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Heads or Tails: Enhancing the Energy Illusion!

Section: In the news · February 23, 2026 · No comments |

By Gerard Kreeft

Hank was scheduled to work his usual 30 days offshore when he heard the news: Transocean was merging withValaris to become the world’s largest offshore driller. Hank was apprehensive about the news…how many mergers, acquisitions and redundancies had he not already witnessed? How many colleagues had he not seen being given the sack over the last 25 years? The number of drillers—many of them friends—had diminished greatly over the years. Those jobs would never return. Was he now engaged in a sunset industry? The last of his kind?

This narrative is a fitting story of how oil companies reserves—or lack of reserves– is dictating the pace of the downfall of the hydrocarbon industry. It’s a decline that not only involves the oil companies but also the drilling and service sector. It’s a sad tale that requires telling! And one that Hank would be telling his grandchildren.

How did we get here?

The UK major Shell and several industry analysts have said that the company needs an acquisition or exploration breakthrough to make up for an expected production shortage of 350,000-800,000 barrels of oil equivalent per day by 2035. due to maturing fields unable to meet its output targets.

Almost within the same time-frame Transocean and Valaris have announced merger plans to become the world’s largest offshore drilling contractor.

These are not isolated incidents but two warning signs that the energy transition—at least the fossil fuel portion of the energy cycle—is moving to a new and disruptive stage in which self-preservation is disguised as a market force creating shareholder value.

In the short-term the higher share prices of Chevron and ExxonMobil are meant to provide shareholders the required dividends but in the longer-term will not necessarily have a happy ending and will reap shareholder havoc. The emancipation of greed?

A much safer bet is TOTALEnergies’ Return on Average Capital Employed (ROACE) of 12.6% in 2025, the highest of the oil majors. True, TOTALEnergies share price currently is near the bottom of the pack but look at what the French major has done:

created a second income stream via its renewables and electrification arm which is now bringing in 12% ROACE…a much safer and secure source of income!
In 2025 total shareholder return was 28%, the highest of the oil majors.

This is based on a strategy developed some years ago and which is discussed below.

This should be a wake-up call for all members of the oil and gas fraternity to realize—be that a producer or service provider—that it’s no longer business as usual…when a company such as Wood Mackenzie pronounces that Shell’s reserve count is dwindling, the industry should sit up and take notice. Not only reputational damage but the very legitimacy of the oil and gas sector is coming into question!

Shell’s wake-up call

Luke Parker, Wood Mackenzie’s vice president of corporate research, expects Shell’s output to fall sharply from 2028 onwards. The company’s production is likely to drop by 800,000BOEPD in a decade based on its current portfolio.

“Shell’s biggest challenge, from our perspective, is that it doesn’t have the portfolio to support its strategy to go longer in oil and gas”.

Shell’s ‘reserve life’ – or how long its proven reserves can sustain current output levels – is equivalent to less than eight (8) years of production as of 2025, from nine (9)a year earlier, which was its lowest since 2021.

This compares with over 12 years each at Exxon and TOTALEnergies at the end of 2024. A shorter reserve life increases pressure to buy assets or to have a big exploration success to grow or maintain production.

THE CHIEF OBSESSION OF WAEL SEWAN’S, SHELL CEO SINCE 2023, is to drive up the company’s stock price, mimicking the narrative of Chevron and ExxonMobil and increasing cash distribution to shareholders of between 40%-50%.

Within this context its important to see how the oil majors are adapting their strategies for 2026 and beyond. The Dow Jones Industrial Index in the period 2021- 2025 increased 57%: from 31,098 to 48,711. In that same period the oil majors have displayed a variety of results:

ExxonMobil +159%

Shell +83%

ENI +73%

Chevron +65%

TOTALEnergies +44%

BP +42%

Equinor +28%

Shell’s share price has increased 83% in this five-year period making it more competitive with the shares of ExxonMobil and Chevron.

Shell’s total capex for the period 2025-2028 is between $20-$22Billion per year, $2-$3Billion less than 2023-2025. Also, the company is pledging to reduce its cost structure by $5-$7Billion by 2028.

Yet Shell has not provided any strategy how it will build up its reserves…probably more of the same!

Understanding Reserve Replacement Ratio (RRR)

This confronts us with a very old and repetitive theme which has been presented on these pages a number of times: the need to understand RRR—Reserve Replacement Ratio—how the oil and gas industry measures its reserves…. In short, one must learn to understand the petroleum classification system, which provides the heartbeat of the industry. In the trade this is called the Reserve Replacement Ratio (RRR), the annual amount of oil and gas reserves that a company must replace on an annual basis to maintain its portfolio. The Paris Agreement of December 2015 was a sharp warning to the oil and gas industry that it was no longer business as usual.

But it was during the summer of 2020 that the seeds that will eventually destroy the oil and gas industry, as we know it, were planted. In the summer of 2020, French oil and gas giant TOTALEnergies announced a $7Billion impairment charge for two Canadian oil sands projects. This might have seemed like an innocuous move, merely an acknowledgement that the projects hadn’t worked out as planned. However, it opened a Pandora’s box that could change the way the industry thinks about its core business model—and point the way toward a new path to financial success in the energy sector.

While it wrote off some weak assets, it also did something else: TOTALEnergies began to sketch a blueprint for how to transition an oil company into an energy company.

The French Connection

Patrick Pouyanné, TOTALEnergies’ chairman and CEO, now says that by 2030 the company “will grow by one third, roughly from 3Million Barrels of Oil Equivalent per Day (BOEPD) to 4Million BOEPD, half from LNG, half from electricity, mainly from renewables.” This is the first time that any major energy company has translated its renewable energy portfolio into barrels of oil equivalent. So, at the same time that the company has slashed proven oil and gas from its books, it has added renewable power as a new form of reserves.

Each of the oil and gas majors spilled red ink in 2020, and most took significant write-downs, but TOTALEnergies’ oil sands impairments were different. The company wrote off reserves, or oil and gas that the company had previously deemed all but certain to be produced.

Proven reserves long stood as the holy of holies for the oil industry’s finances—the key indicator of whether a company was prepared for the future. For decades, investors equated proven reserves with wealth and a harbinger of long-term profits.

Because reserves were so important, the reserve replacement ratio (RRR), the share of a company’s production that it replaced each year with new reserves, became a bellwether for oil company performance. The RRR metric was adopted by both the Society of Petroleum Engineers and the US Securities and Exchange Commission. An annual RRR of 100 percent became the norm.

TOTALEnergies’ write-off showed that even proven reserves are no sure thing and that adding reserves doesn’t necessarily mean adding value. The implications are devastating, upending the oil industry’s entire reserve classification system as well as decades of financial analysis.

How did TOTALEnergies reach the conclusion that reserves had no economic value? Simply put, reserves are only reserves if they’re profitable. The prices paid by customers must exceed the cost of production. Given current forecasts that prices would remain lower for longer, TOTALEnergies’ financial team decided those resources could never be developed at a profit.

The company hasn’t abandoned oil and gas, and its hydrocarbon investments may prove problematic over the long term. However, its renewable investments will add ballast to the company’s balance sheet, keeping it afloat as it carefully chooses investments, including oil and gas projects, with a high economic return.

Implementing the strategy

Oil and Gas and Integrated Power in the period 2026-2030 will have a capex of $14-16Billion; down $1Billion from 2025. Low carbon energy will receive $4Billion.

The company is accelerated its gas-to-power integration strategy in Europe by acquiring 50% of a portfolio of flexible power generation assets from EPH(Energeticky), the Slovak power company which has a flexible power generation platform in Western Europe.

