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Medium-Term Market Report 2016

OIL

Market Analysis and Forecasts to 2021

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Medium-Term Market Report 2016

OIL


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FOREWORD

MEDIUM-TERM OIL MARKET REPORT 2016 3

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 re-balancing 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. Dr. Fatih Birol Executive Director International Energy Agency

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ACKNOWLEDGEMENTS

4 MEDIUM-TERM OIL MARKET REPORT 2016

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. For questions and comments, please contact the Oil Industry and Markets Division. For contact information, please see https://www.iea.org/oilmarketreport/contacts/.

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TABLE OF CONTENTS


TABLE OF CONTENTS

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

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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

LIST OF FIGURES 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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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

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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 Global oil demand growth, by region, 2001-21 ..................................................................... 14 Map 2.1 Iran oil and gas fields ............................................................................................................. 65 Map 2.2 Iraq oil infrastructure ............................................................................................................. 68 Map 2.3 Libya oil infrastructure ........................................................................................................... 73 Map 3.1 Crude exports in 2021 and growth in 2015-21 for key trade routes ..................................... 84 Map 4.1 Regional product supply balances in 2015 and 2021 - gasoline/naphtha ........................... 107 Map 4.2 Regional product supply balances in 2015 and 2021 - gasoil/kerosene .............................. 108 Map 4.3 Regional product supply balances in 2015 and 2021 - fuel oil ............................................ 109

LIST OF TABLES

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

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OVERVIEW


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 re-evaluated 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. 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. 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

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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 over-capacity. 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. 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

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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.

Figure ES 1 Global balance base case

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

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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. 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.

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DEMAND


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, 2009-15. 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

2015 2016 2017 2018 2019 2020 2021 2015-21 OECD Americas 24.4 24.4 24.5 24.4 24.4 24.3 24.2 -0.1 OECD Asia Oceania 8.1 8.0 8.0 7.9 7.9 7.9 7.8 -0.3 OECD Europe 13.7 13.7 13.6 13.5 13.4 13.3 13.1 -0.5 FSU 4.9 4.9 4.9 5.0 5.0 5.1 5.2 0.3 Other Europe 0.7 0.7 0.7 0.7 0.8 0.8 0.8 0.1 China 11.2 11.5 11.9 12.4 12.8 13.2 13.6 2.5 Other Asia 12.5 13.0 13.5 14.0 14.4 14.9 15.3 2.8 Latin America 6.8 6.8 6.8 6.9 6.9 7.0 7.1 0.3 Middle East 8.2 8.3 8.5 8.7 9.0 9.2 9.5 1.3 Africa 4.1 4.2 4.4 4.5 4.7 4.8 5.0 0.9 World 94.4 95.6 96.9 98.2 99.3 100.5 101.6 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.

• Our projections are highly vulnerable to uncertainties around oil prices, changing interest rates, the pace of investment in oil supply and geopolitical issues.

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Figure 1.1 Global oil demand growth, by product, 2001-21

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

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.

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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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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

MTOMR 2016, based on IMF January 2016 IMF October 2015 MTOMR 2015, based on

IMF January 2015 2016 3.4% 3.6% 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. 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%.

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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.

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.

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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.

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-to-olefins 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.

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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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 lower-sulphur 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

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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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

1995 2000 2005 2010 2015 2020 2025 New PLDVs 9.5 9.7 9.5 8.3 7.7 6.6 5.2 Average PLDVs 10.8 11.2 11.7 11.6 11.0 9.9 8.7

Note source: PLDVs: Passenger Light-Duty Vehicles.

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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 2015-21, 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 key goals of the 12th 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

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.

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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

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. 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.

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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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

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

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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

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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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 Five-Year 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.

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.

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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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.

Table 1.4 Recent subsidy adjustments

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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Box 1.3 Oil price declines could drive reform of fossil fuel subsidies (continued) Table 1.4 Recent subsidy adjustments (continued)

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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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

2015 2016 2017 2018 2019 2020 2021 2015-21 LPG 0.4 0.4 0.4 0.4 0.4 0.4 0.5 0.1 Naphtha 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 Gasoline 1.0 1.1 1.1 1.1 1.2 1.2 1.3 0.3 Jet/kerosene 0.3 0.3 0.3 0.3 0.4 0.4 0.4 0.1 Gasoil 1.5 1.6 1.7 1.7 1.8 1.9 2.0 0.4 Residual fuel oil 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.0 Others 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.0 Total 4.1 4.2 4.4 4.5 4.7 4.8 5.0 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 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.

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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 consumer-orientated 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 clean-air 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

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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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

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. 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

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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 diesel-generation 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

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.

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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

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 year, according to the 11th 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.

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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) 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.

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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

2015 2016 2017 2018 2019 2020 2021 2015-21 LPG 0.5 0.5 0.5 0.5 0.5 0.6 0.6 0.1 Naphtha 0.4 0.5 0.5 0.5 0.5 0.6 0.6 0.2 Gasoline 1.2 1.2 1.2 1.2 1.2 1.2 1.2 0.0 Jet/kerosene 0.4 0.3 0.3 0.3 0.4 0.4 0.4 0.0 Gasoil 1.0 1.0 1.0 1.0 1.0 1.1 1.1 0.1 Residual fuel oil 0.5 0.4 0.4 0.4 0.4 0.3 0.3 -0.2 Others 1.0 1.0 1.0 1.0 1.1 1.1 1.1 0.1 Total 4.9 4.9 4.9 5.0 5.0 5.1 5.2 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%. 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.

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Figure 1.10 Brazilian oil demand, 2009-21

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. Middle East 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

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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

2015 2016 2017 2018 2019 2020 2021 2015-21 LPG 1.3 1.3 1.3 1.4 1.5 1.6 1.6 0.4 Naphtha 0.1 0.1 0.1 0.1 0.1 0.2 0.2 0.1 Gasoline 1.6 1.6 1.6 1.7 1.7 1.8 1.8 0.2 Jet/kerosene 0.5 0.5 0.5 0.6 0.6 0.6 0.6 0.1 Gasoil 2.2 2.2 2.3 2.4 2.4 2.8 2.8 0.7 Residual fuel oil 1.5 1.5 1.5 1.5 1.5 1.3 1.3 -0.2 Others 1.1 1.1 1.1 1.1 1.1 1.1 1.1 0.1 Total 8.2 8.3 8.5 8.7 9.0 9.2 9.5 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

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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

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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.

Although the default response from shippers to the legislation will be to switch to low sulphur fuels, on-board 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).

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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

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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.

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.

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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 net-exporters 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.

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.

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2. SUPPLY

• 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.

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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 2015-2021, 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 Figure 2.2 Global capacity growth 2015-21

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 awarded below initial budgets. 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. Major new project developments outside of the US are also seeing sharp reductions in cost levels. For example, Statoil reported early this year it had cut development costs at its Johan Castberg discovery by nearly half compared with estimates from 2013.

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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 Figure 2.5 Annual change in capex

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.

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.

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.

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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 non-OPEC 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.

Figure 2.6 Selected sources of non-OPEC supply changes, 2015-21

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. 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.

