Re-Ranking the Oil Majors: what will 2025 bring?

By Gerard Kreeft

OPINION

Reviewing the majors for 2025 brings with it a plurality of scenarios.

Trump’s entry to the White House has more than a passing interest to both Chevron and ExxonMobil. Both companies will be lobbying Trump to ensure that US-Russian relationships are improved. Why?

When the Soviet Union broke up in the early 90s and Kazakhstan emerged as a new oil province, both Chevron and ExxonMobil,  seen as ambassadors of US goodwill, gained access to the country’s black gold. Chevron’s prize was operatorship of Tengiz (50%) and ExxonMobil gained a 25% share. Chevron also has an 18% share in the large Karachaganak Gas Field. ExxonMobil has a 16.81% share of the troubled Kashagan Project.

 Shell’s attention will no doubt be focused on its important LNG sector which can anticipate the necessary headwinds.  While the courts in the Netherlands has given the UK major a pass on its Carbon Dioxide (CO₂) reduction appeal, no doubt a new narrative must be developed if new energy is to develop a societal consensus.

Equinor …willing to fight the good fight is too small to be a force for good and must re-invent its development scenarios.

ENI, small and contrarian, has found through strategic alliances and pragmatic solutions that it has become a respected player in Africa.

TOTALEnergies, both in terms of leading the pack with its innovative approach for the energy transition and its deepwater exploration, is a player to watch.

BP continues to flounder: a company in search of its soul.

In the period 2021-2024 the Dow Jones Industrials gained 38%: from 31,098 in January 2021 to 42,992 December 2024. The oil majors have displayed a variety of results:

ExxonMobil +130%

Chevron +58%

Shell +55%

Eni +23%

Equinor +22%

BP +21%

TOTALEnergies +20%

Table 1: Oil majors stock prices 2021-2024 (NYSE)  

BP: A Takeover prey?

BP’s share price in the period January  2021- December 2024 has  remained tepid: from $24 to $38. The company’s checkered history continues to haunt its assets:

BP’s Deepwater Horizon oil spill of 2010  in the Gulf of Mexico has   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 is promising to spend up to $65Billion on renewables between 2023-2030, 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 would start to kick in, an expected growth of between 12–14% to be maintained.

More recently BP has announced that in 2025 its oil and gas production to be around 2.6Million b/d of oil equivalent. The capex for oil and gas is $8.5Billion. The company has a renewable pipeline of some 47GW.

BP’s faltering vision, its downward share price and its low valuation—some $84Billion–makes the company a vulnerable takeover prey.

The chief obsession of Wael Sewan, Shell CEO  since 2023, is to drive up the company’s stock price. His hydrocarbon narrative is mimicking that of Chevron and ExxonMobil.

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

Yet what distinguishes Shell is its strong LNG arm, truly global. In short, Shell is really a natural gas company.

A fundamental concern for Shell should be the global outlook for LNG. 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 far 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.

 Where did it go wrong?

A long-term LNG slow down for China is only a part of the puzzle. According to IEEFA the global demand for LNG is slowing:

Europe, while maintaining a high degree of LNG import, is also increasing  energy efficiency measures and wind and solar projects have become commonplace.

Japan and Korea, historically dependable LNG importers, are increasingly turning to nuclear, and renewables; and

South Asia, including India, Pakistan, and Bangladesh slashed purchases by 16% in 2022 and suppliers often defaulted on contracts to obtain higher prices elsewhere.

“After several years of weak supply growth, IEEFA anticipates that the global LNG market will see a tidal wave of new projects come online starting in mid-2025. The wave will likely crest in 2026, with the addition of 64Million metric tons of annual liquefaction capacity—the most in the history of the global LNG industry. The supply additions will boost global liquefaction capacity by roughly 13% in a single year. Liquefaction projects targeting in-service after 2026 may be entering a much smaller demand pool than bullish market forecasts anticipate. As new supply floods the market, today’s tight markets may give way to a supply glut, with lower-than-anticipated prices, smaller netbacks, tighter margins, and lower profits for LNG exporters.”

The turning point will be 2025.

