Fossil Fuels Still Generate 57% of the World's Electricity

By Irina Slav - Jul 21, 2026

• Coal, gas and oil still generate 57% of the world's electricity, down from 65% in 2000, according to Pew Research Center's analysis of Ember data.
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• Wind and solar now supply 17% of global electricity, more than triple their share a decade ago, but nuclear's share has fallen from 17% to 9% since 2000.
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• China leads the world in wind and solar capacity while still burning more coal than any other country; the EU now gets 48% of its power from non-hydrocarbon sources versus 29% from gas and coal.
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When the Energy Institute reported in its Statistical Review of World Energy that the global grid is still ruled by hydrocarbons, it may have come as a surprise to some observers. Now, another report has confirmed the status quo: alternative energy sources of electricity are expanding, but the world still generates most of its electricity from coal, gas, and oil.

Some 57% of global electricity is generated from hydrocarbons, Pew Research Center reported, after analyzing data produced by net-zero outlet Ember, which is also a partner of the Energy Institute in the Statistical Review of World Energy. While a solid portion of the total, that share is a decline from 65% back in 2000, the report noted. For context, the Energy Institute's report estimates the share of coal, gas, and oil in global primary energy consumption at 86%, essentially unchanged over the past 20 years/

Alternative energy sources such as wind and solar, meanwhile, have been expanding rapidly, especially solar, according to the Pew Research Center report. According to the Ember data, wind and solar together accounted for a total of 17% of the world's electricity generation last year, while a decade ago the two combined only covered less than 5% of demand. The report noted that when bundled with energy sources such as geothermal, hydropower, and tidal power, renewable energy sources accounted for a larger share of global electricity generation than hydrocarbons. This is hardly a surprise, given the world's significant hydropower generation capacity, which has been in use for decades.

A problematic finding of the Pew Research Center report is the decline in nuclear power generation. This fell last year to 9% of total generation, from 17% back in 2000. The reason this is a problem was revealed by the Energy Institute in its report and has to do with the rate of electricity demand growth versus the rate of generation capacity growth. According to the Energy Institute and its partners, energy demand globally is soaring much faster than new generation capacity is being added—even solar, which is normally fast to build and put into operation.

The Energy Institute said in its report that this is the reason why coal and gas—and to a lesser extent oil—remain such a big part of the electricity generation mix of the world. They can be supplied on demand and generate power also on demand, unlike their alternatives.

The Pew Research Center also noted the much faster growth of electricity demand compared to supply, highlighting the inevitable increase in the use of hydrocarbons in absolute terms, while as a share of the total, they declined, according to the Ember data. Alternatives, such as wind and solar, on the other hand, have grown as a share of the total as a number of countries embarked on a crusade against emissions and energy import dependence.

China has been by far the most successful in shifting away from hydrocarbons—while it has remained one of the biggest consumers of all three of them. This is another piece of evidence of the difference between energy mix as capacity and energy use. China is the world's biggest market for wind and solar capacity, but it is also the largest consumer of coal—and builder of new coal power plants.

The European Union is at the other end of the scale, boasting more electricity generated by non-hydrocarbon sources than hydrocarbons last year. The alternative source total in the report does not include a breakdown by type but likely includes hydropower. That share stood at 48%, according to Ember data, while 29% of the total was generated by gas and coal power plants.

By Irina Slav for Oilprice.com

Africa’s Richest Man Proposes To Build 700,000 Bpd Oil Refinery In Kenya

By Alex Kimani - Jul 22, 2026

• Dangote plans a $17 billion, 700,000 bpd refinery on Kenya’s Lamu Island, aiming to end East Africa’s reliance on imported fuels.
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• The refining hub could serve Kenya, Uganda, South Sudan, Rwanda, Burundi, and the DRC.
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• The proposal faces significant hurdles, including environmental opposition over impacts on Lamu’s UNESCO-listed ecosystem, concerns about carbon emissions and stranded assets, and fears the refinery could dominate regional fuel markets.
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East Africa has spent decades exporting one commodity and importing another. The region holds roughly 4.7 billion barrels of crude oil reserves and more than 70 trillion cubic feet of natural gas across Uganda, South Sudan, Kenya and the DRC, according to the African Energy Commission (AFREC). Yet it imports 100% of its refined fuel after Kenya Petroleum Refineries Limited (KPRL), the region’s last operating refinery, shut down in 2013. Nigerian billionaire Aliko Dangote now says he intends to reverse that equation with a $17 billion (KSh2.2 trillion), 700,000-barrel-per-day refinery on Kenya’s Lamu Island that would process crude for Kenya, Uganda, South Sudan, Rwanda, Burundi and the DRC. The refinery’s planned capacity of 700,000 barrels per day exceeds East Africa’s current refined fuel demand of roughly 450,000 bpd by about 250,000 bpd, leaving room to supply markets elsewhere on the continent. Lamu’s natural harbor, with drafts reaching 18 meters, can accommodate fully laden Post-Panamax crude tankers carrying up to 2 million barrels, vessels too large to call at Mombasa. 

