Oil Price Rebalancing Underway

Transcription

1 SECTOR BRIEFING 47 DBS Asian Insights DBS Group Research August 2017 number Oil Price Rebalancing Underway

2 02 Oil Price Rebalancing Underway Suvro SARKAR Equity Analyst DBS Group Research HO Pei Hwa Equity Analyst DBS Group Research Glenn NG Equity Analyst DBS Group Research Janice CHUA Head of Equity Research DBS Group Research Produced by: Asian Insights Office DBS Group Research Goh Chien Yen Jean Chua Geraldine Tan Martin Tacchi Editor-in-Chief Managing Editor Editor Art Director

3 Executive Summary Demand-Supply Equation Can Only Improve Hereon But Inventory Drawdown Will Be Slow at Best OPEC Adherence to Production Cuts Has Been Sincere So Far Strong US Production Trend Could Lose Steam What Is Driving the Shale Rebound? Production Trends: New Oil Well Production Per Rig Production Trends: Legacy Production Changes Production Trends: Drilled-but-Uncompleted Wells Changes in Technology and Drivers of Efficiency Is There a Limit to Cost Reductions and Productivity Improvements? Cut in Global Oil & Gas Capex Positive for Prices Geopolitical Risks Not a Big Mover

4 04 Executive Summary Prices back to levels before OPEC production cut, but not for long Brent crude has averaged around US$52.8 per barrel (bbl) year-to-date, higher than 2016 s average of US$45.1/bbl as prices held up well around the US$50-55/bbl mark in the early months of 2017, following optimism on supply moderation after the Organization of Petroleum Exporting Countries (OPEC) cut production in late However, prices have been falling again since May 2017 on renewed concerns over the oversupply situation as global inventory levels remain stubbornly high and US shale production has rebounded. Brent crude oil prices fell all the way to around US$45/bbl in June, back to levels seen before the OPEC production cut was announced last year. We believe, however, that there is limited downside at those levels and a gradual recovery can be expected again in 2H17. The key near-term and longer-term drivers are highlighted below, and we will cover these in greater detail in the following pages. Near-term Negative driver: Libya is ramping up production, Nigeria to follow? Negative driver: US shale production is almost back to previous highs Positive driver: Extension of OPEC production cuts for nine months to March 2018; filtering of production cuts to actual export cuts hereon Positive driver: Gradual inventory drawdowns amidst seasonally higher demand in 2H and lower year-on-year supply Longer-term Positive driver: US shale productivity gains are plateauing, costs of US shale starting to rise again Positive driver: With two years of major capital expenditure cuts and counting, the supply deficit will loom large by 2020 timeframe Expect recovery trend to continue in near term In the near term, we believe the negative drivers have been largely priced in and as we see sustained evidence of inventory drawdowns in the US and Organisation for Economic Cooperation and Development (OECD) countries going forward, driven by seasonally higher demand and lower export volumes from the OPEC countries, oil prices should recover in 2H The fact that US shale production costs are starting to rise again and productivity improvements are near saturation levels means that prices below US$45/bbl are not sustainable from a return point of view. We project a move toward the US$55/bbl mark by the end of 2017, thus implying an average of between US$50-55/bbl for FY17.

5 should see further market rebalancing Longer-term forecasts maintained While our updated 2017 forecast is slightly lower than our previous projections, we expect Brent crude oil to average between US$55-60/bbl in 2018, with the mild year-on-year (y-o-y) recovery in oil prices driven by accelerated inventory drawdowns as we move into another year where demand growth will comfortably outstrip supply growth. Upside risks in the near term could stem from the possibility of heightened tensions in the Middle East leading to supply-chain disruptions. We expect oil prices to move upwards at a faster trajectory toward the end of the decade. Firstly, of course, we consider the fact that close to US$380 billion worth of capital expenditure (capex) has been deferred since the oil price crash in late 2014 (this according to industry consultant Wood Mackenzie) and further deferrals will mean that close to 3 million barrels per day (mmbpd) of supply that was supposed to come on-stream by 2020 will now only come in the years after that. This will help the supply/demand equation as we approach 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. According to estimates from independent oil & gas consultancy Rystad Energy, the marginal sources of supply in 2020 will be currently non-producing shale fields (new shale) and oil sands, with a weighted average breakeven price of around US$63-66/bbl. This supports our longer-term oil price forecast of around US$60-65/bbl, unchanged from previous projections. Diagram 1: Oil price forecast scenario ' Source: Bloomberg Finance L.P., DBS Bank forecasts

