Regional Oil & Gas Refer to important disclosures at the end of this report Lower 2017 oil price but remain positive on rebalancing.

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1 Refer to important disclosures at the end of this report DBS Group Research. Equity Market rebalancing underway, despite shale Lowering 2017 Brent crude oil price forecast by US$5/bbl; but remain positive on rebalancing in 2H17 and into 2018 US shale productivity gains have stalled while costs look set to rise, setting a higher oil price floor in our view Oil price weakness and reform uncertainties reflected in the recent underperformance of Chinese NOCs; stockpicks: CNOOC>PetroChina>Sinopec Lower 2017 oil price but remain positive on rebalancing. We lower our 2017 Brent crude oil price forecast by US$5/bbl to US$50-55 range, adjusting for the higher-than-expected US shale production. Nonetheless, we are hopeful for recovery in 2H17 as we see more evidence of inventory drawdowns, supported by seasonally higher demand and lower OPEC exports. This rebalancing should accelerate into 2018 and lift average oil price to US$55-60/bbl in We maintain our long-term oil price forecast of US$60-65/bbl as current underinvestment will lead to supply deficit over the next few years, and cost of future marginal sources of oil supply is expected to be around US$63-66/bbl. US shale productivity gains have plateaued and costs look set to rise. Over the last few months, we have seen US shale drilling productivity gains (in bpd per well) stall, especially in the Permian basin. Major US shale producers cash operating costs per barrel have been inching up since 4Q16 as well, adding to evidence that the days of sharp cost reductions are over. We think oil prices in excess of US$50/bbl are required for shale producers to remain profitable, and prices below US$45/bbl may be unsustainable. A good entry point. Chinese NOCs have been underperforming their comparable global peers by c.30%, due to largely priced-in uncertainty amidst ongoing SOEs and energy reforms. CNOOC is the best proxy to ride the recovery of oil prices and upstream seems to be less impacted by reforms. PetroChina is an underappreciated proxy to oil price with imminent catalyst from pipeline divestment. We initiate coverage on Sinopec - a relatively defensive downstream play which benefits from moderated long-term oil prices. 18 Jul 2017 HS8: 26,389 ANALYST Suvro SARKAR suvro@dbs.com Pei Hwa HO peihwa@dbs.com Glenn Ng glennng@dbs.com Recommendation & valuation Company CNOOC (883 HK) Petrochina (857 HK) China Petroleum & Chem (386 HK) Source: Thomson Reuters, DBS Bank Mkt Target Price Cap Price Recom FY17F HK$ US$bn HK$ PE BUY BUY BUY 13.3 CNOOC : CNOOC Ltd is primarily engaged in the upstream exploration, and production of crude oil and natural gas in the offshore space, both in China and overseas. PetroChina : The largest integrated oil and gas company in China China Petroleum & Chem : The second largest vertically integrated oil company in China ed-js & TH/ sa- DL Page 1

2 The DBS Asian Insights SparX report is a deep dive look into thematic angles impacting the longer term investment thesis for a sector, country or the region. We view this as an ongoing conversation rather than a one off treatise on the topic, and invite feedback from our readers, and in particular welcome follow on questions worthy of closer examination. Table of Contents INVESTMENT SUMMARY & KEY CHARTS 2 OIL PRICE RECOVERY 8 The demand-supply equation can only improve hereon 8 But inventory drawdown will be slow at best 9 OPEC adherence to production cuts has been sincere so far 11 US production has again surprised on the upside, but longer term trend could be more benign 15 What is driving shale 38 Cut in global oil &gas capex will have long term positive impact on prices 38 Geopolitical risks not a big mover in our view 40 Stock Profiles 42 CNOOC Limited (883 HK) 42 PetroChina (857 HK) 48 China Petroleum & Chemical (386 HK) 56 Note: Prices used as of 14 Jul 2017 Page 2 Page 2

3 INVESTMENT SUMMARY & KEY CHARTS Lowering our 2017 oil price assumptions by ~US$5/bbl; longterm oil price forecasts unchanged. Brent has averaged around US$52.8/bbl YTD up from the 2016 average of US$45.1/bbl, as prices held up well around the US$50-55/bbl mark in the early months of However, oil prices have been weak of late on renewed concerns in the market regarding the oversupply situation as global inventory levels have remained stubbornly high and US shale production has rebounded. We now expect a move towards the US$55/bbl mark by the end of 2017, thus implying an average of between US$50-55/bbl for the full-year We expect prices to average between US$55-60/bbl in 2018, with the mild y-o-y recovery in oil prices driven by accelerated inventory drawdowns as we move into another year where demand will continue to outstrip supply. Our long-term oil price forecast of US$60-65/bbl remains unchanged and is based on a marginal cost curve analysis. Oil price trends and forecast summary US$ per bbl 140 Brent hit a high of US$115/bbl on 19-J un-14 before collapsing DBS forecast for Brent: 2017 average US$50-55/bbl 2018 average US$55-60/bbl 20 0 Long-term price US$60-65/bbl Brent has been hovering around US$45-50/bbl levels lately, down from early 2017 peak of US$57/bbl Jan-09 Jul-09 Jan-10 Jul-10 Jan-11 Jul-11 Jan-12 Jul-12 Jan-13 Jul-13 Jan-14 Jul-14 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Brent WTI Source: Bloomberg Finance L.P., DBS Bank forecasts Key oil price drivers in the near to long term Near term Negative driver Libya ramping up production, Nigeria to follow? Negative driver US shale production almost back to previous highs Positive driver extension of OPEC production cuts for nine months; filtering of production cuts to actual export cuts hereon Positive driver gradual inventory drawdowns amid seasonally higher demand in the second half and lower y-o-y supply Longer term Positive long-term driver US shale productivity gains have plateaued, costs of US shale starting to rise again Positive long-term driver Two years of major capex cuts and counting; supply deficit will loom large by 2020 Source: DBS Bank Page 3 Page 3

4 Rebalancing to support oil prices. We believe 2017 production should see similar production growth of around 0.4mmbpd similar to 2016 with the roles of OPEC and the US reversed compared to 2016, whereby OPEC production cuts are offset to an extent by rebound in US shale production. On the demand-side, we expect oil consumption to grow by 1.3mmbpd and 1.4mmbpd.in 2017 and 2018, respectively. Given steady demand growth projections, we should see the demand-supply equation finally reaching some sort of balance over the course of 2017 and some inventory drawdowns to start in 2H-2017, and extend into The global oil production and consumption forecast as per EIA is shown in the figure below, which shows the trend of rebalancing. Our supply growth numbers, are however, less aggressive than EIA estimates, and we present our case for possibility of inventory drawdowns in 2017/18 in the table below: PetroChina (H) and CNOOC Ltd (H) TPs lowered by 2.8% and 4.5% respectively, on lower oil price assumptions. As we had previously been using conservative assumptions at the lower end of our forecast range, to adjust to the new forecasts, FY17-FY19 assumed oil prices are lowered by US$2.5/bbl each instead of US$5/bbl (as implied in the lowering of our forecast range). The effect on CNOOC is more pronounced as it is a pure upstream player, whereas PetroChina sees some offsetting effects from its downstream segments. Despite the TP cuts, we continue to like the Chinese oil majors as their valuations look cheap, and on expectations of a gradual recovery in crude oil prices. Maintain BUY on CNOOC (with new TP of HK$10.70) and PetroChina (with new TP of HK$6.63). DBS earnings estimates and TPs for Chinese oil majors after accounting for adjusted oil price forecast: Global oil production and consumption growth and inventory build forecasts - DBS Supply Growth (mmbpd) Demand Growth (mmbpd) Inventory Build (mmbpd) Source: US EIA, DBS estimates (for forecast) Page 4 Page 4