That gives the refinery direct access to long-haul crude imports while providing an export outlet for surplus gasoline, diesel and jet fuel. Construction and operation are projected to create more than 60,000 jobs, making the project one of the largest industrial employers ever proposed for Kenya’s coast.

Situated along the strategic LAPSSET Corridor, the project is already sparking major cross-border private sector partnerships.

Tanzanian billionaire Mohammed Dewji has expressed intent to inject $100 million into the development. 

The giant refinery will also test the feasibility of intra-African industrial integration under the African Continental Free Trade Area (AfCFTA). The refinery would be able to process crude from East African producers such as Uganda, South Sudan and Kenya as regional production expands, while also accepting cargoes from larger exporters including Nigeria and Angola. Refined fuels and petrochemical feedstocks could then be sold across the African Continental Free Trade Area (AfCFTA), a 55-country market with 1.4 billion people and a combined GDP of roughly $3.4 trillion that is gradually removing tariffs and other trade barriers on intra-African commerce.

Kenya’s new mega-project will be encouraged by the success story of Nigeria's Dangote refinery. The Dangote Refinery has transformed Nigeria from an import-dependent nation into an energy-secure hub by eliminating the need to import refined fuel. Commissioned in 2023, the 650,000 bpd refinery meets 100% of Nigeria's total domestic requirements for gasoline, diesel, and jet fuel, stabilizing structural supply shocks with local marketers now able to buy and sell directly. By slashing refined product import bills, the refinery has significantly improved Nigeria's balance of payments. This improved external financial position directly led to Nigeria receiving its first sovereign credit rating upgrade to B in 14 years, helping the country secure loans on more attractive terms. Local refining retains wealth domestically, alleviating massive demand for foreign exchange and helping stabilize local currency fluctuations.

Beyond energy, the facility produces Dangote fertilizer, creating thousands of jobs and reshaping trade flows by exporting clean fuel to other African countries and global markets. And, it has also helped lower Nigeria's emission: by processing crude domestically rather than exporting it to carbon-intensive refineries overseas, the highly energy-efficient plant is expected to eliminate over one million metric tonnes of CO? emissions annually.

As you might expect, Kenya’s proposed project is already facing mounting criticism and opposition. Activists from Greenpeace Africa and local community groups have vigorously rejected the project, warning it could destroy Lamu's delicate UNESCO world heritage marine ecosystem, including vital mangrove forests and coral reefs that sustain local tourism and fisheries. Critics have warned the facility risks becoming a stranded asset as global energy transitions accelerate, potentially locking Kenya into decades of heavy carbon emissions. Human rights and constitutional lawyers have threatened High Court cases, demanding the Kenyan government pause all work until exhaustive, impartial Environmental and Social Impact Assessments (ESIAs) and transparent public participation are fully executed.

Meanwhile, economists note that Dangote Industries' demand for robust anti-dumping protections and tax incentives could spark local backlash if it is perceived to unfairly corner the regional fuel market or stifle fair competition. After all, the Dangote Petroleum Refinery has previously faced legal and regulatory battles with the Nigerian state oil firm (NNPC) and major markers after the company sought to nullify rival import licenses to protect its dominant share, with regulators and marketers arguing it exposes the market to monopoly control.

By Alex Kimani for Oilprice.com

India Scours Angola, Venezuela for Crude as Mideast Supply Dries Up

By Charles Kennedy - Jul 24, 2026

Indian refiners are in search of crude supply from as far as Angola in Africa and Venezuela in South America as their term supplies from the Middle East are trapped again and unable to reach India as planned.

Some of the biggest state-held refiners in India, the world’s third-largest crude oil importer, are looking for and testing new crude grades, to offset part of the supply lost to the Middle East conflict, senior refinery executives told Indian outlet Economic Times.

