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DBS Asian Insights DBS Group Research • May 2016

Oil Prices Bumpy Road Up

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Oil Prices Bumpy Road Up Suvro Sarkar Equity Analyst DBS Group Research [email protected]

Ho Pei Hwa Equity Analyst DBS Group Research [email protected]

Janice Chua Head of Equity Research DBS Group Research [email protected]

Production and additional research by: Asian Insights Office • DBS Group Research go.dbs.com/research @dbsinsights [email protected] Chien Yen Goh Jean Chua Geraldine Tan Martin Tacchi

Editor-in-Chief Managing Editor Editor Art Director

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04 07 08 11 17 23 28 33 36

Executive Summary Demand-Supply Equation Skewed Further Too Much Inventory – The Key Overhang OPEC’s Underwhelming Response US Production Surprisingly Resilient So Far Capex Cuts Will Help Prices in the Long Term China Uncertainty, Global Growth Worries Hurt Demand-Side Sentiment Geopolitical Risks Remain Conclusion

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Executive Summary Prices are hovering around 2004 levels. Since the last meeting of the Organization of the Petroleum Exporting Countries (OPEC) on December 4, 2015, Brent crude oil prices have been weak. So far this year, they have averaged around US$37.30 per barrel, compared to 2015’s average of US$53.60 per barrel. Among the key negative factors behind the slide have been the uncertainty surrounding OPEC’s production stance – Saudi Arabia stopping short of a production cut, while regional rival Iran not even agreeing to a freeze – as well as weak economic data from China in early 2016 that spooked financial markets. Could weaken before recovering. We now expect oil prices to average US$35-40 per barrel in 2016. In the near term, oil prices are likely to stay volatile and could again weaken due to weak demand data, inventory pile-up, and speculative pressures – before recovering somewhat towards the end of the year. While the pace of US interest rate hikes hereon could be slower than initially projected, any subsequent strength in the US dollar will also continue to weigh on oil prices in 2016. The big wild card in our near-term forecasts could be the upcoming meetings between OPEC and non-OPEC producers. The world’s largest oil producers failed to strike a deal to freeze output at the Doha meeting on April 17. It was reported that talks could resume, if Iran agreed to join the freeze at the next OPEC meeting on June 2. While we expect these meetings will only formalise the production freeze outlined earlier by Saudi Arabia and Russia, any talk or suggestion of future production cuts will be watched keenly and could have a big impact on the market. As of now, we believe Iran is unlikely to be a party to this meeting. In 2017, we can expect a mild year-on-year recovery, with oil prices averaging US$4045 per barrel, driven by gradual convergence of oil supply-demand trends. The key changes driving our lower forecasts for oil prices are the wider gap between supply and demand that opened up in 2015, OPEC’s negative stance, the removal of sanctions against Iran, and possibly weaker-than-expected demand from China and other emerging economies. Upside risks in the near term could stem from potential heightened tensions in the Middle East leading to supply-chain disruptions. Longer-term forecasts are more sanguine. We expect oil prices to move upwards at a faster trajectory towards the end of the decade. Firstly, we consider the fact that close to US$380 billion of capital expenditure (capex) has been deferred since the oil-price crash in late 2014, according to research and consultancy firm Wood Mackenzie1, and further deferrals will mean that close to 3 million barrels per day (mmbpd) of supply that was supposed to come onstream by 2020 will now come later. This will help the supply-demand equation as we approach 2020. Also, the need to develop oil production in more expensive areas – and the cost of the most expensive last barrel needed to meet demand – will continue to support oil prices. On the cautious side, we note that technological advances have rendered extraction of oil (read: shale oil) more flexible to demand changes, with a

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shorter lead time to production, and the global focus on climate change will limit the future exploitation of fossil fuels to an extent. Our longer-term oil price forecast is currently around US$55-60 per barrel, but we reckon there could be more upside risk in the medium to long term than downside risk. Oil price forecast scenario Brent hit a high of US$115/bbl on 19-Jun14 before collapsing

We now expect oil prices to average US$35-40 per barrel in 2016

DBS forecast for Brent: 2016 average – US$35-40/bbl 2017 average – US$40-45/bbl Long-term price – US$55-60/bbl

Brent has been hovering around US$35-45/bbl levels, after hitting lows of US$27/bbl in January 2016

Source: Bloomberg Finance L.P., DBS Bank forecasts

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Demand-Supply Equation Skewed Further The gap between demand and supply – how big is it? Despite the low oil prices, global oil supply in 2015 expanded by over 2.1 mmbpd – after expanding by around 2.5 mmbpd in 2014, with both OPEC and non-OPEC sources contributing significantly to the increase. In 2015, most of the increase had come from non-OPEC sources, led by the US shale revolution, but 2016 also saw supply increasing from OPEC sources as they sought to regain lost market share. We see supply flattening out in 2016, with additional supply from Iran offset by some reduction from the US and other high-cost production areas. However, there will still be a gap between supply and demand through 2016, and while it will narrow over the course of the year, it is unlikely to be breached until well into 2017, in our opinion. No spectacular spurt in demand expected. The US Energy Information Administration (EIA) expects oil consumption to grow by 1.1 mmbpd and 1.2 mmbpd in 2016 and 2017, respectively. This is slightly lower than the 1.3 mmbpd demand growth seen in 2015. Oil consumption forecasts have been revised downwards in recent months as doubts over global GDP growth intensified. Slowing GDP growth in China amid economic transformation has been the key downward bias. Thus, despite the prevailing low oil prices, overall global economic conditions do not evoke expectations of a strong oil demand growth scenario. Diagram 1: Global oil production and consumption – trends and forecasts (EIA)

Source: US EIA

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Too Much Inventory – The Key Overhang Oil, oil everywhere; storage tanks are filling up. US crude-oil supplies are at their highest level in more than 80 years while spare storage capacity is dwindling around the globe, leading to fears that crude prices could fall further in the near term. As of end-April, crude-oil inventory in the US breached 540 million barrels, equal to almost 80% of US storage capacity. While more storage tanks are being built across the US and some large tanker ships are being leased to store oil, the new tankers and facilities will take time to be built and therefore, will not be able to deal with the growing supplies in the market. As such, crude oil prices will continue to come under pressure. Diagram 2. Crude-oil inventory in the US

Source: Bloomberg Finance L.P.

Overall OECD inventory levels are rising as well. While US inventory levels are a good barometer of excess oil in the system – given the regular data flow and the fact that the stockpile consumes about 20% of the world’s oil annually – inventory levels in other developed countries have been rising as well. EIA estimates that the Organization for Economic Cooperation and Development (OECD) member-countries’ total commercial oil inventories amounted to 3.04 billion barrels at the end of 2015, the highest end-of-year level on record, and equivalent to roughly 66 days of consumption. OECD oil inventories are projected to rise to 3.24 billion barrels by the end of 2016 and to 3.3 billion barrels by the end of 2017.

