Gabon Hydrocarbons Code Bets on Zero Bonus to Offset Falling Oil

Gabon’s oil output slipped to about 207,000 b/d in July 2026, down from roughly 227,000 b/d across 2025. Yet the proposed fiscal terms for ultra-deepwater blocks, a central plank of the new Gabon hydrocarbons code debate, would ask investors to pay nothing upfront.

That looks like a state giving away revenue it badly needs. The design is more deliberate than that.

David Parkinson, Wood Mackenzie’s vice president for upstream operations, presented a profitability-linked model at African Energy Week in Cape Town yesterday. The new Petroleum and Gas Codes, which split up the 2019 framework, have still not been enacted as of mid-October. Memoranda of understanding (MoUs) with BP and ExxonMobil have not yet become production-sharing contracts (PSCs).

Here is how to judge whether this fiscal design can credibly replace declining barrels, and which signals tell you if Gabon is serious.

Why is Gabon betting on ultra-deepwater terms now?

The output trend

The numbers move in one direction. Gabon averaged about 227,000 b/d in 2025, slipped to around 222,000 b/d in June 2026, then fell to roughly 207,000 b/d in July, with similar levels reported for September.

The Directorate General of Economy and Fiscal Policy put Q1 2026 oil output down 8.7% year on year. The World Bank linked part of that slide to technical incidents and maintenance stoppages, but the deeper cause is maturing fields and ageing infrastructure.

Its 2026 Public Finance Review records a 17% production fall between 2000 and 2023, with a further 2-3% annual decline expected from 2026. Outages explain the bad months; geology explains the trend.

The budget assumptions

The draft 2027 Finance Bill, adopted on 18 September 2026, projects oil revenue down 9% to CFAF 1.013 trillion (about US$1.77-1.8 billion) at an assumed $70/bbl, against $80/bbl for 2026.

Then comes the quiet assumption. The bill expects output to rise 4.1%, from 10.80 million tonnes in 2026 to 11.30 million tonnes in 2027.

What this tells you is that the 2027 revenue target is exposed to a shortfall. Deepwater replacement barrels are still at MoU, appraisal or negotiation stage and are years away, which explains why the state is willing to rethink what it charges explorers.

Gabon’s code rewrite sits within a wider wave of regulatory reform across Africa, where governments are rebalancing fiscal terms, licensing rules and institutional oversight to compete for scarce exploration capital.

How does the proposed R-factor model work, and what does it change?

The signal is the missing bonus. A signature bonus is a one-off payment a company makes to the government when it signs a PSC. Wood Mackenzie proposes scrapping it for ultra-deepwater blocks while keeping a 19% royalty, which is a share of the value of oil produced, paid to the state from the first barrel.

The state is also guaranteed at least 20% of profit oil. Profit oil is the oil left after the company has recovered its investment costs, and the state’s share of it rises as the project becomes more profitable.

Production-sharing contract structures allocate cost recovery, profit oil and risk between state and operator in very different ways, which is why the absence of a signed PSC leaves Gabon’s proposed terms untested against any real project.

How the mechanism works

R-factor: a ratio of a project’s cumulative revenue to its cumulative cost, used to set how much profit oil goes to the government.

When a project is new and still spending, the ratio sits low and the state takes its minimum share. As revenue catches up with and then exceeds cost, the ratio climbs through set tiers and the government’s share steps up.

The Society of Petroleum Engineers (SPE), in a 2026 analysis, describes how this lifts the government share automatically as investment is recovered, with no new law or contract renegotiation required. That automatic step-up is the core attraction.

Why drop the bonus

The case for removal rests on four points:

1. The bonus is due before any commercial discovery, so it is paid even on a dry block.
2. It can deter exploration by loading costs onto the riskiest stage, according to the SPE.
3. The state may capture more over decades through royalties, profit oil, taxes and local activity.
4. Deepwater, ultra-deepwater and mature-field work carry very different risks, so one upfront fee suits none well.

