum Co. - Mina Abdulla
Kuwait
Kuwait National Petroleum Co. - Mina al-Ahmadi
Kuwait
Kuwait National Petroleum Co. - Al-Zour
Oman
Sohar Bitumen Refinery - Sohar
Oman
Oman Refinery Co. - Sohar
Oman
Oman Refinery Co. - Duqm
Qatar
QatarPetroleum - Ras Laffan 2
Saudi Arabia
Saudi Aramco - Sumitomo - Rabigh 2
Saudi Arabia
Saudi Aramco - Jizan
UAE-Dubai
Emirates National Oil Co. - Jebel Ali
Non-OECD Americas
Brazil
Petrobras - Pernambuco State Abreu e Lima
Brazil
Petrobras - COMPERJ
Colombia
Ecopetrol - Barrancabermeja-Santander
Costa Rica
Recope/PetroChina - Limon
Peru
Petroperu SA - Talara, Piura
Venezuela
Petroleos de Venezuela SA - Puerto de la Cruz
Petroleos de Venezuela SA - Santa Inés (Barinas)
Venezuela
Africa
Algeria
Sonatrach - Skikda
Algeria
Sonatrach - Arzew
Algeria
Sonatrach - Algiers
Angola
Sonangol - Lobito
Egypt
MIDOR - Alexandria
Nigeria
Dangote Oil Refining Company - Lagos
Uganda
Total/Tullow/CNOOC - Albertine Graben
Capacity
(kbd)
Start
Year
-205
150
120
120
60
86
70
36
60
60
44
100
300
10
200
2016
2017
2016
2017
2018
2019
2019
2019
2020
2020
2020
2021
2020
2016
2018
365
-262
120
120
120
120
195
120
-195
50
140
-200
184
-119
615
30
82
230
136
50
400
20
2020
2020
2016
2017
2019
2019
2020
2020
2020
2018
2021
2017
2019
2019
2021
2016
2017
2020
2016
2017
2019
2016
115
165
50
65
33
90
40
2018
2021
2021
2021
2019
2018
2020
30
25
21
120
60
500
30
2016
2018
2018
2019
2018
2020
2020
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
© OECD/IEA, 2016
Country
T ABLES
Table 5 World Ethanol Production
Table 5
World Ethanol Production1
(thousand barrels per day)
2014
2015
2016
2017
2018
2019
2020
2021
OECD North America
963
989
976
943
929
924
919
920
United States
934
954
943
913
901
896
892
892
Canada
28
29
26
22
19
19
18
18
85
91
103
112
116
120
124
117
OECD Europe
Austria
4
2
3
3
3
3
3
3
Belgium
5
1
7
7
7
7
7
7
France
14
15
17
18
20
20
21
21
Germany
16
16
16
18
18
18
20
17
Italy
1
2
3
4
4
4
5
5
Netherlands
4
6
6
8
9
9
9
9
Poland
3
5
6
7
7
7
7
7
Spain
8
10
9
9
9
10
10
8
UK
13
14
15
14
14
14
15
15
OECD Pacific
5
6
6
6
6
6
6
6
Australia
5
4
4
4
4
4
4
4
1,054
1,085
1,085
1,061
1,051
1,050
1,050
1,043
2
3
3
3
4
4
4
4
Total OECD
FSU
Non-OECD Europe
2
2
2
2
2
2
2
2
China
48
49
52
52
54
55
56
60
Other Asia
32
42
48
62
71
75
80
87
India
7
11
15
22
26
28
30
35
Indonesia
1
1
1
1
2
2
2
2
Malaysia
0
0
0
0
0
0
0
0
Philippines
2
3
3
4
4
5
5
5
Singapore
1
1
1
1
1
1
1
1
Thailand
18
22
22
28
30
32
33
36
Latin America
526
554
556
578
610
656
687
725
Argentina
12
14
15
16
17
18
18
19
Brazil
495
516
516
534
564
608
637
674
7
8
9
10
11
12
13
13
Middle East
1
1
1
1
1
1
1
1
Africa
2
3
7
10
13
14
15
16
Colombia
Total Non-OECD
Total World
613
654
668
709
754
807
846
896
1,667
1,739
1,753
1,769
1,805
1,857
1,896
1,939
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
121
© OECD/IEA, 2016
1 Volumetric production; to convert to energy adjusted production, ethanol is assumed to have 2/3 energy content of conventional gasoline.
T ABLES
Table 5a World Biodiesel Production
Table 5a
World Biodiesel Production
(thousand barrels per day)
2014
2015
2016
2017
2018
2019
2020
2021
OECD North America
89
91
107
106
108
111
114
115
United States
83
85
100
101
103
105
108
110
Canada
6
6
7
5
5
6
6
6
230
231
228
240
248
253
263
234
6
OECD Europe
Austria
5
5
5
5
6
6
6
Belgium
7
10
7
7
7
7
7
7
France
41
41
38
43
43
43
44
45
Germany
58
52
52
56
56
56
61
51
Italy
8
13
10
10
11
11
13
15
Netherlands
33
27
31
31
33
33
33
27
Poland
14
14
19
19
21
21
22
19
Spain
23
23
25
25
25
28
28
21
UK
5
9
6
8
9
9
9
6
10
11
11
11
11
11
11
11
OECD Pacific
Australia
2
2
2
2
2
2
2
2
329
333
346
357
367
374
387
360
FSU
1
1
1
1
1
1
1
1
Non-OECD Europe
3
3
3
3
3
3
4
3
China
11
14
15
16
18
21
23
24
Other Asia
203
Total OECD
121
95
149
171
181
190
198
India
2
2
3
3
4
4
5
5
Indonesia
53
29
86
103
109
115
120
122
Malaysia
13
12
15
18
19
20
21
22
Philippines
3
3
3
3
4
4
4
4
Singapore
30
27
20
20
21
21
22
23
Thailand
20
22
22
24
24
25
26
26
Latin America
124
122
130
137
146
153
158
161
Argentina
50
36
45
47
49
51
53
54
Brazil
59
70
68
73
79
84
87
89
Colombia
10
10
11
11
11
11
12
12
Middle East
0
0
0
1
1
1
1
1
Africa
4
5
6
8
8
8
10
10
Total Non-OECD
263
241
305
337
359
378
394
404
Total World
592
574
651
694
726
752
782
764
122
M EDIUM -T ERM O IL M ARK ET R EPO RT 2016
This publication reflects the views of the International Energy Agency (IEA) Secretariat but does not
necessarily reflect those of individual IEA member countries. The IEA makes no representation or
warranty, express or implied, in respect to the publication’s contents (including its completeness or
accuracy) and shall not be responsible for any use of, or reliance on, the publication.
This document and any map included herein are without prejudice to the status of or sovereignty
over any territory, to the delimitation of international frontiers and boundaries and to the name of
any territory, city or area.
SECOND EDITION, February 2016.
IEA Publications, 9, rue de la Fédération, 75739 Paris cedex 15
© OECD/IEA, 2016
Printed in France by ISI Print.
(61 2016 01 1E1) ISBN 978-92-64-25122-9; ISSN 2310-4651
Cover design: IEA. Photo credits: © GraphicObsession.
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