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Eskom Prepares to Issue Gas-Supply Request for Proposals (RFP)


By Kelly-Ann Mealia, Co-Founder and Chairperson, Energy Capital & Power (www.EnergyCapitalPower.com)

State-owned utility Eskom has announced plans to issue a request for proposals for the supply of gas to its Ankerlig and Gourikwa open-cycle gas turbine power stations, as well as potentially repower some of its decommissioning power stations in Mpumalanga province using gas-to-power technology

As South Africa experienced Stage 4 load-shedding in the week of May 1, 2022, state-owned utility Eskom announced plans to issue a request for proposals (RFP) for the supply of gas to the Ankerlig and Gourikwa open-cycle gas turbine (OCGT) power stations in the Western Cape province. The power stations, which generate electricity from diesel, currently operate during peak periods and for emergency purposes only. South Africa has experienced load-shedding since 2008, whereby electricity supply is deliberately interrupted as a measure to prevent total collapse of the national grid and is most recently sitting at over 15,000 MW of total unplanned outages.

The announcement comes at a critical point in South Africa’s gas expansion agenda. Not only is natural gas being positioned as the solution for a constrained grid, but also as a transition fuel away from coal, which accounts for more than 85% of domestic power generation and classifies the country as the 14th largest emitter of greenhouse gases globally. Within its Integrated Resource Plan, the South African government has targeted gas technology for the generation of 6,000 MW from combined-cycle gas turbines – of which 3,000 MW will come from LNG-to-power, 726 MW from gas-to-power and 1,500 MW from non-specified gas. Domestic gas demand is expected to double by 2040, driven in large part by the power generation sector, in which gas is expected to increase its share from two percent of the power generation mix in 2020 to eight percent in 2040.

The Ankerlig Plant: Eskom has indicated that it plans to continue to operate the OCGT plants below capacity, which would diminish profitability for potential power producers. As a result, the national utility has expressed interest in implementing either a Public-Private Partnership (PPP) or Independent Power Producer model for the power stations to help procure capital and utilize innovative financing mechanisms.

While climate activists have charged for the complete elimination of fossil fuels from national energy matrices, South Africa and its leaders maintain that natural gas, as a relatively clean-burning fuel, is not only integral to the country’s economic growth, but also to its ability to execute a sustainable energy transition. During an address at the 2022 Investing in African Mining Indaba, President Cyril Ramaphosa stated that the continued exploration and development of South Africa’s oil and gas resources remain critical to achieving energy security, fostering social and economic development and eradicating energy poverty, as well as enabling the country’s transition to a low- or zero-carbon future. Natural gas, for instance, can be utilized as feedstock for the production of agricultural chemicals, methanol, ethylene, propylene and a wide variety of petrochemicals used in refining and manufacturing processes. Enabling South Africa to harness its own hydrocarbon resources in the form of natural gas liquids and naphtha would be transformative for a country in need of mass industrialization, job and wealth creation and economic diversification.

Yet South Africa’s road to gas-to-power is proving far from easy. On one hand, the country currently lacks a sufficiently large or reliable enough domestic gas supply to fuel its energy transition on its own. While recent offshore gas discoveries including the Brulpadda and Luiperd prospects have shown promise, along with pockets of shale gas in the Karoo Basin, the country imports more than three-quarters of its natural gas supply by pipeline, from neighboring Mozambique, which is also facing tight supply. In short, establishing new gas import and distribution infrastructure, or developing LNG facilities and domestic gas-to-power capacity from scratch, would require significant amounts of capital.

Eskom’s RFP for the supply of gas to its OCGT plants presents similar financial constraints for stakeholders. Financing large-scale gas development projects in sub-Saharan Africa has historically proven difficult due to the shortage of creditworthy off-takers – or few entities able to buy the power – as well as limited government support and a lack of guarantees. Moreover, Eskom has indicated that it plans to continue to operate the OCGT plants below capacity, which would diminish profitability for potential power producers. As a result, the national utility has expressed interest in implementing either a Public-Private Partnership (PPP) or Independent Power Producer model for the power stations to help procure capital and utilize innovative financing mechanisms. The success of PPPs in South Africa has already been proven through the country’s Renewable Energy Independent Power Producer Procurement Program, which leverages private-public partnerships to achieve clean energy targets. Accordingly, public sector involvement can provide a degree of long-term government backing, while the private sector’s technical knowledge, expertise and free-market edge drives projects to be more bankable.

Finally, Eskom faces regulatory hurdles in advancing gas-to-power projects. While South Africa is one of the few sub-Saharan African markets with a designated Gas Master Plan that aligns policy with investment strategies, these projects are likely to exceed the 100 MW maximum for embedded generation projects that can proceed without a license. Therefore, some regulatory adjustments will be required to facilitate gas-to-power generation, whether it be through the decommissioning and conversion of existing coal power stations or the construction of new greenfield projects. As a result, Eskom’s solicitation of gas-supply bids for its OCGT plants must adequately address regulatory concerns and provide financial backstops for power producers, if it is to successfully transform and electrify one of the fastest-growing markets on the continent.

Sirius & Somoil Sign SPA For Three Angolan Offshore Blocks 

The Sirius-Somoil consortium, comprising London based Sirius Petroleum and Somoil S.A., Angola’s largest homegrown, privately owned E&P firm, have signed a legally binding Sale and Purchase Agreement (SPA) with Sonangol Pesquisa e ProduçãoS.A., Angola’s state-owned oil company, to acquire participating interests of 8.28% and 10% respectively in the producing Angolan offshore Blocks 18 and 31 and a 25% participating interest in the exploration Block 27, for a total consideration of $335.5Million.

