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African E&P: out of adversity comes opportunity

In exclusive interview with AfrOil, an Africa oil patch veteran discusses his views on the short-term outlook for the continent’s E&P industry as we navigate the energy transition.


What: Drilling activity throughout Africa is down more than 40% year on year and investment decisions have been held up amid a struggle for capital allocation.

Why: Listed oil and gas firms are faced with the challenge of an increasingly ESG-savvy investor base that has already brought about strategic change at some of the world’s largest companies.

What Next: As investors grow ever more cautious about hydrocarbon investments, African E&P is experiencing an existential crisis, but this presents significant opportunities for those less encumbered by the green revolution.


The oil and gas industry has rebounded somewhat since the start of 2021 with prices rising relatively steadily and giving the appearance of stability. However, despite the best efforts of OPEC+, concerns about demand have persisted as new variants of coronavirus (COVID-19) and a patchy vaccine roll-out continue to cast clouds of doubt over the anticipated recovery.

Meanwhile, the unprecedented shift among consumers and investors towards lower-carbon energies that has sped up over the last 18 months poses a particularly significant challenge for the development of hydrocarbon resources in Africa, where high risk/high reward extractive sectors have long appealed to listed European companies that are now radically altering their strategies. This has seen some IOCs with large African footprints, including BP and Kosmos Energy, shift their attention away from traditional exploration towards lower-carbon, short-cycle, value led projects respectively.

These factors have led to a widespread shake-up of African E&P, and as Eskil Jersing, business development advisor at newly formed Eburon Resources, told AfrOil this week, this is creating a multitude of opportunities, as long as you have funding and “belief in the ability to overcome control and pace issues that have often hampered activity and success this last decade”.

Jersing, who previously managed E&P assets and led new business teams for Africa at Wentworth Resources, Sterling Energy, Marathon and Petrobras, said: “Upstream is at a critical crossroads, with a number of African economies in contraction due to COVID-19, final investment decisions (FIDs) and project start-ups at multi-decade lows, in part due [to] strategic refocusing of IOC portfolios to meet transition priorities.”

For its part, Eburon anticipates that underinvestment in conventional exploration will contribute to a material hydrocarbon supply gap in the coming decade, presenting a challenge to an orderly energy transition. The company is building a diversified exploration portfolio of non-operated, minority working interests in drill-ready prospects through targeted and data-driven farm-ins.



According to Wood Mackenzie, total sub-Saharan African (SSA) M&A deal spend dropped to $1.1bn in 2020, down from $5.7bn in 2019. In parallel, data from Baker Hughes shows that the number of drilling rigs active in April was down 41% year on year.

Just 61 rigs were active onshore and offshore Africa last month, compared with 103 in April 2020. Of these, 39 were located in Libya and Algeria, with five or less each in Angola, Cameroon, Chad, Gabon, Ghana, Kenya, Mozambique, Nigeria, Ethiopia and Djibouti.

Fiscal hesitancy also saw four projects, accounting for 400mn barrels of oil equivalent (boe) of reserve additions, moved to a 2021 start-up – Nene Marine (Phase 2b) in Congo (Brazzaville), CLOV (Phase 2) in Angola, Hassi Bir Rekaiz (Phase 1) in Algeria and Oryx in Chad.

Meanwhile, Jersing added that just three planned project FIDs – for Block 32 & Agogo in Angola, plus Cameroon’s Etinde – “comprise 50% of potential reserves additions and 70% of capex spend”.

As access to capital continues to become trickier, he adds that many higher cost/carbon intensity projects are likely to be delayed or stranded with overarching public market driven ESG requirements influencing capital allocation, noting that those with breakevens above $40 per barrel are particularly under threat.

“Continued project delays are likely to limit production increases and lead to the lowest reserve additions since the early 1980s and around 50% lower than in 2015,” Jersing said.

However, there is light at the end of the tunnel, with economies expected to rebound quickly during the second half of the year despite debt vulnerability and limited fiscal flexibility slowing the pace of the recovery for some. Jersing notes that “those countries with an ‘open for business’ approach, stability and bureaucratic flexibility such as Namibia, South Africa, Egypt, Angola, Equatorial Guinea, Gabon, and more recently Uganda and Tanzania, should do better in terms of progressing their oil and gas agendas than their peers”.

The willingness of host countries to adapt to this new reality is also likely to play a significant role in their success.

