Oil Price Rebalancing Underway 19

SECTOR BRIEFING number DBS Asian Insights DBS Group47 Research • August 2017 Oil Price Rebalancing Underway 19

DBS Asian Insights SECTOR BRIEFING 47 02

Oil Price Rebalancing Underway

Suvro SARKAR Equity Analyst DBS Group Research [email protected]

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

Glenn NG Equity Analyst DBS Group Research [email protected]

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

Produced by: Asian Insights Office • DBS Group Research

go.dbs.com/research @dbsinsights [email protected]

Goh Chien Yen Editor-in-Chief Jean Chua Managing Editor Geraldine Tan Editor Martin Tacchi Art Director 19

DBS Asian Insights SECTOR BRIEFING 47 03

04 Executive Summary Demand-Supply Equation Can Only 06 Improve Hereon But Inventory Drawdown Will Be 08 Slow at Best OPEC Adherence to Production Cuts 11 Has Been Sincere So Far Strong US Production Trend Could 17 Lose Steam 19 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 40 and Productivity Improvements? Cut in Global Oil & Gas Capex Positive 50 for Prices 52 Geopolitical Risks Not a Big Mover DBS Asian Insights SECTOR BRIEFING 47 04

Executive Summary

Prices back to rent crude has averaged around US$52.8 per barrel (bbl) year-to-date, higher than levels before OPEC 2016’s average of US$45.1/bbl as prices held up well around the US$50-55/bbl production cut, but not mark in the early months of 2017, following optimism on supply moderation after for long the Organization of Petroleum Exporting Countries (OPEC) cut production in late B2016. 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 In the near term, we believe the negative drivers have been largely priced in and as we see to continue in near sustained evidence of inventory drawdowns in the US and Organisation for Economic Co- term operation 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-2017. 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. DBS Asian Insights SECTOR BRIEFING 47 05

2018 should see While our updated 2017 forecast is slightly lower than our previous projections, we expect further market Brent crude oil to average between US$55-60/bbl in 2018, with the mild year-on-year rebalancing (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.

Longer-term forecasts We expect oil prices to move upwards at a faster trajectory toward the end of the decade. maintained 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 2020. Also, the need to develop oil production in more expensive areas – and the cost of the most expensive last barrel needed to meet demand – will continue to support oil prices. 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 DBS Asian Insights SECTOR BRIEFING 47 06

Demand-Supply Equation Can Only Improve Hereon

Rebalancing will happen lobal oil supply growth slowed significantly in 2016 as the US shale boom took in 2017 a breather. This was after two years of supercharged production growth in 2014 and 2015. 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 GOPEC 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. 2016 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 We expect oil consumption to grow by 1.3mmbpd and 1.4mmbpd in 2017 and 2018, steady 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. DBS Asian Insights SECTOR BRIEFING 47 07

Diagram 2. Global oil production and consumption – trends and forecasts (EIA)

Source: EIA Diagram 3: DBS’ forecasts for global oil production, consumption growth, and inventory build-up Supply Growth Demand Inventory Build (mmbpd) Growth (mmbpd) (mmbpd) 2014 2.5 1.4 1.1 2015 2.1 1.4 1.8 2016 Total 0.4 1.4 0.8 US -0.6 OPEC 0.7 Russia 0.3 2017 Total 0.4 1.3 -0.1 US 0.4 OPEC -0.4 Kazakhstan 0.1 Canada 0.3 Russia 0.0 2018 Total 0.7 1.4 -0.7

Source: EIA, DBS Bank estimates DBS Asian Insights SECTOR BRIEFING 47 8

But Inventory Drawdown Will Be Slow at Best

US crude inventories at S crude oil stocks did not fall as fast as anticipated, given the attempted similar levels y-o-y 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 2017. This is still a very high reading for this Utime of the year and is almost the same level as in June 2016. 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 While the US inventory levels is a good barometer of excess oil in the system, given levels just starting to the regular data flow and the fact that it consumes about 20% of the world’s oil thaw 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 2011-14. EIA estimates that total current OECD commercial oil inventories are equivalent to roughly 64 days of consumption, and while there is DBS Asian Insights SECTOR BRIEFING 47 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)

Source: EIA

Diagram 6: OECD’s commercial oil stocks - days of supply

Source: EIA DBS Asian Insights SECTOR BRIEFING 47 10

Inventory drawdowns Given that supply is expected to grow slower than demand in 2017 and 2018, we expect expected from 2H17 market rebalancing to occur in 2017 and for the market to go into a minor supply deficit onwards 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 2018. This should support our near-term oil price recovery thesis from 2H17 onwards.