“This transaction is fully consistent with TOTALEnergies’ Integrated Power strategy and will strengthen its position in European electricity markets by enhancing the complementary relationship between intermittent renewable power generation and flexible power generation (gas-fired plants, batteries).”

The company has confirmed that it is on track to deliver 100GW of renewables by 2030. Its Integrated Power division should, in the next 5 years, have a ROACE(Return on Average Capital Employed) of 12 percent; in 2025 the company’s ROACE was 12.6%, the highest of all the oil majors.

Wood Mackenzie has offered this verdict about TOTALEnergies’ strategy:

“TOTALEnergies is powering ahead in integrated power while many rivals scale back. The company has doubled electricity production since 2021, lifted returns on average capital employed to 10% and generated nearly a tenth of group operating cash flow from its fast-growing Integrated Power business.

It’s clear, consistent strategy – spanning renewables, flexible generation, trading and retail – sets it apart from peers. But driving returns even higher and more than doubling operating cash flow by 2030 will require flawless execution across every element of the value chain.”

The Response of the Drillers

The announced Transocean/Valaris merger– an all-stock transaction valued at $5.8Billion—comes as no surprise. Leslie Cook, Principal Analyst, Upstream Supply Chain for Wood Mackenzie said, “Once finalized, Transocean will solidify their market leading position in the high spec ultra-deepwater rig market and become a top-five player in the high spec jack-up market.”

Rystad Energy says that in 2026-2027, the demand for benign floaters and drillships will increase to 120 units. The bulk will come from the 96 units listed below:

Noble Drilling with 25 deepwater floaters and drillships;

Odfjell Drilling with 8 deepwater units, owned or managed;

Saipem with 6 deepwater units;

Seadrill with 17 units;

Transocean+ Valaris with 42 units(33 drillships+ 9 semi-submersibles).

The merger between Transocean/Valaris means that the new entity controls almost 50% of the deepwater rig market.

The Transocean merger comes as no surprise. The company has for years struggled with a mountain of debt: from a peak of nearly $10Billion in 2018-2019; the company’s debt load in mid-2025 was $6.55Billion. While other companies had gone through a painful Chapter 11—declaring bankruptcy—Transocean refused to go that route. According to one analyst “ it was a grave mistake at the business level, and the company is still paying for it.”

Some Final Takeaways

S+P Global forecast that for 2026-2027 oil and gas capital expenditures (CapEx) are expected to be characterized by continued financial discipline, with a focus on high-return, low-carbon, and brownfield projects, despite a forecasted decline in oil prices.

Total oil and gas capital expenditures are projected to be around $680Billion in 2026. Many major companies are tightening their spending due to expected oversupply and lower price assumptions.

Shell has always been quick to point out that its LNG arm would enable the company to withstand economic headwinds. Yet according to the latest Global LNG Outlook from the Institute for Energy Economics and Financial Analysis (IEEFA)….”Sluggish demand growth for liquefied natural gas (LNG), combined with a record increase in global export capacity through 2028, will likely thrust markets into an extended period of oversupply”.

“As major importing regions—including Japan, South Korea, and Europe—aim to reduce LNG demand through 2030, global LNG suppliers and traders will increasingly depend on growth in emerging markets to both compensate for falling imports elsewhere and absorb a flood of new supply”…

..”such rapid LNG demand growth in emerging economies is not guaranteed, even in an oversupplied market. Countries in South and Southeast Asia, for example, will face distinct barriers to rising demand, including fiscal and credit challenges, extensive infrastructure delays, and contracting issues, among other obstacles.”

Shell, in the final analysis, can offer little hope to the investment community. Other than more of the same and hoping for a better day.

Equally uninspiring is the message for the drillers and service providers. As long as the band plays the players will continue to dance.

The only glitter of hope and practical thoughtfulness for the sector is TOTALEnergies twin-pronged approach involving both deepwater and renewables. A strategy developed over a number of years and now showing fruition.

There are no easy solutions, otherwise they would have already been implemented. While the Energy Transition is important it is beyond the scope of this article. This is meant to be a wake-up call. Now is the time to take account of what is broken. Fixing it will be much more difficult.

At the end of the day Hank was rather proud of his grandchildren and their future choice of vocations: in the emerging energy transition.

Gerard Kreeft, BA (Calvin University, Grand Rapids, USA) and MA (Carleton University, Ottawa, Canada), Energy Transition Adviser, was founder and owner of EnergyWise. He has managed and implemented energy conferences, seminars and university master classes in Alaska, Angola, Brazil, Canada, India, Libya, Kazakhstan, Russia and throughout Europe. Kreeft has Dutch and Canadian citizenship and resides in the Netherlands. He writes on a regular basis for Africa Oil + Gas Report, and guest contributor to IEEFA(Institute for Energy Economics and Financial Analysis). His book ‘The 10 Commandments of the Energy Transition ‘is on sale at https://books.friesenpress.com/store/title/119734000211674846/Gerard-Kreeft-The-10-Commandments of the Energy Transition.

Deepwater Orange Basin, Namibia: Why Did Galp Energia Give Away 40% in the “2025 Discovery of the Year”?

Section: In the news · February 23, 2026 · 2 comments |

Tako Koning, P.Geol., Senior Geologist

Independent Calgary-based Consultant

INTRODUCTION

Since 2022, 14 oil and gas fields have been discovered in the deepwater Orange Basin, Namibia. This basin is one of the world’s current hotspots for oil and gas exploration. Two of these are giant-size fields including Galp Energia’s Mopane field and TOTALEnergies’ Venus field. Water depths range from 1,200 metres to 3,000 metres. Wood Mackenzie named Mopane as “2025 Discovery of the Year”. However, producing some of these fields will be challenging. For example, the Venus field is in 3,000 metres of water. Also, very high volumes of associated gas is found in all of the fields raising the question: “What will we do with all of that gas?”.

EARLY EXCITEMENT

Only four years ago Shell electrified the world’s oil industry with the announcement of the discovery of light oil and associated natural gas in the Graff-1X exploration well in the deepwater Orange Basin. The reservoirs were described as Upper Cretaceous marine sandstones. Almost immediately after, TOTALEnergies announced that the deepwater Venus-1X exploration well had discovered oil and associated gas in high-quality Lower Cretaceous sandstones. In 2023, the Portuguese energy company, Galp Energia added excitement with their announcement of the Mopane oil discovery. Following the Graff discovery, Shell announced oil and gas discoveries in the La Rona, Lesedi, Jonker and Enigma exploration wells. In total, five discoveries were made by Shell. Within a span of only four years, the Orange Basin has risen to become one of the world’s top-rated areas for oil exploration.

Figure 2. From: Sintana Energy’s website, January 23, 2026

SHELL’S $400Million WRITE DOWN

On January 9, 2025, oil industry analysts including myself were shocked to hear the news that Shell had written down its holdings in deepwater Namibia by $400Million. This has led to many people asking, “Whatever is going on in deepwater Namibia”? Although in fairness to Shell, as early as August 2024 Shell’s CEO Wael Sawan speaking to analysts said of Shell’s PEL 39: “It’s a complex subsurface. While there is no shortage of hydrocarbon volume, the question is going to be the commercial producibility and mobility of those molecules” (Upstream, 2 August 2024).