If it goes through, it would be a huge, transformational deal for both companies, especially Sirius which has, until now, been trying to stamp its signature on some asset or the other in the African hydrocarbon market.

The proposed acquisition is expected to be entirely financed by debt.

Proposed Acquisition Summary

• Acquiring non-operating interests in prolific deepwater production assets with strong cash flow characteristics.

• Current gross production from Blocks 18+31 is averaging c.160,000BOPD.

• Net production entitlement to the Consortium is expected to average 15,500BOPD.

• Significant cash flow entitlement is given low operating costs and unrecovered costs

• Major medium and long-term development upside.

• Sirius-Somoil will be making targeted investments in Sonangol social projects in Angola as part of its committed strategy of working with partners to improve lives through sustainability initiatives in the community.

Block 31 – Producing

• Acquiring a 10.0% interest for a total consideration of $170Million.

• Unrecovered development cost balance of c.$14Billionn boosts contractor group entitlements, enhancing overall EBITDA/bbl and long-term returns.

• The Block is operated by BP Angola and is located offshore some 400 kilometres northwest of Luanda. 
• The block consists of four oil fields; Plutão, Saturno, Vénus, and Marte (PSVM), which were discovered between 2002 and 2004 in water depths of up to 2,000 metres in the North-East part of Block 31.PSVMis the second BP-operated development in Angola and production started up in December 2012. License partners are currently BP (26.67%), Equinor (13.3%), Sinopec International (15%), and Sonangol (45%).

• Current gross production from the block is averaging c.80,000BOPD.

• Gross 2P/2C reserves of 275MMbbls relate to existing production and sanctioned developments, according to the operator.

• Further gross 2C resources of 516 MMbbls from existing discoveries, according to Gaffney Cline & Associates.

• Future payments, on new developments within the block, are contingent on sustained high oil prices (>=$75/bbl) and first oil from long-term developments.

  Block 18 – Producing

• Acquiring an 8.28% interest for a total consideration of $165Million.

• The block is operated by BP Angola and is located offshore, 160 kilometers northwest of Luanda. Eight discoveries have been made in this block, of which the fields Galio, Cromio, Cobalto, Paladio, and Plutonio make up the first producing complex known as Greater Plutonio.

• Production started in 2007 and remains at material levels. Late last year the Platina project started production adding significant volumes and reserves to total block production. License partners are currently BP (26.67%), Equinor (13.3%), Sinopec International (15%), and Sonangol (45%).

• Current gross production from the block is averaging c.80,000BOPD.

• Gross 2P/2C reserves of 220MMbbls relate to existing production and sanctioned developments, according to the operator.

• Future payments, on new developments within the block, are contingent on sustained high oil prices (>=$75/bbl) and first oil from long-term developments.

 Block 27 – Exploration

• The Consortium is acquiring a 25.0% non-operated interest in this deepwater exploration and appraisal block for a total consideration of $0.5Million.

• The block is located offshore in the Kwanza basin, an area known for its gas potential.

The Proposed Acquisition is conditional upon satisfactory due diligence (“DD”) being conducted and following the signing of the SPA the Consortium will enter a period of DD of the data for blocks 18, 31, and 27 supplied to the Consortium by Sonangol.  The economic effective date of the Transaction is April 2022. Completion is expected to take place in 2022, subject to customary conditions and approvals.

The Consortium expects that the Proposed Acquisition will be financed through the provision of new debt facilities.

Can we improve flaring to cut down carbon emissions?

In this article, we feature an interview with Lei Sui, Product Manager for flare.IQ, in our Digital Solutions business.

 What is flare.IQ?

The way I would think of flare.IQ is that it’s a digital platform enabling us to provide a holistic flare management solution for our oil and gas customers: from up, to mid to downstream, across the entire value chain.

Our strength has always been in measurement. flare.IQ is a hardware and software solution that brings our expertise in measurement together with an advanced algorithm for optimization to deliver outcome for our customers.

 Could you please tell us how this works, in simple terms?  

flare.IQ delivers value in three ways:

First, it guides operators across the globe, to comply with most recent regulations around flaring.

Second, it helps customers including refiners operate more efficiently. The system can help bring down operational cost through reduced utility consumption.

And third, it reduces their overall carbon footprint by maximizing flare combustion efficiency. Flaring is one of the largest causes of carbon emissions across the oil and gas sector. Low flare combustion efficiency typically leads to venting more methane (a more potent Green House Gas than CO2) to the atmosphere, contributing to a larger carbon footprint.

 What does it look like?

The hardware product is actually a platform from our Nexus Controls business, also in Digital Solutions, which is combined to sensors and software to create the flare.IQ package. It is basically an industrial computer that sits in the customer’s controls room, as a rack mounted server.

flare.IQ advanced flare control platform

Who is using this tech right now, and how is it performing?

We recently gathered data from customers with refineries in Ohio, in North Dakota, and in Texas in the US.

Using the analysis done on results and measurements gathered, we can see that the combustion efficiency was improved with the system by 15-20%, saving them approximately USD200K per year in steam.

During normal flaring events, operators have to inject other gases to the flare to optimize the combustion. This is currently a manual process. With flare.IQ, they can automate that process, saving operators money and making their plant cleaner: this is the most important.

