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By Adeniyi Adeoloye

French President Emmanuel Macron is the latest high-profile figure among a growing number of stakeholders calling for a pause in the implementation of the Article 28 of the European Union (EU) Methane Regulation, joining the United States and a group of EU member states that have already backed a delay.

Barring any postponement, the requirement under Article 28 of the EU Methane Regulation for importers of crude oil, natural gas, and coal sourced from outside the EU to demonstrate and report Monitoring, Reporting and Verification (MRV) equivalence will take effect on January 1, 2027.

The provision seeks to ensure that imported fossil fuels meet the same methane MRV standards as those required of producers within the EU.

Under Article 28, effective January 1, 2027, importers of crude oil, natural gas, and coal from outside the bloc whose “contracts concluded or renewed on or after 4 August 2024” will be required to demonstrate and report MRV measures equivalent to those required within the EU. In contrast, for contracts signed before August 4, 2024, importers are only required to “undertake all reasonable efforts” to ensure the imports are subject to MRV measures established under the regulation.

There are two paths to demonstrating MRV equivalence under the regulation. Producer level and the exporting country level. Regardless of the route chosen, certain conditions need to be met for equivalence to be recognised. Under the producer level route, methane emissions measurement is required at source and site level, and must be verified by a third party. For crude oil and natural gas, monitoring and reporting established at the Oil & Gas Methane Partnership (OGMP) 2.0 level 5 reporting is also considered sufficient to meet the equivalence requirement. OGMP is a United Nations Environment Programme (UNEP) led initiative for methane emissions disclosure and mitigation in the oil and gas industry through a global reporting framework based on direct measurements.

At the country level, equivalence requirement can be met where an exporting country has an MRV regulatory framework that applies to producers and exporters supplying crude oil, natural gas or coal to the EU market and that is at least equivalent to the EU requirement. Such a framework must provide for source and site level quantification, regular reporting, independent verification, effective regulatory oversight, and compliance mechanism.

While the onus is on the importer to provide the required documentation to the competent authority in an EU member state, the underlying information would originate from the producer.

The regulation does not prohibit imports that are not compliant with its requirements. However, such volumes may become subject to fines and penalties.

Whether or not the pause for implementation materialises, African hydrocarbon producers exporting to the EU cannot construe it as a green light for inaction.

For many African producers, the Article 28 requirement and its January 2027 implementation date are not merely an academic exercise. They could become a market access issue, given the substantial exposure of some of the major continent’s major hydrocarbon exporters to the EU market. Any disruption to these trade flows could have implications beyond individual producers, particularly for countries where oil and gas revenues make a significant contribution to government finances.

The degree of exposure, however, varies from country to country. Data from the National Oil Corporation (NOC) of Libya’s 2025 Annual Report Technical and Statistical shows that about 79% of the NOC share of production exports, which reached 342Million barrels in 2025, went to the European market. Of this volume, EU member states received the majority. Italy accounted for 137.6Million barrels (40.2%), France 26.482Million barrels (7.7%), and the Netherlands 22.742Million barrels (6.6%), while Greece, Germany, Romania, Croatia, Sweden, Bulgaria and Poland account for the remainder.

Data from the United Sates Energy Information Administration (EIA) shows that Algeria exported 402,000 barrels per day of crude oil in 2024, of which 73% was shipped to Europe. France accounted for 21% of exports, Spain 12%, and Germany and Portugal 7% each, while the remainder went to other European destination. Algeria exported 1.9Trillion cubic feet (Tcf) of natural gas in 2023, out of which 90% went to Europe. Of this, 672Billion cubic feet was exported as LNG and 1.2Tcf through pipeline. According to the data from the Energy Institute, France received 30% of exports, Italy 12%, Turkey 32%, and the remained was shipped to other European markets.

Data from the Vanderbilt Terminal for Angola’s Oil & Gas Industry shows that EU member states accounted for about 14% of Angola’s 1.05Million barrels per day (BOPD) of crude oil export destination in 2024. Spain led the pack with 45,000BOPD (4.3%), followed by France with 38,000BPD (3.6%), Italy with 35,000BOPD (3.3%), the Netherlands with 18,000BOPD (1.7%) and Portugal with 12,000BOPD (1.1%).