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Table 2.1 Non-OPEC supply (mb/d)

2015 2016 2017 2018 2019 2020 2021 2015-21 OECD 23.8 23.3 23.3 23.8 24.4 25.0 25.8 2.0

Americas 19.9 19.4 19.4 19.9 20.6 21.1 21.8 1.9 Europe 3.5 3.3 3.3 3.3 3.2 3.2 3.3 -0.2 Asia Oceania 0.5 0.5 0.6 0.7 0.7 0.7 0.7 0.2

Non-OECD 29.3 29.2 29.0 29.0 29.0 28.9 28.8 -0.5 FSU 14.0 13.9 13.8 13.8 13.8 13.8 13.8 -0.2 Europe 0.1 0.1 0.1 0.1 0.1 0.1 0.1 -0.0 China 4.3 4.3 4.2 4.2 4.2 4.1 4.1 -0.2 Other Asia 2.7 2.7 2.7 2.7 2.6 2.6 2.5 -0.2 Americas 4.6 4.6 4.7 4.8 4.9 5.0 5.1 0.6 Middle East 1.3 1.2 1.2 1.2 1.2 1.1 1.1 -0.1 Africa 2.3 2.3 2.3 2.3 2.2 2.1 2.1 -0.3

Non-OPEC ex PG and biofuels 53.1 52.4 52.3 52.8 53.4 53.9 54.6 1.5 Processing Gains 2.2 2.3 2.3 2.3 2.3 2.4 2.4 0.2 Global Biofuels 2.3 2.4 2.5 2.5 2.6 2.7 2.7 0.4 Total-Non-OPEC 57.7 57.1 57.0 57.6 58.3 58.9 59.7 2.0 Annual Change 1.4 -0.6 -0.0 0.6 0.7 0.6 0.8 0.3 Changes from last MTOMR* 1.1 0.1 -0.5 -0.6 -0.5 -0.4

*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.

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.

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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.

Figure 2.7 Non-OPEC production scenarios and impact on global inventories

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. 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.

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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

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.

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.

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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 debt and equity offerings, while in the second half that number fell to USD 7.8 billion.1

Figure 2.11 Average US shale play well performance

Figure 2.12 Average daily production by shale play - 2015 production start year

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.

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.

1 Financial Times, 7 January

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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. 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.

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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 Despite its high investment and operating costs, Canadian oil sands remain a key contributor to non-OPEC 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 2.13 Canada oil production Figure 2.14 Canada oil supply growth

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. 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 mid-2014.

Figure 2.15 Russian oil production

Figure 2.16 Brent price index in USD vs roubles

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.

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.

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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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.

Caspian 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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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 2.17 Kazakhstan oil production Figure 2.18 Azerbaijan oil production

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 Azeri-Chirag-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 2.19 Brazil oil production Figure 2.20 Total non-OPEC Latin America oil production

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. 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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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 API sour crude – to prospective partners, causing delays in the tendering of the FPSO and another unit and also to any significant ramping up of production. 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. 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. 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.

Figure 2.21 Mexico oil production

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North Sea 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 are on track to be commissioned over the forecast period, continued decline at mature fields and a return to more normal shutdown levels are expected to see output fall back from recent highs – until Statoil starts up its major Johan Sverdrup projects towards the end of the decade. Norwegian oil production surprised to the upside in 2015, posting a second consecutive year of growth. Following gains of 50 kb/d in 2014, total oil output expanded by a further 55 kb/d last year, to 1.94 mb/d – a five year 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. 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.

Figure 2.22 North Sea oil production

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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

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. 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.

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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 politics have curbed our outlook for growth from the region compared with last year’s MTOMR. New supplies are nevertheless expected to come from Ghana and Congo, and, towards the end of the decade, from Uganda. Total launched Phase 1 at its Moho Bilondo project in Congo in December, adding 40 kb/d to total production. The company will complete the Moho Nord extension in 2016, adding another 100 kb/d of oil output. Eni is also developing assets in 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.

Figure 2.25 African oil production growth

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In Ghana, Tullow is on track to bring its Tweneboa-Enyenra-Ntomme (TEN) project online in mid-2016. 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. Asia 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

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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. 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. 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 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.

Figure 2.26 China oil production

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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 six-year 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.

Table 2.2 Estimated sustainable crude production capacity (mb/d)

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21 Algeria 1.15 1.12 1.09 1.06 1.04 1.01 0.99 -0.17 Angola 1.81 1.81 1.77 1.81 1.78 1.76 1.8 -0.02 Ecuador 0.56 0.55 0.55 0.55 0.55 0.54 0.53 -0.03 Indonesia 0.69 0.71 0.71 0.69 0.67 0.65 0.63 -0.06 Iran 3.6 3.6 3.7 3.75 3.8 3.9 3.94 0.34 Iraq 4.35 4.35 4.36 4.4 4.45 4.53 4.62 0.27 Kuwait 2.83 2.87 2.91 2.93 2.94 2.9 2.88 0.05 Libya 0.4 0.4 0.43 0.46 0.49 0.53 0.59 0.19 Nigeria 1.91 1.9 1.84 1.75 1.78 1.85 1.85 -0.07 Qatar 0.68 0.67 0.66 0.66 0.66 0.66 0.66 -0.02 Saudi Arabia 12.26 12.31 12.43 12.45 12.44 12.39 12.33 0.07

UAE 2.93 2.97 3.02 3.07 3.12 3.17 3.2 0.27 Venezuela 2.46 2.46 2.44 2.43 2.45 2.44 2.42 -0.04 OPEC 35.64 35.72 35.89 36.02 36.17 36.34 36.44 0.8

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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.

It is difficult, however, to evaluate the real state of Iran’s infrastructure and production capacity. IOCs have had limited access to Iranian data and only Chinese companies have tapped the country’s oil fields during recent years. Our assessment is that Iran made considerable progress in preparing its oil network well before sanctions were eased, which set the stage for a swift increase in 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

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.

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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.

Map 2.1 Iran’s oil and gas fields

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Iranian Central Bank Governor Valiollah Seif has said USD 32 billion of funds would be released post-sanctions. 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 non-nuclear 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%.

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.

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Table 2.3 Iran’s key IPC oil and gas projects

Greenfield Projects – Oil Reserves (billion bbl) Production ('000 b/d) South Azadegan -- Phase 2 25.6 50 Oil Fields Package* 16.7 0 Golshan/Ferdowsi 4.5 / 31.7 0 Darquain Phase 3 2.6 0 Changuleh 2.4 0 South Pars Oil Layer 1.7 – 4.2 0 Brownfield Projects – Oil

Ahwaz-Bangestan 31.6 150 West of Iran Package** 15.7 160 Mansuri-Bangestan 15.1 70 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 Greenfield Projects – Gas Reserves (Bcf) Production (MMcf) North Pars 57,068 0 Kish 55,000 0 Gas Fields Package (a) 42,834 0 Golshan/Ferdowsi 22,500 / 8,800 0 South Pars Phase 11 20,129 0 Khami Fields (eight fields) 13,000 0 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 Gulf Bamdad/Mahan/Parsa 3 Kopeh Dagh Sarakhs/Dusti/Raz 3 Eastern Iran Sistan 1 Taybad Taybad 1 Dezful/Zagros Abadan 1 Lorestan/Zagros Timab/Zahab 2 Fars/Zagros Tudej 1

Caspian Sea Block 24/26/29/Sardar e-Jangal 4

Total No. of Exploration Blocks -- 18

*Sohrab, Arvand, Band-e Karkeh, Jofayr, Sepehr, Susangerd

**Aban, Paydar, West Paydar, Danan, Cheshmeh Khosh, Dalpari, Naft-Shahr, Sumar, Deloran

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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

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.