What have you learned from the innovation process?

I would say the most important lesson I learned through this process is listening to customers, and the problems that they face on a daily basis.

This idea came directly from a customer, while we were in the field. You know, we have always been in the flare measurement space for 40 years. But not in flare management, that’s very different.

Helping the customer manage their risk is something we had not been used to. Yet, we had the capability within our corporation to do it: by leveraging technology from our Nexus Controls product line, working with our global network of Research & Tech centers, we were able to take an idea into a product in less than a year. I can say the typical New Product Introduction cycle is 3 to 5 years.

I have to admit that as a team we didn’t set out originally to develop a product that saved operators money or reduced emissions. We learned that along the way. We set out to develop a product that helped our customers meet regulations here in the US (from the EPA) and as we deployed the solution and looked at the data, we started to understand the ancillary values of the product, then it started to broaden and scale into other economies outside of the US.

A great testament to the way this industry is transforming today, by testing, listening and leveraging talent and expertise, to take energy forward.

Visit: https://www.bakerhughes.com/panametrics/flare-management/flareiq

Alternatives to Russian Gas in Europe Materialize and Firm Up

By Rystad Energy

Russian gas exports to Europe have declined in the past month, with Norway increasing flows 17% in the past week and LNG imports at a 5-year hire.

Here is Rystad Energy’s regular gas and LNG note from senior analyst Nikoline Bromander:

European LNG imports are soaring, hitting a five-year monthly high in April as supply tightness in the continent continues, averaging 4.45 GWh/d, continuing the strong trend over the past months.

Russian gas exports to Europe have declined in the past month, with Norway increasing flows 17% in the past week and LNG imports at a 5-year hire.

Alternatives to Russian gas in the European market have started to materialize and firm up since Russia’s decision to halt flows to Bulgaria and Poland.

Poland is now cut off from Russian gas as of May 3, 2022, but a new pipeline to Lithuania, opened on May 1, 2022, will provide some supply relief.

Bulgaria too has been cut off by Russia, but announcement of a new floating LNG facility opening in 2023 in nearby Greece will keep them buoyant.

France, Spain, and the UK have accounted for most LNG imports in the past month.

The limited gas pipeline capacity in Europe has resulted in weaker price couplings between different regional benchmark prices.

The UK’s NBP spot benchmark is trading at a large discount to the TTF, priced at €46 at closing yesterday compared to €96 for the TTF spot.

Russian pipeline flows to Europe are stable May 4, 2022, ~250 MCMD, after Flows via the Yamal pipeline from Germany to Poland went to zero May 3, 2022.

Norway has ramped up its gas flows to Europe, currently at ~329 MCMD, up 17% week over week.

Nervousness in the market is driving gas prices (TTF) to EUR 106/MWh (~$35/MMBTU) on May 4, 2022, up nearly 7% day on day, following the new list of sanctions including a phase out from the EU announced earlier.

In addition to concern in the market over EU sanctions, there is also a upside risk related to threats from Russia terminating natural gas exports, as has already happened with Bulgaria and Poland.

If Russia shuts off supplies to more countries unwilling to pay in rubles then prices could skyrocket in the near term.

Most European countries will struggle to replace a sudden drop in supply.

Germany and Italy in particular are likely to suffer severe economic consequences given their heavy reliance on Russian gas imports.

Poland has currently ample natural gas storage, currently at 79%.

Poland has prepared well for this eventuality and has the capacity to ramp up liquefied natural gas (LNG) imports and will also benefit from the Poland-Lithuania Gas Connector (GIPL) that started operating on 1 May with a capacity of 2.4 Bcm/year.

Bulgaria, which was 100% reliant on Russian gas imports, will need to quickly take opportunities to diversify its gas imports.

The announcement, on May 3, 2022, that a new floating liquefied natural gas (FSRU) facility near the Greek port of Alexandroupolis, will start operations at the end of 2023, will be welcome news in Sofia.

Asian gas prices have been falling since the week of April 25, 2022,  due to lower demand and lockdowns.

Pricing in the region continues to trail the European market, while still competing with Europe for LNG deliveries.


Oil & Gas Sandwich Courses to Commence in Ghana’s Cape Coast University


The Institute for Oil and Gas Studies at the University of Cape Coast in Ghana, has outlined plans to start a series of Sandwich Programmes.

A two-month long series of Sandwich Programme will be run for each of the following:

  • Master of Business Administration (MBA) in Oil and Gas Management
  • Master of Science (MSc) in Oil and Gas Resource Management
  • Master of Arts (MA) in Communication in Oil and Gas Management

 The courses start on June 3 and end on August 5, 2022.

 Fuller details for enquiry and applications available in these links





Nigeria’s Noteworthy Renewable Energy Providers-An Update

By Bunmi Aduloju

Grid-scale renewable energy plants are being installed everywhere.

Not in Nigeria.

There is not a single wind or solar energy plant of higher than 15MW that is installed in the country.

But a poorly electrified economy worth over $400Billion of Gross Domestic Product with 200Million people living on close to 1Million square kilometres of land and water masses should have absorptive capacity large enough for thousands of enterprises supplying off grid power to thrive, right?

The renewable energy market potential is huge in the country, with the suboptimal grid situation providing opportunity for innovative electricity solutions. Nigerian (mostly) solar power market is taking off from a low base and while the space is still slowly evolving, some players are proving noteworthy.