EIA data also shows that Nigeria, Africa’s largest oil producer exported 1.3MillionBPD (1.3MMBPD) of crude oil and condensate in 2024. Of this volume, 622,000BPD (48%) went to Europe. France received 128,000BPD (10%), Spain 153,000BPD (12%), the Netherlands 7%, while 20% was exported to other destinations across Europe.

It can be deduced from the data above that Algeria, Libya, and Nigeria are particularly exposed to the implementation of Article 28, given the share of their hydrocarbon exports that flows to the EU market.

Given the current state of the oil market, particularly in the aftermath of the Russia-Ukraine conflict, and the ongoing tensions between the USA and Iran, it is understandable why some countries and stakeholders are calling for a delay. Perhaps it is not lost on those calling for a pause that the implementation of Article 28 could leave European buyers facing limited supply alternatives, particularly if a significant share of the current import is unable to meet the equivalence requirements. The pertinent question now, is what becomes of the exposure risk to the EU market once the supply constraints created by current geopolitical disruptions begin to ease and there is no postponement of the MRV compliance implementation.

Understandably, the implications of the implementation cut both ways, affecting exporting countries as well as the importing market. This is illustrated by Wood Mackenzie’s research conducted in mid-2025, which found that none of the countries “exporting gas/LNG or crude oil to the EU” currently meets the “country-level equivalence requirements” under the EU Methane regulation. Wood Mackenzie study assumes the producer level equivalence “and the ability of importers to identify the upstream producers” will likely determine the volumes of hydrocarbon that meet the requirements of the EU market. The Wood Mackenzie study further indicates that, under its Default Scenario, the non-compliant volume to the EU market could hit about 43% (4Trillion cubic feet) for natural gas, and 87% (9.8MMBPD) of crude oil by 2027. According to the study, the resulting supply constraints could significantly affect the EU refining industry, tighten fuel markets, and contribute to higher gasoline and diesel prices.

The implications for producers in African countries may not be uniform. However, International Oil Companies (IOCs) are better positioned to meet the MRV requirements, owing to their deeper technical capabilities and the reputational expectations of investors and stakeholders in their home countries. National oil companies and indigenous independent producers may face greater compliance challenge, particularly where in-country regulatory frameworks, technical capacity, and MRV systems are not well developed. Although companies such as Shell, bp, Chevron, ENI, ExxonMobil, Equinor, Azule Energy, NNPC Ltd, Libyan National Oil Corporation, Asharami Energy, and Renaissance Africa Energy Company, all of which operate in Africa, are already members of OGMP 2.0, level 5 compliance remains limited. As the Wood Mackenzie study notes, the “availability of fully verified Level 5 [of the OGMP 2.0] supply remains far below what is needed to meet EU demand” despite OGMP 2.0 being one pathway to meet producer level compliance under the EU methane regulation.

African producers and exporters therefore cannot afford to base their strategy solely on the prospect of a postponement from Brussels. Producing countries need to act. Developing equivalent methane regulations at the national level would create the policy framework needed to drive producer compliance. This, in turn would improve the prospects of achieving both country level and producer level equivalence, provided implementation and enforcement are effectively managed.

Whether Article 28 takes effect as scheduled or temporarily delayed, the direction of its travel is clear. It extends beyond regulatory compliance to one of market access. For African producers and exporters, the challenge is no longer whether to prepare for stringent MRV requirements. Rather, it is how urgently domestic regulatory frameworks, institutional capacity, and compliance systems can be developed and strengthened to remain competitive in a market where methane performance is of growing commercial importance.

Adeniyi Adeoloye, a petroleum geoscientist based in Calgary, is in a postgraduate course on Energy Management at the University of Calgary. An editorial associate of Africa Oil+Gas Report, Adeoloye writes from time to time for this platform and can be reached at adeniyi@africaoilgasreport.com.

This Geoscience & Technology themed edition addresses the subject in two ways. One is a return to our old haunt; describing some of the most functional tools currently in use in the subsurface evaluation toolbox. The other is an invited case study of a new discovery in one of Africa’s most consequential exploration basins.

When integrated, Petrel and Paleoscan, developed by SLB and Eliis respectively, provide a powerful end-to-end subsurface evaluation workflow, the Kickstarter reports. “Paleoscan rapidly extracts detailed stratigraphic information and high-resolution seismic surfaces, while Petrel transforms these outputs into robust geological and reservoir models for volumetric estimation, well planning, and production forecasting”.

