Guyana and Senegal have been major success stories for deepwater exploration in recent years.

In a bid to better reflect the sector’s prospects for growth, the governments of both countries plan to revise the fiscal regimes governing the upstream industry before new licensing is introduced.

Companies acquiring new exploration acreage in the coming years are likely to operate under more taxing terms than current license holders, emphasising the importance of early entry in emerging oil and gas provinces.

Senegal oil and gas

In Senegal, the government has drafted a new petroleum code it plans to pass into law before presidential elections in February 2019. The imposition of a royalty and changes to cost recovery and profit oil terms in the draft code mean that the government will receive a minimum of around 20% of revenue from deepwater oil projects. This is in addition to income tax and revenues from Petrosen’s (the Senegalese national oil company) interest.

Using the first phases of the Liza and SNE developments as scenarios under which to compare regimes, returns under the new terms would be lower than under the regimes of established deepwater producers such as Ghana and Brazil. But, these developments still appear more attractive than those offered in Angola, Nigeria, Equatorial Guinea and the Republic of Congo.

However, the high effective royalty has a considerable effect on the breakeven price. Under the new terms the Liza scenario’s breakeven price increases from US$31/ barrel (bbl) to US$34/bbl and the SNE scenario breakeven increases from US$43/bbl to US$49/bbl. While projects of this scale may still be able to move forward, similar effects may prevent the development of more marginal discoveries.

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The initial rate of return (IRR) of the Liza and SNE development scenarios under the South Atlantic Margin Regimes, at US$60/bbl


Source: Upstream Economics, GlobalData oil and gas

Guyana oil and gas

As Guyana looks to develop its new model Production Sharing Agreement, the government will have to address this trade-off between government revenues and investment attractiveness.

One option could be to adopt a progressive mechanism which increases the state’s share of profit oil from the standard 50% as the R-factor (the ratio of cumulative revenues to cumulative costs) increases. This could achieve a significant increase in discounted state take (73% to 81% for the Liza scenario and 61% to 73% for the SNE scenario) while limiting the increase in breakeven price to less than US$1/bbl in both cases.