Reviewing the majors: Your guide to the 2024 AGMs(Annual General Meeting) - Africa’s premier report on the oil, gas and energy landscape.

Reviewing the majors: Your guide to the 2024 AGMs(Annual General Meeting)

By Gerard Kreeft

Energy investors and shareholders have a diversity of visions which the oil majors— BP, Shell, ENI,TOTALEnergies, Chevron, ExxonMobil and Equinor—will present them at the various AGMs. Below is an overview of what to anticipate. Perhaps not earth-shattering but enough food for thought to give you the reader a better understanding of the energy transition, regardless of your point of view.

The New York Stock Exchange (NYSE) is an excellent barometer to determine the current status of the oil majors (July 2019-March 2024). It is not a pretty picture.

In the July 2019-March 2024 period the Dow Jones Industrial Index rose 50%: increasing from 26,599 to 39,807. Yet the European oil majors have in this same period (with the exception of Equinor and TOTALEnergies), seen their share prices underperforming badly:

BP -10%

Shell -3%

Eni -3%


Equinor + 35%.

In the same period US oil giants Chevron and ExxonMobil have seen their share prices flourish: Chevron up 27% and ExxonMobil 51%.

 Table 1: Stock market prices of  majors July 2019-March 2024 (NYSE – New York Stock Exchange)






Why is it that the share prices of Chevron and ExxonMobil have performed so well and their European counterparts have done so poorly? And why have TOTALEnergies and Equinor been able to maintain investor confidence? Below a company analysis and a series of conclusions which will help explain the seeming paradoxes.

BP: A Takeover prey?

 BP’s faltering share price has in the period July 2019-March 2024 remained on a downward trajectory: from $42 to $38. The company’s history is rather checkered:

BP’s Deepwater Horizon oil spill of 2010 in the Gulf of Mexico has to 2018 cost the company $65Billion;

The company’s withdrawal from Russia in February 2022, because of the Ukraine conflict, meant the loss of 50% of its global reserves; and

In September 2023 the abrupt resignation of CEO Bernard Looney after he admitted that he had not been “fully transparent” about historical relationships with colleagues.

BP meanwhile is promising to spend up to $65Billion on renewables between 2023-2030 and amounting to half of its investments by 2030. Yet the company has written off $540Million of its offshore wind assets in New York.

Will BP be able to meet its renewable energy goal given the long-term slump of renewables and BP’s lingering share price?

What BP was promising originally?

  • An underlying EBIDA (earnings before interest, depreciation, and amortization) of between 5–6% per year through to 2025, with returns in the range of 12–14% in 2025.
  • From 2025 onwards, when its low-carbon projects start to kick in, an expected growth of between 12–14% to be maintained.
  • Its $25Billion divestment would provide the basis for up-scaling its low-carbon business. A pipeline of twenty-five oil and gas projects and an additional eighteen projects in the pipeline were also key factors.
  • Spending $5Billion per year to green itself and by 2030 will have 50 GW of net generating capacity. To date the company has a planned pipeline of 20 GW of green generating capacity.

More recently BP has announced that it is lowering its oil and gas production to be around 2Millionbarrels per day of oil equivalent (2MMBOEPD) by 25% by 2030,  lower than the 40% originally announced. How this will affect BP’s green vision is difficult to predict.

Yet BP’s faltering vision, its downward share price and its low valuation—some $100Billion–makes the company a vulnerable takeover prey.

Shell’s three illusions

The chief obsession of Wael Sewan, Shell CEO since January 2023,  is to drive up the company share price. Yet the share price has barely moved—it was $65 at the start of April 2019 vs $67 March 2024. In his view Shell must mimic Chevron and ExxonMobil. While the Shell share price has remained virtually unchanged, Chevron has seen its share price in the same period  increase 27% and ExxonMobil 51%.

Shell’s total capex for the period 2023-2025 is between $22Billion-$25Billion per year, of which some 80% is earmarked for hydrocarbons. Not unlike Chevron and ExxonMobil.

Sewan is attempting to change Shell’s narrative: that Shell is in the business of producing hydrocarbons, instead of also selling the illusion that its new energy policy matters. Europe’s oil majors, Including Shell, have seen their share prices flounder. Why? Because of their messaging—wanting to appear to be both an oil company and a green energy company.

Illusion 1:The Common Good

In Shell World the company represented ‘the Common Good’.  Year—in-and-Year–Out Shell’s will was seen as law, at least in the Netherlands. For example, the Director-General of the State Mining Authority in the Netherlands, the highest regulatory body for the oil and gas industry, was always a high-ranking Shell manager who took early retirement from Shell and parachuted into his new regulatory role.