Now let us go out to the field.

“Infrastructure-Led Exploration requires more than a new strategy”, JohnBosco Uche writes in a column in this edition. “It demands new ways of seeing and understanding the subsurface. To accelerate opportunity maturation and improve drilling success, Renaissance Energy identified technology as a critical enabler of the exploration transformation”.

Uche is the Vice President Exploration at Renaissance Energy, Nigeria’s largest hydrocarbon producing company. He is retailing the company’s strategy and success in the JK-P (JK-004) discovery well in Oil Mining Lease (OML) 74 in shallow water offshore central Niger Delta basin. “Modern exploration is increasingly a data and technology business. Renaissance therefore prioritises seismic acquisition, advanced processing and AI-enabled workflows to improve subsurface imaging, reduce uncertainty and accelerate decision-making”.

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The Africa Oil+Gas Report is the primer of the hydrocarbon industry on the continent. It is the market leader in local contextualizing of global developments and policy issues and is the go-to medium for decision makers, whether they be international corporations or local entrepreneurs, technical enterprises or financing institutions. Published by the Festac News Press Limited since 2001, AOGR is a paid subscription, monthly e-copy publication delivered around the world. Its website remains www.africaoilgasreport.com, and the contact email address is info@africaoilgasreport.com. Contact telephone numbers in the West African regional headquarters in Lagos are +2348124374087, +2348130733523, +2347062420127, +2348036525979, +2348023902519.

–Editor

By Sola Adebawo

Africa’s $100 Oil Execution Test

In the oil business, price can make almost everyone look better than they really are. Rising prices strengthen cash flow, flatter margins and return previously marginal projects to corporate presentations. Governments see stronger revenues. Operators rediscover confidence.

But price can also conceal weakness. It can disguise declining reservoirs, unreliable infrastructure, delayed approvals and projects whose economics survive only while the market remains unusually tight. Oil’s return above US$100 should therefore be treated not simply as good news for Africa, but as an execution test.

The immediate cause is clear. Conflict and infrastructure disruption in the Middle East have constrained one of the world’s most important energy corridors. In its September 2026 assessment, the International Energy Agency reported that oil flows through the Strait of Hormuz averaged 7.6Million barrels per day in August, 13.1Million barrels per day below pre-conflict levels. Global inventories had fallen by 507Million barrels since the conflict began, despite the release of 400Million barrels of emergency stocks by IEA member countries.

Yet scarcity is only one side of the market. The IEA also estimates that global oil demand over the past six months averaged 5.8Million barrels per day below its February level as high prices, shortages and weaker economic activity suppressed consumption. It expects demand to contract by 2.5Million barrels per day this year. The cure for high prices may therefore be high prices themselves.

“Africa does not need to argue that the energy transition has ended. It has not. The stronger case is that a changing energy system still requires secure oil and gas supply, and that African projects capable of meeting competitive cost, governance and emissions standards deserve capital.”

That is why African producers must not confuse a moment with a cycle. An offshore project sanctioned today may not deliver first oil for several years. By then, supply routes may have reopened, demand may have weakened further and financing conditions may have changed. $100 oil improves project economics, but it does not remove project risk.

The disruption nevertheless creates strategic space for geographically diversified supply. Africa possesses material reserves, underexplored basins and established petroleum systems. The opportunity, however, is not uniform. Mature producers must arrest decline and improve reliability. Emerging producers must convert discoveries into bankable developments. Frontier jurisdictions must establish regulatory and geological credibility before capital will arrive at scale.

There are encouraging signals. Nigeria added about 200,000 barrels per day of supply between February and August, according to the IEA. The Nigerian Upstream Petroleum Regulatory Commission also reported that 31 companies emerged as winners of 37 oil and gas blocks after 143 companies submitted 200 bids. In Côte d’Ivoire, Petrobras has signed production-sharing contracts for eight offshore blocks, taking a 90 percent operating interest alongside Petroci, while examining opportunities elsewhere in Africa.

These decisions largely pre-date the latest price surge, but the supply shock increases their strategic significance. It also raises the standard by which they should be judged. The prize is not acreage awarded or agreements signed. It is hydrocarbons discovered, financed, developed and reliably produced.

