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Reviewing the majors: Your guide to the 2024 AGMs(Annual General Meeting)

By Gerard Kreeft

Energy investors and shareholders have a diversity of visions which the oil majors— BP, Shell, ENI,TOTALEnergies, Chevron, ExxonMobil and Equinor—will present them at the various AGMs. Below is an overview of what to anticipate. Perhaps not earth-shattering but enough food for thought to give you the reader a better understanding of the energy transition, regardless of your point of view.

The New York Stock Exchange (NYSE) is an excellent barometer to determine the current status of the oil majors (July 2019-March 2024). It is not a pretty picture.

In the July 2019-March 2024 period the Dow Jones Industrial Index rose 50%: increasing from 26,599 to 39,807. Yet the European oil majors have in this same period (with the exception of Equinor and TOTALEnergies), seen their share prices underperforming badly:

BP -10%

Shell -3%

Eni -3%


Equinor + 35%.

In the same period US oil giants Chevron and ExxonMobil have seen their share prices flourish: Chevron up 27% and ExxonMobil 51%.

 Table 1: Stock market prices of  majors July 2019-March 2024 (NYSE – New York Stock Exchange)






Why is it that the share prices of Chevron and ExxonMobil have performed so well and their European counterparts have done so poorly? And why have TOTALEnergies and Equinor been able to maintain investor confidence? Below a company analysis and a series of conclusions which will help explain the seeming paradoxes.

BP: A Takeover prey?

 BP’s faltering share price has in the period July 2019-March 2024 remained on a downward trajectory: from $42 to $38. The company’s history is rather checkered:

BP’s Deepwater Horizon oil spill of 2010 in the Gulf of Mexico has to 2018 cost the company $65Billion;

The company’s withdrawal from Russia in February 2022, because of the Ukraine conflict, meant the loss of 50% of its global reserves; and

In September 2023 the abrupt resignation of CEO Bernard Looney after he admitted that he had not been “fully transparent” about historical relationships with colleagues.

BP meanwhile is promising to spend up to $65Billion on renewables between 2023-2030 and amounting to half of its investments by 2030. Yet the company has written off $540Million of its offshore wind assets in New York.

Will BP be able to meet its renewable energy goal given the long-term slump of renewables and BP’s lingering share price?

What BP was promising originally?

  • An underlying EBIDA (earnings before interest, depreciation, and amortization) of between 5–6% per year through to 2025, with returns in the range of 12–14% in 2025.
  • From 2025 onwards, when its low-carbon projects start to kick in, an expected growth of between 12–14% to be maintained.
  • Its $25Billion divestment would provide the basis for up-scaling its low-carbon business. A pipeline of twenty-five oil and gas projects and an additional eighteen projects in the pipeline were also key factors.
  • Spending $5Billion per year to green itself and by 2030 will have 50 GW of net generating capacity. To date the company has a planned pipeline of 20 GW of green generating capacity.

More recently BP has announced that it is lowering its oil and gas production to be around 2Millionbarrels per day of oil equivalent (2MMBOEPD) by 25% by 2030,  lower than the 40% originally announced. How this will affect BP’s green vision is difficult to predict.

Yet BP’s faltering vision, its downward share price and its low valuation—some $100Billion–makes the company a vulnerable takeover prey.

Shell’s three illusions

The chief obsession of Wael Sewan, Shell CEO since January 2023,  is to drive up the company share price. Yet the share price has barely moved—it was $65 at the start of April 2019 vs $67 March 2024. In his view Shell must mimic Chevron and ExxonMobil. While the Shell share price has remained virtually unchanged, Chevron has seen its share price in the same period  increase 27% and ExxonMobil 51%.

Shell’s total capex for the period 2023-2025 is between $22Billion-$25Billion per year, of which some 80% is earmarked for hydrocarbons. Not unlike Chevron and ExxonMobil.

Sewan is attempting to change Shell’s narrative: that Shell is in the business of producing hydrocarbons, instead of also selling the illusion that its new energy policy matters. Europe’s oil majors, Including Shell, have seen their share prices flounder. Why? Because of their messaging—wanting to appear to be both an oil company and a green energy company.

Illusion 1:The Common Good

In Shell World the company represented ‘the Common Good’.  Year—in-and-Year–Out Shell’s will was seen as law, at least in the Netherlands. For example, the Director-General of the State Mining Authority in the Netherlands, the highest regulatory body for the oil and gas industry, was always a high-ranking Shell manager who took early retirement from Shell and parachuted into his new regulatory role.

Then there is the matter of Shell’s pending appeal regarding its CO2 emissions. In 2021 the court ordered Shell to cut its absolute carbon emissions by 45% by 2030 compared to 2019 levels. Very quickly Shell stated that its emissions issue was a private Shell matter and not a matter of ’the Common Good’.

Illusion 2: Upstream will provide green funding

Prior to Sewan’s leadership Shell had argued that its Upstream pillar ..”delivers the cash and returns needed to fund our shareholder distributions and the transformation of our company, by providing vital supplies of oil and natural gas.”

Yet Sewan is  frank enough to acknowledge that this vision was an illusion. Depending on its upstream portfolio to lead the company to a bright new green future is perhaps central to Shell’s dilemma. Using funding from its upstream division to fund its green energy is in Sewan’s view a non-starter.

