Conservative estimates suggest that in the wake of oil prices crashing in late 2014, the Malaysian oil and gas services and equipment (OGSE) sector contracted by at least 11%. Analysis of overall financials for the OGSE sector by the Malaysian Petroleum Resource Corp, an agency under the Prime Minister’s Department, reveal that revenue for 2015 fell by 11%, while profits contracted by a severe 52.3%. Including companies such as MISC, Sapura Energy, Dialog, Scomi, Bumi Armada, the numbers for 2016 are not available yet, but a glance over the financial reports released for the bigger players indicate that while sector revenue will probably be down for the year, profits maybe be up, after aggressive cost-cutting that included a tide of retrenchments.
So what is in store in 2017 and beyond?
If we go by the health of Petroliam Nasional Berhad, better known as Petronas, the word seems to be “cautiously optimistic”. The guardian and bellwether of Malaysia’s Oil & Gas sector, Petronas is one of the few major integrated state oil companies that is holding up fairly well during the current on-going oil crises. Petrobras is engulfed in debt, as is PDVSA, while Pertamina appears to be struggling with corruption and clarity of its long term investment direction while select Russian entities battle being used as political tools. Full year 2016 revenue for Petronas fell by 17.3% from lower sales coupled with weak crude prices but profit was up by a whopping 28% to RM16.95 billion (US$3.82 billion), just slightly behind Shell’s own profit for 2016. For 2017, Petronas projects better times ahead, promising no more staff redundancies and bolstering defences by pegging its 2017 capex expenditure at US$45/b, while it prepares to focus on natural gas - both at home in Sarawak and Sabah, and abroad in its Canadian LNG export project, and the recent go-ahead given to its massive US$27 billion RAPID refinery and petrochemicals project.
However if oil prices fall any further or just lingers within the US$50-55/b range, the so called recovery being experienced now, may just stagnate or not be strong enough to re-boot the industry to its previous glorious days and create the jobs badly needed for Malaysia. The threat of market oversupply is still there as US shale oil continues to grow unabatedly. The reality is low oil prices for (much) longer. The future prosperity of Petronas would depend on how much it can increase its productivity and lower production costs. Petronas has moved very decisively and embarked on intensifying its internal cost competitiveness through better collaboration amongst other upstream operators in Malaysia through the CORAL 2.0 project, and is beginning to see lower cost scenarios for its well engineering programs already. On the new technology front, Petronas is collaborating with MIT Innovation Sdn Bhd (MIT) to promote a smart and efficient technology that significantly lowers drilling costs. All moves in the right direction.
The weak link to Petronas’s current cost strategy and competitiveness globally could however be its very own local supply chain. As Petronas tries to prosper in the current climate, the industry that supports it needs to be similarly positioned to do the same - efficient and cost competitive. With the exception of a few large players like MISC, Sapura Energy and Dialog that have the width and breadth to survive challenging conditions like in 2015 and 2016, further down the supply chain, the smaller players many of whom are just agents or third-party equipment representatives do not necessarily own technology, are extremely vulnerable to volatility. (Debt is a particularly pressing concern in this end of spectrum especially in the offshore segment, with players like UMW Oil & Gas, Dayang Entreprise and Perisai Petroleum Teknologi facing recent problems in renegotiating their debt incurred during the good times. Those who can’t keep afloat will be targets for acquisition or forced mergers, like the recent merger between UMW Oil and Gas, Icon Offshore and Orkim.) In a recent business seminar, Malaysia Petroleum Resources Corp (MPRC) senior vice-president Syed Azlan Syed Ibrahim said that “although we foresee 2017 will not be far off than 2016, I do not think it will be worse. This is the opportunity for players to make the hard decision to restructure or reform. That time is now. They (local oil & gas supply chain companies) need to do it now so that when the market goes back up they will be ready” Calls for consolidation amongst local companies, especially in the upstream segment will help strengthen the industry, allowing for greater combination of resources for increased technological innovation and value creation that is urgently needed for Petronas to be competitive locally and overseas. Less reliance on foreign US dollar denominated technology or service providers will help Petronas achieve its low cost operations goal.
As Petronas announces fewer projects in 2017 compared to pre-2014 levels, local service player will need to compete and work outside Malaysia for revenue and business growth. It will be useful here for the local oil industry to emulate the success in the Norway. As we have seen and witnessed the growth of Statoil, Norway's national oil company, as a global player in the oil industry, it is backed-up with a group of highly matured and capable technology and services providers. The grouping is now known as Norwegian Energy Partners or NORWEP in short. NORWEP looks beyond the shores of Norway for new business, and compete for projects globally. It independently (without Statoil’s direct assistance) builds relations with other governments and strategically partners with other state controlled oil companies. To date, it has achieved a respectable track record in developing new technologies in enhanced oil recovery methods as well as strong health & safety in its operations.