“We diversified our crude sourcing outside of the Strait of Hormuz, exploring multiple geographies including two new crude grades from Venezuela and Angola,” Vetsa Ramakrishna Gupta, finance director at state-run Bharat Petroleum Corporation Limited (BPCL), told ET.

Another state-run refiner, Hindustan Petroleum Corporation Limited (HPCL), said it barely got any term supplies from the Middle East in the first quarter as cargoes were trapped in the Persian Gulf west of the Strait of Hormuz.

“This time in the first quarter, we hardly got anything from our term contracts because a lot of the term contracts were sitting on the other side of Strait of Hormuz,” HPCL managing director Vikas Kaushal told the Indian outlet.

“We had to make decisions based on availability rather than optimisation,” the executive added.

India’s crude oil imports from Russia have remained close to record-high levels in July despite the end of the U.S. waiver the previous month.

But this week, some of India’s state refiners suspended crude oil loadings from Iraq, amid the escalation of hostilities in the Middle East and the abrupt halt to traffic through the Strait of Hormuz.

Indian Oil Corp and Mangalore Refinery and Petrochemicals Limited (MRPL) have reportedly suspended crude loadings from Iraq, with Indian Oil ditching earlier plans to load the supertanker Lila Jamnagar, concluding that sending a fully laden 2-million-barrel tanker through Hormuz was no longer worth the risk. MRPL has also halted Iraqi liftings as security in the region continues to deteriorate.

By Charles Kennedy for Oilprice.com

Global Refiners Are Cutting Out Oil Traders To Buy Venezuelan Crude Directly

By Alex Kimani - Jul 22, 2026

• Companies including Phillips 66, Reliance, Chevron, Repsol, and Eni are signing direct crude supply deals with PDVSA, reducing the role of trading houses such as Vitol and Trafigura.
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• By selling directly to refiners and joint-venture partners, Venezuela captures higher realized prices while reshaping crude trading flows and Gulf Coast refining economics.
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• Oil exports have climbed above 1.2 million bpd, though growth remains constrained by aging infrastructure and limited oilfield services despite expectations for further production gains.
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Commodity traders are having the rug pulled out from under one of their biggest paydays yet as refiners start bypassing oil and traders and buying Venezuelan crude directly, according to Reuters. Refiners and major oil-producing firms are rapidly gaining market share in Venezuelan crude by locking in direct supply contracts with state-run Petróleos de Venezuela, S.A. (PDVSA), bypassing the global middlemen and commodity trading houses such as Trafigura and Vitol that previously dominated the space. Six months after traders reopened Venezuela’s oil market, Phillips 66 (NYSE:PSX) and India’s Reliance Industries have already signed direct supply agreements, with Valero (NYSE:VLO) and Thailand’s Tipco expected to follow.

Previously, Vitol and Trafigura enjoyed first-mover advantage, managing to become dominant in Venezuelan crude marketing because of their exclusive U.S. government licenses, pre-existing logistical infrastructure and historical ties to PDVSA. Following major political shifts in Venezuela in January, the U.S. administration brokered a deal to manage and sell the country's oil. The U.S. Department of the Treasury issued special, long-term licenses specifically to Vitol and Trafigura until June 2027, effectively giving the traders a temporary monopoly. The pair collectively moved more than 100 million barrels of crude over a six-month period while other global firms remained legally locked out.

Their unmatched logistics also gave them a clear upper hand. After all, global trading houses have the fleet capacity and global reach to quickly deploy tankers and reroute large volumes of crude. They could absorb massive storage and shipping costs in a difficult market, using floating storage facilities in places like Malaysia to break up bulk shipments. When the ongoing war in Iran disrupted Middle Eastern supply chains, Vitol and Trafigura quickly diverted heavy Venezuelan grades like Merey 16 to major Asian refining hubs in India, South Korea, and Malaysia at narrower discounts.

Unfortunately for Vitol and Trafigura, that access monopoly has begun to evaporate.

PDVSA is now actively restoring its pre-2019 business model, which prioritizes direct supply contracts with refiners and joint-venture partners over intermediaries. After a seven-year hiatus, Phillips 66 has resumed purchasing spot cargoes directly from PDVSA. In July, the company was directly allocated three cargoes of Merey 16, a heavy sour crude grade that suits its U.S. Gulf Coast refining system.

By eliminating intermediaries, PDVSA is able to raise its realized price by avoiding paying reseller premiums, reshaping Gulf Coast refining economics.