Because we are so keen on the growth of the industrial economy, we start here at Solar Panel Assembly.

The closer a company is to being called a manufacturing enterprise, the higher it is on our consciousness

Auxano Solar, founded in 2014, is the first privately-owned solar PV assembler of solar systems in Nigeria. In 2020, it signed a $1.5Million expansion deal with All On, an investment company created by Shell, the European hydrocarbon major. The company has an installed capacity of 10MW and intends to increase its capacity to 100MW by 2022.


Greenvillage Electricity (GVE), is a widely referenced firm in the supply of mini-grids, To some, it is the biggest supplier in the country. Founded in 2009, it claims a cumulative installed capacity of 4.54MWp with 6,35GWhrs energy generated till date. It launched its flagship project, a 6kW solar mini-grid in Ebgeke, Rivers State in 2013. In 2019, the company signed a tripartite agreement with the Abuja Electricity Distribution Company Plc (AEDC) and Wuse Market Association, to develop a 1MW PV Solar Hybrid system for Wuse Market, Abuja.  GVE says it has installed about 13 mini-grid projects across the country.By 2022, GVE plans to have installed 20MW of solar power to supply electricity to over 500 communities.

 Rubitec came on board in 2005, specializing in solar and inverter, small hydro power, waste to energy plant, biomass energy systems, backup systems and land-fill gas plants and wind energy. In 2018, Rubitec commissioned the Gbamu Gbamu solar mini grid plant, an off-grid installation in the Gbamu Gbamu community, Ogun State. The 85kw solar hybrid mini grid project was funded by USAID and GIZ, a German development agency under the Nigerian Energy Support Programme (NESP). Rubitec recently won the bid for the Interconnected Mini-Grid Acceleration Programme, an initiative of Nigeria’s Ministry of Power (FMC), and implemented by Rural Electrification Authority REA, with financial support from the European Union (EU) and the German Government through Nigerian Energy Support Programme (NEP). With this new status, Rubitec Solar was granted partial financial support to work with the Benin Disco in deploying their proposed interconnected mini-grid projects with an in-kind partial capital grant.

Husk Power Systems was founded in the United States, but heavily Indian owned. It’s a mini-grid developer with offices in Nigeria, Tanzania, USA as well as its home country. The company serves the rural energy economy, with mini-grids at the centre of the company’s business model. It serves both completely rural off-grid areas, which have in the past only been able to use diesel generation to power their businesses and livelihoods, as well as weak grid areas where the main grid (distribution companies or power utilities often referred to as “Discoms” in India, and “Discos” in Nigeria) provide unreliable and poor quality connections, Husk launched its first six mini-grids in Nigeria in November 2021, and is looking to have 100 operational within two years..Husk Power has raised around $40Million in equity from investors. In 2018, it raised a Series C totaling $20Million[5] from Shell Technology Ventures, Swedfund International and Engie Rassembleurs d’Energies, with FMO coming in later with an additional $5Million. Other investors have included The Rockefeller Foundation, Acumen, US International Development Finance Corp. and First Solar.

PowerGen-Formed by Ameicans and headquartered in Nairobi, Kenya, has contributed to mitigating Nigeria’s universal electrification challenges by deploying seven local solar networks in the African country. Work is going on to quadruple the number of networks to 28 systems with a total generation capacity of 2.1 MW and an average figure of around 70 kW per set-up, and with around 4.5 MWh of total battery storage at a typical mini-network volume of around 160 kWh. The project is funded by equity investors who will recoup their money when all 28 systems are sold to CrossBoundary Energy Access.

Havenhill Synergy was established in 2010. In 2017, it commissioned a 20kW Solar Mini-Grid in Kigbe Community, Abuja. It followed up with a 100kWp solar hybrid mini-grid in Budo-Are Community, Itesiwaju Local Government Area, Oyo State in 2020. It has received funding from the U.S Trade and Development Agency (USTDA) and United States African Development Foundation (USADF). The company has also secured a $4.6Million debt funding from Chapel Hill Denham’s Nigeria Infrastructure Debt Fund (NIDF), an infrastructure debt fund in Nigeria and Africa, for the construction of 22 mini-grids being developed by Havenhill Synergy Limited under the Nigeria Electrification Project (NEP), according to Havenhill Synergy Limited.


Beebeejump comes highy recommended from one of Africa Oil+Gas Report’s more esteemed energy analysts.  It claims a sales and after-sales team of more than 200 in its Lagos headquarters alone. Beebeejump says it “not only has the world’s top solar battery digital control, light power generation, and other areas of technical experts for research and development but also the industry’s experienced product team with more user-friendly products and services”. The company’s core competency is in power products used in homes, farms, and corporate businesses. She provides a range of solar power products such as DC power solutions, AC/DC power solutions

Arnergy, founded in 2014, says it has an installed capacity of over 3MW and a storage capacity of over 9MWh.  In 2019, the company raised $9Million through an investment drive championed by Breakthrough Energy Solutions with support from All On, ElectriFi (EDFI Management Company), and Norwegian Investment Fund for Developing Countries (Norfund), in its Series A round of funding. This funding would deploy about 14MW of PV solar panels and 35MWh storage, with an annual capacity of 13,500MWh/y from 2019 to 2022. In the fourth quarter of 2020, the Federal Government of Nigeria, through the Rural Electrification Agency (REA), signed an official grant agreement with seven firms including Arnergy Solar. Under the Nigerian Electrification Project (NEP), the Output Based Fund (OBF) grant would deploy stand-alone Solar Home Systems (SHS) to Nigerian Small and Medium Enterprises in rural communities. In 2021, the company was listed by Bill Gates and his Friends among the top five leading Cleantech firms changing the narrative by saving the planet. One of its long-term goals is to power 35,000 businesses and homes

Lumos Nigeria, a subsidiary of Lumos Global, is an off-grid solar service provider, incorporated in 2013 with the aim of providing reliable, clean and affordable electricity in Nigeria. Through a strategic partnership with MTN, a multinational mobile telecommunications company, Lumos has installed over 100,000 solar systems in homes around Nigeria.