5 DBS earnings estimates and TPs for Chinese oil majors after accounting for adjusted oil price forecast Old New 2017F 2018F 2019F 2020F 2017F 2018F 2019F 2020F Oil price (average) Oil price (average) Revenues: Revenues: - PetroChina 1,749,362 1,803,309 1,908,149 1,925,872 - PetroChina 1,720,084 1,757,723 1,862,861 1,924,435 - Sinopec N/A N/A N/A N/A - Sinopec 2,088,482 2,241,401 2,380,141 2,487,160 - CNOOC Ltd 178, , , ,697 - CNOOC Ltd 170, , , ,854 EBITDA: EBITDA: - PetroChina 297, , , ,854 - PetroChina 293, , , ,538 - Sinopec N/A N/A N/A N/A - Sinopec 179, , , ,717 - CNOOC Ltd 98, , , ,375 - CNOOC Ltd 94, , , ,732 PATMI: PATMI: - PetroChina 46,021 61,728 79,704 81,928 - PetroChina 43,264 56,586 74,225 81,178 - Sinopec N/A N/A N/A N/A - Sinopec 47,082 53,131 57,662 60,923 - CNOOC Ltd 21,307 32,399 41,242 41,477 - CNOOC Ltd 17,799 28,885 37,681 37,809 Target price (HK$/sh) Old New % chg - PetroChina % - Sinopec N/A 7.90 N/A - CNOOC Ltd % Source: Companies, DBS Bank Chinese NOCs underperformance relative to global peers pricing in reform uncertainties. Over the last decade, oil companies have struggled to maintain the high ROEs they once enjoyed, as reserve replacement has proven increasingly difficult and expensive, owing to fewer discoveries of cheap oilfields (lower-hanging fruit has been plucked), and profitability erosion due to persistent cost inflation. This was aggravated by lower oil prices (e.g. in 2009 and 2015, post oil price collapse). As a result of lower profitability, P/B multiples have gradually adjusted downwards; this applies to both the global and Chinese majors CNOOC, Sinopec and PetroChina. The Chinese companies now trade at the low end of the band, underperforming peers by c.30%, which seems unwarranted given their ROEs are at the mid-to-high end of the peer range. We believe this is partly pricing in the uncertainties amidst SOE and energy reforms in China. Big three s market leadership to stay; smaller O&G players will take time to catch up. While the ongoing reforms and liberalisation of the Chinese energy sector might open up the market to more competition, we believe the big three will remain instrumental in developing the O&G sector in China. Their competitive advantages - technical know-how, economies of scale, financial muscle etc - built over the years will set a high barrier to entry for the smaller players. In the near term, potential listing of pipeline and marketing arms by PetroChina and Sinopec respectively could unlock value and catalyse share price. Preference: CNOOC>PetroChina>Sinopec. CNOOC is the best proxy to ride the recovery of oil prices and upstream seems to be less impacted by reforms. PetroChina is an underappreciated proxy to oil price with imminent catalyst from pipeline divestment. We initiate coverage on Sinopec - a relatively defensive downstream play which benefits from moderated long-term oil prices. Page 5 Page 5

6 Big oil has experienced a secular decline in profitability (%) Secular decline in industry ROE, as 'lowerhanging fruit' resources are exploited, and on cost inflation Other large caps used: Shell, Exxon, Total, Chevron, Eni, PTTEP. BP was excluded due to distortions relating to its Deepwater Horizon settlement Other large-cap oil companies - ROE range CNOOC PetroChina Sinopec Source: Bloomberg Finance L.P., Company, DBS Bank estimates P/B valuations for Chinese NOCs seem underperforming global peers (x) Other large-cap oil companies - P/B range CNOOC PetroChina Sinopec Source: Bloomberg Finance L.P., Company, DBS Bank estimates Page 6 Page 6

7 Regional/Global peer comparisons Bloomberg Ticker Market cap (US$m) P/E EV/EBITDA P/B ROE (%) Net D/E Div Yld (%) FYending: FY17F FY18F FY17F FY18F Current FY17F FY18F Current Current Company Integrated oil companies: Exxon Mobil XOM US 344,405 12/ x 19.2x 9.5x 8.9x 1.9x 8.8% 9.7% 0.22x 3.7% Royal Dutch Shell RDSA LN 222,323 12/ x 13.3x 6.2x 5.6x 1.2x 7.6% 8.8% 0.39x 7.2% Chevron CVX US 197,868 12/ x 19.9x 7.6x 6.6x 1.3x 5.1% 6.4% 0.27x 4.1% Total FP FP 124,274 12/ x 11.4x 5.9x 5.3x 1.2x 9.4% 9.8% 0.23x 5.7% BP BP/ LN 115,098 12/ x 14.9x 5.8x 5.1x 1.2x 6.3% 8.2% 0.36x 7.1% PetroChina 857 HK 201,576 12/ x 13.7x 15.6x 12.0x 0.7x 3.6% 4.7% 0.35x 1.4% Sinopec 386 HK 107,120 12/ x 11.8x 4.3x 3.9x 0.9x 6.5% 7.2% 0.06x 4.8% Eni ENI IM 55,161 12/ x 17.3x 4.4x 3.7x 0.9x 4.1% 5.5% 0.28x 6.0% Statoil STL NO 56,581 12/ x 15.2x 3.2x 2.9x 1.5x 9.2% 9.7% 0.46x 5.2% PTT PTT TB 31,939 12/ x 9.9x 5.2x 5.0x 1.4x 12.2% 11.5% 0.19x 4.2% Average: 17.6x 14.7x 6.8x 5.9x 1.2x 7.3% 8.1% 0.28x 4.9% Median: 17.4x 14.3x 5.8x 5.2x 1.2x 7.0% 8.5% 0.28x 5.0% Asian upstream peers: CNOOC Ltd 883 HK 49,718 12/ x 11.6x 4.7x 4.0x 0.9x 4.7% 7.4% 0.36x 4.1% ONGC ONGC IN 31,599 03/ x 7.4x 4.3x 4.0x 0.9x 11.3% 12.0% 0.17x 4.7% Inpex 1605 JP 14,064 03/ x 16.7x 3.9x 2.9x 0.5x 2.0% 3.3% 0.01x 1.7% PTT Exploration & Production PTTEP TB 10,009 12/ x 11.6x 2.8x 2.6x 0.9x 6.5% 7.0% CASH 3.8% Cairn India CAIR IN N/A 03/2016 N/A N/A N/A N/A N/A 4.2% 5.3% CASH 6.2% Average: 16.6x 11.8x 3.9x 3.4x 0.8x 5.7% 7.0% 0.18x 4.1% Median: 16.0x 11.6x 4.1x 3.5x 0.9x 4.7% 7.0% 0.17x 4.1% Asian refining/petrochem peers: Reliance Industries RIL IN 77,548 03/ x 14.6x 11.5x 9.5x 1.7x 9.7% 10.6% 0.53x 0.0% Formosa Petrochemical Corp 6505 TT 32,626 12/ x 18.2x 9.7x 11.2x 3.0x 19.4% 17.0% CASH 5.8% Indian Oil Corpn IOCL IN 28,172 03/ x 8.7x 6.7x 6.2x 1.8x 19.4% 19.3% 0.49x 6.0% Bharat Petroleum Corp BPCL IN 15,543 03/ x 10.9x 8.6x 7.7x 2.9x 24.5% 23.4% 0.73x 2.6% SK Innovation KS 13,849 12/ x 7.5x 4.3x 4.4x 0.9x 12.3% 10.9% 0.04x 3.8% S-Oil Corp KS 10,327 12/ x 9.3x 9.2x 7.5x 1.9x 17.1% 18.2% 0.07x 6.0% Turkiye Petrol Rafinerileri AS TUPRS TI 7,597 12/ x 9.9x 7.6x 7.5x 3.7x 29.1% 25.9% 0.74x 5.8% Idemitsu Kosan 5019 JP 3,876 03/ x 5.3x 8.7x 8.1x 0.7x 12.4% 10.9% 1.72x 1.8% Thai Oil PCL TOP TB 4,765 12/ x 9.8x 5.8x 5.9x 1.4x 15.2% 13.6% 0.14x 5.7% Showa Shell Sekiyu KK 5002 JP 3,768 12/ x 11.1x 7.1x 7.0x 1.9x 16.7% 13.2% 0.37x 3.4% IRPC PCL IRPC TB 3,182 12/ x 9.2x 8.3x 7.4x 1.3x 12.3% 13.1% 0.75x 4.4% Petron Corp PCOR PM 1,782 12/ x 9.1x 6.7x 6.3x 1.0x 14.3% 12.7% 1.72x 1.0% Bangchak Petroleum BCP TB 1,368 12/ x 8.0x 5.2x 5.0x 1.1x 13.2% 13.1% 0.42x 5.4% Average: 10.5x 10.1x 7.6x 7.2x 1.8x 16.6% 15.5% 0.64x 4.0% Median: 10.5x 9.3x 7.6x 7.4x 1.7x 15.2% 13.2% 0.51x 4.4% All comparables average 14.1x 12.1x 6.8x 6.2x 1.4x 11.3% 11.4% 0.44x 4.3% All comparables median 12.5x 11.4x 6.2x 5.9x 1.2x 10.5% 10.8% 0.36x 4.5% Source: Bloomberg Finance L.P., Company, DBS Bank estimates Page 7 Page 7

