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2014 and 2020: the crisis years that triggered the transition of oil giants to carbon-neutral energies?

May 18, 2021

The oil industry is in the eye of a new storm, with barrel prices crashing by more than 60% in just four months in early 2020. The 2020 results of the industry’s five major players have shown cumulative losses of more than €60 billion (ca. $65 billion), compared to 2019 when they had reported cumulative gains of over €40 billion. It is time for us to look back on 2020, which marked a turning point for the oil and gas (O&G) industry as it started to look beyond its core activities to push for renewable energy and carbon capture.

The O&G industry is a cyclical industry and it saw its share of major upheavals, notably the oil crises of 1973 and 1979. The frequency of these cycles is increasing (1998, 2008, 2014), but more importantly, their magnitude is more severe. Since 2019, global growth has been slowing down, awareness of the looming climate crisis has been growing, and the governments of developed economies are facing increasing pressure to initiate energy transition.

The 2014 crisis, a competitive shale market and a global economic slowdown

After the economic and financial crisis of 2008 and the rollout of stimulus packages worldwide, oil prices continued to increase and finally stabilized for almost three years at over $100/bbl. With these prices being maintained over time, oil giants were able to restart projects that had been put on hold during the 2008 crisis and American shale players were able to rise from the ashes. While American shale oil represented only 5% of global production, it accounted for half of the growth in oil production between 2010 and 2014. In 2014, shale oil production in the US reached 5 Mbbl/d, while the country’s total production increased from 8 Mbbl/d in January to nearly 9.5 Mbbl/d in December 2014, thus making the US self-sufficient. This revival happened because of efficiency gains (improved well designs, higher initial productivity), lower production costs (reduced drilling and completion times), and the ease with which these players could use hedging thanks to their very short production cycles. These improvements helped lower the break-even point of American shale producers from more than $70/bbl in 2013 to less than $50/bbl in 2016. Despite an increase in global production, market prices remained at high levels until 2014, due to geopolitical uncertainties among some OPEC members and their collectively agreed production regulations to stabilize prices.

Moreover, from 2013, signs of a slowdown in global economic growth, particularly in China, were being felt. Consumer prices stabilized and the prices of metals and other raw materials began to fall. To protect their market shares, OPEC members and Russia opened the floodgates and started selling their oil at preferential prices. Between May 2014 and December 2014, the barrel price of Brent crude fell from $113 to $55. In January 2016, a barrel of Brent dropped below $35. This drop was one of the most significant since the end of the Second World War.

Oil majors had to adapt to much lower oil prices and change the way they worked. Many put their investments on hold and reduced assets considered too unprofitable; for Total and Shell, this was the Canadian oil sands, which were expensive and high in COemissions; for US companies, it was the North Sea, as they preferred to focus on their high-growth shale assets. Companies in this sector then worked on three fronts: cleaning up the balance sheet as required by shareholders, asking employees to make certain adjustments/compromises (extending offshore shifts, reducing site bonuses, freezing salaries) before reducing the workforce, and, finally, putting pressure on suppliers and service providers to drastically reduce costs.

Many players in the oilfield services sector had not yet fully recovered from the economic crisis of 2008 and these new economic pressures from their clients resulted in bankruptcies and layoffs. In 2016, nearly 350,000 oil industry jobs were cut globally. The sector was consolidated, for example, with the takeover of British Gas by Shell in April 2015 for £47 billion (ca. $50 billion), the acquisition of Cameron by Schlumberger in August 2015 for $14.8 billion, the acquisition of Maersk Oil by Total for $7.45 billion in 2017, and finally, the bankruptcy of more than 200 companies in the sector in the US in the same year. This allowed the surviving producers to lower their break-even point from an average of $50/bbl before the crisis to about $40/bbl in 2019–2020.

Apart from these costly consolidations, certain players started looking for new sources of revenue, moving away from hydrocarbons: Total invested heavily in electricity supply and storage with the acquisitions of Direct Energie in France, Lampiris in Belgium, and the battery manufacturer Saft. Meanwhile, Shell invested in the German battery manufacturer Sonnen while progressively increasing its presence in the solar energy space.

The 2020 pandemic, a catalyst for overproduction

The recovery of the world economy in the second half of 2016 and an adjustment in global production volumes helped stabilize oil prices at around $50/bbl. This new price environment allowed oil companies to reinvest in ambitious projects (West Barracouta in Australia, Liza Destiny and Unity in Guyana for ExxonMobil, Mozambique LNG for Total, and Coral South in Mozambique for ENI), after having significantly reduced their debt levels. These investments were all the more necessary because the reserves that were depleted during years of austerity had to be renewed. The accumulated cash was also used to reward shareholders through share buyback plans. This share buyback policy proved to be all the more important as many institutional investors wanted to abandon the so-called “polluting energy.” Lastly, supplier margins started increasing gradually and salaries were on the rise again, although they had not yet returned to their pre-2014 levels. Oil companies capitalized on this opportunity to modernize their tools and processes. The industry went digital and capitalized on data to improve performance. Predictive maintenance and industrial mobility helped increase equipment availability, reduce on-site staff, and minimize unplanned shutdowns. Exploration and drilling benefitted from advancements in big data technologies to reduce human and financial risks and improve success rates.