It has received several funding from international investment firms and the Federal Government of Nigeria. The Federal Government of Nigeria, jointly funded through its Rural Electrification Agency (REA) and the Nigeria Electrification Project (NEP) by the World Bank, awarded a share of the $75Million grant to electrify over a million households by 2025.









Angola’s 30,000BPD Cabinda Refinery Passes Milestone Tests in Houston


The new Cabinda Oil Refinery in Angola successfully passed milestone tests in Houston at the VFuels facility in Houston yesterday.

The Factory Acceptance Testing (‘FAT’) helps verify that newly manufactured and packaged equipment meets its intended purpose before it is delivered to its intended destination, a significant step in the process of developing major refineries and similar plants.

The Cabinda Refinery will be 60,000 barrels a day (b/d) facility once fully operational. The full project is expected to represent an investment of $1Billion in three phases, with the first phase being $350Million. Phase 1 will feature a 30,000BPD crude distillation unit, desalinator, kerosine treating unit, pipelines, and a more than 1.2Million barrels of crude oil storage terminal. Phases 2 and 3 will add another 30,000BPD of crude processing capacity, as well as units for catalytic reforming, hydrotreating, and catalytic cracking that will transform the site into a full-conversion refinery. Once fully operable, the Cabinda refinery will produce gasoline, diesel, LPG, fuel oil, Jet A1, and kerosine.

Work on the Cabinda Refinery has created over 500 jobs in Houston while achieving the construction of a 30,000BPD modular crude distillation column – the largest throughput to date by VFuels, and the largest single-train modular crude distillation unit built to date globally. In Angola the project is expected to create 1300 jobs in total.

The project is being seen as a key step in the economic development of Angola because increasing domestic crude processing capacity helps reduce the country’s dependence on expensive imports of refined products, which also will have a positive environmental impact. It is also an important example of international development cooperation and of U.S. technological expertise in the space.

Angolan State Minister of Petroleum Diamantino Pedro Azevedo and Sonangol Chair & CEO Sebastião Gaspar Martins and other members of the board toured the VFuels facility as part of the proceedings.

Gemcorp Holdings Ltd and Sonangol are sponsors of the project and Odebrecht is the main EPC contractor.



BP in Transition: An Open Letter to BP Shareholders

By Gerard Kreeft

Dear Shareholder;

BP’s announcement on February 27 that it was withdrawing from Russia was welcomed in Western circles, but has a nasty side effect: the loss of 50% of its global oil reserves. While the company has put on a brave face, there is strong need to demonstrate how BP will maintain its golden dividend and continue its transformation from oil giant to a new green energy giant. Of the oil majors operating in Russia, BP’s departure of its 19.75% of Rosneft was the most severe. Yet according to the company….” BP’s financial frame and distribution guidance remains unchanged”. Can shareholders simply assume that BP’s strategy is sound? Must shareholders just go ahead and accept everything that BP tells them?

BP’s share price in the period 2018-2022 has, with the exception of Repsol, been the biggest laggard of the oil majors. Chevron, ENI, ExxonMobil, Equinor and Shell have all fared better. Regardless of one’s perspective of the ongoing energy transition, a company’s share price and accompanying dividend policy are holy items. Europe’s new energy companies—Engie, ENEL, Iberdrola, Ørsted and RWE– have also have shown diverse results ranging from being laggards to first-in-class. The key message from the investor community is clarity of message, regardless of whether a company is only pursuing hydrocarbons or low carbon solutions.

Lessons learned from TOTALEnergies

BP could well take a page from the TOTALEnergies’ playbook to learn how a loss of oil reserves can be compensated by new energy sources, helping the company to become greener, sooner rather than later. Perhaps even ensuring shareholders that it will become CO2 free in 2030 instead of 2050 as is now the case.

In the summer of 2020, the French oil and gas giant 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.

Patrick Pouyanné, the company’s chairman and CEO, now says that by 2030 the company “will grow by one third, roughly from 3Million BOE/D (Barrels of Oil Equivalent per Day) to 4Million BOE/D, half from LNG, half from electricity, mainly from renewables.”[1] This was the first time that any major energy company translated its renewable energy portfolio into barrels of oil equivalent. So, while the company was slashing down proven oil and gas from its books, it was adding 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 of 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% 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 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.

Meanwhile, competitors that stick to the old business model will have no choice but to continue to develop hydrocarbons—even if their proven reserves ultimately prove to be financial duds.