8 OIL PRICE RECOVERY The demand-supply equation can only improve hereon Rebalancing will happen in Global oil supply growth slowed down significantly in 2016 as the US shale boom took a breather. This comes after two years of supercharged production growth in 2014 and Despite the low oil prices, global oil supply in 2015 expanded by over 2.1 million barrels per day (mmbpd) after expanding by around 2.5mmbpd in 2014 with both OPEC and non-opec sources contributing significantly to the increase. In 2014, majority of the increase had come from non-opec sources, led by the US shale revolution, but 2015 also saw supply increasing from OPEC sources as they sought to regain lost market share. OPEC production increased again in 2016 before an agreement was reached to a cut around end-november which was largely offset by falling production from the US. Overall production increased by about 0.4mmbpd in 2016, compared to demand growth of around 1.4mmbpd, thus tempering the inventory buildup somewhat. Looking forward, we believe 2017 production should see similar production growth of around 0.4mmbpd, with the roles of OPEC and US reversed compared to 2016 OPEC production cut offset to an extent by rebound in US shale production. Given steady demand growth projections, we should see the demand-supply equation finally reaching some sort of balance over the course of 2017, and expect inventory drawdowns to start in 2H Demand likely to hold steady. We expect oil consumption to grow by 1.3mmbpd and 1.4mmbpd.in 2017 and 2018, respectively. This is relatively steady compared to oil demand growth in previous years. Oil consumption forecast for 2017 have been revised slightly downwards owing to possibility of lower demand from India following the demonetisation exercise last year. Chinese demand growth is likely to sustain at around 0.4mmbpd per year in the near term, driven by the transport and petrochemical sectors. The global oil production and consumption forecast as per (EIA) is shown in the chart below, which shows the trend of rebalancing. Our supply growth numbers are however less aggressive than EIA estimates, and we present our case for possibility of inventory drawdowns in 2017/18 in the table below. Global oil production and consumption trends and forecasts (EIA) mmbpd Q12 3Q12 1Q13 3Q13 1Q14 3Q14 World production (mmbpd) 1Q15 3Q15 1Q16 3Q16 1Q17 3Q17 1Q18 3Q18 World consumption (mmbpd) Source: EIA Global oil production and consumption growth and inventory build forecasts - DBS Supply Growth (mmbpd) Demand Growth (mmbpd) Inventory Build (mmbpd) Total US -0.6 OPEC 0.7 Russia Total US 0.4 OPEC -0.4 Kazakhstan 0.1 Canada 0.3 Russia Total US 0.7 Source: EIA, DBS Bank estimates Page 8 Page 8

9 But inventory drawdown will be slow at best US crude inventories at similar levels y-o-y. The US crude oil stocks have not fallen as fast as envisaged earlier, given the attempt of rebalancing in the market, and inventories climbed to seasonal record high levels of close to 540 million barrels (mmbbls) by March 2017, before declining to around 509mmbbls currently. This is still a very high reading for this time of the year, and is almost the same level as in June Thus, the increase in shale production since late 2016 seems to be delaying the expected inventory drawdowns in the US, and this will continue to have a moderating effect on oil prices. The only silver lining is that inventories are not piling on any more and 10 of the last 11 weeks have seen inventory declines, though perhaps not as much as the market predicted. Crude oil inventory in the US mmbbls Jan-2013 Apr-2013 Jul-2013 Oct-2013 Jan-2014 Apr-2014 Jul-2014 Oct-2014 Jan-2015 Apr-2015 Jul-2015 Oct-2015 Jan-2016 Apr-2016 Jul-2016 Oct-2016 Jan-2017 Apr-2017 US Crude Oil Inventories (mmbbls) Source: Bloomberg Finance L.P. Overall OECD inventory levels starting to just slowly thaw. While US inventory levels is a good barometer of excess oil in the system, given the regular data flow and the fact that it consumes about 20% of the world s oil annually, inventory levels in other developed countries remain stubbornly high, at around 3,000mmbbls, significantly higher than the historical OECD commercial crude oil and other liquids inventory (million barrels) average level of around 2,600-2,700mmbbls seen in EIA estimates that total current OECD commercial oil inventories are equivalent to roughly 64 days of consumption, and while there is expected to be some degree of drawdowns in 2H-2017, inventories are not expected to be significantly below the 3,000mmbbls mark anytime soon. OECD commercial oil stocks days of supply mm bbls Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Sep-16 Jan-17 May-17 Sep-17 Jan-18 May-18 Sep-18 Source: EIA EIA projections Days of supply 68 EIA projections Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Sep-16 Jan-17 May-17 Sep-17 Jan-18 May-18 Sep-18 Source: EIA Page 9 Page 9

10 Inventory drawdowns expected to start from 2H17 onwards. Given that supply is expected to grow slower than demand in 2017 and 2018, we expect market rebalancing to occur in 2017 and for the market to go into minor supply deficit situation in 2018, as presented in our projections in the previous section. Thus, we should see sustained evidence of inventory drawdowns in the US and OECD countries in general going forward in 2H17, driven by seasonally higher demand and lower export volumes from the OPEC countries. The trend of inventory drawdowns should accelerate somewhat in This should support our expectations of oil near term oil price recovery from 2H-2017 onwards. But clearing the entire 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 1.1mmbpd in 2014, 1.8mmbpd in 2015 and 0.8mmbpd in If we were to add up the extra barrels of oil produced since 2014 over and above normal inventory levels, it would amount to more than 1 billion barrels. This stockpile of a billion barrels plus will thus continue to depress the market well after the market is in some sort of supply-demand equilibrium (rebalanced), which we expect to happen over the course of The International Energy Agency (IEA) estimates that the inventory build up from will take at least four years of expected undersupply to be absorbed by the market. That would bring us to 2021 the next decade, in other words. And make it difficult to expect any sharp recovery in oil prices. The continuing large inventory buildup is a major source of risk to oil prices as the capacity of the global storage systems to handle such additional supplies 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 market rebalancing had started in 2017 and inventory drawdowns are likely to continue hereon, restoring prices back to where they were before the inventory buildup started may take a long time. 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. Page 10 Page 10

11 OPEC adherence to production cuts has been sincere so far OPEC extends production cuts till March In its most recent general meeting in Vienna in May 2017, OPEC members decided to extend the previously agreed upon production cuts for nine more months from July 2017 to March The decision was taken jointly by the 14 OPEC members and 10 non-opec countries who are participating in the production cuts which started in January The meeting was chaired jointly by the Saudi and Russian representatives. The decision to not deepen production cuts amid stubbornly high inventory levels worldwide seem to have left the market unimpressed, at least in the short term. Decent compliance to production cuts YTD in To recall, in a landmark decision on 30 November 2016, OPEC and non- OPEC countries had jointly agreed to cut production by about 1.8mmbpd from October 2016 reference levels for a 6-month period from January to June 2017, in an attempt to balance the market. OPEC as a whole has been largely compliant in the first five months of 2017, though some countries like Saudi Arabia have cut more than the target while others like Iraq have produced more. However, crucially, we believe OPEC exports YTD in 2017 has not declined as much as production, as previous stockpiles were utilised. Combined with the revival of shale oil production in the US since 4Q16, and the lack of significant inventory drawdowns so far in 2017, we believe the cartel s hand was forced in terms of extending the cuts, in an attempt for the production cuts to actually filter down into exports. OPEC had cut production in the first five months of 2017 in line with agreed levels mmbpd Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Note: Numbers exclude Indonesia and Equatorial Guinea Source: Bloomberg Finance L.P. Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 OPEC-13 Crude Output ( 000 bpd) since Aug Aug 16-Sep 16-Oct 16-Nov 16-Dec 17-Jan 17-Feb 17-Mar 17-Apr 17-May Saudi Arabia 10,640 10,600 10,580 10,530 10,480 9,870 9,940 9,940 9,950 9,930 Libya Iraq 4,480 4,540 4,590 4,620 4,630 4,490 4,440 4,430 4,410 4,450 Iran Kuwait 2,930 2,940 2,960 2,910 2,860 2,710 2,710 2,705 2,700 2,710 UAE Qatar Algeria Angola 1,770 1,730 1,500 1,690 1,670 1,670 1,690 1,630 1,660 1,670 Nigeria Ecuador Venezuela Gabon Total 32,840 33,110 33,280 33,410 33,140 32,230 32,295 31,935 31,895 32,210 Note: Figures do not include Indonesia, which suspended its membership in November 2016, and Equatorial Guinea, which joined OPEC in May 2017 Source: Bloomberg Finance L.P. Page 11 Page 11

12 OPEC crude output adjustments by member countries YTD in 2017 (mbpd) Reference Production Level Proposed Adjustment Proposed Production level effective Jan 2017 Jan - May 2017 actual production average Observed Adjustment YTD in 2017 Production deviation from proposed Saudi Arabia 10,544 (486) 10,058 9,926 (618) -1.3% Libya Exempted Iraq 4,561 (210) 4,351 4,444 (117) 2.1% Iran 3,975 Kuwait 2,838 (131) 2,707 2,707 (131) 0.0% UAE 3,013 Qatar 648 (30) (32) -0.3% Algeria 1,089 Angola 1,753 (80) 1,673 1,664 (89) -0.5% Nigeria Exempted Ecuador 548 (26) (17) 1.7% Venezuela 2,067 (95) 1,972 2,004 (63) 1.6% Indonesia Suspended membership Gabon 202 (9) (11) -1.0% Total (1,166) (1,423) Source: OPEC, Bloomberg Finance L.P., DBS Bank Managing fiscal deficits will force OPEC countries to remain prudent. The International Monetary Fund (IMF) has forecast a fiscal breakeven oil price of about US$78/bbl for Saudi Arabia in 2017, and while the breakeven oil price has fallen from close to US$106/bbl back in 2014 owing to fiscal prudence, the fact that it is likely to be much above the near term oil price trading range remains a key driver behind Saudi s support towards negotiating the OPEC production cuts in October 2016, and supporting a nine-month extension recently. Despite the government s efforts to cut costs and diversify its economy, Saudi Arabia generates more than 80% of its official revenue from oil, according to a World Bank report. The fiscal breakeven oil price for Saudi Arabia is higher than that for regional rival Iran, which has a more diversified economy. The only OPEC member in the Middle East and North Africa region able to balance its budget with oil below U$50/bbl is Kuwait, with a break-even oil price of around US$48/bbl in 2017, as per IMF projections. Libya, which has the highest break-even among the region s OPEC members, is exempt from the production cut targets. That is now beginning to look like a problem. Fiscal break even oil price estimates for Gulf OPEC countries 2017 fiscal breakeven oil price US$/bbl Algeria Iran Iraq Kuwait Libya Qatar Saudi Arabia UAE Source: IMF (Regional Economic Outlook Middle East and Central Asia, October 2016) Page 12 Page 12