But clearing the entire According to EIA data and our estimates, the gap between supply and demand (or in glut could take years other terms, inventory build) averaged around 1.1mmbpd in 2014, 1.8mmbpd in 2015, and 0.8mmbpd in 2016. 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 2017.

The International Energy Agency (IEA) estimates that the inventory built up from 2014-16 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 The continuing large inventory builds is a major source of risk to oil prices as the capacity sharp recovery in oil of the global storage system to handle this much additional supply is unknown. If the prices 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. DBS Asian Insights SECTOR BRIEFING 47 11

OPEC Adherence to Production Cuts Has Been Sincere So Far

OPEC extends production n its most recent general meeting in Vienna in May 2017, OPEC members decided to cuts till March 2018 extend the previously agreed upon production cuts for nine more months from July 2017 to March 2018. 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 2017. IThe 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.

Decent compliance to OPEC and non-OPEC countries made a landmark decision on 30 November 2016 to jointly cut production cuts YTD in production by about 1.8mmbpd from October 2016 reference levels for a six-month period 2017 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. DBS Asian Insights SECTOR BRIEFING 47 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 260 340 520 580 630 690 700 620 550 760 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 660 640 620 620 620 615 620 610 615 620 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 550 560 560 550 550 530 535 530 530 530 Venezuela 2,190 2,200 2,180 2,120 2,080 2,030 2,030 2,000 1,980 1,980 Gabon 210 210 200 210 210 195 180 180 200 200 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. Diagram 9: OPEC’s crude output adjustments by member country YTD in 2017 (mbpd) Reference Proposed Proposed Jan - May Observed Production production adjustment production 2017 actual adjustment deviation level level effective production YTD in 2017 from Jan 2017 average 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 90 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) 618 616 (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) 522 531 (17) 1.7% Venezuela 2,067 (95) 1,972 2,004 (63) 1.6% Indonesia Suspended membership Gabon 202 (9) 193 191 (11) -1.0% Total (1,166) (1,423)

Source: OPEC, Bloomberg Finance L.P., DBS Bank DBS Asian Insights SECTOR BRIEFING 47 13

Managing fiscal deficits The International Monetary Fund (IMF) has forecast a fiscal breakeven oil price of about US$78/ will force OPEC countries bbl for Saudi Arabia in 2017. While the breakeven oil price has fallen from close to US$106/ to remain prudent 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 Libya, one of the most unstable countries in North Africa and the entire Gulf region, for production significantly that matter, has beaten market expectations – ramping up production significantly in the compared to last year 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 DBS Asian Insights SECTOR BRIEFING 47 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 Similarly, the oilfields in Nigeria are also coming back as militant activity has subsided, and also ramp up in the output could ramp up from current levels of 1.6-1.7mmbpd to 2.0mmbpd. Royal Dutch near term 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 While non-OPEC countries, led by Russia, committed to their share of production cuts of about countries, Russia 0.6mmbpd from November 2016 reference levels, compliance to the cuts has been slow, as only met its targeted evidenced by the fact that it took until April 2017 for Russia to bring down production to 300mbpd cut in April 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. DBS Asian Insights SECTOR BRIEFING 47 15

Diagram 12: Russia’s oil production trends

Source: Bloomberg Finance L.P.

Kazakhstan has been Kazakhstan was among the six non-OPEC countries that agreed to support OPEC when it non-compliant 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- 2018. This is an added concern at this stage.

OPEC’s surplus capacity According to EIA estimates, OPEC’s surplus crude oil production capacity averaged only has increased after 1.1mmbpd in 2016, but is expected to increase to around 2.1mmbpd in 2017 following the production cut 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 DBS Asian Insights SECTOR BRIEFING 47 16

Diagram 13: OPEC’s crude oil surplus capacity – trends and forecast

Source: EIA

OPEC’s exports have in the first five months of 2017, slightly higher than the 25.4mmbpd number in the same not decreased as much period last year. While tanker shipments from Saudi Arabia fell by roughly 440mbpd in as production so far 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.