 BP’s Outlook

BP maintains, that in spite of losing 50% of its reserves, the company can maintain its green goals:

  • 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, up from around 9% today.
  • After allowing for the impact of divestments and reflecting the expected share buyback commitment, EBIDA per share is expected to grow by 7–9% per year through to 2025.
  • From 2025 onwards, when its low-carbon projects start to kick in, expect growth of between 12–14% to be maintained.
  • Reducing its oil production by 40% by 2030.
  • Its $25Billion divestment will 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 are 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.
  • Partnering with 10-15 cities and 3 core industries in decarbonization efforts and doubling customer interactions to 20 million per day, all by 2030.

A key component of BP’s strategy is building an investment structure, which requires only a few skilled accountants. The company has either sacked employees or will be delegating BP’s headcount to its joint ventures. The goal is to become lean and mean, reducing costs and, hopefully, increasing margins. In short becoming an investment vehicle.

To date the company has initiated a series of joint ventures to speed up its transition.

  • BP and Ørsted have partnered to develop zero-carbon ‘green hydrogen’ at BP’s Lingen Refinery in north-‎west Germany, BP’s first full-scale project in a sector that is expected to grow rapidly. The 50 MW electrolyser project is expected to produce 1 ton of ‎hydrogen per hour – almost 9,000 tonnes a year – starting in 2024. The project could be expanded to up to 500 MW at a later stage to replace all of Lingen’s fossil fuel-based hydrogen. Final investment decision is due later this year.
  • BP and Equinor revealed that BP will become a 50% partner of the non-operated assets Empire Wind (offshore New York State) and Beacon Wind (offshore Massachusetts). BP and Equinor will jointly develop four assets in two existing offshore wind leases located offshore of New York and Massachusetts that together have the potential to generate power for more than two million homes.
  • BP joined Statkraft and Aker Offshore Wind in a consortium bidding to develop offshore wind energy in Norway. The partnership—in which BP, Statkraft, and Aker Offshore Wind will each hold a 33.3% share—will pursue a bid to develop offshore wind power in the Sørlige Nordsjø II (SN2) licence area.
  • In Angola, BP has merged its upstream activities with ENI to form Azule Energy, which could become a model for other African countries.

The New Energy Players

The speed with which BP has unveiled its strategy indicates that it wants a seat at the green table occupied by the new energy elite—ENGIE, ENEL, E-on, Iberdrola, Ørsted, RWE, and Vattenfall—who have pole position in determining the direction of the global renewables market. Is BP’s $5Billion per year investment to green itself and its goal of 50 GW net generating capacity by 2030 enough to warrant it a place at the green table? Perhaps a starting position but hardly enough to be classified as a heavyweight! Consider the competition:

  • ENGIE: In 2021 the company spent more than $11Billion on investments across a broad swath of sectors, including solar, wind (on and offshore), hydro plants, biogas, and developing gas and power lines, and it will have 50 GW of global renewable capacity installed by 2025.
  • Enel: The company’s strategic plan outlines total investments of $231Billion by 2030 and tripling renewable capacity to 154 GW.
  • Ørsted: By 2030, the company will have an installed capacity of 50 GW.
  • Iberdrola: From 2020–2025, the company will be spending $165Billion on renewable energy and has a pending target of 95 GW of installed wind capacity.
  • RWE: By 2030, RWE will have 50 GW of installed wind and solar capacity.
  • Vattenfall: In the Nordic countries, Vattenfall has low emissions, with practically 100% of the electricity produced by renewable hydroelectric power and low-emitting nuclear energy.

Food for thought

Originally BP’s Net Zero Scenario was to reduce fossil fuels to 20% of today’s share of primary energy by 2050. Given its reserve losses and the urgency to become greener more quickly, 2030 could become the new deadline for BP to become CO2 neutral.

BP’s board has recommended investors vote against a shareholder resolution filed by Dutch activist group Follow This urging the British energy company to accelerate its energy transition strategy. In a report ahead of its May 12, 2022 annual general meeting, BP said that the resolution was “unclear, generic, disruptive and would create confusion as to board and shareholder accountabilities”.

Shareholder revolts–across the entire oil and gas spectrum– have increasingly voted against recommendations of oil & gas companies concerning environmental resolutions. Consider the shareholders’ revolts in 2021 concerning Chevron and ExxonMobil! Shareholders of both companies voted for stricter environmental measures, contrary to recommendations of their boards.  This does not bode well for BP in 2022.

The board, if it is to preserve its hide, should be prepared to discuss the following options:

BP’s West Nile Project in Egypt: “Whether a company is an oil company or an energy company seems to matter little to investors. Instead, they demand clarity”.

How will the company exit its remaining 20% of primary energy? Perhaps putting it in a joint venture much like its Angolan assets which have been merged with that of ENI?

What mega-investments can BP make so that it can become, very quickly, a giant of new energy? Some examples:

Hyphen Hydrogen

The Hyphen Hydrogen project in Namibia will invest $9.4 billion over a period of nine years. The project sponsors aim to produce 5 GW of power by 2030 and 3 GW of electrolysis capacity.

Hyphen is a Windhoek-based joint venture between British Virgin Islands-registered investment holding company Nicholas Holdings and German renewables developer Enertrag. The Namibian Government says that a large focus would be on exporting hydrogen to Europe and to sell some of the output to neighbouring countries, to “take advantage of the vision that our leaders have for the African Continental Free Trade Area”.

Morocco-UK Power Project 

A second project which has received much media attention is the Morocco-UK Power Project which will produce 10.5 GW of power. The solar and wind farm will be built in Morocco’s Guelmim-Oued Noun region, and it will supply the UK with clean energy via subsea cables. The twin 1.8 GW high voltage direct current (HVDC) subsea cables will be the world’s longest.

