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The Clock is Ticking for Nigeria’s Petroleum Reserves/Our Latest Issue

Time is running out for Nigeria to take the full advantage of its hydrocarbon deposits, which it had largely exported in the raw for over 60 years.

A new administration took office on May 29, 2023 and immediately dispensed with subsidy of gasoline importation, which had drained the treasury for several decades.

It’s a start, even though the country still has several months to go before the first products from the gigantic Dangote Refinery 650,000BSPD) are likely to roll out and ensure ample, domestic production of fuels.

And there is just about 12 years to the beginning of the end of the fossil fuel era.

Nigeria desperately needs to convert its vast gas resources into products that energise the economy; but the state hydrocarbon company has been a chokehold to development; two crucial grid length, natural gas pipelines, which should enable evacuation to power plants and industries, have been under construction for close to 15 years. A third one, for which installation started two years ago, is facing severe headwinds.

As oil majors leave the country’s onshore and shallow water assets, Nigerian independents are coming in. With very few exceptions, the overall performance of the Independents is poor and is a large reason for the continuing low crude oil output.

How does the new President, Bola Ahmed Tinubu get Nigeria to leap into the light?

Read your copy here

We also interrogate the lack lustre performance of Nigerian independents.

The Africa Oil+Gas Report is the primer of the hydrocarbon industry on the continent. Published by the Festac News Press Limited since November 2001, it is a paid subscription based monthly, hardcopy and pdf publication delivered around the world. Website is Contact email address is Contact telephone numbers in our West African regional headquarters in Lagos are +2348130733523, +2347062420127, +2348036525979, +2348023902519.



Congo’s Boatou Marginal Field Reaches First Oil 40 Years After Discovery

Perenco operated Boatou field offshore Congo Brazzaville is now in production.

The French owned, London headquartered independent hooked up four new production wells on the Boatou permit between March and May 2023, thirty-nine years after the field was discovered with Boatou-1, by Elf, one of the precursors of TOTALEnergies.

Perenco took the advantage of the field commissioning event to announce a new 20-year operating permit for Boatou.

Although the field’s start-up output of 4,500Barrels of Oil Per Day is 5% of the company’s gross output for 2022,  Perenco says it is “committed to assessing and developing” Boatou further, along  with its partners; SNPC, (Société nationale des pétroles du Congo -the National Petroleum Company of the Congo), Africa Oil and Gas Corporation (AOGC) and PetroCongo.

The Boatou field is situated 55km off the coast of Pointe-Noire in the Republic of Congo, and 7km from the neighbouring infrastructure at Likouala.

“These four wells, which were put into production forty years after discovery,” declares Stéphane Barc, General Manager, Perenco Congo, adding:  “Finding tailor-made solutions for marginal fields,delivering them quickly, efficiently, and safely, points to a very promising future in the Republic of Congo”.

Perenco operates Boatou with 75% state;  SNPC  holds 15%, AOGC 5% and PetroCongo 5%.


‘OPEC+ Chooses to Keep Current Output But Saudi Will ‘Sacrifice’ Some

By Rystad Energy

The OPEC+ group of oil exporting countries has decided not to implement additional official production cuts in 2023, choosing instead to set a new and lower target production for 2024.

Saudi Arabia however announced an additional voluntary cut of 1Million barrels per day in July that can be extended, to help shore up oil prices after crude oil dropped 16% in the past seven weeks to an 18-month low.

All nine countries that implemented voluntary cuts in April of 1.66 million bpd (Saudi Arabia, Iraq, UAE, Kuwait, Oman, Algeria, Kazakhstan, Gabon, and Russia) agreed to extend the cuts by a year, until the end of 2024.

This move will add limited short-term upside price pressure in the coming weeks, according to our projections.
The long-term price development will hinge on macroeconomic sentiment and the possible extension of the voluntary Saudi Arabian production cut beyond July.
The pure possibility of the Saudi production cut extending beyond July will limit downside price pressure for the rest of 2023.


