Your essential guide to Organization of the Petroleum Exporting Countries (OPEC) meetings – find out how they affect global oil prices and other energy markets.
The oil industry is back on its feet, and oil prices have rallied to their highest level in almost four years.
‘Energy forecasting is easy. It's getting it right that's difficult,’ - Graham Stein, 1996.
It has been a tumultuous five years for the oil industry. Look back to 2013, and the sector was basking in earnings they had not seen since the financial crisis and as prices reached a high of $115 a barrel in the middle of 2014, Big Oil (the world’s largest six or seven publicly traded oil and gas companies) readied itself for another year of bumper profits.
But as the cyclical nature of the industry dictates, the good times had to come to an end. By early 2015, only six months after reaching new highs, oil prices had plummeted below the $50 mark and by early 2016 prices had reached the trough at just $30.
Big Oil responded as it always does: by cutting costs and spending. When times get tough the oil industry becomes amazed at how wasteful it has been when oil prices were high, and always manages to find billions in savings when forced to, albeit with a lot of help from the oilfield services industry that has to ride in their wake.
With a sector now fit for business and back in profit, oil prices have continued to climb, reaching $78 in May 2018 (its highest level in over three years) with current prices only lingering just below that.
The current support behind oil prices is largely being driven by concerns over tightening supply in the global oil market. Political instability in both Venezuela and Libya, combined with imminent US sanctions on Iran, threatens as much as two million barrels of daily supplies – equal to over 2% of global daily production.
Venezuela’s oil output has already dropped off a cliff, falling by around 700,000 barrels per day over the last year or so, and there are concerns over Libya’s contribution of one million barrels per day due to militia in the country threatening to hand over key oil ports to rivals of the state-owned oil company.
For Iran, the third largest producing country in the Organisation of the Petroleum Exporting Countries (OPEC), contributing about 3.8 million barrels per day, the situation is even more dire. Since the US pulled out of the Iran nuclear deal and warned it would impose new sanctions on the country, it has now been reported that the US is pressuring its allies to stop all imports of crude from Iran by November, which would be a much tougher stance than many first expected.
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With such a large amount of OPEC’s 32.4 million barrels of daily output under threat, the organisation’s leader, Saudi Arabia, and non-OPEC member but now close partner Russia have agreed to take action to plug the gap. Following the most recent meeting, the pair announced the organisation had agreed to raise daily output by one million barrels per day.
Importantly, both Saudi Arabia and Russia are looking to add the majority of that bump-up in production, helping them to steal market share from other countries. However, Iran has claimed that no other member outside of Saudi Arabia or Russia had been given the go-ahead to turn on the taps, and has said that this will see a much smaller rise in OPEC production, of around 500,000 barrels daily. While Saudi Arabia is by far OPEC’s largest producer and willing to leverage its own excess capacity to get its point across to the market, there are concerns that it does not have as much as capacity as is needed.
‘Just spoke to King Salman of Saudi Arabia and explained to him that, because of the turmoil and dysfunction in Iran and Venezuela, I am asking that Saudi Arabia increase oil production, maybe up to 2,000,000 barrels, to make up the difference….prices too high! He has agreed!” – US President Donald Trump on Twitter.
Although OPEC only accounts for about one-third of global production, it is the closest thing there is to a central bank for the oil industry, tasked with balancing supply and demand and steering prices. This was especially true ten years ago, when the US was solely reliant on importing oil and producing just three million barrels per day. But the take-off of US shale has revolutionised the country’s energy production industry and pushed the US’s daily output to over eight million barrels per day in January 2018.
In fact, the US will produce more energy than it needs within the next decade (with some claims it could be as early as 2022). This will make the US an energy exporter and rebalancing the relationship between the country and OPEC after decades of being heavily reliant on energy imports, albeit mostly from Canada but also from member nations.
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So, if the US has a growing oil industry and is slowly becoming less reliant on imports, why does it still rely on OPEC to manage the market and why does it want lower (not higher) prices?
There are a few reasons. Firstly, the US is not self-sufficient in energy and still imports a considerable amount from its northern neighbour and OPEC nations. This is not only down to the US deficit, but also because of the type of oil produced from US shale, which is known as West Texas Intermediate (WTI) and trades a small discount to the international benchmark. WTI is lighter than Brent, meaning that certain US refineries that need a heavier product still have to import it from elsewhere, as an example.
