Year after year, the oil majors have managed to remain afloat in all sorts of crises. These companies overcame oil price shocks, environmental disasters, force majeure and many operational challenges.

This time around though, things are different. Five out of the seven largest integrated oil companies have committed to net-zero carbon emissions by 2050 with smaller entities (in relative size, but large entities otherwise) also following suit. It is almost like acknowledging that their existing nature cannot be sustained in the future.

Year after year, the oil majors have managed to remain afloat in all sorts of crises. These companies overcame oil price shocks, environmental disasters, force majeure and many operational challenges.

This time around though, things are different. Five out of the seven largest integrated oil companies have committed to net-zero carbon emissions by 2050 with smaller entities (in relative size, but large entities otherwise) also following suit. It is almost like acknowledging that their existing nature cannot be sustained in the future.

The business strategies of how to get there, however, remain relatively blur. And even if some of the companies announce more details on their targets over five-year periods until 2050, significant questions remain.

Oil majors are heavily playing their renewable energy card. BP has set a target of 50GW installed capacity by 2030 from a mere 2.5GW in 2019. Total is even more ambitious stating a 100GW installed renewable capacity by 2030. By comparison, today’s renewable energy giants Enel, Iberdrola and EDF have targets of 75-150GW by 2030.

But how can oil companies compete in a segment where they are currently laggards compared to power companies? Technology, commercial agreements, regulatory hurdles and lower returns are only few of the challenges oil companies need to overcome. Are these companies too late to join the renewable surge?

How to play? Partnerships and new business models

Lacking most of the elements above (in varying degrees) calls for innovation. And not purely technological innovation, but business innovation. Oil companies would need to work-out what’s the best way to achieve the scale in new energies they require, while at the same time ensuring shareholder returns.

Installing renewable capacity at the scale publicized is difficult. It would need to compete for capital with traditional oil & gas projects and will also require significant resources to be tied-up to develop those projects.

Could progress come via mergers with renewables companies? Sounds unlikely given the scale of operations on both sides, lengthy & expensive integration costs and heavy financing required to do something like this.

Joint ventures with utility companies sounds like a more prominent solution. Exchange of know-how, equity contribution and project development capabilities will be mutual benefits among the JV partners, in my opinion.

Partnerships with original equipment manufacturers (OEM) and technology licensors could also be a move towards the right direction. Again, oil companies have the money (some of them) and experience in scalable solutions demonstrated in the oil & gas sector, while OEMs have the technological know-how.

It’s not all bad news for the big oil gang though. Oil companies have historically been very close to their consumers through their retail branding building loyalty through generations, despite the market sentiment being somewhat negative this time around.

Retail offering can easily be transformed and expanded into EV charging stations, hydrogen refueling and biofuels expanding the companies’ social license to operate.

Moreover, the knowledge acquired through these consumer-based operations can provide a leading-edge in the power distribution market that these companies are looking to enter into.

The next decade would be pivotal for oil majors. Multi-decade long business models are now questioned around their sustainability and shareholders returns. The near future will be among the most interesting periods in the history of energy. Never before has the public sentiment been more critical about oil companies. Let’s see how the play unfolds.

Energy Voices is a democratic space presenting the thoughts and opinions of leading Energy & Sustainability writers, their opinions do not necessarily represent those of illuminem.

Why oil majors need to reinvent themselves

Biofuels have been around for quite some time. Driven by the oil shocks in the 70’s and questions around energy security, biofuels attracted quite some interest but also significant investment.

Currently there are three types of biofuels produced at commercial scale:

Ethanol: Brazil’s government in 1973 started an ambitious ethanol production program to potentially replace gasoline in the transport sector with the sugarcane-based fuel

Biodiesel: Biodiesel was made commercially available in the 1990’s starting from the US due to advances in technology, and Europe followed shortly

Hydrotreated Vegetable Oil (HVO) or renewable diesel which is currently the smallest in terms of production but has the greatest growth potential

Well, the similarities are mostly around feedstock required. Ethanol is by majority produced by sugarcane while biodiesel is mostly sourced from processing vegetable oils and fats. HVO is more flexible in the sense that it can be produced by both vegetable oils, fats but also waste oils such as used cooking oil. Therefore, they can all be considered “renewable” fuels.