Illusion 3: Shell’s LNG global forecasting—back to the drawing board

Shell’s LNG Outlook 2024 forecasts that China will grow its LNG requirements more than 50% by 2040: rising to 23Trillion Cubic Feet (Tcf) in 2040 from 14Tcf in 2023. Yet Shell’s optimism may be premature.

The Institute for Energy Economic and Financial Analysis IEEFA’s Global LNG Outlook 2023-2027 casts a more somber analysis for  future  LNG developments, in particular for China: rising domestic gas production, pipeline gas imports, and renewable power capacity could limit the potential for rapid LNG demand growth over the medium term.

“Lackluster demand growth and a massive wave of new export capacity are poised to send global liquefied natural gas (LNG) markets into oversupply within two years. These two trends are developing even faster than anticipated.”

“Declining Russian gas supplies to Europe, driven by Russia’s full-scale invasion of Ukraine, caused a spike in European LNG imports that sent global prices to record highs. But despite modest new LNG export capacity additions in the last two years, prices have retreated from 2022 levels, largely due to falling demand from developed economies.

In Japan, South Korea and Europe—which account for more than half of the world’s LNG demand—combined imports fell in 2023 and will likely continue falling.

In emerging Asian markets, structural LNG demand growth faces a complex web of economic, political, fiscal, financial and logistical challenges. The global LNG crisis of the last several years heightened those challenges, spurring some Asian nations to reduce the role of LNG in their development plans and accelerate the development of alternative energy sources.”


ENI, the Italian oil and gas giant, is often overlooked in any discussions involving the other oil majors. Yet ENI could be the Joker in the deck providing surprises to an unwitting public and be an upstart which deserves the needed attention. The company operates in the frontier areas seldom mentioned in the daily news media.

For starters ENI produces 1.7MMBOED, has a balance sheet which has an economic leverage of 20%, and has, according to its website,  an Internal Rate of Return(IRR) of 34%, the highest of all its peers  for the 2012-2021. Also, its RRR (Reserve Replacement Ratio) of 110% for the period 2012-2021 is the highest compared to its industry peers.

ENI further states that 90% of exploration capex is spent on near fields and proven basins. Some $11Billion in the last 10 years has been spent on its dual exploration model—near fields and proven basins. The company states that it only requires three years—from first discovery of oil to market—twice as fast as the industry average.

Yet ENI’s stock market price has remained flat in the period July 2019-March 2024: from $33 to $32.

A key ENI strategy  is developing a series of joint-ventures to ensure that ENI can achieve maximum leverage for its current oil and gas assets and at the same pursuing new strategies as part of its energy transition plan. Two examples:

 Vår Energi, Norway was formed in 2018, following the merger of ENI Norge AS and Point Resources AS, owned  by Hitec Vision, a private Norwegian investment fund.  The company’s primary focus is oil and gas developments on the Norwegian Continental Shelf. ENI controls 69.6% of the shares, and HitecVision 30.4%. Vår Energi has production in 36 fields and produces 247,000BOEPD.

Azule Energy, Angola, a 50-50 joint venture between ENI and BP formed in 2022 to include both companies’ upstream assets, LNG and solar business. Azule Energy is now Angola’s largest independent equity producer of oil and gas, holding 2Billion barrels equivalent of net resources and growing to about 250,000BOEPD of equity oil and gas production over the next 5 years. It holds stakes in 16 licences (of which 6 are exploration blocks) and a participation in Angola LNG JV. The company also participates in the New Gas Consortium(NGC), the first non-associated gas project in the country.

 ENI’s North African Gas Hub

ENI’s North African Gas Hub–Algeria, Libya and Egypt–will certainly be a key provider of natural gas to Europe. The three countries together produce 648,000 boepd, approximately a third of Eni’s total global production.


In July 2022, Sonatrach and ENI announced that an additional 141Bcf per year will be exported to Italy via the TransMed Pipeline which is a 2,475 km-long natural gas pipeline built to transport natural gas from Algeria to Italy via Tunisia and Sicily. In 2023 ENI’s production from Algeria was scheduled to rise to over 120,000BOEPD.


The Libyan gas produced by the Wafa and Bahr Essalam fields operated by Mellitah Oil & Gas, an operating company jointly owned by ENI and NOC(Libyan National Oil Company). The gas  is brought to Italy through the Greenstream pipeline. The 520-kilometre natural gas pipeline crosses the Mediterranean Sea connecting the Libyan coast with Gela in Sicily. The natural gas pipeline has a capacity of 283Bcf per year. ENI has a production of 168,000BOEPD in that country.


ENI is operator of the large Zohr field which In August 2019, had a  production of more than 2.7Bcf/d. An important agreement was the restart the of Damietta liquefaction plant which will provide up to 106Bcf in 2022 for European customers. ENI produces 360,000BOEPD.

TOTALEnergies: Providing the lead

The company’s twin growth pillars— developing its low carbon hydrocarbon assets and developing its integrated power business—are key for implementing  its energy transition strategy.

TOTAL is replicating its integrated oil and gas business into the electricity value chain to achieve a profitability of at least 12% ROACE(return on average capital employed) for its integrated power segment, based on an equivalent of $60 per barrel.

TOTALEnergies aims to grow its power generating capacity to 100 GW by 2030: investing $4Billion per year so that by 2030 it will achieve positive cash flow.