Then there is the matter of Shell’s pending appeal regarding its CO2 emissions. In 2021 the court ordered Shell to cut its absolute carbon emissions by 45% by 2030 compared to 2019 levels. Very quickly Shell stated that its emissions issue was a private Shell matter and not a matter of ’the Common Good’.

Illusion 2: Upstream will provide green funding

Prior to Sewan’s leadership Shell had argued that its Upstream pillar ..”delivers the cash and returns needed to fund our shareholder distributions and the transformation of our company, by providing vital supplies of oil and natural gas.”

Yet Sewan is  frank enough to acknowledge that this vision was an illusion. Depending on its upstream portfolio to lead the company to a bright new green future is perhaps central to Shell’s dilemma. Using funding from its upstream division to fund its green energy is in Sewan’s view a non-starter.

Illusion 3: Shell’s LNG global forecasting—back to the drawing board

Shell’s LNG Outlook 2024 forecasts that China will grow its LNG requirements more than 50% by 2040: rising to 23Trillion Cubic Feet (Tcf) in 2040 from 14Tcf in 2023. Yet Shell’s optimism may be premature.

The Institute for Energy Economic and Financial Analysis IEEFA’s Global LNG Outlook 2023-2027 casts a more somber analysis for  future  LNG developments, in particular for China: rising domestic gas production, pipeline gas imports, and renewable power capacity could limit the potential for rapid LNG demand growth over the medium term.

“Lackluster demand growth and a massive wave of new export capacity are poised to send global liquefied natural gas (LNG) markets into oversupply within two years. These two trends are developing even faster than anticipated.”

“Declining Russian gas supplies to Europe, driven by Russia’s full-scale invasion of Ukraine, caused a spike in European LNG imports that sent global prices to record highs. But despite modest new LNG export capacity additions in the last two years, prices have retreated from 2022 levels, largely due to falling demand from developed economies.

In Japan, South Korea and Europe—which account for more than half of the world’s LNG demand—combined imports fell in 2023 and will likely continue falling.

In emerging Asian markets, structural LNG demand growth faces a complex web of economic, political, fiscal, financial and logistical challenges. The global LNG crisis of the last several years heightened those challenges, spurring some Asian nations to reduce the role of LNG in their development plans and accelerate the development of alternative energy sources.”


ENI, the Italian oil and gas giant, is often overlooked in any discussions involving the other oil majors. Yet ENI could be the Joker in the deck providing surprises to an unwitting public and be an upstart which deserves the needed attention. The company operates in the frontier areas seldom mentioned in the daily news media.

For starters ENI produces 1.7MMBOED, has a balance sheet which has an economic leverage of 20%, and has, according to its website,  an Internal Rate of Return(IRR) of 34%, the highest of all its peers  for the 2012-2021. Also, its RRR (Reserve Replacement Ratio) of 110% for the period 2012-2021 is the highest compared to its industry peers.

ENI further states that 90% of exploration capex is spent on near fields and proven basins. Some $11Billion in the last 10 years has been spent on its dual exploration model—near fields and proven basins. The company states that it only requires three years—from first discovery of oil to market—twice as fast as the industry average.

Yet ENI’s stock market price has remained flat in the period July 2019-March 2024: from $33 to $32.

A key ENI strategy  is developing a series of joint-ventures to ensure that ENI can achieve maximum leverage for its current oil and gas assets and at the same pursuing new strategies as part of its energy transition plan. Two examples:

 Vår Energi, Norway was formed in 2018, following the merger of ENI Norge AS and Point Resources AS, owned  by Hitec Vision, a private Norwegian investment fund.  The company’s primary focus is oil and gas developments on the Norwegian Continental Shelf. ENI controls 69.6% of the shares, and HitecVision 30.4%. Vår Energi has production in 36 fields and produces 247,000BOEPD.

Azule Energy, Angola, a 50-50 joint venture between ENI and BP formed in 2022 to include both companies’ upstream assets, LNG and solar business. Azule Energy is now Angola’s largest independent equity producer of oil and gas, holding 2Billion barrels equivalent of net resources and growing to about 250,000BOEPD of equity oil and gas production over the next 5 years. It holds stakes in 16 licences (of which 6 are exploration blocks) and a participation in Angola LNG JV. The company also participates in the New Gas Consortium(NGC), the first non-associated gas project in the country.