13 However, Libya, which is exempt from the production cuts, has ramped up production significantly compared to last year. Libya, one of the most unstable countries in North Africa and the entire Gulf region for that matter, has beaten market expectations, and ramped production significantly in the first few months of 2017, adding to supply woes that the OPEC countries desperately want to address. According to Bloomberg data, Libyan production as of May 2017 stood at 760mbpd, roughly double its average production of 384mbpd in 2016, as major oilfields like the El Sharara and El Feel reopened. This kind of ramp up looked highly improbable earlier as the country is governed by two competing governments and several hostile tribal militia groups, and pipelines are kept open by striking deals with these groups. Libyan oil executives, however, are projecting production to ramp up all the way to 1mmbpd within the next few months, which could seriously undermine OPEC efforts to control production. Libya oil production trends mmbpd Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Source: Bloomberg Finance L.P. Nigeria output could also ramp up in the near term. As in Libya, oilfields in Nigeria are also producing as militant activity has subsided, and output could ramp up from current levels of mmbpd to 2.0mmbpd. Royal Dutch Shell, the largest operator in Nigeria, has recently lifted the force majeure on oil exports from Forcados, one of Nigeria s largest fields, which had been in place for well over a year. This could add to OPEC s difficulties in speeding up a reduction in world oil inventories. Among non-opec countries, Russia took until April to meet its targeted 300,000bpd cut. While non-opec countries, led by Russia, committed to their share of production cuts of about 0.6mmbpd from Nov-2016 reference levels, compliance to the cuts has been slow, as is evidenced by the fact that it has taken until April 2017 for Russia to bring down production to 11.0mmbpd from the reference level of 11.3mmbpd. In fact, average Russian production YTD in 2017 of 11.1mmbpd is higher than the average in Russia will have to seriously demonstrate a cut in production in 2H-2017, as much of the gradual decline in 1H-2017 can be explained by seasonal factors. Russian production usually increases in the second half of the year, and the extension of the production cuts agreed with OPEC countries will be needed to curtail that growth. Russia oil production trends mmbbl/d Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 Source: Bloomberg Finance L.P. Kazakhstan has been a violator of the production cuts. Kazakhstan was among the six non-opec countries that agreed to support the OPEC members when it first announced the production cuts last November. Kazakhstan had committed to a 20,000bpd cut in production from the baseline level of October 2016, but instead of adhering to this, it has actually increased production since then, largely thanks to the reopening of the massive Kashagan field. Among the non-opec countries which agreed to production cuts, Oman has the best compliance, while Russia took a few months to reach the desired cuts. On the other hand, the Kashagan field alone is producing around 170,000bpd currently, and could double that by end This is an added concern at this stage. OPEC s surplus capacity has increased after production cut but is still in tight region. According to EIA estimates, OPEC surplus crude oil production capacity averaged only 1.1mmbpd in 2016, but is expected to increase to around 2.1mmbpd in 2017, following the production cuts. Despite the production cuts, the surplus capacity below 2.5mmbpd indicates a relatively tight oil market, based on historical trends. However, the continuing inventory buildup and high current and forecast levels of global oil inventories make the projected benign OPEC surplus capacity level less significant. Page 13 Page 13

14 OPEC crude oil surplus capacity trends and forecast mmbpd Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q Q 2018 Source: EIA OPEC exports have not decreased as much as production so far. The oil market rebalancing has taken longer than expected so far in 2017, and that is likely because the production cuts by OPEC have not fully filtered into export numbers. While output is important, it may be better to focus on what the group is actually importing. According to vessel tracking and port data from Thomson Reuters, OPEC exported 25.6mmbpd by tankers in the first five months of 2017, slightly higher than 25.4mmbpd in the same period last year. While tanker shipments from Saudi Arabia fell by roughly 440,000bpd in the above period, other members more than compensated for Saudi Arabia s cuts, thus suggesting that Saudi is shouldering the bulk of not only production cuts but exports as well. Thus, some other members may not be doing as much and supplanting lost production with crude from storage and freeing up barrels for export by managing domestic refinery maintenance schedules. Cuts in exports should be hopefully more visible over the next few quarters. With the extension of output cuts for another nine months, export declines could catch up with production cuts for other OPEC members as well, and we should see faster rebalancing of the oil market as we move into the second half of This is something we need to keep a close watch on. Page 14 Page 14

15 US production has again surprised on the upside, but longer term trend could be more benign US shale oil has rebounded off 2016 lows. Driven by a more stable oil price environment, supportive government policies, falling costs, and rising productivity, onshore rig counts in the US (mainly supporting tight oil regions) started to rise in mid for the first time since oil prices fell in Since September 2016, the trend in production was reversed, as can be seen in the chart below. Total US production has now rebounded from around 8.6mmbpd in September 2016 to 9.3mmbpd currently, and look set to cross previous highs over the course of 2017/18. The Permian basin has been the key driver of recent growth. Among the seven key shale producing regions in the US Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian and Utica the Permian Basin has benefited the most in terms of recent investments and drilling activity owing to lower cash production costs and improved productivity of new wells. US crude oil production trends mmbbl/d Source: Bloomberg Finance L.P. US crude oil production trends conventional vs tight oil mmbpd Source: Bloomberg Finance L.P. US total oil production Jan-07 May-07 Sep-07 Jan-08 May-08 Sep-08 Jan-09 May-09 Sep-09 Jan-10 May-10 Sep-10 Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Sep-16 Jan-17 May-17 Bakken production Eagle Ford production Haynesville production Marcellus production Niobrara production Permian production Utica production Other regions Page 15 Page 15

16 Key shale regions in the US comparative production growth trends over the last 3-4 years Area Jan 2014 Mar 2015 Sep 2016 May 2017 Bakken production (bpd) 966,600 1,224, ,050 1,026,212 Growth 27% -19% 4% Eagle Ford production (bpd) 1,250,367 1,701,168 1,181,538 1,244,480 Growth 36% -31% 5% Haynesville production (bpd) 54,115 55,452 43,872 44,565 Growth 2% -21% 2% Marcellus production (bpd) 37,000 45,000 36,000 40,455 Growth 22% -20% 12% Niobrara production (bpd) 305, , , ,168 Growth 60% -12% 5% Permian production (bpd) 1,478,864 1,882,231 2,041,419 2,421,445 Growth 27% 8% 19% Utica production (bpd) 26,623 64,647 50,796 53,493 Growth 143% -21% 5% Total production (bpd) 4,119,375 5,460,636 4,766,708 5,280,818 Growth 33% -13% 11% Source: Bloomberg Finance L.P. What is driving the shale rebound? 1. Increase in rig counts. The total number of rigs drilling for oil and natural gas in the US fell all the way to 404 in May 2016, down 79% from the September 2014 high of 1,931 rigs. Since then, rig counts have slowly come back and currently stand around 900 rigs, largely driven by recovery in horizontal rigs drilling for shale oil, based on Baker Hughes data. In the last 56 weeks for which we have data from Baker Hughes, rig additions were positive in all but five of those weeks. The growth in rig count seems to be positively correlated with the WTI oil price trends, as can be seen in the following charts, as increasing confidence in oil prices staying above the US$50/bbl mark, coupled with lower production costs of around US$30-35/bbl, especially in the Permian Basin, prompted the US shale producers to bump up their capex plans for 2017, after steep cuts in Page 16 Page 16

17 US rig count has rebounded since mid-2016 Rig Count w -o-w chg Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Land rigs (LHS) Offshore rigs (LHS) w-o-w chg in rig count (RHS) Source: Baker Hughes -120 Land rig additions were negative in only 5 of the last 56 weeks since June 2016 w -o-w chg in rig count Jun-16 Jun-16 Jul-16 Aug-16 Aug-16 Sep-16 Oct-16 Oct-16 Nov-16 Dec-16 Dec-16 Jan-17 Feb-17 Mar-17 Mar-17 Apr-17 May-17 May-17 Jun-17 Source: Baker Hughes Spending on new drilling programs in the US have improved since 2H-2016 on the back of more optimism regarding oil price environment. A look at the capex trends for key listed US independent shale players from 2015 onwards as presented in the following page will signal that producers are looking to increase capex by an average of 30-40% in This comes after a sharp 50%+ decline in capex on average in 2016, and despite the projected increase in 2017, it is still be some way off 2015 levels. The optimism is more concentrated in the Permian Basin, where producers are looking to increase capex by 40% on average in 2017 and production increase of 16% on average. Page 17 Page 17