By 2050 TOTALEnergies’ energy mix will be:

25% low carbon molecules

50% electricity and renewables

18% LNG

7% oil

To understand the French major’s strategy we must go back to 2020. Then TOTALEnergies took the unusual step of writing off $7Billion in impairment charges for two oil sands projects in Alberta, Canada. Both projects were listed as proven reserves. By declaring these proven reserves as null and void, with one swoop of a pen, TotalEnergies cast aside the petroleum classification system, which was the gold standard for measuring oil company reserves.

The company simply decided that these reserves could never be produced at a profit. Instead, TotalEnergies has substituted renewables as reserves that can be produced profitably.

TOTALEnergies’ strategy was based on the two energy scenarios developed by the International Energy Agency (IEA): the Stated Policies Scenario (SPS), which is geared for the short to medium term, and the Sustainable Development Scenario (SDS), which focuses on the medium long term.

Taking the “Well Below 2 Degrees Centigrade” SDS scenario on board, TotalEnergies has, in essence, taken on a new classification system. By embracing this strategy, the company is the only major to have seen a direct benefit from using the Paris climate agreement to enhance its renewable energy base.

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.

This was the first time that any major energy company 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.

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% became the norm.

But TOTALEnergies’ write-offs 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. TOTALEnergies’ financial team decided those resources could never be developed at a profit.

The company had not abandoned its oil and gas investments. However, its renewable investments were seen as additional 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.

Equinor: Will it maintain its course?

Equinor’s past message of spending more than one-half of its capital spending on low carbon energy by 2030 in offshore wind technology had caught the fancy of its investor community.

Yet the reality could prove to be different. In 2023 the company suffered a loss of more than $750Million on its New York offshore wind projects.

In spite of its loss Equinor’s transformation ambitions, combining a focus on renewable energy with continued high production of oil and gas, will result in a renewable share of 7–12% by 2030. The company aims to produce around 2 million barrels of oil and gas per day in 2030, which is at the same level as in 2022.

 Equinor’s twin pillars

 Will  Equinor’s twin pillars of natural gas and its growing offshore wind portfolio provide the company  the financial depth and ability to achieve maximum leverage for both pillars?

 Equinor’s  goal to grow its offshore wind portfolio to 12–16 GW of installed capacity by 2030 faces a number of severe challenges:

In the past the company had pledged that renewables would receive more than 50% of capital investments by 2030. Now there is no mention of trying to achieve this!

There is severe competition from a number of key European new energy players, who have the economies-of-scale that Equinor can only dream about.

  • ENGIE based in France: will have 80 GW of global renewable installed capacity by 2030.
  • Enel based in Italy: The company’s strategic plan outlines that by 2025 it will have 75 GW of installed capacity; and by 2040 its electricity generation derived solely from zero-emission sources.
  • Ørsted based in Denmark: By 2030 the company will have an installed capacity of 50 GW of renewable power.
  • Iberdrola based in Spain: From 2024–2026, the company will be spending more than $40Billion on renewable energy and has a pending target of 100 GW of installed renewable capacity.
  • RWE based in Germany: By 2030 RWE will have 65 GW of installed wind and solar capacity and net zero emissions by 2040.

Equinor has chosen a series of joint ventures to develop its offshore wind portfolio. The first, Dogger Bank, heralded to become the world’s largest offshore wind farm, is being developed together with SSE Renewables  based in the UK. Located in the North Sea, the project will produce some 3.6 GW of energy, enough to power 6 million households.

Equinor’s Empire Wind and Beacon Wind assets off the USA’s east coast have resulted in a swap transaction with BP. Equinor will take over full ownership of the Empire Wind Lease and projects and BP will take over full ownership of the Beacon Wind lease and projects.

Chevron: Stay vigilant

Aside from its newly acquired asset in Guyana  two-thirds of Chevron’s total production of 3 million barrels of oil will in  2025 come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States  each yielding 1 million barrels of oil equivalent per day.

Today the company has a net value of  over $300Billion, seen its stock price rise to $158 by March 2024, up from $124 in July 2019. A rise of 27%. It anticipates maintaining a capital budget of between $18.5-19.5Billion per annum, which includes capex for affiliates. The company has indicated that $14Billion is devoted to upstream, two-thirds or $9Billion mostly in the Permian Basin and Gulf of Mexico.

Outside the USA, Chevron will spend $5Billion: $1.5Billion to further develop its Tengiz asset in Kazakhstan, with the remaining $3.5Billion spent elsewhere. This is not promising for Africa, where Chevron has major operations stretched across the continent including major projects in Nigeria, Angola, Equatorial Guinea, and Egypt.

Caspian Pipeline Consortium (CPC)

A potentially troubling problem is the Caspian Pipeline Consortium (CPC) which transports Caspian oil from Tengiz field to Novorossiysk-2 Marine Terminal, an export terminal at the Russian Black Sea port of Novorossiysk. The CPC pipeline handles almost all of Kazakhstan’s oil exports. In 2021 the pipeline exported up to 1.3 million bpd(barrels per day). On July 6, 2022 a Russian court ordered a 30-day suspension of the pipeline because of an oil spill. The CPC appealed the ruling and the suspension was lifted on 11 July of the following week, and the CPC was instead fined 200,000 rubles ($3,300).

