A long-term shift by oil majors towards deep offshore African oil exploration raises new challenges for indigenous African producers which have yet to be fully addressed.

The flight to deep offshore exploration is the result of a “long strategic view” by the majors, says Kaase Gbakon, who spent 15 years in technical and strategy advisory roles with the Nigerian National Petroleum Company (NNPC). In Nigeria, the political environment has made operations in onshore and shallow waters of the Niger Delta risky, he says. Emerging African producers such as Namibia, Senegal and Mozambique have also seen the majors set up offshore.

The fiscal terms applicable to deepwater oil production have been attractive relative to those available in shallow water and onshore, Gbakon says. Ever-tighter ESG standards prompted by climate change and energy transition considerations also play their part. By divesting onshore/shallow assets, the majors can “wash off legacy environmental issues from their portfolios and look ‘carbon-clean’”.

Remote placement of assets away from direct interaction with host communities removes a layer of stakeholder engagement, Gbakon argues. Even well-established environmental groups opposed to oil development find it costly and dangerous to mount physical disruption of deep-water production, he says. “This march by the IOCs into deepwater is inevitable – the strategic imperatives are unassailable.”

A consequence for African-producing countries, he says, is increasing costs to develop the infrastructure needed to deliver the energy for domestic use onshore. “This will pose a barrier to economic growth and may instead incline the affected governments to simply rely on the tax dollar inflows without dedicating the needed effort to connect energy development to economic growth.”

Decommissioning challenges

Fiscal terms for deep water tend to be designed to incentivise the majors to develop assets. So tax dollar flows to governments might suffer delays and depressed levels while investors recoup their outlay, Gbakon says.

This, he says, may help explain why Senegal is already calling for a review of offshore fiscal terms. In the case of Nigeria, he says, the benefit to the domestic players is that they can further develop local oil industry capacity. However, the government may come under pressure to provide incentives as the domestic players argue they are developing the assets in the “national interest”.

“This appeal to a sense of nationalistic duty, if entertained, will cost the government in forgone and/or delayed revenues,” Gbakon says. The Nigerian government will also have to work with new owners on how to bear the burden of environmental cleanup, with the government “inevitably taking a financial hit”.

Oil exploration in Africa has seen a strategic shift which is still in its early days, says Tullow Oil CEO Rahul Dhir. Tullow has producing assets in Ghana, Gabon and Côte d’Ivoire, and a resource base in Kenya. “Our destiny is mid- to late-life assets,” Dhir says. “We do what the majors don’t. We occupy the white space that the big boys leave behind.”

Dhir agrees that the end-of-life decommissioning of oil assets has yet to be fully addressed. The skills needed are in short supply, both in Africa and globally, and there isn’t a formal mechanism for knowledge transfer on how to manage such assets, he notes.

Tullow and its joint venture partners in April agreed to establish a decommissioning fund for the Jubilee Field offshore Ghana.

Dhir sees grounds for optimism in West Africa in that governments and regulators have become better informed on the issue, including increased cooperation and knowledge between different regulators. But the issue of funding for decommissioning also needs to be tackled, Dhir argues. “Governments are saying ‘I need to see the money’” for decommissioning plans.

Afentra in Angola

No one knows when peak world oil demand will be reached, but Oxford Economics has forecast that it may be as soon as 2027. Oil majors are likely to continue to replicate the pattern seen offshore the UK in the North Sea by gradually vacating mature African fields, says Paul McDade, CEO of Afentra. The majors have “pretty much exited the North Sea” over the last 20 years, McDade notes.

Afentra’s strategy is to build a portfolio of mid-life-producing assets that no longer fit the portfolio of the majors. The firm, which trades on London’s Alternative Investment Market (AIM), entered Angola in May 2023 and has a 30% non-operated interest in the offshore Block 3/05. The block represents a resource of about 3.5 billion barrels, of which about 40% has been recovered. It has “huge potential” and production there has increased by about 30% since early 2023, McDade says. Afentra is working with state-owned Angolan oil company Sonangol to increase output from the block to above 30,000 barrels per day (bpd), and there’s potential for output of 40,000 bpd, McDade says.

Nigeria, McDade says, is much more developed than Angola in terms of local capacity.

Angola’s largest private oil company is Etu Energias, formerly called Somoil. The company has a strong track record, but beyond that, there is “limited” technical and financial capacity among local players, McDade says. He’s keen to work with smaller Angolan companies to facilitate knowledge transfer. “There’s a need to create more local champions.”

McDade is also discussing plans to export gas from the block with Sonangol. Moves by Angola to start exporting gas are an important development,  he says. “A leg of Angola’s future is putting more emphasis on gas.”

Afentra was established in 2021 through a restructuring of Sterling Energy, an AIM-listed cash shell. One asset that Afentra may be willing to sell is in Somaliland, where the company has a 34% carried interest in the onshore Odewayne Block. This was inherited as part of the cash shell. The interest doesn’t cost Afentra anything to hold, but the company “could look at divesting it,” McDade says. “We’re looking to rationalise that asset.”

Higher production imperative

In Angola, according to research from BancTrust & Co, prospects for increased oil production are “underwhelming” due to “years of underinvestment”. Nigeria, BancTrust says, has a clearer path to higher production. Nigerian indigenous players are by no means hemmed in with purely short-term assets.

Gbakon notes that Oando and Seplat both hold assets that can sustain production for well over 20 years. Even so, he says, there is a risk of constrained growth if the companies are unable to expand their reserves or fail to produce at anticipated levels.

As assets age, maintenance costs will increase, and indigenous players also face costs for mitigating above-ground security risk and procuring the “social licence” to operate, Gbakon says. “Ultimately the indigenous players cannot rest on their wins. They must increase their reserves relative to production even if it means venturing out of the Niger Delta.”

That means becoming cost-efficient producers, showing diligence in meeting their fiscal obligations, and strengthening governance processes, he says. Delivering projects jointly with other African players and building international synergies and partnerships will help with financing, technology access, risk sharing and adoption of best practices.

Indigenous players, Gbakon says, must build robust portfolios across the oil, gas and power value chains, and need to pursue vertical integration. “Governments also have a role to play in ensuring a hassle-free regulatory process that sees approvals for major strategic steps granted speedily.”