 ENI’s North African Gas Hub

ENI’s North African Gas Hub–Algeria, Libya and Egypt–will certainly be a key provider of natural gas to Europe. The three countries together produce 648,000 boepd, approximately a third of Eni’s total global production.


In July 2022, Sonatrach and ENI announced that an additional 141Bcf per year will be exported to Italy via the TransMed Pipeline which is a 2,475 km-long natural gas pipeline built to transport natural gas from Algeria to Italy via Tunisia and Sicily. In 2023 ENI’s production from Algeria was scheduled to rise to over 120,000BOEPD.


The Libyan gas produced by the Wafa and Bahr Essalam fields operated by Mellitah Oil & Gas, an operating company jointly owned by ENI and NOC(Libyan National Oil Company). The gas  is brought to Italy through the Greenstream pipeline. The 520-kilometre natural gas pipeline crosses the Mediterranean Sea connecting the Libyan coast with Gela in Sicily. The natural gas pipeline has a capacity of 283Bcf per year. ENI has a production of 168,000BOEPD in that country.


ENI is operator of the large Zohr field which In August 2019, had a  production of more than 2.7Bcf/d. An important agreement was the restart the of Damietta liquefaction plant which will provide up to 106Bcf in 2022 for European customers. ENI produces 360,000BOEPD.

TOTALEnergies: Providing the lead

The company’s twin growth pillars— developing its low carbon hydrocarbon assets and developing its integrated power business—are key for implementing  its energy transition strategy.

TOTAL is replicating its integrated oil and gas business into the electricity value chain to achieve a profitability of at least 12% ROACE(return on average capital employed) for its integrated power segment, based on an equivalent of $60 per barrel.

TOTALEnergies aims to grow its power generating capacity to 100 GW by 2030: investing $4Billion per year so that by 2030 it will achieve positive cash flow.

By 2050 TOTALEnergies’ energy mix will be:

25% low carbon molecules

50% electricity and renewables

18% LNG

7% oil

To understand the French major’s strategy we must go back to 2020. Then TOTALEnergies took the unusual step of writing off $7Billion in impairment charges for two oil sands projects in Alberta, Canada. Both projects were listed as proven reserves. By declaring these proven reserves as null and void, with one swoop of a pen, TotalEnergies cast aside the petroleum classification system, which was the gold standard for measuring oil company reserves.

The company simply decided that these reserves could never be produced at a profit. Instead, TotalEnergies has substituted renewables as reserves that can be produced profitably.

TOTALEnergies’ strategy was based on the two energy scenarios developed by the International Energy Agency (IEA): the Stated Policies Scenario (SPS), which is geared for the short to medium term, and the Sustainable Development Scenario (SDS), which focuses on the medium long term.

Taking the “Well Below 2 Degrees Centigrade” SDS scenario on board, TotalEnergies has, in essence, taken on a new classification system. By embracing this strategy, the company is the only major to have seen a direct benefit from using the Paris climate agreement to enhance its renewable energy base.

While it wrote off some weak assets, it also did something else: TotalEnergies began to sketch a blueprint for how to transition an oil company into an energy company.

This was the first time that any major energy company translated its renewable energy portfolio into barrels of oil equivalent. So, at the same time that the company has slashed proven oil and gas from its books, it has added renewable power as a new form of reserves.

Proven reserves long stood as the holy of holies for the oil industry’s finances—the key indicator of whether a company was prepared for the future. For decades, investors equated proven reserves with wealth and a harbinger of long-term profits.

Because reserves were so important, the reserve replacement ratio (RRR), the share of a company’s production that it replaced each year with new reserves, became a bellwether for oil company performance. The RRR metric was adopted by both the Society of Petroleum Engineers and the US Securities and Exchange Commission. An annual RRR of 100% became the norm.

But TOTALEnergies’ write-offs showed that even proven reserves are no sure thing and that adding reserves doesn’t necessarily mean adding value. The implications are devastating, upending the oil industry’s entire reserve classification system as well as decades of financial analysis.

How did TOTALEnergies reach the conclusion that reserves had no economic value? Simply put, reserves are only reserves if they’re profitable. The prices paid by customers must exceed the cost of production. TOTALEnergies’ financial team decided those resources could never be developed at a profit.

The company had not abandoned its oil and gas investments. However, its renewable investments were seen as additional ballast to the company’s balance sheet, keeping it afloat as it carefully chooses investments, including oil and gas projects, with a high economic return.