“IEEFA anticipates that roughly 17Million Tonnes Per Annum (MMTPA) of liquefaction projects are likely to come online around the world in 2025—more than in 2023 and 2024 combined. New capacity additions will crest in 2026, with an estimated 64MMTPA of capacity coming online in a single year, and continue into 2027, when 37MMTPA of new capacity is expected to begin operating”.

How will a floundering LNG market affect Shell’s dominant LNG  position? Does Shell continue to have the agility to re-calibrate its strategy?

Redefining the Common Good

Up to 10-15 years ago, what Shell stated as a company policy in the Netherlands was largely interpreted as the ‘Common Good’. What was good for Shell was also deemed good for the country as a whole.

For example, up to 2018, the Inspector-General of the Dutch State Supervision of Mines, the highest regulatory authority for the oil and gas industry in the Netherlands, was always headed up by an ex-Shell nominee.

Yet Shell’s recent win in its landmark case overturning an earlier ruling requiring it to cut its carbon emissions by 45% have seen Shell do an  abrupt about-turn: in essence arguing  that cutting carbon emissions was a “private matter” and had little to do with the “Common Good”.

The Court of Appeal in the Netherland’s capital city of The Hague, said it could not establish that Shell had a “social standard of care” to reduce its emissions by 45% or any other amount, even though it agreed the company had an obligation to citizens to limit emissions.

 If people considered progress was too slow towards cutting emissions, then, according to Shell,  they should lobby governments to change policies and bring about a green transition.

Shell’s insistence that the courts have no jurisdiction in the Shell boardroom could in the longer-term backfire. Perhaps time to go  back to Jean-Jacques Rousseau.

For Rousseau, writing in the mid-18th century, the notion of the Common Good, achieved through the active and voluntary commitment of citizens, was to be distinguished from the pursuit of an individual’s private will.

As Rousseau explains, the general will is the will of the sovereign, or all the people together, that aims at the Common Good—what is best for the state as a whole.

The heart of the matter for Shell is that the company has continued to argue that this is a private( company) matter, not one involving the the Common Good.

Yet the 2016 Paris Climate Agreement, which was signed by 195 countries, agreed to try and prevent an average global temperature rise of under the 2⁰C and hopefully 1.5⁰C, is the clearest example of a Common Good.

What the court and Shell are arguing is that the Common Good must be redefined: a court follows precedent and does not establish it. In other words, the  current design of the energy transition must have a more encompassing architecture if a new consensus is to be arrived at.

The Joker in the Deck

ENI, the Italian-based oil and gas giant, is often overlooked in any discussions involving the other oil majors-BP, Chevron, Equinor ExxonMobil, Shell,  and TOTALEnergies. Yet ENI could be the Joker in the deck providing surprises to an unwitting public and be an upstart which deserves the needed attention.

ENI’s strong presence in North Africa—Algeria, Egypt, and Libya—could in the coming months become one of Europe’s substitute providers of natural gas. This region currently produces 648,000barrels of oil equivalent per day (BOEPD). The company operates in the frontier areas seldom mentioned in the daily news media.

For starters the company produces 1.7mboed(million barrels of oil equivalent per day), 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.

 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. Some 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 247,000 boepd.

Ithaca Energy in the UK (ENI 37.17%)  has become the largest O&G operator in the UKCS by resources.

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 five years.

Azule Energy in 2024 completed a farm-in of Block 2914A located in Namibia’s Orange Basin, giving the company a 42.5% share.

 Plenitude, ENI’s new company, launched in June 2022 is an integrated business combining the generation of electricity from renewables, the sale of electricity, gas and energy services to households and businesses, and a European network of charging points for electric vehicles.

Enilive is ENI’s mobility transformation company. Founded with the goal of offering integrated services and products that are progressively decarbonized by 2050, Enilive is the tangible result of Eni’s ten-year commitment to sustainability-driven mobility transformation.

TOTALEnergies’ energy production in the period 2020 -2030 “will grow by one third, roughly from 3MMBOEPD to 4MMBOEPD, half from LNG, half from electricity, mainly from renewables”, according to  Patrick Pouyanné, the company’s Chairman and CEO.