  • OPEC+ held its 35thMinisterial meetingJune 4 2023 and decided not to implement additional production cuts this year, despite the increasing rumors in the run-up to the meeting that a 1 million bpd cut was being negotiated.
  • The group decided to provide guidance into its production management strategy for 2024. The current production target of 40.1 million bpd is for the period from November 2022 until December 2023.
  • The new target production for 2024 is 38.7 million bpd, which is 1.4 million bpd lower than this year’s target. The new target production numbers for 2024 include a significant reduction for Russia (650,000 bpd), Nigeria (360,000 bpd) and Angola (175,000 bpd), among others, and a 200,000 bpd increase in the UAE’s target production (Figure 1).

  • Saudi Arabia announced a voluntary cut of 1 million bpd (on top of the 500,000 bpd voluntary cut announced in April, running from May until December 2023). This new voluntary cut is planned for July only, but Saudi Arabia was very clear in saying that these cuts could be extended. Saudi crude production in July would drop to just below 9 million bpd, its lowest level since June 2021.
  • Macroeconomic headwinds have kept the crude oil price well below $80 per barrel in May, despite the OPEC+ voluntary cuts which initially pushed price to $87 per barrel in mid-April. The oil price fell to $73 per barrel just a few days ago, its lowest level since late 2021.
  • When seven OPEC+ countries surprised the market with the announcement of voluntary cuts of 1.66 million bpd voluntary cuts (including 500,000 bpd from Russia) in early April, oil prices increased by $7 per barrel in one week – but this effect completely faded away in just four weeks as macroeconomic factors again took over as the main driver of the crude oil price (Figure 2).

  • Before the meeting, our modeling showed that even if OPEC+ were to keep the current production policy in place for the rest of the year, we believed the market would tighten significantly in the third quarter of this year. This would add significant upside price pressure until the end of 2023.
  • The additional Saudi voluntary cut of 1 million bpd in July, with the option to extend, is likely to deepen the market deficit to more than 3 million bpd, which could add upside pressure in the coming weeks (Figure 3).

  • The 36thOPEC+ Ministerial Meeting is planned for Sunday 26 November 2023, in Vienna.


  • Possible extension of the Saudi voluntary cut of 1 million bpd, initially planned for July only.
  • Macroeconomic risk and the evolution of global demand as refineries ramp up to meet summer demand in the US and Europe, while mainland China’s local demand accelerates again.
  • Future Russian compliance with its voluntary cuts.

Rystad Energy is one of three independent research and analysis companies that OPEC+ partners with for data and production capacity estimates.



Angolan Output Rebounds Above 1MMBOPD

Angola’s crude oil production returned to slightly above 1Million Barrels of Oil Per day in April 2023, Its 1.055MMBOPD for the month was 85,523BOPD higher than the daily average of 969,646BOPD achieved in March 2023, but was still less than the 1,063,589BOPD produced in February 2023.

Associated gas (AG) output was also higher at 2.7Billion cubic feet of gas per day (2.7Bscf/d), a lear 300MMscf/d over the March 2023 output of 2.4Bscf/d.

Most of this gas (1.5Bsf/d) was injected though, with 656MMsf/d going to the Angolan LNG plant; 327MMscf/d used for power generation in oil installations and the remainder used in operations and oil disposal and

Read further



IMF Looks Favourably at Libya’s Economy, Oil & Gas Production

The International Monetary Fund (IMF) expects Libya’s hydrocarbon production to grow by around 15% in 2023 following an increase in oil production from 1Million barrels per day in 2022 to around 1.2Million barrels per day in 2023 and increase gradually thereafter.

“Libya’s economic fortunes will hinge on oil and gas production for the foreseeable future”, the fund says in a report by the Executive Board of Fund, which concluded a consultation with Libyan officials on Wednesday, May 24, 2023.

Looking ahead, assuming fiscal spending remains contained, the baseline projection is for fiscal and external surpluses to gradually decline over coming years. The key risks to the outlook are lower oil prices due to lower-than-expected global growth, and renewed conflict and/or social unrest that leads to disruptions in oil production.

A rebound in oil prices and the resumption of oil production after the deleterious intervention of COVID 19 has resulted in budget and current account surpluses in both 2021 and 2022. Gross Domestic Product—which closely tracks oil production—remained volatile. Inflation has been relatively subdued despite a sizable depreciation of the dinar in 2021 and rising global commodity prices, rising from 2.9 percent in 2021 to 4.5% in 2022.

