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Nigeria’s Power Minister Announces $2.2Billion PV Solar agreement deal with US Firm 

By Fasilat Oluwuyi

Nigeria’s Minister of Power, Adebayo Adelabu, has announced a collaborative deal with Sun Africa LLC, a l US-based renewable energy solutions provider.

Adelabu made the announcement via his X handle (formerly twitter) on November 19, 2023.

He said Sun Africa has committed to delivering 961 MWp of solar PV generation infrastructure and 455 MWh of battery energy storage systems, totalling $2.2Billion.

The Minister said the collaborative effort will advance sustainable and reliable energy solutions for the nation adding that it will also address Nigeria’s increasing power demand.

There were no details of execution of the deal; where the projects will be sited, whether it will be in form of min-grids in rural areas of scaled-up projects connected urban infrastructure, and whether it will involve subnational governments.

Nigeria has one of the lowest renewable energy deployments on the planet. There is no single functioning solar or wind power generating project with capacity higher than 10MW.

Adelabu wrote: ‘‘I met with representatives from Sun Africa LLC, a leading US-based renewable energy solutions provider. Together, we solidified a collaboration to enhance Nigeria’s power landscape. As the Honorable Minister of Power, I am excited about the positive impact our nation, aligning with my power sector transformation roadmap of Distributed Power leveraging on Renewable Energy. Sun Africa has committed to delivering 961 MWp of solar PV generation infrastructure and 455 MWh of battery energy storage systems, totaling $2.2Billion.

“This addresses Nigeria’s increasing power demand, supporting economic and energy sustainability objectives. This collaboration is a crucial step in transitioning to a more sustainable power mix, vital for economic growth and environmental responsibility.

“Grateful for Sun Africa’s partnership, I anticipate embarking on a journey to provide cutting-edge renewable power infrastructure to our citizens. Their dedication mirrors our vision for a resilient and energy-abundant Nigeria.”




Fuel for Thought: Liquefied Petroleum Gas


By: Gorgui Ndoye

The past several years have shown that a range of fuel options for power generation is an important hedge against instability. Fuel flexibility is a hallmark of Capstone microturbines, which can run off a variety of sources, from natural gas and propane to methane, hydrogen, and more.

Today we’re spotlighting liquefied petroleum gas (LPG), a widely available fuel that is an excellent alternative to diesel and other expensive, “dirty” fuels. This primer explains the types of commercially available LPG and how they can integrate into Capstone microturbine systems.

What is LPG?

Using LPG in Microturbines

LPG is a mixture of propane (C3), butane (C4), and small quantities of various other hydrocarbons, such as propylene and butylene.

LPG is transferred and stored as a pressurized liquid; however, its boiling point is such that it evaporates easily under ambient temperature and pressure. The molecular composition of LPG determines the dew point, heating value, density, and many other properties, as well as the percentage of contaminants. These values determine whether a fuel can be used in an engine or turbine. For this reason, it is important to know the composition of the LPG before designing the fuel delivery system. Because the LPG composition can vary significantly between fuel types, Capstone enhanced the fuel capabilities of the C200 and C1000 series microturbines to use a variety of LPG.

The four most common commercially available types of LPG are Special Duty Propane (HD-5), Commercial Propane (HD-10), Propane-Butane Mixtures (PB Mix), and Commercial Butane. LPG can also be mixed with conditioned air to make an LPG/Air Mixture. The addition of air may alter the overall fuel properties to a more desirable level for operation. Capstone’s microturbines can run using HD-5, PB Mix, or LPG/Air Mixtures.

When comparing LPG to Natural Gas (NG), it’s important to note the heating value difference. NG has an average heating value of 1,000 Btu/scf. SD-5 is roughly 2,500 Btu/scf, and Commercial Butane is over 3,000 Btu/scf. Therefore, the heating value of LPG is 2.5 to 3 times greater than NG. So, LPG requires much lower volumetric flow rate to achieve the same engine output. LPG is also stored as a liquid, which compresses the fuel volume 250:1—without costly cryogenics required by LNG. These factors offer a small footprint for LPG compared to NG’s need for pipelines and large infrastructure, and LPG can be transported easily and stored in tanks, making it a good diesel replacement.

