To grasp the difference between Africa’s two busiest oil drillers, look at where each chose to spend its money in the past year. TotalEnergies, a French supermajor, picked up more acreage in the Niger Delta, raised its stake in an Angolan block, and pressed ahead with a giant gas project in Mozambique that it had to abandon four years ago after jihadists overran a nearby town. Eni, an Italian rival, went looking for oil where almost nobody has found any. It signed deals in Sierra Leone and the Gambia, two countries with a long history of dry wells and abandoned licences, and poured a further $4 billion into a field off Côte d’Ivoire that did not exist on any map five years ago.
Both companies insist Africa is central to their future. Both are right to think so. Output from the five Western supermajors in sub-Saharan Africa has fallen by a third since 2019, reckons Energy Intelligence, an industry publisher, as ageing fields run dry and companies sell off assets they no longer want to operate. Yet new basins keep opening up, often in places investors had written off. TotalEnergies already draws around 450,000 barrels a day from the region, more than any other big firm. Eni is not far behind, and in West Africa’s newest frontiers it has been the more adventurous of the two.
The contrast is not simply a matter of corporate taste. It reflects two different theories about where the next decade of African oil will be made. TotalEnergies’ bet is that the safest returns lie in basins it already understands, places with decades of seismic data, working pipelines, and governments it has dealt with for half a century. Eni’s bet is that the biggest prizes go to whoever turns up first in a basin nobody else believes in yet, and is willing to absorb the years of failure that frontier exploration usually involves.
Geology does not respect a company’s spreadsheet, and both strategies carry genuine risk. Total’s approach can look conservative when oil prices are high and rivals are finding giant fields elsewhere. Eni’s approach can look reckless when a country with three decades of failed wells turns out, yet again, to have nothing commercial underground. What follows is a look at how each firm is placing its bets, where the two strategies quietly cross over, and what each will need to go right.
The countries involved have little patience for either company’s spreadsheets. Nigeria, Angola and Mozambique need oil money to plug budgets battered by aid cuts and expensive debt. Sierra Leone and the Gambia, poorer still, have spent forty years waiting for a discovery that pays for a hospital or bring hundreds of out-of-school children in classrooms. Whichever bet wins, it is their economies that will feel it first.
Total bets on what it knows
TotalEnergies’ Africa strategy can be summed up in three words its chief executive, Patrick Pouyanné, used at a recent event in New York: Nigeria, Angola, “historically.” Asked where the company’s oil ambitions lay outside Brazil and the American Gulf, he did not reach for a frontier basin. He named the two countries Total has worked in since before most of its current engineers were born, then added Namibia almost as an afterthought. “We are too small” for shale, he said of the rival bet some American firms have made; deepwater basins with a known geology are where Total’s “technical expertise is a key driver.”
In Nigeria that has meant doubling down rather than starting over. Total signed a new production-sharing contract with the state and a local partner, Sapetro, for two blocks in the Niger Delta, and raised its operating stake in another, OPL 257, to 90% through a swap with a Nigerian firm, Conoil. At the Ubeta gas field, more than 90% of the workforce on site is Nigerian, the company says, a detail it likes to repeat to officials wary of foreign firms extracting wealth and little else. None of this required Total to drill a single new wildcat well. It required only the patience to keep negotiating in a basin it has known since the 1960s.
Angola tells similar story at a larger scale. Total is the country’s biggest oil operator, holding stakes in five blocks and the Angola LNG plant, and recently sanctioned the Cameia-Golfinho field alongside two further gas projects due online this year. The company’s Angola country manager talks about helping the country hold national output above a million barrels a day, a target that depends less on discovery than on squeezing more from fields already mapped decades ago.
However, Mozambique is the boldest version of the same logic, and the most fraught. In 2021 fighters loyal to the local franchise of Islamic State overran Palma, a town near the site where Total was building a plant to liquefy gas from offshore. At least 800 people were killed. French prosecutors are investigating whether the company did enough to evacuate its contractors; Total denies wrongdoing and says everyone on site got out.
The $20bn project, in which Total holds a 26.5% stake, was barely removed from a force majeure earlier this year. The insurgents’ numbers have dwindled to perhaps 300 or 400 fighters, reckons Tomás Queface of the Mozambique Conflict Monitor, too few to threaten the site directly, though they struck villages 40km away as recently as August. Rwandan troops, paid for by the European Union, now patrol the area, and the LNG site itself sits on a peninsula that has been turned into something close to a fortress. “Everything is ready” to restart, Pouyanné said on the relaunch date. If he is right, the IMF reckons Mozambique’s growth could reach 10% a year by the time gas starts flowing.
What unites Nigeria, Angola and Mozambique is not safety in any simple sense. Total has decades of seismic data, established partners, and governments it knows how to read. The company is not avoiding risk so much as choosing the risks it already understands.
Eni’s bet: turning up where nobody else will
On the other hand, Eni is quitely building a new portfolio in Africa on opposite instinct. Where Total reaches for what it knows, Eni goes looking in places its rivals have given up on.
Sierra Leone is the clearest case yet. Exploration there began in the 1980s with two wells that found oil but never enough to be worth pumping. A long silence followed, broken in 2009 when an American firm, Anadarko, struck oil at a site called Venus, 1.8km under the Atlantic. Four more discoveries followed over the next few years, at Mercury, Jupiter, Djembe and Savannah. Every one of them was judged commercially unviable. By 2018 the last major foreign operator had walked away, citing the cost of drilling in such deep water and the global price of oil, which had halved.