“A major challenge for the development of Venus is the need to re-inject the gas at a reasonable cost. Excessive costs could conceivably make the project non-economic. This will require leading edge technology since never before has reinjection of gas been carried out in 3,000 metres of water. The world’s deepest oil producing platform is Shell’s Perdido Spar in 2,450 metres of water in the Gulf of Mexico. Accordingly, the Venus project will be extending the technology by another 550 metres of water. This is a bold step by TOTALEnergies in a field which has possible major issues – especially reservoir permeability”

In the oil industry’s geoscience community, there’s been a lot of discussions on social media about why Shell has downgraded its Orange Basin assets. The overall consensus as summarized in the UK-based publication GEOExPro (October 2024) is that chlorite cementation probably has had a detrimental effect on the reservoir properties, especially reducing the permeability. Poor permeability reduces the oil and gas flow rates, recoverable reserves and commerciality of hydrocarbon fields. Of major importance is that the problem of reservoir permeability is not present in the Mopane discovery and appraisal wells nor in the three oil discoveries drilled by Rhino Resources. However, as more information was provided to the public by TOTALEnergies on the Venus oil field, the worrisome issue of permeability in Venus was mentioned. This will be detailed later herein.

Figures 3 & 4. From: Sintana Energy’s website, January 23, 2026

Galp Energia’s Giant Mopane Oil & Gas Field

In mid-2024, Galp Energia completed the drilling of its first two wells in Petroleum Exploration License (PEL) 83 where it had a high 80% working interest. State-owned Namcor had a 10% working interest as well as Namibia-based Custos Energy with a 10% working interest. Custos Energy is a Namibian indigenous company. The initial discovery well, Mopane-1X was followed by Mopane-2X, an exploration well located eight (8) kilometres westwards. Namcor stated that Mopane-1X had discovered “a substantial column of light oil in high quality reservoir-bearing Cenomanian and Turonian age sands”. Galp declared that with Monpane-2X, “significant light oil columns were found in high-quality reservoir sands”. In April 2024, Galp announced that well tests in the Mopane-1X reached 14,000 barrels of oil per day equivalent which was the maximum allowable limit for testing. The oil was light oil with low viscosity, minimal carbon dioxide and no hydrogen sulfide.

In November 2024, Galp Energia drilled and completed appraisal well Mopane-1A. Galp announced “light oil and gas-condensate reservoir-bearing sands with good porosities”. In January 2025, Galp completed appraisal well Mopane-2A and announced that the reservoir consisted of good quality sands with good porosities and permeabilities, high pressures and low fluid viscosities, minimum concentrations of carbon dioxide and no hydrogen sulfide. Galp also stated that “in line with the previous Mopane wells, no water contacts were found”.

“In handing over its 40% in Mopane, Galp received a 10% interest in the Venus oil field which is super-challenging due to its water depth, highly gas saturated reservoirs and the issue of permeability. Galp also received a 9.4% interest in TOTALEnergies’ PEL 91 which is in deeper water than Venus and is even more challenging. Is the commercial viability of Venus dependent on improved fiscal terms from the Government of Namibia? You can be sure that the Namibian government is watching everything like a hawk to ensure that Namibia gets its pound of flesh. If the government does not cooperate with TOTALEnergies, could Venus become a stranded, never-to-be-produced oil field?”

Subsequently Galp drilled Mopane-3X located about 15 kilometres southeast of the Mopane field. Galp confirmed significant light oil and gas-condensate columns, all in “high quality” sandstones, high pressures and high permeabilities, minimum CO₂ and hydrogen sulfide concentrations, and no water column was intersected. Mopane-3X was described as “far oilier” than the Mopane-1X to the northwest.

The water depths in the Mopane field range from 1,200 metres to 1,700 metres. Based on the exploration and appraisal wells, Galp Energia declared that Mopane holds hydrocarbon resources equivalent to 10Billion barrels of oil. In their Annual Report, Galp reported that Mopane consisted of 55% oil and 45% gas. My own “back of the envelope” analysis using a recovery factor of 20% indicates that Mopane has probable recoverable resources of 2.0 billion barrels of oil equivalent. The American Association of Petroleum Geologists (AAPG) defines a giant oil or gas field as a field with holding over 0.5 billion barrels of oil recoverable. By this definition, Mopane certainly qualifies as a giant field.

Rhino Resources Exploration Drilling PEL 85

The partners in PEL 85 include Rhino Resources, the block operator with a 42.5% interest and is a privately-owned company based in South Africa. The partners include the BP-ENI joint venture Azule Energy 42.5%, as well as Namcor with 10%, and Korres Investments with 5%.

Sagitarius-1X was the first well drilled by Rhino. It was reported to have penetrated a hydrocarbon reservoir with 90 metres gross thickness and no observed water contact.

Capricornus-1X was the second well drilled in PEL 85. Rhino reported the existence of a high-quality light oil-bearing reservoir with no observed water contact. The well tested at a flow rate of at least 11,000 barrels per day of light oil with limited associated gas from Lower Cretaceous sandstones. Rhino reported that the production test had been completed across a 38 metres net oil-bearing reservoir. The oil had an API of 37 degrees, 2% carbon dioxide and no hydrogen sulfide. No water contact was observed in the well.

The third and final well drilled to date in PEL 85 was Volans-1X which discovered rich gas-condensate-bearing reservoirs in 26 metres of net pay in Upper Cretaceous reservoirs. No water was observed in the well.

Stock Market Performance Due to the Mopane Discovery

Galp Energia’s current stock market capitalization on January 23, 2026 was Euro 10.6Billion (USA$ 12.6Billion). The impact of Mopane has doubled Galp’s market capitalization. A similar stock market performance has been achieved by Toronto-based Sintana Energy, which has a 4.9% interest in Mopane through its indirect interest in Custos Energy. Sintana’s stock market capitalization as of January 23, 2026 was Cdn$ 235Million (USA$172Million).

Figure 5: Galp Energia share price in Euros. The share price increased from Euro 14.0 to over Euro 20.0 after the drilling of Mopane-1X and Mopane-2X. Galp’s shares trade on the Euronext Lisbon stock exchange in Portugal.

Figure 6: Sintana Energy share price in Canadian dollars. Sintana’s shares trade on the Toronto Stock Exchange (TSE) Venture Exchange (TVX).

Chevron Dry Hole

A year ago, a cold wind blew over deepwater Namibia with Chevron announcing in January 2025 that their first exploration well in Namibia, Kapana-1X drilled on PEL 90 was a disappointing dry hole (Upstream, 15 January 2025). This well was drilled 60 kilometres west of Mopane. PEL 90 covers 5,433 square kilometres in water depths of 2,300 metres to 3,300 metres. Chevron is operator of PEL 90 with a 90% working interest and partnered with Namibia-based Trago Energy which holds the remaining 10%. Sintana Energy has a 5% carried indirect interest in PEL 90 in the initial exploration phase. Sintana acquired its interest through its acquisition in March 2022 of 49% of Trago Energy which is a wholly owned subsidiary of Custos Energy.

TOTALEnergies – Two Recent Discouraging Wells

Two of the most recent wells drilled by TOTALEnergies have been discouraging. The Tamboti-1X exploration well was drilled in 2024 to evaluate the area on the northern edge of Venus and was reported to have found oil but not in commercial quantities due to the sandstones being “lower

quality”. The Marula-1X well drilled in 2025 to a total depth of 6,460 metres approximately 40 km south of Venus-1X and was plugged and abandoned without any announcements of encouraging news.

How Does the Kudu Gas Field Fit into the Picture?