That distinction matters particularly in Nigeria. A licensing round is successful only when credible financing becomes seismic acquisition, wells, development approvals and production. NUPRC’s drill-or-drop warning is therefore important. It signals that acreage should be governed by performance rather than possession. But regulatory firmness must be matched by regulatory speed. Approval delays defer cash flow, inflate costs and consume licence terms without adding a barrel.

Investors will look beyond the headline price. They will test break-even costs against conservative price assumptions and scrutinise decline rates, infrastructure uptime, evacuation reliability, fiscal stability, decommissioning liabilities and access to finance. They will ask how quickly reserves can be converted and whether the operator can absorb delay, cost escalation and community disruption.

Strong markets create their own pressures. Rigs, vessels, equipment and specialist personnel become more expensive. Consumers demand insulation from rising pump prices. Governments may feel entitled to capture more of the windfall, while operators may postpone difficult restructuring because price has temporarily repaired the income statement.

Governments should avoid opportunistic fiscal changes during an upswing. Where terms genuinely require revision, changes should be transparent, prospective and designed to preserve investor confidence. Regulators should enforce work programmes while ensuring that commercially sound projects do not become stranded in administrative queues.

Operators also face a choice. Stronger cash flow can fund distributions, or it can reinforce the foundations of production through well interventions, asset integrity, debottlenecking, pipeline reliability, reserves replacement and security. Shareholder returns matter, but cash flow is not the same as operating capacity.

For indigenous companies holding larger portfolios as international companies reshape their African positions, ownership must now be matched by capital, governance and technical depth. High prices can carry weak structures for a time. Lower prices reveal them.

The crisis carries a parallel gas lesson. The IEA estimates that about one-fifth of global LNG trade passed through the Strait of Hormuz in 2025. This strengthens the strategic case for gas projects from Nigeria and Senegal to Mozambique and Mauritania. But Africa will need more than resources and announcements. It needs bankable commercial frameworks, processing capacity, pipelines, creditworthy buyers and a balance between exports and domestic industrial demand.

The quality of Africa’s response can be measured. What conservative price deck are boards using to sanction projects? How long does it take to move from award or discovery to final investment decision? What proportion of committed capital becomes seismic work, wells and facilities? How much production is lost to infrastructure failure and avoidable deferment?

Those measures will reveal whether the present windfall is building productive capacity or merely improving short-term accounts.

Africa does not need to argue that the energy transition has ended. It has not. The stronger case is that a changing energy system still requires secure oil and gas supply, and that African projects capable of meeting competitive cost, governance and emissions standards deserve capital.

The current shock has reminded the world that energy security cannot be assumed. It has given Africa an opening, but not an entitlement. Oil above $100 can deliver a windfall. Lasting value will depend on whether the continent converts price into performance before the market turns again.

Sola Adebawo is an energy industry executive, strategic advisor and thought leader with nearly three decades of experience across Africa’s upstream petroleum sector. He is the Chief Executive Officer of Hyphen Partners Limited, a specialist advisory firm focused on policy and regulatory intelligence, market entry, stakeholder strategy, executive and institutional positioning in complex and highly regulated industries. A former executive at Chevron and Heritage Energy, he is an author, scholar and ordained minister. His writing explores energy policy, political economy, corporate governance, strategic communication, leadership, the relationship between institutions and public life, as well as the institutional forces shaping Africa’s development.

BAP Energy is one of the top six companies to reach “technical first oil” among the 50 entities awarded licences to marginal fields in Nigeria’s 2020­2022 licencing window.

Twice in the course of Africa Oil+Gas Report’s wide ranging, 90-minute interview with Temitope Edun, the company’s Chief Executive Officer, the word ‘Finance’ came up, but not as charged or loaded as it always does in conversations with C-Suite, E&P types.

“Finance has not been a struggle for us”, she told us, “but smaller oil and gas players do have challenges accessing funds”. This phrasing came across as: “other people have issues and they may need help, but not us”. Edun was more keen on getting the word out: “operating in an environment where the fiscal framework is skewed towards bigger companies was more challenging, as were the permits and regulatory compliance needed to drill or do anything on our asset”.

EXCERPTS FROM THE INTERVIEW BY AKPELU PAUL KELECHI AND FIDELIS AKPOM…

AOGR: BAP Energy is one of the early movers among the 2020-2022 marginal field awardees. You carried out a re-entry and workover of Igbomotoru 2 in PPL 207, carved out from OML 33. Can you briefly walk us through that journey? Why did you opt for Well 2 instead of Well 1. 