Jersing sees continued fiscally regressive operating environments as “the single most challenging risk on the continent”. With fewer companies focusing on a smaller top quartile producing barrel opportunity set owing to a lack of capital in the system, the “question is: how much pressure due [to] lack of spending will catalyse fiscal changes/stability sufficiently to re-attract capital in E&P?”



As investors come under increased capital allocation scrutiny, they will likely focus on higher margin, infrastructure-led exploration (tiebacks) and phased developments with shorter cycle times in more ‘liquid’ and stable jurisdictions primarily onshore.

Licensing rounds are expected to close in Angola, Egypt, Liberia and Senegal between May and August, while numerous other countries will continue to pursue direct negotiations for available acreage. Jersing notes that only a few of these are likely to “be successful due [to] acreage quality, risk of stranded long-cycle assets and lack of discretionary capital in the system”.

Those he views as more likely to enjoy success are Egypt, which continues to benefit from sustained activity, a flexible fiscal environment, subsurface success and asset churn; and if held, Senegal protection acreage adjacent to the Grand Tortue Ahmeyin LNG blocks. Liberia’s regulatory flexibility is unlikely to counter a lack of overseas interest in the Harper Basin blocks, though seven domestic firms have been pre-qualified. Resource materiality will likely be a limiting factor in Angola’s onshore. Offshore Angola has, however, recently witnessed a novel joint venture tie-up between BP and Eni, in order to efficiently harvest mature Upstream assets. It is likely that IOCs will look to duplicate this innovative commercial approach elsewhere on the continent. With regards to Gabon’s 23 open deepwater blocks, existing gas condensate discoveries will need to find viable monetisation solutions to encourage further interest in the basin.

Exploration success in the second half of the year is likely to be determined by the results of a few key high impact offshore wells that are expected to spud, including Total’s Ondjaba in Angola, and Venus in Namibia; Petronas’ Jove Marine in Gabon and Azinam’s Gazania in South Africa.

Jersing notes: “Should Venus be a material liquids success outcome, there will likely be a Namibian frenzy by incumbent players in the Orange river basin to unlock dependent upside and running room.”


Changing of the guard

Meanwhile, as some majors reduce their exposure, Wood Mackenzie estimates that more than 40% of BP, Chevron and Equinor’s remaining capex focuses on mature, non-core fields, and will be largely spent on decommissioning.

At the other end of the scale, France’s Total “with major stakes in East Africa will seek to continue to press ahead with geopolitical oversight and host government engagement, to keep momentum going”, according to Jersing.

In addition to its major upstream projects in Kenya, Uganda and LNG Mozambique – currently under force majeure – through two offshore high-impact wells – Ondjaba and Venus – due to spud this year, Total remains “the key material frontier explorer along with Eni, CNOOC and, [to a lesser extent] [Royal Dutch] Shell on the continent”.

Meanwhile, as BP appears likely to sell its Algerian assets, Oxy continuing to sell out of Ghana, ExxonMobil looking to exit Chad, Block B in Equatorial Guinea, some of its Nigerian assets and Block 2 in Tanzania, and Eni heading for the exit in Congo (Brazzaville), Jersing believes “the challenge will be finding buyers.”

This changing of the guard will require “smaller, less strategically constrained and more agile operators [like Assala Energy, Trident Energy and others] who can compress timelines and lower breakevens through agile and lean operating models,” he added.

Jersing notes that newer players such as Carlyle-backed Boru Energy and more recently Afentra with its ex-Tullow leadership are focused on West African ‘flowing barrels’ assets, with the latter saying last week that it intends to pick up “material production [of] multiple tens of thousands” of barrels per day.

Despite the challenging outlook, Jersing remains confident about the future of African E&P, concluding: “Capital is amoral and will always continue to chase the best margins; as resource holders become more fiscally welcoming to life-cycle investment win-wins, the tide will turn.”

Speaking to AfrOil on condition of anonymity, several fund managers said that while the need for investment in low-carbon and renewable energy is warranted, the about-face from oil and gas risks “throwing the baby out with the bathwater” and public funds will likely lose significant ground to private equity.

Meanwhile, as governments compete for investors and majors continue to shed assets, there are likely to be numerous opportunities for those with cash on the hip or PE backing to pick up bargains.


Ian Simm is principal advisor at consultancy IGM Energy and collaborates with companies throughout the energy value chain on asset marketing, due diligence and strategy.