The Kudu gas field was discovered in 1974 in 170 metres of water depth 130 kilometres off the southwest coast of Namibia. Approximately 1.3Trillion cubic feet of gas occur in Triassic-age sandstone reservoirs. The operator of Kudu is BW Energy who drilled the Kharas-1A appraisal well in September 2025. The primary objective was to further appraise the Triassic reservoir but of secondary importance was evaluating possible Cretaceous-age turbidite reservoirs age-equivalent to the turbidites in Mopane. Kharas-1A is 70 kilometres east of Mopane-1X. BW Energy reported “several shallow turbidite reservoirs with dry gas shows were encountered and reservoir properties from these and the acquired whole core are now being evaluated”. Most oil industry analysts would interpret this as being discouraging and indicates that the Mopane turbidites do not extend into the Kudu area and it thereby establishes the eastern boundary of the play.

What to Do with the Gas?

How to handle associated gas appears to be a common issue among all operators of Orange Basin discoveries. Flaring is not an option. Re-injection appears to be the favoured solution. The amount of gas found to date is not certain, although two years ago Namcor had mentioned a figure of about 9 TCF (trillion cubic feet of gas). Due to the deep water which ranges from as deep as 3,000 metres for TOTALEnergies to 2,000 metres for Shell and 1,700 metres for Galp, a gas solution will be complicated and expensive.

TOTALEnergies Moving Ahead with Venus

The Venus field is reportedly a giant light oil and associated gas field that was discovered by Venux-1X and has been appraised by Venus-1X sidetrack plus three additional appraisal wells: Venus-1A, Venus-2A, and Mangetti-1X (Upstream, 4 November 2024). The discovery well, Venus-1X intersected 84 metres of pay with light oil and associated gas and was drilled to a depth of 6,300 metres. The most recent information from TOTALEnergies on the size of Venus is 750Million barrels of oil recoverable. However, Venus being located in 3,000 metres of water will be challenging.

Soon after news broke out about the Venus discovery, oil industry analysts stressed how the development of Venus would hinge on dealing with the gas, particularly in such deepwater (Upstream, 26 July 2024). The volume of associated gas held in Venus will be a headache for the production engineers. Compounding the problem is that the reservoir is low-permeable. The issue of permeability is also a problem with Venus as it is with Shell’s oil discoveries.

Beginning in April 2025, TOTALEnergies started discussions with the new government of Namibian President Netumbo Nandi-Ndaitwah about how to improve the profitability of Venus (Upstream, 1 May 2025). TOTALEnergies’ CEO Patrick Pouyanne told the President that Venus had technical challenges which Windhoek needed to help address. The latest development scenario (Upstream, 12 September 2025) is that Venus will be produced via a150,000 barrels of oil per day FPSO and a 40-well subsea production system, with project sanction in 2026 and first oil in 2029. The vessel will be designed to process up to 550Million cubic feet of gas per day with 15Million standard cubic feet per day (MMscf/d) to be used for onboard power, with the remainder reinjected.. The FPSO will house a 160-strong crew. TOTALEnergies said that the project is designed to stay within the company’s investment criteria, particularly the target of keeping development costs below $20 per barrel (Upstream, 20 January 2025).

In early April 2025, Patrick Pouhyanne said that TOTALEnergies and Shell had a data sharing agreement. He said, “Venus clearly has better petrophysical characteristics than that of Shell’s nearby Jonker discovery. While Venus permeability of 2 to 4mD is not very high, it is far better than Jonker’s which is about 0.7mD”.

In an interview, Pouyanne said because Venus’ reservoir has permeability challenges, it will have a lower-but-longer production plateau than TOTALEnergies’ 200,000 bpd FPSO in the GranMorgu field in Suriname. He said, “With Venus there is 700Million to 800Million barrels of oil but there is one difficulty: the permeability is low. So that means in order to sweep the oil, we need to reinject the associated gas. As a result, Venus will have a production plateau of about 150,000BOPD, longer than that of GranMorgue which holds a similar volume of resources”.

In my view, a major challenge for the development of Venus is the need to re-inject the gas at a reasonable cost. Excessive costs could conceivably make the project non-economic. This will require leading edge technology since never before has reinjection of gas been carried out in 3,000 metres of water. The world’s deepest oil producing platform is Shell’s Perdido Spar in 2,450 metres of water in the Gulf of Mexico. Accordingly, the Venus project will be extending the technology by another 550 metres of water. This is a bold step by TOTALEnergies in a field which has possible major issues – especially reservoir permeability.

Where Is This All Going?

None of the discoveries in the Orange Basin have yet been declared commercially viable. None yet can be classified as reserves since reserves are volumes of oil which have been determined to be economically produceable by the operator, independent consultants, and the Government of Namibia.

The oil and gas discoveries made by Galp Energia and Rhino Resources are certainly impressive. None of their wells have encountered any water beneath the oil and gas zones. Flow rates have confirmed the high quality of the reservoirs with Mopane-1X tested at 14,000 barrels of oil equivalent per day and the nearby Capricornus-1X flowing 11,000 barrels of oil equivalent per day.

The recent discouraging Tamboti-1X and Marula-1X must have TOTALEnergies scratching its head about where next to explore on its acreage. Perhaps there are no more Venus-like opportunities and Venus will be a single field development?

In the meantime, Shell’s activities in the Orange Basin has analysts including myself asking, “What the heck is Shell doing?”. In January 2025, Shell writes down $400Million due to “technical and geological difficulties”. Then just six months later, Shell turns around and announced that Namibia had returned to its radar. In mid-December, Shell Namibia CEO Eduardo Rodriguez announced, “We look forward to working with our partners NAMCOR and the Government of Namibia to deliver shared value for the country and its people” (AOGR, 16 December 2025). Shell is preparing to drill an exploration well on PEL 39 in April 2026 using the Deepsea Mira drilling unit (Reuters, 11 December 2025). Perhaps the sudden write down and abrupt turn around by Shell is a negotiating strategy by Shell to obtain better fiscal terms from the Government of Namibia?

The Orange Basin is massive consisting of 150,000 square kilometres of which around 55,000 square kilometres is in Nambia and the larger 95,000 square kilometres (according to Justin Cochrane, Regional Research Director, S &P Global) extends into South Africa. In the meantime, in the South Africa portion of the Orange Basin, Shell, TOTALEnergies and Eco (Atlantic) Oil & Gas and their partners have each acquired large blocks from the Government. Rather enigmatically, at the same time that Shell had declared its oil and gas discoveries in PEL 39 to be noncommercial, it was acquiring acreage in South Africa southwards and geologically on trend with their discoveries in PEL 39. Some analysts including myself asked, “Are Shell’s geoscientists in South Africa not talking with their counterparts in Namibia?”.

The Exchange of Interests Between Mopane and Venus

Soon after Galp Energia announced the results of Mopane-1X and Mopane-2X, Galp announced plans to dilute their high 80% working interest in Mopane. Oil industry analysts, including myself, keenly waited to see the outcome of a possible farmout. This could reveal more about the size of Mopane by the purchase price or details of the farm-out. Companies interested in Mopane presumably included Shell, TOTALEnergies, Chevron, Azule Energy, ExxonMobil, Woodside and perhaps Norway’s Equinor and the Chinese NOCs including Sinopec and CNOOC.

On December 9, 2025, Galp Energia announced the following: “Galp Energia partners with TOTALEnergies in Namibia. “Galp forms a relevant partnership and expands its position in Namibia’s Orange Basin”. Galp will exchange a 40% interest in PEL 83 where the Mopane discovery lies for a 10% interest in PEL 56 wherein Venus is located and a 9.4% interest in TOTALEnergies PEL 91. Furthermore, TOTALEnergies will take operatorship of PEL 83”.