Using LPG in Microturbines

  1. Special Duty Propane

Special Duty, or HD-5, Propane is defined as greater than 90% propane and less than 5% propylene. This grade is ideal for all types of engines and turbines due to the burn’s cleanliness and the low level of contaminants relative to diesel.

All Capstone microturbines have a version that can operate using HD-5 Propane.

  1. Propane-Butane Mixtures.

Twenty-three Capstone C65 microturbines provide prime power to Southern California Edison’s Avalon site on Catalina Island

Propane-Butane Mixtures,  or PB Mix, have no standard specification for their compositions and can be a problem for gaseous fuel operation due to the low dew point of butane. The higher the concentration of butane, the lower the dew point falls, and the more heat tracing and insulation needed with the fuel delivery system. This causes a higher risk of fuel condensation, which may lead to engine problems. The LPG-capable C200 and C1000 series microturbines were designed with a versatile fuel system. This includes internal heat tracing and fuel line insulation, which reduce the risk of condensing vapor from heavier fuels. The goal of the heat tracing and insulation is to maintain the supplied inlet fuel temperature without needing to increase the fuel temperature or vaporize condensed liquids.

The LPG-capable C200 and C1000 microturbines are approved to operate using a Propane-Butane Mixture of up to 40% butane. This does not mean that PB Mixtures containing greater than 40% butane are disqualified. Capstone applies the same limitations towards propylene, limited to less than 5%, as well as all other contaminants listed in the Special Duty Propane specification.

  1. LPG/Air Mixtures

Certain LPG types that are not suitable for microturbines may be approved when mixed with air. Alternatively, the mixture may attempt to match the properties of a more standard fuel, such as NG. LPG/Air mixtures are not standard and may require complex fuel delivery systems. The approval of these fuel types depends on review of the fuel properties and composition. Detailed analysis would be needed to determine feasibility for use in microturbines.

  1. Real-World Application

In March 2023, a 600 kW, C600S, LPG-fueled system was commissioned at a remote food processing facility in Bamako, Mali. Like many land-locked countries, Mali relies on expensive, “dirty” fuels like diesel and heavy fuel oil, so this project was important in demonstrating the benefits of a system whose fuel is less expensive and more environmental.

The new system also improves reliability, which addresses issues of load shedding and blackouts the facility had previously experienced. Because the microturbines also require very little maintenance compared to other technologies like diesel generators, power availability and cost savings were also improved.

Twenty-three Capstone C65 microturbines provide prime power to Southern California Edison’s Avalon site on Catalina Island

“The Mali project is a model for other customers and power companies, showing the benefits of LPG as an alternative fuel,” said Gorgui Ndoye, business development director for Capstone Green Energy. “There is tremendous opportunity to use LPG in many regions around the globe, but it can play an especially important role in Africa as part of the continent’s energy transition.”

Better for Business and the Environment.

It’s difficult to underestimate the positive impact that added reliability and cost savings have on the bottom line. Often, the combination of LPG and microturbines offers significant upside—including cleaner fuel and lower emissions. What’s more, once a customer decides to go with Capstone, we can fast-track and deploy nearly anywhere within three months of order.

The world’s energy landscape won’t become more predictable. Smart power security decisions made today will set businesses up to confidently navigate the future. An LPG-fueled microturbine system could be the answer.



Renewable Energy Wheeled for the first time through Cape Town’s Grid

The first electrons of renewable energy have officially been wheeled via the City of Cape Town’s energy grid, as part of the city’s plans to end power outages, which plagues South Africa.

Growthpoint Properties (JSE: GRT) became the first party to wheel renewable electricity in the city in collaboration with licenced electricity trader Etana Energy (Pty) Limited (Etana), a joint venture in which the South African owned Neura Group and H1 Holdings hold 49% and 26% respectively and UK based Chariot holds a 25% interest.

Wheeling is a process where electricity is bought and sold between private parties, using the existing grid to transport power from where it is generated to end-users that can be long distances apart.

“It creates greater access to affordable renewable energy and contributes to resolving the country’s energy crisis”, UK based Chariot says in a statement.

“As part of the City’s wheeling pilot project, in which Etana was selected as a participating trader, solar energy generated at Growthpoint’s The Constantia Village shopping centre in Constantia is being exported into Cape Town’s electricity grid for use at Growthpoint’s 36 Hans Strijdom office building in the Foreshore”.