Similarly, Chevron Corp.(NYSE:CVX) has significantly expanded its Venezuelan oil exports, recently hitting an average of 293,000 barrels per day (bpd) in the second quarter, up from 223,000 bpd earlier in the year. This ramp-up coincides with the company’s uptick in shipments to U.S. Gulf Coast refiners, along with its moves to secure assets and drilling deals in the Orinoco Oil Belt. Chevron and PDVSA finalized an asset swap that increased Chevron's stake in the Petroindependencia JV to 49% and granted development rights to new areas in the Orinoco Oil Belt.

The U.S. Oil & Gas major aims to steadily expand its JV output, competing directly with global trading houses for a larger slice of Venezuela's total crude exports, which have risen to over 1.2 million bpd. Analysts estimate that maximizing these export and production capabilities could add up to $700 million annually to Chevron's operating cash flow, according to Bloomberg back in January.

Reliance Industries, India’s top refiner, has also begun direct purchases of Venezuelan crude to complement the volumes it previously had to source through intermediaries. Back in April, Reliance loaded a 2-million-barrel cargo of heavy Venezuelan crude directly from PDVSA, navigating terms controlled by the U.S. Treasury Department.

Meanwhile, European energy majors have followed suit: Spain's Repsol (OTCQX:REPYY) and Italy's Eni S.p.A. (NYSE:E) both expanded direct liftings of Venezuelan crude to supply their European refining operations. The two companies are using this to offset billions in receivables accumulated from supplying the domestic Venezuelan market with gas and diluents. Eni and Repsol co-manage the Cardón IV project and are actively pursuing agreements to sustain and expand domestic gas supply, with long-term ambitions for LNG exports.

That said, the ongoing revival of the Venezuelan oil trade has hardly been smooth-sailing, with the South American country facing a severe shortage of functional oilfield services and drilling equipment. Rystad Energy estimates that while a 17% crude production increase is technically possible by 2028, real operational limits are dictating the actual pace of recovery. Backed by U.S. regulatory clearance, Venezuela’s total oil and fuel exports climbed past 1.2 million barrels per day in mid-2026, up from an average of 847,000 bpd in 2025, and now eyeing 1.37 million bpd by the end of the year.

By Alex Kimani for Oilprice.com

Insurers Flock to Oil Projects Outside the Middle East

By Tsvetana Paraskova - Jul 23, 2026

• Global insurers are slashing premiums by up to 50% for upstream oil and gas projects outside the Middle East as companies shift investment away from war-exposed regions.
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• Big Oil is accelerating exploration and development in lower-risk basins including Guyana, Namibia, Brazil, Nigeria, Venezuela, Turkey, and Cyprus to reduce geopolitical exposure.
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• Strong oil prices and the search for secure supply are driving a new wave of global upstream investment, with insurers competing aggressively for business outside the Gulf.
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Global insurers had just shaken off the ESG push from earlier this decade when the Middle East conflict upended oil and gas upstream project coverage.

The world’s lowest-cost oil and gas producing region became a war zone at the end of February, with war-risk premiums and oil and gas drilling and construction projects facing either delays or significant cost inflation.  

Five months of uncertainties about new oil and gas projects in the Middle East have prompted insurance giants to turn to underwriting drilling and project construction ventures outside the prolific but highly volatile region.

And the race is on for attracting insurance business in oil and gas basins less exposed to geopolitical flare-ups. Insurers are slashing premiums on upstream energy insurance for projects not depending on the on-and-off closed Strait of Hormuz and other chokepoints in the Middle East.

Insurers Compete for Underwriting Projects Outside Middle East

Premiums for upstream energy insurance outside the Middle East have tumbled by about 25% year to date, insurance brokers told the Financial Times.

In some cases, some insurers have slashed the premiums by as much as 50%, even at a short-term loss, according to industry insiders who spoke to FT. 

The reason is clear—as oil and gas companies boost exposure to basins and projects outside the Middle East, insurers are competing for a market share of the now-shrunk global pool of upstream developments that are not in an active war zone.

“Upstream [energy] has been a very profitable sector for the market for a number of years,” Rupert Mackenzie, a natural resources insurance broker at WTW, told FT.

“The view from insurers is, this is a sector which they would like to have ongoing exposure,” the broker added.

Mackenzie’s colleagues at WTW said in an April report, Energy Market Review 2026, that “ratings are ‘through the floor’”.