Oil industry analysts have asked if this is a win-win agreement? Did one of the companies win and the other one lose? One of the world’s premier oil industry consultancies is Wood Mackenzie who named Mopane as the “2025 Discovery of the Year” (reference Wood MacKenzie 2025 Annual Exploration Survey). Galp gave up half of its 80% interest in Wood Mackenzie’s top ranked discovery in 2025 in a giant oil and gas field with no reservoir complications. The issue of permeability which plagues Shell’s discoveries as well as in Venus, is not present in Mopane. Five wells were drilled in Mopane with a 100% success rate. No underlying water was encountered in any of the Mopane wells nor in the nearby Rhino Resources’ discoveries. Impressive flow rates of oil and gas were recorded in Mopane-1X and in Capricornus-1X. The water depths in the Mopane field range from 1,200 metres to 1,700 metres so operationally not challenging.

In handing over its 40% in Mopane, Galp received a 10% interest in the Venus oil field which is super-challenging due to its water depth, highly gas saturated reservoirs and the issue of permeability. Galp also received a 9.4% interest in TOTALEnergies’ PEL 91 which is in deeper water than Venus and is even more challenging. Is the commercial viability of Venus dependent on improved fiscal terms from the Government of Namibia? You can be sure that the Namibian government is watching everything like a hawk to ensure that Namibia gets its pound of flesh. If the government does not cooperate with TOTALEnergies, could Venus become a stranded, never-to-be-produced oil field?

In my view, TOTALEnergies got the best part of this deal. My opinion is also shared by the international investment community with Galp Energia’s share price dropping 15% following the December 9, 2025, announcement (Figure 4).

My opinion is reinforced by comments provide by TOTALEnergies in their fourth-quarter results call on February 11, 2026. TOTALEnergies said that Mopane has a discovered resource estimate of between 800Million and 1.1 billion barrels of oil equivalent, enough to support a production level of above 200,000 boepd (Upstream, February 12, 2026).

Galp Energia’s problem as a business is that since its founding in 1999, it has had exploration and production assets in Angola, Brazil, Sao Tome & Principe, Mozambique and Namibia. However, Galp was just a passive investor and gained no experience as operator. Accordingly Galp has no capacity to be operator developing Mopane. They had no alternative but to make a deal with one of the “big boys”.

Had I Been CEO of Galp Energia

Had I been CEO of Galp Energia, I would have tried to negotiate a trade of working interests in the next door PEL 85 where Rhino Resources holds 42.5% and where Azule Energy (BP 50% & Eni 50%) holds 42.5%. BP or ENI could have capably operated the joint consortium. My second choice would have been receiving 100% cash for the 40% share of Mopane. This would have been far better than getting a small piece – just 10% of the possibly marginal Venus oil field.

Final Comments

All indications are that Namibia will become a major oil and gas producer, joining the ranks of oil and gas producing Nigeria and Angola on the west coast of Africa. Namibia is not a rich country with a GDP of only USA$4,800 per capita in comparison to that of the USA at $90,000 per capita. In my view, the impact of the deepwater Orange Basin will be transformational for Namibia’s economy and will greatly benefit Namibia’s people.

“In early April 2025, Patrick Pouhyanne said that TOTALEnergies and Shell had a data sharing agreement. He said, “Venus clearly has better petrophysical characteristics than that of Shell’s nearby Jonker discovery. While Venus permeability of 2 to 4mD is not very high, it is far better than Jonker’s which is about 0.7mD”.”

For the past fifty years I have been hands-on involved in worldwide oil and gas exploration as a geologist, manager, consultant and industry analyst. This is classic frontier oil exploration in a minimally evaluated super-large sedimentary basin. This story is not yet finished. Stay tuned.

Biography

Tako Koning is Holland-born, Canada-raised and resides in Calgary. He was involved with the evaluation of Namibia’s Kudu gas field from 1995 – 1997 when he was portfolio manager with Texaco in Luanda, Angola. At that time, Shell was operator of Kudu and Texaco had a 15% working interest in Kudu. Since that time, he has had an abiding interest in Namibia’s oil industry. He closely follows the latest news coming out of Namibia. He has travelled several times in Namibia for business and also as a tourist. His view is that Namibia is magnificent with its deserts, spectacular coastline, wildlife, and numerous national parks.

Koning has a B.Sc. in Geology (1971) from the University of Alberta and a B.A. in Economics (1981) from the University of Calgary. He worked worldwide for Texaco for thirty years and subsequently he continued to work in Angola for Tullow Oil and the consultancy of Gaffney, Cline & Associates. During his fifty-year career, he lived and worked for a combined 30 years in Indonesia, Nigeria, and Angola and the remainder in Calgary. He is pleased to share his knowledge of Namibia in this article. He has been on the International Advisory Board of the Africa Oil + Gas Report for 25 years since it was founded by Toyin Akinosho in 2001.

Tinubu’s Executive Order-9- A Structural Recalibration or a Fiscal Short-Circuit

Section: In the news · February 19, 2026 · No comments |

OPINION/EDITORIAL PIECE

By Emeka Eboagwu

The Presidential Executive Order No. 9 of 2026, announced by the office of Nigeria’s President Bola Ahmed Tinubu, represents one of the most consequential post-Petroleum Industry Act (PIA) interventions in the country’s petroleum governance framework.

To understand its significance, it must be assessed against the structural logic of the overarching legislation that was signed into law in August 2021. The PIA was not merely a fiscal reform statute; it was a governance re-architecture designed to create predictability, ring-fenced funding mechanisms, regulatory clarity, and commercial independence for state participation.

In restructuring the former NNPC into Nigerian National Petroleum Company Limited (NNPC Ltd), creating the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) and the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA), and establishing defined fiscal and sector funding structures, the PIA sought to reduce discretionary interference and enhance investor confidence. Executive Order No. 9 alters several of these fiscal flows, and in doing so reopens foundational design questions about the industry’s governance equilibrium.

The Order suspends inflows into the Frontier Exploration Fund and redirects those revenues to the Federation Account. Under the Petroleum Industry Act, frontier exploration was established as a structured and predictable funding mechanism intended to support long-term reserves replacement and basin diversification. Frontier basins are commercially marginal and capital intensive; without ring-fenced funding, exploration becomes subject to annual political discretion. While redirecting funds to the Federation Account may improve short-term liquidity for federal and subnational governments, it undermines the long-term rationale of exploration financing. In capital-intensive extractive industries, reserves replacement is vital. Removing a predictable funding stream without establishing a transparent alternative risks weakening Nigeria’s upstream sustainability and long-term production outlook.

The legal basis for the Executive Order is rooted in the Minister’s authority to issue general policy directives under the PIA. However, a significant distinction exists between issuing policy guidance and suspending the operational effect of statutory fiscal mechanisms. Policy directives are typically meant to guide regulatory interpretation within the bounds of the Act, rather than to significantly alter revenue earmarks embedded in legislation or subsidiary regulations. This raises a potential ultra vires concern. If challenged, the courts would assess whether the Executive Order effectively amends the statutory framework through executive action rather than legislative change. Even without litigation, the perception that statutory fiscal mechanisms can be halted by executive order may increase sovereign risk perceptions among investors.