TEMITOPE  EDUN: BAP Energy was put together as an SPV for three companies that won the bid for PPL 207. We started working on the asset in July 2024. We looked at the two wells we had on the ground: Igbomotoru 1, a plugged- and-abandoned well, and Igbomotoru 2, a suspended well. We realised we wouldn’t have to do too much to get into Igbomotoru 2. That well goes through reservoir levels that, by our economic evaluation, were very viable. We decided to re-enter and get faster market access by producing through the shallower levels accessible with Igbomotoru 2. That is why we went with Well 2. Well 1 was plugged and abandoned with hundreds of metres of cement, so we would have to sidetrack it and deal with the swamp terrain, which we couldn’t do with a workkover unit. Our strategy was that once we became a producing company, we would be more valuable and able to get financial support. That was our strategy going into the re-entry.

You have been running an extended well test in Igbomotoru 2, so what exact volume of crude have you exported, and how much do you have in storage?

We started production some months ago. We have had 31 shipments to Brass, which is the terminal to which we evacuate. We have done north of 250,000 barrels.

As for what is in the tank, that is a moving target, but we have done about three cargoes of crude offloads in the back.

You mentioned Igbomotoru 1 being plugged and abandoned. At a recent technical session of the Nigerian Association of Petroleum Explorationists (NAPE), Shell presented and spoke about re-purposing wells. Is that something BAP is considering?

We realised there was about 600 feet of plug- and-abandon cement in three sections. It is not that we cannot drill through it, but it is not worth it. We are going to sidetrack that well. If you mean re-entering, yes, we are going to reuse the well, drill to a certain level, kick out, and use it that way. That well encounters almost 17 reservoir levels, so it is still a good well. We just do not want to start drilling through the old hole, so we will sidetrack to access the same levels.

What is BAP’s full value proposition, and what is your strategy for the next five to 10 years?

Every meeting we attend at NUPRC (Nigerian Upstream Petroleum Regulatory Commission), we hear about one million barrels added, three million barrels to be added. We know marginal fields are expected to support this drive. Our objective is to bring production to market. NUPRC has always told us they want to increase production in Nigeria and put money in the pockets of the government. Marginal field oil companies will add to these numbers. Our plan is to exploit this asset to get the best value out of it. We are bringing oil barrels to the table and even more gas molecules. We plan to first exploit the oil, drilling at least three wells, and then go into another three wells for gas. We are bringing a lot to the market.

Now that you have captured a lot of data from the extended well test, what is the full outline of BAP’s FDP on the asset?

We have re-entered the first well. The second well will be sidetracked to access the best three levels. A third well will access the very deep level. That is the plan for oil. In about two years, we plan to go into gas and drill another three wells to access our vast gas reserves.

When do you expect to begin the long- awaited drilling campaign? Is a rig finally on the way, and when is it expected to arrive?

This is an oil and gas problem in Nigeria. Swamp rigs are scarce. We have had opportunities for a swamp rig but have faced missed schedules and market challenges. We are speaking to a number of swamp rig providers and are waiting to start before the end of 2026.

When should we expect full steady evacuation into these mid-sized assets? Are there any proposed gas developments? You mentioned three gas wells. What volume are we expecting?

We are still evaluating the asset. We cannot say exactly what we will produce yet because we have not finalised that study. But we know our gas reserves are very high. In two years, we expect to start exploiting gas.

Given the field’s estimated 2P reserves of about 7Million barrels and STOIIP of 20Million barrels, what peak daily crude output do you expect over the next three years?

These are theoretical workings, but we know what we are producing from this first well and what we hope to produce from the next two. All in all, I expect about 5,000 to 7,000 barrels per day in the next few years if we are successful.

What are you currently producing?

We cannot say categorically at this point because we have had quite a few challenges – ups and downs since this is a well-test phase. We are testing different things, so I cannot give a definitive daily production figure.

Igbomotoru 1, 2, and 3 are old wells with difficult operating conditions and numerous vegetative channels. What challenges did you face with access, data certainty, evaluation, and interpretation? Did you need new seismic data?