Cuts in exports should, With the extension of output cuts for another nine months, export declines could catch hopefully, be more up with production cuts for other OPEC members as well, and we should see faster visible over the next rebalancing of the oil market as we move into 2H17. This is something we need to keep few quarters a close watch on. DBS Asian Insights SECTOR BRIEFING 47 17

Strong US Production Trend Could Lose Steam

US shale oil has riven by a more stable oil price environment, supportive government policies, rebounded off 2016 falling costs, and rising productivity, onshore rig counts in the US (mainly lows supporting tight oil regions) started to rise in mid-2016 for the first time since oil prices fell in 2014. Since September 2016, the trend in production was Dreversed (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.

Permian Basin the key Among the seven key shale-producing regions in the US –Bakken, Eagle Ford, Haynesville, driver of recent growth 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. DBS Asian Insights SECTOR BRIEFING 47 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 1,224,295 986,050 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) 305,806 487,841 427,034 450,168 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. DBS Asian Insights SECTOR BRIEFING 47 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 2016.

Diagram 17: US rig count has rebounded since mid-2016

Source: Baker Hughes DBS Asian Insights SECTOR BRIEFING 47 20

Diagram 18: Land rig additions were negative in only five of the last 56 weeks since June 2016

Source: Baker Hughes

Spending on new A look at the capex trends for key listed US independent shale players from 2015 onwards drilling programmes in (see Diagram 20) show that producers are looking to increase capex by an average of 30- the US has improved 40% in 2017. This comes after a sharp 50%+ decline in capex on average in 2016, and since 2H16 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. DBS Asian Insights SECTOR BRIEFING 47 21

Diagram 20: North American top independent shale producers – capex trends and production guidance for 2017

2015 2015 2017 2015-2016 2016-2017 2017 production guidance Capex Capex Capex Y-o-Y Chg Y-o-Y Chg (US$bn) (US$bn) (US$bn) Pioneer Natural 1.9 2.1 2.8 14% 33% 15-18% production Resources growth Concho Resources 2.0 1.3 1.7 -35% 31% 20-24% production growth ConocoPhillips 10.1 4.9 5.0 -51% 2% Flat to 2% growth in production Hess Corporation 4.0 2.1 2.3 -48% 7% Occidental Petroleum 5.6 2.9 3.3 -48% 14% 4-7% production growth Anadarko Petroleum 5.5 2.8 4.6 -49% 64% 24-26% production growth Noble Energy 3.0 1.5 2.2 -50% 47% Flat to 2% growth in production EOG Resources 4.9 2.6 3.9 -47% 50% 18% production growth Marathon Oil 3.1 1.4 2.2 -55% 57% 5% production growth Chesapeake Energy 3.0 1.7 2.2 -43% 29% 10% production growth Apache Corporation 3.8 1.9 3.1 -50% 63% 10% production growth Newfield Exploration 1.7 0.8 1.0 -56% 33% 3-5% production growth EP Energy 1.4 0.5 0.7 -64% 36% Negative 6-14% growth Continental Resources 2.7 1.1 2.0 -59% 77% 1-6% growth Devon Energy 4.1 1.2 2.2 -71% 79% 13-17% growth Murphy Oil 2.3 0.6 0.9 -74% 48% Flattish production Whiting Petroleum 2.3 0.6 1.1 -76% 99% 4-6% growth Total 61.4 29.9 41.0 -51% 37%

Source: Companies, DBS Bank DBS Asian Insights SECTOR BRIEFING 47 22

Diagram 21: Permian Basin’s top independent shale producers – capex and production trends

