Oil and Energy in Latin America 2026: The Complete Guide

RioTimes Deep Analysis | Series: Latin America Energy Guide

Latin America’s energy sector entered 2026 as the most consequential swing producer in global oil markets — not by accident, but by the compounding force of a decade of deepwater investment in Brazil, a shale revolution in Argentina, a tiny nation called Guyana rewriting its economic future barrel by barrel, and a geopolitical shock in the Persian Gulf that turned every Atlantic-facing export terminal into a strategic asset. This guide traces every major thread: production records, governance crises, price shocks, and the unresolved question of whether the region can expand hydrocarbons and build a clean energy future at the same time.

Petrobras: Brazil’s Pre-Salt Machine Breaks Records

Brazil’s state oil company opened 2026 at full throttle. According to AInvest, Brazil’s total operated oil production hit 5.304 million boe/d in February 2026 — a 16.4% year-on-year surge — with pre-salt fields from the Santos Basin now accounting for 80–82% of all output.

Industrial Info Resources confirmed that Petrobras’s own equity production reached approximately 2.45 million boe/d, driven by two new FPSOs that entered service during 2025: the Almirante Tamandaré at Búzios and the Alexandre de Gusmão at Mero. A third platform, P-78, entered operation on December 31, 2025, followed by an eighth FPSO arriving at Búzios in early 2026.

The financial results matched the operational records. Q4 2025 EBITDA came in at $11.1 billion — a quarterly record — and the board approved a $109 billion five-year investment plan for 2026–2030 in late 2025, with $78 billion dedicated to upstream exploration and production.

The company maintains a dividend policy of distributing 45% of free cash flow — totaling roughly R$41.2 billion (~$8 billion) proposed for 2025 alone.

April 2026 brought a landmark frontier investment: Petrobras approved the final investment decision for the Sergipe Águas Profundas (SEAP I) project, a $6 billion deepwater gas and condensate development in the Sergipe-Alagoas Basin. The SEAP project carries strategic fertilizer implications, as it would feed the UFN3 nitrogen fertilizer plant, reducing Brazil’s dependence on imported urea.

Separately, Petrobras also confirmed a new pre-salt discovery at Marlim Sul, demonstrating that the basin continues to yield exploration upside even after more than a decade of intensive development.

Governance has become as closely watched as production. In early 2026, President Lula nominated Guilherme Mello to chair Petrobras’s board, reflecting ongoing government ambitions to align the company’s strategic direction with broader economic policy — including fertilizer self-sufficiency and biofuel expansion.

CEO Magda Chambriard has publicly defended continued hydrocarbon investment while allocating $16.3 billion of the five-year plan to low-carbon energy, biofuels, and CCS, maintaining a dual-track posture that critics say papers over a genuine contradiction.

Vaca Muerta: Argentina’s Shale Revolution Reaches Escape Velocity

Argentina’s shale boom has become one of the most significant energy stories in the Western Hemisphere. According to S&P Global, national oil production hit 865,000 bbl/d in February 2026 — up 15.3% year-on-year — with Neuquén province (the home of Vaca Muerta) alone contributing 603,800 bbl/d, a 30.3% increase.

Deputy Energy Minister Daniel González told the AmCham Summit in April 2026 that Argentina is on track to reach 1 million bbl/d in 2026, a milestone that would surpass the previous national record set in 1998.

The RIGI investment framework has unleashed an $18 billion filing rush into Vaca Muerta. Established under Law No. 27,742 in July 2024, the Régimen de Incentivo para Grandes Inversiones offers a 25% corporate income tax rate, import duty exemptions for equipment, export duty waivers after an adhesion period, and full foreign exchange repatriation rights.

A February 2026 presidential decree extended the RIGI enrollment deadline by one year to July 8, 2027, and — critically — expanded RIGI’s scope to include upstream shale oil drilling, previously restricted to pipelines and separation plants. Pampa Energía has filed a $4.5 billion project targeting 45,000 bbl/d by mid-2027; Tecpetrol filed a $2.4 billion project targeting 70,000 bbl/d.

