Some numbers may be crucial here to explain the jibes the industry has attracted. To be sure, the intention is not to single out these six majors, but they are representative of the overall trend across the sector. Plus, the group collectively has reported its latest earnings, offering a clear view of where the money was spent last year, while many of their independent peers are still in the process of doing so. The group collectively made over $300 billion in cash flow from operations in 2022, a record high and some 41% more than in 2021 as well as over three times that seen during the first year of the pandemic in 2020. But their investment ratio – in terms of upstream spending relative to cash flow generated from operating activities – fell to its lowest in a decade last year. They used part of the proceeds to pay down some debt. Dividend payouts ended at about $53 billion up from $46-$47 billion in 2020-2021. But the figure that has perhaps most irked policymakers and governments alike – share buybacks, which jumped to $60 billion, a whopping 7.5 times higher compared to an already strong 2021 and 10 times that of 2020. And hence the understandable anger. 

As highlighted above, the trend is not limited to the majors. Up until recently, US shale was touted as a swing producer and justifiably so. It enjoyed the shortest investment cycle decisions – with an experienced operator in theory capable of obtaining a drilling permit, contracting and deploying a drilling, fracturing and finally connecting a well to a gathering system in less than six months: a feat by any measure. Hence, the theory went – high oil prices will trigger the quickest response from the sector, with any fall triggering a prompt pullback. But fast-forward to today, and the elevated oil and gas market through most of 2022 failed to trigger any response from publicly traded operators, while their privately held peers catapulted their plans to cash in on the firm market. The sole driver of this discipline? Again, shareholders and investors, who are demanding higher returns, making the sector turn away from its growth-for-growth’s sake business model. Let’s study this discipline using the same re-investment ratio yardstick. Historically, this ratio exceeded 100%, meaning the industry was cash-flow negative, living beyond its means to chase growth and higher market share. That started to change by early 2019, and since the third quarter of 2020, the re-investment rate has been consistently below 60%, hitting a historical low in third quarter of last year, at less than 40%. This means that most of the cash generated from operations is being returned to shareholders in some form – dividends and buybacks being the most common – which in effect means the amount of capital deployed decreases each quarter. At one level, this fiscal discipline has managed to turn a once unprofitable business into one of the most cash-flow generating sectors in the American economy, in record time. A success story, as oil and gas companies are generating the highest ever cash flows in their history by some metrics. Yet this inelasticity to oil prices is clearly dangerous – lack of investment will inevitably lead to declining volumes, market imbalances, an oversupplied service market all of which is ultimately unsustainable. 

Then what’s wrong with the anger displayed toward the industry? The problem lies in looking at the sector through a short prism of just two to three years. Prior to the pandemic, through a large part of the previous decade, the oil and gas industry struggled to breakeven amid massive swings in oil and gas prices. Companies had accumulated billions of dollars in debt, straining their balance sheet as the value of the asset against which those loans were taken – their oil and gas reserves – plummeted because of low prices. Even bellwether names such as ExxonMobil had to halt their share buyback plan in 2016 – which had averaged at about $20 billion a year over the preceding decade – partly to conserve cash as oil prices plunged to less than $30 per barrel. The energy industry has been painted sometimes as a money-hungry, profit-seeking group out to exploit natural resources across the globe, putting revenue at the expense of the consumer and the environment. Yet, the energy industry is, at the end of the day, just a business like most other – one that must generate a return on capital to stakeholders to sustain the investment cycle for capital intensive projects. 

Exploration and production (E&P) companies are realizing some of the largest profits in history, but investments have declined to historic lows, which is why the consideration of a windfall tax is now legitimately on the table. This current state could convince an investor to expect this trend to continue for the long term. But a quick, high-level reflection on recent years tells a different story. Had shale E&Ps not gone through their previous cash-burning avatar, the sector would not be where it is today – flourishing with strong capital gains and dividend and buybacks. Intense capital investment in fossil fuels and the encouragement of accelerated growth was and is a key component to energy security, both in the US and globally. The ambitious goal to transition away from traditional fuels is a shared view, one that spans across all energy sectors. But the world cannot move over to cleaner technologies without going through the phase of transition. Achieving the right balance of energy sources – and it is indeed a delicate balance – will require increased investments now and over the coming decades to ensure global energy initiatives remain on course and renewables and low-carbon technologies can successfully offset the dominant energy sources of today.

And is the industry really not investing in future growth? Oil and gas reinvestment is still viable if we zoom out and look at more diversified players over a longer time horizon, even though the story here diverges somewhat between the US and European majors. US majors ExxonMobil and Chevron continue to target production growth into the late 2020s. ExxonMobil’s upstream output is guided to increase from 3.7 million barrels of oil equivalent per day (boepd) in 2022 to 4.2 million boepd in 2027 on the back of growth in the Permian and Guyana. Chevron is increasing from 3 million boepd in 2022 to up to 4 million boepd in 2026, likewise driven by the Permian and deepwater. Most European giants, on the other hand, are guiding long-term production decreases through natural decline and divestments, although previous targets are softening in some cases. BP, which produced 2.25 million boepd in 2022, recently revised its 2030 production target up from 1.5 million boepd to 2 million boepd, citing demand and hydrocarbon-led financial performance. Shell announced its oil production had peaked in 2019 and is targeting annual oil production declines of 1-2% to 2030. However, the company will continue to high-grade its lucrative deepwater oil assets and is targeting 20 exploration wells in GoM over the next few years alone for replacement volumes.