The suspension of the 30% management fee deductions payable to Nigerian National Petroleum Company Limited from PSC and related contract structures also has structural implications. The PIA commercialised NNPC Ltd as a CAMA entity, intended to operate with financial autonomy and market discipline. Removing predictable revenue streams through executive action could re-politicise its financial architecture. If NNPC Ltd’s cash flow becomes subject to executive adjustment, credit markets may reassess its borrowing capacity and balance sheet stability. The PIA attempted to reposition NNPC Ltd from a fiscal instrument to a commercially viable company; Executive Order No. 9 risks blurring that distinction.

The redirection of gas flare penalties away from sector-specific funding streams into the Federation Account creates another structural tension. Under the PIA framework, flare penalties were part of a design logic where environmental sanctions were linked to sector reinvestment and gas infrastructure development. This established an incentive alignment between environmental compliance and gas monetisation.

“Privatization whether through partial listing, asset-level divestment, or strategic equity participation—heavily depends on governance credibility. Investors contemplating participation in NNPC Ltd would assess not only asset quality but also regulatory protection. Executive orders that significantly affect company revenue streams suggest that shareholder rights may be subordinate to fiscal expediency. Even if legally justified, this perception introduces political risk into valuation models. When governance autonomy is uncertain, discount rates rise. This directly results in a lower potential valuation in any future listing or private placement.”

In routing penalties into general revenue, the causal link between polluter-pays principles and sector remediation becomes diluted. This may weaken Nigeria’s gas transition narrative and complicate ESG positioning in international capital markets, particularly as global investors increasingly scrutinise how environmental penalties are deployed.

The Executive Order also aims to tackle regulatory fragmentation by establishing a Joint Project Team between NUPRC and NMDPRA to support coordinated operations. This measure addresses a real coordination issue within the PIA’s split-regulator structure. Integrated upstream-midstream assets often encounter overlapping approval processes and fee arrangements. However, placing oversight under executive advisory bodies risks adding an extra bureaucratic layer instead of simplifying the process. The success of this measure will hinge on whether it establishes a clear, transparent one-window licensing system or merely results in parallel administrative oversight.

From a public finance perspective, the centralisation of revenues into the Federation Account addresses long-standing concerns about first-line deductions and opaque earmarks. Subnational governments have consistently argued that off-budget allocations reduce distributable revenue pools. In that sense, the Executive Order aligns with fiscal transparency and distributive equity objectives. However, petroleum fiscal systems globally rely on earmarked mechanisms to manage sector-specific capital intensity and reinvestment needs. The policy trade-off is therefore between immediate distributable liquidity and sustained sector reinvestment. Removing earmarks without establishing alternative funding structures risks short-term fiscal gain at the expense of long-term industry competitiveness.

The broader industry implications are considerable. Investors prioritise stability and predictability in fiscal regimes. When fiscal mechanisms embedded in legislation are suspended through executive instruments, the perceived durability of the legal framework diminishes. This could lead to higher risk premiums, slower capital commitments, and more cautious bidding behaviour in frontier and deepwater blocks. Momentum in frontier basins may stall until there is clarity. Financing decisions for gas infrastructure might be postponed if investors remain uncertain about the sector’s future funding structures. Regulatory coordination reforms could enhance efficiency, but only if they are institutionalised in a transparent and legally robust manner.

Moreover, by suspending or redirecting certain management fee deductions and revenue flows previously accruing to NNPC Ltd, the Order introduces executive discretion into what was intended to be a predictable commercial revenue structure. For a company transitioning to commercial status, revenue certainty is essential. If cash flows can be administratively adjusted outside of a shareholder resolution or legislative amendment process, lenders and potential equity investors will reassess risk. The market will interpret this as residual sovereign control over corporate income. That perception weakens the argument that NNPC Ltd operates as a commercially autonomous entity.

Second, commercialisation requires a credible balance sheet. NNPC Ltd’s ability to borrow, issue bonds, refinance joint venture obligations, or restructure legacy assets relies on stable internal cash generation. Any intervention that reallocates revenue before it boosts retained earnings impacts leverage ratios, debt-service coverage metrics, and credit rating outlooks. If rating agencies see revenue streams as politically adjustable, they may impose a sovereign override risk premium. This makes external financing more costly and hinders the PIA’s aim of transforming NNPC Ltd into a commercially disciplined oil company.

Third, privatization whether through partial listing, asset-level divestment, or strategic equity participation—heavily depends on governance credibility. Investors contemplating participation in NNPC Ltd would assess not only asset quality but also regulatory protection. Executive orders that significantly affect company revenue streams suggest that shareholder rights may be subordinate to fiscal expediency. Even if legally justified, this perception introduces political risk into valuation models. When governance autonomy is uncertain, discount rates rise. This directly results in a lower potential valuation in any future listing or private placement.

There is also a conceptual contradiction. The PIA aimed to depoliticise NNPC by separating it from the Federation Account framework and embedding it within corporate law. Executive Order No. 9, by redirecting revenue flows to the Federation Account and adjusting management fee structures, partially reintegrates NNPC Ltd into the state’s fiscal machinery. This does not formally reverse privatisation, but it weakens the boundary between the corporate entity and the fiscal instrument. For privatisation to be credible, that boundary must be robust and predictable.

Furthermore, privatisation requires a clear narrative. Investors need to believe that the government is dedicated to enabling market discipline to guide corporate strategy. If fiscal pressures can lead to revenue reallocation through executive action, investors might question whether dividend policies, reinvestment strategies, or asset allocations could be similarly changed. This uncertainty lowers valuation and delays access to capital markets.

However, there is a counterargument. If the Executive Order improves transparency by removing opaque first-line deductions and strengthens the Federation Account without significantly impairing NNPC Ltd’s operational capacity, it could boost overall fiscal credibility. If the company’s core commercial revenues stay intact and the changes simply correct inefficient internal allocations, then long-term governance clarity might improve. The key factor will be whether the revenue adjustments weaken retained earnings and capital formation or merely streamline internal fiscal structures.

For privatisation specifically, timing becomes crucial. If the government plans to list or partially divest NNPC Ltd in the medium term, it must establish a stable, legislatively supported fiscal framework for the company. Investors need assurance that corporate income will not be altered by executive measures outside standard shareholder procedures. Without this assurance, valuation discounts are unavoidable.

An alternative reform pathway could have achieved the Executive Order’s objectives with greater structural coherence. Instead of suspending earmarks, the government could pursue formal legislative amendments to adjust contribution percentages or restructure fund governance. Another approach would be to channel all revenues into the Federation Account but reallocate defined allocations annually through the budget process, subject to published performance metrics and audit oversight. A performance-linked funding model could also ensure that exploration or gas infrastructure funding is tied to measurable milestones, addressing efficiency concerns without dismantling the long-term financing structure. Such alternatives would preserve transparency while maintaining investor confidence in statutory stability.

Ultimately, the Petroleum Industry Act was enacted to reduce discretion, strengthen institutional independence, and promote consistency in Nigeria’s petroleum governance. Executive Order No. 9 reintroduces centralised fiscal authority at the executive level. Whether this results in reform or instability will depend on the subsequent steps taken. If legislative changes are implemented and transparent reinvestment processes are put in place, the reform could be a well-balanced adjustment. Conversely, without these measures, the industry might face a period of regulatory uncertainty that could hinder investment and long-term planning. The key issue is not just how much revenue is allocated to the Federation Account in the short term, but whether Nigeria’s petroleum governance system remains stable, credible, and aligned with the sector’s long-term sustainability.