All of them are also considered to have a lower emissions profile compared to their fossil-based equivalent fuels. Although, the debate is still ongoing regarding the environmental benefits of ethanol.

Ethanol and biodiesel have significant disadvantages when compared to HVO. Firstly, they can only be used blended with conventional fossil fuels in different quantities. Ethanol can be blended with gasoline in a maximum ratio of 85:15 while most commonly it is around 20:80. On the other hand, biodiesel is thought to be able to mix with conventional diesel at a maximum ratio of 30:70. Currently, the most common biodiesel to diesel blending ratio is 10:90.

Secondly, ethanol and biodiesel directly compete with other industries for feedstock and most importantly with the food industry, compromising in a degree food security. China’s recent case of reversing their biodiesel blending mandate is a prime example of food security concerns.

HVO on the other hand is a “drop-in” fuel, meaning it has the potential to replace conventional diesel completely. And this is without any further modification in the diesel engines or any danger for engine degradation. Its main advantage is that compared to simple biodiesel it contains no oxygen making it easier to store, transport and ultimately combust in conventional diesel engines. And from an energy content perspective, it is actually more efficient than diesel.

From a technology perspective, HVO is more capital intensive as the technology required resembles more that of the conventional oil refineries while ethanol and biodiesel are more easily produced.

Europe is the frontrunner in HVO production with significant capacities in Finland, Netherlands and Italy. Neste, a Finish refiner, has been developing HVO plants since the early 2000’s with great success. Eni has also converted two of its refineries into HVO refineries due to the lack of profitability, while Total has also recently started HVO production in its La Mede refinery in France.

However, growth in HVO production will come from the US, driven by significant policy incentives that reward HVO producers with tax credits – both at a Federal level and also at the state level.

More than 20 projects have been announced in the United States either as greenfield or conventional refinery conversion. Another benefit of HVO which can lead to significant capital costs savings. Refineries that currently don’t generate any profits can be switched to HVO with simple retrofits offering a new earnings stream for the badly hit refining industry.

Investors will also be happy as HVO has the potential to completely eradicate emissions related with diesel engines, ticking the ESG investing boxes.

Lastly, HVO answers two key questions that remain unanswered regarding energy transition: heavy duty vehicles and aviation decarbonization can be achieved with the usage of HVO. An HVO derivative bio-jet is currently at an early stage but developments are expected in that field before 2030.

Despite its potential to be sourced by processing of waste oil, these waste oils are not currently collected in a large-scale. In Europe only 5% of the used cooked oil is collected and converted into HVO. Supply chains and logistics are therefore imposing a barrier in large scale HVO deployment.

Secondly, the spur in the US HVO investment is driven by policies that currently favor biofuels by generating tax credits for every gallon of biofuel produced. With uncertainty post 2022 regarding the renewal of policies, the commerciality of these plants will come into question.

Lastly, since HVO is a one-to-one alternative for diesel it is understood that oil price swings affect the price of this biofuel as well with recent cases of used cooking oil being more expensive than diesel fuel.

With technology advancements and supply chain for feedstock maturing, we do think that HVO has the potential to be a game changer in the transport industry but requires various elements to align first.

Advanced biofuels: A silver bullet for refiners?

Of course, the energy industry could not have been left unaffected from the shock that COVID-19 had on the world. It was, in fact, an industry badly hit as it is estimated that world energy consumption fell by 5% compared to 2020 (IEA WEO 2020). To put that into perspective, the world's primary energy consumption has grown about 2% every year since 2008 (BP Statistical review of the World Energy 2020).

Unprecedented is a term that has been among the most used words for the year that we have just left behind. Surely a pandemic is an occurrence that has happened before but it has been probably the largest shock in modern times with far-reaching implications on every aspect of society.

Of course, the energy industry could not have been left unaffected from the shock that COVID-19 had on the world. It was, in fact, an industry badly hit as it is estimated that world energy consumption fell by 5% compared to 2020 (

). To put that into perspective, the world's primary energy consumption has grown about 2% every year since 2008 (

BP Statistical review of the World Energy 2020

Consequences have been dire for energy producers and this article aims to highlight the key events and developments in 2020 that have the potential to shape the energy industry of the future.