This year, “15–20% reductions are available for core upstream risks with clean loss histories and substantial premium on the slip, with 40%+ reductions still observed in exceptional cases,” WTW said in its annual report published a month and a half after the Iran war began

“The overarching pricing trend is unmistakable: even after a decade of softening, the market is still finding new downward territory,” according to WTW.

The Iran war and the Middle East becoming an active war zone have pushed the world’s biggest international oil and gas firms to pursue upstream projects away from the region, Mackenzie told FT.

Big Oil Firms Double Down on Exploration Far From Middle East

Amid the Middle East conflict, Big Oil firms are trying to minimize losses on curtailed production and barrels not lifted because of the Strait of Hormuz crisis.

And they are betting on high-impact exploration and upstream projects in hotspots such as Guyana, Suriname, Namibia, Brazil, Turkey, and Cyprus, to name a few.

Exxon and Chevron are doubling down on the billions of barrels of crude oil discovered offshore Guyana. Separately, Chevron is boosting its business in Venezuela, where the Trump Administration hopes U.S. firms would increase production and oil exports to the United States.

Exxon, for its part, expects to invest billions of U.S. dollars in Nigeria’s deepwater oil and gas fields. Exxon is progressing the $7-$8 billion billion-barrel Owowo deepwater project offshore Nigeria, “looking into an FID as early as next year,” Hunter Farris, Senior Vice President – Deepwater for ExxonMobil Upstream Company, said in April.

That’s only one of Exxon’s new projects in Africa’s top oil producer, which has raised its crude oil sales in Asia in recent months as refiners reel from the shock supply loss from the Middle East.

ExxonMobil’s subsidiary in Nigeria and its partners earlier this month committed $1 billion to the on-block activities for the Usan Infill Project in OML 138. The project will unlock 40,000 additional barrels of crude oil in 18 months. It also “signifies renewed interest and hope in Nigeria being Esso’s first major deep water project in the country since 2016,” the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) said in early July.

Elsewhere, BP in April bought into three offshore exploration blocks in Namibia, one of the hottest exploration destinations, where Shell, TotalEnergies, and Galp have already made large oil discoveries.

TotalEnergies in April signed a Memorandum of Understanding with Türkiye Petrolleri Anonim Ortakl??? (TPAO) to evaluate exploration opportunities in the Black Sea region and internationally.

Companies are also increasingly looking at shale opportunities outside the U.S., with Argentina, China, Turkey, and Australia drawing interest for potential development of onshore resources far away from the Middle East. 

Oil and gas exploration has created a lot of value for the industry in recent years.

The industry created $54 billion of value after deducting $97 billion of spend on exploration from 2021 to 2025, under a long-term Brent price of $65 per barrel, an analysis by energy consultancy Wood Mackenzie showed in April.  

At $85 per barrel Brent, value creation more than doubles to $120 billion, according to WoodMac.

By Tsvetana Paraskova for Oilprice.com

Brazil’s Oil Boom Is Accelerating as Asian Buyers Flee the Middle East

By Matthew Smith - Jul 22, 2026

• Brazil's oil and gas production reached fresh record highs, driven by prolific offshore pre-salt fields that continue attracting massive investment.
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• Disruptions in the Strait of Hormuz are boosting demand for Brazilian crude, particularly from Asian refiners seeking reliable, high-quality supplies.
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• Petrobras and international oil majors are investing heavily, positioning Brazil to become one of the world's top five hydrocarbon producers and exporters.
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Since Middle East hostilities reignited, oil prices have soared higher, although they remain below the highs witnessed during April 2026. This can be blamed on U.S. strikes against Iran, with Tehran and Washington disrupting traffic in the Strait of Hormuz, through which a fifth of global hydrocarbon supplies are shipped. This has sparked greater demand for Brazil’s high-quality oil grades, notably from Asia, because there is no need for shipments to pass through contested waters. This will drive greater petroleum investment and production, keeping Brazil on track to become a top 5 global producer and exporter.

Government data shows Brazil’s June 2026 hydrocarbon output hit a new record of 5.8 million barrels of oil equivalent daily. This is a 4.2% increase month over month and 3.6% higher than April 2026’s record high of 5.64 million barrels of oil equivalent daily. It is also an impressive 19.2% greater than the same period a year earlier. Oil production for June 2026 reached an all-time high of 4.5 million barrels per day, a 4% month-over-month increase and a stunning 19% higher than the same period a year earlier.