Looking into the future of energy, the argument for diversification into how energy will be generated, distributed and utilised also seems compelling. Shell is convinced that the next phase of fossil fuel energy will belong to gas. Petronas is well positioned in the gas business, as it continues to be within the top 3 exporters of LNG globally with strong gas reserves and infrastructure locally as well as internationally, especially in Canada. However the argument for energy diversification goes further from fossil fuels. During the 2017 CERAWeek, the fossil fuel big annual conference, most speakers proclaim a long and prosperous future for their industry. But companies and countries that rely on oil and gas income are recognizing that renewable forms of electricity are gaining traction as prices come down and their popularity rises. Oil executives are adapting their portfolios to add cleaner fuels and moderating their rhetoric on climate change. "A low-carbon future will reshape the energy space. Some see this as a threat to our industry, but we should rather look for and act on the opportunities it offers," said Eldar Sætre, CEO of Norway's Statoil. "We have to respond more forcefully to the challenge of climate change." The oil and gas industry has clearly recognized that its monopoly on transportation fuels is weakening for the first time since automobiles replaced horse-drawn carriages. To be fair, Petronas has embarked on feasibility projects in renewable energy space with the commissioning of a Solar Independent Power Plant (IPP) project in Gebeng in Kuantan. The Solar IPP project came on-stream in 2013 has a capacity of 10 megawatt peak (MWp). However this venture seems to be dwarfed by recent announcements especially from the gulf operators. Saudi Aramco is planning to produce 10 gigawatts of power from renewable energy sources including solar, wind and nuclear by 2023 and transform Aramco into a diversified energy company. The kingdom also plans to develop a renewable energy research and manufacturing industry as part of an economic transformation plan announced by Deputy Crown Prince Mohammed bin Salman. Shell, Europe’s largest oil company, has also recently established a separate division, called New Energies, to invest in renewable and low-carbon power. The new division brings together its existing hydrogen, biofuels and electrical activities. Should Petronas make bigger investment in-roads into the renewable energy sector now rather than later? Shell is projecting that it will not make any money from renewable investments at least for another 10 years. Getting ahead in the game will certainly help any new player. Noting of course that there are other players in Malaysia in the renewable energy scene, for example Tenaga Nasional Berhad or TNB is growing its portfolio in solar energy aggressively.
In conclusion, Petronas seems to be generally on the right path in evolving its energy mix and growth strategy in the energy sector. Being a state controlled company, it will require undivided political support to transform its local supply chain and embark on a commercially driven low cost structure. If the large dividends that Petronas pays annually to Government are to continue, it should be an incentive for the Government for more action to reform the industry’s supply and support base.
Petronas being a large and complex business, reforms typically take time. However due to the prolonged nature of the low oil price climate, the pace of change impacting the industry seems to be moving faster compared to previous downturns. As the oil business is global and fairly transparent in terms of revenue and cost structure, Petronas is unfortunately unable to dictate it’s not own timeline in reforming itself and the industry that supports it. “Faster the better..lah” seems to come to mind. Easier said than done.
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Throughout much of its history, the United States has imported more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it has exported. That status changed in 2020. The U.S. Energy Information Administration’s (EIA) February 2021 Short-Term Energy Outlook (STEO) estimates that 2020 marked the first year that the United States exported more petroleum than it imported on an annual basis. However, largely because of declines in domestic crude oil production and corresponding increases in crude oil imports, EIA expects the United States to return to being a net petroleum importer on an annual basis in both 2021 and 2022.
EIA expects that increasing crude oil imports will drive the growth in net petroleum imports in 2021 and 2022 and more than offset changes in refined product net trade. EIA forecasts that net imports of crude oil will increase from its 2020 average of 2.7 million barrels per day (b/d) to 3.7 million b/d in 2021 and 4.4 million b/d in 2022.
Compared with crude oil trade, net exports of refined petroleum products did not change as much during 2020. On an annual average basis, U.S. net petroleum product exports—distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others—averaged 3.2 million b/d in 2019 and 3.4 million b/d in 2020. EIA forecasts that net petroleum product exports will average 3.5 million b/d in 2021 and 3.9 million b/d in 2022 as global demand for petroleum products continues to increase from its recent low point in the first half of 2020.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook (STEO), February 2021
EIA expects that the United States will import more crude oil to fill the widening gap between refinery inputs of crude oil and domestic crude oil production in 2021 and 2022. U.S. crude oil production declined by an estimated 0.9 million b/d (8%) to 11.3 million b/d in 2020 because of well curtailment and a drop in drilling activity related to low crude oil prices.