6 06 Demand-Supply Equation Can Only Improve Hereon Rebalancing will happen in 2017 Global oil supply growth slowed significantly in 2016 as the US shale boom took a breather. This was after two years of supercharged production growth in 2014 and Despite low oil prices, global oil supply in 2015 expanded by over 2.1mmbpd following an increase of around 2.5mmbpd in 2014 with both OPEC and non-opec sources contributing significantly to the rise. 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 again saw OPEC production increase before they agreed to a cut in 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 build-up somewhat. Looking forward, we believe 2017 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 a 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 some inventory drawdowns to start in 2H17. Demand should hold steady We expect oil consumption to grow by 1.3mmbpd and 1.4mmbpd in 2017 and 2018, respectively. This is quite steady compared to oil demand growth levels seen in previous years. Oil consumption forecasts 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 US Energy Information Administration (EIA) is shown in Diagram 2, which shows the rebalancing trend. Our supply growth numbers are, however, less aggressive than EIA estimates, and we present our case for the possibility of inventory drawdowns in 2017/18 in Diagram 3.

7 07 Diagram 2. Global oil production and consumption trends and forecasts (EIA) Diagram 3: DBS forecasts for global oil production, consumption growth, and inventory build-up Supply Growth (mmbpd) Demand Growth (mmbpd) Source: EIA 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 Source: EIA, DBS Bank estimates

8 8 But Inventory Drawdown Will Be Slow at Best US crude inventories at similar levels y-o-y US crude oil stocks did not fall as fast as anticipated, given the attempted rebalancing of the market and as inventories climbed to seasonal record-high levels of close to 540 million barrels (mmbbls) by March 2017, before declining to around 509mmbbls in July 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 rising further and the last two months have seen steady inventory declines, and in the last few weeks, at a higher pace than the market predicted. Diagram 4: Crude oil inventory in the US Source: Bloomberg Finance L.P Overall OECD inventory levels just starting to thaw While the 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 as well, at around 3,000mmbbls, significantly higher than the historical 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

9 9 expected to be some drawdown in 2H17, inventories are not expected to fall significantly below the 3,000mmbbls-mark anytime soon. Diagram 5: OECD s inventory of commercial crude oil and other liquids (million barrels) Diagram 6: OECD s commercial oil stocks - days of supply Source: EIA Source: EIA

10 10 Inventory drawdowns expected from 2H17 onwards But clearing the entire glut could take years 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 a 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 near-term oil price recovery thesis from 2H17 onwards. 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 being 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 reaches 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 built 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. Difficult to expect any sharp recovery in oil prices The continuing large inventory builds is a major source of risk to oil prices as the capacity of the global storage system to handle this much 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 market rebalancing has started in 2017 and inventory drawdowns are likely to continue hereon, restoring prices back to where they were before the inventory build-up 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.

11 11 OPEC Adherence to Production Cuts Has Been Sincere So Far OPEC extends production cuts till March 2018 Decent compliance to production cuts YTD in 2017 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 have participated in the production cuts that started in January The meeting was jointly chaired by Saudi and Russian representatives. The decision to not deepen production cuts amidst stubbornly high inventory levels worldwide seem to have left the market unimpressed, at least in the short term. OPEC and non-opec countries made a landmark decision on 30 November 2016 to jointly cut production by about 1.8mmbpd from October 2016 reference levels for a six-month period from January to June 2017, in an attempt to balance the market. OPEC, as a whole, has been largely compliant to the production cuts in the first five months of 2017, though some countries like Saudi Arabia have cut more than the target while Iraq have produced more. But crucially, we believe OPEC exports year-to-date (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 thus 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 into the exports line. Diagram 7: OPEC has cut production in the first five months of 2017 in line with agreed levels Note: Numbers exclude Indonesia and Equatorial Guinea Source: Bloomberg Finance L.P.