Libya is heavily reliant on oil and gas production, and therefore subject to considerable volatility and downside risks from the global green transition. IMF Directors noted that the key medium-term challenge is to diversify away from hydrocarbons and to promote stronger and more inclusive private sector-led growth. They encouraged the authorities to enhance transparency, strengthen institutions and address corruption and governance concerns to support these efforts. Directors highlighted the importance of enhancing data provision and statistical capacity.

IMF calls for an agreed and transparent budget to support policy credibility and macroeconomic stability and help preserve intergenerational prosperity. They noted the importance of improving public financial management, avoiding procyclical spending, diversifying the tax base, gradually reforming untargeted energy subsidies to make room for additional social spending and infrastructure development, strengthening management of state-owned enterprises, and building a medium-term framework.

The Fund observes that reunification of the central bank is crucial for strengthening monetary policy, supporting financial stability, and fostering private sector development. It notes that frequent changes to the currency peg should be avoided to maintain confidence in the exchange rate as the nominal anchor. Maintaining the peg would also allow the central bank to better protect foreign exchange reserves amid elevated political and security risks.


ENI: Plan for the Worst and Hope for the Best!

By Gerard Kreeft

Claudio Descalzi, was recently re-appointed Chief Executive Officer (CEO) for a fourth term by ENI’s Board of Directors. He has been CEO since 2014, making him one of the longest serving CEOs in the industry. Under his command the company has become a dominant voice in the industry, especially in the frontier areas of Africa and Asia, seldom covered by the media.

It is time to reflect on his reign and what to anticipate in the coming period. Perhaps a very bumpy road to 2050.

For starters the company produces 1.7Million barrels of oil equivalent per day (1.7MMBOEPD), 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 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, like the other oil majors, has performed badly in the period between January 2018 and April 2023. While the DOW Jones Industrial Index rose 35% (25,295 to 34,098) in this period, the ENI share and most of the European majors, with the exception of Equinor, have underperformed dramatically. In this five-year period , the ENI share price has, for example, decreased  14%. Other European stocks also decreased: Repsol down 18%, BP down 7%, Shell down 10%, and TOTALEnergies remained the same. Only Equinor was up 26%. In the same period US oil giants Chevron and ExxonMobil have seen their share prices flourish: Chevron up 32% and ExxonMobil 36%.

Table 1: Stock market prices of  majors Jan 2018- April 2023(NYSE – New York Stock Exchange)




Why is it that the share prices of  Chevron and ExxonMobil have performed so well and their European counterparts, including ENI, have done so poorly?

The message from the investor community is the clarity of the message. Chevron and ExxonMobil have as their mainstay–the production of hydrocarbons and this is the message that is preached. New energy policies including CCS (Carbon Capture and Storage) and other new energy initiatives make up only  between 15-20% of their capital budgets. In the case of Chevron some $3Billion per year based on a capital budget of $15-$17Billion; ExxonMobil’s new energy comes in at $3Billion per year based on a capex of $23- $25Billion. The message is clear and simple: we are oil companies pure and simple. Done in the good tradition of John D. Rockefeller the spiritual father of both companies.

European oil giants, have seen their dualism—wanting to maintain their green image and also profiting from the oil bonanza—fall out of favor by company shareholders. Their clarity of messaging has been found wanting.   The sole exception is Equinor who have stated that the majority of their capex budget will be from renewables by 2030.

ENI’s Strategy

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. Three 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 247,000 boepd.

Vår Energi has entered into a collaboration with Odfjell Oceanwind and Source Galileo to pursue a pilot project for floating offshore wind at Goliat. The Goliat platform is currently electrified and is supplied with power from shore through a power cable with a capacity of 75 MW. The purpose of the project, which is called GoliatVind, is to use the cable as infrastructure for electricity to the mainland and increased renewable power generation in Finnmark, Norway.

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 250,000 barrels equivalent per day (boed) 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.

An interesting footnote: “The JV incorporation took place after the pending conditions were met, among them having secured a third-party financing of $2.5Billion in the form of Pre-Export Financing, and after receiving regulatory approvals.” In other words, any financing of Azule Energy will not be reflected in the ENI and BP balance sheets.

Plenitude, ENI’s new company, launched in June 2022 is an integrated business combining the generation of electricity from renewables, the sale of electricity, gas and energy services to households and businesses, and a European network of charging points for electric vehicles.