Argentina’s first RIGI-approved LNG export project — a 6 MTPA floating LNG terminal from Southern Energy and Golar LNG — represents the country’s opening bid to become a major gas exporter to Europe.

The Iran/Hormuz price shock accelerated the investment case dramatically. Higher global oil prices improve the fiscal return on every Vaca Muerta barrel, and Reuters forecasts Argentina’s energy trade surplus reaching $8.5–$10 billion in 2026 — a new record.

Long-term targets point toward 1.456 million bbl/d by 2030, which would transform Argentina from a secondary producer into a global top-10 oil nation.

Pemex: Ambition Meets Structural Decline in Mexico

Mexico’s state oil company presents the starkest contrast in regional energy: a government committing its largest-ever investment package to an institution whose output has fallen for nine consecutive years. President Claudia Sheinbaum and Pemex Director General Víctor Rodríguez Padilla unveiled a 425 billion peso ($21.2 billion) investment plan for 2026 — a 34% increase from the prior year — targeting crude oil production of 1.8 million bbl/d.

The plan is part of a 5.6 trillion peso national infrastructure program.

The gap between ambition and reality is severe. Full-year 2025 crude oil production came in at just 1.367 million bbl/d — the lowest in 35 years and nearly 8% below 2024 — according to Rio Times reporting on Pemex financials.

The 2026 target of 1.8 million bbl/d would require reversing a long-term structural decline driven by the maturity of major fields — a challenge that capital alone cannot easily solve. Mixed contracts with private sector partners have been slow to materialize: only 11 of 21 planned contracts were awarded as of mid-2026, with no major international oil companies participating and production additions far below targets.

One path being explored is a deepwater partnership with Petrobras. The Pemex-Petrobras Gulf of Mexico alliance was under active discussion in early 2026 after President Lula proposed the collaboration to Sheinbaum.

The logic is straightforward: Petrobras has mastered ultra-deepwater operations at scale; Pemex has frontier acreage but lacks the institutional capacity to develop it alone. No deal had been finalized as of April 2026, but the strategic rationale is compelling enough that CEO Chambriard was scheduled to visit Mexico to advance talks.

Ecopetrol and Colombia: Governance Crisis Meets Transition Politics

Colombia’s oil sector entered 2026 with a governance drama that reflects the country’s broader political fault lines. Colombia’s Attorney General filed formal influence-peddling charges against Ecopetrol President Ricardo Roa Barragán in March 2026, prompting the oil and gas workers’ union (USO) to demand his removal and threaten a national strike.

The Ecopetrol board deadlock over Roa’s future became a referendum on the balance of power between the Petro government, which sought his removal, and institutional shareholders who voted on March 24 to retain him. Roa subsequently went on scheduled vacation from April 7 to May 27, with Juan Carlos Hurtado Parra appointed acting president, according to a Ecopetrol board announcement.

Despite the political turbulence, production has remained broadly stable. Colombia’s national average output through March 2026 was 734,919 barrels per day — 2.3% above the technical baseline derived from proven reserves, according to MarketScreener.

Ecopetrol’s 2026 guidance is 730,000–740,000 boe/d, with 380–430 development wells and 8–10 exploration wells planned. The deeper policy question is whether that exploration pipeline has a future: President Gustavo Petro has refused to issue new oil exploration contracts and hosted a 2026 Fossil Fuel Phase-Out Conference in Bogotá, calling for concrete international commitments to end coal and oil use — even as higher oil revenues from the Iran price shock improved Colombia’s fiscal position, as Foreign Policy noted.