Capital allocation to exploration has downshifted – perhaps permanently – in the wake of the pandemic. But several key exploration strategies have emerged from the rubble, one of which is rapid development of high-return new finds in conjunction with energy transition objectives. Guyana is the gold standard here – Liza Phase 1 was discovered in 2015 and brought on-line within five years against the backdrop of a favorable regulatory regime. Along with subsequent discoveries, Guyana’s total oil production expected to push 1 million bpd by the late 2020s, compared to 75,000 bpd in 2020. This rapid execution principle has gained steam in nearby areas such as offshore Suriname, although subsurface uncertainties threaten to delay development here. Further afield, Namibia’s Orange Basin has seen an uptick in development potential, with the 2022 Venus and Graff natural gas discoveries identified as fast-track candidates.

The lack of an inclination to double down on spending could also be driven by another factor that is beyond just investor pressure: the supply chain. The unprecedented disruption caused by the pandemic had forced factory shop floors to down their shutters for months on end, making it virtually impossible for the supply chains to snap back up promptly to meet the spurt in demand. Added to that was the zero-Covid-19 policy in the global manufacturing hub China, which lasted till the end of last year, restricting movement and holding back business from reopening. The oil and gas industry in the US and elsewhere had laid off hundreds of thousands of workers during the downturn, making it hard to rapidly rehire the workforce. The combined shortage of equipment and labor pushed costs higher, further adding to elevated expenses being incurred because of higher gasoline and diesel pump prices. Shortages of casings and tubing, commonly referred to as oil country tubular goods (OCTG) mean no matter how high oil prices climb, an E&P can't drill a well. For example, price increases from trough to peak in the 2016-18 period in some key segment in the Permian were about 23%. In comparison, the trough to peak from 2020-23 will be 100%. 

Still, as manufacturing capacity expands, with factories restaffing again, price increases are set to slow. Seamless and welded pipe prices in the US should continue their downward trend that started in the fourth quarter. Prices have been overinflated when compared to underlying costs, driven by the supply demand mismatch. Similarly, most other key drilling and well services segments will see slower price increases through 2023, before starting to also fall in 2024. Depressed natural gas prices and weather-related issues have caused the year to start off on a softer note in comparison to previous years where budget resets typically led to a spike in drilling and completions (D&C) activity. Operators with natural gas assets are in a ‘wait and see’ mode to assess if natural gas prices would recover in the coming months. A sustained depressed natural gas price environment would lead to rigs and frac fleets getting dropped in gas regions like the Haynesville and Appalachia. The outlook for oil, however, remains strong for 2023 and hence any decline in service rates in 2023 is unlikely just based on a weaker natural gas outlook. Service prices are likely to increase through mid-2023, although at a slower pace than previously anticipated, before stabilizing in the second half of 2023.

In terms of the macro inflation outlook, with China finally abandoning its zero-Covid-19 policy, the nation will slowly ‘return to normal’ after a period of turbulence but it does not necessarily mean that everything will be back to normal in 2023. We also expect China’s economic growth to remain relatively modest compared to what the country saw through the 1990s. Chinese manufacturers and fabricators are pre-emptively offering discounts to try and drive-up activity. Since the re-opening, metal prices rose by 15-30% (when compared against September 2022 levels). However, those increases have stabilized and have started to fall again – meaning their contribution to inflation should be minimal when compared against the increased manufacturing capacity of the country. 

While technology has grown exponentially, renewable energy is still in its development phase and is not yet capable of supporting full scale global energy needs. Renewables require significant investment in developing new technologies and deployment to structurally augment the energy mix. Fossil fuels, like it or not, are the bridge to renewables, and the length of the bridge will be determined by the pace of the transition. Less investment in traditional oil and gas will inevitably lead to a decline in production, which in turn would lead to higher energy prices that are passed on to consumers. A strong concern in the transition from fossils to renewables is the phasing out of these traditional energy sources as bridge fuels, potentially creating an energy crisis. Consumers are already faced with increasing costs of utility bills, for electricity and oil and gas heating due to supply and demand fundamentals, and the increasing frequency and severity of extreme weather events globally. As investment in these traditional sources of fuel and energy wanes, the utility network risks higher cost swings associated with changes in production.

Hence, imposing windfall taxes on a sector that has just had about two years of a rosy business environment will perhaps likely discourage spending as pressure from shareholders for higher returns will remain strong as they seek to recoup their investments after years of making no returns. The prospect of windfall taxes will therefore mean more money taken away from the companies that could have gone toward future investment. 

Windfall taxes will inevitably lead to more uncertainty in an industry that is already dealing not only with its usual geological and geopolitical risks, but increasingly with the energy transition risks, and currently with inflation risks. If implemented, windfall taxes would bring about lower investments, which eventually implies higher costs for consumers and the economy. Administrations should look at other ways of incentivizing investments in the energy sector, and they should all aim to decrease the uncertainty surrounding the industry, not increase it.

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Authors: 

Claudio Galimberti  

Senior Vice President, Oil Markets, Head of Americas Research
claudio.galimberti@rystadenergy.com

Emily McClain

Vice President, Gas Markets
emily.mcclain@rystadenergy.com

Matthew Fitzsimmons

Senior Vice President, Supply Chain
matthew.fitzsimmons@rystadenergy.com

Thomas Parambil Jacob

Senior Vice President, Onshore Supply Chain
thomas.jacob@rystadenergy.com

Alexandre Ramos-Peon

Vice President, Shale
alexandre.ramos-peon@rystadenergy.com

Thomas Liles

Vice President, Upstream
thomas.liles@rystadenergy.com

Manash Goswami

Vice President, Analytics
manash.goswami@rystadenergy.com

(The data and forecasts contained in this column are Rystad Energy’s and the opinions are of the authors.)