Secondly, the main reason there is concern that a flood of oil could be taken out of the market (and prices could shoot higher) is because the US is seeking to slap new sanctions on Iran and stop it exporting oil altogether. But you can’t pressure the world to cut millions of barrels from daily supply while at the same time asking for lower prices.
Thirdly, with the US midterm elections fast approaching, Trump is trying to make sure that his attacks on the international community – whether it be trade tariffs or the hard-line stance against Iran – doesn’t start hurting consumers and discredit his ambition to overhaul international trade. Even as Trump tells his voters that the blame for any hardship felt by the US in terms of jobs or consumer prices falls at the feet of others, things like rising petrol prices would not win votes later this year.
This is why the US wants Saudi Arabia to plug the gap. It means the country can crackdown on Iran, maintain the balance between supply and demand (and therefore prices), and keep its growing energy industry alive without hurting consumers. Saudi Arabia, Iran’s nemesis, seems happy to oblige and take the opportunity to steal valuable market share from its enemy.
2017 represented a turning point for the oil industry, as all of the big five oil companies delivered significantly better bottom-line results. Much of their resilience during the downturn over recent years has been down to their downstream divisions that refine oil and purify natural gas and produce a range of products like petrochemicals. While the upstream divisions centred on producing oil and gas struggled amid lower prices, downstream units helped absorb those losses by remaining profitable.
Despite the majority of oil majors having sunk to heavy losses in recent years, they have ensured that investors have been looked after by maintaining dividend pay-outs, even if that has meant using debt. Following the cyclical nature of the market, oil majors often flex their muscles during tough times and build up debt during downturns in the knowledge that the eventual upswing is coming. When cash flow starts to gain momentum, they can not only to pay the debt but also improve shareholder returns. While all of the oil majors have at least maintained pay-outs over the last three years, only a handful have been able to afford to keep their progressive dividend policies.
Using debt to sweeten shareholders may sound like a dangerous ploy for any company but for the oil industry it seems to have paid off. Almost all of the big five saw their net debt levels reduced for the first time in years in 2017 as cash flow levels gradually return to their pre-downturn levels, and the message to patient shareholders that have been dealt stagnate or slow-growing pay-outs over the last few years is quite clear: expect both dividends and share buybacks to ramp up over the coming years.
The fact that BP returned to profit in 2017 after two years of heavy losses was extra sweet for investors, as the company has now largely drawn a line under the Deepwater Horizon accident in the Gulf of Mexico back in 2010 that killed 11 people and tarnished the company’s reputation. Almost $66 billion has been spent on the clean-up and legal costs, and while that sum could continue to creep up over the coming years, BP investors now know the worst is behind them.
|BP ($, billions)||2013||2014||2015||2016||2017|
|Pre-tax profit (loss)||30.2||5||(9.6)||(2.3)||7.2|
|Operating cash flow||21.1||32.8||19.1||10.7||18.9|
While BP has managed to perform well through the downturn (relative to rivals amid the additional issues it has had to address), the eye-watering sums spent on the Deepwater Horizon ultimately means that both results and the dividend have been held back. Pay-outs were flat for the third straight year in 2017, and BP relaunched its scrip dividend programme late last year.
2017 was the first year of BP’s five-year strategy running to 2021, and saw BP launch seven major new upstream projects to help lift production by 12% to 3.6 million barrels per day, report record downstream earnings and deliver its ‘most successful year for exploration since 2004’. One of the major aims of its five-year plan is to add 900,000 barrels of oil production on a net basis, compared to its 2015 base.
BP has already launched one new project this year (Atoll in Egypt) with another five to follow, which will lead to higher annual output this year. If oil prices can hold up, this should lead to another year of progress, particularly as it is being more stringent with spending and planning to sell another $2-$3 billion of assets. As demonstrated over the past few years, BP’s immediate aim is to sustain dividends.
For Royal Dutch Shell, there has been the added complication of integrating BG Group into its business after purchasing the gas company in 2015 for $47 billion. That also prompted the firm to launch a $30 billion asset sale programme to streamline its now much larger portfolio, and although that has essentially been completed, Shell has continued to sell-off assets, most recently two fields offshore Norway for $550 million.