Guyana: The Hemisphere’s Fastest-Growing Producer

ExxonMobil’s Stabroek block off the coast of Guyana has become the most productive offshore oil development story of the decade. The block surpassed 900,000 bbl/d capacity in Q4 2025, according to the U.S. Energy Information Administration, and a fifth FPSO — the Errea Wittu, which will add 250,000 bbl/d under the Uaru project — completed assembly in Singapore and was on the verge of its voyage to Guyanese waters as of March 2026.

After the Uaru arrival, total Stabroek capacity will exceed 1.15 million bbl/d. The seventh sanctioned project (Hammerhead, 150,000 bbl/d, start 2029) and a potential eighth non-associated gas project are in government review, pointing toward a total target of 1.7 million bbl/d by 2030 from a block that had produced nothing a decade ago.

The economic transformation of Guyana is without modern parallel among small nations. The country’s GDP grew 19.3% in 2025 and is forecast at 16.2% in 2026, according to Reuters.

The Natural Resource Fund reached $3.82 billion in early 2026 — a sovereign wealth pool accumulated entirely within a few years of first oil. The Iran/Hormuz price shock delivered an additional windfall: all Stabroek exports are Atlantic-facing and entirely unaffected by Persian Gulf disruption, while ExxonMobil’s cost recovery timeline — originally modeled at $60/bbl — accelerated dramatically as prices approached $100 and beyond.

Venezuela: A Post-Maduro Oil Reset Under U.S. Oversight

Venezuela’s energy sector is undergoing its most rapid institutional transformation in two decades following a January 3, 2026 U.S. military operation that captured President Nicolás Maduro. According to documented accounts of the intervention, Maduro was transferred to New York to face drug trafficking and terrorism charges, with Acting President Delcy Rodríguez sworn in by January 5.

Within weeks, the National Assembly passed a sweeping oil industry privatization law — allowing private companies to control production and sales, introducing independent arbitration and production-sharing agreements, reducing taxes, and granting PDVSA operational autonomy — according to Reuters.

Production has recovered rapidly from the disruption caused by a U.S. naval blockade in January 2026. Output reached 924,000 bbl/d in January, recovered to 1.021 million bbl/d in February, and climbed to 1.095 million bbl/d by March, per Al Jazeera.

The U.S. expanded Chevron’s Venezuelan license in January 2026, allowing the company — which produces approximately 250,000 bbl/d — to sell extracted oil and receive cash payments rather than crude. A March 18 Treasury general license extended broad authorization to U.S. companies doing business with PDVSA.

The political constraints on Venezuela’s full oil sector recovery remain significant — Rice University’s Baker Institute projects best-case output of only 1.2 million bbl/d by end-2026, with recovery to the historical peak of 3.5 million bbl/d requiring years of sustained rule-of-law improvement and foreign investment.

The Iran/Hormuz Shock: Latin America’s Geopolitical Windfall

On February 28, 2026, U.S. and Israeli airstrikes targeted Iranian military infrastructure in Operation Epic Fury, triggering the closure of the Strait of Hormuz on March 4, 2026 — the route for approximately 20% of global oil supply and 15–20% of global LNG. The International Energy Agency described it as “the largest supply disruption in the history of the global oil market,” according to a Wikipedia summary of the conflict’s economic impact.

Brent crude moved from $72.48/bbl on February 27 to $103/bbl on average through March, and peaked near $128/bbl on April 2, 2026, per EIA data. The EIA revised its full-year 2026 Brent forecast to $96/bbl on April 7, up from $78.84 previously.

A two-week ceasefire announced by the Trump administration in April briefly reopened the Strait, causing a sharp price pullback.

Columbia University’s Center on Global Energy Policy framed the strategic consequence clearly: Latin America was already the world’s primary source of non-OPEC supply growth in 2026; the Iran shock made the region’s Atlantic-facing barrels indispensable. The full breakdown by country: Brazil received a mild positive from Petrobras revenues, offset by fertilizer import inflation and R$30 billion ($5.8 billion) in government fuel subsidies.