Plenitude had an installed renewables generation capacity of 2.3 GW and a pipeline of renewables projects of over 10 GW, a retail portfolio of 10 million clients and an electric vehicle charging network of 7,300 proprietary installed charging points (excluding inter-operational charging points).

“The cash flows from the retail business area will underpin the growth of the business, with the Company having sufficient leverage capacity to independently achieve its targets through a strong balance sheet and an investment-grade profile. Sustainability is at the core of Plenitude as it plans to achieve Net Zero by 2040.

ENI considers the IPO an important step in the development of PlENItude. The IPO will enable the Company to diversify its ownership structure, create a long-term shareholder base, access competitive funding, consolidate its positioning and develop more quickly while creating sustainable value for all stakeholders.”

Will PlENItude be given a more important strategic role in the coming years to ensure that ENI can achieve its energy transition role?

ENI’s Dexterity

On 23 November 2022, the President of Mozambique, Filipe Jacinto Nyusi, visited and inaugurated the ENI’s Coral-Sul FLNG installation. The event took place after the shipment of the first LNG cargo on 13 November from Coral Sul FLNG. ENI’s Coral Sul FLNG project’s inauguration deserves special attention. Especially at a time when the two of the country’s most highly touted LNG projects—Rovuma and Mozambique LNG– continue to be on security hold.

While LNG markets in 2023 are scrambling to meet European and global gas demands, there has been radio silence on two of Africa’s most touted LNG projects located in Mozambique: Rovuma owned by a consortium consisting of ExxonMobil, ENI, China National Petroleum Company, Galp, Kogas and ENH; and Mozambique LNG owned by TOTALEnergies, Mitsui Group, ENH, ONGC, Bharat Petroleum, PTTEP, and Oil India.

ENI’s pole position that the company has achieved with its Coral South project cannot be underestimated. With a long-term predicted weakened global demand for LNG, both ExxonMobil and TotalEnergies may have to go cap-in-hand to ENI to discuss possible project options.

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 650,00BOEPD, approximately a third of ENI’s total global production.


In July 2022 Sonatrach and ENI announced that an additional 4Billion cubic meters per year (Bcm/y) 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. Built in 1983, it is the longest international gas pipeline system and has the capacity to deliver 30.2Bcm/y of natural gas.

ENI recently  announced that it has agreed to acquire BP’s business in Algeria, including the two gas-producing concessions “In Amenas” and “In Salah” (45.89% and 33.15% working interest respectively).

In 2023 ENI’s production from Algeria is 130,000BOEPD.


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  8 bcm/y. ENI has a production of 168,000 boepd.


ENI is operator of the large Zohr field which In August 2019, had a  production of more than 2.7Billion cubic feet of gas per day (Bcf/d). An important agreement was the restart the of Damietta liquefaction plant which will provide up to 3 bcm in 2022 for European customers. ENI produces 360,000BOEPD.

The Kazakhstan Connection

ENI has been present in Kazakhstan since 1992  and is a co-operator of the Karachaganak producing field in which it has a share of 29.25% share; and is a partner of the North Caspian Sea PSA (NCSPSA) consortium which operates  the Kashagan Project.  The success of both projects is dependent on the goodwill of both Russia and Kazakhstan. ENI production in Kazakhstan is 145,000 boepd.

The Karachaganak Project produces approximately 45% of Kazakhstan’s natural gas. Peak production reached 155Billion cubic feet per year and oil production of 100,000 bopd(barrels oil per day). An important part component of this project is the Karachaganak Orenburg Transportation System (KOTS) connecting

the Karachaganak field to the Orenburg Gas Plant (OGP) in the Russian Federation. Two pipelines of 28 inches in diameter transport sour gas to OGP for further treatment. In addition, there are three 14-inch lines of which one is a liquid export line and two are dual service and transport either unstabilised liquid or sour gas.

The Kashagan Field discovered in 2000 has approximately 13Billion barrels of recoverable reserves. The project has from the start been hampered by harsh weather conditions including sea ice in the winter, temperatures varying from -35C to -40C, extremely shallow water and high levels of hydrogen sulphide, together with project delays, mismanagement and disputes. In 2012 it was designated as the main source of supply for the Kazakhstan-China oil pipeline. CNN Money had estimated that field development had cost $116Billion, making it the most expensive energy project in the world. No wonder cynics named the project ’Cash-is-Gone’.