18 US horizontal rig count vs WTI prices US$/bbl Jun-09 Oct-09 Feb-10 Jun-10 Oct-10 Feb-11 Jun-11 Oct-11 Feb-12 Jun-12 Oct-12 Feb-13 Jun-13 Oct-13 Feb-14 Jun-14 Oct-14 Feb-15 Jun-15 Oct-15 Feb-16 Jun-16 Oct-16 Feb-17 No of Rigs 1,600 1,400 1,200 1, WTI prices (LHS) Horizontal Rig Count (RHS) Source: Baker Hughes, Bloomberg Finance L.P. North America top independent shale producers capex trends and production guidance for Capex (US$bn) 2016 Capex (US$bn) 2017 Capex (US$bn) Y-o-Y Chg Y-o-Y Chg 2017 production guidance Pioneer Natural Resources % 33% 15-18% production growth Concho Resources % 31% 20-24% production growth i ConocoPhillips % 2% Flat to 2% growth in production Hess Corporation % 7% Occidental Petroleum % 14% 4-7% production growth Anadarko Petroleum % 64% 24-26% production growth Noble Energy % 47% Flat to 2% growth in production EOG Resources % 50% 18% production growth Marathon Oil % 57% 5% production growth Chesapeake Energy % 29% 10% production growth Apache Corporation % 63% 10% production growth Newfield Exploration % 33% 3-5% production growth EP Energy % 36% Negative 6-14% growth Continental Resources % 77% 1-6% growth Devon Energy % 79% 13-17% growth Murphy Oil % 48% Flattish production Whiting Petroleum % 99% 4-6% growth Total % 37% Source: Companies, DBS Bank Page 18 Page 18

19 Permian Basin top independent shale producers capex and production trends Capex (US$bn) Production (mboepd) Y-o-Y Chg Y-o-Y Chg Y-o-Y Chg Y-o-Y Chg Parsley % 120% % 70% PDC Energy % 88% % 40% RSP Permian % 117% % 88% Pioneer % 33% % 16% Laredo % 33% % 15% Concho % 31% % 20% Cimarex % 44% % 13% SM Energy % 25% % -27% Occidental % 14% % 13% Energen % 32% % 20% Diamondback % 125% % 60% Total % 40% % 16% Source: Companies, DBS Bank 2. Productivity improvements. Rig counts in isolation may not provide the best picture. While growing rig counts is definitely a good indicator of current and future supply, productivity improvements in the past have meant that production has been much more resilient than expected despite the sharp fall in rig counts since October 2014, as can be seen in the chart below. In the initial phase of the chart s timeline, drilling ramps up fast, production catches up towards the middle but does not fall as fast as rig counts later on. This is mainly explained by productivity gains or increase in new well production rates through improvements in well design and technology. Productivity gains across the 7 main shale producing areas in the US has been relentless, as drillers have applied new, innovative technologies to increase output and reduce drilling time. As a result, new-well oil production per rig the benchmark for productivity has more than doubled since Oct 2014, when rig counts began on their steep decline. This is not a new phenomenon as productivity gains have increased at CAGR>30% since 2007, as seen in the chart below. These productivity gains helped to partially offset the decline in drilling rigs from Oct 2014 to June Productivity gains are markedly more visible in the bigger shale producing areas Eagle Ford, Bakken, Niobrara and Permain - as shown in the charts in the following pages. US horizontal rig count vs. US lower 48 states total oil production trends mboepd Jun-09 Nov-09 Apr-10 Sep-10 Feb-11 Jul-11 Dec-11 May-12 Oct-12 Mar-13 Aug-13 Jan-14 Jun-14 Nov-14 Apr-15 Sep-15 Feb-16 Jul-16 Dec-16 No of rigs 1,600 1,400 1,200 1, Lower 48 oil production (LHS) Horizontal Rig Count (RHS) Source: Baker Hughes, Bloomberg Finance L.P. Page 19 Page 19

20 US productivity by shale oil regions - overall (No. of rigs) / (Productivity: Bpd per well) 1,600 Despite a collapse in the US shale rig count, oil production has remained resilient, primarily a result of productivity gains. (mmbpd) 6 1,400 1,200 1, US tight (shale) oil drilling rig count (LHS) Jan-07 May-07 Sep-07 Jan-08 May-08 Sep-08 Jan-09 May-09 Sep-09 Jan-10 May-10 Sep-10 Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Sep-16 Jan-17 Shale oil production (bpd) Bakken - productivity Eagle Ford - productivity Haynesville - productivity Marcellus - productivity Niobrara - productivity Permian - productivity Utica - productivity Weighted avg productivity US Shale rig count Source: Bloomberg Finance L.P., DBS Bank US productivity by shale oil region Bakken (No. of rigs) / (Productivity: Bpd per well) 1,200 1, (mbpd) 1,400 1,200 1, Jan-07 Jun-07 Nov-07 Apr-08 Sep-08 Feb-09 Jul-09 Dec-09 May-10 Oct-10 Mar-11 Aug-11 Jan-12 Jun-12 Nov-12 Apr-13 Sep-13 Feb-14 Jul-14 Dec-14 May-15 Oct-15 Mar-16 Aug-16 Jan-17 0 Bakken production Bakken - productivity Bakken Rig Count Source: Bloomberg Finance L.P., DBS Bank Page 20 Page 20

21 US productivity by shale oil region Eagle Ford (No. of rigs) / (Productivity: Bpd per well) 1,600 1,400 1,200 1, Jan-07 Jun-07 Nov-07 Apr-08 Sep-08 Feb-09 Jul-09 Dec-09 May-10 Oct-10 Mar-11 Aug-11 Jan-12 Jun-12 Nov-12 Apr-13 Sep-13 Feb-14 Jul-14 Dec-14 May-15 Oct-15 Mar-16 Aug-16 Jan-17 Eagle Ford production Eagle Ford - productivity Eagle Ford Rig Count Source: Bloomberg Finance L.P., DBS Bank (mbpd) 1,800 1,600 1,400 1,200 1, US productivity by shale oil region Permian (No. of rigs) / (Productivity: Bpd per well) Jan-07 Jun-07 Nov-07 Apr-08 Sep-08 Feb-09 Jul-09 Dec-09 May-10 Oct-10 Mar-11 Aug-11 Jan-12 Jun-12 Nov-12 Apr-13 Sep-13 Feb-14 Jul-14 Dec-14 May-15 Oct-15 Mar-16 Aug-16 Jan-17 Permian production Permian - productivity Permian Rig Count Source: Bloomberg Finance L.P., DBS Bank (mbpd) 2,500 2,000 1,500 1, Page 21 Page 21

22 Production trends new oil well production per rig Permian Basin average oil production per well Source: EIA High initial production rates boosted productivity. Tight oil growth has been driven by increasing initial production rates from tight wells in regions analyzed by the EIA. As drilling techniques and technology improve, producers are able to extract more oil during the initial months of production from new wells. For example, as per the production profile for the Permian basin in 2015 above, production per well peaked at around 230bpd in the first month of production compared to around 150bpd in the first month of production in The production profiles in the second, third months and so on are also higher than in previous years, though the slope of decline is sharper as we advance in time. After a year, average production for wells in 2015 is down to around 65bpd (down 72% from peak), while that in 2014 is down to around 50bpd (down by a lower 67% from peak), Despite the steeper slope of decline, the amount of oil produced per well (area under the curve) is significantly higher each year. Similar trajectories are observed for other key shale producing areas in the US. This leads us to two obvious conclusions: i) fewer newer wells are required to replace ageing wells, and ii) the same number of new wells will result in much higher production levels than before. Eagle Ford region average oil production per well Source: EIA Page 22 Page 22

23 Bakken region average oil production per well Source: EIA Niobrara region average oil production per well Source: EIA The average new well in each of these regions produces more oil than previous wells drilled in the same region, a trend for nine consecutive years. The increasing prevalence of hydraulic fracturing and horizontal drilling, along with improvements in well completions and the ability to drill longer laterals, has greatly improved well productivity. This trend can be seen in the continued increase in initial production rates since 2007, and it has allowed production in major shale basins to be fairly resilient despite high decline rates common to drilling and producing in tight formations and, since 2014, the declining number of rigs drilling for oil. High decline rates over the first year or two of production from tight oil plays mean that more new wells are required than in conventional formations to offset production declines from legacy wells. As the rig count in these regions declined because of low oil prices, there were not enough new wells to overcome the decline from legacy wells, resulting in falling production from Eagle Ford, Bakken, and Niobrara regions. Only in the Permian region did the significant reduction in rig count not result in lower production, because most of the rigs that left the region were vertical rigs, whereas the remaining active horizontal rigs continued to target low-permeability formations similar to those in Bakken and Eagle Ford. Additionally, unlike the other regions discussed, the Permian has a large number of conventional wells. Although these wells do not produce as much as horizontal wells, they have slower production decline rates and thus do not need as many new wells each month to compensate for legacy declines. Production trends legacy production changes Page 23 Page 23