Igbomotoru is in a swamp area, not close to land. By fast speedboat, it is almost one and a half hours from here; many mobilise from Port Harcourt, making it nearly a three-hour trip. It was quite difficult to walk in that terrain because there is nothing around, just many creeks. Security can be a concern in the creeks, but we have not had any major attacks or issues. In terms of data, re­entering the well gave us much new data, which helped us re-evaluate the entire asset and decide where to go for the next campaign. We are still looking at our substantial gas asset. On your question about seismic, it might be something we do soon, but it is not yet in the pipeline. We have worked with the old Shell seismic data.

Recent global pressure on renewable energy and fossil-fuel financing has affected marginal fields. Aside from financing, what other major challenges have you had to overcome as a new operator?

Finance was not too much of a challenge for us in the first phase. Operating in an environment where the fiscal framework is skewed towards bigger companies was more challenging, as were the permits and regulatory compliance needed to drill or do anything on our asset. It is not that we could not overcome these challenges; we just had to know exactly what was required and do it. Are they easy for marginal field operators? Maybe not, but it can be achieved. We need regulatory consistency and a framework skewed towards marginal field operators. There have been talks about harmonising taxes for marginal field operators, and I agree. There are too many layers, too many governmental agencies, too many things we suddenly hear about and ask, “Was that on the list?” We need harmonisation, especially for smaller players without deep pockets. We need to speak to just one or two organisations or ministries, and they cascade down what we need to do. That is one of the key challenges.

Would you say the ease of doing business has not been fully implemented, especially from a regulatory standpoint?

In the last decade or so, marginal field operators were not that many. Suddenly, Nigeria has created an environment where many have come into the market, and it is an evolving industry. The framework needs to work for these smaller and medium-sized players. The PIA was very good for the industry, but is it skewed towards all facets? These are things the NUPRC is looking at and trying to address.

What have been your key host community development successes, and is there any project that you are especially excited about?

Under the PIA, there is now the Host Community Development Trust (HCDT), where we are supposed to put money, and the community comes up with its needs assessment. It is no longer about a company just doing CSR. We operate within six communities, and we have had success because we carried them along in everything we do. We did not wait for the HCDT alone; we made them part and parcel of every decision concerning their area. The community has been well schooled on the new PIA, given workshops, and they know we would do right by them. It has been a smooth ride so far.

Is there any community project you are especially excited about?

The community identified what makes a better community: schools, hospitals, and electrification. What excites me is that they did not bring lofty ideas. They said, “I need a walkway from here to here,” “I need water in this particular way.” They made it very specific. We sat down for days and came together to ask, “What do you need?” That excites me. We also support the women, ensuring they speak up and are not side­stepped. That is also exciting.

So, these six communities have each set up a board of trustees in line with the PIA?

There is one board of trustees for all six communities under one umbrella. Yes.

Do you think a 20 MW gas plant is a feasible project in these small communities?

I cannot say because I have not done the assessment. The communities are quite educated; they know what they need. If electrification comes up, they will tell us how much electricity they need, and we will work with that.

Aside from harmonising taxes and agencies, what else can the government do to relieve pressure on new marginal entrants?

Finance has not been a struggle for us, but smaller oil and gas players do have challenges accessing funds. It would be interesting for the government to provide some kind of alleviation, perhaps a fund for smaller players drilling wells for less than $30 million, or tax holidays to help them get to market. I know the NUPRC talks about these things, and they know finance, the regulatory environment, and community issues are all key. They step in when there are community issues to educate everyone on the real requirements.

How seamlessly do the three partners in BAP Energy work together? And you were appointed CEO of Milesquare two years ago, effectively making you the CEO of BAP. Do they cash-call well?

It is an interesting marriage. They are people from different walks of life, but they know the real objective of this SPV. They all sit down and discuss issues, and we have moved ahead quickly because they have allowed certain things to fall into place. We have a cash-calling strategy that has worked for us, which is why we have been able to do things fast.

You mentioned that BAP is likely to become more of a gas producer than an oil producer in the future. Would you expect the gas to be primarily for domestic consumption or for export?

That is forward-looking. We are engaging a few people, and every business looks for the best value. We will finalise our discussions with off-takers and go with whichever offers the best value.

You’re a mechanical engineer trained in both Canada and Nigeria, with experience at ExxonMobil and elsewhere. Why did you choose the energy industry? As an engineer with a Canadian master’s degree, you had many options. What was it about the energy industry that attracted you?