The Xlinks Morocco-UK Power Project will cover an area of around 1,500 square kilometres in Morocco and will be connected exclusively to the UK via 2,361 miles (3,800 km) of HVDC subsea cables.

The project will cost $21.9Billion. Xlinks will construct 7 GW of solar and 3.5 GW of wind, along with onsite 20GWh/5GW battery storage, in Morocco. The transmission cable will consist of four cables. The first cable will be active in early 2027, and the other three are slated to launch in 2029.

The Morocco-UK Power Project will be capable of powering a whopping 7Million UK homes by 2030. Once complete, the project will be capable of supplying 8% of Britain’s electricity needs.

While this energy divergence for Europe will be welcomed, it sends a double message to Africa. Providing Europe with potential renewable energy is only part of the equation; it is  also important that Africa’s energy transition is geared for its own domestic use.

 Finally, the investor outlook

BP’s profile has been discussed, but what is the verdict of the investor community? Of the seven majors—BP, Chevron, Eni, ExxonMobil, Equinor, Shell, Repsol and TOTALEnergies—BP aside from Repsol, has been the industry laggard between 2018 and 2022.

 Table 1: Stock market prices of  majors 2018-2022(NYSE)


YearRepsol      BP      ShellEniTotalEnergiesChevronExxonMobilEquinor

Note: Values based on 5 January 2018 and 1 April 2022

In comparison, during these five years, Repsol’s stock is down 32%, BP’s stock is down 30%, Shell 19%, ENI 14%, and TOTALEnergies down by 10%, whereas Chevron’s stock rose by 28%, ExxonMobil was up by 46% and Equinor more than doubled to 65%.

 Regardless of how one views the energy transition, the messaging and the guaranteeing of the golden dividend have been key factors in maintaining the price levels of the stock market prices of the majors. Even the current spike of oil prices has contributed only marginally to the BP share price.

Yet the recent oil crisis demonstrated how far the oil majors will go to defend their sacred oil dividend. According to an IEEFA(The Institute of Energy Economics and Financial Analysis) report of March 2021 the oil supermajors combined to spend almost $50bn on payouts to their investors in 2020 to prop up their dividend policies: $20.5billion from their core business, the remaining $29.4 billion borrowed.[2]

Whether a company is an oil company or an energy company seems to matter little to investors. Instead, they demand clarity. That is why Chevron, which is on track to make 2022 the 35th consecutive year with an increase in annual dividend payout per share, has maintained its value. The same reasoning applies to ExxonMobil. And why Equinor’s message of spending more than one-half of its capital spending on low carbon energy by 2030 is a leader in offshore wind technology, which has caught the fancy of its investor community.

The compromise of straddling both sides of the divide—hydrocarbons and low carbon solutions—has failed to spark  investor confidence in ENI, TOTALEnergies, Shell and Repsol.

 On a similar note, there is good news and bad news for Europe’s new energy companies. Engie, the large French energy giant, has seen its share price  decrease by 19%. ENEL, the Italian power company, has seen its share price increase 40%. Iberdrola, the Spanish power company, has had an increase of 38%. The two big winners are Ørsted, the Danish power company which has seen its stock soar by 142% and RWE, the German utility giant, has seen a stock price increase of 60%. Ørsted’s constant low carbon energy news has resonated with investors. Again, like the oil majors, the messaging is key.

 Table 2: Stock market prices of new energy companies 2018-2022


Finally, the BP message for the investor community is  ambiguous.  BP has always portrayed itself as the greenest of the major oil & gas companies changing their corporate logo to the sun-burst green and yellow logo.  They promoted themselves as “Beyond Petroleum”.  But BP’s diminished stock price and market capitalization is very disappointing.   BP must re-examine its future roadmap and decide whether it can continue being an oil company and an energy company.  Bernard Looney became CEO of BP in February 2020 and was tasked by BP’s board to navigate the energy transition.   Understandably BP’s shareholders are upset and are questioning the wisdom and strategies carried out by Mr. Looney and his executive management team.

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 contributes to IEEFA (Institute for Energy Economics and Financial Analysis).

[1] TotalEnergies Strategy and Outlook Presentation, 9/30/2020, Totalenergies.com/media/news

[2] James Murray, ‘Super majors spending more on investors  than earnings from business”, Institute for Energy Economics and Financial Analysis, March 8, 2021 https://ieefa.org/supermajors-spending-more-on-investors-than-earning-from-business


Hydrogen, the New Energy Rush for Africa


With rapidly improving technology and decreasing costs for fuel cells, green hydrogen is becoming a more appealing fuel alternative in Africa

Green hydrogen will be one of the largest economic opportunities over the next 30 years. Driven by international actions to combat climate change, it has the potential to revolutionise numerous value chains in the energy industry and across both the mobility and manufacturing sectors. With rapidly improving technology and decreasing costs for fuel cells, green hydrogen is becoming a more appealing fuel alternative in Africa.

At the core of green hydrogen production is the availability of renewable energy that is not being utilised for its prime role as electricity supply. For Europe, the lack of spare renewable energy capacity will be a roadblock for the hydrogen economy and so the search is on for viable locations for production. Pilot projects have started in Chile and the Middle East, but the greatest opportunities lie in Africa with many European backed schemes at various stages in the planning process.