24 Decline rates are still steep though there is evidence of stabilisation in more mature plays. Legacy production change refers to change in the region s production from existing wells and is typically negative since well production naturally declines over time. A summation of legacy production changes and production from new wells will typically give us the estimate of net new production in a region. The trend of legacy production change thus has an effect on the impact that new rigs in a region will have on volumes. The charts below show the legacy production change trend for the four key shale areas in the US. As can be seen, legacy production change is usually increasingly negative, and a higher number of new wells would be needed to replace existing supply. However, in the case of the more mature Bakken and Eagle Ford regions especially, this trend seems to have reversed in early 2015, which meant production could be sustained at a decent level in spite of lower new rig numbers. In these areas, a lower level of new supply can lead to positive net new production levels, whereas in areas like the Permian Basin, net new production can only be supported by an increasing number of new rigs, as legacy production changes continue to be increasingly negative. The net new production trend overall in June 2017 (production from new wells + legacy production changes) is also presented in a chart below, highlighting positive and negative drivers in terms of the current US shale rebound. Bakken region legacy production change Eagle Ford region legacy production change mbpd - (10) (20) (30) (40) (50) (60) (70) Jan-07 Sep-07 May-08 Jan-09 Sep-09 May-10 Jan-11 Sep-11 May-12 Jan-13 Sep-13 May-14 Jan-15 Sep-15 May-16 Jan-17 mbpd - (20) (40) (60) (80) (100) (120) (140) (160) Jan-07 Sep-07 May-08 Jan-09 Sep-09 May-10 Jan-11 Sep-11 May-12 Jan-13 Sep-13 May-14 Jan-15 Sep-15 May-16 Jan-17 Niobrara region legacy production change Permian basin legacy production change mbpd - (5) (10) (15) (20) (25) (30) (35) (40) (45) Jan-07 Sep-07 May-08 Jan-09 Sep-09 May-10 Jan-11 Sep-11 May-12 Jan-13 Sep-13 May-14 Jan-15 Sep-15 May-16 Jan-17 mbpd - (20) (40) (60) (80) (100) (120) (140) (160) Jan-07 Sep-07 May-08 Jan-09 Sep-09 May-10 Jan-11 Sep-11 May-12 Jan-13 Sep-13 May-14 Jan-15 Sep-15 May-16 Jan-17 Source: EIA Page 24 Page 24

25 Net new production from seven key areas is overall positive in June 2017 mbpd Bakken Eagle Ford Haynesville -2 Marcellus -2 Niobrara Permian Utica Production from new wells Legacy production change Source: EIA Production trends Drilled but Uncompleted Wells (DUCs) DUCs need to be watched. The US EIA has recently started ti publish data on Drilled but Uncompleted Wells (DUCs), which can act as a rough forward indicator of future shale production growth/ decline. If oil prices recover fast, these DUCs can be completed quickly and brought into production. Thus, a higher number of DUCs means higher flexibility for shale production to respond to oil price increases and thereby possibly helping to ensure that oil price recovery is capped below a certain range. Has a drawdown in DUCs contributed to recent recovery in production levels? Since the recovery of US shale production in September 2016, it may be useful to look into whether the inventory of DUCs fell as more wells were brought into production. However, as the charts below show, this is not the case, and the total number of DUCs start to increase from November 2016 onwards. This is especially true for the Permian Basin, where most of the recent drilling activity is centered. Other shale plays combined continued to draw down on DUCs in 2H-2016, but even these regions have started to add DUCs YTD in Bakken region DUCs Eagle Ford region DUCs DUCs 1, Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 DUCs 1,600 1,400 1,200 1, Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Source: EIA Page 25 Page 25

26 Niobrara region DUCs Permian Basin DUCs DUCs Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 DUCs 2,500 2,000 1,500 1, Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Source: EIA Sharp increase in Permian Basin DUCs is an indicator that US production will continue to increase over 2017/18. The recovery in rig counts in the US in recent months has been largely driven by investments in the Permian Basin, which has manifested itself into the trend of increasing DUCs as seen above. This underpins our belief that US shale production will continue to increase in 2017/18 as long as prices are above the US$45/bbl level by around 0.4mmbpd in 2017 and another 0.7mmbpd in Beyond that, capex decisions taken in 2017/18 will determine the speed of growth, which in turn will depend on prevailing oil prices. Change in DUCs led by Permian Basin since Sep-2016 m-o-m chg in DUCs Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 May-17 Permian Other regions Source: EIA Page 26 Page 26

27 3. Cost reductions Before we look at how US shale players have been able to cut costs over time, it may be worthwhile to look at the cost components before we look at cost drivers and underlying trends in these costs. For onshore wells, upstream costs can be broken down into the following key categories: Cost breakdown for US onshore drilling (excluding operation costs) Facilities 6% Completion 63% Drilling 31% Source: EIA, IHS Description of cost components for US onshore drilling Drilling Completion Facilities Operation Comprises about 30-40% of total well costs. These costs are comprised of activities associated with utilising a rig to drill the well to total depth and include: a) Tangible Costs such as well casings and liners, which have to be capitalised and depreciated over time, and b) Intangible Costs, which can be expensed and include drill bits, rig hire fees, logging and other services, cement, mud and drilling fluids, and fuel costs. Comprises around 55-70% of total well costs. These costs include well perforations, fracking, water supply and disposal. Typically, this work is performed using specialised frack crews and a workover rig or coiled tubing and include: a) Tangible Costs such as liners, tubing, Christmas trees and packers, and b) Intangible Costs include frack-proppants of various types and grades, frack fluids which may contain chemicals and gels along with large amounts of water, fees pertaining to use of several large frack pumping units and frack crews, perforating crews and equipment and water disposal. Facilities construction comprises around 6% of total well cost. These costs include: a) Road construction and site preparation, b) Surface equipment, such as storage tanks, separators, dehydrators and hook up to gathering systems, and c) Artificial lift installations. These comprise primarily the lease operating expenses. Costs can be highly variable, depending on product, location, well size and well productivity. Typically, these costs include: a) Fixed lease costs including artificial lift, well maintenance and minor workover activities. These accrue over time, but are generally reported on a US$ per boe basis. b) Variable operating costs to deliver oil and natural gas products to a purchase point or pricing hub. Because the facilities for these services are owned by third party midstream companies, the upstream producer generally pays a fee based on the volume of oil or natural gas. These costs are measured by US$ per Mcf or US$ per mmbtu or US$ per bbl basis and include gathering, processing, transport, and gas compression costs. Source: EIA, IHS Page 27 Page 27

28 Five key cost categories together account for more than three quarters of the total costs for drilling and completing typical US onshore wells. Given that drilling and completing costs are the key cost components, we next look at what are the key cost drivers for drilling and completing typical US shale wells. Rig and drilling fluids, casing and cement, frac pumps and equipment, proppants and completion fluids are the key cost drivers. Key cost drivers for US onshore drilling Others 23% Rig and drilling fluid 15% Completion fluids 12% Proppant 14% Casing and cement 11% Frac Pumps, equipment 25% Source: EIA, IHS Description of key cost drivers for US onshore drilling Rig and drilling fluids costs Casing and cement costs Frac pumps and related equipment costs Proppant costs Completion fluids Around 15% of total costs; rig related costs are dependent on drilling efficiency, well depths, rig day rates, mud use and diesel fuel rates Rig day rates and diesel costs are related to broader market conditions and overall drilling activity rather than well design Around 11% of total costs, and relate to casing design required by local well conditions and the cost of materials. Casing costs are driven by the casing markets, often related to steel prices, dimensions of the well, and by the formations or pressures that affect the number of casing strings. Around 24% of total costs; dependent on horsepower needed and number of frack stages. The amount of horsepower is determined by combining formation pressure, rock hardness or brittleness, and the maximum injection rate. Higher pressure requirements increase the cost. The number of stages, which often correlates with lateral length, is important since this fracturing process, with its associated horsepower and costs, must be repeated at each stage Around 14% of total costs and include the amount and rates for the particular type of material introduced as proppant in the well. Proppant costs are determined by market rates for proppant, the relative mix of natural, coated and artificial proppant and the total amount of proppant. Proppant transported from the sand mine or factory to the well site, and staging stages make up a large portion of total proppant costs. Flow back costs make up around 12% of total costs, and include sourcing and disposal of the water and other materials used in hydraulic fracturing and other treatments that are dependent on geology and play location as well as available sources. Water sourcing costs are a function of regional conditions relating to surface access, aquifer resources and climate conditions. Water disposal will normally be done by re-injection, evaporation from disposal tanks, recycling or removal by truck or pipeline, each with an associated cost. Source: EIA, IHS Page 28 Page 28