EIA expects the rising price of crude oil, which started in the fourth quarter of 2020, will contribute to more U.S. crude oil production later this year. EIA forecasts monthly domestic crude oil production will reach 11.3 million b/d by the end of 2021 and 11.9 million b/d by the end of 2022. These values are increases from the most recent monthly average of 11.1 million b/d in November 2020 (based on data in EIA’s Petroleum Supply Monthly) but still lower than the previous peak of 12.9 million b/d in November 2019.
In the past week, crude oil prices have surged to levels last seen over a year ago. The global Brent benchmark hit US$63/b, while its American counterpart WTI crested over the US$60/b mark. The more optimistic in the market see these gains as a start of a commodity supercycle stemming from market forces pent-up over the long Covid-19 pandemic. The more cynical see it as a short-term spike from a perfect winter storm and constrained supply. So, which is it?
To get to that point, let’s examine how crude oil prices have evolved since the start of the year. On the consumption side, the market is vacillating between hopeful recovery and jittery reactions as Covid-19 outbreaks and vaccinations lent a start-stop rhythm to consumption trends. Yes, vaccination programmes were developed at lightning speed; and even plenty of bureaucratic hiccoughs have not hampered a steady rollout across the globe. In the UK, more than 20% of adults have received at least one dose of the vaccines, with the USA not too far behind. Israel has vaccinated more than 75% of its population, and most countries should be well into their own programmes by the end of March. That acceleration of vaccinations has underpinned expectations of higher oil demand, with hopes that people will begin to drive again, fly again and buy again. But those hopes have been occasionally interrupted by new Covid-19 clusters detected and, more worryingly, new mutations of the virus.
Against this hopeful demand picture, supply has been managed. Squabbling among the OPEC+ club has prevented a more aggressive approach to managing supply than kingpin Saudi Arabia would like, but OPEC+ has still managed to hold itself together to placate the market that crude spigots will remain restrained. And while the UAE has successfully shifted OPEC+ quota plan for 2021 from quarterly adjustments to monthly, Saudi Arabia stepped into the vacuum to stamp its authority with a voluntary 1 million barrels per day cut. The market was impressed.
That combination of events over January was enough to move Brent prices from the low US$50/b level to the upper US$50/b range. However, US$60/b remained seemingly out of reach. It took a heavy dusting of snow across Texas to achieve that.
Winter weather across the northern hemisphere seemed harsher than usual this year. Europe was hit by two large continent-wide storms, while the American Northeast and Pacific Northwest were buffeted with quite a few snowstorms. Temperatures in East Asia were fairly cold too, which led to strong prices for natural gas and LNG to keep the population warm. But it was a major snowstorm that swept through the southern United States – including Texas – that had the largest effect on prices. Some areas of Texas saw temperatures as low as -18 degrees Celsius, while electricity demand surged to the point where grids failed, leaving 4.3 million people without power. A national emergency was declared, with over 150 million Americans under winter storm warning conditions.
For the global oil complex, the effects of the storm were also direct. Some of the largest oil refineries in the world were forced to shut down due to the Arctic conditions, further disrupting power and fuel supplies. All in all, over 3 mmb/d of oil processing capacity had to be idled in the wake of the storm, including Motiva’s Port Arthur, ExxonMobil’s Baytown and Marathon’s Galveston Bay refineries. And even if the sites were still running, they would have to contend to upstream disruptions: estimates suggest that crude oil production in the prolific Permian Basin dropped by over a million barrels per day due to power outages, while several key pipelines connecting Cushing, Oklahoma to the Texas Gulf Coast were also forced to shutter.
That perfect storm was enough to send crude prices above the US$60/b level. But will it last? The damage from the Texan snowstorm has already begun to abate, and even then crude prices did not seem to have the appetite to push higher than US$63/b for Brent and US$60/b for WTI.
Instead, the key development that should determine the future range for crude prices going into the second quarter of 2021 will be in early March, when the OPEC+ club meets once again to decide the level of its supply quotas for April and perhaps beyond. The conundrum facing the various factions within the club is this: at US$60/b, crude oil prices are not low enough to scare all members in voting for unanimous stricter quotas and also not high enough to rescind controlled supply. Instead, prices are at a fragile level where arguments can be made both ways. Russia is already claiming that global oil markets are ‘balanced’, while Saudi Arabia is emphasising the need for caution in public messaging ahead of the meeting. Saudi Arabia’s voluntary supply cut will also expire in March, setting up the stage for yet another fractious meeting. If a snow overrun Texans was a perfect storm to push crude prices to a 13-month high, then the upcoming OPEC+ meeting faces another perfect storm that could negate confidence. Which will it be? The answer lies on the other side of the storm.