Backed by Africa’s extensive renewable energy resources – the International Renewable Energy Agency estimates that renewable energy capacity in Africa could reach 310GW by 2030. The hope is that development of green hydrogen projects will not only address continent-wide energy demand, increasing energy security and contribute to domestic energy independence, but will provide an environmentally sustainable fuel alternative for years to come. The big question, however, is whether that hydrogen production will benefit the African energy transition or be shipped back to Europe.

South Africa’s hydrogen valley

In South Africa, the government is attempting to match the synergies between platinum mining, renewable energy, and hydrogen production to form a hydrogen hub. Platinum is a key component in Polymer Electrolyte Membrane (PEM) electrolysis used to produce hydrogen at scale and in fuel cells themselves. The hydrogen valley will serve as an industrial cluster, bringing various hydrogen applications in the country together to form an integrated hydrogen ecosystem.

The initiative is part of the work being done to support the implementation of the National Hydrogen Society Roadmap, which was recently approved by Cabinet, as well as phase 3 of the country’s Economic Reconstruction and Recovery Plan.

Phil Mjwara, director-general of the South Africa Department for Science and Innovations, said at the launch that the establishment of a hydrogen valley was an important national initiative. “The implementation of phase 3 of the Economic Reconstruction and Recovery Plan is driven by the core elements of ‘reconstruct’ and ‘transform’, and this entails building a sustainable, resilient and inclusive economy,” he said. “The establishment of a South African hydrogen valley is an opportunity that has great potential to unlock growth, revitalise the industrial sector, and position South Africa to be an exporter of cost-effective green hydrogen to the world. Hydrogen therefore remains an integral part of our Economic Reconstruction and Recovery Plan.”

South Africa’s proposed hydrogen valley will start near Mokopane in Limpopo, where platinum group metals (PGMs) are mined, extending through the industrial and commercial corridor to Johannesburg and leading finally to Durban on the coast of the Indian Ocean. The hydrogen valley will be used to establish, accelerate, and embed niche innovations through upscaling and replication. Hydrogen and fuel cell technologies offer an alternative source of clean electricity, while hydrogen allows for energy to be stored and delivered in usable form.

The feasibility study, conducted by Engie, identifies nine hydrogen-related projects across the mobility, industrial and construction sectors that could be used as a springboard for the establishment of the hydrogen valley. One project will focus on converting heavy-duty diesel-powered trucks to fuel cell-powered trucks, which will support increased consumption of hydrogen in the transport sector. The projects will also facilitate the commercialisation of publicly funded intellectual property, while contributing to the beneficiation of PGMs in targeted geographic areas. Hydrogen and fuel cell technologies offer an alternative source of clean electricity, while hydrogen allows for energy to be stored and delivered in usable form. Using hydrogen as an energy carrier could potentially reduce South Africa’s dependence on fossil fuels that cause global warming, while reducing the country’s reliance on imported oil.

Namibia to develop hydrogen hub

In West Africa, an ambitious project to produce 300,000 tonnes of green hydrogen each year is taking shape. The Namibian Government has appointed Hyphen Hydrogen Energy to develop the country’s first large-scale, vertically integrated green hydrogen project in the Tsau //Khaeb national park. The project, worth an estimated $9.4 billion, will produce either pure green hydrogen or in derivative form such as green ammonia.

“The first phase, which is expected to enter production in 2026, will see the creation of 2 GW of renewable electricity generation capacity to produce green hydrogen for conversion into green ammonia, at an estimated capital cost of $4.4Billion,” Marco Raffinetti, Hyphen CEO, says. “Further expansion phases in the late 2020s will expand combined renewable generation capacity to 5 GW and 3GW of electrolyser capacity, increasing the combined total investment to $9.4Billion.”

Once fully developed, the project will provide a major boost to Namibia in terms of foreign direct investment and job creation. The $9.4 billion investment amounts to the same order of magnitude of the country’s current GDP and will see 15,000 direct jobs created during the four-year construction of both phases, with a further 3,000 jobs created permanently during the operational phase. More than 90 per cent of all these jobs created are expected to be filled by Namibians. In addition to taxes, Hyphen will pay concession fees, royalties, a sovereign wealth fund contribution and an environmental levy to the government.

“The Tsau //Khaeb national park is among the top five locations in the world for low-cost hydrogen production, benefiting from a combination of co-located onshore wind and solar resources near the sea and land export routes to market,” Raffinetti adds. “Namibia’s world class natural resources, combined with a progressive, pro-investment and visionary government under the leadership of President Hage Geingob, has enabled the country to move with incredible speed to position itself as the leading edge of Africa’s ambitions to enter the green hydrogen production space.

“This collective deep technical expertise across the entire green hydrogen value chain, combined with our financial strength and experience in developing, fundraising, and implementing infrastructure projects in Africa, will be crucial in successfully delivering a project of this magnitude and complexity.”

Green Energy Africa Summit

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Okwok Field: Oriental Hopes for First Oil by Early 2024

Oriental Energy Resources is working up the programme to commence crude oil production from the Okwok field, in south eastern offshore Nigeria, by March 2024.

It would be close to 10 years since the field’s wellhead jacket had been installed, permitting the drilling of Okwok-13, the first development well, which flowed at a rate over 5,000 barrels per day of crude.

Okwok is located in 31metre water depth, in shallow water Oil Mining Lease (OML) 67 in southeast offshore Nigeria.

The ongoing field development anticipates peak production be around …

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