12 12 Diagram 8: OPEC-13 s crude output ( 000 bpd) since Aug-2016 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 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 3,620 3,630 3,680 3,750 3,730 3,800 3,780 3,785 3,760 3,760 Kuwait 2,930 2,940 2,960 2,910 2,860 2,710 2,710 2,705 2,700 2,710 UAE 3,030 3,110 3,110 3,060 3,070 2,950 2,950 2,915 2,900 2,860 Qatar Algeria 1,110 1,110 1,110 1,120 1,110 1,040 1,040 1,040 1,040 1,040 Angola 1,770 1,730 1,500 1,690 1,670 1,670 1,690 1,630 1,660 1,670 Nigeria 1,390 1,500 1,670 1,650 1,500 1,640 1,680 1,550 1,600 1,700 Ecuador Venezuela 2,190 2,200 2,180 2,120 2,080 2,030 2,030 2,000 1,980 1,980 Gabon Total 32,840 33,110 33,280 33,410 33,140 32,230 32,295 31,935 31,895 32,210 Diagram 9: OPEC s crude output adjustments by member country YTD in 2017 (mbpd) Reference production level Proposed adjustment 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. 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, ,797 3,777 (198) -0.5% Kuwait 2,838 (131) 2,707 2,707 (131) 0.0% UAE 3,013 (139) 2,874 2,915 (98) 1.4% Qatar 648 (30) (32) -0.3% Algeria 1,089 (50) 1,039 1,040 (49) 0.1% 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

13 13 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 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 above the near-term oil price trading range remains a key driver behind Saudi Arabia s support toward negotiating the OPEC production cut back in October 2016 and supporting a nine-month extension recently. Despite the government s efforts to cut costs and diversify its economy away from oil, 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 breakeven oil price of around $48/bbl in 2017, as per IMF projections. Libya, which has the highest breakeven point among the region s OPEC members, is exempt from the production cut targets. That is now beginning to look like a problem. Diagram 10: Estimates for fiscal breakeven oil prices for Gulf OPEC countries Source: IMF (Regional Economic Outlook Middle East and Central Asia, October 2016) Libya 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 ramping up production significantly in the first few months of 2017, adding to the supply woes that the OPEC countries desperately wanted to address. According to Bloomberg data, Libyan production as of May 2017 stood at 760,000 bpd (or 760mbpd), roughly double their average production of 384mbpd in 2016, as major oilfields like the El Sharara and El Feel re-opened. This kind of ramp up looked highly improbable earlier given that 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

14 14 1mmbpd within the next few months, which could seriously undermine OPEC s efforts to control production. Diagram 11: Libya s oil production trends Source: Bloomberg Finance L.P. Nigeria s output could also ramp up in the near term Among non-opec countries, Russia only met its targeted 300mbpd cut in April Similarly, the oilfields in Nigeria are also coming back 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. While non-opec countries, led by Russia, committed to their share of production cuts of about 0.6mmbpd from November 2016 reference levels, compliance to the cuts has been slow, as evidenced by the fact that it took 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 2016 average. Russia will have to seriously demonstrate a cut in production in 2H17 as much of the gradual decline in 1H17 can be attributed to 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 need them to curtail that growth.

15 15 Diagram 12: Russia s oil production trends Source: Bloomberg Finance L.P. Kazakhstan has been non-compliant OPEC s surplus capacity has increased after production cut Kazakhstan was among the six non-opec countries that agreed to support OPEC when it first announced the production cuts last November. Kazakhstan had committed to a 20mbpd 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 re-opening of the massive Kashagan field. Among the non-opec countries which agreed to the production cut, Oman has the best compliance, while Russia took a few months to reach the desired cuts. The Kashagan field alone is producing around 170mbpd currently, and could double that by end This is an added concern at this stage. According to EIA estimates, OPEC s 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 cut, surplus capacity below 2.5mmbpd indicates a relatively tight oil market, based on historical trends. However, the continuing inventory builds, as well as high current and forecast levels of global oil inventories make the projected benign OPEC surplus capacity level less significant. The oil market rebalancing has taken longer than expected 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

16 16 Diagram 13: OPEC s crude oil surplus capacity trends and forecast Source: EIA OPEC s exports have not decreased as much as production so far Cuts in exports should, hopefully, be more visible over the next few quarters in the first five months of 2017, slightly higher than the 25.4mmbpd number in the same period last year. While tanker shipments from Saudi Arabia fell by roughly 440mbpd in the above period, other members more than compensated for Saudi Arabia s cuts, thus suggesting that the kingdom 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. 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 2H17. This is something we need to keep a close watch on.