Capex (US$bn) ’15-‘16 ’16-‘17 Production (mboepd) ’15-‘16 ’16-‘17 Top ten 2015players 2016 2017 Y-o-Y Y-o-Y 2015 2016 2017 Y-o-Y Y-o-Y Chg Chg Chg Chg Parsley 0.5 0.5 1.1 2% 120% 22.0 38.3 65.0 74% 70% PDC Energy 0.6 0.4 0.8 -33% 88% 15.4 22.0 30.8 43% 40% RSP Permian 0.4 0.3 0.7 -25% 117% 21.0 29.2 55.0 39% 88% Pioneer 1.9 2.1 2.8 11% 33% 204.0 234.0 272.0 15% 16% Laredo 0.6 0.4 0.5 -33% 33% 44.8 49.6 57.0 11% 15% Concho 2.0 1.3 1.7 -35% 31% 52.3 55.1 66.1 5% 20% Cimarex 1.0 0.8 1.2 -20% 44% 164.2 160.5 181.4 -2% 13% SM Energy 1.3 0.7 0.9 -46% 25% 147.0 151.0 109.6 3% -27% Occidental 5.6 2.9 3.3 -48% 14% 110.0 124.0 140.0 13% 13% Energen 1.2 0.6 0.8 -48% 32% 53.6 54.6 65.7 2% 20% Diamondback 0.4 0.4 0.9 -5% 125% 33.1 43.0 69.0 30% 60% Total 15.5 10.4 14.5 -33% 40% 867.4 961.3 1111.6 11% 16%

Source: Companies, DBS Bank

2. Productivity improvements

Rig counts in isolation While growing rig counts is definitely a good indicator of current and future supply, may not provide the productivity improvements in the past have meant that production has been much best picture 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 Productivity gains across the seven main shale-producing areas in the US have been in US’ main shale- relentless as drillers applied new, innovative technologies to increase output and reduce producing areas have drilling time. As a result, new-well oil production per rig – the benchmark for productivity been relentless – 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 2016. Productivity gains are markedly more visible in the bigger shale-producing areas of Eagle Ford, Bakken, Niobrara, and Permain (see Diagrams 24-29). DBS Asian Insights SECTOR BRIEFING 47 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 DBS Asian Insights SECTOR BRIEFING 47 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 DBS Asian Insights SECTOR BRIEFING 47 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 DBS Asian Insights SECTOR BRIEFING 47 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 DBS Asian Insights SECTOR BRIEFING 47 27

Production Trends: New Oil Well Production Per Rig

Diagram 30. Permian Basin – average oil production per well

barrels per day 2015 2014 barrels per day 2015 2014 2013 2012 2013 2012 500 2011 2010 250 2011 2010 ﬁrst full month ﬁrst full month 2009 2008 2009 2008 of production of production 2007 pre-2007 2007 pre-2007 400 200 Bakken Bakken 300 Marcellus 150 Marcellus Niobrara Niobrara Utica Utica

200 Haynesville 100 Haynesville Permian Permian 100 Eagle Ford 50 Eagle Ford

0 0 0 12 24 36 48 60 0 12 24 36 48 60 month of operation month of operation Source: EIA

High initial production Tight oil growth has been driven by increasing initial production rates from tight wells in rates boosted regions analysed by the EIA. As drilling techniques and technology improve, producers are productivity 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 seen2015 in Diagram 201430, production barrels per day 2015 2014 per well peaked at around 230bpd in the first month of production2013 compared2012 to around barrels per day 2013 2012 500 150bpd in the first month of production in 2014. The production2011 profiles in 2010the subsequent ﬁrst full month 250 2011 2010 2009 2008 ﬁrst full month of production months are also higher than in previous years, though the decline is sharper as time passes. 2009 2008 2007 pre-2007 of production 400 After a year, average production for wells in 2015 was down to around 65bpd (down 72% 2007 pre-2007 from peak), while that in 2014 was down to around 50bpd (down by a lower 67% from 200 Bakken peak). Despite the steeper decline, the amount of oil produced per well (area under the curve) Bakken 300 is significantly higher each year. Similar trajectories are observed for other key shale-producingMarcellus Niobrara 150 Marcellus areas in the US. Utica Niobrara Utica

200 Haynesville This leads us to two obvious conclusions: i) Fewer newer wells are required to 100 Haynesville replace ageing wells; and ii) the same number of new wellsPermian will result in much higher Permian 100 production levels than before. Eagle Ford 50 Eagle Ford

0 0 0 12 24 36 48 60 0 12 24 36 48 60 month of operation month of operation barrels per day 2015 2014 barrels per day 2015 2014 2013 2012 2013 2012 500 2011 2010 250 2011 2010 ﬁrst full month ﬁrst full month 2009 2008 2009 2008 of production of production 2007 pre-2007 2007 pre-2007 400 200 Bakken Bakken 300 Marcellus 150 Marcellus Niobrara Niobrara Utica Utica