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Diagram 3. OECD commercial oil stock – days of supply

Source: EIA

US crude oil supplies are at their highest level in more than 80 years

Clearing this glut could take years. According to EIA data and our estimates, the gap between supply and demand (or in other terms, inventory build) averaged around 0.8 mmbpd in 2014 and 1.8 mmbpd in 2015. If we were to add up the extra barrels of oil being produced since 2014 over and above normal inventory levels, the number would amount to around one billion barrels. This stockpile of a billion barrels (plus the stockpile that will be built in 2016) will thus continue to depress the market well after it has reached some sort of supply-demand equilibrium, probably in 2017. The International Energy Agency (IEA) estimates that the inventory built up from 2014-17 will take at least four years of expected undersupply for it to be absorbed by the market. That would bring us to 2021 – the next decade, in other words. Diagram 4. Oil stocks’ excess build-up and expected drawdown

Source: International Energy Agency, Bloomberg Finance L.P.

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Inventory build-up expected to ease from second half of 2016 onwards… Global oil inventory builds are projected to still average around 1.6 mmbpd in the initial part of 2016, with the builds moderating during the second half of the year as non-OPEC supply growth slows, particularly in the US, because of lower oil prices. …But still difficult to expect any sustained recovery in oil prices. The continuing large inventory build is a major source of risk to oil prices as the capacity of the global storage system to handle such a massive amount of additional supply is unknown. If the global storage capacity is strained, floating storage costs will rise and put pressure on near-term oil prices. Additionally, while oil supply and demand will probably be better matched by 2017 and inventory drawdowns could start by 2018, restoring prices to where they were before the inventory build-up may take a long time, as evident from diagram 4. The excess inventory is also likely to lead to more volatility in the system as these oil stocks can be released rapidly, if held for trading purposes.

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OPEC’s Underwhelming Response OPEC production has been way above 30 mmbpd in recent months. OPEC production has been breaching the 32-mmbpd mark consistently since June 2015, higher than the existing target of 30 mmbpd set by member nations earlier. Iraq and Saudi Arabia have been the key drivers behind the production increase in 2015. Iran has already ramped up production to 3.2 mmbpd from 2.8 mmbpd earlier, and expectations are that it can ramp up to 3.8 mmbpd – levels before the imposition of sanctions – over the next 1-2 years. Diagram 5. OPEC crude output (‘000 bpd) since June 2015

Saudi Arabia

Jun-15

Jul-15

Aug-15

Sep-15

Oct-15

Nov-15

Dec-15

Jan-16

Feb-16

Mar-16

10500

10570

10500

10300

10300

10330

10250

10200

10200

10190

Libya

400

380

355

350

430

375

375

370

370

330

Iraq

4388

4295

4299

4247

4217

4321

4440

4370

4200

4350

Iran

2850

2850

2900

2800

2800

2800

2800

2860

3100

3200

Kuwait

2835

2825

2850

2940

2820

2850

2900

3000

3000

3000

UAE

2900

2800

2950

2950

2970

2940

2940

2970

2980

2890

Qatar

650

670

640

650

640

670

680

650

650

650

Algeria

1100

1100

1105

1100

1100

1100

1100

1100

1110

1100

Angola

1870

1810

1750

1776

1814

1840

1859

1751

1801

1842

Nigeria

1950

1880

1905

1980

2019

1876

1919

2028

1889

1815

Ecuador

540

538

537

544

544

539

533

533

551

551

Venezuela

2486

2490

2490

2500

2500

2480

2476

2466

2451

2440

Total

32469

32208

32281

32137

32154

32121

32272

32298

32302

32358

Source: Bloomberg Finance L.P.

Diagram 6. OPEC monthly production

Note: numbers exclude Indonesia Source: Bloomberg Finance L.P.

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OPEC’s production stance has been difficult to call. The most recent OPEC general meeting held in December 2015 did nothing to limit production targets, as expected. Worryingly, the group abandoned its official production target altogether. This reaffirms OPEC’s ongoing policy – led by Saudi Arabia – to protect market share and slow down highcost producers, a strategy that has not been very successful so far. The only agreement that was reached by the member-states in the last meeting was to meet again on June 2, 2016.

Despite oil prices sliding for more than 18 months, Saudi Arabia has steadfastly refused to cut output

Historically, Saudi Arabia, as the leading producer in OPEC, has adjusted its production during periods of instability in the oil markets in order to restore some balance. However, this time around, there has been a sharp departure from its usual policy. Despite oil prices sliding for more than 18 months, it has steadfastly refused to cut output. The main logic governing decision-making in Saudi Arabia seems to be that cutting output will only help non-OPEC competitors gain more market share, and hence, without reciprocity, OPEC will not take a unilateral stance of cutting production. By allowing oil prices to remain weak, Saudi Arabia is betting that a period of low oil prices will force some of the higher-cost producers in non-OPEC countries – such as US, Russia, and Brazil, which have all turned up their taps in recent years – to blink. To put things into perspective, we have seen non-OPEC output grow by 6 mmbpd since 2008 whereas OPEC output has been capped at 30 mmbpd, even though most OPEC countries have had surplus capacity. Thus, Saudi Arabia believes that if OPEC cuts production targets, it will have to keep cutting as non-OPEC supply will increase and the overall supply situation will not ease.

Highlights of OPEC’s last meeting on December 4, 2015 No production cut agreed upon by members The Group’s official communiqué made no mention of its existing output target of 30 mmbpd, saying it would continue to closely monitor developments Decision on production postponed to next meeting, when the picture will be clearer, with Iranian production coming back Big divide inside OPEC is one reason. Some members inside OPEC – also referred to as the oil price doves – can withstand low oil prices better than the others and they largely consist of the Gulf Cooperation Council (GCC) countries, namely Saudi Arabia, Qatar, Kuwait, and the United Arab Emirates. Others, including Venezuela, Nigeria, Ecuador, Algeria, and Libya, risk plunging into deeper economic and political crisis if the low-oil-price scenario drags on. Adding to this volatile mix is the longstanding regional rivalry between Saudi Arabia and Iran, with Iran unlikely to accept any restrictions on production now that the sanctions against it have been removed. Thus, even if Saudi Arabia were to be more open towards a production cut, Iran would ensure that OPEC, as a cartel, does not have a formal ruling towards that.