Solar power from The Constantia Village was successfully injected into the City’s energy grid for the first time in September 2023.

Etana Energy says it is pleased that the city selected it as a trading partner, and we look forward to providing further energy support to the region for the foreseeable future.

“This electricity licence not only enables us to instigate this trading, but it also has the potential to help to unlock the development of further large renewable projects in South Africa. We are looking to supply greener power across the national grid for commercial and industrial requirements so this early-stage trading is a key step within our longer term plans for this business.”

Why Less Looks Like More: A Performance Review of Nigeria’s Power Generation Capacity

By Adeniyi Adeoloye

The Nigeria power sector is encumbered right through the entire value chain.

The figures for installed generation capacity, the grid transmission, and what the distribution companies can deliver to the end users, are common knowledge. But there’s a vast gulf between the capacity and the delivery and the specific details of this gap is absent from the conversation.

Many have dismissed the transmission segment as the weak link in the power industry value chain. The call has led to pleas for government to let go of operating it in order to drive efficiency and deliver optimum value. There has been a scathing searchlight on the distribution and transmission links of the sector. But then, the generation segment is as broken.

Nigeria, like many countries, organises its energy mix around energy sources that are abundant within its borders. Hydro power and gas fired plants dominate the energy mix in Africa’s most populous country. Save for the emissions during their construction and location outside demand centres, hydro is largely seen as a clean means of power generation. On the other hand, gas has been given green credentials by the European Union due to its less polluting nature than coal and since labelled a transition fuel. So by and large, the grid emission factor of the power generation systems in Nigeria based on energy source are in relatively good stead.

What are the numbers like? By the tally, there are 23 power generating plants connected to the grid in Nigeria with installed capacity of 10,396 MW and available capacity of 6,056 MW. Of this, gas fired plants account for 8,457.6 MW with available capacity of 4,966 MW while the remainder is hydropower with installed capacity of 1,938.4 MW and available capacity of 1,060 MW. The large chunk of the country’s generation is gas fired.  The ownership of these plants cuts across government and the private sector. Nigerian Bulk Electricity Plc (NBET) undertakes Power Purchasing Agreement (PPA), with the generating companies and sells the energy purchased to the distribution companies via Vesting Contracts. A total of 16 generation companies have PPA with NBET.

Performance of Government Run Power Plants

Government hatched the National Integrated Power Project (NIPP) in 2004 in a bid to stabilize electricity supply in anticipation of the takeoff of the private sector led structure of the Electric Power Sector Reform Act (EPSRA) of 2005. The primary idea of NIPP was to build 7 medium sized gas fired power plants in gas producing states alongside crucial transmission infrastructure required to move the added power to the national grid. The Niger Delta Power Holding Company Limited (NDPHC) was set up to house and manage the NIPP assets with market oriented practice. Available information by NDPHC indicates it owns 10 thermal plants – Calabar (563 MW), Omotosho (500 MW), Sapele (450 MW), Egbema (338 MW), Omoku (225 MW), Alaoji (960 MW), Ihovbor (450 MW), Gbarain (225 MW), Gerugu (434 MW) and Olorunsogo (675 MW). Of this ten, eight of them except Egbema and Omoku have “interim agreement” with government owned Nigerian Bulk Electricity Trading Plc (NBET) that buys power from Independent Power Producers (IPP) and successor generation companies from the unbundling of Power Holding Company of Nigeria (PHCN) and resale to Distribution Companies who deliver to end users and other large consumers who take electricity directly from the grid.

The eight plants having interim agreements with NBET have total contract capacity of 4,257 MW and tested capacity of 1762 MW with average generation capacity of 488.15 MW as at year 2021 according to data by NBET. The data further shows average generation of these plants is a paltry 11% of net contract capacity, and about 27% of tested capacity. Plants with installed contract capacity of 500 and above didn’t perform any better. Alaoji with net contract capacity of 960 MW and tested capacity of 212.33 MW averaged an output of 58. 19 MW.  Olorunsogo (675 MW, 212.67 MW and 23.07 MW), Calabar (563 MW, 339.55, 236.02) and Omotoso (500 MW, 219.61 MW and 43.24 MW) for net contract capacity, tested capacity and average generation capacity respectively. The Ihovbor Plant with contract capacity of 450 MW and tested capacity of 202.34 MW last done in 2021 had average generation capacity of 16.87 MW in year 2021. This is an abysmal low of capacity utilisation. Across board, NDPHC managed plants are poorly performing.