200 Haynesville 100 Haynesville Permian Permian DBS Asian Insights 100 Eagle Ford 50 Eagle Ford SECTOR BRIEFING 47 28 0 0 0 12 24 36 48 60 0 12 24 36 48 60 month of operation month of operation

Diagram 31: Eagle Ford region – average oil production per well

2015 2014 barrels per day 2015 2014 2013 2012 barrels per day 2013 2012 500 2011 2010 ﬁrst full month 250 2011 2010 2009 2008 ﬁrst full month of production 2009 2008 2007 pre-2007 of production 400 2007 pre-2007 200 Bakken Bakken 300 Marcellus Niobrara 150 Marcellus Utica Niobrara Utica

200 Haynesville 100 Haynesville Permian Permian 100 Eagle Ford 50 Eagle Ford

0 0 0 12 24 36 48 60 0 12 24 36 48 60 month of operation month of operation Source: EIA

Diagram 32: Bakken region – average oil production per well

200 Haynesville 100 Haynesville Permian Permian 100 Eagle Ford 50 Eagle Ford

0 0 0 12 24 36 48 60 0 12 24 36 48 60 month of operation month of operation Source: EIA

200 Haynesville 100 Haynesville Permian Permian 100 Eagle Ford 50 Eagle Ford

200 Haynesville 100 Haynesville Permian Permian 100 Eagle Ford 50 Eagle Ford DBS Asian Insights SECTOR BRIEFING 47 0 0 29 0 12 24 36 48 60 0 12 24 36 48 60 month of operation month of operation

Diagram 33: Niobrara region – average oil production per well

200 Haynesville 100 Haynesville Permian Permian 100 Eagle Ford 50 Eagle Ford

0 0 0 12 24 36 48 60 0 12 24 36 48 60 month of operation month of operation Source: EIA

New wells producing The increasing prevalence of hydraulic fracturing and horizontal drilling, along with more, a trend for nine improvements in well completions and the ability to drill longer laterals, has greatly consecutive years 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. DBS Asian Insights SECTOR BRIEFING 47 30

Production Trends: Legacy Production Changes

Decline rates still Legacy production change refers to the change in the region’s production from existing wells steep... 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 34-37 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.

...though signs of However, in the case of the more mature Bakken and Eagle Ford regions especially, this trend stabilisation are seems to have reversed in early 2015, which meant production could be sustained at a decent emerging 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 DBS Asian Insights SECTOR BRIEFING 47 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 DBS Asian Insights SECTOR BRIEFING 47 32

Diagram 38: Net new production from seven key areas is positive overall in June 2017

Source: EIA Production Trends: Drilled-but-Uncompleted Wells

DUCs need to be The EIA recently started publishing data on drilled-but-uncompleted wells (DUCs), which can watched 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 2017. Diagram 39: Bakken region – DUCs

Source: EIA DBS Asian Insights SECTOR BRIEFING 47 33

Diagram 40: Eagle Ford region – DUCs

Diagram 41: Niobrara region – DUCs

Diagram 42: Permian Basin – DUCs

Sources: EIA DBS Asian Insights SECTOR BRIEFING 47 34

Spike in Permian The recovery in rig counts in the US in recent months has been largely driven by investments Basin DUCs in the Permian Basin (see Diagram 43). This underpins our belief that US shale production indicates US will continue to increase in 2017/18 as long as prices are above the US$45/bbl level production will rise – by around 0.4mmbpd in 2017 and another 0.7mmbpd in 2018. Beyond that, capex over 2017/18 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. DBS Asian Insights SECTOR BRIEFING 47 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 DBS Asian Insights SECTOR BRIEFING 47 36

Diagram 44: Cost breakdown for US onshore drilling (excluding operation costs)

Source: EIA, IHS

Drilling, Drilling and completing costs account for more than three quarters of the total costs for completing costs drilling and completing typical US onshore wells. We now look at what are the key cost make up bulk of drivers for drilling and completing typical US shale wells: total costs Rig and • Around 15% of total costs; rig-related costs are dependent on drilling drilling fluids efficiency, well depths, rig day rates, mud use, and diesel fuel rates costs • 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 • Casing costs are driven by the casing markets, often related to steel cement prices, dimensions of the well, and by the formations or pressures that affect costs the number of casing strings