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Foreign reserves can help tide OPEC through a period of low oil prices. While many of the OPEC countries will likely run into budget deficit problems in a low-oil-price scenario, especially given that they have been focusing on running social-spending programmes to curb civil unrest, they have built up significant reserves of foreign currency. Saudi Arabia leads the pack, with more than US$600 billion in foreign currency reserves. For 2015, the International Monetary Fund (IMF) estimated the kingdom’s fiscal breakeven price was US$106 per barrel. With the oil price less than half that, Saudi Arabia is running a big deficit. But its sizable reserves could help it to sustain deficits for a few years without borrowing any money. Kuwait could even run a budget surplus with some tweaks in its policy. But fiscal deficits will start to pinch. Financially weaker OPEC countries like Ecuador, Angola, Nigeria, and Venezuela will be under great pressure to ensure oil prices move up quickly before their reserves run out. Even Saudi Arabia has a budget deficit of 20%, one of the highest among OPEC members. But Venezuela has the highest fiscal deficit-to-GDP percentage and its latest budget more than doubles expenditures in 2016, widening a deficit that already stood at 30% of GDP in 2014. This is why we have seen Venezuela take on a leading role to get OPEC and non-OPEC members around the table to start a discussion on production cuts. Diagram 7. Fiscal breakeven estimates for OPEC countries

Note: These are moving numbers and rough guides at best Source: Wall Street Journal, OPEC, IMF, central banks

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Our expectation of some recovery in the oil price towards the latter part of the year thus remains sanguine

Talks between Saudi Arabia and Russia are a good start, if nothing else. Saudi Arabia and Russia, two of the world’s largest oil-producing countries, held surprise talks in Qatar in February 2016 and have agreed to a freeze on crude-oil output. The talks were brokered by Venezuela in a desperate bid to shore up oil prices. Saudi Oil Minister Ali Al-Naimi agreed with the oil ministers of Qatar, Russia, and Venezuela to freeze their output at January levels, provided other major producers followed suit. According to him, this step is “adequate” for the market at this point, as Saudi Arabia still wants to meet the demand of its customers (implying it does not want to lose market share). Markets were, however, hoping for some word on production cuts and were hence disappointed with this result. Production in January was already close to peak levels for Saudi Arabia and at record levels for Russia. So the decision does nothing much to alleviate the supply-demand gap as no one was expecting these countries to increase production any further. We believe these talks – while not really very fruitful – does set the stage for future talks between the big oil-producing countries to think about a process to stabilise and improve the oil market going forward. Our expectation of some recovery in the oil price towards the latter part of the year thus remains sanguine. These talks also provide some support against another steep fall in the oil price from current levels. Iran will have nothing to do with a production freeze. Following the talks in Qatar, oil ministers from Venezuela, Iraq, and Qatar met their Iranian counterpart in Tehran to discuss the production freeze. However, Iran – fresh off the lifting of sanctions – is unlikely to be a participant in this output freeze as it wants to regain lost market share for now. Iran may only consider freezing output once production and exports reach pre-sanctions levels. OPEC, non-OPEC meeting eventually took place on April 17... Nigeria’s Petroleum Minister Emmanuel Kachikwu was the first to announce that some OPEC members plan to meet other oil producers in Russia around March or April, and forecast that the meeting would have a dramatic impact on oil prices. Russian Energy Minister Alexander Novak also commented recently that the meeting between the OPEC group and other leading oil producers about freezing oil output could take place soon, but the plans could exclude Iran. Eventually, the meeting was set for April 17 in Doha, Qatar. …but ended without output freeze deal. The meeting to discuss a potential oil output freeze between 18 OPEC and non-OPEC oil producers fell apart as Saudi Arabia told participants that it wanted all members of OPEC – including an absent Iran – to take part in a freeze. Novak called the Saudi demand “unreasonable”, and expressed disappointment at the lack of a deal, which he had been expecting to be signed. Qatar’s Energy Minister Mohammed al-Sada said, “We concluded we all need time to consult further.” Several

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OPEC sources reportedly commented that talks could resume, if Iran agreed to join the freeze at the next OPEC meeting on June 2. What to expect in next OPEC general meeting? OPEC members are scheduled to meet on June 2 to discuss output policies and whether to curb production output. The spotlight will likely shine on Iran again. We doubt any consensus can be reached in view of Saudi-Iran tensions and Iran’s determination to regain lost market share. Diagram 8. Recent voices from OPEC participants have been conflicting Date

Country

February 2016 Iran

February 2016 Saudi Arabia

Who

Comments

Bijan Zangeneh, Oil Minister

Vehemently rejects any possibility of Iran stopping increase in oil

Ali al-Naimi, Oil Minister

Ruled out coordinated production cuts across OPEC and non-

production, calls it a joke that countries producing more than 10 mmbpd are calling on others to freeze production. OPEC nations.

Puts faith in market forces to push out inefficient, uneconomic producers.

”We can coexist with US$20 per barrel oil price. We don’t want to, but if we have to, we will.”

February 2016 Iraq

March 2016

March 2016 March 2016

Nigeria

UAE Saudi Arabia

Adel Abdel Mahdi, Oil Minister

Plans to increase oil output to 7 mmbpd over the next five years,

Emmanuel Ibe Kachikwu, Petroleum Minister

Talked about scheduling a meeting in Russia between OPEC and

Suhail Mazrouei, Oil Minister

Output freeze already in place, makes no sense to pump more at

Adel al-Jubeir, Foreign Minister

Saudi Arabia will maintain its oil market share, and the idea that

and export 6 mmbpd.

non-OPEC producers.

Expects dramatic price movement after the meeting. Target of US$50 per barrel oil price current prices

it would cut production while other countries increase it, is not a realistic one.

OPEC’s surplus capacity is relatively low, which is one less risk. OPEC’s surplus crude oil production capacity, which averaged 1.6 mmbpd in 2015, is expected to be 1.8 mmbpd in 2016 and 1.6 mmbpd in 2017, according to EIA estimates. Surplus capacity is typically an indicator of market conditions, and surplus capacity below 2.5 mmbpd indicates a relatively tight oil market. However, the continuing inventory build-up, as well as high current and forecast levels of global oil inventories, makes the projected low-surplus capacity less significant.

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Diagram 9. OPEC crude-oil surplus capacity

Source: US EIA

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US Production Surprisingly Resilient So Far Recap – supply glut mainly driven by the US shale-oil revolution. The growth in non-OPEC production since 2008 has been relatively fast, thanks to the US. US production growth over the last five years has frequently outpaced earlier production growth estimates owing to the shale-oil revolution, which is characterised by technological advances and short lead times to production. This has made the US, by far, the leading contributor to nonOPEC crude oil production growth in recent years, followed by Canada and Brazil. Even in 2015, US oil production grew by 0.8 mmbpd by our estimates despite the fall in oil prices, which was supposed to cause a lot of stress for shale-oil players. US production has relented but it’s no sharp falloff. At the start of 2015, most players held the view that Saudi Arabia’s policy of maintaining crude production would push many US tight-oil players out of business. However, production from US tight oil continued increasing in the initial months of 2015 and overall US production peaked out around April at 9.7 mmbpd. This was despite the fall in rig counts, with improving productivity more than making up for it. Since May, US production has gradually declined but production has in no way fallen off the cliff. With month-on-month declines, US production ended the year at around 9.5 mmbpd. On a year-on-year basis, average production in 2015 was still about 9% higher than in 2014. Diagram 10. US crude-oil production trends

Source: Bloomberg Finance L.P.