In a year like this with energy consumption declining and nationwide lockdowns, oil price has seen huge declines, from a ~50$ per barrel WTI in January 2020 to a -37$ per barrel on April 20, 2020. A combination of weak demand, WTI fundamentals (landlocked with limited physical storage) and trading contracts reaching settlement dates have pushed oil price to negative levels for the first time in history.

In 2020, 5 out of the 7 oil majors have declared their ambitions to become Net-Zero energy companies by 2020. Shell, BP, Eni, Equinor and Total have all revised their long-term strategic agendas to transition from Integrated Oil Companies to more wide spectrum energy companies or as BP calls it: “Integrated Energy Companies”. And to no one’s surprise as these companies have already been active into the New Energies space driving towards more sustainable business models. The real surprise here though is that even traditional oil heavyweights like ConocoPhillips and Occidental have also joined the Net-Zero club, though without giving more details about their action plans.

Oil dividends are not to be taken for granted

As the COVID-19 impacts were starting to be felt in oil majors' income statements, companies were looking everywhere to find cash to preserve liquidity. Project cancellations and capital expenditures cuts were the first to be announced but 4 out of 7 oil majors also proceeded to dividend cuts with Shell, BP, Eni and Equinor all slashing their quarterly dividends – some of them for the first time in their history.

4. OPEC+ has opened more room for negotiation than ever

In a market shocked by negative oil prices, OPEC+ acted swiftly to take significant production off the market in an attempt to rebalance oil’s fundamentals. This however, has always been the case with OPEC+ in all shorts of market swings. The difference this time was that the oil exporting countries’ organization sought the help of the G20 as, “as noted in thousands of articles”, this time the price shock was unprecedented. United States, Canada and Norway were among the countries that agreed to production cuts to help rebalance the oil markets and send the oil price back to more reasonable levels.

Last year may have initiated a paradigm shift in the way energy companies look at the future. Consensus among oil companies is that we may have reached peak oil – the year of peak demand - while others like OPEC and IEA believe that oil demand will recover to 2019 levels within the next 2-3 years.

Either way, oil companies – IOCs and NOCs - are planning differently for the future. We expect to see more and more leaning towards ESG from pure oil companies and moves into new energies to continue attracting investors.

We also expect more consolidation - fewer and larger oil companies. Already, 2020 has seen some mega merger announcements of large-cap independent oil producers, something that was seen in the 80’s after a different kind of oil price shock.

For national oil companies the way forward looks bumpy. They cannot just leave their nation’s wealth in the ground. What we expect them to do is move towards improving public perception of their operations. Petronas was the first NOC to announce that it is considering Net-Zero while even Saudi Aramco has openly talked about interest in decreasing carbon content in the products they sell.

Things the energy industry taught us in 2020 and what to expect in the future

It was in February 2014, when most of the key gas pricing agencies reported a record in the spot price (price for immediate delivery) of LNG cargoes in Japan-Korea. Driven by the Fukushima crisis and the impairment of Japan’s nuclear plants gas, LNG has gained significant share in the country’s power generation mix being a relatively environmental-friendly fossil fuel. The sport price in that month? The more than extraordinary $20 per Mmbtu!

That seemed to be the silver bullet for many gas producers and LNG import operators. A commodity that is relatively cheap to buy or produce could be liquefied and sold into distant markets for a price 5 to 6 times more than its cost.

Reports on global LNG supply balances showed a potential supply gap after 2020 and added to the rush to expand LNG liquefaction capacities but also to sanction more gas projects with the potential to build LNG plants linked to them - a rush that resembled the gold rush 1800 century.

Gas was also favorable compared to oil among investors and shareholders. It has lower emissions intensity compared to oil and it would be a good first step among the oil dinosaurs to start their diversification efforts towards a greener resource type.

Everything seemed in line for a gas revolution. Huge projects were sanctioned in Australia (amid equivalent huge project delays and cost overruns). Qatar the world leader in LNG expanded its production capacity and the US started to transform its LNG import terminals to liquefaction/export facilities. And then reality struck…

In 2016, as projects were ramping-up and winter in Asia was milder than expected LNG prices dropped to $6-7 per mmbtu. The market was not able to absorb the gas, and coal was cheaper to burn leading to the price decline.