17 17 Strong US Production Trend Could Lose Steam US shale oil has rebounded off 2016 lows Permian Basin the key driver of recent growth 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-2016 for the first time since oil prices fell in Since September 2016, the trend in production was reversed (see Diagram 14). Total US production rebounded from around 8.6mmbpd in September 2016 to 9.3mmbpd currently, and looks surpass previous highs over the course of 2017/18. Among the seven key shale-producing regions in the US Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian, and Utica the Permian Basin has benefitted the most in terms of recent investments and drilling activity owing to lower cash production costs and improved productivity of new wells. Diagram 14: US crude oil production trends Source: Bloomberg Finance L.P.

18 18 Diagram 15: US crude oil production trends conventional vs tight oil Source: Bloomberg Finance L.P. Diagram 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.

19 19 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 to just 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 a 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 West Texas Intermediate (WTI) oil price trends, as can be seen in the following charts. 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 US shale producers to bump up their capex plans for 2017 after steep cuts in Diagram 17: US rig count has rebounded since mid-2016 Source: Baker Hughes

20 20 Diagram 18: Land rig additions were negative in only five of the last 56 weeks since June 2016 Spending on new drilling programmes in the US has improved since 2H16 Source: Baker Hughes A look at the capex trends for key listed US independent shale players from 2015 onwards (see Diagram 20) show 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 some way off 2015 s 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. Diagram 19: US horizontal rig count vs WTI prices Source: Baker Hughes, Bloomberg Finance L.P.

21 21 Diagram 20: North American top independent shale producers capex trends and production guidance for 2017 Pioneer Natural Resources 2015 Capex (US$bn) 2015 Capex (US$bn) 2017 Capex (US$bn) Y-o-Y Chg Y-o-Y Chg 2017 production guidance % 33% 15-18% production growth Concho Resources % 31% 20-24% production growth 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

22 22 Diagram 21: Permian Basin s top independent shale producers capex and production trends Top ten players Capex (US$bn) Production (mboepd) 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% Y-o-Y Chg Source: Companies, DBS Bank 2. Productivity improvements Rig counts in isolation may not provide the best picture Productivity gains in US main shaleproducing areas have been relentless 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 (see Diagram 22). 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 seven main shale-producing areas in the US have been relentless as drillers 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 October 2014, when rig counts began their steep decline. This is not a new phenomenon as productivity gains have increased at a compound annual growth rate (CAGR) of more than 30% since 2007 (see Diagram 23). These productivity gains helped to partially offset the decline in drilling rigs from October 2014 to June Productivity gains are markedly more visible in the bigger shale-producing areas of Eagle Ford, Bakken, Niobrara, and Permain (see Diagrams 24-29).

23 23 Diagram 22. US horizontal rig count vs US lower 48 states total oil production trends Source: Baker Hughes, Bloomberg Finance L.P. Diagram 23. US productivity by shale oil region - overall Source: Bloomberg Finance L.P., DBS Bank

24 24 Diagram 24: US productivity by shale oil region Bakken Source: Bloomberg Finance L.P., DBS Bank Diagram 25. US productivity by shale oil region Eagle Ford Source: Bloomberg Finance L.P., DBS Bank

25 25 Diagram 26. US productivity by shale oil region Haynesville Source: Bloomberg Finance L.P., DBS Bank Diagram 27. US productivity by shale oil region Marcellus Source: Bloomberg Finance L.P., DBS Bank

26 26 Diagram 28. US productivity by shale oil region Niobrara Source: Bloomberg Finance L.P., DBS Bank Diagram 29. US productivity by shale oil region Permian Source: Bloomberg Finance L.P., DBS Bank

27 27 Production Trends: New Oil Well Production Per Rig Diagram 30. Permian Basin average oil production per well barrels per day first full month 2009 of production pre Niobrara Bakken Utica Haynesville Marcellus 50 Permian Eagle Ford month of operation Source: EIA High initial production rates boosted productivity Tight oil growth has been driven by increasing initial production rates from tight wells in regions analysed 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 seen in Diagram 30, 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 subsequent months are also higher than in previous years, though the decline is sharper as time passes. After a year, average production for wells in 2015 was down to around 65bpd (down 72% from peak), while that in 2014 was down to around 50bpd (down by a lower 67% from peak). Despite the steeper 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.

