Oil prices have rallied from US$27/bbl at the start of this year to above US$50/bbl this month. ING believes prices are now at a soft ceiling and will face headwinds not just in the short term, but also the long term.
While it was clear that supply would be constrained at sub-US$30/bbl and prices were expected to tread higher, the pace of this quarter’s recovery was quickened by the threat of supply disruptions in countries such as Nigeria and Canada.
Without these temporary outages, one has to ask what has changed since last year’s bear market. Inventories are still at or near seasonal records. Iran is increasing exports faster than most expected. US rig counts have started to increase once again. Capex cuts have petered out. And OPEC maintains its coda of market share at any cost.
ING’s ‘Crude oil special: Medium-term update’ report covers five significant issues which have led it to revise its medium term oil prices lower through 2018: Saudi Aramco IPO and market diversification, the decline in automotive demand, increasing the share of renewables, cost efficiency of US shale, and other shale resources.
Saudi Aramco IPO and market diversification
2018 is likely to be the year of the world’s largest-ever IPO, valuing oil producer Saudi Aramco at c. US$2 trillion. The immediate impact of an IPO should be higher production but, more importantly, the offering is a bellwether for Saudi Arabia’s push away from a heavy dependence on oil.
In the Kingdom’s recently unveiled ‘Vision 2030’ plan, Saudi targets to become among the 15 largest economies (versus a current position of ninteenth) by 2030. The Kingdom aims to increase its non-oil government revenues from 163 billion riyals to 1 trillion riyals by 2030. It is hoped that unemployment will fall from 11.6% to 7%, whilst the private sector contribution towards GDP will be raised from 40% to a targeted 65%. Meanwhile, the share of total small and medium enterprises in the Kingdom is planned to increase from 20% to 35%, with the government planning to make it easier for SMEs to access capital.
To achieve these targets, the country would need a large amount of (foreign and local) investment in the industrial sector. For external investment, Saudi is aiming to increase FDI from 3.8% to 5.7% of GDP by 2030, an ambitious target given the political volatility in the region. For internal investment, oil revenue is the only major source of initial funds, so in the meantime the aim is likely to maximise oil revenues.
Following the IPO, Saudi Aramco will have to act in the best interests of shareholders. Aramco will need to maximise returns for shareholders, and the way to do this is by fully utilising assets. The oil producer will find it difficult to hold back capacity from the market, and so instead of seeing just over 10 million bpd, we should see closer to 11.5 million bpd, which is where current capacity is reported to be. This also calls into question the future of OPEC. Saudi Arabia is the largest OPEC oil producer, accounting for over 30% of the cartel’s total production. If Aramco moves further away from OPEC policy, this will make the cartel a weaker force, which could see other member countries also more reluctant to hold back capacity. Maybe a more extreme view, but there is the potential that the Aramco IPO leads to the eventual break up of OPEC.
The decline in automotive demand
The transportation sector, including shipping, aviation and others, makes up 64% of global crude oil demand, with automobiles alone accounting for 43% (and as much as c. 55% in countries like the US). This demand is being battered on all sides – from higher efficiency ratings (US fuel mileage has increased from 22.1 mpg in 2010 to 25.4 mpg in 2016 YTD) to fuel displacement.
Over the first four months of 2016, global electric vehicle sales increased 43% y/y to c.184 000 units, with nearly a quarter of these sales (49 762 units) coming from the US. China has increased sales by nearly 100% y/y, while Europe saw growth of c. 40% y/y.
This argument has been heard before. Automotive displacement was meant to take place from compressed natural gas or methanol or hydrogen fuel cells – even Israeli Californian start-up Better Place was supposed to end electric car range anxiety using swappable batteries at service station. Yet Better Place went bankrupt within six years and oil has remained king for a century due to a host of issues for replacements – reliability, cost, infrastructure, etc.
With electric vehicles, this time seems different. According to the EIA Annual Energy Outlook, growth in gasoline-based vehicle fleets will be flat over the next 20 years, while electricity-based fleets could increase at a 20 year CAGR of 10 - 15%; other alternative fuels (including CNG, propane and hydrogen cell) could be reporting a CAGR of 0 - 5%. Infrastructure build-out has already taken place, with electric charging stations in the US increasing from just 541 in 2010 to 30 945 at the end of 2015. Growth is global instead of confined to regional availability (such as ethanol in Brazil or CNG in South Asia), and the major automotive companies are playing catch-up instead of ignoring the technology.
The cost argument is also becoming easier to make, with the prospect of Tesla’s US$30 000 Model 3 and falling component costs. According to a UN report released in March 2016, battery costs (one of the most expensive parts of EVs) dropped from US$1000/kwh in 2010 to c. US$350/kwh in 2015. A cost of US$150 - 200/kwh theoretically makes EVs competitive to gasoline-fuelled cars.
Many call out the existing asset base of refined fuel vehicles as a hurdle to EV penetration. Yet car ownership has transitioned in recent years to a lease model. Instead of holding a car for 20 years, consumers change on a lease every three years. Perhaps in three years’ time electric cars will remain too expensive for lease holders to switch. Perhaps in six years, availability will not be wide enough to suit consumer tastes. But by the third lease cycle in nine years’ time, the argument for electric vehicles will be compelling for vast swathes of the population.