Caspian Pipeline Consortium (CPC)

An equally troubling problem is the Caspian Pipeline Consortium(CPC) which transports Caspian oil from Kazakhstan 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 1.3MillionBPD(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 future production. No doubt this is not the last such incident which involves Russian and Kazakhstan goodwill to ensure that Kazakhstan’s oil and production does not falter. Being dependent on Russian-Kazakhstan goodwill is the most brazen example of a lack of diversity of oil  supply.

Some Final Considerations

ENI is a company that can be admired because of the joint-ventures it has established to date, its contrarian decentralized management style, and its symbolic race to become green. Yet there is a  need to establish a more central message. Much too much of a central green message has remained at the decentralized level of its joint ventures. In effect reducing any message that top management wants to send to shareholders. Consider the following aspects:

Going Green

If ENI is to be a serious contender in the Green Race it must ask whether it continues down the road of its current European duality: wanting to be green through its PlENItude subsidiary and also maintain its core mandate that of producing hydrocarbons. To date only Equinor has found a doable solution: announcing that by 2030 the majority of its capex will be based on renewable fuels.  Will Plenitude become ENI’s green vehicle in the energy transition?

Meanwhile the European competition has not been sitting idle:

Enel: committed to achieving CO2 neutrality by 2040 instead of 2050, achieving 75% of electricity from renewables and 80% digitalization of its customers on the grid  by 2025. and having an installed generating capacity of 75GW by 2050.

Engie: pledged to reduce to CO2 neutrality by 2045, 45% of investments is focused on renewables and by 2030 will have 80GW of installed generating capacity.

Iberdrola: in the period 2023-2025 the company will invest $50Billion and achieve net zero for Scope 1, 2 and 3 before 2040. By 2030 the company will have installed capacity of 100GW, valued at $70Billion.

Note: Essentially, scope 1 and 2 are those emissions that are owned or controlled by a company, whereas scope 3 emissions are a consequence of the activities of the company but occur from sources not owned or controlled by it.

Ørsted: the Danish wind energy pioneer, continues to set new records. Ørsted share price in December 2022 was $93; five years earlier in 10 June 2016 it was $37. By 2030 the company’s goal is to have an installed capacity of 50GW. Ørsted is also involved with the building of two energy islands– Bornholm and North Sea– which will deliver 10GW of power.

What has set these companies apart is that they have created a huge competitive advantage which will be hard to challenge for newcomers. Moreover, they have moved well beyond simply dabbling in green energy. These companies have become specialists and now moving on to the next level: creating a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems. Essentially borrowing a chapter from Uber, which does not own taxis or Booking, which does not own hotels. Creating a digital platform on which value does not reside in owning resources but rather in managing data-driven ecosystems.

How will shareholders react to  these companies in 2023?  To date there is good news and bad news for green energy companies.

Table 2: Stock market prices of new energy companies  Jan 2018- April 2023


Enel, the Italian power company has seen its share price increase by 40%. Engie, the large French energy giant has seen its share price remain flat . Iberdrola, the Spanish power company has had an increase of 86% and Ørsted, the Danish power company, has seen its stock soar by 82%.

ENI’s Joint Ventures

The Vår Energi  and Azule Energy joint ventures demonstrate that ENI is willing and able to put together decentralized entities in diverse settings and still  maintain management control. Do not be surprised that additional JVs will be commissioned.

In the future ENI’s North African Gas Hub–Algeria, Libya and Egypt—will probably become more integrated as it continues to provide natural gas to Europe.

What could provide the company additional problems is its multi-party relationship in Kazakhstan dependent  on the good will of the Governments of both Kazakhstan and Russia and the Karachaganak and  Kashagan Partners.

ENI operates in a very fluid market place and has shown the ability to be diverse and able to provide contrarian strategies. The company has a divergent portfolio yet it lacks an overarching strategy which provides a roadmap to its 2050 low carbon deadline.  Such a roadmap should provide clarity of message which no doubt would help bolster its share price.

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

Egina Slides Deeper, Desperate for The Floor

By Johnson Otalo

The Egina field in deep offshore Nigeria has plunged further lower than the symbolic 100, 000Barrels of Oil Per Day

Its April 2023 output of 91,266BOPD is an even stronger signal of its  unrelenting pace of decline since plunging to 145,000 Barrels of Oil Per Day BOPD, as of March 2022, a clear 25% decline in two years of production

The field commenced production in December 2018 and peaked at 200,000BPD in mid-2019.