Natural gas production is also soaring. June 2026 output hit a record 7.7 billion cubic feet per day, which was 5.5% greater than a month earlier and is a whopping 19.6% higher year over year. This is particularly important with demand for natural gas in South America soaring higher while regional supply becomes increasingly constrained because of falling reserves and production. This is particularly the case in Colombia as well as Trinidad and Tobago, where domestic hydrocarbon sectors are facing significant headwinds.

Those solid numbers indicate Brazil’s oil and natural gas production is expanding in leaps and bounds, putting the country on track to become a top five global hydrocarbon producer and exporter. It is the offshore ultra-deepwater pre-salt layer, which is responsible for most of Brazil’s petroleum production, contributing nearly 77% of all oil lifted during June 2026. It is the prolific offshore Santos Basin, where the first pre-salt discovery was made during 2006 in the Tupi oilfield, which produces 74% of Brazil’s petroleum.

Brazil’s medium sweet pre-salt petroleum is gaining greater market share, notably since the U.S. conflict with Iran disrupted world oil supply by closing the Strait of Hormuz. The country’s main petroleum grade, Tupi, is a medium crude oil with an API gravity of around 29 degrees, which is sweet with a sulfur content of a mere 0.31%. Those characteristics, along with low contaminants, notably paraffin and metals, make it easier and cheaper to refine Tupi into high-grade fuels.

Brazil’s top export crude oil grade is increasingly popular with Asian countries, especially China, seeking high-quality feedstock for refineries which isn’t subject to the same supply risks as Middle East crude. Since transit through the Strait of Hormuz was disrupted in early 2026, Brazil’s oil exports have surged higher, although shipments were steadily growing since 2021. As a result, Brazil’s first quarter oil exports soared by 31% year over year to be worth $12.56 billion.

During March 2026, China imported record volumes of Brazil’s crude oil, receiving 1.6 million barrels per day from South America’s largest oil producer. The world’s fastest-growing major economy, India, received 15% of Brazil’s oil exports, making the country the world’s second largest recipient of the country’s petroleum shipments. With further disruptions to shipping traffic needing to pass through the Strait of Hormuz and escalating strikes in the Middle East, demand for Brazil’s petroleum will remain high for the foreseeable future.

Production, along with the tremendous amounts of investment required to drive higher hydrocarbon output, is growing despite leftist president Luiz Inácio Lula da Silva recently extending a controversial 12% tax on oil exports for 60 days. It is estimated that during 2026, Brazil will attract $21.3 billion of investment in upstream hydrocarbon operations. This will drive higher production at a crucial time, with the outlook for oil and natural gas highly uncertain because of ongoing clashes between the U.S. and Iran.

Brazil’s aggressive plans to expand hydrocarbon output and become a leading global energy exporter will be a boon for South America. It will reduce the continent’s dependence on fossil fuel imports from the Middle East and offset declining petroleum production in Colombia, Ecuador and Peru. National oil company Petrobras will be a key driver of that expansion with the driller investing significant capital in its operations, particularly upstream assets, until the end of the decade.

The Brazilian integrated energy major recently committed to spending $109 billion on operations between 2026 and 2030. Petrobras budgeted $69.2 billion for upstream projects alone, with 62% of that capital to be invested in pre-salt assets, 24% on post-salt operations and 10% for exploration activities, with the balance directed to onshore infrastructure. This, Petrobras believes, will lift its hydrocarbon output to 3.4 million barrels of oil equivalent daily, with 82% coming from pre-salt operations. 

Brazil’s geopolitical stability coupled with a more favorable regulatory environment since 2016 has attracted considerable attention from foreign supermajors. That investment is behind the considerable growth of the South American nation’s oil production, which rose 75% over that period. A key international player in Brazil is Anglo-Dutch supermajor Shell, which has invested heavily in the country over the last five years, nearly doubling its holdings to have a working interest in nearly 70 oil blocks compared to 30 in 2022.

Shell’s aggressive expansion saw it become Brazil’s second largest oil producer behind Petrobras, lifting nearly 12% of all petroleum extracted for June 2026. This makes Brazil Shell’s largest producing country. Other energy supermajors, including Equinor, TotalEnergies, ExxonMobil and Chevron, are operating in Brazil’s prolific offshore deepwater pre-salt oilfields. Heightened Middle East tensions and ongoing disruptions to the Strait of Hormuz, with no clear end to the U.S. conflict with Iran in sight, make a geopolitically stable Brazil a preferred country for investment from Big Oil.

By Matthew Smith for Oilprice.com