And that brings us to the new reality of 2020 and the COVID era

Remember that $20 per Mmbtu spot price in 2014? Divide that by 10 and you will get the same price marker for April-May 2020. Of course, the weather in spring-time is milder than February but if we look at the April-May 2016 prices they are still however at the $16-18 range. This signaled a fundamental change in pricing dynamics…

And this becomes more evident if we look at project cancellations and deferrals announced by oil & gas companies. Shell has walked out from Lake Charles LNG project due to weak market conditions. ExxonMobil is deferring its Mozambique LNG project for 2021 and the same stands for the Browse, Scarborough and Pluto-3 LNG projects in Australia.

Many more gas projects linked to LNG plants have also been deferred or cancelled completely. The preference showed by operators in cancelling these types of projects is driven by two factors. Firstly, LNG projects are capital intensive and more prone to overruns and delays since they are more technically complex compared to upstream projects. Secondly, oil remains much more profitable.

In a world were oil companies are looking to save even the last dollar to remain afloat in the COVID flood, it is the gas projects that are offloaded first.

Even the National Oil Companies that were looking to increase their domestic gas capacities and possibly expand into gas exports are having second thoughts amid fiscal budget pressures.

Aramco has delayed its giant Jafurah shale gas development, while ADNOC has cancelled contracts for its sour gas fields. Petronas with SK 408 and many more have done the same.

This article is meant to prove a reminder that any energy transition - even among different fossil fuels - is costly. Gas is cleaner than oil and has the potential to transform economies with its increased efficiency, but oil still remains on top in the oil companies’ agendas.

Whatever happened to the rush for gas?

Unprecedented times as well for the energy industry overall. Rapid decline in energy demand, negative oil prices, refinery idled or mothballed, and LNG carriers used as storage to dampen the loss from destroyed gas demand.

The year 2020 is probably where the word “unprecedented” has been used the most. The COVID-19 pandemic indeed brought unprecedented conditions upon the world, with global economy well into recession and forecasts now looking gloomy.

The toll has been heavy in the stock prices of Major oil companies. Year-on-year the market caps of Exxon, Chevron, Total, Shell and BP are down by 50%. This certainly is unprecedented value destruction.

The same stands for the Large-caps of the industry. Companies from the group of ConocoPhillips, EOG, Pioneer and Occidental have also lost on average 47% of their market cap year-on-year.

Lastly the small-caps, or else the pure-play E&Ps, have also lost 58% on average year-on-year from a group of 50 companies.

The verdict: In this unprecedented crisis everyone loses

Talks about peak oil demand already reached, surging COVID-19 cases globally and fears of supply glut with Libya restarting its operations have made the road to recovery even harder for oil companies.

We believe there is a silver lining here. Looking at the same three peer groups (Majors, Large-caps and Small-caps) it appears that the road to recovery might be bumpy – but at least there is one!

Large-caps on average have recorded a growth in market cap of 36% on average

Market has also shown some appreciation to Small-caps with average market cap growth of 31% for the groups

Oil Majors have recorded market cap reduction of 14% on average

So, does the market favor upstream pure plays compared to Oil Majors?

Possibly. Turning around a smaller organization with only one or two key business segments sounds like an easier job to do compared to a giant integrated oil company. Despite the lack of access to cheap finance, the Large and Small-caps can adapt more easily to the new demand patterns either by consolidating and merging with similar companies, or by taking deeper cuts in their budgets and headcounts.

Not the same stands for oil Majors though. Despite the deep cuts already announced (20-25% Capex and 10-15% Opex cuts), there isn’t much left to squeeze out.

Refining and Chemicals operations where Shell and Exxon are among the global leaders require heavy manning levels due to the complexity of the processes - raising the companies’ headcount by significant numbers.

However, they offer the benefit of vertical integration from oil & gas production to refined products and petrochemicals production giving these companies the benefit of synergies, optimization and portfolio optionality.

It is therefore easy to understand that these are areas that the oil Majors have invested a lot of capital and time in to develop and are likely to remain in these companies’ portfolios.

An exception is BP (although much smaller in scale compared to Exxon and Shell), where they have already divested their Petrochemicals arms to INEOS in an attempt to reduce their debt and overall headcount and transform into a leaner organization.

This crisis is like a water tank with multiple holes

Logic says it is easier to fix one hole rather than five at the same time.