Frac pumps • Around 24% of total costs; dependent on horsepower needed and and related number of frack stages equipment costs • 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 DBS Asian Insights SECTOR BRIEFING 47 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 • Around 14% of total costs and include the amount and rates for the costs 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 • Proppant transported from the sand mine or factory to the well site, and fluids 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

Diagram 45: Key cost drivers for US onshore drilling

Source: EIA, IHS DBS Asian Insights SECTOR BRIEFING 47 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 The shift from vertical to horizontal wells is the most important change to length 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. DBS Asian Insights SECTOR BRIEFING 47 39

Completions 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 Multi-well pad drilling allows for maximisation reservoir penetration pads and with minimal surface disturbance, which is important in areas that are higher environmentally sensitive, have little infrastructure, or in mountainous surface areas with extensive terrain relief. Operational costs are reduced as this operation allows operators to check wellhead stats (pressure, production, etc.) on efficiency 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.

Improved As water resources become increasing scarce, operators are forced to Water come up with better solutions for the amount of water used for each Handling 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 For the main shale players, breakeven prices for shale are falling every year. This is a result shale have fallen every of both a reduction on well cost and an increase in oil recovery per well, as discussed in year 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 2013. 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. DBS Asian Insights SECTOR BRIEFING 47 40

Is There a Limit to Cost Reductions and Productivity Improvements?

Possible for breakeven ccording to studies done by Rystad Energy, average breakeven prices have dropped prices to reverse trend 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 Apricing 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 These services were created specifically for unconventional oil and natural and rentals 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 2010. 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. DBS Asian Insights SECTOR BRIEFING 47 41

Casing and Casing cost is driven primarily by steel prices, which moved up in 1Q17 cement 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 Like rigs and rig crews, these are specialised services for unconventional equipment resources. We expect price movements to mirror those of rig rates and rentals. and crews

Proppant 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 long- term 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 Annual rates of increase are slowing, which may be due to limitations length 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. DBS Asian Insights SECTOR BRIEFING 47 42

More Operators continue to push the limits and production may continue proppant to increase as some operators are using as much as 2,000 pounds of per foot proppant per foot. 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 the Marcellus and Bakken regions where pay zones are typically thinner. As proppant levels increase, additional fluid will be needed for emplacement.

More wells Facilities costs per well will decrease as facilities are increasingly designed on a drill pad 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 Operators are putting more frack stages within the lateral length as stage stages lengths are decreasing to around 150-200 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 Proppant amounts are expected to increase in all plays. However, proppant proppants types will move toward cheaper natural proppant, except in Eagle Ford where proppant mixes are weighted more toward artificial sand.

Source: EIA, DBS Bank DBS Asian Insights SECTOR BRIEFING 47 43

Case Study Whiting Petroleum in Bakken by Rystad Energy

Rystad Energy did 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 2014. 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 DBS Asian Insights SECTOR BRIEFING 47 44

Costs inching up In light of the case study done by Rystad Energy on the Bakken area, we have also tracked for select US shale the operating/production costs of producers focused in the Permian Basin, the key area of producers recent activity and investment. A look at the financials of some of these players in Diagrams 49-52 shows 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 began 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 now a higher risk of costs surprising on the upside than downside.

Diagram 46: RSP Permian – cash operating costs (US$ per boe)

Diagram 47: Pioneer Natural Resources - cash production costs (US$ per boe)

Note: LOE – Lease Operating Expenses, G&T – Gathering & Transportation Expenses, G&A – General & Administrative Expenses Source: Companies, DBS Bank DBS Asian Insights SECTOR BRIEFING 47 45

Diagram 48: Concho Resources – cash operating costs (US$ per boe)

Diagram 49: Laredo Petroleum - cash production costs (US$ per boe)

Note: LOE – Lease Operating Expenses, G&T – Gathering & Transportation Expenses, G&A – General & Administrative Expenses Source: Companies, DBS Bank

Productivity We tracked well productivity data for seven key shale-producing areas in the US. While there improvements are were sharp improvements between 2014 and 2015, and again between 2015 and 2016, plateauing 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. DBS Asian Insights SECTOR BRIEFING 47 46