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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 mid-2015 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. 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. 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

Figure 2.29 Iraq crude capacity

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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. 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. 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. 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.

Figure 2.30 UAE crude capacity

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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. 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 production-sharing 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 pre-qualified 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. 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. 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.

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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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. 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 project in 2014, but has delayed the decision on the estimated USD 12 billion scheme. Companies may be hoping to achieve lower development costs that reflect the decline in oil prices. Oil’s sharp drop has also hit growth prospects in Angola, with capacity in Africa’s second largest producer expected to hover around the 1.80 mb/d level over the forecast period. A 90 kb/d capacity expansion was forecast in the 2015 MTOMR. The country’s ageing offshore oil 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. 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 production-sharing 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.

Figure 2.31 West African crude capacity

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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, 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. 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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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. 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 mid-2014. 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 2015 2016 2017 2018 2019 2020 2021 2015-21 Algeria 469 471 466 464 454 444 439 -30 Angola 70 79 105 118 128 138 140 70 Ecuador 0 0 0 0 0 0 0 0 Indonesia 133 133 133 133 128 123 121 -12 Iran 732 835 878 932 965 983 990 258 Iraq 86 90 90 95 95 100 105 19 Kuwait 310 310 307 305 300 297 297 -13 Libya 35 40 45 50 60 70 75 40 Nigeria 494 473 476 459 444 429 415 -78 Qatar 1,192 1,202 1,231 1,253 1,246 1,250 1,255 63 Saudi Arabia 1,830 1,881 1,920 1,943 1,963 1,985 1,995 165 UAE 856 868 875 882 881 885 884 28 Venezuela 205 200 195 185 180 170 160 -45 Total OPEC NGLs* 6,412 6,582 6,722 6,818 6,843 6,873 6,876 464 Non-Conventional** 265 271 271 271 274 275 275 11 Total OPEC 6,677 6,854 6,993 7,089 7,117 7,149 7,152 475

* Includes ethane.

** Includes gas-to-liquids (GTLs).

Biofuel supply 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

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.

Regional outlook

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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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 gasoline3 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 initiatives4 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. 4

Brazil’s INDC outlines that the share of biofuels in the energy mix will be maximised through stimulating biofuel supply and consumption. 5

20% for captive fleets and public pumps and 30% for transport, agriculture and industrial users.

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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. 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.

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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 cellulosic-ethanol 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-generation6, and public sector financial support to assist with high investment costs in some cases. 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.

6 Co-generation refers to the combined production of heat and power.

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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. 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 medium-term 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 3.1 Regional crude exports, yearly change Figure 3.2 Regional crude imports 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)

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.

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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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 net-import 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 medium-term. 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 re-exported 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.

Figure 3.3 Global demand / supply balance

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.

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 long-term 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 mid-year. 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. 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. 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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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

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. 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-Chirag-Deepwater Gunashli (ACG) complex. 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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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 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.

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.

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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. Domestic refinery expansion to curb Latin American exports 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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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 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

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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 Figure 3.7 Chinese crude imports, 2021

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 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.

Africa FSU Latin America Middle East Others

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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 Figure 3.9 Order book

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.

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.

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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.

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.

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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 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.

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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

2015 2016 2017 2018 2019 2020 2021

Total liquids demand 94.4 95.6 96.9 98.2 99.4 100.4 101.5 of which biofuels 2.3 2.4 2.5 2.5 2.6 2.7 2.7

Total oil demand net of biofuels 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 9.0 9.2 9.4 9.6 9.7 9.7 9.8

Refinery products demand 81.5 82.4 83.4 84.4 85.5 86.4 87.4

Refinery market share 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. 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,

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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

Regional developments OECD 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.

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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 Utilisation rates

2015 2021 Change 2015 2021 Change 2015 2021

North America 21.9 22.6 0.8 18.9 19.5 0.5 87% 86%

Europe 16.0 15.9 0.0 13.6 13.1 -0.4 85% 83%

FSU 7.7 7.9 0.2 6.2 6.2 0.0 82% 78%

China 13.2 15.3 2.2 11.0 12.7 1.7 83% 83%

Other Asia 20.1 21.0 0.9 16.4 17.1 0.7 82% 82%

Middle East 9.3 11.6 2.3 6.9 9.2 2.3 74% 79%

Latin America 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 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 development of cracking margins in North-West Europe (Brent), Singapore (Tapis7) and US Gulf coast (50/50 blend of Maya and Mars).

Figure 4.2 Regional cracking margins Figure 4.3 Margin dynamics

7 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 4.4 Europe middle distillates stocks Figure 4.5 NWE ULSD barges crack vs Brent

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

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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. China takes steps toward deregulation 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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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. 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 due to a non-updated building permit forcing it to temporarily stop construction. PetroChina will also complete the 100 kb/d expansion of its Renqui (Huabei) refinery. Other large refinery projects, such as Sinopec’s 200 kb/d Luoyang expansion and Sinopec/Kuwait Petroleum Corporation’s 300 kb/d Zhanjiang refinery have slipped to 2019 and 2020, respectively. Petrochina/PDVSA’s Jieyang JV has been delayed from 2018 to 2021 and reduced in size as PDVSA suffers from a difficult financial situation, while the Petrochina/Qatar Petroleum 300 kb/d Taizhou project is now only expected to be completed after the forecast period.

Figure 4.8 Share of imports in crude throughputs*

*Imported from other regions, intra-regional flows count as domestic

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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 30-40%, 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 small-scale 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.

• 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 20068– 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. 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 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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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 2015-2021 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. Russia digests the latest tax manoeuver 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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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

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.

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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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)

OECD Americas 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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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 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)

Other Asia 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

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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 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.