29 Changes in technology and drivers of efficiency. Over the past decade specific changes in technology have been employed to both reduce costs and increase production. Technology improvements related to drilling: Longer laterals (increase performance). Better geosteering to stay in higher-producing intervals (increase performance), Decreased drilling rates (decrease cost), Minimal use of casings and liners (decrease cost), Multi-pad drilling (decrease cost), and High-efficiency surface operations (decrease cost). Technology improvements related to well completion: Increase amount of proppant superfracks (increase performance), Number and position of frack stages (increase performance), Shift to Hybrid (cross-link and slick water) fluid systems (increase performance), Faster fracking operators (decrease cost), Less premium proppant used (decrease cost), and Spacing and stacking optimisation (increase performance). Drivers of higher efficiency in shale drilling Lateral length Completions Multi-well pads and higher surface operation efficiency Improved Water Handling: The shift from vertical to horizontal wells is the most important change to occur over the last decade, allowing for greater formation access while only incrementally increasing the cost of the well. Over the past decade, lateral lengths have increased from 2,500 feet to more than 8,000 feet and, at the same time, we have seen nearly a three-fold increase in drilling rates (feet/day). This increase in efficiency is leading to overall downward pressure on drilling costs for each well, even though lateral lengths may be increasing. Within each play, larger amounts of proppant, fluid and frack stages are employed to drive up production performance. Cheaper proppant and slightly less water per pound of proppant are being used to combat costs. With the well completion schemes evolving and growing over time, performance is also expected to increase. Average stage length has decreased from 400 to 250 feet, which allows more proppant to be used. Multi-well pad drilling allows for maximisation reservoir penetration with minimal surface disturbance, which is important in areas that are environmentally sensitive, have little infrastructure, or in mountainous areas with extensive terrain relief. Operational costs are reduced as this allows operators to check wellhead stats (pressure, production, etc.) on numerous wells in the same location. Most pads are situated with 4-6 wells, but some are planned for 12, 16, or even 24 wells where there are multiple stacked zones. With the surface locations of wells on a pad being close to each other, mobilizing rigs from one well to another is also more efficient. Walking rigs, automated catwalks, and rail systems allow rigs to move to the next location in hours, not days. Facilities can be designed around pads, thus further reducing costs. As water resources become more and more scarce, operators are forced to come up with better solutions for the amount of water used for each well, especially in arid regions, such as the Permian Basin and the Eagle Ford in South Texas. This is also important in environmentally sensitive areas. Many companies are using recycled water for drilling and completion operations instead of having water trucked in or out. Using recycled water also reduces operators costs. Source: EIA Examples of efficiency programs. In a lower cost environment, US shale drillers have continued their emphasis on gaining efficiencies and improving performance in order to drive down unit costs per barrel of oil equivalent (boe). Some examples of how the shale producers have strived to lower costs are shown on the following page. Page 29 Page 29

30 Example 1: Pioneer Natural Resources How shale drillers have evolved over the last few years Source: Pioneer Natural Resources (corporate presentation) Example 2: Laredo Petroleum Laredo Petroleum driving drilling efficiencies to reduce costs Laredo Petroleum longer laterals reducing finding & development costs Source: Laredo Petroleum (corporate presentation) Page 30 Page 30

31 Overall, breakeven prices for shale have fallen every year. For the main shale players, breakeven prices for shale are falling every year. This is a result of both a reduction on well cost and an increase in oil recovery per well, as discussed in earlier sections. Thus, more projects are now feasible at lower oil prices in the US than earlier anticipated, and production has been quite resilient. According to estimates from industry consultant Rystad Energy, breakeven at the major US shale plays are in the range of US$30-45/bbl in the Bakken, Eagle Ford, Permian and Niobrara regions, down from US$65-100/bbl in But achieving actual profitability and returns on equity after debt servicing and ensuring future capex would require oil prices to be above US$45/bbl at least in our opinion. Development in wellhead breakeven prices for key shale plays in the US Source: Rystad Energy NASWellCube US shale plays IRR sensitivity to WTI prices Source: S&P Global, Bentek Page 31 Page 31

32 Is there a limit to cost reduction and productivity improvements? Are cost reductions sustainable? According to studies done by Rystad Energy, average breakeven prices have dropped by 55% over the last three years. However, trends in efficiency improvements and cost reductions cannot be unidirectional forever, despite continuing changes in technology. Some of the production cost components are cyclical in nature as pricing for costs and services for unconventional resource development will move according to changes in utilisation. While efficiency gains are structural in nature, incremental gains are harder to come by. In addition, companies resort to high grading or drilling their best acreage during periods of low oil prices, and again, this is not sustainable. Some of the trends in costs and efficiency improvements are presented below, which supports our view that it is possible for breakeven prices to reverse its trend. Trends in costs Rig rates and rentals These services were created specifically for unconventional oil and natural gas development. According to data from RigData, a unit of S&P Global Platts, the first quarter of 2017 saw a 3.5% spike in the average day rate to US$14,600. While that is still down from a record US$19,015 in 4Q-2014, it is the biggest quarter-to-quarter jump since the previous post-bust recovery in A major contributing factor to the day rate recovery has been the erosion of the rig glut in recent months. Rigs with drawworks capacity of more than 1,000 horsepower (hp) is dominating the drilling scene, especially Tier 1 Class D (1,500-1,999 hp) AC newbuilds. These newbuilds have been dominating horizontal drilling in the Permian Basin and elsewhere. The proliferation of these higher-cost rigs pulled the overall average day rate -- aggregated across all regions and all rig classes -- up to the record of US$19,015 just before the downturn began. The current recovery in day rates will likely level off in the months to come, but further declines are unlikely. Casing and cement Casing cost is driven primarily by steel prices, which moved up in 1Q17 owing to higher iron ore prices and coking coal prices since late 2016, but is expected to moderate over the rest of the year. On average though, steel prices in 2017 should be higher y-o-y. Frack equipment and crews Like rigs and rig crews, these are specialised for unconventional resources and no other markets currently exist for these services. We expect price movements to mirror those of rig rates and rentals. Proppant The majority of the proppant cost is the price of sand and transportation from sand mines. YTD, we have seen the market for sand surging again with the rebound in US shale oil production. Prices have moved towards US$40 per tonne or more as demand for sand increases, compared to around US$20 per tonne in the second half of Increasing sand orders are also raising transportation costs from mines in states like Wisconsin to shale fields in other states. Sand accounts for roughly 5-7% of well costs and given the increasing amount of sand that is going into the fracking process every year, this cost component is likely to continue rising over the next two years. Frack fluids and water disposal Water sourcing costs are tied to regulatory conditions and are not market based, although we expect cost of chemicals and gels to drop. Disposal costs will not be affected by industry activity as rates are based on long term contracts that escalate each year by around 2%. Source: EIA, DBS Bank Page 32 Page 32

33 Trends in efficiency improvements Drill days Lateral length Drill bits have continued to improve as evidenced by the increase in drill feet per day. More pad drilling will decrease rig movement times for mobilisation and de-mobilisation. Annual rates of increase are slowing, which may be due to limitations imposed by lease and drilling unit size and configuration. Within a given drilling unit, operators will drill their longest laterals first and then fill in the gaps with shorter laterals. More proppant per foot Operators continue to push the limits and production may continue to increase as some operators are using as much as 2,000lbs/ft. There has been an increase in the number of closely spaced wells as operators continue to harvest as much of the resource as possible. Additional proppant is likely to be needed in order to achieve the recovery rates required for economic success in these more closely spaced wells. Nevertheless, some evidence exists that certain plays have reached their maximum limit of how much proppant can be used per lateral foot before well production is crowded out. This may be true for Marcellus and the Bakken where pay zones are typically thinner. As proppant levels increase, additional fluid will be needed for emplacement. More wells on a drill pad Facilities costs per well will decrease as facilities are increasingly designed for the drill pad, not for the well. Other efficiencies such as water disposal, frack staging and rig movements will also eat into costs. Number of Stages Operators are putting more frack stages within the lateral length as stage lengths are decreasing to around feet (with more closely spaced perforation clusters) in order to accommodate the increased proppant amounts being used. Changing the configuration is also improving production performance. Natural Proppants Proppant amounts are expected to increase in all plays. However, proppant types will move toward cheaper natural proppant, except in the Eagle Ford where proppant mixes are weighted more towards artificial sand. Source: EIA, DBS Bank Page 33 Page 33

34 Case Study Whiting Petroleum in Bakken by Rystad Energy Rystad Energy created a case study of Whiting Petroleum in Bakken. Bakken is one of largest and most competitive shale plays in the US, and Whiting is the largest operator within this play. The company s average breakeven price has dropped from around US$66/bbl to US$29/bbl over the last two years, according to Rystad Energy s estimates. Key drivers for the lower breakeven price: 1. High grading of wells Cyclical factor 2. Well performance Structural factor 3. Efficiency gains Structural factor 4. Unit costs (drilling and completion costs) Cyclical factor 5. Production costs (lease operating expenses) Cyclical factor By studying high grading and the other drivers, Rystad Energy calculated the breakdown of the reduction in the breakeven prices, as shown in the chart below. This shows that improved well performance is the largest contributor to lower breakeven prices experienced by Whiting since But out of the total drop of US$37/bbl in breakeven prices, only US$16/bbl was due to structural factors, while the remaining was what Rystad Energy considers as cyclical costs. A rise in unit prices for drilling and completion costs, and lease operating expenses could lead to a 40% increase in the breakeven price for Whiting in Bakken, according to Rystad Energy. In the medium to long term, most companies will also need to start drilling outside the core areas; hence, there will be a reversal of the high grading effect as well. If the positives from these cyclical effects fade, the breakeven price could thus grow by 65% over the next few years in general for US shale plays. Thus long-term breakeven prices are closer to the US$50/bbl level. Breakdown of the change in Whiting s Bakken wellhead breakeven price (US$ per barrel) Source: Rystad Energy NASWellCube Page 34 Page 34