Peak output, as a rule, for a field its size, (>500Million barrels estimated recoverable reserves) should take at least three years before descent.

On the contrary, Nigeria’s “youngest” large sized deepwater development started crashing rapidly from peak output in 2020.

The field now delivers less than Chevron operated Agbami and Shell operated Bonga complex, both of which have been in production for over 12 years.

Egina’s rapid fall contrasts the argument that Nigeria’s output decline is largely the result of pipeline sabotage, which obstructs evacuation from the flowstations to the terminals. It also challenges the notion that wells shut in out of economic or physical challenges are the major culprits for the country’s production slide. What this precipitous drop calls for is massive investment in new field development away from easy targets of saboteurs.

TOTAL has commenced a nine well drilling campaign including seven development and two exploration wells to halt the decline, but it’s not clear if hook up of the new producers has commenced.

This story is an updated and abridged version of the one published in the March 2023 edition of Africa Oil+Gas Report, released to paying subscribers. It is here as a form of public service.


BNP Paribas, an African Favourite: No More Financing of Independents, and New Oil and Gas Fields

By Macson Obojemuinmoin

BNP Paribas, which has been in the process of exiting fossil fuels for several years, is accelerating the financing of low-carbon energy.

A key part of that is immediate phasing out of financing to independent oil companies for projects intended to support oil production (corporate financing or RBL.

“As a founding member of the Net-Zero Banking Alliance, BNP Paribas no longer provides financing dedicated to the development of new oil and gas fields and continues to decarbonise its loan portfolio”. the company says in its most recent update.

The group, known for several years to have been more tolerant of oil and gas transactions in Africa than most of its peers in the Western Hemisphere,  says that its pull back from financing of new oil and gas fields is “regardless of the financing methods”. The Bank has also updated its oil and gas sector policy to reflect this.portfolio. The Group presented its new emission reduction targets for the steel, cement and aluminium sectors in its Climate Report.

At the end of September 2022, the Group’s financing for these projects was already 20% higher than that of fossil fuels, with the objective of devoting 80% of its financing to low-carbon energy by 2030.

To support the economy in its transition to low-carbon, BNP Paribas acts to limit greenhouse gas emissions from its loan portfolios. The Group thus makes strong commitments, aligned with the International Energy Agency’s “Net-zero 2050” scenario, in the sectors with the highest emissions.

BNP Paribas will reduce its financing of oil exploration and production by 80% by 2030 as follows:

– No longer providing any financing dedicated to the development of new oil fields (including project financing, RBL, FPSO;

– Phasing out financing to non-diversified oil exploration and production players (independent oil companies) which is intended to support oil production (corporate financing or RBL);

– Reducing the share of the general corporate-purpose facilities which is allocated to oil exploration and production.

As regards gas exploration and production, BNP Paribas will cease all financing dedicated to the development of new fields. As announced on January 24th, 2023, BNP Paribas is committed to reducing financing for gas exploration and production by more than 30% by 2030 (vs. September 30th, 2022 baseline).

As part of its 2022 Climate Report, BNP Paribas has set new portfolio alignment targets in three key sectors. These targets are informed by the International Energy Agency’s Net Zero Emissions (IEA NZE) by 2050 scenario and are set for 2030, which is considered as the appropriate time horizon when taking into account the respective industries’ decarbonisation inflexion points:

– Steel: a 25% emission intensity reduction vs. 2022 in order to reach 1.2 tCO2/t crude steel.

– Aluminium: a 10% emission intensity reduction vs. 2022 in order to reach 5.6 tCO2e/t aluminium.

– Cement: a 24% emission intensity reduction vs. 2021 in order to reach 0.51 tCO2/t cementitious products.

BNP Paribas confirms that it remains on track with the trajectories announced in 2022 for its first three sectors of focus:

– Oil and gas:  12% reduction in financing for oil and gas exploration and production at year-end 2022 vs. 2020 (targeted 12% reduction by 2025 substantially achieved); emission intensity of 67 gCO2e/MJ at year-end 2022, with a target of <61 gCO2e/MJ by 2025.