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5. TABLES Table 1 World Oil Supply and Demand

1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 2017 2018 2019 2020 2021

OECD DEMANDAmericas 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 24.2Europe 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 13.1Asia Oceania 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

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

NON-OECD DEMANDFSU 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 5.2Europe 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 0.8China 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 13.6Other 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 15.3Latin 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 7.1Middle 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 9.5Africa 4.1 4.1 4.0 4.1 4.1 4.3 4.2 4.1 4.3 4.2 4.4 4.5 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 SUPPLYAmericas 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 21.8Europe 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 3.3Asia 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 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

NON-OECD SUPPLYFSU 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 13.8Europe 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 0.1China 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 4.1Other 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 2.5Latin 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 5.1Middle 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 1.1Africa 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 2.1Total Non-OECD 29.5 29.3 29.2 29.3 29.3 29.2 29.1 29.1 29.1 29.2 29.0 29.0 29.0 28.9 28.8Processing Gains2 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 2.4Global 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 2.7Total Non-OPEC3 57.4 57.5 57.9 57.9 57.7 57.0 56.9 57.1 57.2 57.1 57.0 57.6 58.3 58.9 59.7

OPECCrude3 31.2 32.2 32.4 32.4 32.1OPEC NGLs 6.6 6.7 6.7 6.8 6.7 6.8 6.8 6.9 6.9 6.9 7.0 7.1 7.1 7.1 7.2Total OPEC3 37.7 38.9 39.1 39.1 38.7Total Supply 95.1 96.3 97.0 97.1 96.4

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 34.81 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.

WORLD OIL SUPPLY AND DEMAND(million barrels per day)

Table 1

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Table 1a World Oil Supply and Demand: Changes from last Medium Term ReportReport

1Q14 2Q14 3Q14 4Q14 2014 1Q15 2Q15 3Q15 4Q15 2015 2016 2017 2018 2019 2020

OECD DEMANDAmericas 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 -0.1Europe 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 0.4Asia 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 DEMANDFSU 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 0.1Europe 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 0.0China 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 1.1Other Asia -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 0.3Latin America 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 -0.4Middle East -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 -0.2Africa 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 1.0Total 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

OECD SUPPLYAmericas 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 -0.6Europe 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 0.1Asia 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

NON-OECD SUPPLYFSU -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 0.4Europe 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 0.0China 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 -0.1Other 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 0.1Latin 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 -0.2Middle 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 0.0Africa 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 -0.1Total 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 0.1Processing 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 -0.1Global 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

OPECCrude 0.0 0.0 0.0 0.0 0.0OPEC 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 0.1Total OPEC 0.0 0.0 0.0 0.0 0.0Total Supply 0.2 0.3 0.4 1.2 0.5

Memo items:Call on OPEC crude + Stock ch. 0.1 0.2 -0.2 -0.6 -0.1 0.2 0.7 -0.1 -0.6 0.0 1.2 1.7 1.8 1.8 1.7

Table 1aWORLD OIL SUPPLY AND DEMAND: CHANGES FROM LAST MEDIUM-TERM REPORT

(million barrels per day)

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Table 2 Summary of Global Oil Demand

1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 2017 2018 2019 2020 2021Demand (mb/d)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 24.2Europe 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 13.1Asia Oceania 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 7.8Total 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 45.2Asia 23.4 23.8 23.6 23.9 23.7 24.1 24.6 24.4 24.9 24.5 25.5 26.4 27.3 28.1 28.9Middle 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 9.5Latin 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 7.1FSU 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 5.2Africa 4.1 4.1 4.0 4.1 4.1 4.3 4.2 4.1 4.3 4.2 4.4 4.5 4.7 4.8 5.0Europe 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 0.8Total 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 56.4World 93.5 93.9 95.4 94.9 94.4 94.6 95.0 96.4 96.5 95.6 96.9 98.2 99.3 100.5 101.6of which:

US50 19.3 19.2 19.7 19.4 19.4 19.4 19.3 19.7 19.7 19.5 19.5 19.5 19.5 19.4 19.3Euro5 8.1 8.0 8.3 8.0 8.1 8.0 8.0 8.2 8.0 8.1 8.0 7.9 7.8 7.7 7.6China 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 13.6Japan 4.8 3.9 3.9 4.3 4.2 4.6 3.7 3.9 4.3 4.1 4.0 4.0 3.9 3.9 3.8India 3.9 4.0 3.9 4.1 4.0 4.2 4.3 4.0 4.3 4.2 4.4 4.6 4.8 4.9 5.1Russia 3.4 3.6 3.8 3.6 3.6 3.5 3.5 3.7 3.5 3.6 3.6 3.6 3.7 3.7 3.8Brazil 3.2 3.2 3.2 3.2 3.2 3.0 3.1 3.2 3.2 3.1 3.1 3.1 3.1 3.1 3.2Saudi Arabia 2.9 3.5 3.6 3.1 3.3 2.9 3.4 3.8 3.1 3.3 3.4 3.4 3.5 3.6 3.6Korea 2.5 2.3 2.4 2.6 2.4 2.6 2.4 2.4 2.5 2.5 2.5 2.5 2.5 2.5 2.5Canada 2.4 2.3 2.4 2.4 2.4 2.3 2.3 2.4 2.3 2.3 2.3 2.3 2.3 2.2 2.2Mexico 1.9 1.9 2.0 2.0 2.0 1.9 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.1Iran 1.8 1.9 1.8 1.9 1.8 1.9 1.9 1.9 1.9 1.9 1.9 2.0 2.0 2.1 2.1