The incident demonstrates the vulnerability of Tengiz and future production. No doubt this is not the last such incident which involves Russian and Kazakhstan goodwill to ensure that Chevron’s Tengiz Project does not falter. Having to dependent on Russian-Kazakhstan goodwill to guarantee Tengiz production has put Chevron’s  lack of diversity of oil  supply in a very bad light.

 Permian Basin

 A final sour note for Chevron could be its Permian Basin assets. What assurances do we have that Chevron’s Permian Basin adventure will fare better than that of past shale operators?

In a 2021 March report IEEFA (Institute for Energy Economics and Financial Analysis) found the 30 producers generated $1.8Billion in free cash flows in 2020 after slashing capital spending by $20Billion from the previous year.

Since 2010, the 30 companies examined by IEEFA had reported negative free cash flows totaling $158Billion. “The positive free cash flows pale in comparison to the industry’s accumulated debt loads.” The 30 shale producers owe almost $90Billion in long-term debt, and the reductions in capital expenditures are unlikely to ensure that the industry grows.

ExxonMobil: Don’t count your chickens…

ExxonMobil’s vital signs are the following: between July 2019 and March  2024 the stock price at the NYSE has risen from $77 to $116, 51%. The company has a capex of between $23-$25Billion in 2024 and for the period 2025-2027 it will spend annually $22-27Billion.

Good News & Bad News from Guyana

ExxonMobil continues to publish for the world its good news from its offshore Stabroek Block in Guyana: by 2027 a target of 1.2MMBOPD will be pumped, budgeted at a cost of $45Billion. Total recoverable reserves are estimated at 11Billion barrels.

Not mentioned is the price tag.

At the end of five years(2024), according to IEEFA, Guyana will carry a minimum $20Billion outstanding balance owed to its oil producer partners. This amount must be paid, along with other contractually obligated development costs, before the country can fully enjoy any long-term benefits that might materialize.

This is a discussion which must be had in the coming months.

 LNG—A Mixed Blessing

Rovuma LNG was supposed to become ExxonMobil’s futuristic model LNG project. ExxonMobil has recently issued various tenders to move its Rovuma project ahead. Instead, in a matter of months events have overtaken ExxonMobil’s best laid plans.

IEEFA’s recent warning of a global LNG oversupply in the coming five years is not good news!  Will Rovuma make it to the starting gate?

Then there is the matter of ENI’s Coral Sul Project in Mozambique.

The  inauguration of this project deserves special attention. The first LNG shipment of ENI’s Coral Sul FLNG shipment took place in November 2022.

  While Africa’s two  most highly touted LNG projects—Rovuma and Mozambique LNG– continued to be on security hold,  ENI achieved pole  position with its Coral Sul FLNG project.

A Final Investment Decision (FID) is expected to be made on ENI’s  second Coral Sul Project in Mozambique June 2024.

 Key takeaways

BP’s quest to survive is taking precedent over any discussion whether how green the company should be or whether to indeed be an oil and gas company. No doubt the final chapter has yet to be written.

 Shell continues in vain to search for its soul. Anxious to play catch-up with its US rivals—Chevron and ExxonMobil. Yet in hot pursuit of them is no guarantee that Shell’s future will become brighter.

 ENI operates in a very fluid market place and has shown the ability to be diverse and able to provide contrarian strategies. A characteristic needed in a fast-changing energy world. The Joker has not yet dealt his final card.

TOTALEnergies continues to set new precedents for the energy transition:  replicating its integrated oil and gas business into the electricity value chain to achieve a profitability of at least 12% ROACE(return on average capital employed) for its integrated power segment, based on an equivalent of $60 per barrel. By 2030 it will achieve positive cash flow. This is no mean achievement given that the industry average for the electrical sector is 6%.

 Chevron’s key achievement to date has been its relatively stable share price—rising 27% in the period July 2019-March 2024.  A key concern  for shareholders is that two-thirds of Chevron’s total production of 3 million barrels of oil will in 2025 come from just two projects: Tengiz in Kazakhstan and the Permian Basin in the United States  each yielding 1 million barrels of oil equivalent per day. Not exactly diversity of supply.

ExxonMobil in the period July 2019- March 2024 seen its share price increase 51%. Much of the gloating is based on its Guyana offshore project, scheduled to produce 1.2 mbpd by 2027. Yet little is being said about the $20Billion debt which the Government of Guyana must pay in 2024 to settle its cost of developing the Stabroek Block.

Equally concerning is the Rovuma LNG project in Mozambique: IEEFA’s recent warning of a global LNG oversupply in the coming five years could prove to be a challenge for the company.

Equinor has managed to achieve an ROACE of 34% and its share price has risen some 35% in the period July 2019-March 2024. The company’s fallback position is that it is a key provider of natural gas to Europe. Yet its offshore wind sector lacks the economies of scale to compete with companies such as Enel, Iberdrola, Ørsted and RWE.

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.  Gerard has Dutch and Canadian citizenship and resides in the Netherlands.  He writes on a regular basis for Africa Oil + Gas Report, and contributes to IEEFA(Institute for Energy Economics and Financial Analysis). His book The 10 commandments of the Energy Transition is now on sale at  Bookstore






Namibian Oil: “We’re Not Looking for a Knight in Shining Armour”

By Toyin Akinosho, in Windhoek

The Namibian government is keen on accelerated development of the string of huge oil and gas discoveries made offshore the country in the last two years.