The five holes reflect the multiple business segments and diverse portfolios of Oil Majors. Upstream, refining, chemicals, and integrated gas were largely loss making this year.

And that brings us back to the stock market discussion. Large and Small-caps have been less hammered by the market. Possibly because the market shares the belief that fixing one hole is easier than five…savvy?

Portfolio high-grading and rationalization should be on the agendas of Oil Majors. These energy behemoths are not nimble enough to respond to crises and…unprecedented events. Turning-around five to six business segments in 15 to 20 countries is a cumbersome task.

Maybe transforming from an Integrated Oil Company to an Integrated Energy Company is not a great idea after all. BP’s share price is trading at levels akin to 1994, after the company announced its aspirations, “From IOC to IEC…”.

From IOC to… what?

The COVID-19 pandemic has brought havoc in the energy markets. Oil prices turned negative, one third of global oil demand got erased between April and May, and as a result oil & gas operators had to revise their project pipelines. Cancellations, delays and farm outs were observed by most oil companies. But what really drives companies to move projects from pre-FID to FID (Final investment decision)?

Every project - regardless of the industry - is exposed to a set different types of risk. A new manufacturing plant for example is exposed to cost inflation risks, schedule risks and performance risks. In the world of oil & gas however there are industry specific types of risk that a project will need to overcome prior passing the FID gate. In summary these are:

ESG (Environmental Social and Governance)

Most of these risk dimensions, if not all, need to be overcome for an oil & gas project to move from concept and feasibility to reality.

One may argue that in an era of low oil prices it doesn’t really matter. All projects are at risk and the above mentioned risk dimensions are meaningless. Well if that was the case, all the oil & gas projects would be deferred or cancelled this year. And that has clearly not been the case.

What really drives oil & gas projects sanctioning?

Low commodity prices have a similar effect for every oil & gas company. The common point is that low prices lower the value of the project and ultimately the operator’s profitability from it. But the oil prices won’t stay low forever as history has shown. Therefore, companies plan accordingly on what projects will move forward at this price environment but also looking forward to the future. This is done by looking at the above mentioned risk types for each projects.

Below we summarize how each risk dimensions weighs on project decisions and we provide some examples of recent projects where these were satisfied:

 This type of risk relates to the technical complexities related with the project. These may vary from the hydrocarbon content to location remoteness or reservoir quality. An example of a high technical risk project was the Hail & Ghasha sour gas field offshore UAE. The sulfur content is very high in the gas reservoir and it requires specific equipment to handle, transport and process this type of gas. As per the operator’s announcement this project will be delayed having not passed the technical risk gate

 This type of risk does not apply to every company. Oil & gas majors and some of the national oil companies are likely to be able to finance most of their pre-FID portfolio through their balance sheets. Smaller companies however rely to external financing from institutional investors to be able to move forward with their projects. Sea Lion oil project off the coast of Falklands Islands has recently announced as deferred by operator Premier Oil. Securing external financing for a challenging project in a frontier, from the oil & gas perspective, environment has proved to be difficult leading to the deferral of the project

While the oil market is a very liquid market in the sense that there are many buyers for oil (refiners, governments, traders even oil companies) that is not the case for gas-yet. When a gas market exists in the vicinity of a potential gas project that driver is key to move the project past the FID gate. Shell has moved forward with its giant ($5.4 billion) Surat Gas project in the east coast of Australia despite the global weak market conditions. This is because the east coast of Australia is a market “hungry” for new gas due to domestic demand and LNG feedstock requirements. The volume offtake security clearly moved the needle for Shell in this project

Oil companies tend to have a diversified portfolio of projects that spans different resource types and different geographies. However there is a clear direction among different companies on a what projects are prioritized. Chevron and Exxon for example have put a big bet on the onshore US and the Permian basin while Shell and Total show a strong preference in gas projects. It is reasonable to think that operators will try to go with what they are best at and fit most their portfolio, especially in times of low prices

 An increasing area of focus among energy companies. Shareholders are pushing for “greener” projects while oil companies work to improve their social license to operate. Most oil majors for example have walked out of the Canadian oil sands as this type of resource is among the highest greenhouse gas emitting. Projects in environmental sensitive locations like the Arctic are likely to fall lower in the companies preferences while new energies and renewables are slowly gaining their share in oil & gas companies portfolio

These criteria are the most common among oil & gas companies. Other criteria may include political influence or national energy security especially when it comes to national oil companies. In a more stable price environment these criteria have increased importance.