Total 65.1 65.1 66.2 65.7 65.5 65.5 65.4 66.7 66.6 66.1 66.7 67.4 67.9 68.4 68.9% of World 69.6 69.3 69.4 69.2 69.4 69.2 68.9 69.2 69.0 69.1 68.9 68.6 68.4 68.0 67.9Annual Change (% per annum)Americas1 1.5 1.6 1.5 -0.5 1.0 0.5 0.2 -0.3 0.9 0.1 0.3 -0.3 0.0 -0.3 -0.5Europe2 3.2 0.9 2.0 0.7 1.7 -0.1 1.0 -1.5 0.4 -0.1 -0.4 -0.8 -0.9 -0.7 -1.4Asia Oceania3 -1.4 -0.4 1.2 -0.7 -0.4 -1.4 -0.6 0.2 -0.1 -1.3 0.0 -0.6 -0.6 -0.7 -0.4Total OECD 1.4 1.0 1.6 -0.2 1.0 0.0 0.3 -0.6 0.6 0.1 -0.2 -0.4 -0.5 -0.6 -0.5Asia 4.3 4.9 6.0 3.3 4.6 2.9 3.3 3.7 4.1 3.5 3.8 3.6 3.4 3.0 2.9Middle East -1.0 2.2 2.1 3.8 1.8 2.5 0.7 3.0 0.6 1.7 2.1 2.9 2.8 2.5 2.6Latin America 0.2 -0.1 -1.2 -2.3 -0.8 -1.2 -0.4 0.2 1.6 0.1 0.5 0.8 0.9 0.7 1.2FSU -1.1 0.7 -1.9 -1.7 -1.0 1.7 -1.6 -0.2 -0.7 -0.2 1.0 1.3 1.5 1.1 1.5Africa 2.1 1.7 2.1 4.2 2.5 4.2 4.2 4.3 3.6 4.1 3.7 3.6 3.5 2.9 3.2Europe 5.4 4.8 2.5 3.4 4.0 2.3 3.7 1.3 2.8 2.5 2.3 1.8 1.8 1.6 1.6Total Non-OECD 2.1 3.0 3.0 2.1 2.6 2.2 1.9 2.7 2.6 2.4 2.8 2.9 2.8 2.4 2.5World 1.8 2.0 2.3 1.0 1.7 1.1 1.2 1.1 1.6 1.2 1.4 1.3 1.2 1.1 1.1Annual Change (mb/d)Americas 0.4 0.4 0.4 -0.1 0.2 0.1 0.1 -0.1 0.2 0.0 0.1 -0.1 0.0 -0.1 -0.1Europe 0.4 0.1 0.3 0.1 0.2 0.0 0.1 -0.2 0.0 0.0 -0.1 -0.1 -0.1 -0.1 -0.2Asia Oceania -0.1 0.0 0.1 -0.1 0.0 -0.1 0.0 0.0 0.0 -0.1 0.0 0.0 0.0 -0.1 0.0Total OECD 0.6 0.5 0.7 -0.1 0.4 0.0 0.1 -0.3 0.3 0.0 -0.1 -0.2 -0.2 -0.3 -0.2Asia 1.0 1.1 1.3 0.8 1.0 0.7 0.8 0.9 1.0 0.8 0.9 0.9 0.9 0.8 0.8Middle East -0.1 0.2 0.2 0.3 0.1 0.2 0.1 0.3 0.0 0.1 0.2 0.2 0.2 0.2 0.2Latin America 0.0 0.0 -0.1 -0.2 -0.1 -0.1 0.0 0.0 0.1 0.0 0.0 0.1 0.1 0.0 0.1FSU 0.0 0.0 -0.1 -0.1 -0.1 0.1 -0.1 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1Africa 0.1 0.1 0.1 0.2 0.1 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.2 0.1 0.2Europe 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 0.0Total Non-OECD 1.0 1.4 1.4 1.0 1.2 1.1 0.9 1.3 1.3 1.1 1.4 1.4 1.4 1.3 1.4World 1.6 1.9 2.2 0.9 1.6 1.0 1.1 1.0 1.5 1.2 1.3 1.3 1.2 1.1 1.1Revisions to Oil Demand from Last Medium Term Report (mb/d)Americas 0.2 0.1 0.4 -0.1 0.1 0.1 0.1 0.2 0.2 0.1 0.1 0.0 0.0 -0.1Europe 0.5 0.3 0.5 0.2 0.3 0.3 0.5 0.4 0.4 0.4 0.4 0.4 0.4 0.4Asia Oceania 0.2 0.2 0.1 0.0 0.1 0.2 0.2 0.1 0.0 0.1 0.1 0.1 0.1 0.0Total OECD 0.8 0.6 0.9 0.1 0.6 0.6 0.7 0.7 0.6 0.7 0.6 0.5 0.4 0.3Asia 0.4 0.7 0.6 0.4 0.5 0.9 0.8 0.7 0.4 0.7 1.0 1.2 1.4 1.5Middle East -0.3 0.0 -0.2 0.0 -0.1 -0.2 -0.2 -0.3 -0.3 -0.2 -0.3 -0.3 -0.3 -0.2Latin America 0.0 -0.1 -0.1 -0.2 -0.1 -0.2 -0.2 -0.2 -0.3 -0.2 -0.3 -0.3 -0.4 -0.4FSU 0.1 0.3 0.3 0.3 0.2 0.2 0.3 0.2 0.1 0.2 0.2 0.2 0.1 0.1Africa 0.0 0.0 -0.1 0.0 0.0 -0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1Europe 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 0.0Total Non-OECD 0.2 0.8 0.5 0.4 0.5 0.7 0.7 0.5 0.0 0.5 0.6 0.8 1.0 1.0World 1.0 1.4 1.4 0.5 1.1 1.4 1.4 1.2 0.6 1.1 1.2 1.3 1.3 1.4Revisions to Oil Demand Growth from Last Medium Term Report (mb/d)World 0.8 1.0 1.2 -0.1 0.8 0.3 0.0 -0.2 0.1 0.0 0.1 0.1 0.0 0.1* France, Germany, Italy, Spain and UK

Table 2SUMMARY OF GLOBAL OIL DEMAND

TABLES


Table 3 World Oil Production 1Q15 2Q15 3Q15 4Q15 2015 1Q16 2Q16 3Q16 4Q16 2016 2017 2018 2019 2020 2021

OPECCrude Oil Saudi Arabia 9.77 10.29 10.27 10.16 10.12 Iran 2.82 2.85 2.87 2.89 2.86 Iraq 3.50 3.94 4.24 4.27 3.99 UAE 2.84 2.87 2.92 2.89 2.88 Kuwait 2.70 2.72 2.76 2.76 2.74 Neutral Zone 0.20 0.09 0.04 0.04 0.09 Qatar 0.67 0.66 0.64 0.67 0.66 Angola 1.77 1.76 1.77 1.76 1.76 Nigeria 1.81 1.77 1.80 1.84 1.80 Libya 0.37 0.46 0.38 0.40 0.40 Algeria 1.11 1.11 1.12 1.11 1.11 Ecuador 0.55 0.55 0.53 0.54 0.54 Venezuela 2.39 2.43 2.40 2.38 2.40 Indonesia 0.67 0.70 0.69 0.69 0.69

Total Crude Oil 31.16 32.21 32.43 32.38 32.05Total NGLs1 6.59 6.66 6.70 6.76 6.68 6.77 6.82 6.88 6.94 6.85 6.99 7.09 7.12 7.15 7.15

Total OPEC2 37.75 38.87 39.13 39.14 38.73NON-OPEC3

OECDAmericas 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 United States 12.76 13.00 13.01 12.93 12.92 12.53 12.43 12.30 12.47 12.43 12.35 12.70 13.13 13.63 14.23 Mexico 2.66 2.56 2.60 2.59 2.60 2.58 2.56 2.50 2.52 2.54 2.47 2.38 2.39 2.42 2.41 Canada 4.56 4.04 4.43 4.42 4.36 4.48 4.28 4.48 4.58 4.46 4.55 4.79 5.03 5.09 5.16 Chile 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01Europe 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 0.91 1.01 0.88 1.02 0.95 1.00 0.95 0.84 0.95 0.94 0.93 0.98 0.98 0.93 0.90 Norway 1.93 1.93 1.91 2.01 1.94 1.96 1.87 1.81 1.89 1.88 1.89 1.79 1.71 1.78 1.91 Others 0.57 0.55 0.55 0.55 0.55 0.54 0.53 0.52 0.52 0.53 0.50 0.49 0.48 0.48 0.47Asia Oceania 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 Australia 0.35 0.36 0.42 0.39 0.38 0.40 0.40 0.40 0.41 0.40 0.47 0.57 0.58 0.58 0.60 Others 0.08 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09 0.09