Diagram 50: Productivity (bpd/well) – average of 7 key shale regions

Diagram 51: Productivity (bpd/well) – Permian Basin

Source: Bloomberg Finance L.P., DBS Bank DBS Asian Insights SECTOR BRIEFING 47 47

Diagram 52: 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 111 385 562 1,000 1,130 Growth 247% 46% 78% 13% Eagle Ford – productivity 42 548 757 1,365 1,448 Growth 1205% 38% 80% 6% Haynesville – productivity 6 20 25 30 33 Growth 233% 25% 20% 10% Marcellus – productivity 4 30 46 84 70 Growth 650% 53% 83% -17% Niobrara – productivity 35 325 554 1,199 1,288 Growth 829% 70% 116% 7% Permian – productivity 66 188 291 646 640 Growth 185% 55% 122% -1% Utica – productivity 20 54 176 117 234 Growth 170% 226% -34% 100% Total – productivity 42 285 402 692 732 Growth 578% 41% 72% 6%

Source: Bloomberg Finance L.P., DBS Bank

Oil prices in excess In Diagrams 56-59, we track the profitability of a broad gamut of listed US shale oil producers of US$50/bbl are against prevailing WTI oil prices. While the companies will typically hedge a portion of their necessary for further production, it seems apparent that spot WTI prices play a big role in revenues and profits. investment While the cash breakeven level of shale-producing areas in the US have fallen and are currently between US$30-45/bbl, it is apparent that return on equity (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 the US$40-45/bbl range, thus limiting future capex and production growth and hence, helping to swing oil prices back to healthier levels. DBS Asian Insights SECTOR BRIEFING 47 48

Diagram 53: US shale producers’ quarterly revenue vs WTI

Diagram 54: US shale producers’ quarterly net profit vs WTI

Sources: Bloomberg Finance L.P., DBS Bank DBS Asian Insights SECTOR BRIEFING 47 49

Diagram 55: US shale producers’ quarterly net profit margin vs WTI

Diagram 56: US shale producers’ quarterly ROE vs WTI

Sources: 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 DBS Asian Insights SECTOR BRIEFING 47 50

Cut in Global Oil & Gas Capex Positive for Prices

Expect tighter oil hile US onshore capex is projected to increase in 2017, the picture is market closer to 2020 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 Wprojects 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 Capex budgets worldwide have been cut substantially since the onset of the collapse in oil down by about 40% prices. Capex budgets for 2015 and 2016 were slashed by an average of about 25% each in 2017 compared to year across our sample, and while 2017 may not see such steep cuts, there is no visible 2014 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 2H17. In any case, we do not expect capex levels to recover back to the highs of 2012-14 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 2000-2014 for an almost five-fold increase. Diagram 57: Capex budgets for select oil majors: 2017E vs 2014A – average decline of about 40%

Source: Companies, DBS Bank DBS Asian Insights SECTOR BRIEFING 47 51

All these capex cuts will Final investment decisions (FIDs) on 68 large projects globally totalling US$380 billion in capex pave the way for higher were deferred since crude prices first plunged in 2014, according to a report by research and prices in longer term 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 start-ups currently targeted to take place in 2020-23. By 2021, deferred liquids volumes are estimated to reach 1.5 mmbpd, and rising sharply to 2.9 mmbpd by 2025. The impact on supply will be felt more acutely in the medium term as it typically takes 5-7 years to bring a greenfield conventional project into commercial production.

According to estimates from Rystad Energy, marginal sources of supply in 2020 will come Oil prices may stabilise from currently non-producing shale fields (new shale) and oil sands, with a weighted average around US$60-65/bbl breakeven price of around US$63-66/bbl. The Rystad Energy liquids cost curve is made up in the longer term of nearly 20,000 unique assets and considers each asset’s breakeven oil price and potential production in 2020. The breakeven price is the Brent crude oil price at which net present value 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.

Diagram 58: Global liquids cost curve analysis from Rystad Energy

Source: Rystad Energy DBS Asian Insights SECTOR BRIEFING 47 52

Geopolitical Risks Not a Big Mover

n one of our earlier reports, we had flagged the Syrian crisis as a potential source of geopolitical risk if the conflict escalates and results in confrontation between regional rivals Saudi Arabia and Iran. So far, the conflict has had limited impact on oil prices as the global supply glut has ensured minor supply disruptions are ignored by the market. IAgainst this backdrop, we examine whether the recent Qatar blockade led by some Gulf Cooperation Council members will have any impact on the market.