Global oil production rose from 97 Mbbl/d in early 2017 to 103 Mbbl/d by the end of 2019. Global consumption remained stable at 100 Mbbl/d until the last quarter of 2019 before it started plummeting, reaching less than 90 Mbbl/d in the second quarter of 2020. This fall in consumption can be explained by three factors:

  1. A new slowdown in the world economy, especially in China and Europe
  2. Development of renewable energies, with their increasingly attractive returns on investment
  3. The confinement of people due to the spread of COVID 19.

With the confinement of populations in China alone, the barrel price of Brent crude fell from $65 on January 1 to $55 on January 31. OPEC and other oil producing countries came together in March in an attempt to stop the decline in prices, but no agreement was ratified in Vienna on March 6, 2020.

Saudi Arabia and Russia then decided to start a new price war in order to capture market share and to stifle independent American shale producers in particular. Prices fell by 40% in just one week, at about $30/bbl. On April 20, 2020, with the approaching due date for the futures contract for delivery in May 2020, the prices of WTI crude collapsed to -$37.63/bbl before stabilizing at around $30/bbl.

The direct consequences of this new crisis

These low prices and the dizzying rate at which they fell once again put O&G players in a challenging position and the first measures of reducing costs and freezing investments were not long in coming. However, this crisis soon proved to be more acute than the previous one. It was not just a supply crisis; it was also a sharp decline in consumption. The measures taken during the previous crisis were less effective and no longer sufficient. In fact, all sizeable companies in the sector went through severe downsizing measures. At that time, Shell, Chevron, and Schlumberger each cut 10,000 jobs. New workforce reduction plans were implemented. Chevron immediately announced approximately 5,000 job cuts, while Shell announced a voluntary retirement plan and Schlumberger 21,000 job cuts and a complete restructuring of its businesses. Besides, the operating margins of oilfield services companies remained low and, although they improved between 2018 and 2020, they are still far from their pre-2015 levels.

Little room was left for these operators for further cost reductions after 2015–2016 with all other factors remaining constant. The decline in business in 2020 was a significant setback for drilling companies. Between June 2019 and June 2020, the number of active drilling platforms decreased by more than 70% in the United States and by more than 30% worldwide. In addition to drastic reductions in investments of close to 25% for operators, oil majors discontinued their share buyback plans. BP, Equinor, and Shell went even further by announcing a lower dividend for 2020. For Shell, this was the first dividend cut since the World War II. While oil majors have long been considered high-yield investments because of their high and stable dividends, the generalization of a low-dividend policy could be interpreted by investors as an acknowledgment by the board of directors of a declining sector. Investor concerns call into question the sector’s ability to finance new major projects, something which has already been significantly hampered by increased price volatility.

The long-term consequences of this new crisis

The repetition of workforce reduction plans, often perceived as trivial and devoid of consequences on business, could prove impactful for the sector. With each new redundancy plan, these companies lose knowledge that they have difficulty finding again or find at a high price. On the other hand, oil companies, which used to appeal to the most talented young graduates, are now struggling to restore their image. The polluting image of the sector and its instability repel young people, who often perceive the industry as dated or no longer find salary levels lucrative enough to compensate for the difficult and demanding working conditions.

In the meantime, while fossil energy is facing greater opposition from the public, so-called green energies are soaring thanks to commitments by companies and governments to reduce pollution. Renewable energies, such as solar and wind power, which represent 10% of the world’s energy production, compared to only 1.5% in 2000, are being developed almost all over the world. Large solar or wind projects are becoming increasingly profitable, even with the decrease in state subsidies, thanks to lower manufacturing costs and efficiency gains.

On the other hand, low oil prices will reduce the profitability of oil projects significantly, especially if states impose a substantial tax on the carbon generated. These lower returns are already perceptible because areas that were perceived as the new El Dorado a few years ago – such Alaska or the Arctic, which appear to be teeming with oil and gas, but where development costs far exceed the costs of the largest projects carried out so far – have now been completely set aside.

Most oil companies have reduced their exploration expenditures, halted the implementation of new projects, and started reevaluating their asset portfolios. In 2014, investments in upstream oil activities reached $800 billion; in 2020, these investments were expected to drop to $300 billion, the lowest since 2005. Stopping exploration campaigns and launching new projects will lead to a significant decrease in reserves and the production of private companies and will thus make national oil companies (NOCs) stronger. In fact, NOCs, and OPEC members in particular, often benefit from very large reserves that are easily exploitable at lower costs.

Non-production of oil at a vast majority of complex offshore reserves could eventually lead to a supply deficit, and therefore, a sharp increase in prices by the end of 2021–early 2022, largely depending on whether the global economy recovers at “full throttle” after the pandemic. In 2011, after the international military intervention in Libya, the disappearance of a little less than 2 Mbbl/d in global production was enough to propel prices past $120/bbl. The decrease in global production, combined with significant geopolitical instability in some regions, could thus lead to a price explosion. OPEC countries would then fully regain their role of market makers on a global scale and gain considerable political clout.