28 28 Diagram 31: Eagle Ford region average oil production per well barrels per day first full month 2009 of production pre Niobrara Bakken Utica Haynesville Marcellus 100 Permian Eagle Ford month of operation Source: EIA Diagram 32: Bakken region average oil production per well barrels per day first full month 2009 of production pre Niobrara Bakken Utica Haynesville Marcellus 100 Permian Eagle Ford month of operation Source: EIA

29 29 Diagram 33: Niobrara region average oil production per well barrels per day first full month 2009 of production pre Niobrara Bakken Utica Haynesville Marcellus 50 Permian Eagle Ford month of operation Source: EIA New wells producing more, 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 the 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 the 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.

30 30 Production Trends: Legacy Production Changes Decline rates still steep......though signs of stabilisation are emerging Legacy production change refers to the 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. Diagrams show the legacy production change trend for 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) as seen in Diagram 38, highlights the positive and negative drivers in terms of the current US shale rebound. Diagram 34: Bakken region legacy production change Source: EIA

31 31 Diagram 35: Eagle Ford region legacy production change Diagram 36: Niobrara region legacy production change Diagram 37: Permian Basin region legacy production change Sources: EIA

32 32 Diagram 38: Net new production from seven key areas is positive overall in June 2017 DUCs need to be watched Production Trends: Drilled-but-Uncompleted Wells Source: EIA The EIA recently started publishing 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. 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, Diagrams 39 to 42 show that 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 centred. Other shale plays combined continued to draw down on DUCs in 2H16, but even these regions have started to add DUCs YTD in Diagram 39: Bakken region DUCs Source: EIA

33 33 Diagram 40: Eagle Ford region DUCs Diagram 41: Niobrara region DUCs Diagram 42: Permian Basin DUCs Sources: EIA

34 34 Spike in Permian Basin DUCs indicates US production will rise over 2017/18 The recovery in rig counts in the US in recent months has been largely driven by investments in the Permian Basin (see Diagram 43). 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. Diagram 43: Change in DUCs led by Permian Basin since Sep-2016 Source: EIA 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: Drilling Comprises about 30-40% of total well costs. These costs comprise 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.

35 35 Completion 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 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. Operation This is 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 barrel of oil equivalent (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 thousand cubic feet of natural gas (Mcf) or US$ per million British thermal units (mmbtu) or US$ per bbl basis and include gathering, processing, transport, and gas compression costs. Source: EIA, IHS

36 36 Diagram 44: Cost breakdown for US onshore drilling (excluding operation costs) Source: EIA, IHS Drilling, completing costs make up bulk of total costs Drilling and completing costs account for more than three quarters of the total costs for drilling and completing typical US onshore wells. We now look at what are the key cost drivers for drilling and completing typical US shale wells: Rig and drilling fluids costs 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 and cement costs Frac pumps and related equipment costs 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

37 37 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 Proppant costs 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 Completion fluids 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 Diagram 45: Key cost drivers for US onshore drilling Source: EIA, IHS Source: EIA, IHS

38 38 Changes in Technology and Drivers of Efficiency Over the past decade, US shale oil producers have employed new and improved technology to reduce costs and increase production. Technology improvements related to drilling include: 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). Lateral length 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.

39 39 Completions Multi-well pads and higher surface operation efficiency Improved Water Handling 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 increasing 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 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 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.

40 40 Is There a Limit to Cost Reductions and Productivity Improvements? Possible for breakeven prices to reverse trend According to studies done by Rystad Energy, average breakeven prices have dropped 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 in Diagram 47, 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, 1Q17 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 4Q14, 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.

41 41 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 Proppant Like rigs and rig crews, these are specialised services for unconventional resources. We expect price movements to mirror those of rig rates and rentals. Majority of the proppant cost is attributable to 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 2H16. 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. Proppant Water sourcing costs are tied to regulatory conditions and are not market based, although we expect the cost of chemicals and gels to drop. Disposal costs will not be affected by industry activity as rates are based on longterm contracts that escalate each year by around 2%. Source: EIA, DBS Bank Trends in efficiency improvements: Drill days 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. Lateral length 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.