Equinor: Will it maintain its course?

Equinor’s past message of spending more than one-half of its capital spending on low carbon energy by 2030 in offshore wind technology had caught the fancy of its investor community.

Yet the reality could prove to be different. In 2023 the company suffered a loss of more than $750Million on its New York offshore wind projects.

In spite of its loss Equinor’s transformation ambitions, combining a focus on renewable energy with continued high production of oil and gas, will result in a renewable share of 7–12% by 2030. The company aims to produce around 2 million barrels of oil and gas per day in 2030, which is at the same level as in 2022.

 Equinor’s twin pillars

 Will  Equinor’s twin pillars of natural gas and its growing offshore wind portfolio provide the company  the financial depth and ability to achieve maximum leverage for both pillars?

 Equinor’s  goal to grow its offshore wind portfolio to 12–16 GW of installed capacity by 2030 faces a number of severe challenges:

In the past the company had pledged that renewables would receive more than 50% of capital investments by 2030. Now there is no mention of trying to achieve this!

There is severe competition from a number of key European new energy players, who have the economies-of-scale that Equinor can only dream about.

  • ENGIE based in France: will have 80 GW of global renewable installed capacity by 2030.
  • Enel based in Italy: The company’s strategic plan outlines that by 2025 it will have 75 GW of installed capacity; and by 2040 its electricity generation derived solely from zero-emission sources.
  • Ørsted based in Denmark: By 2030 the company will have an installed capacity of 50 GW of renewable power.
  • Iberdrola based in Spain: From 2024–2026, the company will be spending more than $40Billion on renewable energy and has a pending target of 100 GW of installed renewable capacity.
  • RWE based in Germany: By 2030 RWE will have 65 GW of installed wind and solar capacity and net zero emissions by 2040.

Equinor has chosen a series of joint ventures to develop its offshore wind portfolio. The first, Dogger Bank, heralded to become the world’s largest offshore wind farm, is being developed together with SSE Renewables  based in the UK. Located in the North Sea, the project will produce some 3.6 GW of energy, enough to power 6 million households.

Equinor’s Empire Wind and Beacon Wind assets off the USA’s east coast have resulted in a swap transaction with BP. Equinor will take over full ownership of the Empire Wind Lease and projects and BP will take over full ownership of the Beacon Wind lease and projects.

Chevron: Stay vigilant

Aside from its newly acquired asset in Guyana  two-thirds of Chevron’s total production of 3 million barrels of oil will in  2025 come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States  each yielding 1 million barrels of oil equivalent per day.

Today the company has a net value of  over $300Billion, seen its stock price rise to $158 by March 2024, up from $124 in July 2019. A rise of 27%. It anticipates maintaining a capital budget of between $18.5-19.5Billion per annum, which includes capex for affiliates. The company has indicated that $14Billion is devoted to upstream, two-thirds or $9Billion mostly in the Permian Basin and Gulf of Mexico.

Outside the USA, Chevron will spend $5Billion: $1.5Billion to further develop its Tengiz asset in Kazakhstan, with the remaining $3.5Billion spent elsewhere. This is not promising for Africa, where Chevron has major operations stretched across the continent including major projects in Nigeria, Angola, Equatorial Guinea, and Egypt.

Caspian Pipeline Consortium (CPC)

A potentially troubling problem is the Caspian Pipeline Consortium (CPC) which transports Caspian oil from Tengiz field to Novorossiysk-2 Marine Terminal, an export terminal at the Russian Black Sea port of Novorossiysk. The CPC pipeline handles almost all of Kazakhstan’s oil exports. In 2021 the pipeline exported up to 1.3 million bpd(barrels per day). On July 6, 2022 a Russian court ordered a 30-day suspension of the pipeline because of an oil spill. The CPC appealed the ruling and the suspension was lifted on 11 July of the following week, and the CPC was instead fined 200,000 rubles ($3,300).

The incident demonstrates the vulnerability of Tengiz and future production. No doubt this is not the last such incident which involves Russian and Kazakhstan goodwill to ensure that Chevron’s Tengiz Project does not falter. Having to dependent on Russian-Kazakhstan goodwill to guarantee Tengiz production has put Chevron’s  lack of diversity of oil  supply in a very bad light.

 Permian Basin

 A final sour note for Chevron could be its Permian Basin assets. What assurances do we have that Chevron’s Permian Basin adventure will fare better than that of past shale operators?

