In December 2023, Angola stunned global energy markets by announcing it would leave OPEC after 16 years of membership. The decision followed months of tension over production quotas. Angola had been assigned a daily output cap of 1.1 million barrels of oil – far below what Luanda considered fair. At the time of its withdrawal, however, Angola’s production had already collapsed by almost 40% in 8 years, sliding from 1.7 million b/d to 1.1 million b/d. The decline owed less to OPEC than to geology and high government intake: mature fields were running dry, and new investment had slowed.
Hopes that leaving OPEC would allow a resurgence quickly faded. The government stopped publishing official output figures after November 2023, just weeks before its departure became effective in January 2024, but exports tell the story. Because Angola refines very little oil domestically (with only one operational refinery of 60,000 b/d capacity) and all of the production is offshore, seaborne shipments mirror total output. In 2022, the last year of full reporting, the gap between exports (including deliveries to the Luanda refinery) and overall production was barely 25,000 b/d, and exports have hovered around 1.1 million since 2021. Freedom from quotas brought no boost in output, the volumes remained flat.
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The main reason is straightforward: Angola’s producing wells are simply running out of oil. The already developed fields are old, and modest discoveries over the past decade have not offset depletion. Of the country’s 20 largest fields, only 5 remain below 70% maturity. The flagship Block 15 Kizomba complex operated by ExxonMobil produces about 200,000 b/d but is 85% depleted. The second largest TotalEnergies’ Kaombo project in Block 32 (around 150,000 b/d) is around 60% mature. With decline rates high and reservoirs getting dry, Angola’s structural problem is in large part geological, not political.
Naturally, Angola’s oil story is far from over. Numerous offshore blocks are still undeveloped, and exploration in others has barely started, sustaining the interest of international operators. The upstream industry remains dominated by a few big players: Azule Energy – a joint venture between BP and Eni formed in 2022 – has become the country’s largest producer, accounting for around 230,000 b/d. Sonangol, the state-owned oil company, ranked second with roughly 200,000 b/d, while ExxonMobil continued to run the vast Kizomba complex in Block 15, and TotalEnergies maintained a broad oil-and-gas portfolio across several deepwater blocks.
Yet even as these companies have kept Angola’s oil flowing, their investments have been shrinking – and this time the maturity of the fields is not a full excuse. The country’s Production-Sharing Contracts (PSC) imposed a heavy government take – high royalties, rigid cost-recovery limits, and steep profit-oil shares that left international operators within margins. For years, the fiscal structure spoiled enthusiasm for drilling new wells or redeveloping mature fields. By 2024, policymakers in Luanda had come to a clear realization: the problem wasn’t OPEC – it was Angola’s own tax regime.
In November 2024, the ANPG (the National Oil, Gas and Biofuels Agency, Angola’s state oil regulator) introduced the Incremental Production Decree, a measure designed to attract capital back into mature offshore blocks and undeveloped areas. The new rules cut royalties to 15% (from 20%), capped ANPG’s profit-oil share at 25%, raised the cost-recovery ceiling to 70% of production, and even allowed companies to recover exploration costs from unsuccessful wells. Acreage now had to be classified as “mature” or “undeveloped,” ensuring incentives targeted aging assets. These changes, rather than Angola’s exit from OPEC, finally shifted investor sentiment.
The results came quickly. In September 2025, Chevron signed a risk service contract (RSC) for Block 33 in the Lower Congo and Kwanza Basins, a block previously relinquished by ExxonMobil and TotalEnergies after only minor discoveries. Earlier that year, TotalEnergies brought its Clov Phase 3 project onstream, adding 30,000 b/d and explicitly crediting the improved fiscal environment. ExxonMobil and Azule Energy both expanded their existing leases under the new regime: Exxon’s Block 15 was redrawn to include the Mbulumbumba, Vicango, and Tchihumba fields — small accumulations that can be tied back to the Kizomba FPSO — while Azule Energy secured a similar revision in Block 31. The friendlier investment climate even lured Shell back to Angola after a 20-year absence, with a preliminary deal to explore Block 33 signed in September 2025. New entrants followed: London-based Afentra PLC — short for Africa Energy Transition — acquired stakes in Blocks 3/05 and 3/05A and plans to revive onshore production in the Kwanza Basin that has been dormant since the civil war (1975-2002).
These deals mark a relative success for Luanda’s post-OPEC strategy: Angola has regained the attention of major operators while attracting smaller independents able to work with tighter margins. But the nature of the progress underscores the limits of its upstream recovery. The new activity is not focused on large discoveries or frontier basins, but on re-tapping overlooked assets and prolonging the lives of fields already deep into decline. Angola may have won back the right to pump as it pleases — yet it is largely using that freedom to scrape the remaining barrels from aging reservoirs.
Little progress on the downstream side gave producers even less reason to boost domestic crude supply. For decades, Angola had only one functioning refinery – the 65,000 b/d Luanda plant operated by Sonangol – and a small Chevron topping plant in Cabinda. The new Cabinda refinery, a joint venture between Gemcorp (90%) and Sonangol (10%), began commissioning in September 2025 after long delays. Commercial operations are expected by the end of 2025, with an initial 30,000 b/d phase focused on diesel, which represents about 60% of local fuel demand. A second phase planned for 2028 is set to double capacity and add gasoline production, meeting another 25% of domestic needs. Two larger greenfield projects – the 200,000 b/d Lobito refinery and 100,000 b/d Soyo plant – remain stuck in financing and ownership disputes, with construction yet to begin.
Two years on, Angola’s OPEC exit looks less like a bold strategic move and more like a symbolic gesture. Production remains flat; exports have not risen; and the decline of mature fields continues. Ironically, the only real progress – fiscal reform, renewed exploration interest, and new contracts – arrived after the exit, but for reasons unrelated to OPEC. The decisive change was not breaking with the oil group but rebuilding investor confidence through domestic policy.
Yet even as Luanda tries to chart its own course, the timing could hardly be worse. In addition to the maturity of its aging oil fields and persistent challenges in attracting fresh investment, Angola now faces a global market awash with crude. Accelerating non-OPEC shale and offshore output from the Americas – unrestrained by OPEC discipline – has pushed excess supply that is expected to exceed demand through at least mid-2026. For lack of large-scale developments, the average breakeven cost for Angolan deepwater offshore oil production is higher than that of Guayana and Brazil (US$40 against US$30-35 per barrel). Because of this the higher-cost producers willing to operate in the Angolan waters are being squeezed, and hopes of a meaningful production rebound are fading.
Thus, Angola’s difficulties are both internal and external – a mix of geological decline, investor hesitation, and adverse global market dynamics. The result is a perfect storm of bad timing and bad luck. Leaving OPEC, far from delivering independence, has so far given Luanda little more than autonomy over stagnation.
By Natalia Katona for Oilprice.com
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