We believe 2016 could see a decline of around 0.6 mmbpd from 2015 levels. EIA estimates total US production has fallen 0.6 mmbpd since April 2015, to an average of 9.1 mmbpd in February 2016. We expect the month-on-month declines to continue well into 2017 on the back of declining oil prices. The expectation of reduced cash flows in 2016 and

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The prospect of higher interest rates and tighter lending conditions will also limit the availability of capital to many smaller producers

2017 has prompted many US companies to scale back investment programmes, deferring major new capex until a recovery in oil prices is sustained. The prospect of higher interest rates and tighter lending conditions will also limit the availability of capital to many smaller producers, giving rise to distressed asset sales and possibility of consolidation in the industry. Overall US crude oil production is projected to decrease from an average of 9.4 mmbpd in 2015 to 8.7 mmbpd in 2016 and to 8.2 mmbpd in 2017. From 2018 onwards, production is expected to increase again as oil prices start recovering. Rig count has fallen in the US. The total number of rigs drilling for oil and natural gas in the US closed the year 2015 below 700 rigs for the first time since 1999. Rig count in the US as of April 15, 2016 stands at only 440, including 351 rigs probing for oil and a paltry 89 drilling for natural gas, based on Baker Hughes’ data. Oil-field operators have pulled back 77% of the rigs that were operating at the peak of the US oil boom in November 2014 – US rig count has dropped from 1929 on November 21, 2014 to a current low of 440. While the decline in the number of rigs has slowed slightly since the start of the year, the number has fallen by 74 between February 26 and April 15. Diagram 11. The number of oil rigs operating in the US

W-O-W chg Source: Baker Hughes

But productivity has shot up. Productivity gains across the seven main shale-producing areas in the US have been relentless, as drillers apply new, innovative technologies to increase output and reduce drilling time. As a result, new-well oil production per rig – the benchmark for productivity – has surged 41% since October 2014, when the rig count began its steep decline. This is not a new phenomenon. Tight oil has boasted steady

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productivity gains of about 34% compound annual growth rate (CAGR) since 2007, as evident from the chart below . These productivity gains have more than offset the decline in drilling rigs so far. Diagram 12. US new-well production per rig mmbpd

Source: Bloomberg Finance L.P., DBS Bank

Productivity gains across the seven main shale-producing areas in the US have been relentless More US projects remain feasible at lower oil prices than earlier anticipated. Another factor that has enabled US tight-oil players to sidestep Saudi Arabia’s attacks: Lower-than-expected breakeven levels. This is partially due to the knock-on effect of productivity gains, since breakeven levels are moving targets. In a report issued by industry consultant Rystad Energy in December 2014, they found breakeven levels of major US shale players to be as low as US$42 per barrel, with an average of about US$58 per barrel. Notwithstanding the fact that Rystad’s estimates assume a breakeven with a 10% internal rate of return (cash breakeven could be even lower), these levels could be more tolerable than the breakeven needed to balance fiscal budgets for OPEC membercountries. With productivity improvements and falling input costs, these costs could right now be significantly lower than estimates.

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Diagram 13. Estimates of breakeven production cost for US shale-oil players are lower than expected US$/bbl

Source: Rystad Energy Research & Analysis

Breakeven prices for shale are falling every year. Wood MacKenzie’s recent analysis shows that the breakeven shale prices for the main players are falling every year. This is a result of both falling well costs and oil recovery per well. A reduction in well costs is due to shorter drilling (increased pad drilling) and completion periods (increased use of zipper fracs). An increase in oil recovery rates has been observed when estimating it at 30 years, with wells decreasing initial decline thanks to better well placement and advances in known completion techniques i.e. modified zipper fracs. We believe future technology advancement could bring down the cost of shale production further. Diagram 14. Estimates for breakeven production cost for US shale-oil players

Source: Rystad Energy Research & Analysis

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And supply is more elastic to price changes. Frackers can also react more flexibly to oilprice shifts compared with conventional exploration & production (E&P), because of the relative ease of bringing new wells into production or shutting flows. Any price-induced reduction of US shale production would thus be short-lived. The industry’s resilience to lower oil prices reduces the power of OPEC to set global prices at higher levels. Top US shale producers are, however, cutting capex. Having said that, lower oil prices have discouraged investment into some of the higher-cost shale projects and this will adversely impact the development of US shale in the longer term. The top US shale producers have announced capex cuts of more than 50% on average for 2016, after reductions of 25% in 2015. Diagram 15. Capex budgets of top US shale producers Top shale oil producers in the US

Capex (US$ bn)

2015

2016

Y-O-Y chg

EOG Resources

4.8

2.4-2.6

-50%

Anadarko Petroleum

5.6

2.8

-50%

Chesapeake Energy

4.0

1.3-1.8

-57%

Cabot Oil & Gas Corp

0.8

0.3

-58%

ConocoPhillips

10.2

7.7

-25%

Concho Resources Inc

2.0

1.2-1.4

-35%

Encana Corporation (USA)

2.0

0.9-1.0

-55%

Apache Corporation

3.6

1.4-1.8

-60%

Hess

4.0

2.4

-60%

Devon Energy

5.3

0.9-1.1

-75%

Marathon Oil

2.8

1.4

-50% Source: Various companies

Thus, the pace of US production growth will slow down in the near term. The capex cut by major shale players in the US is what underpins our assumption that US production will fall in the near term (2016/17); investments in shale are more geared towards production 6-12 months down the line, instead of 4-5 years in the case of conventional oil. However, any increase in oil prices towards the US$50 per barrel mark will likely see shale players hedging their output at these higher levels, which will mean higher-than-expected production coming onstream by the end of the year. But medium-term outlook for shale oil remains robust and will place a cap on any oil-price rebound. In its medium-term outlook report published in 20162, the IEA expects that once the near-term decline in shale-oil production brings the supply-demand equation to a balance by 2017, higher oil prices will again set the wheels in motion for an increase in shale-oil production. By 2021, the agency expects shale-oil production to

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reach 5 mmbpd, compared to 4.2 mmbpd in 2015. In the agency’s words: “In today’s world, anyone who can produce oil sells as much as possible for whatever price can be achieved.” – a very different “free-for-all” market from what we have been used to. Thus, in addition to the huge inventory overhang we discussed earlier, this is the other dampener preventing oil prices from recovering beyond a certain limit over the long term.