Wood Mackenzie counts 26 available blocks in Gabon, mostly onshore and shallow water. One caveat: Parkinson’s full presentation was not publicly accessible, so these figures come from Ecofin’s reporting.

For you, the shift is simple. The state swaps certain but small upfront cash for larger but conditional later payments, so the model’s value depends entirely on projects reaching payback.

What could undermine the model, and where do the BP and ExxonMobil contracts stand?

On paper, the design balances both sides neatly: a lower entry cost for explorers, a royalty floor for the treasury, and a rising share once profits arrive. The trouble sits in the details still unresolved.

Fiscal and cost-recovery risk

If costs run high, production slips or the R-factor tiers are never reached, the state could collect less in the near term than it would under a bonus-heavy system. The 19% royalty cushions that risk without removing it.

The bigger technical weakness is the definition of “cost”. Drilling, subsea equipment, floating production, logistics and decommissioning may all be recoverable, and weak auditing could keep the state stuck in a lower tier for longer. The SPE flags cost-recovery oversight as a common deepwater problem.

The World Bank has already warned that Gabon receives fewer resources per barrel than several regional peers, and that contractual flexibility may be eroding the state’s share. An R-factor regime only works with:

• reliable production and cost data
• independent audit
• a capable regulator
• clear dispute resolution

Contract and legal transition

Drafts of the Petroleum and Gas Codes were reportedly received in March 2026, but the 2019 Code remains operative. In April 2026, Oil and Gas Minister Clotaire Kondja said the MoUs should become PSCs within four to six months. No completed PSC had been reported by mid-October.

Gabon is also reported to be weighing a cut in Gabon Oil Company‘s carried interest from 20% to 10%, though this has not been independently confirmed.

Treat the absence of signed PSCs as the real test. Until a binding contract embeds these terms, the fiscal model remains a proposal.

What does Angola’s 2018 reform teach Gabon?

Angola’s playbook

Angola is the obvious regional reference, and its fiscal changes were only one part of a longer sequence. Presidential Decree No. 6/18 of 18 May 2018 cut petroleum production tax from 20% to 10% and petroleum income tax from 50% to 25% for fields under 300 million barrels or held back by infrastructure.

The institutional work went further. Angola created the ANPG as upstream regulator and concessionaire in 2019, set up the IRDP, restructured Sonangol and replaced sporadic rounds with a 2019-2025 multi-year licensing programme. It added Risk Service Contracts, incremental production incentives, a Marginal Field Law and a Gas Monetization Law.

The Sonangol restructuring and the creation of a separate regulator were the institutional half of Angola’s reform, and they arguably mattered as much to investor confidence as the tax cuts did.

The result was stabilisation, not growth. Output steadied near 1.1 million b/d, well below its 2008 peak of about 1.87 million b/d, and crediting reform for that is the African Energy Chamber’s framing.

Other comparators

Guyana and Nigeria show how fixed terms age badly.

Gabon’s mature fields are expected to shrink 2-3% a year, so brownfield incentives matter too. The read you should take is that Gabon’s outcome hinges on regulator strength and mature-field policy as much as on deepwater terms.

What to watch as the code is finalised, and what the proposal cannot fix

The R-factor model improves frontier economics and gives the state a revenue floor. It does not reverse near-term decline, because any deepwater barrels are years away.

Your watchlist as the Gabon hydrocarbons code moves forward:

1. Enactment of the Petroleum and Gas Codes
2. Conversion of the BP and ExxonMobil MoUs into PSCs with published terms
3. Cost-recovery and audit rules
4. Treatment of existing contracts
5. Any brownfield incentives

Recheck the unverified items, including the GOC carried-interest cut and the BP MoU date, before relying on them. The decision point is whether signed contracts match the design.

Investors exploring whether gas can offset falling crude will find our detailed coverage of Gabon’s gas projects useful for its look at infrastructure progress and development timelines.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions. Past performance does not guarantee future results. Financial projections are subject to market conditions and various risk factors.