The country acknowledges that the path to crude oil development is in early stages and the institutional framework and the Namibian capacity in the sector are a work in progress, but the authorities have signaled that they are neither desperate nor despondent.

“The investors we seek to attract are those who agree that the investment must result into a mutually rewarding relationship that benefits both the Namibian people and the investor”, Tom Alweendo, Minister of Mines and Energy, told delegates at an annual energy conference in Windhoek, the country’s capital.  “Not only will the investor earn a return on his investment, but the investment, in itself, would have assisted to transform the economy into a more complex and dynamic one – something that will better serve humanity.

“It is the savvy investor we would like to attract to our shores, and not a knight in a shining armour who is coming to rescue us from a situation of hopelessness”.

Alweendo, a graduate of Commerce from the South African University of Witwatersrand and the first Namibian national to be the Governor of his country’s Central Bank (1997-2010), said the government had accepted companies who hold oil and gas licences, “to collaborate with us and in return we expect that you earn your license to operate.

“I ask that you tune out the barrage of noise about how Namibia lacks the necessary expertise, or capital, or infrastructure to build a successful oil and gas industry. We want you to adopt a tenacious persistence to make things happen and use your unique perspectives to develop Namibia-specific strategies that will succeed”.

Since the announcement of the basin opening discovery of the Graff accumulation by Shell in February 2022, there have been reportedly bigger finds in the deepwater Orange Basin by (again) Shell, TOTAL, and (the Portuguese explorer) Galp Energia. These subterranean hydrocarbon tanks are now estimated, by the authorities, as collectively holding in excess of 4Billion Barrels of Oil Equivalent.

The industry and the government are “still assessing the commercial viability of these exciting finds”, Alweendo explained. However, “we are confident that the early projections will prove accurate, and that we need to prepare for a hydrocarbon bounty that will turn Namibia into a major oil & gas producer.”

The minister turned on the pressure.

“To those who have made commercial discoveries, we want you to fast-track field development for all discoveries. Although I consider myself a pragmatist, the fact is that we need the resources out of the ground for the oil & gas industry to flourish”, Alweendo told the 1,000 delegates from around the world, including industry professionals from Angola, Nigeria and South Africa (in Africa); France, Britain and Portugal from Europe; the United States, Canada and Brazil from the Americas.

“We need to develop plans now to speed up production as soon as the discoveries are determined commercially viable”.

Petrofac Wins $350Million Service Contract for Equatorial Guinea’s Zafiro Field

London based engineering firm, Petrofac, has been awarded a Technical Services Contract by Compañía Nacional de Petróleos de Guinea Ecuatorial (GEPetrol), Equatorial Guinea’s state hydrocarbon company, to support the operation of the country’s Block B.

Under the contract, valued at around $350Million over five years, Petrofac will deliver technical services across onshore support bases, a Floating Production, Storage Offloading (FPSO) facility and a platform on behalf of GEPetrol, the Operator. The contract draws on the core services of Petrofac’s Asset Solutions division, including operations, maintenance, asset integrity, integrity management, marine services, well engineering, project delivery and supply chain services.

The 2,000 square kilometre Block B hosts the Zafiro oil field, located 68 kilometres WNW of Bioko island, adjacent to the international border with Nigeria. ExxonMobil brought the Zafiro field online in 1996 via subsea wells tied back to the Zafiro Producer floating production unit (FPU). The Zafiro complex is a group of seven mature fields located in the offshore eastern Niger Delta.

The contract signing “marks a key milestone in our journey to becoming operator of Block B on 1 June 2024”, notes Teresa Isabel Nnang Avomo, Director General of GEPetrol. “We are excited to grow our partnership with Petrofac. By unlocking the huge potential of our indigenous national workforce, we will build with Petrofac’s assistance, an organisation for the long-term management and development of our country’s oil and gas assets.”

A fixed platform called Jade was added to the Zafiro complex in 2000 while the Southern Area Expansion project was brought on stream in 2003 using the FPSO Serpentina. ExxonMobil was forced to stop production at the Zefiro field in September 2022 due to severe water infiltration into the FPU Zafiro Producer.

The contract follows Petrofac’s initial scope supporting the transition of the asset from Mobil Equatorial Guinea Inc (MEGI).



The Gasfired Plant is Not Africa’s Default Electricity Generator/Our Latest Issue:  Gas to Wire Annual

Contrary to perception, the default choice for power generation among Africa’s hydrocarbon resource rich countries, is not the gas fired thermal generating plant.

True, there are invitations for partnerships and investments in Senegal, Cote D’Ivoire, Nigeria, even Mozambique.

But growth in natural gas intake for power has been relatively flat on the continent in the last five years, with the exception of Ghana.

Mozambique’s abundant gas reserves have mostly been spoken for; the hydrocarbon molecules will be exported. The country adds more hydropower capacity than install the thermal engine.

Out of Nigeria’s Grid Connected capacity of 12,199MW, in February 2024, which included 21 gas fired plants, only 3,957MW was actually generated. Five hydropower plants accounted for 1,649MW, or 42% of that generation.

We invite you to become a paying subscriber of our monthly harvest and go through a number of operational events: rig activity in detail; production update; market intelligence…

Read your copy here

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. It is also routinely distributed in major conferences focused on the African hydrocarbon investment. This allows wide advertising to the stake holding public. Our website remains, and the contact email address is Contact telephone numbers in the West African regional headquarters in Lagos are +2348124374087, +2348130733523, +2347062420127, +2348036525979, +2348023902519.