International oil majors’ crystal balls have turned a lot cloudier since the second half of 2015

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Capex Cuts Will Help Prices in the Long Term International oil majors’ crystal balls have turned a lot cloudier since the second half of 2015, when oil prices were trading within the US$45-55 per barrel range, and most of them predicted oil to rebound to about US$65 per barrel by 2017/18. Fast forward to January 2016 and none of the oil majors have issued new forecasts for short-term oil prices; US$25-30 per barrel seems to have caught everybody off guard. Supermajors slashed 2016 capex budget by close to 30%... Nonetheless, capex budgets have already been cut substantially since the onset of the oil-price collapse. Capex budgets for 2016 have been slashed by an average of about 30% across our sample from 2014’s quantum, and further cuts have been announced for 2017 and 2018 (see chart below ). This spells more pain for oil & gas service companies in the near term, as less work is likely to be available. …as well as OPEX. Operating-cost (opex) reductions in 2015 have been substantial as well. For example, ExxonMobil, Chevron, and Shell are estimated to have cut US$7 billion, US$4 billion, and US$4 billion in operating costs, respectively in 2015 alone – or a 10-17% reduction. Additionally, ExxonMobil has disclosed a 20-50% savings rate on offshore rig charters in the first nine months of 2015, which is unsurprising given that we have seen offshore supply vessel (OSV) day rates mirror this and tumble by at least as much. Investment in deepwater not completely dried up. One interesting point to note is that not everybody is turning his back on deepwater exploration, which entails higher costs for extraction per barrel. Shell is planning to focus on deepwater E&P after its merger with BG Group; BP plans to maintain deepwater as a piece of its portfolio. We believe this is moderately encouraging for service players in the deepwater space as it signals that deepwater work will not dry up completely. On the following pages, we give a brief update on the state of upstream E&P strategy across key international oil majors, a recap of projects that they have deferred or cancelled in light of depressed oil prices, a summary of estimated opex reductions that have been achieved so far, as well as their executives’ view on the direction of oil prices over the near or long term, where available. Diagram 16. Capex budgets for selected oil majors

Source: Bloomberg Finance L.P.

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Diagram 17. Summary of oil majors’ strategies and recent actions Oil major Exxon Mobil

Recent take on oil prices

E&P strategy

Project deferments/ cancellations

OPEX

N/A

Aims to improve profitability through higher-margin production growth: Doubling US onshore liquids production. Pursuing only high-quality resources with stable, competitive fiscal terms. Eleven projects due for start-up between 2015 December quarter and 2017.

N/A

Achieved US$8.5 billion in opex reductions for full-year 2015. In September quarter 2015, ExxonMobil disclosed that opex savings on offshore rig spending has been the largest in percentage terms, ranging from 20-50%.

Chevron N/A

Focus on investments with short cycles, low subsurface risk, and rateable production. Will leverage existing facilities (e.g. infill drilling, workovers).

Deferred plans to drill in the Canadian Arctic indefinitely. Cancelled tender for a rig to drill in the Frade oilfield off Brazil, postponing development drilling.

Opex reductions of approximately US$4 billion on an annual full run rate basis (about 16% reduction yearon-year). About half of this is coming through organisational reviews and portfolio rationalisation, with the other half coming from working through the supply chain.

Shell

“The oil prices we are seeing today are not sustainable and are going to settle at higher levels,” he said, “And higher, in my mind, over the next few decades than the low US$60’s that we require to make this deal [referring to the Shell-BG merger] a good deal.” - CEO Ben van Beurden in January 2016 “It is a very, very volatile business in terms of supply and demand. The oil price responds to very small mismatches between supply and demand.” CEO Ben van Beurden in September 2015

Focusing on liquefied natural gas (LNG) and deepwater after the merger with BG Group, while high-grading its E&P portfolio, picking the most attractive options.

Scrapped the US$6.5 billion petrochemicalplant project with Qatar Petroleum, cancelled the Carmon Creek thermal in-situ project in Canada, sold its Elba LNG project in Savannah, Georgia to Kinder Morgan, and divested its 50% stake in Malaysia’s MLNG Dua project. Shell has also pulled out of its Alaskan drilling programme in the Chukchi Sea, on which it had already spent US$7 billion.

US$4 billion in opex reductions in 2015, representing a 10% decline; 7,500 staff and contractor headcount reductions in 2015. Shell-only opex should reduce by a further US$3 billion in 2016.

BP

“A low point could be in the first quarter [of 2016]. But 2016’s third and fourth quarters could witness a more natural balance between supply and demand, after which stock levels could start to wear off.” - CEO Bob Dudley in January 20163

Still planning to maintain a balance of deepwater, gas and giant fields, with an increasing bias towards gas.

US$10 billion asset divestment plan carried out in 2014/15, with a further US$3-5 billion expected in 2016, before normalising to US$2-3 billion from 2017 onwards. Mad Dog II deepwater project’s final investment decision (FID) was put on hold; project cost estimates now halved to US$10 billion.

Upstream: 10% fewer employees, 42% fewer contractors. Unit production cost (US$/ barrel of oil equivalent, or boe) has reduced by about 20%. Third-party spend has reduced by 15%. Downstream: 40% reduction in head office costs through streamlining and activities. 2015 cash costs US$3.4 billion lower than 2014.

Source: Companies, Newswires, Upstream

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Oil major

Recent take on oil prices

E&P strategy

Project deferments/ cancellations

OPEX

Conoco Phillips

“We believe this downturn could last a while longer. Just a few months ago, we thought the market would rebalance by the second half of 2016. Now it looks like that could stretch into 2017… greater concerns about global growth suggest it could take longer to reach and equilibrium mid-cycle price after balancing occurs.” Chairman and CEO Ryan Lance in February 2016

Exiting deepwater exploration. Shifting E&P capital allocation toward a low cost of supply resource base that is flexible, allowing the company to scale up in a high-oilprice environment and vice versa when prices are low: North American Unconventionals (e.g. tight oil) was highlighted as the most attractive investment type (having more than 25% return on investment, low cost of less than $60/boe, and high flexibility). Conversely it will scale back on lower-return, higher-cost oil sands, North American gas, and LNG projects.

US$2.2 billion Tommeliten Alpha gas development off Norway cancelled. Greater Mooses Tooth 1 Alaskan project deferred; cost would have been approximately US$900 million. 50%-owned Christina Lake oil sands project in Canada has been deferred. All shale projects in China have been suspended.

Opex guidance now lowered to US$7 billion, down from earlier estimates of US$7.7 billion. 2015’s operating expense was US$8 billion.

TOTAL

“We don’t anticipate a recovery in 2016...Having said that, I don’t know if the price will be at US$40, 45, 50, 60. In 2016, the growth of capacity will still be larger than the growth of demand. I am not very optimistic for 2016, beyond that it is difficult to know.” - CEO Patrick Pouyanne in December 2015

Of the US$19 billion in capex estimates for 2016: US$10 billion will go to upstream assets under development, US$4 billion to upstream producing assets, and US$3 billion in downstream. LNG as one of the group’s growth drivers - increasing LNG production capacity by 50% by 2020. LNG to account for 30% of operating income by 2020. No specific guidance on which segments the capex reduction will come from.

Martin Linge in the North Sea has had its start-up date deferred by over a year to January 2018, although engineering issues played a part here. US$34 billion Ichthys LNG mega-project in Australia and Tempa Rossa in Italy reportedly had start-up dates pushed back beyond 2017.