That graveyard of dry wells is the basin Eni walked into in October, signing a reconnaissance deal covering nearly 6,800 sq km of Sierra Leonean waters, alongside Shell. The government’s own estimate, fairly hard to verify and not obviously conservative, puts recoverable reserves at 15bn-20bn barrels, including a single prospect called Vega that one previous operator believed held 3bn barrels before deciding it could not make the numbers work. Whether Eni reaches different numbers, or simply has a higher tolerance for risk than Anadarko did, the company is committing serious money to find out.
The Gambia offers an even thinner track record. Eni picked up its first ever exploration block there this June, in a country with no history of commercial oil production at all. The appeal is mostly inference: the Gambia sits on the same geological trend that has produced large discoveries elsewhere along West Africa’s Atlantic margin, even though nobody has yet drilled deep enough, in the right spot, to prove it holds anything.
Then there is Côte d’Ivoire, the example Eni reaches for whenever it wants to justify the rest of this strategy. The company discovered the Baleine field in 2021, the country’s first commercial find in twenty years. Production started two years later, an unusually fast turnaround built on reusing existing floating vessels rather than waiting for new ones to be built. In May this year Eni and its partners, the Ivorian state firm Petroci and the trading house Vitol, approved $ 4billion for a third expansion phase, expected to more than double output to 150,000 barrels a day.
Eni calls its approach the “dual exploration model”: drill at high risk, prove a discovery, then sell down part of the stake while keeping control, using the proceeds to fund the next bet. It sold 30% of Baleine to Vitol last September and a further 10% to Azerbaijan’s state oil firm in January, saying plainly that the deals were meant to “accelerate the monetization of exploration discoveries” so the cash could be redeployed elsewhere. Sierra Leone and the Gambia are, in effect, where that cash is going next.
Where the two oil majors’ strategies quietly meet
Indeed, neither company is as one-dimensional as its headline deals suggest.
Total’s gentlest frontier bet is in Uganda, where it is building the world’s longest heated pipeline, 1,443km of it, to carry crude to the Tanzanian coast. The project has drawn fierce opposition from European campaigners trying to “stop Total,” and from quieter, more dangerous pressure on Ugandans who protest locally; dozens have been arrested, and some report threatening calls or break-ins.
Western banks have refused to finance the pipeline, leaving African lenders, and possibly Chinese ones, to fill the gap. Total has avoided saying who. In Namibia, too, the company is weighing a $10bn bet on drilling 300km offshore in waters 3km deep, a project as geologically uncertain as anything Eni has signed up for. A decision is expected soon, with first oil targeted for 2029, though the field’s gassiness and low rock permeability could slow things down.
Eni, for its part, has not abandoned the basins in Africa that made it rich. It remains a large operator in Nigeria and the Republic of Congo, where its Litchendjili gas field feeds a liquefaction project due to expand again this year. The company’s African chief executive, Claudio Descalzi, began his career running Eni’s Nigerian and Congolese operations in the 1990s, and the firm’s older, steadier assets in those two countries still generate much of the cash that funds its frontier bets elsewhere.
“The overlap suggests the real difference between the two firms is one of emphasis, not philosophy. Both are running a portfolio of safe cash generators alongside riskier exploration plays. Total simply keeps the frontier share smaller, and concentrated in projects, Uganda and Namibia, that it can justify to investors as adjacent to basins it already knowsm” says Charles Nzagoghi, a policy director at Instart Energy, in Ghana.
“Eni keeps a larger share of its capital in places with no production history at all, betting that one Baleine is worth several Sierra Leones that come to nothing.”
What it will mean for the countries involved
For the governments hosting these projects, the money on offer is not abstract. In Uganda, oil revenue might eventually add $1 billion to $2 billion a year to a government whose entire GDP is around $ 60billion; not transformative, says Adam Mugume, a director at the central bank, but more than the country used to receive in American aid before recent cuts.
Namibia’s reserves, modest in global terms, would go a long way in a country of three million people. Mozambique’s potential growth rate, if the LNG project restarts as planned, dwarfs almost anything else on the continent.
All three governments have set up funds meant to ring-fence the windfall for future generations rather than today’s budget. Whether that holds is another matter. Mozambique and Uganda are both ruled by parties that have held power for decades and show signs of strain: Mozambican security forces shot dead hundreds of protesters last year, and in Uganda the ageing president, Yoweri Museveni, faces a succession nobody has planned for cleanly. Oil money in that kind of environment tends to grease whichever wheels are already turning, for better administration or for worse patronage.
Sierra Leone and the Gambia face a smaller but more basic risk: that Eni’s bet simply does not pay off, as it has not paid off for half a dozen companies before it. A failed well in a country this poor is not a footnote on an annual report. It is a licensing round that produces nothing, a survey that confirms only how little anyone still knows, and another decade added to a wait that already runs to forty years.
What both companies share, in the end, is a wager that Africa’s geology still has surprises left in it, whether in basins everyone already trusts or in ones nobody has dared believe yet. The continent’s finance ministers, watching either bet from the sidelines, have little choice but to hope both pay off at once.