Royal Dutch Shell managed to escape the red during the downturn, but that does not take away from the huge lift in profit in 2017. Shareholders have also been pleased with the large chunk of debt paid off last year after the company’s debt pile swelled in 2016. While Shell has kept dividends flat through the cycle too, it actually cancelled its long-running scrip alternative late last year as BP relaunched its own. In addition, it has pledged to buyback $25 billion of shares between 2018 and 2020.
|Shell ($, billions)||2013||2014||2015||2016||2017|
|Pre-tax profit (loss)||33.6||28.3||2||5.6||18.1|
|Operating cash flow||40.4||45||29.8||20.6||35.7|
While production remained flat last year at 3.7 million barrels a day, output was still one million barrels higher than it was in 2014, and Shell has since made one of its largest discoveries for over a decade in the US Gulf of Mexico after drilling the whale deep-water well with partner Chevron.
With cash flow increasing and debt reducing, Shell aims to follow a ‘lower forever’ approach to capital spending going forward. Although the BG asset disposal programme will be completed by the end of this year, it will be followed by another round of divestments worth a minimum of $5 billion between 2019 and 2020.
ExxonMobil has arguably been the most resilient oil giant through the most recent downturn, comfortably remaining in the black and keeping its progressive dividend, while debt finally started to fall last year.
The company is currently boasting better average returns on capital employed, claiming it has delivered 17.6% over the past ten years, compared to Chevron at 12.6%, Shell at 9.2%, Total at 9.1% and BP at 7%. It also claims its integration means it is worth considerably more as a whole than it is on a sum-of-parts basis, where each part of the business is valued independently of one another.
|ExxonMobil ($, billions)||2013||2014||2015||2016||2017|
|Pre-tax profit (loss)||57.7||51.6||22||8||18.7|
|Operating cash flow||33.4||33.6||30.3||22.1||30.1|
ExxonMobil says its investments in recent years has captured the company’s ‘highest-quality inventory’ since the Exxon and Mobil merger in 1998, highlighting high-impact projects in the likes of Guyana and Brazil that will add around 450,000 barrels of net production by 2025, as well as new LNG projects being developed in Papua New Guinea and Mozambique. Its ramp-up in the US Permian basin is at the heart of its upstream growth plans, with the area to add almost 600,000 barrels to daily production on a net basis by 2025.
Its downstream business is focused on margins and higher-value products, while capacity is being added to the high-growth chemicals division.
Although Chevron sank to a loss in 2016, the company returned to healthy profit last year and managed to maintain its progressive pay-out, which is the ‘first financial priority’ of the company. Last year represented the 30th consecutive year of higher annual dividends.
The company has sold off $8 billion worth of assets over the past two years, with more potentially on the cards.
|Chevron ($, billions)||2013||2014||2015||2016||2017|
|Pre-tax profit (loss)||35.9||31.2||4.8||(2.2)||9.2|
|Operating cash flow||35||31.5||19.5||12.8||20.5|
In addition to the major discovery with Shell in the Gulf of Mexico, Chevron launched production in Angola, Australia and Canada during 2017, while building out its US downstream business.
Chevron’s future upstream growth is also centred around the Permian basin, where it already produces over 180,000 barrels per day. Overall net oil production is to rise 4% to 7% this year, although it has said any movement in oil prices could change this.
Total has been focused on improving cash flow in recent years by stripping out costs and becoming more efficient, and results have improved annually since 2015.
The French giant introduced a new dividend strategy in 2015 after making a cut to the pay-out, and that has now seen three consecutive years of dividend growth (in addition to buybacks), with expectations for that to continue in the coming years. This is supported by plans to make $4 billion worth of cost-savings in 2018 alone. A maximum of $5 billion of shares will be bought back between 2018 and 2020, Total said, with the dividend to rise 10% to hit €2.72 per share in 2020.
|Total ($, billions)||2013||2014||2015||2016||2017|
|Pre-tax profit (loss)||26.3||12.8||6.5||7.2||11.3|
|Operating cash flow||28.5||25.6||19.9||16.5||22.3|
|Net cash (debt)||23.6||28.8||26.6||27.1||15.4|
The newest projects adding production to Total’s base include the likes of Yamal LNG in Russia and Moho Nord in the Congo. Two new projects were launched in the first quarter (Q1) of this year, Fort Hills in Canada and Timimoun in Algeria, as well as from asset purchases including a swathe of North Sea oil projects bought from Maersk Oil. Overall, the ambition is to grow annual production by an average of 5% up until 2022.