And talking about testing, the data also established year 2015 as the last test date for all NDPHC plants with the exception of Alaoji plant whose capacity test was carried out in June 2021. The lag in test capacity is against what is stated in a March 2022 draft power purchase agreement for brownfield power plants by NBET which states “the Tested Capacity of the Plant shall be verified at least annually by further Capacity Tests that will establish the revised Tested Capacity”. Usually there are diverse reasons to appraise the performance of a plant other than meeting contract guarantees. Performance tests for a brownfield power plant can be done to verify its capacity and heat rate before an acquisition in order to determine its asset worth. Testing is also useful for the goal of maintaining a Power Purchase Agreement, tariff up-gradation as well as to ascertain the performance differences brought by major repairs or component upgrades.

Review of Successor Gencos

Successor Gencos are power generation companies created in the aftermath of the unbundling of PHCN. There are eight of these plants around the country namely: Kainji (760 MW), Jebba (576 MW), Shiroro (600 MW), Egbin (1100 MW), Sapele (1020 MW), Delta (900 MW), Afam IV-V (776 MW) and Gerugu (414MW). Tese are nameplate capacities. With the exception of Kainji, Jebba and Shiroro that are hydro power, the rest are gas fired. Many of the plants have been fully or partially sold, and others under long term concession. All of the plants have Power Purchase Agreement with NBET with total contract capacity of 6,146 MW, last tested capacity of 2,853.72 MW and average generation capacity of 2,010.4 MW in year 2021. The average generation capacity of these plants is 32% of contract capacity and 70% of tested capacity. On a plant by plant basis, the Sapele plant is an overwhelming underperformer given its contract capacity of 1020 MW and test and 2021 average generation capacity of 52.29 MW and 46.39 MW, being last tested in June 2021. This translates to a miserly 4.5% average generation capacity to contract capacity. Afam IV-V didn’t fare any better with contract capacity of 776 MW and test and average generation capacity of 121.9 MW and 66.75 MW respectively and last tested in July of 2021. For context, the output from Afam IV-V is a beggarly 8.6% of its contract capacity.

Test dates for the plants was between June and August 2021. Over two years ago. Still far behind the annual recommendation of NBET. The performance of plants in this category outmatch those of the NIPP plants managed by NDPHC despite the sub par productivity of Sapele, Kainji, and Afam IV-V respectively.

A look at Plants in other Categories

There are five plants that are classified by NBET as having active PPA namely: Okpai operated by Agip, Afam VI run by Shell, Omotosho Electric, Olorunsogo and Azura Edo IPP. All of these plants are gas fired with total contract capacity of 2,188 MW, tested capacity of 1,815.61 MW and average 2021 generation capacity of 1,338.68 MW. The average generation capacity of these plants with respect to tested capacity is 71% and 61% with respect to contract capacity – an indication of better performance. Of plants in this category, Azura Edo IPP with contract capacity of 450 MW and test capacity of 452.6 MW and average generation capacity in 2021 at 420.84 outperforms it peers. In context, average generation capacity with respect to test capacity and contract capacity stands at 92% respectively with last capacity test carried out in June 2022. Shell run Afam VI has contract capacity of 650 MW, tested capacity of 464.96 and average generation capacity of 261.04 MW in 2021 with last test date of July 2021.   In performance terms, the average generation capacity with respect to contract capacity and tested capacity stands at 40% and 71% respectively. For Agip run Okpai with contract capacity of 480 MW, it tested capacity is 464.96 MW with average generation at 261.04 MW. Last tested in July 2021. This translate to 56% and 54% of average generation capacity with respect to tested capacity and contract capacity respectively. Without doubt, Azura leads the pack in terms of production efficiency.