In a 2021 March report IEEFA (Institute for Energy Economics and Financial Analysis) found the 30 producers generated $1.8Billion in free cash flows in 2020 after slashing capital spending by $20Billion from the previous year.

Since 2010, the 30 companies examined by IEEFA had reported negative free cash flows totaling $158Billion. “The positive free cash flows pale in comparison to the industry’s accumulated debt loads.” The 30 shale producers owe almost $90Billion in long-term debt, and the reductions in capital expenditures are unlikely to ensure that the industry grows.

ExxonMobil: Don’t count your chickens…

ExxonMobil’s vital signs are the following: between July 2019 and March  2024 the stock price at the NYSE has risen from $77 to $116, 51%. The company has a capex of between $23-$25Billion in 2024 and for the period 2025-2027 it will spend annually $22-27Billion.

Good News & Bad News from Guyana

ExxonMobil continues to publish for the world its good news from its offshore Stabroek Block in Guyana: by 2027 a target of 1.2MMBOPD will be pumped, budgeted at a cost of $45Billion. Total recoverable reserves are estimated at 11Billion barrels.

Not mentioned is the price tag.

At the end of five years(2024), according to IEEFA, Guyana will carry a minimum $20Billion outstanding balance owed to its oil producer partners. This amount must be paid, along with other contractually obligated development costs, before the country can fully enjoy any long-term benefits that might materialize.

This is a discussion which must be had in the coming months.

 LNG—A Mixed Blessing

Rovuma LNG was supposed to become ExxonMobil’s futuristic model LNG project. ExxonMobil has recently issued various tenders to move its Rovuma project ahead. Instead, in a matter of months events have overtaken ExxonMobil’s best laid plans.

IEEFA’s recent warning of a global LNG oversupply in the coming five years is not good news!  Will Rovuma make it to the starting gate?

Then there is the matter of ENI’s Coral Sul Project in Mozambique.

The  inauguration of this project deserves special attention. The first LNG shipment of ENI’s Coral Sul FLNG shipment took place in November 2022.

  While Africa’s two  most highly touted LNG projects—Rovuma and Mozambique LNG– continued to be on security hold,  ENI achieved pole  position with its Coral Sul FLNG project.

A Final Investment Decision (FID) is expected to be made on ENI’s  second Coral Sul Project in Mozambique June 2024.

 Key takeaways

BP’s quest to survive is taking precedent over any discussion whether how green the company should be or whether to indeed be an oil and gas company. No doubt the final chapter has yet to be written.

 Shell continues in vain to search for its soul. Anxious to play catch-up with its US rivals—Chevron and ExxonMobil. Yet in hot pursuit of them is no guarantee that Shell’s future will become brighter.

 ENI operates in a very fluid market place and has shown the ability to be diverse and able to provide contrarian strategies. A characteristic needed in a fast-changing energy world. The Joker has not yet dealt his final card.

TOTALEnergies continues to set new precedents for the energy transition:  replicating its integrated oil and gas business into the electricity value chain to achieve a profitability of at least 12% ROACE(return on average capital employed) for its integrated power segment, based on an equivalent of $60 per barrel. By 2030 it will achieve positive cash flow. This is no mean achievement given that the industry average for the electrical sector is 6%.

 Chevron’s key achievement to date has been its relatively stable share price—rising 27% in the period July 2019-March 2024.  A key concern  for shareholders is that two-thirds of Chevron’s total production of 3 million barrels of oil will in 2025 come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States  each yielding 1 million barrels of oil equivalent per day. Not exactly diversity of supply.

ExxonMobil in the period July 2019- March 2024 seen its share price increase 51%. Much of the gloating is based on its Guyana offshore project, scheduled to produce 1.2 mbpd by 2027. Yet little is being said about the $20Billion debt which the Government of Guyana must pay in 2024 to settle its cost of developing the Stabroek Block.

Equally concerning is the Rovuma LNG project in Mozambique: IEEFA’s recent warning of a global LNG oversupply in the coming five years could prove to be a challenge for the company.

Equinor has managed to achieve an ROACE of 34% and its share price has risen some 35% in the period July 2019-March 2024. The company’s fallback position is that it is a key provider of natural gas to Europe. Yet its offshore wind sector lacks the economies of scale to compete with companies such as Enel, Iberdrola, Ørsted and RWE.

Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise.  He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe.  Gerard has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report, and contributes to IEEFA(Institute for Energy Economics and Financial Analysis). His book The 10 commandments of the Energy Transition is now on sale at  Bookstore






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