Total OECD 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 25.79NON-OECDFormer USSR 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 Russia 11.02 11.03 11.04 11.13 11.06 11.18 11.11 11.06 11.01 11.09 10.99 10.94 10.90 10.85 10.78 Others 3.03 2.94 2.88 2.84 2.92 2.84 2.83 2.79 2.81 2.82 2.79 2.73 2.72 2.79 2.83Asia 7.05 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 China 4.29 4.36 4.34 4.33 4.33 4.30 4.30 4.30 4.29 4.30 4.23 4.20 4.18 4.15 4.13 Malaysia 0.75 0.72 0.67 0.70 0.71 0.72 0.73 0.73 0.73 0.73 0.74 0.76 0.76 0.77 0.76 India 0.87 0.86 0.87 0.88 0.87 0.85 0.83 0.83 0.85 0.84 0.83 0.82 0.80 0.78 0.77 Others 1.15 1.15 1.14 1.17 1.15 1.14 1.13 1.12 1.12 1.13 1.11 1.08 1.05 1.02 0.99Europe 0.14 0.14 0.14 0.14 0.14 0.13 0.13 0.13 0.13 0.13 0.13 0.12 0.11 0.10 0.10Latin America 4.61 4.54 4.54 4.56 4.56 4.54 4.56 4.59 4.65 4.59 4.68 4.79 4.89 4.98 5.14 Brazil 2.54 2.50 2.56 2.54 2.53 2.55 2.59 2.63 2.71 2.62 2.74 2.89 3.03 3.16 3.36 Argentina 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.63 0.62 0.63 0.63 0.63 0.61 0.60 0.59 Colombia 1.03 1.03 0.98 1.00 1.01 0.99 0.97 0.96 0.95 0.97 0.93 0.90 0.87 0.85 0.83 Others 0.41 0.38 0.37 0.39 0.39 0.37 0.37 0.37 0.37 0.37 0.38 0.38 0.38 0.37 0.36Middle East4 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 Oman 0.99 1.00 1.01 1.01 1.00 0.98 0.97 0.96 0.96 0.97 0.93 0.92 0.91 0.89 0.88 Syria 0.03 0.03 0.03 0.03 0.03 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 Yemen 0.11 0.04 0.02 0.02 0.05 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 Others 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.19 0.20 0.21 0.21 0.21 0.21Africa 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 Egypt 0.72 0.72 0.73 0.72 0.72 0.71 0.70 0.70 0.69 0.70 0.67 0.64 0.62 0.60 0.58 Equatorial Guinea 0.29 0.29 0.29 0.29 0.29 0.29 0.28 0.28 0.28 0.28 0.28 0.25 0.22 0.21 0.19 Sudan 0.11 0.11 0.10 0.10 0.10 0.09 0.09 0.09 0.09 0.09 0.09 0.08 0.07 0.07 0.06 Others 1.22 1.21 1.18 1.19 1.20 1.20 1.22 1.25 1.29 1.24 1.29 1.31 1.30 1.27 1.23

Total Non-OECD 29.50 29.32 29.16 29.30 29.32 29.23 29.15 29.08 29.14 29.15 29.04 29.00 28.95 28.86 28.82Processing Gains5 2.24 2.24 2.24 2.24 2.24 2.27 2.27 2.27 2.27 2.27 2.29 2.32 2.35 2.37 2.39Global Biofuels 1.82 2.38 2.59 2.40 2.30 1.90 2.39 2.75 2.41 2.36 2.46 2.52 2.60 2.67 2.70TOTAL NON-OPEC2 57.38 57.48 57.88 57.94 57.67 57.01 56.94 57.05 57.25 57.06 57.04 57.65 58.31 58.90 59.70TOTAL SUPPLY 95.13 96.34 97.01 97.08 96.401 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.

Table 3WORLD OIL PRODUCTION


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TABLE 3A: Selected Non-OPEC Upstream Project Start-Ups

OECD Americas 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 OceaniaUSA 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 FSUUSA 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 AsiaCanada 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 Latin AmericaOECD Europe Brazil 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 AfricaUK 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 2018UK Kraken 50 2017 Uganda Albert Basin (Kingfisher) 35 2020UK Western Isles 30 2017

Start Year

Table 3aSELECTED NON-OPEC UPSTREAM PROJECT START-UPS

Country ProjectPeak

Capacity (kbd)

Start Year Country Project

Peak Capacity

(kbd)

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TABLE 3B: Selected OPEC Upstream Project Start-Ups

Crude Oil Projects 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 (Mafumeira Sul) 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

Start Year

Table 3b

Selected OPEC upstream project start-ups

Country ProjectPeak

Capacity (kbd)

Start Year Country Project

Peak Capacity

(kbd)

TABLES


Table 3c MTOMR – WEO Non-OPEC supply comparison

Calculation 2005 2010 2015 2016 2017 2018 2019 2020 2021

NON-OPEC SUPPLY 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 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

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 Conventional 44.8 45.4 45.6 45.3 45.2 45.3 45.3 45.2 45.1

Crude oil =2-3-4-5 38.7 38.1 36.6 36.2 36.0 35.8 35.6 35.4 35.1

Natural gas liquids (total) =3+6 6.2 7.3 9.0 9.1 9.3 9.5 9.7 9.8 10.0

Unconventional 1.5 2.5 7.5 7.1 7.1 7.5 8.1 8.7 9.5 EHOB (incl. syncrude)2 =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 CTL = coal to liquids; GTL = gas to liquids.

2 Extra-heavy oil and bitumen

Table 3cNon-OPEC supply - MTOMR and WEO definitions


Medium Term Oil Market Report definitions

World Energy Outlook definitions

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Table 4 World Refinery Capacity Additions

2015 2016 2017 2018 2019 2020 2021 Total

Refinery Capacity Additions and Expansions1

OECD Americas 364 401 240 100 40 781 OECD Europe -57 -258 214 -44 OECD Asia Oceania -232 -318 23 -295 FSU -68 46 140 50 236 Non-OECD Europe China 244 327 630 270 440 300 200 2,167 Other Asia 450 -75 270 260 192 464 100 1,211 Latin America 210 205 33 40 280 558 Middle East 417 306 52 50 705 453 755 2,321 Africa 30 106 120 530 786

Total World 1,328 459 1,355 1,255 1,530 1,787 1,335 7,720

Upgrading Capacity Additions2 OECD Americas 143 127 55 182 OECD Europe 82 20 128 148 OECD Asia Oceania -36 FSU 215 254 240 375 176 95 1,140 Non-OECD Europe 116 40 40 China 176 45 410 182 34 430 1,101 Other Asia 421 218 31 80 329 Latin America 173 163 85 29 133 410 Middle East 184 147 -41 221 149 107 584 Africa 57 20 50 127

Total World 1,473 851 829 876 590 244 670 4,060

Desulphurisation Capacity Additions3

OECD Americas 60 35 35 OECD Europe 21 -170 114 -56 OECD Asia Oceania FSU 271 73 97 98 268 Non-OECD Europe 20 China 324 152 425 296 60 492 1,424 Other Asia 242 102 10 209 321 Latin America 190 48 40 80 64 74 306 Middle East 290 200 107 425 194 739 1,665 Africa 95 42 45 182

Total World 1,419 500 640 750 757 194 1,304 4,145 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

Table 4

WORLD REFINERY CAPACITY ADDITIONS(thousand barrels per day)

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Table 4a World Refinery Capacity Additions: Changes from last Medium Term Report