State Government owned plants Ibom Power, Mabon, Omoku FIPL, Trans Amadi FIPL, AFAM (Rivers IPP) FIPL, and Eleme have combined contract capacity of 870 MW, with tested capacity of 451.88 and average generation of 185.09. The average generation capacity of Ibom power of 12.53 MW compared to test and contract capacity of 112.83 MW and 190 MW respectively, translating to 11% of average generation to test capacity is an indication of operation plunging into an abysmal depth. The Mabon and Eleme are new plants in the inventory of NBET with their capacity test yet to be carried out.

The foregoing is the state of things with the plants based on data from NBET. Cash liquidity constraint is a major issue given collection inefficiency by distribution companies. This has a ripple effect on the sector, leading to inability of operators to pay gas producers. Additionally, the insufficiency of the transmission company to transmit contracted or test generation capacity due to infrastructural gap and vandalism has left the country with more than 20 plants with test capacity of 6,884.76 MW out of contract capacity of 13,461 MW and an average generation of 4,022 MW in 2021 to back up power from the grid with gasoline or diesel generators. The factors causing this inefficient operations has to be reigned in rather than pushing the much needed reform to turn things around into the long grass as done by successive governments. Economic growth, its attendant job creation and prosperity will continue to be an illusion with this sort of underwhelming productivity of the power generating plants.

“Key Parts of a Power Purchase Agreement” According to NBET

Tariff Structure – Provides the details of how NBET will pay for the duration the PPA is calculated.

Risk Allocation – Identifies all project related risks and allocates these risks to parties best able to bear them.

Conditions Precedent – Provides all the conditions precedents (CPs) which either the Buyer (NBET) or Seller (Owner of plant) must satisfy before the PPA can become effective.

Tenor of PPA – A standard NBET PPA has a 20 year tenor. There are clauses within the PPA to handle early termination due to either a Buyer’s or Seller’s default.

Project Documents – All documents that are connected to the PPA such as Engineering, Procurement and Construction, Gas Supply Agreement (GSA), Gas Transport Agreement (GTA), Operations and Maintenance, Long Term Service Agreement, Financing documents e.t.c.

Commissioning & Testing Procedure – Contains a set of guidelines for plant testing and commissioning.

Operation & Maintenance – Contains details of the maintenance and operational obligations of the Seller throughout the tenor of the PPA.

Conflict Resolution – Indicates clear procedures for conflict resolution in case of disputes and/or conflicts on invoices.

Metering – Sets out the rules about metering. However, in case of conflicts between PPA provisions and the metering code, the metering code supersedes.

Liability & Indemnification – Enumerates the parties responsible for certain failures and provides indemnification to both parties.

Insurance – States the required insurance coverage to be put in place by the Seller and how the proceeds will be administered.

Scheduling Notices – Provides a methodology by which the Buyer nominates for the dispatch of Net Electrical Output to be made available at the delivery point by the seller.

Force Majeure – Provides details of events to be considered as force majeure and possible payments during the occurrence of such events.

Adeniyi Adeoloye is a consulting Editorial associate at the Africa Oil+Gas Report.






Senegalese Power Plant Opts for Wärtsilä Long-term Service Agreement

Technology group Wärtsilä has signed a long-term service agreement for two years with ContourGlobal, an energy provider based in the United States.

The agreement covers the company’s Cap des Biches power plant in Dakar, Senegal.

The plant dispatches power to the national electricity distributor Senelec, and reliability of supply is essential. The Wärtsilä agreement is designed to ensure that the customer’s commercial and contractual terms and conditions are met. The order was booked by Wärtsilä in March 2023.

The plant delivers an output of 86 MW. The scope of the agreement includes all spare parts for major overhauls of the engines, optional field service personnel to carry out maintenance tasks, along with a guarantee limiting the downtime during scheduled maintenance procedures.

“We have worked closely with Wärtsilä on projects in different countries, and appreciate the professional and highly qualified support that they are able to deliver. This agreement provides us with important guarantees that will allow us to supply electricity to the grid in line with our commitments. Furthermore, it provides predictability of costs, while freeing our people to focus on their core business,” said ContourGlobal’s CEO for Africa, Ara Hovsepyan.

Nigeria’s New Power Minister Will Need Enormous Willpower in a Fraught Sector

By Fasilat Oluwuyi, Energy Access Reporter, in Ibadan

With the appointment of Adebayo Adelabu as Nigeria’s minister of power, the very crucial overseer of electricity supply in the country has again been sourced from Ibadan, the once famous hotbed of the country’s opposition politics.