2015 saw US$1.5 billion in opex savings, mainly derived from the upstream business. 2016 opex savings targeted at US$2.4 billion; 2017 opex savings targeted at US$3 billion, up from US$2 billion target set in 2014; almost US$2 billion of the 2017 opex savings will come from the upstream business segment. 30% reduction on rig charter rates, 20% reduction on subsea services and marine logistics.

Statoil

“It’s difficult to predict how the price will develop in the short term. There will probably be volatility and big swings. We firmly believe prices will rise because there is little new production capacity entering the market.” - CEO Eldar Saetre in January 2016

Improved its portfolio of non-sanctioned projects, reducing the average breakeven oil price from US$70 per barrel to US$40 per barrel. “Reshaping our next generation portfolio,” Saetre said in February 2016

Pushed back start-up date of US$7 billion Mariner project in the North Sea from second half of 2017 to second half of 2018. The start-up of the US$4 billion Aasta-Hansteen gas field off Norway has also been delayed to the second half of 2018 from 2017.

‘Efficiency Programme’ targeting approximately US$2.5 billion in annual cash savings in 2016 (from capex and opex). Adjusted opex and selling, general and administrative expenses are down 13% year-on-year in 2015; continued downward trend

ENI

Projecting an average oil price of :

Shifting focus to proven plays and near field exploration. Main exploration activities will be concentrated in North Africa, West Africa, and the Far East. Production growth is planned for a more than 3% growth rate from 2016-2019.

Delayed the spudding on wildcat well on the Dazzler prospect in the Barents Sea off Norway until 2017. Deferred drilling plans at ultra-deepwater Kekra field until late-2016.

Opex per barrel reduced by 13% in 2015, and is targeted to be cut another 3-11% over 2016-2019 from 2015 levels.

• US$45 per barrel for 2016-2017 • US$63 per barrel for 2018-2019

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All these capex cuts will pave the way for higher prices over the longer term. Final investment decisions (FIDs) on 68 large projects globally – totalling US$380 billion in capex – have been deferred since crude prices first plunged in 2014, according to a report by Wood Mackenzie4. These deferrals and capex cuts won’t necessarily translate into significantly lower production in the near term as it’s likely that the most productive projects will go ahead while costs are also likely to decline along with oil prices. The Wood Mackenzie report finds that FIDs on many of the projects have been pushed to 2017 or beyond, with production start-ups currently targeting 2020-23. By 2021, deferred liquids volumes will reach 1.5 mmbpd, Wood Mackenzie projects, and rising sharply to 2.9 mmbpd by 2025. The impact on supply is thus more acutely felt in the medium term as it typically takes 5-7 years to bring a greenfield conventional project into commercial production.

From 8% of global oil demand in 2005, China now accounts for close to 12% of global oil demand

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Diagram 18. List of selected major oil & gas projects deferred / scrapped recently

Company

Project

Location / Area

Description

Type

Est. Capex (US$ bn)

Status

Woodside Petroleum

Browse FLNG

Australia

Development costs came in at more than US$50 billion and studies showed the project would need oil prices of US$50-60 per barrel just to break even.

LNG

40

Shelved

Statoil

Mariner Field

UK North Sea

Production would be delayed from 2017 until the second half of 2018, after development costs rose more than 10% from the original plan.

Oil

7

Deferred

BP

Mad Dog Phase 2

Gulf of Mexico

Originally planned to make a decision by early 2016, now unlikely to make any investment decision until later this year at the earliest, if not in 2017. Tender for semi-subs delayed.

Development

-

Deferred

Shell

Bonga South West

Nigeria

Postponed final investment decision.

Exploration & development

-

Deferred

Chevron

Oleska shale gas field

Ukraine

Chevron lost interest in the western Ukraine shale exploration project after findings in nearby Poland and Lithuania with similar geology showed worse-than-expected reserves.

Shale gas

10

Scrapped

Chevron

Ubon field

Thailand

Delayed sanctioning of project in light of reassessment of development costs by partner PTTEP.

Development

-

Deferred

Chevron

Canadian Arctic drilling

Beaufort Sea, Canada

Cited "economic uncertainty in the industry" as oil prices fell.

Exploration

-

On Hold

Chevron

Shale gas drilling in Poland

Poland

Chevron will discontinue its shale-gas project in Poland as it no longer makes business sense.

Shale gas

-

Scrapped

Shell

Arrow Greenfield LNG

Queensland, Australia

Shell has abandoned its plans for what would have been a fourth coal seam gas-LNG project at Gladstone in Queensland.

LNG

20

Scrapped

Shell

Carmon Creek Phase III and IV

Canada

Slowed down the pace in deepwater. Will delay phase three and four of the Carmon Creek project in Canada.

Upstream

-

Deferred

Premier Oil

Sea Lion

Falkland Island

The Falkland Islands’ first commercial oil discovery will be delayed until crude prices start to recover. It is estimated that the project requires oil price above US$80 per barrel to be economically viable.

Exploration

2

On Hold

Husky

White Rose Extension

Canada

Husky Energy will defer the final investment decision on its offshore West White Rose oilfield extension project for a year.

Development

2.8

Deferred

Source: Upstream, various companies

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China Uncertainty, Global Growth Worries Hurt Demand-Side Sentiment China has been the biggest driver of oil demand for much of the last decade. As China moved into its strongest phase of growth during the last decade, with a big push in manufacturing and infrastructure development, oil demand skyrocketed in the economy. From 8% of global oil demand in 2005, China now accounts for close to 12% of global oil demand. That represents a CAGR of 4.9% over the last ten years, and a slightly slower 4.2% CAGR over the last five years. Compare this with global oil demand growth rates of around 1.2% and you know how important China is to the oil producers. Diagram 19. Growth of oil consumption in China mmbpd p

c



Source: EIA

However, China now stands at a critical juncture. As China gradually transitions from a manufacturing- to a service-based economy, major economic indicators have headed southwards persistently since 2015 without significant signs of recovery. Confidence in the economy has also been shaken by a fall in foreign currency reserves and a very volatile domestic share market. Worries about a huge jump in non-performing loans have also increased. Our economists believe the macroeconomic challenges facing policymakers in China are unprecedented in scale and complexity. Thus, we remain cautious on the growth outlook for China. Although we don’t expect a Lehman-style hard landing for China, the country does not inspire the same confidence as before. Speed of demand growth likely to halve over the next five years. Going by current projections, China’s demand for oil will be growing at 2.5-3.0% over the next five years, roughly half the pace seen in recent times. Global oil experts like EIA and IEA have been downgrading demand numbers for China in recent months to reflect significant changes in its growth patterns, economic policies, and energy efficiency. Policy shifts in China visualise reduced oil demand with the closure of excess capacity in many industries, most notably coal and steel. Government efforts to satisfy tighter clean-air regulations and a