This was the first time that a major operator has wittingly or unwittingly translated its renewables to BOE(barrels of oil equivalent). The golden rule was that RRR(Reserve Replacement Ratio) was always used  to assess a company’s hydrocarbon reserves. This author has for some time argued that oil companies also include other fuels in their reserve count—be that wind or solar– to create a basket of energy reserves. Thus, increasing reserve count and buttressing up   fossil reserves and adding value to hydrocarbon  assets.

By taking renewables on board has enabled the company to leapfrog the competition. Getting a head start with renewables and continuing to manage its deepwater  projects. The company has confirmed that it is on track to deliver 100GW of renewables by 2030.

The company’s twin pillars—Oil and Gas and Integrated Power—have a capex of  between $16-18Billion for 2025 of which $5 billion will be spent on low-carbon energy.

TOTALEnergies’s goal for its Integrated Power division is to have a ROACE(Return on Average Capital Employed) of 12%; in 2023 it was 10%.

Yet ROACE averages for the oil and gas industry are virtually double that of new energy: in 2022 TOTALEnergies’ROACE stood at 28.2%, and in 2023 Equinor’s ROACE stood at 24.9%.

In terms of deepwater TOTALEnergies will be focused on its Venus prospect in Namibia: in its Venus 2913 B development is taking place and the company is engaged in a further exploration programme.

 Fly in the Ointment:  ENI’s Coral Sul Project in Mozambique

 A fly in the ointment could well be ENI’s LNG projects. The first LNG shipment of Eni’s Coral Sul FLNG shipment took place in November 2022. ENI’s second LNG project—Coral Norte–is expected to receive FID shortly.

 Meanwhile  Africa’s two  most highly touted LNG projects—Rovuma and Mozambique LNG—have continued to be on security hold.

TOTALEnergies has made no final FID decision on its Mozambique LNG project, which is expected to cost $20 billion and produce up to 43 million tons per annum remains. Will it ever be developed?

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 1Million barrels of oil equivalent per day.

Today the company has a net value of  over $283Billion, seen its stock price rise to $144 by December 2024, up from $91 in January 2021.

The company will devote $14.5-$15.5Billion of capital spending for consolidated subsidiaries. The company has indicated that $13 billion is devoted to domestic upstream operations.

Outside the USA, Chevron will spend  between $1.7 -$2Billion to further develop its Tengiz asset in Kazakhstan, and other assets 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.

Tengiz Project

Tengiz production is  currently producing 560,000 BOPD and is being expanded  by some 260,000BOPD. Total costing is estimated at $45Billion.

Expiry date for the Tengiz concession is 2033. What will  happen then? Tengiz was for most of its duration Chevron’s crown jewel, providing cash to developing assets elsewhere including Africa. Given Chevron’s current strategy it can only hope that Tengiz can continue to squeeze out more oil.

 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 found the 30 producers generated $1.8 billion 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 January 2021 and December 2024 the stock price at the NYSE has risen from $46 to $106. The company has a capex of between $27-29Billion  in 2025 and a market capitalization of $487Billion.

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 1.7MMBPD will be pumped, budgeted at a cost of $45Billion. Total recoverable reserves are estimated at 11Billion barrels.

Not mentioned is the price tag.

Guyana will carry a minimum $20Billion outstanding balance owed to its oil producer partners at the end of 2024, in the opinion IEEFA.  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.

ENI’s Coral Sul FLNG project’s inauguration 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 FID(Final Investment Decision) is expected to be made on ENI’s second Coral Sul Project in Mozambique in early 2025.

On May 31, 2023 Equinor announced that it would delay by at least three years its Bay du Nord project in the deepwater Flemish Pass basin 500 km off the coast of Newfoundland, Canada. Why? Because the project would cost an estimated $12Billion.  Only $12Billion you might think. Is that a reason for not developing this project at a time when oil and gas companies are showing record earnings?  According to Equinor technical and financial challenges are the main reasons for the delay.