In Bola Ige, former governor of Oyo State, of which Ibadan is the capital, the city provided the first minister of power in the current fourth republic, in 1999. Mr. Ige later moved on to become the nation’s Attorney General and Minister of Justice.

A chronic shortage of publicly distributed electricity has held down the Nigerian economy for all the 24 years of the current phase of democratic rule. Mr. Adelabu’s job is to reverse the course.

Adelabu has said the right things as he took the reins of the Ministry on Monday, August 21, 2023.

“A significant goal is the universal metering of households and addressing the challenges faced by our national power grid”, the new power helmsman declared in his new office. “The ministry will leverage on the Nigerian Electricity Act, 2023 to boost power supply in the country”.

He looked to the future: “We will equally pay critical attention to the options of renewable and alternative energies”.

The new Minister’s main claim to the role has been through his fierce, aggressive involvement in provincial politics. He is a grandson of Adegoke Adelabu, the late legendary politician of the pre-independence era, popularly known as Penkelemesi (a play on the words “Peculiar Mess”, which he often used to describe the dynamics of his time). In the 2023 elections, Adelabu contested for governorship of Oyo state on the platform of the Accord Party, after he failed to clinch the ticket of the All-Progressives Congress (APC), the ruling party at the centre.

But Adelabu is also quite familiar with the politics at the Federal level, at least on the periphery. You play close to the league when you are Deputy Governor of the Central Bank of Nigeria (CBN), a position he occupied for four solid years from April 9, 2014 to May 24, 2018.

Still, the job of bolstering Nigeria’s electricity delivery to improve the productivity of Africa’s largest population is not as easy as a structured oversight function in a plush office at the Central Bank. 85 Million Nigerians, almost double the population of South Africa, have no access to grid-connected electricity. The Manufacturers Association of Nigeria (MAN) reports that expenditure on alternative energy sources increased to around $100Million in the second half of 2022 . And President Bola Tinubu’s removal of subsidy on gasoline imports has inadvertently heightened the stakes for electricity for small scale businesses, for whom gasoline is the preferred fuel for generators in hundreds of thousands of mini- business clusters in Lagos, the country’s commercial heartland.

There is no shortage of advice on the table, ready for Mr. Adelabu’s review. One is the 66 page policy advisory report by a Power Subcommittee, commissioned by President Tinubu, which declares the electricity sector, as “fundamentally, an inadequate and unstructured governance environment”, which enables “numerous inefficiencies”. The team derides the electricity supply industry in one blistering phrase: “Low collaboration among regulatory stakeholders”, it says “hampers policy harmonization and coordination”.

Key suggestions from this report request the government to “define framework for successful participation of State Governments; restate commitment to phase out the Nigerian Bulk Electricity Trading (NBET), split the Transmission Company of Nigeria (TCN) immediately into transmission service provider and independent system operator, accelerate investment for Transmission Investment Programme through concessioning, address short-term sector liquidity and restructure for lending sustainability”.

The memo also calls on the Minister to “establish electrification intervention programmes for vulnerable unserved and underserved citizens and relaunch and accelerate the National Mass Metering Programme”.

There are critics, of course. And some of them are influential. “The latest appointment of a new Minister of Power, lacking industry experience”, writes Proshare, a widely read market analysis newsletter, “and the unfolding operationalization of the Electricity Act, with its ongoing effort to transition the sector into a wholesale competitive market, contribute to a climate of unpredictability”.

Will Adelabu succeed in this fraught sector?

One thing is clear: Tinubu’s Minister of Power is a well-educated, widely exposed professional. With a first-class degree in Finance from Obafemi Awolowo University (OAU), he has also taken professional courses in business schools such as Harvard, Stanford, Wharton, Columbia, Kelloggs, Euromoney, and the University of London. His career began at the elite consultancy PriceWaterhouse(now PriceWaterhouse coopers) where he led and managed various audit and consultancy engagements for large banks and non-bank financial institutions. He has been Group Head of Risk Management and Controls and latterly Group Head of National Public Sector Business at First Atlantic Bank; West African Regional Head of Finance and Strategy (Consumer Banking Business) at Standard Chartered Bank and eventually an Executive Director/Chief Financial Officer (CFO) of Nigeria’s largest bank, First Bank of Nigeria Plc.(CBN) at the age of 39.