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“new normal” of lower economic growth rates – IMF projects Chinese GDP growth rates of 6.8% and 6.3% in 2015 and 2016, respectively, down from heady 7-8% growth – would also likely result in slower growth in oil demand. Global growth is likely to be slow. The IMF cut its global growth forecasts for 2016 and 2017 by 0.2 percentage points to 3.4% and 3.6%, respectively. While there is some recovery expected from Euro-area countries and Japan, the slowdown in Russia, China, and Latin America will affect the global picture. As a result, global oil demand growth is projected to even come off slightly on absolute terms in 2016 and 2017 from 2015, as highlighted in our earlier section on demand and supply. Structural changes in oil consumption in developed countries to continue. Consumption in areas like Japan and Europe is expected to flatten out or continue declining over the next two years, albeit at a slower rate than in 2014, when there was a marked decline. Developed countries tend to use oil more for transportation than industrial/manufacturing, and hence, oil demand growth is slower. Taxes on oil usage for vehicles and other policy mechanisms also ensure that oil efficiency in these countries improve, thus reducing demand per capita over time. This tends to lower the elasticity of oil demand even in the face of strong economic growth. Moreover, the economies in OECD countries tend to have larger service sectors relative to manufacturing. As a result, strong economic growth in these countries may not have the same impact on oil consumption as it would in non-OECD countries. An increasing shift to electric cars would also spell bad news for oil markets in the longer term, according to a recent Bloomberg analysis – see inset below.

Will 2020s be the decade of the electric car?5 In the next two years, Tesla and Chevy plan to start selling electric cars with a range of more than 200 miles priced in the US$30,000 range. Ford is investing billions, Volkswagen is investing billions, and Nissan and BMW are investing billions. Nearly every major carmaker—as well as Apple and Google—is working on the next generation of plug-in cars. Will this be a problem for oil markets? Electric cars make up 0.1% of all cars today. Most oil majors believe this number will go up to 1% of global car sales by 2040. But what if that number is bigger? It took a gap of 2 mmbpd of oil consumption to cause the current oil price crisis. If sales of electric cars were to take out 2 mmbpd of oil demand again sometime in the future, that could be bad news for oil majors all over again.

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Even amid low oil prices last year, sales of electric vehicles were up 60%. Batteries are the biggest cost component of electric vehicles and battery prices fell 35% last year, thus making possible trajectory whereby electric vehicles could be cost comparable to their fossil fuel counterparts within the next six years, according to Bloomberg’s analysis. This could provide the lift-off for electric vehicle sales in the future. Bloomberg estimates electric vehicles would account for a staggering 35% of new vehicle sales by 2040. Diagram 20. The rise of electric cars

Source: Bloomberg Finance L.P.

Even if the numbers do not pan out the way Bloomberg envisages – as there are a myriad of factors including assumptions on how fast electric vehicle prices need to drop and what kind of supporting infrastructure is needed – it is fair to say that oil markets are currently too sceptical of this trend, and are not really planning for it. Will oil markets be in for another shock in the future? Only time will tell.

A stronger US dollar will also affect the extent to which countries enjoy low oil prices. The US dollar has climbed steadily over the past year, fuelled by expectations of US interest rate hikes and the comparative strength of the US economy relative to other developed countries, particularly Europe. Given that most oil trade is denominated in the US dollar, an appreciating greenback adversely affects import costs in local currencies, which means that some of these countries will not be able to fully reap the benefit of lower oil prices. A focus on the environment and climate change will also have a long-term impact on fossil-fuel exploitation. The burning of fossil fuels – oil, coal, and gas – is the

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cause of one of the biggest challenges facing the world today: Climate change. Extreme weather events, rising oceans, and record-setting temperatures (see inset below) are already becoming a major problem. Greenhouse gas emissions, primarily from the burning of fossil fuels, have already warmed the globe by more than 1°C since the beginning of the Industrial Revolution. The recent global climate agreement in Paris was a major step in recognising the urgency of the crisis, but it will take serious action from governments in both developed and developing countries to meet new goals that aspire to limit global warming to 1.5°C. To meet the goal of even limiting global warming to 2°C, countries will need to limit new fossil-fuel projects and replace some of the existing fossil-fuel production and consumption with cleaner, renewable fuels by the middle of the century. While coal is likely to be the worst-affected fossil fuel, exploitation of oil reserves is likely to take a hit as well, thus limiting the long-term trend of secular oil-price appreciation.

February 2016 was the hottest February on record February 2016 smashed a century of global temperature records by a huge margin, according to data released by National Aeronautics and Space Administration (NASA)6. The NASA data shows the average global surface temperature in February was 1.35°C warmer than the average temperature for the month between 1951 and 1980, a far bigger margin than ever seen before. The previous record, set just one month earlier in January, was 1.15°C above the long-term average for that month. Climate change is usually assessed over years and decades, and 2015 has already shattered the record set in 2014 for the hottest year seen, in data stretching back to 1850. Diagram 21. Change in average temperatures °C

Source: NASA

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According to experts, what these results suggest is that we are far closer than anticipated to breaching the 2°C limit. The United Nations climate summit in Paris in December confirmed 2°C as the limit for dangerous global warming which should not be passed. But it also agreed to “pursue efforts” to limit warming to 1.5°C, a target now looking highly unrealistic.

What did countries agree to in the recent Paris climate summit? The 2015 United Nations Climate Change Conference (known as COP 21 or CMP 11) was held in Paris, France, from November 30 to December 12, 2015. The conference negotiated the Paris Agreement, a global pact on climate change, the text of which represented a consensus of the 196 parties attending it. Highlights of the Paris climate deal are as follows: Calls for holding the increase in the global average temperature to well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5°C above pre-industrial levels. Countries should reach global peaking of greenhouse gas emissions as soon as possible, recognising that peaking will take longer for developing country parties, and to undertake rapid reductions thereafter. The deal requires a global “stock take” — an overall assessment of how countries are doing in cutting their emissions compared to their national plans – every five years, starting in 2023. The deal requires countries to monitor, verify, and report their greenhouse gas emissions using the same global system.