Dr. Emeka Eboagwu, PhD, CMILT fASCS, is a Global Social Sustainability Expert and an Energy Economist who writes from the UK. He can be reached at eeeboagwu@gmail.com

Nigeria’s President Signs New Executive Orders, Chipping Away at Extant Petroleum Law

Section: In the news · February 18, 2026 · No comments |

Nigeria’s President Bola Tinubu has signed an Executive Order mandating the direct remittance of all oil and gas revenues to the Federation Account, effectively bypassing deductions and retentions previously allowed under the Petroleum Industry Act (PIA) of 2021.

The order, signed on February 13, 2026, and gazetted immediately, aims to restore full constitutional revenue entitlements to the federal, state, and local governments by eliminating what the presidency describes as excessive and duplicative deductions that have significantly reduced inflows to the Federation Account.

“These instructions all chip away at validly legislated sections of the Petroleum Industry Act, even as there were no indications on the press release posted on X by the government’s spokespersons that there are plans for any recourse to the National Assembly for amendments.“

Key provisions of the Executive Order include:

Ending NNPC Limited’s 30% management fee on Profit Oil and Profit Gas from Production Sharing Contracts, Profit Sharing Contracts, and Risk Service Contracts. The government argues that the existing 20% profit retention for working capital and investments already covers NNPC’s operational needs.
Abolishing NNPC’s 30% retention for the Frontier Exploration Fund under Sections 9(4) and (5) of the PIA. All such funds must now be transferred directly to the Federation Account, preventing the accumulation of large idle balances for speculative exploration.
Requiring operators and contractors under production sharing arrangements to pay Royalty Oil, Tax Oil, Profit Oil, Profit Gas, and all other government entitlements directly to the Federation Account starting February 13, 2026.

Suspending payments of gas flare penalties into the Midstream and Downstream Gas Infrastructure Fund (MDGIF). All future penalties will go to the Federation Account, with existing MDGIF expenditures required to comply fully with public procurement laws.

These instructions all chip away at validly legislated sections of the Petroleum Industry Act, even as there were no indications on the press release posted on X by the government’s spokespersons that there are plans for any recourse to the National Assembly for amendments.

The presidency stated that the current PIA framework has allowed deductions that “far exceed global norms” and divert more than two-thirds of potential revenues away from the Federation Account. The declining net oil revenue inflows are largely attributed to these structures and fragmented oversight.

President Tinubu also highlighted structural concerns with NNPC Limited continuing to act as both concessionaire and commercial operator under Production Sharing Contracts, which he said creates competitive distortions and hinders the company’s transition to a fully commercial entity as intended by the PIA.

To implement the reforms, the President has approved:

The constitution of a joint project team, with the Nigerian Upstream Petroleum Regulatory Commission (NUPRC) serving as the interface for integrated upstream and midstream operations.

An implementation committee chaired by the Minister of Finance and Coordinating Minister of the Economy, and including the Attorney-General, Minister of Budget and National Planning, Minister of State for Petroleum Resources (Oil), Chairman of the Federal Inland Revenue Service, Special Adviser to the President on Energy, and the Director-General of the Budget Office.

Nigerian Output in a January Bump

Section: In the news · February 18, 2026 · No comments |

Nigeria’s crude oil output increase by 37,000Barrels of Oil Per Day (BOPD) in January 2026 was an encouraging start to the new year.

It is a signal, no less, that the country’s hydrocarbon production is still stuck in a lower for longer mode.

The main contributor to the M-o-M increase was the ExxonMobil operated deepwater Erha field, which ‘shot back up’ to 70,756BOPD, from 11, 248BOPDaveraged in the prior month.

At 1.459MMBOPD, the January 2026 data ranks low (Number 6) in the 13 monthly range of output (January 2025 to January 2026), even though it compares favourably with 1.422MMBOPD averaged in December 2025.

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European Bank President in First Visit to Nigeria and Sub-saharan Africa

Section: In the news · February 16, 2026 · No comments |

European Bank for Reconstruction and Development (EBRD) President Odile Renaud-Basso will travel to Nigeria this week of February 16, 2026, marking her first visit to a sub-Saharan country since Bank shareholders’ historic decision to start investing in the region.

She will be meeting senior Nigerian government officials and business representatives, joined by Heike Harmgart, the EBRD’s Managing Director for Sub-Saharan Africa, and Hamza Al-Assad, EBRD Director of the Bank in Nigeria.

Nigeria became an EBRD shareholder and a country of operation in 2025.

“President Renaud Basso and her team will meet with senior government officials, including Minister of Finance and Coordinating Minister of the Economy and EBRD Governor Adebayo Olawale Edun, to discuss government economic priorities and private-sector investment,” the Bank said in a statement. “She will also meet representatives from the private sector and development partners. The discussions will focus on supporting government economic priorities and private-sector investments”.

The visit underscores the EBRD’s growing engagement in Nigeria and sub Saharan Africa, and the Bank’s commitment to supporting private sector development, sustainable infrastructure and economic resilience across the region.

“Nigeria stands out as a vibrant, high potential economy where our private sector focused model can make a real difference”, the statement added.

The EBRD signed its first investment agreement in Nigeria in 2025, to provide a trade financing facility to Access Bank.

In Nigeria, EBRD aims to invest in sustainable critical infrastructure that underpins private-sector development, to support the modernisation and efficiency of enterprises, and to strengthen the economic governance of institutions.

Regulatory Diplomacy and Policy Architecture: Forging a Unified Voice across Africa

Section: In the news · February 9, 2026 · No comments |

By Osten Olorunsola, Chairman Aradel Holdings

Despite differences in geography, politics, and resource endowment, many African countries share common structural characteristics and credentials much beyond colour and frames.

These include Electricity deficits, limited transmission, grid instability and outages; Heavy dependence on petroleum for Revenues; Large untapped Mineral and Renewable Resources; Infrastructure constraints; Energy Access gaps; Energy transition dilemma; Financing difficulties as well as diverse Social challenges including Urbanisation pressure.

These similarities tend to shape policies, regulations, investment focus and strategy which only terminate at territorial borders with minimal cross boarder sharing, alignment or even collaboration.

Remember that African Proverb, “If you want to go fast, go alone. But if you want to go far, go together”.

I am not too sure if we are going fast nor convinced we are heading far.

I will say that an African moonshot, like the Framework for the African Continental Free Trade Area (AfCFTA) is a great driver for collaboration and alignment across the continent, but more specifically in the area of energy sufficiency and how to sustain such.

As we all know, without unhindered access to electricity and energy generally, economic growth and resilience will continue to elude us in Africa.

However, this big bang-type of Pan African agenda and roadmap may be too heavy, to even start at all.

Latching on established frameworks (AU, AfCTTA, APPO, ECREE), and more importantly using the successful platforms (e.g ECOWAS, Power Pools in Eastern and Southern Africa) in the five Regions in Africa (Northern, Eastern, Southern, Western and Central)

These quasi-homogeneous groupings stand a better chance of facilitating “Joined-up Thinking” and implementation within the regions before a second phase at pan-African scale. That is the way I believe we develop and sustain the Unified Voice we look up to, and hopefully becoming a template and DNA for other collaborations beyond borders and geographies.

However we must take a little time to study and understand why previous cross border initiatives failed to deliver as intended.

Political will, Shared purpose and mutual benefits for all, Trust and transparency, Institutional Governance, Competence and Capacity to deliver, Structured cooperation and Infrastructure gap closure mechanisms must be the central focus to attain the Unified Voice we aim for.

Finally, and speaking to Regulatory diplomacy, I dare say charity begins at home.