Achieving the right balance of risk among operator’s portfolio is crucial and has become more important after the oil price crash of 2015. This year has been an alarm for operators to re-think, re-evaluate and potentially even re-shape their portfolios to ensure the right balance between risk, growth and shareholders returns

Oil & Gas projects in the Covid-19 era 

BP was the first oil major to announce its ambition to become a net-zero company by 2050, meaning that the company will either eliminate or offset carbon emissions from its operations.

Shell followed shortly after along with Eni, Total, Equinor and Repsol. Their American counterparts, Exxon and Chevron have been less active with regards to energy transition and emissions having no strict targets set.


BP was the first oil major to announce its ambition to become a net-zero company by 2050, meaning that the company will either eliminate or offset carbon emissions from its operations.

Shell followed shortly after along with Eni, Total, Equinor and Repsol. Their American counterparts, Exxon and Chevron have been less active with regards to energy transition and emissions having no strict targets set.

At first BP was accused of “greenwashing” i.e. conveying false impression that the company would become environmentally friendly-given the fact that in the end it is still an oil company. And the accusations had a valid ground. This has been the second diversification effort of BP after the failure of transforming British Petroleum to Beyond Petroleum in the early 2000’s. Moreover, following BP’s 2020 announcement of net-zero, no concrete action plan was set to explain how the company would achieve its target.

What followed was an announcement regarding the reorganization of the company and a headcount reduction of 15% which is roughly 10,000 jobs. All that after already having cut its dividend by 50% in Q2-2020. The market was not happy. BP lost almost 50% of its market cap since January 2020. None of the announced radical actions seemed to have persuaded the investors that BP has a feasible way out to net-zero.

The strategy came a few months later in August where BP announced its net-zero strategy laying out a set of actions, portfolio shifts and targets. The market was still not impressed.

An aggressive reduction of 40% by 2030 in oil production, 50GW of renewable energy capacity by 2030, 5-fold growth in biofuels production and investment in hydrogen and CCUs.

Ambitious - maybe even far-fetched targets that didn’t help BP’s share price recover at the slightest, with questions regarding returns from renewable investment and income generation remaining unanswered.

On the other side of the Atlantic, the energy transition “laggards” Exxon and Chevron are keeping the dividends at pre-COVID levels with 6.3% and 9.4%, respectively.

Are the energy transition ambitions and dividend payouts connected? Well let’s see:

BP, Shell, Eni and Equinor are considered the energy transition leaders among oil companies. All of them have cut their dividend by 50-66% in 2020. Total did not cut its dividend but has offered shareholders scrip dividends instead. After all, the energy transition might be taking its toll on the shareholders dividends from oil companies.

But why are Chevron and Exxon still high dividend paying and not moving into new energies?

One would think due to the EU regulations, the former group of companies would have to act faster as carbon pricing paired with the declining oil prices will deem part of their assets stranded and uneconomical.

This is a fair point. The United States does not have a carbon price or regulation in place apart from tax credits for carbon sequestration which provides some cushion for oil companies to keep pumping more hydrocarbon out of the ground.

But if we leave policies and regulations aside, the reality is that Chevron and Exxon have a larger and cheaper resource base than their European counterparts. To put it simply, the US is full of oil while Europe is running out of it. The Permian basin in the US is expected to yield significant production growth for both companies at a low-cost base. Both have well established and optimized LNG facilities tied with long term contracts providing secure cashflows. Guyana and Kazakhstan are also some areas that will provide growth for Exxon and Chevron respectively in the long term.

With multiple growth engines, there is simply no incentive for US companies to commit to any shift in their strategies other than investors pressure which is partly offset by the high dividends.

Maybe the net-zero way is a way out of low returns from oil & gas rather than a paradigm shift for the oil companies. The oil price crash has played a role in accelerating the net-zero trend, but in the end, hydrocarbons will still be around for many years to come. And that’s where the fittest will survive…

Net-zero and energy transition in oil & gas: The early signs

Stefanos Mourelatos is an experienced energy analyst having worked across multiple sectors, namely oil & gas, energy 

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