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Geopolitical Risks Remain The Syrian problem could get out of hand. The biggest geopolitical crisis is currently playing out in the Middle East, which holds the largest proportion of the world’s oil reserves. In Syria, what started as a domestic tragedy has now assumed global proportions, with various countries fighting proxy wars in Syria and the surrounding areas. So far, the conflict has had limited impact on oil prices and global markets, but we cannot rule out an expansion of the war and its fallouts. The Syrian war was transformed late last year when Russia started bombing targets that are against Syrian president Bashar al-Assad in Syria; Russia is still trying to expand its influence in Syria in a bid to restore Assad’s grip on the country. This is bad news for Syria’s northern neighbour Turkey, which has been at loggerheads with Russia for ages. Turkey’s attack on Syrian Kurds also threatens to escalate the country’s internal problems with its Kurdish population. While Turkey and Russia haven’t gone headlong into a confrontation yet, the stance of both sides remains aggressive. Diagram 22. Areas under control of various factions in the Syrian civil war as of February 2016

The Saudi-Iranian conflict lurks behind the surface. While Syria and Iraq continue to be the theatres of outright conflict, long-time regional rivals Saudi Arabia and Iran have upped the ante in terms of fighting their own proxy wars in the conflict zone. While Saudi Arabia has been financing Sunni rebels in Syria, Iran has been helping the Shia regime of Assad. If the confrontation intensifies and Saudi warplanes join the war in Syria, the

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opposing forces’ reaction could be unpredictable. It is difficult to rule out attacks on Saudi oil wells by Iranian missiles or Islamic State of Iraq and al-Sham (ISIS) suicide bombers. Saudis may also be tempted to bomb Iranian oil fields. The effect of the brewing tensions is uncertain at this point. In the past, geopolitical tension in the Middle East would usually send oil prices higher by a few dollars per barrel. This risk premium in the price of oil captured the possibility of supply disruptions arising from potential conflicts in the Middle East. However, so far in the current oil price crisis, the global supply glut has loomed much larger than anything else in determining the price of oil, with the events in the Middle East barely registering. What has been more apparent is the simmering tensions manifesting itself into a battle of market share of oil, with both Saudi Arabia and Iran refusing to see eye-to-eye on production cuts. The two rivals have so far been engaged in proxy wars in Syria and even Yemen, supporting opposite sides. As highlighted above, a full-blown confrontation cannot be ruled out entirely and that could have a catastrophic effect on the oil market. The current supply glut of 1-2 mmbpd could be reversed swiftly if oil fields or oil terminals on either side are attacked.

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Conclusion In our previous oil-price reports, we identified several key factors which might have a big impact on price movements. Some of these factors have turned more negative in the last few months, and that is why we are revising downwards our oil-price forecasts. The table below lists how some of these key issues have evolved over the past few months to shape our view of oil prices. Diagram 23. Studying the impact of the key structural issues so far Key Issues

What has happened since our last report

OPEC’s response

No let-up with regards to production from OPEC countries, led by Saudi Arabia. Discarded official production target at last general meeting; not a good sign as far as supply is concerned. Production has consistently been above 32 mmbpd since the second half of 2015, higher than the earlier 30 mmbpd cap set by member nations. Talks with Russia in February led to an agreement to freeze production but Saudi Arabia has so far steered well clear of any talks of a production cut.

Profile of US shale production

Shale-oil production in the US has been declining gradually since April 2015 but not fast enough. US tight-oil production was actually up 9% yearon-year on average in 2015. This is despite a steep decline in the working rig count in the seven regions contributing to the bulk of tight-oil production. Increased productivity per well, lower costs, and price hedges ensured that production has been much more resilient than what the market (or the Saudis) were looking for. Given the relatively short lead time and fast decline rates of shale-oil wells, the profile of shale production is much more flexible and can adjust to price movements faster than conventional oil. Thus, shale oil could be the swing producer in the current scenario and limit price volatility.

Inventory build-up

The gap between supply and demand continued to be very wide through 2015. US crude inventories reached new peak levels of 541 million barrels as of end-April. Overall, OECD inventory levels continue to rise (from 59 days at end-2014 to about 66 days of supply as of end-2015, and will thus continue to exert pressure on oil prices in the future.

Structural changes in global oil demand

Lower oil prices have not resulted in any significant pickup in demand. The gap between supply and demand was more than 2 mmbpd in 2015 and should still be around 0.5-1 mmbpd in 2016, despite assumed production cuts in the US. A balance in demand-supply could only be achieved in 2017 and beyond, according to current estimates.

Impact

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Key Issues

What has happened since our last report

The role of China in oil demand

China is still expected to add around 0.3 mmbpd of oil demand in 2015/16, but is no longer the big driver. Economic data coming out of China has not been particularly strong. The plunge in domestic stock markets and the possibility of further devaluation of the Chinese yuan continue to stoke fears of a hard landing for the world’s second-largest economy and a collapse in demand for commodities.

US dollar strength

Following the US Federal Reserve’s first rate hike in December 2015, views differ on how quickly the Fed funds rate will climb in 2016. Consensus currently sees the rate heading to 1% by end-2016, while our economist expects a faster pace, rising 25 basis points per calendar quarter – lifting rates to 1.5% by the end of the 2017 March quarter. A fast rise in US rates and the corresponding strength in the US dollar could be further negatives for oil prices.

Geopolitical issues

Intensification of the conflict in the Middle East – Syria, Iraq, and Yemen – where various parties like Saudi Arabia, Iran, Turkey, Russia, and the US are also playing their own proxy wars, could cause a sharp uplift in oil prices if oil wells and oil transfer facilities are attacked by either side in a direct confrontation.

Response from global oil majors

Capex budgets have already been cut substantially since the onset of the oil price collapse. Capex budgets for 2016 have been slashed by an average of 25% across our sample from 2014’s quantum, and further cuts have been announced for 2017 and 2018. This should gradually lead to restoration of the supply-demand balance in the future.

Impact

Source: DBS Bank

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References 1

http://www.woodmac.com/media-centre/12530462

2

http://www.iea.org/bookshop/718-Medium-Term_Oil_Market_Report_2016

3

http://www.reuters.com/article/us-bp-dudley-prices-idUSKBN0UG04K20160102

4

http://www.woodmac.com/media-centre/12530462

5

http://www.bloomberg.com/features/2016-ev-oil-crisis/

6

http://data.giss.nasa.gov/gistemp/

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Disclaimers and Important Notices The information herein is published by DBS Bank Ltd (the “Company”). It is based on information obtained from sources believed to be reliable, but the Company does not make any representation or warranty, express or implied, as to its accuracy, completeness, timeliness or correctness for any particular purpose. Opinions expressed are subject to change without notice. Any recommendation contained herein does not have regard to the specific investment objectives, financial situation and the particular needs of any specific addressee. The information herein is published for the information of addressees only and is not to be taken in substitution for the exercise of judgement by addressees, who should obtain separate legal or financial advice. The Company, or any of its related companies or any individuals connected with the group accepts no liability for any direct, special, indirect, consequential, incidental damages or any other loss or damages of any kind arising from any use of the information herein (including any error, omission or misstatement herein, negligent or otherwise) or further communication thereof, even if the Company or any other person has been advised of the possibility thereof. The information herein is not to be construed as an offer or a solicitation of an offer to buy or sell any securities, futures, options or other financial instruments or to provide any investment advice or services. The Company and its associates, their directors, officers and/or employees may have positions or other interests in, and may effect transactions in securities mentioned herein and may also perform or seek to perform broking, investment banking and other banking or financial services for these companies. The information herein is not intended for distribution to, or use by, any person or entity in any jurisdiction or country where such distribution or use would be contrary to law or regulation.

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