Yet Equinor’s reasoning is not directly related to the Bay du Nord capital costs. By 2030 the company is pledged to spending half of its capex on renewable energy. In 2024 its capital budget was $13Billion. On this basis Equinor’s capital budget for future oil and gas projects is rather restrained.

Yet the company has revealed how it will be implementing its strategy:

In October 2024 Equinor announced that it  had  taken a 10% stake in Ørsted.

Equinor UK and Shell UK have combined their UK offshore oil and gas assets to form a new joint JV.

Will more strategic alliances be announced?

 Pillar Number One

Equinor’s concern is  whether  the company’s twin pillars–natural gas and offshore wind — have the financial depth and ability to achieve maximum leverage for both pillars?

Equinor’s offshore wind portfolio is pledged to grow to 12–16 GW of installed capacity by 2030. 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.

Originally Equinor and BP were partners in the Empire Wind and Beacon Wind assets off the USA’s east coast. Under a swap agreement Equinor has taken over full ownership of the Empire Wind lease and projects and BP will take full ownership of the Beacon Wind lease and projects. The two projects will generate 4.4 GW of energy.

Equinor’s rivals have the size and economies of scale to be very competitive:

• ENGIE based in France: In 2021 the company spent more than $11 billion on investments across a broad swath of sectors, including solar, wind (on and offshore), hydro plants, biogas, and developing gas and power lines, and will have 50 GW of global renewable installed capacity by 2025.
• Enel based in Italy: The company’s strategic plan outlines total investments of $231Billion and tripling renewable capacity to 154 GW by 2030.
• Ørsted based in Denmark: By 2030 the company will have an installed capacity of 50 GW of renewable power.
• Iberdrola based in Spain: From 2020–2025, the company will be spending $165Billion on renewable energy and has a pending target of 95 GW of installed wind capacity.
• RWE based in Germany: By 2030 RWE will have 50 GW of installed wind and solar capacity.
• Vattenfall based in Sweden: In the Nordic countries, Vattenfall has low emissions, with practically 100% of the electricity produced based on renewable hydro power and low-emitting nuclear energy.

 Pillar Number Two

Oil is the main money earner for Equinor but it’s providing  of natural gas to Europe which has caught the public fancy.

According to the Norwegian Petroleum Association (see below), Norway produced in 2020, 22% of Europe’s natural gas demands. Additionally, 2/3’s of Norway’s total gas resources is still to be produced. No doubt in the short-term natural gas exports from Norway to Europe will be substantially raised.

Choosing a Future Home

The company’s net income in 2023 was $11.9Billion, basically the lion’s share from natural gas while its renewables business division(read offshore wind) Equinor’s renewables business has reported a net operating loss of $166Million for the third quarter of 2024, compared with a loss of $412Million in the same period in 2023.

No doubt Equinor’s natural gas will continue to flourish in the short-term. The key question is what will happen to the offshore  wind division? In this context do not expect that the Bay du Nord project will be developed in Canada any time soon.

Some Final Thoughts

• The Higher Court’s decision in the Netherlands ruled that it could not establish that Shell had a “social standard of care” to reduce its emissions by 45% or any other amount. Yet the court agreed the company had an obligation to citizens to limit emissions.
• A court follows precedent and does not establish it. In other words, the current design of the energy transition must have a more encompassing architecture if a new consensus is to be arrived at.
• An important item to address is the high ROACE rate which the oil companies see necessary to maintain their operations and investments: an ROACE above 20% is more or less the norm; double that of the new energy companies who aim to achieve an ROACE of 10%-12%.
• Maintaining a 20% ROACE is necessary if an oil company is to continue its generous dividends.
• If an energy transition CO2 surcharge were introduced would an oil company’s ROACE look so positive?
• New energy companies will be seeking more specialized services and government incentivized programs to ensure their growth both in terms of their share price and dividends.
• Finally, anticipate that the oil companies and new energy will continue to spin off, merge or form joint ventures to maintain economies of scale and further profitability.

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.  Kreeft has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report and contributes to the Institute Energy Economics and Financial Analysis(IEEFA). His book The 10 commandments of the Energy Transition is now on sale at  Bookstorehttps://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments-of-the-Energy-Transition.