Mid-cap oil companies like FTSE 250 constituents Premier Oil, Tullow Oil, Cairn Energy and Energean Oil & Gas have had a tougher time weathering the downturn for a number of reasons. Some chase a very different business model (like Cairn Energy, which primarily focuses on making discoveries and selling them on for a profit with production a secondary objective), and others are ramping-up production from quite low levels like Mediterranean-focused Energean.
They also lack the muscles that the oil majors boast in terms of downstream operations and their ability to leverage debt in the same way.
|($, millions)||Premier Oil||Tullow Oil||Cairn Energy||Energean Oil|
|Pre-tax profit (loss)||(414)||(366)||(908)||(299)||(152)||256||(50)||25|
|Operating cash flow||431||496||597||1158||(21)||29||15||29|
|Net debt (billions), (cash)||2.8||2.7||4.8||3.5||0.3||(0.1)||48||76|
These mid-cap companies offer high growth to investors at a time when the industry looks to be over the worst of the downturn, but the recovery will be slower. With no dividends being paid by any of the four UK mid-caps shareholders should not expect any pay-outs in the immediate future.
The highlight for Premier Oil last year was the launch of the major Catcher project in the UK North Sea, which will help the company lift daily production this year to 80,000 to 85,000 barrels per day having lifted output to 75,000 barrels per day last year. While it has prioritised debt and cost reductions this year it will still progress two more major projects in 2018.
The outlook for Tullow Oil is ‘brighter than it has been for some time’, and it now plans to invest in its portfolio after spending the last few years creating a more disciplined business. The company’s producing projects in West and East Africa will remain at the heart of the business while it builds reserves through exploration in Africa and South America, and it will have no problem chopping and changing its portfolio in order to free up capital.
Cairn Energy hit a milestone last year after its joint ventures in the North Sea started producing, one of which was the Catcher project with Premier and the other named Kraken in partnership with EnQuest. These will help provide cash flow to fund its exploration in the likes of Senegal.
Energean Oil is a Greek firm that only listed in London in March 2018, raising $460 million to develop two gas fields in offshore Israel. Believing that the Eastern Mediterranean is attracting more attention from bigger players, Energean plans to acquire, de-risk and develop projects in the region while scaling up its existing portfolio.
Companies like John Wood Group, Weir Group, Petrofac, and Hunting provide services such as drilling, project management, engineering work and so on to oil companies. These oilfield service providers ride in the wake of the oil industry, with the downturn taking about two years to fully trickle down to the sector. Oil companies will often cancel or delay major investments in new projects during a downturn, and pressure oilfield service providers to provide discounts and help with cutting costs.
This two-prong hit to the industry, with lower levels of work as well as tighter margins from any work they do secure, has sparked a wave of consolidation among oilfield service providers, led by John Wood’s purchase of struggling rival Amec Foster Wheeler last year. It was the same in the US, where Schlumberger bought Cameron and Baker Hughes merged with General Electric’s oil and gas business. This has seen oilfield service providers become more efficient and operate at a lower cost base and now that oil prices are improving and activity levels are starting to pick-up the recovery is starting to drip-down to the service sector.
‘The United States is on pace to becoming the world’s top oil producer by 2023, thanks mainly to the phenomenal growth of shale production. The IEA estimates that by then, US output will expand by 3.7 million barrels per day, more than half of the world’s expected production capacity growth. One region in particular stands out – the Permian basin in West Texas,’ – International Energy Agency (IEA) oil analyst Oliver Lejeune.
The Permian basin spreads over Texas and New Mexico, has been key to the significant jump in shale production in the US over recent years and will continue to be at the hub of US development in the future. The IEA predicts that daily US output in 2023 will be 3.7 million barrels higher than current levels, and the Permian basin will contribute 2.7 million barrels toward that growth (73%).