What is the Qatar On 4 June 2017, the United Arab Emirates (UAE), Saudi Arabia, and Bahrain dramatically blockade? escalated an ongoing conflict with their Gulf neighbour, Qatar. They severed diplomatic ties; closed off air, sea, and land routes; restricted the entrance of Qatari citizens and residents to their countries; and gave their own citizens 14 days to leave Qatar. Egypt also cut off diplomatic ties with Qatar and access to its airspace – but importantly, did not cut access to the Suez Canal, which is governed by an international agreement, nor did it ask its citizens who are working and living in Qatar to leave. On 23 June, Saudi Arabia, the UAE, Egypt, and Bahrain issued Qatar a list of 13 demands through Kuwait, which is acting as a mediator, for Qatar to agree in full within 10 days.

Why this diplomatic The blockade was ostensibly in retaliation to Qatar’s funding of terrorist organisations. crisis? The above countries’ frustration with Qatar had been simmering for years, largely over its support for Islamist movements, including the Muslim Brotherhood and Hamas, its cordial relations with Iran, and its practice of hosting opposition figures and giving them a voice on Al Jazeera, its widely viewed television news network. Incidentally, Qatar is also a close ally of the US, hosting the largest American base in the Middle East, but curiously, US President Donald Trump has welcomed the move by Saudi Arabia.

What is the impact on Qatar is a global leader in liquefied natural gas (LNG) production. Despite the severing of ties, the energy trade? Qatari natural gas continues to flow to the UAE and Oman through Abu Dhabi-based Dolphin Energy’s pipeline. The pipeline meets about 30-40% of UAE’s energy needs. Exports of LNG, Qatar’s main source of revenue, have not been affected much and there is little expectation that they will be. OPEC member Qatar exports around 500 mbpd of oil and disruptions to this would not have much material impact on global supply. Shipping constraints as a result of the crisis have led to some rerouting of shipments of oil and gas to and from the Gulf, but within a week, alterative shipping routes have emerged via Oman and other ports farther away. Within a couple of months, the situation in Qatar would likely stabilise. DBS Asian Insights SECTOR BRIEFING 47 53

How long can this While it is difficult to predict how long or how difficult it will be for Qatar to meet the blockade last? demands of its neighbouring states, it can be safely said that it is not benefitting anyone. Qatar is highly integrated, both socially and economically, with its neighbours, especially Saudi Arabia and the UAE. Qatar imports roughly 40% of its food overland through Saudi Arabia, and most of the rest via shipping routes that pass through the UAE ports of Dubai and Fujairah to refuel. In 2015, the value of Qatar’s trade flows totalled over US$2 billion with Saudi Arabia, US$7 billion with the UAE, and US$500 million with Bahrain. Qatar exports more to those three countries than it imports. The Saudi banking sector’s exposure to Qatar is estimated to be around US$30 billion. The UAE banking sector’s exposure is thought to be of similar magnitude. This blockade comes at a time of severe economic downturn in the Gulf countries owing to the fall in global energy prices. Large infrastructure projects have been put on hold or cancelled, payments have been delayed, and salaries and headcounts reduced to cope with the fall in government revenue. The economies of Saudi Arabia, the UAE, Bahrain, and Qatar can ill afford further disruptions.

Impact of the standoff In the past, geopolitical tension in the Middle East would usually send oil prices higher is likely to be limited by a few dollars per barrel. This risk premium in the price of oil captured the possibility of supply disruptions arising from potential conflicts in the Middle East. However, so far in the current oil price crisis, the global supply glut has loomed much larger than anything else in determining the price of oil and the events in the Middle East barely registered. The only detriment to the oil market would be the ability of OPEC to maintain consensus within its members if the issues with Qatar snowball into bigger issues between Saudi and Iran, which could destabilise the pact to curb oil production.

The only detriment to the oil market would be the ability of OPEC to maintain consensus within its members if the issues with Qatar snowball into bigger issues between Saudi and Iran DBS Asian Insights SECTOR BRIEFING 47 54 DBS Asian Insights SECTOR BRIEFING 47 55

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