Deepwater Performance Most Responsible for Nigeria’s March 2024 Output Decline

By the Editorial Desk of Africa Oil+Gas Report

Nigeria’s seven deepwater fields output an average of 415,392Barrels of Oil Per Day, in March 2024, one of the lowest performances in the last three years.

The 56,575BOPD decrease in deepwater output from the February to March 2024, represents 62% of the country’s total output drop (91,690BOPD) from 1,322,208BOPD to 1,230,518BOPD.

Data released by the Nigerian Upstream Regulatory Commission (NUPRC) indicates that Shell’s Bonga field, which is also the country’s flagship deepwater asset, led the decline by dropping from 124,115BOPD to 95,363BOPD, a 28,752BOPD plunge, representing 31% of the total output drop. TOTAL’s (deepwater) Akpo field shed 17,000BOPD, or 18% of the output gap between February and March 2024.

NUPRC data doesn’t highlight field specific activities, but it is clear that eastern onshore fields, whose crudes are evacuated by the Shell operated Bonny Terminal, are still struggling. Crude receipts at the Bonny Terminal declined by 21,324BOPD, in March 2024, compared with February 2024. In the western Niger Delta, the Chevron operated Escravos Terminal witnessed a small increase in receipts of crude of around 2,000BOPD, from 127,046BOPD in February to 129,442BOPD in March, while the Shell operated Forcados terminal saw an 18,000BOPD decline in receipts month on month.

Basic operational challenges and routine field decline and maintenance, it would seem, played a higher role than the “usual suspects” of vandalism and crude oil theft and pipeline infrastructure, which should have been factored in by now when considering overall crude oil output.

There is no remarkable increase in shallow water production, as indicated by the figures at the ExxonMobil’s Qua Iboe and Yoho Terminals as well as TOTAL’s Odudu, which mostly receive crudes from shallow water fields. Nigerian independent shallow water operators have not yet picked up the slack here, though work is going on in both the Anyala- Madu cluster (First E&P) and Okwok field (Oriental Energy) for the one to increase output and the other to bring new field into production.

The country’s authorities have reached out to the oil majors to invest more in new deepwater developments and a key part of the executive orders on oil and gas reforms signed by President Bola Tinubu in March 2024 addresses this issue with fiscal incentives. But the existing deepwater fields will continue their inexorable decline while any new deepwater field development (like Shell’s Bonga North, being considered for Final Investment Decision by July 2024), is unlikely to each the market before 2027.

The quickest wins remain onshore and in shallow water.

-A public service commentary of Africa Oil+Gas Report.

Work Starts on a New FPSO For Angola’s Newfield Deepwater Development

By Toyin Akinosho

Partners on Block 15/06 in deepwater Angola have carried out the survey and installation of the first modules of the Floating Oil Production, Storage and Transfer Unit (FPSO) for the Agogo field, the country’s regulator has reported.

“These are the first two modules of the twelve (12) that will make up the FPSO Agogo”, the National Oil, Gas and Biofuels Agency (ANPG) says in a statement.

“The others are being built in Singapore, Indonesia and Vietnam”.

The vessel is expected to be delivered to Angolan waters in December 2025.

Azule Energy, the Incorporated Joint Venture between ENI and bp is the operator of Agogo field, with partners including state hydrocarbon company Sonangol and the Chinese behemoth, Sinopec.

“The construction of riser protectors, suction anchors, submarine distribution units (SDU), among other tasks, is reserved for Sonamet’s shipyards in Benguela”, ANPG explains on its website. “The unit will feature technologies that will significantly reduce carbon emissions and improve its operational efficiency”.

Diamantino Azevedo, Angola’s Minister of Petroleum, appealed to the partners to use the operations of the FPSO to reinforce Local Content in the country’s oil sector. “We want them to increase the Angolan workforce and pay special attention to their training, preparing them for major challenges. Likewise, I would like them to make more use of existing facilities and equipment in our country, in order to strengthen our Local Content”, he appealed.

Adriano Mongini, CEO of Azule, said that the Agogo Project will maximize the reserves of Block 15/06 and optimize the Agogo and Ndungu Fields, increasing production to 170 thousand barrels per day.

Petroci in the Market for Jack Up Rig

Cote d’Ivoire’s state hydrocarbon company, Petroci, is asking interested companies to participate in the Request for Information for Provision of Jack-Up Rigs for the purpose of gas development on the Kudu, Eland, and Gnou (KEG) project.

Project Overview:

Location: Approximately 20kilometres offshore from Assouinde, Southeast Ivory Coast.

Project Focus: Extracting, transporting multiphase fluids, and processing onshore gas at an Onshore Processing Plant (OPP).

Anticipated Production: Predominantly gas, condensate, and a limited amount of oil.

The choice of the type of drilling unit to be used will largely depend on the operating characteristic, limitations and availability of rigs, environmental conditions and ultimately economics. You are requested to confirm availability to provide services as per the attached schedule.