TSK to Start Construction of 360MW Gas Fired Plant in Senegal from 2024

European engineering firm TSK, has partnered with Senegalese company LFR Energy for the construction of the Sandiara Power Plant, a gas-to-power facility located in Senegal’s Special Economic Zone (SEZ).

Construction is slated to begin in 2024.

“The consortium has ambitions to build the largest gas-to-power plant in Senegal with the objective to develop Sandiara as a regional energy hub through the exploitation of the country’s gas and oil resources,” says Pierre Diouf, CEO, LFR Enrgy.

The power plant will mostly run on domestic gas obtained from Senegal’s western hydrocarbon reserves, most likely the Greater Tortue Ahmeyim (GTA) and Yakaar Teranga gas basins. “Gas from GTA will be mostly used for export,” says Malick Guaye, First Deputy of the Municipality of Sandiara, who is in charge of the energy projects in the SEZ. “The Sangomar field has gas, but it is mostly an oil field, and first gas from Yakaar-Teranga will be exclusively for domestic use, making it the most appropriate field for the project.”

The gas will be transferred to the power plant via a pipeline connecting Sandiara and the Malicounda power station, which is currently under construction.

The power plant will comprise a combined cycle power station (CCG) that uses Siemens Energy SGT-800 gas turbines to meet industrial power generation demands. With a capacity of 360 MW and utilizing natural gas resources, the project is estimated to have an annual production capacity of 2,900 GWh.

Diouf said the plant will have the potential to integrate resources, “…perhaps with solar energy as well, since we intend to build photovoltaic panels near the plant.”

LFR plans to begin construction of the facility in the first quarter of 2024, with the goal of having it operational by 2026. The project will be funded by loans, mostly from the Emirati investment fund Al Furqan Credit, with the remaining half (around 15 to 20%), financed by shareholder equity. The project will be structured in accordance with Senegalese law governing public-private partnerships while the produced electricity, a portion of which will be dedicated to SEZ demands, will be provided by the state utility SENELEC under a 25-year power purchase agreement.



Nigerian Electricity Discos Apply for Tariff Hike

The Nigerian Electricity Regulatory Commission (NERC) says the eleven (11) successor electricity distribution companies (“DisCos”) have filed an application for rate review with the Commission.

“The request for rate review is premised on the need to incorporate changes in macroeconomic parameters and other factors affecting the quality of service, operations and sustainability of the companies”, NERC says in a release.

“Accordingly, the Commission hereby invites the general public for comments on the rate review applications by the distribution licensees.

“Interested stakeholders are advised to review and take into consideration the excerpts of the Rate Review Applications filed with the Commission by the respective licensees”.

The applications can be accessed on the Commission’s website at www.nerc.gov.ng.

As part of the rule-making process and in the exercise of the powers conferred by the Electricity Act, the Commission shall conduct a Rate Case Hearing on the applications prior to making a ruling.

“Any person wishing to participate in the proceedings as an intervenor should forward his/her application to tariff@nerc.gov.ng before close of business on 20th July 2023. The Request to Participate shall include the following:

  1. An explanation of the person’s interest in the proceeding and how the party would be affected by the outcome of the Application;

and ii. A description of the party’s concerns, observations comments and/or objections to the application.

All members of the public and stakeholders are encouraged to send their comments or representations before the close of business on 20th July 2023 to the following address: The Chairman/CEO The Nigerian Electricity Regulatory Commission Plot 1387 Cadastral Zone A00 Central Business District Abuja

Half a Billion People Gained Access to Electricity: Good News, but Not Enough

By Fasilat Oluwuyi, Energy Access Reporter

While Asians leaped ahead and Latin Americans crawled, SubSaharan Africans barely moved…

425 Million people in the world gained access to electricity in the 11 years between 2010 and 2021.

It is good news; that the human population without access to power dropped from 1.1Billion in to 675Million, in roughly a decade.

The not-so -good news is that Africans are largely excluded from this gain and the so-called recent progress is not on track to reach universal access by 2030.