Argentina captured accelerated export revenue at record energy surplus levels. Guyana — with no domestic fossil fuel consumption to subsidize — received a pure windfall.

Venezuela benefited from an estimated $400 million in additional revenue per $1/bbl price increase. Mexico and Central American nations net-importing refined products absorbed the demand-side pain, with Mexico activating IEPS fuel subsidies to shield domestic consumers.

The full guide to the Iran war and Hormuz crisis traces the conflict’s full trajectory, and Latin America’s gasoline price surge and government responses documents how individual nations managed the consumer-side fallout.

Brazil’s Renewable Grid: A World Leader Building at Scale

While the oil headlines dominate investor attention, Brazil’s electricity grid tells a different story. According to PV Magazine, 84.6% of Brazil’s total installed electricity capacity came from renewables as of January 2026, with 87–88% of actual electricity generation from clean sources in 2024–2025.

Brazil is the only G20 country on track to meet the COP28 goal of tripling renewable capacity by 2030. Total installed capacity reached 215.9 GW in early 2026, with 9.1 GW of new additions forecast for 2026 alone.

Solar is the fastest-growing technology. Brazil added 2,331 MW of new solar in January–February 2026, reaching approximately 68 GW of total installed photovoltaic capacity — second globally in new solar additions in 2024.

Utility-scale additions more than doubled year-on-year as distributed generation fell 37%, reflecting a structural shift toward larger centralized projects. Wind capacity stood at approximately 29.6 GW onshore by end-2025, with wind generating 107.7 TWh in 2024 (a 12.4% annual gain).

The offshore wind sector remains pre-commercial but carries extraordinary potential: IBAMA is reviewing 104 projects with combined capacity exceeding 247 GW, against a World Bank technical potential estimate of 1,200 GW.

The Contradiction: Renewables Leader and Fossil Fuel Expander

Brazil hosting COP30 while simultaneously approving new deepwater oil frontiers and Amazon gas block tenders encapsulates the dual-track dilemma facing Latin America’s largest economy. DNV’s Energy Transition Outlook for Latin America describes the region’s fundamental paradox: the highest renewable electricity penetration of any global region (60–70%+ from clean sources), yet the highest oil share in primary energy supply (40%), with fossil fuels meeting 91% of transport energy needs.

Oil demand in transport will not peak until 2050 on current trajectories, per S&P Global’s regional forecast. The tension is not merely rhetorical — it shapes billions in investment decisions, bilateral climate negotiations, and the terms on which external capital enters the region.

Oil Price Outlook and What It Means for LatAm Fiscal Positions

Before February 28, 2026, major institutions were broadly bearish on oil: the EIA projected Brent averaging around $73/bbl for the year; J.P. Morgan held a sub-$60 view based on expected supply surpluses.

The Iran war invalidated those frameworks. Post-crisis revised consensus from April 2026 shows the EIA at $96/bbl for full-year 2026 (up from $78.84), Goldman Sachs at $85/bbl (raised $8 from its prior forecast), HSBC at $80/bbl, and ANZ projecting prices above $90 through mid-year before easing, per Reuters analyst surveys.

Goldman Sachs noted that if the Hormuz disruption proves structural rather than temporary, Brent could remain above $100 for years, according to Reuters.

For Latin American fiscal balances, the divergence is sharp. Net exporters — Brazil, Argentina, Guyana, Venezuela, Colombia — benefit on current accounts, royalty collections, and state company earnings.

Net importers — Mexico on refined products, most of Central America, and the Caribbean — face subsidy pressure and inflationary pass-through. Mexico’s position is particularly complex: it earns export revenue on crude but must import significant volumes of refined petroleum products, activating IEPS subsidy mechanisms that can offset crude export windfalls.

The sustained high-price environment also strengthens the investment case for every capital commitment in Vaca Muerta and Guyana that was originally modeled at $60–75/bbl break-even costs.

Deep Dive

For the complete picture, see our guide: Oil and Energy in Latin America 2026.