More deals have been struck in the Permian basin in recent years than other region of the US, as players look to gain or grow their foothold in the area. ExxonMobil announced in early 2017 that it was to double its resource base in the Permian by snapping up assets for an initial payment of $5.6 billion, and Chevron said in January 2017 that it was aiming to lift output from the region by 25% to 35% by 2020, potentially taking the firm’s total Permian production to over 700,000 barrels per day.
There are a string of US players that offer exposure to this growing region, including Apache Corp, Pioneer Natural Resources, WPX Energy, Cimarex Energy and Resolute Energy.
However, the region does have a major problem that the industry will have to quickly address. There is widespread expectation that pipeline and storage capacity is far behind the growth in production, sparking fears the region (and therefore the US energy story as a whole) could be held back unless significant investment is made.
‘Backed by an enduring plan we can add a generation of life to the basin, double our supply chain’s global footprint and continue powering the nation for many years to come,’ – Mike Tholen, upstream policy director at trade body UK Oil & Gas.
The UK North Sea has been at the forefront of the international oil industry for decades. But as the downturn started to bite the area’s high cost base, with ever-deeper wells and more costly operations needed to find new resources, meant discussion about the region moved on to decommissioning rather than future growth.
But the downturn has actually been beneficial to the region. The drop in oil prices encouraged aggressive cost-cutting, increased collaboration and an overall huge effort to make producing North Sea oil profitable again. The (better than expected) success over the years, coupled with the upturn in prices, has now revived the home of Brent oil, with industry now working under a plan to extend output under ‘Vision 2035’.
UK Oil & Gas expects ‘around 16 projects’ to get the go-ahead this year, potentially unlocking up to £5 billion worth of new investment, supported by the most recent licensing round that saw interest shift from new exploration areas to formerly-producing, more mature fields that have become attractive once again.
BP had exploration success last year, brought the Quad 204 project online and is expected to start production from Clair Ridge later this year. Shell’s Penguins field is due to be the biggest development project this year, when Premier is due to start output from the Tolmount gas field.
But, while activity in the region is picking up, there is concern that exploration efforts are lacking and risking the three to nine billion barrels of oil UK Oil & Gas believes is left to be found, suggesting that companies are keen to extract what’s left of the existing resources, but not as keen to find new ones.
‘As we look to the future, there is much we do not know,’ – Chevron chairman Michael Wirth.
There has been one overriding difference in the most recent cycle of the oil industry, and that is the general shift away from fossil fuels toward renewable and more sustainable energy sources. While this has long been in the back of oil executive’s minds, the urgency to address it has been lacking. But the industry has now had to seriously start to think about its long-term future, with forecasts for oil demand to peak over the next ten to 15 years.
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This is leading to more questions being asked about the long-term future of the oil industry. All of the oil majors have made some form of move into renewables, and most of them have stretched their legs into new markets. Shell purchased UK energy provider First Utility last year in order to rival the monopolised energy supply market in the UK (for example), and BP spent £130 million on Chargemaster, which deploys charging points in the UK for electric vehicles. Still, there are many question whether Big Oil can or should lead the renewables industry.
A more certain course that investors can expect majors to take over the coming years is a heightened focus on downstream operations and petrochemicals. While demand for oil to power vehicles or for use as an energy source is to decline, forecasts suggest that demand for oil from the petrochemical industry will be 35% higher in 2040 than the 17.4 million barrels used each day by the sector in 2016, according to the IEA. Investment in petrochemicals is rising as companies look to maximise the value they get out of each barrel, feeding demand for products from emerging middle classes in the likes of Asia and Africa.
Moving to renewable energy would involve the reinvention of one of the biggest industries in the world. Although petrochemicals provide a more likely option, it is one that alone cannot plug the gap that will be left by the move away from fossil fuels.
This has led to calls for the industry to start investing less in projects and returning more cash to shareholders. Oil majors will not be tightening their purse strings for a while, but some expect it to happen in the medium term. Investors are ready for higher dividends and returns, and the sector looks set to continue investing in new projects over the coming years. The question of how Big Oil will deploy its cash over the longer term is not yet known.
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