The 2023 edition of Energy Progress Report declares that globally, access to electricity grew by an annual average of 0.7 percentage points between 2010 and 2021, rising from 84% of the world’s population to 91%. The pace of annual growth slowed during 2019–21 to 0.6 percentage points.

The trend differs across regions. Fifty-one countries in the developing world have achieved universal access in those 11 years, 17 of them in Latin America and the Caribbean. Another 95 countries, concentrated in Sub-Saharan Africa, were still short of the target in 2021, despite progress in about one-quarter of them—including half of the 20 countries with the largest access deficits (defined as the population lacking access to electricity).

In Sub-Saharan Africa, the number of people without access was roughly the same in 2021 as in 2010. Most of the decline in the unserved population came in Asia. The number of people without access plummeted in Central and Southern Asia, falling from 414Million in 2010 to 24Million in 2021, with much of the improvement occurring in Bangladesh, India, and other populous countries.

The number without access to electricity in Eastern and South-eastern Asia declined from 90Million to 35Million during the same period. In Northern Africa and Western Asia, the unserved population decreased less markedly—falling from 37Million in 2010 to 30Million in 2021.

The Energy Progress Report is a product of close collaboration among the five Sustainable Development Goals (SDG) 7 custodian agencies; International Energy Agency (IEA); International Renewable Energy Agency (IRENA); United Nations Statistics Division (UNSD); World Bank and  World Health Organization (WHO).

To bridge the electricity gap, especially for people living in poor and remote regions, the annual rate of growth in access must be 1 percentage point per year from 2021 onward—almost twice the current pace. If no additional efforts and measures are put in place, some 660Million people, mostly in Sub-Saharan Africa, would still be unserved in 2030.

In 2021, the 20 countries with the largest access deficits accounted for 75% of the world’s people lacking electricity access. The countries with the largest numbers without access were Nigeria (86Million), the Democratic Republic of Congo (76Million), and Ethiopia (55Million). In 2021, these top three countries are the same as in the previous edition of this report. India and South Sudan dropped out of the top 20, and Zambia and Mali joined it. Increases in electrification did not keep up with population growth in the Democratic Republic of Congo between 2019 and 2021. As a result, the access deficit there increased by about 2Million people. In contrast, the number of people without access in Nigeria and Ethiopia decreased by 2Million each year between 2019 and 2021, although those countries are still in the top three in terms of unserved population.

Policies for energy access should demonstrate political commitment and maximize the socioeconomic benefits of access, keeping the most vulnerable populations at the forefront of efforts to close the access gap.

Access to electricity is expected to improve through 2030, after the difficult economic conditions created by the COVID-19 pandemic and the war in Ukraine have stabilized. However, variations across countries will persist, and many countries will not reach universal access by 2030 unless much more is done, the report argues. “Even then, progress may be limited for countries with weak energy access–related institutions and policies. The outlook is better for countries with strong institutional and policy support for access, most of which have already made historic progress in bringing the benefits of electricity to their population. According to IEA’s Net Zero by 2050 Scenario, annual investment of $30Nillion will be required to achieve universal access to electricity by 2030”, the Energy Report explains.

Senegal Inaugurates a 120MW Thermal Power Plant;  to Utilise the “Coming” Gas Production

The President of Senegal, H.E Macky Sall has inaugurated a 120 Megawatts power plant that is designed to convert to the use of natural gas as soon it comes on stream from domestic fields which are currently under development.

The facility, co-developed by Africa50, Melec PowerGen (MPG), and the statel utility Senelec, is located in Malicounda, in Western Senegal, 67kilometres from Dakar.

The power plant started operations in August 2022 utilizing Diesel fuel, which will be converted to natural gas when the first of several hydrocarbon production projects come on stream before the end of 2023.  The plant will increase Senegal’s generation capacity by 8% and will substantially reduce generation costs, the government has promised.

The €154Million plant construction benefitted from financing through equity and senior debt, provided by the African Development Bank (AfDB), the OPEC Fund for International Development (OPEC Fund), the Arab Bank for Economic Development in Africa (BADEA) and Banque Ouest Africaine de Developpement (BOAD) as senior lenders following a prior EUR 75Million bridge financing arranged by Orabank Sénégal.



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