Much like the year itself, the final quarter of 2020 proved to be full of shocks and surprises… at least in terms of financial results from oil and gas giants. With crude oil prices recovering on the back of a concerted effort by OPEC+ to keep a lid on supply, even at the detriment of their market share, the fourth quarter of 2020 was supposed to be smooth sailing. The tailwind of stronger crude and commodity prices, alongside gradual demand recovery, was expected to have smoothen out the revenue and profit curves for the supermajors.
That didn’t happen.
Instead, losses were declared where they were not expected. And where profits were to be had, they were meagre in volume. And crucially, a deeper dive into the financial results revealed worrying trends in the cash flow of several supermajors, calling into question the ability of these giants to continue on their capital expenditure and dividend plans, and the risks of resorting to debt financing in order to appease investors and yet also continue expanding.
Let’s start with the least surprising result of all. For months, ExxonMobil had been signalling that it would be taking a massive writedown on its upstream assets in Q4 2020, which could lead to a net loss for the quarter and the year. Unlike its peers, ExxonMobil had resisted making writedowns on the value of its crude-producing assets earlier in 2020. At the time, it stated that it had already built caution in the value assessments of those assets, reflecting ‘fair value’; not so long after that bold statement, ExxonMobil has been forced to backtrack and make a US$20.2 billion downward adjustment. Unusually, that meant that non-cash impairments aside, ExxonMobil actually eked out a tiny profit of US$110 million for the quarter on the strength of margins in the chemicals segment, but a full year loss of US$22.4 billion: the first ever annual loss since Exxon and Mobil merged in 1998. This was better than expected by Wall Street analysts, who would also be cheering the formation of ExxonMobil Low Carbon Solutions, in which the group would pump some US$3 billion through 2025 to reduce its greenhouse gas emissions by 20% from 2016 levels. That acknowledgement of a carbon neutral future is still far less ambitious than its European counterparts, but is a clear sign that ExxonMobil is starting to take the climate change element of its business more seriously.
If ExxonMobil managed to surprise in a good way, then its closest American rival did the opposite. Chevron had been outperforming ExxonMobil in quarterly results for a while now, but in Q4 2020 retreated with a net loss of US$665 million. That was narrower than the US$6.6 billion loss declared in Q4 2019, but still a shock since analysts were expecting a narrow profit. Calling 2020 ‘a year like no other’, the headwinds facing Chevron in Q4 2020 were the same facing all majors and supermajors, despite gains in crude prices, refining margins and fuel sales were still soft. Chevron’s cash flow was also a concern – as was ExxonMobil’s – which prompted chatter that the two direct descendants of JD Rockefeller’s Standard Oil were considering a merger. If so, then there is at least alignment on the climate topic: Chevron is also following the trail blazed by European supermajors in embracing a carbon neutral future, with CEO Michael Wirth conceding that Chevron may ‘not be an oil-first company in 2040’.
On the European side of the pond, that same theme of lowered downstream performance dragging down overall performance continued. But unlike the US supermajors, the likes of Shell, BP and Total were somewhat insulated from the Covid-19 blows at the peak of the pandemic as their opportunistic trading divisions capitalised on the wild swings in crude and fuel prices. That factor is now absent, with crude prices taking on a steady upward curve. That’s good for the rest of their businesses, but bad for trading, which thrives on uncertainty and volatility. And so BP reported a Q4 net profit of US$115 million, Shell followed with a Q4 net profit of US$393 million and Total closed out the earning season with industry-beating Q4 net profit of US$1.3 billion, above market expectations.
The softness of the financials hasn’t stopped dividend payouts, but has also been used by Europe’s Big Oil to set the tone for the next few decades of their existence. Total and BP paid a hefty premium to secure rights to build the next generation of UK wind farms; Total joined the Maersk-McKinney Moller Center for Zero Carbon Shipping to develop carbon neutral shipping solutions and splashed out on acquiring 2.2 GW of solar power projects in Texas; BP signed a strategic collaboration agreement with Russia’s Rosneft to develop new low carbon solutions; and aircraft carrier KLM took off with the first flight powered by synthetic kerosene that was developed by Shell through carbon dioxide, water and renewables. That’s a lot of a groundwork laid for the future where these giants can be carbon neutral by 2050.
The message from Q4 seems clear. Big Oil has barely begun its recovery from the Covid-19 maelstrom, and the road to a new normal remains long and painful. But this is also an opportunity to pivot; to set a new destination that is no longer business-as-usual, but embraces zero carbon ambitions. Even the American supermajors are slowly coming around, while the European continues to lead. Will majors in Asia, Latin America and Africa/Middle East follow? Let’s see what that attitude will bring over this new decade.
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