– Power generation: financed technological mix of energy sector comprised of 60% renewable energies at year-end 2022 (target of over 66% by 2025) and 7% coal (target of less than 5% by 2025); emission intensity of 179 gCO2/kWh at year-end 2022, with a target of <146 gCO2/kWh by 2025.

– Automotive: increase in the share of electrified vehicles financed in the total automotive portfolio to 14% at year-end 2022, with a target of reaching >25% by 2025; emission intensity of 167 gCO2/km (WLTP) at year-end 2022, with a target of <137 gCO2/km (WLTP) by 2025.

“As BNP Paribas continues to align its loan portfolio with a net zero trajectory, the bank reiterates one of its key objectives from its GTS 2025 plan: to position the Group as a leader in the energy transition, with a target of deploying €200Billion to support its clients’ transition to a low-carbon economy by 2025[5]. BNP Paribas remains both strongly committed to and on track to meet its goal. This is reflected in its n°1 position in worldwide green bond issuance in 2022 ($19.5Billion[6]) as well as in 2023 year-to date ($9 Billion, in addition to $14.2Billion in sustainable bond issuance)”, the company explains.


“Teach Us How,” Namibians Seek Angolan Help in Hydrocarbon Development

Namibia’s petroleum officials have signed a Memorandum of Understanding (MoU) with their Angolan counterparts, essentially about holding their hands in navigating the terrain of regulating the development of the series of oil discoveries Namibia is walking into. The MoU, between Namibia’s Directorate of Petroleum Affairs and Angola’s National Petroleum, Gas and Biofuels Agency (ANPG) aims to promote bilateral cooperation in the Oil and Gas sector between the institutions, based on mutual benefits between the two countries, strengthening and intensifying cooperation in the Oil and Gas Industry.

“We are going to train the Namibians so that they can assume the responsibility of producing in Namibia”, remarks Paulino Jeronimo Chairman of the Board of Directors of ANPG. “The training will not take place in an office, but in a task force because we have accumulated experience with different operators and we want to make use of this aspect to help in the training of Namibians. Remember that the national workforce in Angola is 80% and it is our expectation that Namibia will gradually reach this level”.

The MoU was inked in the course of the Namibia International Energy Conference held in Windhoek, under the motto “Shaping the future of energy for value creation”.

Namibia has hosted a number of huge discoveries of oil and gas in its deepwater acreages since 2021. By some analysis, the large tanks encountered by Shell and TOTAL under the Namibian portion of the South Atlantic could hold up to six billion barrels of hydrocarbons. But the country has never seen any hydrocarbon discover through to development.

Namibia and Angola will now, after this agreement, move on elaboration, approval and execution of the Action Plan, according to a release by the ANPG.

The MoU follows up on an earlier MOU signed between the Ministry of Natural Resources, Oil and Gas of Angola and the Ministry of Energy and Mines of the Republic of Namibia, on the 29th of November last year, during the Angola Oil and Gas Conference.

The Angolan delegation, headed by the Chairman of the ANPG, was made up of the Executive Director, Belarmino Chitangueleca, the Director of Negotiations, Alcides Andrade, the Coordinator of the Biofuels Nucleus, Vita Mateso, Exploration and Negotiation Specialists, Adriano Sebastião and Hermenegildo Buila, respectively, as well as technicians from various areas assigned to the Concessionaire.

Missed Opportunities in Gas to Wire/Our Latest Issue

The gas to power market is large in North Africa.

It is growing fast in Ghana and has shown encouraging uptick in Tanzania.

Nigeria is punching below its weight, running a distant third after Egypt and Algeria, even with much more abundant gas resources than either of them and more than double the population of each of these two countries.

Namibia has had a great opportunity to take the tide at the brim, but it has been shy to grab it.

Mozambique has everything to take off in the sector, but it has very little ambition.

South Africa keeps fiddling with the chance to become a massive gas fired economy, and has shown either cluelessness about, or utter disdain for, developing either imported gas or local discoveries.

Read your copy of our latest monthly issue

We have stories in this edition, of the broken link in the line from the well head to the Power Plant in Nigeria; the energy challenges facing Egypt and the “good problem” North Africa has in choosing between export to nearby Europe or responding to growing appetite at home

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 e-copy publication delivered around the world. Its 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.

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