35 Costs beginning to inch up for select US shale producers in early In light of the case study done by Rystad Energy on the Bakken area, we have also tracked the operating/ production costs of producers focused on the Permian Basin, the key area of recent activity and investment. A look at the financials for some of these players as below shows us that most players have recorded significant improvements in costs over the past few years (and quarters), but the trend has been slowly reversing since 4Q16. In 1Q17, costs have begun to inch up again and this trend is likely to persist in 2017 and 2018 if expected activity levels are maintained in the Permian Basin and elsewhere. This again conforms to the fact that some costs are cyclical and despite efficiency gains, breakeven levels below current estimates of US$30-45/bbl for the key shale producing areas would be difficult to achieve. Indeed, there is higher risk of costs surprising on the upside than downside. RSP Permian cash operating costs (US$ per boe) Pioneer Natural Resources - cash production costs (US$ per boe) US$/ boe Q17 LOE, G&T Cash G&A Prod. taxes US$/ boe Q15 1Q16 2Q16 3Q16 4Q16 1Q17 LOE G&T Prod Taxes Others Note: LOE Lease Operating Expenses, G&T Gathering & Transportation Expenses, G&A General & Admininstrative Expenses Source: Companies, DBS Bank Concho Resources cash operating costs (US$ per boe) Laredo Petroleum - cash production costs (US$ per boe) US$/ boe Q17 LOE, G&T Cash G&A Prod. taxes US$/ boe Q15 1Q16 2Q16 3Q16 4Q16 1Q17 LOE Midstream Cash G&A Note: LOE Lease Operating Expenses, G&T Gathering & Transportation Expenses, G&A General & Administrative Expenses Source: Companies, DBS Bank Page 35 Page 35

36 Productivity improvements are plateauing. We tracked well productivity data for seven key shale producing areas in the US. While there were sharp improvements between 2014 and 2015, and again between 2015 and 2016, further improvements since September 2016 when there was a rebound in production has been slow, especially in the Permian Basin, where productivity has been declining. Thus, the trend of new wells having incrementally higher production rates seems to have stalled, and it is mainly the rising rig numbers that is driving production higher in the last few months. This implies capex levels will have to be maintained and a lower number of rigs may not be able to maintain production levels as seen in the past. This implies that production level is able to fall off faster in the event that oil prices fall, resulting in lower rig numbers, thereby stabilising the market. Productivity (bpd/well) average of 7 key shale regions Productivity (bpd/well) Permian Basin bpd/ well Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 bpd/ well Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Source: Bloomberg Finance L.P., DBS Bank Key shale regions in the US trends in productivity (bpd per well) improvements over the last decade Area Jan-07 Jan-14 Mar-15 Sep-16 May-17 Bakken productivity ,000 1,130 Growth 247% 46% 78% 13% Eagle Ford productivity ,365 1,448 Growth 1205% 38% 80% 6% Haynesville productivity Growth 233% 25% 20% 10% Marcellus productivity Growth 650% 53% 83% -17% Niobrara productivity ,199 1,288 Growth 829% 70% 116% 7% Permian productivity Growth 185% 55% 122% -1% Utica productivity Growth 170% 226% -34% 100% Total productivity Growth 578% 41% 72% 6% Source: Bloomberg Finance L.P., DBS Bank Page 36 Page 36

37 Profitability of shale producers during the recent oil price cycle gives us an indication of desired price levels In the charts below, we track the profitability of a broad gamut of listed US shale oil producers against prevailing WTI oil prices. While the companies will typically hedge a portion of their production, it seems apparent that spot WTI prices play a big role in revenues and profits. While cash breakeven level of shale producing areas in the US have fallen and are currently between US$30-45/bbl, it is US shale producers quarterly revenue vs WTI apparent that ROE is close to zero when WTI oil prices are around US$50/bbl (in 1Q17). Taking into account that productivity improvements have taken a breather for now and cost trends may have reversed, we would argue that oil prices in excess of US$50/bbl are necessary for further investment from shale players, and losses will resume if oil prices fall back to US$40-45/bbl range, thus limiting future capex and production growth and hence, helping to swing oil prices back to healthier levels. US shale producers quarterly net profit vs WTI US$m 60,000 US$/ bbl 120 US$m 10,000 US$/ bbl ,000 40,000 30,000 20,000 10,000-1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q ,000 6,000 4,000 2,000 - (2,000) (4,000) (6,000) 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q Revenue (US$m) (LHS) WTI (US$/bbl) (RHS) Net Profit (US$m) (LHS) WTI (US$/bbl) (RHS) US shale producers quarterly net profit margin vs WTI US shale producers quarterly ROE vs WTI % 20% 15% 10% 5% 0% -5% -10% -15% -20% -25% 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 US$/ bbl % 14.0% 12.0% 10.0% 8.0% 6.0% 4.0% 2.0% 0.0% -2.0% -4.0% -6.0% 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 US$/ bbl 2Q16 3Q16 4Q16 1Q Net Profit Margin (%) (LHS) WTI (US$/bbl) (RHS) ROE (%) (LHS) WTI (US$/bbl) (RHS) Source: Bloomberg Finance L.P., DBS Bank Note: US shale companies in the above analysis include ConocoPhillips, EOG Resources, Occidental Petroleum, Pioneer Natural Resources, Anadarko Petroleum, Apache Corporation, Concho Resources, Devon Energy, Hess Corporation, Continental Resources, Marathon Oil, Cimarex Energy, Diamondback, Energy Parsley Energy, Antero Resources, Newfield Exploration, RSP Permian, Energen, Chesapeake Energy, PDC Energy, Laredo Petroleum, Whiting Petroleum, Oasis Petroleum, SM Energy and EP Energy Page 37 Page 37

38 Cut in global oil & gas capex will have long term positive impact on prices Expect tighter oil market closer to 2020 timeframe. While US onshore capex is projected to increase in 2017, the picture is different for the offshore market in general. According to the IEA s latest five-year oil market forecast. global oil supply could struggle to keep pace with demand after 2020, risking a sharp increase in prices, unless new projects are approved soon. While there appears to be enough supply and inventory in the market to support demand for the next three years, the picture is not so clear beyond that, as supply growth should slow down, keeping in mind the large capex deferrals since 2015, especially for conventional offshore fields, which require a lead time of five years or more to production. Supermajors capex down by c.40% in 2017 compared to 2014 levels. Capex budgets worldwide have been cut substantially since the onset of the collapse in oil prices. Capex budgets for 2015 and 2016 were slashed by an average of about 25% each year across our sample, and while 2017 may not see such steep cuts, there is no visible evidence of an increase in capex either. We are expecting flattish capex in 2017 at best, though we expect some recovery in 2018 if oil prices stabilise in 2H In any case, we do not expect capex levels to recover back to the highs of anytime soon. This has been quite an unprecedented period of low capex compared to the years preceding 2014, when oil & gas capex grew at a 12% CAGR between for an almost five-fold increase. Capex budgets for selected oil majors: 2017E vs. 2014A average decline of ~40% US$ bn % -51% -44% -43% -12% -44% -48% -57% BP Chevron Exxon Shell (+BG) Total Statoil Eni ConocoPhillips Source: Companies, DBS Bank All these capex cuts will pave the way for higher prices in longer term. Final investment decisions (FIDs) on 68 large projects globally totaling US$380 billion in capital expenditures were deferred since crude prices first plunged in 2014, according to a report by research and consultancy firm Wood Mackenzie. These deferrals and capex cuts will not necessarily translate into significantly lower production in the near term as it is likely that the most productive projects will go ahead while costs are also likely to decline along with the oil price. The Wood Mackenzie report finds that FIDs on many of the projects have been pushed back to 2017 or beyond, with production startups currently targeted to take place in By 2021, deferred liquids volumes are estimated to reach 1.5 million bpd, and rising sharply to 2.9 million bpd by The impact on supply will more acutely felt in the medium term as it typically takes 5-7 years to bring a greenfield conventional project into commercial production. We believe oil prices amy stabilise around US$60-65/bbl level in a tighter market in the longer term. According to estimates from independent oil & gas consultancy Rystad Energy, marginal sources of supply in 2020 will come from currently non-producing shale fields (new shale) and oil sands, with a weighted average breakeven price of around US$63-66/bbl. The Rystad Energy liquids cost curve is made up of nearly 20,000 unique assets and considers each asset s breakeven oil price and potential production in The breakeven price is the Brent crude oil price at which NPV equals zero, and considers all future cash flows using a real discount rate of 7.5%. The cost of these marginal sources of supply will likely determine the longer term oil price trend. Page 38 Page 38

39 Global liquids cost curve analysis from Rystad Energy Source: Rystad Energy Page 39 Page 39