2014 2015 2016 2017 2018 2019 2020 Total

Refining Capacity Additions and Expansions1

OECD Americas -50 35 -54 190 100 271 OECD Europe -57 -258 -315 OECD Asia Oceania -6 -163 99 -71 FSU -138 46 20 50 -22 Non-OECD Europe China 30 214 -163 30 -130 440 300 691 Other Asia -30 325 -405 70 54 -108 464 400 Latin America -115 10 -70 -165 205 -10 -30 Middle East 70 10 -178 -520 625 365 302 Africa -15 5 16 30 51

Total World -110 383 -1,052 66 -225 957 1,149 1,277

Upgrading Capacity Additions2 OECD Americas 20 20 OECD Europe -115 82 -50 22 53 OECD Asia Oceania FSU 20 82 -17 142 197 -25 379 Non-OECD Europe China 128 -150 50 20 48 Other Asia -112 112 85 -80 -125 80 72 Latin America -85 85 -104 -104 Middle East -33 66 -107 -80 80 22 -52 Africa 20 20

Total World -207 286 -46 5 139 135 -82 437

Desulphurisation Capacity Additions3 OECD Americas OECD Europe -35 21 -170 -149 OECD Asia Oceania FSU -30 72 32 18 122 Non-OECD Europe China 275 5 17 297 Other Asia 131 -78 -209 -88 209 -35 Latin America -40 48 80 -30 58 Middle East 70 -82 -100 100 -12 Africa 95 45 140

Total World -65 529 -100 -241 -45 309 -30 421 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.

Table 4aWORLD REFINERY CAPACITY ADDITIONS:

Changes from Last Medium-Term Report(thousand barrels per day)

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Table 4b Selected refinery crude distillation project list

Other AsiaCanada North West Redwater Partnership - Edmonton 50 2018 Chinese Taipei Chinese Petroleum Corp. - Kaohsiung -205 2016Mexico Petroleos Mexicanos - Tula Hidalgo 40 2019 Chinese Taipei Chinese Petroleum Corp. - Ta-Lin 150 2017United States Castleton Commodities - Corpus Christi 100 2016 India Nagarjuna oil Co - Cuddalore 120 2016United States Magellan - Corpus Christi 100 2016 India BPCL - Kochi, Ambalamugal 120 2017United States Valero Energy Corp. - Houston 90 2016 India Indian Oil Co. Ltd. - Barauni 60 2018United States Targa Resources Partners LP - Houston 35 2016 India Indian Oil Co. Ltd. - Koyali, Gujarat 86 2019United States Marathon Petroleum Co. LLC - Robinson 30 2016 India HPCL - Mahul, Mumbai 70 2019United States Flint Hills Resources - Corpus Christi 16 2016 India BPCL - Bina 36 2019United States CHS Inc - McPherson 15 2016 India Mangalore Refinery & Petrochemicals Ltd. - Mangalo 60 2020United States 15 2016 India BPCL - Mumbai 60 2020

India HPCL/MITTAL (HMEL) - Bathinda (GGSR) 44 2020United States Alon Refining - Bakersfield 65 2017 India Indian Oil Co. Ltd. - Panipat 100 2021United States Martin Midstream Partners - Corpus Christi 50 2017 Malaysia Petronas - Rapid 300 2020United States Centurion Terminals - Brownsville 50 2017 Papua New Guinea Puma - Port Moresby/Napa Napa 10 2016United States Gravity Midstream - Corpus Christi 35 2017 Viet Nam Petro vietnam/KPC/Idemitsu Kosan - Nghi Son 200 2018United States Calumet Montana Refining - Great Falls 20 2017 Middle EastUnited States ExxonMobil Refining & Supply Co. - Beaumont 20 2017 Bahrain Bahrain Petroleum Co. - Sitra 365 2020United States Valero Energy Corp. - St. Charles 20 2018 Bahrain Bahrain Petroleum Co. - Sitra -262 2020United States Valero Energy Corp. - Port Arthur 15 2018 Iran National Iranian Oil Co. - Persian Gulf Star Refinery 120 2016United States Holly Corp. - Woodscross 15 2018 Iran National Iranian Oil Co. - Persian Gulf Star Refinery 120 2017OECD Europe Iran National Iranian Oil Co. - Siraf (Assaluyeh) 120 2019France Total SA - La Mede -158 2016 Iran National Iranian Oil Co. - Persian Gulf Star Refinery 120 2019Turkey Socar - Aliaga/Izmir 214 2018 Iran National Iranian Oil Co. - Abadan 195 2020United Kingdom Total SA - Lindsey Oil Refinery -100 2016 Iran National Iranian Oil Co. - Siraf (Assaluyeh) 120 2020OECD Asia Oceania Iran National Iranian Oil Co. - Abadan -195 2020Japan Showa Shell - Unknown -34 2016 Iraq Qaiwan - Baizan 50 2018Japan Cosmo Oil Co. Ltd. - Yokkoaichi -63 2016 Iraq INOC-ORA - Karbala 140 2021Japan Cosmo Oil Co. Ltd. - Chiba -100 2016 Kuwait Kuwait National Petroleum Co. - Shuaiba -200 2017Japan JX Energy - Unknown -121 2016 Kuwait Kuwait National Petroleum Co. - Mina Abdulla 184 2019Japan Taiyo Oil Co. Ltd. - Uknown -13 2017 Kuwait Kuwait National Petroleum Co. - Mina al-Ahmadi -119 2019Japan Fuji Oil Co. Ltd. - Unknown -13 2017 Kuwait Kuwait National Petroleum Co. - Al-Zour 615 2021Japan Idemitsu Kosan Co. Ltd. - Ichihara, Chiba -20 2017 Oman Sohar Bitumen Refinery - Sohar 30 2016Japan Tonen General + Kyokuto - Unknown -72 2017 Oman Oman Refinery Co. - Sohar 82 2017South Korea HyunDai Oil Refinery Co. - Daesan 140 2017 Oman Oman Refinery Co. - Duqm 230 2020China Qatar QatarPetroleum - Ras Laffan 2 136 2016China Yatong petrochemical - Dongying 100 2016 Saudi Arabia Saudi Aramco - Sumitomo - Rabigh 2 50 2017China CNOOC - Zhongjie 70 2016 Saudi Arabia Saudi Aramco - Jizan 400 2019China CNOOC - Shandong Haihua 60 2016 UAE-Dubai Emirates National Oil Co. - Jebel Ali 20 2016China CNOOC - Taizhou 60 2016 Non-OECD AmericasChina Dragon aromatics - Zhangzhou, Fujian 37 2016 Brazil Petrobras - Pernambuco State Abreu e Lima 115 2018China PetroChina - Kunming/Anning 260 2017 Brazil Petrobras - COMPERJ 165 2021China CNOOC - Huizhou 200 2017 Colombia Ecopetrol - Barrancabermeja-Santander 50 2021China PetroChina - Renqui, huabei 100 2017 Costa Rica Recope/PetroChina - Limon 65 2021China CNOOC - Daxie Island, Zhejiang 40 2017 Peru Petroperu SA - Talara, Piura 33 2019China Sinopec - Cangzhou 30 2017 Venezuela Petroleos de Venezuela SA - Puerto de la Cruz 90 2018China Sinopec - Hainan 100 2018 Venezuela Petroleos de Venezuela SA - Santa Inés (Barinas) 40 2020China Huajin Petchem - Lianoning 80 2018 AfricaChina Sinochem - Quanzhou 60 2018 Algeria Sonatrach - Skikda 30 2016China PetroChina - Qingyang 30 2018 Algeria Sonatrach - Arzew 25 2018China Sinopec - Luoyang 200 2019 Algeria Sonatrach - Algiers 21 2018China Sinopec - Shanghai Gaoqiao 140 2019 Angola Sonangol - Lobito 120 2019China Sinopec - Jingmen 100 2019 Egypt MIDOR - Alexandria 60 2018China Sinopec/KPC - Zhanjiang 300 2020 Nigeria Dangote Oil Refining Company - Lagos 500 2020China PetroChina/PDVSA - Jieyang 200 2021 Uganda Total/Tullow/CNOOC - Albertine Graben 30 2020FSUKazakhstan Kazmunigas - Pavlodar 50 2018Russia TAIF - Nizhnekamsk 36 2016Russia Rosneft - Ryazan 10 2016Russia Tatneft/Taneko - Nizhnekamsk 140 2017