Engineering was natural for me. My father is a mechanical engineer, my husband is a mechanical engineer, and my children are engineers. My son has a master’s in mechanical engineering. It runs in the family. I did not think for a second I would do anything else. I did my BSc at the University of Ibadan, starting in electrical engineering but switching to mechanical because I could not see the electrons. After finishing, the natural gravitation for engineers in Nigeria was oil and gas – cutting-edge engineering, technology, travel, and good pay. It was a natural aspiration. Most jobs I got were oil and gas engineering roles. In Canada, I opened my eyes to other things. I worked for PricewaterhouseCoopers in Edmonton and saw I could do analytical work. But coming back to Nigeria, oil and gas was the easiest way into the market. I first went into banking for two years, working as an engineer on projects, then naturally gravitated back to oil and gas. It was not something I intentionally chose; it chose me as an engineer. And as a woman engineer, you are thought of as someone who can work at different levels.

You mentioned technology, which is interesting. Looking 20 years ahead, do you think mechanical engineers and geologists will remain as relevant as they are today, or will AI fundamentally change or even upend their roles?

AI is upending the roles of many people. Upending does not mean they no longer have a role; it means that if you are not AI-savvy, you cannot keep up. I cannot imagine doing my job without AI.

I was just discussing with someone yesterday that if I did not have AI, I do not know how I would handle all the things I handle. If they removed AI, I would probably go back to my village and sit down. AI needs to be incorporated into every job – not just for geologists. Even for mechanical engineers, before you know it, someone designs a machine, sends it to a 3D printer, prints it, and sends it to market with no human in that process.

Everyone can be upended by AI.

The bottom line is how much AI you are using in your job and  incorporating into your daily work. That is what matters in the next era.

The Pope recently called on world leaders to put a leash on AI. Do you agree with that? And given how heavily you use AI in your own work, where do you think the line should be drawn between embracing its potential and putting appropriate limits on it?

I can relate to that concern. Every new technology has someone who can use it for the wrong reasons. With AI’s learning nature, it can bring up information from different aspects and be manipulated. I understand the concern about how AI can change reality. But we also live in a vastly populated, fast- moving world, and we need AI to think and act quickly. It is a double-edged sword. You need to be sure AI is used the right way and not manipulated, but also that you can use it for the right reasons. I cannot say put a leash on it, but I can say make sure you are not doing the wrong things with it.

How do you relax as an engineer?

My husband is always on the golf course, so he would easily say he relaxes. I would probably read a book. I run an NGO that deals with children on the street, so finding out about their lives and challenges is something I do. I also have friends I banter with, have drinks, and eat out with. I love to travel, though I do not get enough of the kind of travel I like. Those are the ways I relax.

What was the last book you read, and would you recommend it?

I’m reading a book by Hadiza Bala Usman, formerly the MD of the Nigerian Port Authority. It’s titled ‘Stepping on Toes.’ It talks about her journey in the NPA; how she started, how she left, and the challenges she faced. It’s an interesting read. I’m almost finishing it.

Do you see yourself one day writing your own story; whether about your personal journey, your career, or the story of BAP Energy?

It would be nice, but it is not top of mind at this point. Maybe someday.

Is there anything else you would like our readers to know about BAP Energy that we haven’t covered?

BAP Energy started just two years ago, but we have a great team. We have women and men in senior and junior roles, integrated together. One of my motives is that competence is not gender- specific. We have women going offshore and men doing typically women’s roles. We are gender- neutral, we just get the job done. That has helped people get into roles they typically would not. It is a lean team, but we are very good at what we do. We inspire ourselves to do better and handle many challenges. We do not have issues doing things outside our job roles to support each other.

Italian contractor Saipem has been awarded a $350Million contract by Azule Energy Angola S.p.A., relating to the West Hub Tails project, part of the wider Agogo Integrated West Hub Development, located 180 kilometre offshore Angola at water depths up to 1,750 metres.

The scope of work covers the engineering, fabrication, transportation and installation of subsea infrastructures, including approximately 62 kilometres of flowlines, risers and umbilicals, to be tied-in to the Agogo Floating Production, Storage, and Offloading unit (FPSO), with an expected duration of approximately two and half years.

Fabrication activities will be carried out at Saipem’s Ambriz yard in Angola, with the involvement of local companies and workforce. For the offshore campaign, Saipem will deploy the construction vessels FDS and Normand Maximus.