Big Oil faces major reserves challenge as new discoveries fail to replace production. Upstream spending was limited to $382 billion in 2020 and is forecast to marginally grow to $390 billion this year. Rystad Energy expects the effect of the pandemic to be a lasting one as — even though spending will start growing from 2022 — it will not return to the pre-pandemic level of $530 billion.
The toll of the Covid-19 pandemic on upstream investments in the first two years of the downturn is estimated at a whopping $285 billion, and although spending will slowly start to rise from 2022, it will not reach pre-crisis levels in the coming period, according to a Rystad Energy report. The shale sector has been the most affected, with conventional exploration and investments in mature assets suffering the least thus far.
In February 2020, before Covid-19 started impacting the global energy system, Rystad Energy estimated global upstream investments for the year would end up at around $530 billion, almost at the same level as in 2019. The forecast at the time suggested 2021 investments would remain in line with the previous year’s level.
However, as the Covid-19 pandemic triggered a collapse in oil prices during the early part of the second quarter last year, E&P companies slashed investment budgets to protect cash flow. This spending trend was not reversed in 2021, when prices rose. Compared to pre-pandemic estimates for 2020 and 2021, Rystad Energy observes that spending fell by around $145 billion last year and will end up losing $140 billion by the end of this year. This implies Covid-19 removed 27% of planned investments.
Upstream spending was limited to $382 billion in 2020 and is forecast to marginally grow to $390 billion this year. Rystad Energy expects the effect of the pandemic to be a lasting one as — even though spending will start growing from 2022 – it will not return to the pre-pandemic level of $530 billion. Growth will be limited and investments will only inch up annually, rising to just over $480 billion in 2025, when this report’s forecast ends.
Over the two-year period between 2020 and 2021, shale/tight oil investments are the ones most affected in both absolute and percentage terms, losing $96 billion of the previously expected spending, or 39% for the sector. Exploration spending is expected to drop by $19 billion, or 22%, compared to what was previously forecast. Greenfield investment in new conventional projects will suffer a $78 billion loss, or 28%, while brownfield investment in existing such projects will fall by $92 billion, or 20%.
“Since shale/tight oil is both the segment with the highest decline in activity and the supply source in greatest need of continuous reinvestment to keep production growing, the immediate impact on output from this sector has been significant,” says Espen Erlingsen, head of upstream research at Rystad Energy.
The proven oil and gas reserves of the group of major companies called “Big Oil” are falling at an alarming rate, as produced volumes are not being fully replaced with new discoveries. A Rystad Energy analysis shows that Big Oil lost 15% of its stock levels in the ground last year and as its currently estimated remaining reserves are set to be produced in less than 15 years, the group needs to add proven volumes by new commercial discoveries — or revisions of existing ones — to keep a balance.
The task is becoming more and more challenging as investments in exploration shrink and success rates slump. The declining proven reserves could create serious challenges for Big Oil (ExxonMobil, BP, Shell, Chevron, Total and Eni) to maintain stable production levels in coming years. This would in turn cause revenue to dwindle and pose a major threat to the financing of the group’s energy transition plans.
Big Oil saw its proven reserves drop by 13 billion barrels of oil equivalent in 2020 as the companies took large impairment charges, and this year’s exploration has not come off to a great start either. The industry’s global first-quarter discovered volumes totaled 1.2 billion boe, the lowest in seven years, as high-ranked prospects failed to deliver and successful wildcats only yielded modest-sized finds.
The collapse in crude oil demand and prices due to the Covid-19 pandemic and an increased focus on capital discipline has led to investment cuts that could aggravate the challenge of many major operators as they strive to boost their proven reserves. Even for European majors, which are increasingly focusing on the energy transition, business models will continue to be dominated by the sale of oil and gas.
“The ability of Big Oil to generate future revenues will continue to depend on the volume of oil and gas the companies have at their disposal to sell. If reserves are not high enough to sustain production levels, companies will find it difficult to fund expensive energy transition projects, resulting in a slowdown of their clean energy plans,“ says Parul Chopra, vice president of upstream research at Rystad Energy.
ExxonMobil’s proven reserves shrank by 7 billion boe in 2020, or 30%, from 2019 levels. This was mainly due to reductions in Canadian oil sands and US shale gas properties. ExxonMobil’s proven reserves of liquids in Canada were revised from 4.8 billion barrels of oil to less than 900 million barrels, while bitumen-related reserves for the Kearl and Cold Lake oil sands projects were slashed from 3.8 billion barrels to less than 100 million barrels. In addition, liquid reserves related to some US shale plays have been reduced by 1 billion barrels.
Also, ExxonMobil’s proven gas reserves dropped last year by 9 trillion cubic feet, mostly in the US. The revisions were primarily linked to the gas assets ExxonMobil bought from XTO in 2009.
Shell, meanwhile, saw its proven reserves fall by 20% to 9 billion boe last year. Liquid reserves accounted for one-third of total reductions and were mostly down to US and South American projects, and a lack of new discoveries elsewhere. Gas reserves accounted for two-thirds of the reductions, led by a 600 million boe revision in Australian projects.
Chevron also suffered reserve losses due to impairments, despite the addition of around 2 billion boe of proven reserves to its inventory through the acquisition of Noble Energy. Similarly, BP saw its total proven reserves drop from 19 billion boe in 2019 to 18 billion boe in 2020, mainly due to the sale of existing assets and a lack of major new discoveries. Total and Eni, however, have been able to avoid any reduction in proven reserves over the past decade.
Amid the proven reserve reductions – due to impairments and a lack of new discoveries — companies are seeing a negative impact on their ratio of proven reserves to production. When assessing the development of this ratio for the period from 2015 through 2020, ExxonMobil, Chevron and Shell show the highest decline.
For ExxonMobil, for instance, the proven-reserves-to-production ratio has not fallen below 13 years for the past two decades, but the 15 billion boe of reserves declared in 2020 means its volumes would run out in just over 11 years, compared to the previous expectation that these would last for more than 16 years. The reserves to production ratio for Shell, meanwhile, fell dramatically to 7.4 years in 2020 — the lowest level among all majors. The company has already reported its oil production peaked in 2019 and it expects an annual decline in output of between 1% and 2% until 2030.
New discovered volumes — a measurement of a company’s exploration performance — illustrates the daunting challenge faced by oil majors to maintain their reserves base and supply existing customers. Over the past five years, the six majors have replaced only 45% of their production through reserves from new discoveries. ExxonMobil fared better than its peers, adding more than 70% of the produced reserves thanks to 9 billion boe of discovered volumes in the offshore Stabroek Block in Guyana.
Total also enjoyed significant exploration success last year in the Guyana-Suriname basin, while Eni did well thanks to success in Africa. Chevron and Shell, on the other hand, have struggled to register new discovered volumes. Chevron managed to replace only 15% of its produced volumes from 2016 through 2020, while Shell replaced 27%.
Proven reserves is a conservative estimate of a producer’s remaining reserves and the tally can fluctuate based on oil price assumptions and on revisions of the status of existing discoveries. As a result, the reserves to production ratio does not accurately reflect the exact moment in time when reserves get depleted. It is rather an indication of the current proven reserves’ lifetime if every other variable remains unchanged, a theoretical exercise for the purposes of research.