As enabling as the PIA has been since enactment in 2021, the implementation excellence we yearned for is yet to be delivered.

And don’t get me wrong, all industry stakeholders are sweating it out and making progress.

It can be a lot better as we NUPRC and NMDPRA collaborating to enable the industry as a whole.

We must subdue silo mentalities and rather encourage working together for common goals which deliver greater benefits and successes.

Getting cooperation right locally will greatly enhance Regulatory diplomacy, sharing and collaboration across borders.

While not trivializing nor keeping it that simple, I believe we can make it happen. We must be intentional and disciplined to obey the core Characteristics, Principles and Fundamentals of Collaboration………. required to forge a Unified Voice for Africa.

-Shared goals and value systems

-Open book

-Trust

-Mutual respect

-Accountability; backed by clear Roles and Responsibilities -Leveraging strengths; iron sharpening iron

-Having long time views

And remember, Pace and Scale matters as we embark on this journey. (PIA gestation is certainly not best practice).

Best Regards,

Osten Olorunsola

This article is an abridged version of the opening remarks at the third session of the 2026 edition of the Nigeria International Energy Summit (NIES) entitled: Regulatory Diplomacy & Policy Architecture: Forging Africa’s Unified Energy Voice. Mr. Olorusola is an architect of Nigeria’s Petroleum Industry Act. He retired from Shell International as Vice President of Commercial Gas Business for Sub Saharan Africa, thereafter serving as Adviser to two Ministers of Petroleum Resources, later as Director of Petroleum Resources, and subsequently as the technical lead for drafting the Petroleum Industry Bill from 2010 till 2019. He is a Fellow and Country Chairman of the Energy Institute..

South Africa’s Upstream Petroleum Resources Development Act (UPRD Act): Can Legal Certainty Revive Major Investment After IOCs’ Exit?

Section: In the news · February 7, 2026 · No comments |

By Africa Energy Chamber

South Africa’s new Upstream Petroleum Resources Development Act offers a fresh regulatory framework, but is it enough to bring supermajors back, or will independent players now dominate the landscape?

The high‑profile exit of global energy major TOTALEnergies from deepwater Blocks 11B/12B and 5/6/7 – home to the Brulpadda and Luiperd gas discoveries – was a significant setback for South Africa’s plans to use domestic resources to boost energy security and economic growth. TOTALEnergies, together with partners QatarEnergy and CNR International, gave up their stakes after determining that the discoveries could not be commercially developed under the existing market conditions and regulatory framework.

The exits underscored long‑standing industry frustrations with South Africa’s legal and regulatory environment, widely seen as lacking the clarity and predictability that deepwater investors demand. That backdrop helps explain the government’s passage of the Upstream Petroleum Resources Development Act (UPRD Act) – a standalone legislative framework designed to replace the petroleum provisions embedded in the old Mineral and Petroleum Resources Development Act and provide a bespoke upstream regime.

At its core, the UPRD Act aims to accelerate exploration and production of South Africa’s petroleum resources by providing clear rules and stable rights for companies – key to attracting major investment. It combines exploration and production rights into a single petroleum right, sets out controlled licensing rounds, guarantees third-party access to infrastructure, and establishes the Petroleum Agency of South Africa as a clear regulatory authority. The law also promotes active participation by the State and previously disadvantaged South Africans, mandates local content, allows a share of output to be sold for strategic stock purposes, and separates oil and gas regulation from mining rules to reduce red tape and simplify operations.

Yet the big question remains: will this new legal certainty be enough to lure back the supermajors, or has the landscape shifted toward leaner, more aggressive independent companies seeking opportunities where majors have stepped away?

TOTALEnergies’ discoveries brought to light alternative energy solutions for a country plagued with a decade‑long energy crisis. However, without clear, predictable rules, even world‑class discoveries struggle to progress to commercial development. It shows how regulatory reform is essential to restoring investor confidence.

The UPRD Act now provides that framework, but timing is crucial. The regulations needed to put the Act into practice are still being finalized, and until these rules – covering licensing, environmental safeguards and rights administration – are published and tested in early rounds, investor confidence is likely to remain cautious.

For supermajors, investment decisions are increasingly guided by a global strategy that prioritizes projects with clearer returns and lower regulatory risk. With growing pressure to meet climate targets and streamline their portfolios amid the energy transition, deepwater frontier projects in emerging markets are less appealing unless they come with clear, predictable terms.

Ultimately, South Africa’s upstream rebound will depend on execution: if the regulations foster transparency, competitive terms and confidence in governance, the UPRD Act could be a turning point. If not, the sector may settle into a new normal where ambitious independents, rather than supermajors, drive the next chapter of oil and gas development.

Afreximbank arranges a $1.75Billion facility for Angola’s State Oil Firm

Section: In the news · January 29, 2026 · No comments |

African Export-Import Bank (Afreximbank), working with other mandated lead arrangers, has successfully closed a US$1.75Billion syndicated receivables purchase facility for Sonangol, Angola’s state hydrocarbon company.

“The strategic financing will support Sonangol’s projected operating and capital expenditure requirements, while advancing Afreximbank’s mandate to promote African-led financing models that support growth, industrialisation, economic self-reliance, and sovereignty”, the bank says in a statement.

Repayment will come from Angolan production, which averaged 1.06Million barrels of oil per day (BOPD) in November 2025. Sonangol lifted 180,535BOPD in that month, delivering 22,040BOPD to the Luanda refinery and exporting 159,161BOPD.

“The transaction will help Sonangol meet its operating and capital needs, sustain export flows, increase energy availability, and support Angola’s broader industrialisation and economic transformation, while directly contributing to increased African participation in global trade,” says Haytham Elmaayergi, Executive Vice President, Global Trade Bank at the Pan African lender.

Afreximbank says it played “a catalytic, balance-sheet-led role in the financing, structuring, and syndication of the facility”, which is designed to provide sustainable funding to the Angolan oil and gas sector while ensuring strong repayment assurance for lenders.

“ In line with the Bank’s strategy of supporting African business champions in strategic sectors, Afreximbank helped design an innovative, de-risked structure that mitigates oil price volatility and allows for flexible security arrangements.”

The financing is expected to enable Sonangol to meet its operating and capital needs by strengthening export-linked trade structures, supporting Afreximbank’s objective of increasing Africa’s share of global trade and reinforcing the export of strategic commodities.

The facility is expected to support Angola’s economic development by enabling the extraction and commercialisation of natural resources, strengthening export proceeds, and reinforcing industrialisation and value creation across the economy.

Kalaekule First Oil Waits For Reality

Section: In the news · January 18, 2026 · No comments |

A torrent of applause came down on social media in the week of December 15, 2025, responding to the news that the Nigerian offshore Kalaekule field had reached first oil.

The shallow water accumulation is located in Oil Mining Lease (OML) 72, operated by West Africa Exploration & Production (WAEP), an upstream subsidiary of the Dangote Group, in Joint Venture with state hydrocarbon company NNPC Ltd.

“Yes, first oil has happened in Kalaekule field”, a ranking NNPC official confirmed to Africa Oil+Gas Report.

Pressed for details, she admitted: “We do not have a number for the output yet. We are looking for reality”.

The company had estimates before starting the Extended Well Test (EWT).

“Now reality is what comes out. We are testing one string at a time. The important number will be when all the 12 wells (meaning 24) strings) have been tested and we flow the wells together. We can then talk about Kalaekule production”.

Does this then mean that the ovation around the news of Kalaekule field first oil is extremely exaggerated?

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