Add these together and on a base case estimate of a 15% CAGR for the next 20 years, global EV car sales are likely to increase to c.17 million units by 2040, displacing nearly 4 million bpd of crude oil demand.
Crude oil displacement could increase to c. 9 million bpd if EV sales increase at a 20% CAGR, a not too far-fetched target given the potential for lower prices in the sector.
Further displacement could come from biofuels. The general trend globally is an increase in biofuel mandates, which should see more of a push towards ethanol/biodiesel at the expense of gasoil/gasoline demand. While governments are keen to implement ethanol mandates, it becomes a bit more difficult to enforce them (more so in developing economies). For example, the Indian government increased its ethanol mandate from 5% to 10% a couple of years ago, but the industry is still battling to meet the previous 5% mandate. If countries can enforce these mandates, expect significant shifts for gasoil/gasoline demand.
Increasing share of renewables
Turning to industrial demand for oil, there is also scope to see a move away from oil as a feedstock and more of a shift towards renewable sources.Global industrial sector demand for oil peaked back in the late 1970s and ever since then has been in decline, from just over 10 million bpd in 1979 to around 6 million bpd in 2013.
In the US, the renewable share (ex-nuclear) in electricity generation has increased from 8% in 2007 to 13% in 2015 and further to 17% in 1Q16.With the COP21 Paris climate accords, no new coal capacity is expected to come on line, opening the door for renewables globally.
If we include nuclear power, Portugal managed to run on 100% renewable electricity for four consecutive days in May 2016, and Germany increased its renewable share up to 90% at times this quarter.
European renewables, including nuclear, already contribute 50% towards electricity generation at times, which could increase to c. 60 - 70% by 2020. The poster child for renewables in the industrial sector would be Tesla’s upcoming ‘gigafactory’, designed to be powered entirely by solar.
Meanwhile, developing countries are also investing heavily in renewable energy, with their US$156 billion outpacing the US$130 billion investment seen in developed countries over 2015.
If industrial demand for oil continues to decline at the same pace as it has been since the 1970s (0.6% per annum), we could see another 1 million bpd of oil demand displaced by 2040. However, given the drive for renewable sources, the actual decline could be even more aggressive.
Cost efficiency of US shale
Technological improvements in US shale exploration continue to improve production efficiency (oil per rig/well) and cost economics. A significant portion of US shale oil fields are profitable, with crude oil prices ranging at US$40 - 50/bbl, and the cost could come down further over the next few years as companies continue to improve efficiency.
Pioneer Resources announced that its cash production cost dropped from US$12.6/bbl in 1Q15 to US$9.2/bbl in 1Q16 (a 27% saving y/y) due to a sharp drop in fracking costs from US$1140/feet in 1Q15 to US$890/feet in 1Q16. Cost reductions are not specific to Pioneer Resources, and the increasing usage of EOR/IOR processes will expand the range of assets profitable at US$30 - 40/bbl, moving forward.
This point can be tackled from the other direction by looking at hedge books. For instance, Denbury Resources has suggested that it will increase its 4Q16 hedge quantity to 30 million bpd at about US$38/bbl. Similarly, EOG Resources initiated swaps for 128 million bpd of oil production in May - June 2016. According to the CFTC’s Commitment of Traders (COT) report, commercial players further increased their net short position to c. 285 000 lots during the week ended 7 June from c. 250 000 net shorts in January 2016. Producers willing to sell at current levels create headwinds for higher levels.
Other shale resources
For the longer term, much has been written about low prices writing off difficult resources such as Arctic fields or Kara Sea drilling. The question is whether these fields can be displaced by alternative sources of production including methane hydrates for natural gas and global shale production for oil.Despite the current focus on US shale, the country is home to less than 20% of global shale oil reserves, with 78.2 billion bbls. Others include: Russia, with 74.6 billion bbls, China, with 32.2 billion bbls and Argentina, with 27 billion bbls.
The progress on ex-US shale development has been slow due to political, technological or environmental reasons; however, the tide has been turning as recent efficiency gains in shale drilling bring down costs, while improving technical expertise makes previously difficult terrain more safely accessible.
In March 2016, BP and CNPC signed a production sharing agreement for the shale gas development project in the Neijiang-Dazu block in the Sichuan Basin, China – BP estimated in its latest annual energy outlook that China will become the world’s largest- growing shale gas producer by 2035. Meanwhile, Sinopec has been producing 5 billion m3/y of shale gas at its southwest Chongqing field, which it expects to triple to 15 billion m3/y by 2020.
In addition to China, Argentina offers promising potential growth in shale in the near future, with oil majors including Exxon, Shell and Chevron active in the country’s shale deposits. Exxon has been investing in Argentina’s Vaca Muerta shale oil/gas field, with US$200 million invested so far and a further US$250 million investment planned over the next few months for the pilot project. Depending upon the outcome of the pilot project, Exxon can increase its investment to US$10 billion in the field. Shell has also planned a test well for shale oil by the end of this year. In January 2016, Argentina’s state-owned YPF and American Energy Partners created a US$500 million joint venture to explore the Neuque´n basin for shale oil.
There is plenty of shale oil out there. With advances in technology lowering extraction costs, it seems to be a matter of when we will see this new supply hit the market.
Adapted from press release by Rosalie Starling
Read the article online at: https://www.hydrocarbonengineering.com/refining/30062016/ing-releases-crude-oil-special-medium-term-update-report-3618/