The Three Affiliated Tribes - Thunder Butte Petroleum Serv.

OECD Americas

Capacity (kbd)

Table 4b

Country Project Start Year Country Project

SELECTED REFINERY CRUDE DISTILATION PROJECT LIST

Capacity (kbd)

Start Year

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Table 5 World Ethanol Production

Table 5World Ethanol Production1

(thousand barrels per day)

2014 2015 2016 2017 2018 2019 2020 2021OECD North America 963 989 976 943 929 924 919 920

United States 934 954 943 913 901 896 892 892Canada 28 29 26 22 19 19 18 18

OECD Europe 85 91 103 112 116 120 124 117Austria 4 2 3 3 3 3 3 3Belgium 5 1 7 7 7 7 7 7France 14 15 17 18 20 20 21 21Germany 16 16 16 18 18 18 20 17Italy 1 2 3 4 4 4 5 5Netherlands 4 6 6 8 9 9 9 9Poland 3 5 6 7 7 7 7 7Spain 8 10 9 9 9 10 10 8UK 14 15 14 14 14 15 15 13

OECD Pacific 5 6 6 6 6 6 6 6Australia 5 4 4 4 4 4 4 4

Total OECD 1,054 1,085 1,085 1,061 1,051 1,050 1,050 1,043FSU 2 3 3 3 4 4 4 4Non-OECD Europe 2 2 2 2 2 2 2 2China 48 49 52 52 54 55 56 60Other Asia 32 42 48 62 71 75 80 87

India 7 11 15 22 26 28 30 35Indonesia 1 1 1 1 2 2 2 2Malaysia 0 0 0 0 0 0 0 0Philippines 2 3 3 4 4 5 5 5Singapore 1 1 1 1 1 1 1 1Thailand 18 22 22 28 30 32 33 36

Latin America 526 554 556 578 610 656 687 725Argentina 12 14 15 16 17 18 18 19Brazil 495 516 516 534 564 608 637 674Colombia 7 8 9 10 11 12 13 13

Middle East 1 1 1 1 1 1 1 1Africa 2 3 7 10 13 14 15 16Total Non-OECD 613 654 668 709 754 807 846 896

Total World 1,667 1,739 1,753 1,769 1,805 1,857 1,896 1,9391 Volumetric production; to convert to energy adjusted production, ethanol is assumed to have 2/3 energy content of conventional gasoline.

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Table 5a World Biodiesel Production

Table 5aWorld Biodiesel Production

(thousand barrels per day)

2014 2015 2016 2017 2018 2019 2020 2021OECD North America 89 91 107 106 108 111 114 115

United States 83 85 100 101 103 105 108 110Canada 6 6 7 5 5 6 6 6

OECD Europe 230 231 228 240 248 253 263 234Austria 5 5 5 5 6 6 6 6Belgium 7 10 7 7 7 7 7 7France 41 41 38 43 43 43 44 45Germany 58 52 52 56 56 56 61 51Italy 8 13 10 10 11 11 13 15Netherlands 33 27 31 31 33 33 33 27Poland 14 14 19 19 21 21 22 19Spain 23 23 25 25 25 28 28 21UK 5 9 6 8 9 9 9 6

OECD Pacific 10 11 11 11 11 11 11 11Australia 2 2 2 2 2 2 2 2

Total OECD 329 333 346 357 367 374 387 360FSU 1 1 1 1 1 1 1 1Non-OECD Europe 3 3 3 3 3 3 4 3China 11 14 15 16 18 21 23 24Other Asia 121 95 149 171 181 190 198 203

India 2 2 3 3 4 4 5 5Indonesia 53 29 86 103 109 115 120 122Malaysia 13 12 15 18 19 20 21 22Philippines 3 3 3 3 4 4 4 4Singapore 30 27 20 20 21 21 22 23Thailand 20 22 22 24 24 25 26 26

Latin America 124 122 130 137 146 153 158 161Argentina 50 36 45 47 49 51 53 54Brazil 59 70 68 73 79 84 87 89Colombia 10 10 11 11 11 11 12 12

Middle East 0 0 0 1 1 1 1 1Africa 4 5 6 8 8 8 10 10Total Non-OECD 263 241 305 337 359 378 394 404Total World 592 574 651 694 726 752 782 764

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

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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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/.

Check out the new and improvedOil Market Report website!

OIL


€80 (61 2016 01 1E1) ISSN 2310-4651 ISBN: 978-92-64-25122-9

9HSTCQE*cfbccj+

Medium-Term Market Report 2016In early 2016 crude oil prices for WTI and Brent fell below USD 30/bbl for the

first time since 2003, having halved in just a few months. In a departure from

the past four decades, producers continue to produce and sell what they can,

letting the market set the price. Low prices are a major short-term benefit to

consumers and will provide a boost to demand growth. But if low prices persist,

investments in new supply are cut back – as has been demonstrated recently

by a succession of announcements from major companies. Unless the heavily

oversupplied oil market can return to balance and high levels of stocks start to

diminish, oil prices cannot rise to the levels necessary to support investments in

the higher cost resources that must be developed to meet rising oil demand. The

result could be a sharp rise in oil prices that risks curtailing economic growth.

In the 2016 edition of its Medium-Term Oil Market Report, the International

Energy Agency analyses the key factors impacting the supply and demand for

oil from today out to 2021. These include: high-cost supply resilience from light,

tight oil producers in the United States; the lifting of nuclear sanctions on Iran;

the impact on demand of lower oil prices – including recent subsidy changes in

the Middle East; and the timing of the oil market’s return to balance. This report

is published during one of the most fascinating periods in oil market history.

Medium-Term Oil Market Report 2016 - iea.org · INTERNATIONAL ENERGY AGENCY The International...

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Transcript of Medium-Term Oil Market Report 2016 - iea.org · INTERNATIONAL ENERGY AGENCY The International...