Furthermore, in the last two years, major names in the sector have been divesting assets deemed unprofitable or non-essential to focus on a smaller number of fields with a lower production break-even point and significant reserves. In the context of low prices, these divestments have generated less cash than expected. BP, for example, had to scale down its expectations both in terms of cash and in terms of the payment schedule and structure for the sale of two of its oilfields in the North Sea to Premier Oil, including the task of decommissioning, which will remain BP’s responsibility.

Many other assets sold by large groups were bought by small players supported by private investment funds. These companies look for maximum profitability, in a short period of time, and often lean towards strategies that reduce operational costs by minimizing on-site staff, reducing maintenance plans, and keeping investments to a minimum. On the other hand, the issue of managing the decommissioning of these assets will be crucial for states. Will it be possible to impose the same environmental standards on these entities as those imposed on internationally recognized groups? Will these small companies have the capacity to pay the exorbitant costs of dismantling plants, or will this burden fall on the taxpayer?

Following the drastic reduction in oil consumption worldwide and the adoption of new lifestyles (telecommuting, reduced air travel, consumption of local products whenever possible, etc.), many top executives of European oil companies believe that a considerable part of their proven reserves will remain underground and are therefore anticipating a decline in oil revenues, which may never go back to their previous levels. These assumptions have led to the writing down of assets of up to £14 billion, $22 billion, and $8.1 billion by BP, Shell and Total, respectively. Other groups may follow suit. The recognition of these assets at their “fair” value automatically increases the debt ratio of groups and could lead to the downgrading of their credit rating, and therefore, their ability to procure funding in the markets. Such a correction in asset value for certain severely affected companies could lead to a breach of contractual covenants vis-à-vis their creditors, leading to bankruptcies. Besides, these write-downs are decreasing capitalization of all O&G producers. All the majors saw their capitalization melt by 40% to 45% in the first three quarters of 2020 before recovering. In the meantime, major renewable actors such as Enel, Iberdrola, and NextEra claimed an increase of their capitalization after the market collapse due to the pandemic of over 30%. Ørsted, the former Danish O&G company, converted to wind farm developer champion and saw its capitalization almost double.

ENI has publicly announced that its oil production would decline after 2025, as it changes its focus to gas production, which would account for 85% of its hydrocarbon production in 2050; its “green” electricity production would exceed 55GW, mainly in OECD countries. Another element that suggests that average oil prices will not quickly return to their pre-crisis levels is the adjustment of revenue projections. BP has announced that from now on, their long-term projections will be based on an average barrel price of $55 and not $70 as was the case previously. ENI will base its projections on a price of $50/bbl, compared to $65/bbl previously.

The radical changes that we may witness in the coming months, due to the weakening of many oil and oilfield services companies and their strategic changes, could lead to a new wave of consolidation in the sector or trigger substantial investments accelerating the diversification of revenue sources. Capitalizing on their expertise in running giant offshore structures and managing the production, storage, transport, and distribution of gas, oil operators would have the ability to generate value in offshore wind power projects or the large-scale use of “green” hydrogen as an energy source.

For example, Repsol is participating in the development of the first semi-submersible wind farm off the coast of Portugal with Engie and EDP. BP and Shell following their colossal losses for 2020 ($18.1 billion and $21.7 billion respectively), due to the massive write-downs of their massive assets, have entered into electricity generation in full force. Shell has signed a deal with the online retail giant Amazon for the distribution of renewable electricity from an offshore wind farm in the Netherlands. BP, for its part, is stepping up its expansion in wind power generation with the purchase of a 50% stake in two offshore wind projects in the US from Equinor for $1.1 billion, and more recently, a new partnership with EnBW for setting up and operating a wind farm of 3 GW in the North Sea.

Total, with losses barely contained compared to its competitors ($7.2 billion), has made a dramatic move by positioning itself across all segments of carbon-neutral energy and may solidify it in the eyes of the public by adopting a new name, TotalEnergies. The French group has invested heavily in wind energy, with notably an offshore project off the coast of Wales, and in solar energy, through the 20% acquisition of Adani Green, the world’s leading developer of solar projects. Total is also looking to roll out its battery subsidiary Saft and will work with the PSA group to build two “gigafactories” for battery production in northern France and in Germany.

Going further, similar to what energy companies have done (E.ON-Uniper, RWE-Innogy, DONG Energy/Ørsted), some oil companies, especially European ones, may consider merging their hydrocarbon assets before a spin-off between hydrocarbon production on one side and “green” energy production on the other, thus giving rise to a European low-carbon energy giant. On the other side of the Atlantic, ExxonMobil and Chevron, two oil giants, considered a possible merger, which would have created a potential American giant with production output of roughly 7% of global production, which could have changed the competitive landscape between oil majors and freed up capital to diversify their businesses. In all cases, the recurrent crises have forced a change in attitude of all O&G companies and a conscientization about their impact on the environment. Business can no longer be as usual, deep transformation on their activities, business models will be required to overcome the challenges of a green energy era.


Hubert Clement

Director – O&G and Industrial Operations expert

Younes Zinoun

Senior Consultant at Capgemini Invent