RFI Details:

Reference: RFI KEG-0001

Submission Deadline: 04th April at 03:00PM GMT

Submission Method: Email to:

RFI Components:

  1. Technical Questionnaire

Supplier Financial Health Questionnaire

Due Diligence (CDD) Questionnaire

RFI Confidentiality Requirements

Contact for Queries:

For any queries or clarification, please contact Ange Didier KOUTOUAN, PETROCI CI-523/CI-525 Project Manager, at

Immeuble Les Hevéas – 14 Bd Carde, BP V 194 Abidjan Côte d’ivoire

Mob  :+225 07 77 28 96 00  / 05

Procurement: Core or Support Function?

By Blessing Adagbasa

Most organizations operate with a Procurement department tasked with acquiring goods and services essential for their production and service delivery. From basic necessities like stationery to crucial inputs such as raw materials and key service providers, the Procurement department’s responsibilities span a wide spectrum. Its role is pivotal in ensuring organizational success.

Within any organization, various functions collaborate to achieve business objectives. The primary functions typically revolve around generating revenue or facilitating the organization’s income generation process. These functions often include manufacturing/production, sales, and marketing. Conversely, support functions are not directly involved in revenue generation but exist to provide necessary services to the core functions.

Given this framework, the question arises: should the Procurement function be classified as a core or support function? To answer this, it is essential to analyze the roles of core functions and compare them with the traditional and evolving roles of procurement.

Production Input Sourcing: The production function is fundamental to organizations as it takes raw materials and converts them into finished products, a process that remains consistent across different types of businesses. Subsequently, the sales and marketing functions focus on distributing these final products to customers and securing payments. Given this, the production function is widely acknowledged as a core function in most organizations.

If production is considered a core function, it is crucial to recognize the inception of the production process. Typically, the production process begins with the procurement of raw materials and necessary services. The sourcing of inputs marks a critical initial stage in production, and the Procurement function assumes responsibility for procuring and delivering these production inputs. Therefore, Procurement emerges as an indispensable function within the production process and is inherently core to the business.

Cost Reduction and Margins Optimization: Let us examine another crucial aspect of the Procurement function: cost optimization. For organizations to maintain competitiveness and enhance profit margins, the Procurement function must secure goods and services at prices that confer a competitive advantage in the market. Managing input costs stands out as a primary value proposition of procurement, directly influencing the bottom line.

Efficient input cost management, facilitated by procurement, holds the potential to reduce the overall cost of production. Consequently, such cost reductions often translate into improved business profits. It is undeniable that maximizing profitability ranks as a central objective for many businesses, underscoring the significance of effective procurement practices in achieving this goal.

Business Continuity and Security of Supply: The threat of supply shortages presents a substantial risk to business continuity. Procurement professionals play a critical role in mitigating this risk by actively seeking alternative sources to minimize operational disruptions caused by supply chain interruptions or the unavailability of essential materials and services needed for production.

To ensure the security of supply, procurement professionals employ various commercial strategies. These strategies may include establishing alternative sources of materials or services, securing advance commitments from suppliers, and implementing other proactive measures to maintain a steady flow of resources into the production process. By adopting such strategies, businesses can better safeguard against the adverse effects of supply shortages and enhance their resilience in the face of unforeseen disruptions.

Legal and Regulatory Compliance: In most countries, regulatory frameworks are in place to set guidelines for the production and distribution of goods and services within their jurisdictions. Many of these regulations also extend to the sourcing of materials and services necessary for the production process. The Procurement function plays a crucial role in ensuring compliance with these regulations and implementing processes to mitigate identified risks within the supply chain.

Procurement professionals are responsible for understanding and adhering to the applicable regulatory requirements governing the sourcing of materials and services. They establish and enforce procedures to ensure that suppliers meet these regulatory standards and that all procurement activities align with legal and compliance obligations.

By proactively addressing regulatory compliance and risk management within the supply chain, Procurement helps safeguard the organization against potential legal liabilities, reputational damage, and operational disruptions. This ensures that the production and distribution of goods and services proceed smoothly within the boundaries of the established regulatory framework.

In summary, Procurement is indispensable to the core operations of a business, and organizations aiming for sustainable success must recognize it as such. Viewing procurement as an integral part of the business, rather than merely a support function, is essential for achieving business objectives effectively.

Procurement should be given a seat at the table during strategic decision-making processes, as it directly influences the bottom line by managing input costs that impact overall profitability. By acknowledging the pivotal role of Procurement and prioritizing its involvement in key business discussions, organizations can optimize their operations from the outset, ensuring a solid foundation for success. In essence, the journey of a business begins with Procurement, highlighting its significance in driving long-term prosperity and growth.

Adagbasa is a Procurement Manager in the Nigeria Energy Sector


Ghana’s Top Crude Oil Producer in Hefty Loss After Tax

Tullow Oil has reported a loss after tax of $110Million in 2023, after write-offs and impairments totaling $435Million.

The loss compares with a profit after tax of $49Million in 2022. Impairments and write offs in 2022 totaled $391Million.

Tullow’s gross profit of $735Million in 2023 trailed that of 2022 ($1,086Million) by a whopping $351Million.

The company’s 2023 adjusted Earnings Before Interest, Taxes, Depreciation, and Amortization EBITDAX1 crashed by …% to $1,151Million compared with 2022 ($1,469illion).

Worse: Tullow’s free cash flow in 2023 was $170Million, almost a hundred million dollars lower than the previous year (2022: $267Million)

But it wasn’t all doom and gloom in the year under review. The UK junior reports completed major infrastructure project with Jubilee South East brought onstream, marking a material step up in production at Jubilee which surpassed 100,000Barrels of Oil Per day (BOPD) gross.

Tullow talks up its  ”strong operating, drilling and completion performance, with seven Jubilee wells brought onstream and facilities uptime of around 96% in Ghana”.

Tullow also announces that “net debt at year-end reduced to $1,608Million, from $1,864Million in 2022; with cash gearing of net debt to adjusted EBITDAX1 of 1.4 times (2022: 1.3 times); liquidity headroom of $1,000Million (2022: $1,055Million).

Tullow claims material step in refinancing strategy with new $400Million five-year Glencore debt facility, with proceeds available for liability management of the senior notes maturing in March 2025.


“Two Decades Of Organic Growth: The Remarkable Journey Of The “Problem Solving” Century Group”

By Osamede Okhomina


Who would have imagined we would end up here today? That we would end up in an investment regime where oil and gas capital would be so hard to come by. In this era of chasing “renewables” and with the anti-fossil fuel campaigners lobby investment funds to pull out of our sector, oil and gas capital has become a very scarce commodity. So oil companies are scrambling around looking for innovative ways to recapitalize themselves and re-tell their development strategy.  Into this mix, we can now appreciate the foresight of Century Energy who had for nearly two decades had been drumming the story that we all needed to re-invent the way we approached our “use of capital”.  That is, as it’s Group CEO, Ken Etete, would always say, that by “farming out” key elements of our oil and gas infrastructure to companies like his, we could better focus our attention on the sub-surface and leave the heavy engineering to strategic partners like Century. This was Ken’s key Innovation and one that took the industry a relative long while to come to fully appreciate.

Ken’s long journey to establishing Century in this space is not so well known. So let me say a few words on it.

In this dynamic landscape of the oil and gas industry, where volatility is constant and innovation rare, few companies have demonstrated the resilience and adaptability of Century Group. Over the past two decades, Century Group has not only weathered the storms of doubt, non-paying clients, difficult funding regimes and geopolitical tensions, but has also managed, against the odds, to carve out a path of sustainable growth through organic means.

Twenty-two years ago, Century Group began its journey as a modest servicing firm through the flagship – Century Energy Services Limited (CESL) firm – with a hand in only one asset. However, the company’s founder – Mr. Ken Etete, driven by a vision of value redistribution anchored on productivity and a commitment to excellence, laid the foundation for what would become a powerhouse in the industry.

One of the key pillars of Century Group’s organic growth strategy has been its relentless focus on unconventional solutions, innovation, and operational efficiency. From the outset, the company invested heavily in obtaining stakeholder insight (the values and challenges peculiar to diverse energy installations) to unlock the potential of an integrated business which has now given birth to a full-fledged energy infrastructure company supported by sister companies in gas commercialization, offshore logistics support, exploration and productions as well as information technology. By leveraging on its nimble operation principle and philosophy of sharing in the risk of its partners and clients, Century’s flag has been successfully hoisted in several international energy fields both directly and indirectly where it has continually added value to stakeholders. Century Group’s penchant for tapping into previously moribund assets and turning them around has significantly expanded its portfolio and contribution to the sector.

Moreover, Century Group embraced a culture of continuous improvement, fostering collaboration between its operations and commercial teams to optimize asset management, and efficiency and enhance safety standards. In addition to the safe and prudent execution of projects, the company pursued strategic acquisitions and partnerships to complement its organic growth initiatives. By selectively acquiring assets with high potential and forming joint ventures with industry-leading players, Century Group diversified its portfolio strengthened its competitive position within the African market and proudly stands among the top ten FPSO Companies in the world.

Furthermore, the Group prioritized sustainability and people development in its operations, investing in initiatives to enable people and create value to reduce poverty and the associated cost of socio-economic deprivations. By embracing best practices in environmental management and corporate social responsibility, the company not only safeguards the communities and ecosystems where it operates but also enhances its reputation as a responsible corporate citizen.

Two decades on, the fruits of the company’s organic growth strategy are evident. The company has evolved into a diversified energy powerhouse, with a balanced portfolio of assets spanning conventional and unconventional resources across multiple continents. Its robust production profile and operational excellence have consistently delivered value to shareholders, even in challenging market conditions. As Group CEO, Ken has unequivocally expressed his belief that although the business climate is principally volatile, uncertain, complex, and ambiguous (VUCA) the philosophy of “development partners” rather than cutthroat competition is what will mine the best value for all players within the sector. Sabotage, corporate espionage, and unethical practices could only give a head start but not sustain any entity to finish the race which is to optimally promote energy security through the mitigation of associated infrastructural, production, and distribution risks.

Looking ahead, the company still remains committed to its principles of innovation, efficiency, and sustainability as it navigates the opportunities and challenges of an evolving energy landscape. With a legacy built on two decades of organic growth, Century Group is well-positioned to continue shaping the future of the global oil and gas industry for years to come beyond Africa. Over and above all, Ken’s near obsession with cost cutting has made him a darling to Oil and gas CEOs and shareholders. In Ken’s mantra, “why travel along with a Rolls Royce on a journey a where a well airconditioned VW can do just as well!”

About the Author: Osamede Okhomina is a graduate from Cambridge University and former CEO of private and public oil and gas companies. He is now a Principal Adviser to company CEOs and assists them in capital raising and formulating strategy.

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