🍞 The Power Problem

Hello,

This is Demilade writing from the very green, peaceful BRB. Peaceful with an uninterrupted power supply, and no sound of generators deafening citizens and chasing away wildlife. An Island of under 300,000 people, the country has a power generation capacity of about 350 MW and demand of about 160 MW (about half its generation capacity). The generation company Barbados Light and Power is owned by Emera Inc, a Canadian energy holding company, with several GenCos in the Caribbean. Power here costs $0.33/kWh, which is twice as expensive as the $0.15/kWh Band A homes pay in Nigeria. Not to speak of the other bands.

National power supply is a delicate balance between creating incentives for corporations to invest in assets that would not break even for a long time, while maintaining the cost of power at a rate that citizens can afford.

Nigeria has a peak power demand of 20,000MW; we currently have the installed capacity for 13,000MW, of which 4,500 MW is available, and 3,300 is actually distributed. This means we have a challenge along the entire power chain. Firstly, we need to generate more, which means companies need to be incentivised to invest in power generation. We also need to ensure transmission from power plants is more efficient, and finally we need to ensure that this power is distributed more efficiently. i.e revenue from distribution can be paid back to gencos, so investors see that this is a commercially viable sector.

The laws of economics say that where supply is more than demand, prices should be low, and the opposite for where demand outstrips supply.

So how do we have cheaper demand than Barbados, where they supply double their demand, and we only supply 15% of our peak demand

The answer is a word most of us are sick of by now…SUBSIDY!

As usual, if you are not subscribed, please do so here; and if you are, send this to people who you think would find this valuable.

Enjoy!
Demilade

Stocks: The NGX All-Share Index eked out a 0.12% gain over the week to 245,573.60 points, lifting market capitalisation to N158.5 trillion and the year-to-date return to 57.81%, though the headline flattered a soft tape, with decliners outnumbering gainers 63 to 26. A 2.33% jump in the banking index, led by FCMB and First HoldCo, did most of the lifting.

Currency: The naira slipped in the official window over the week, closing Friday near N1,365.7 to the dollar, down about N2.53, before firming to roughly N1,361.5 to open this week. The parallel market held around N1,425 to N1,430, keeping the premium over the official rate at about N60.

Commodities: Brent crude stayed firm above $88 a barrel, buoyed by tensions over the Strait of Hormuz, a helpful backdrop for Nigeria's export receipts and the roughly $52 billion in external reserves, even if elevated crude also feeds pump-price and import-cost pressure at home.

On 9 August, FMDQ Securities Exchange flagged Geregu Power's ₦40.09 billion Series 1 bond as being in credit default. The company had missed both a coupon (interest) payment and a scheduled principal repayment, roughly $29 million of obligations, halfway through the life of a bond that matures in July 2029. This was not a company that failed to refinance at the finish line. It ran out of cash in the middle of the race.

A generation company is meant to be the boring, dependable link in Nigeria's electricity chain. It owns turbines, it produces a commodity the whole country is desperate for, and it sells that commodity under long-term guaranteed contracts. On paper, it is the closest thing the Nigerian power sector has to an annuity. So when one of the most prominent listed Gencos misses a payment on its own bond, the interesting question is not really about Geregu. It is about the machine Geregu is plugged into, and why that machine has never reliably turned electricity into cash. To understand the default, you have to understand how the sector is wired. And to understand the wiring, you have to start with why it was rebuilt in the first place.

For most of Nigeria's independent history, electricity meant one organisation: the National Electric Power Authority, NEPA, formed in 1972 from the merger of the Electricity Corporation of Nigeria and the Niger Dams Authority. NEPA was a single, state-owned monopoly that generated, transmitted, and distributed power across the entire country. It also became a national punchline. The acronym was widely rechristened "Never Expect Power Always", and the joke captured a real failure: decades of underinvestment, a grid that expanded far slower than the population, and blackouts so routine that self-generation by diesel “generators” became a permanent feature of Nigerian life.

By the early 2000s, the political consensus was that a single government monopoly could neither fund nor run the system. The Obasanjo administration set the reform in motion, and the foundational legal step was the Electric Power Sector Reform Act of 2005. The Act did two things that still shape the market today. It created the Power Holding Company of Nigeria, PHCN, which absorbed NEPA's assets, liabilities, and staff as a transitional holding vehicle, and it laid the legal groundwork to break that vehicle apart and hand the pieces to private owners.

The mechanics took years. The government published a "Roadmap for Power Sector Reform" in 2010 to sequence the handover, and set up the institutions the new market would need, including the Nigerian Bulk Electricity Trading Company, NBET, incorporated in July 2010. The physical transfer finally happened on 1 November 2013, when private investors took possession of the unbundled successor companies through a bidding process run by the Bureau of Public Enterprises. It was described at the time as one of the largest power privatisations in the world. Geregu Power, the gas plant in Kogi State, was one of the assets that changed hands.

That date, November 2013, is where the modern sector begins. Everything that has happened since, including this month's default, is a story about whether the structure created that day can actually pay for itself.

The privatisation replaced one monopoly with a chain of specialised businesses, a design often summarised as the 11-6-1 model. Six generation companies, the Gencos, were sold to private owners. Eleven distribution companies, the DisCos, were handed to private investors to deliver power to homes and businesses. And one company, the Transmission Company of Nigeria, TCN, was deliberately kept under government control to run the national grid that links the two ends together.

It helps to picture the physical flow. Gencos like Geregu burn gas (or, in the case of the hydro plants, use water) to produce electricity. That power is fed onto TCN's transmission grid, the high-voltage backbone that moves it across the country. The DisCos then take power off the grid and deliver it down to the feeders and transformers that reach actual customers. Generation at one end, your meter at the other, transmission in the middle.

What Geregu sells, then, is not quite "electricity" in the way a shop sells bread. It sells available capacity and energy sent out onto the grid, and it gets paid according to contracts and a tariff structure set by the regulator, the Nigerian Electricity Regulatory Commission, NERC. This distinction matters A LOT, because it means a Genco's revenue does not come from the customer who flips a switch. It comes from a settlement system sitting between generation and distribution. And that settlement system is where the sector's real problem lives.

Here is the flaw the whole structure has never escaped. The people who consume the electricity pay the DisCos. But the DisCos have historically been the weakest link in the chain, and much of the money never makes it back up to the companies that produced the power.

To manage this, the reform placed a single institution in the middle of the cash flow: NBET, the bulk trader. The design was elegant on paper. Because investors did not trust the newly privatised DisCos to be creditworthy, NBET, which is fully government-owned, was set up to be the reliable counterparty instead. NBET buys power from the Gencos under long-term power purchase agreements, and sells it on to the DisCos under vesting agreements. The Gencos get to contract with a government-backed buyer rather than eleven shaky distributors. In theory.

In practice, the cash does not flow cleanly through that pipe. DisCos struggle to collect from customers, partly because a large share of the market is still unmetered and billed on estimate, and they remit only a fraction of what they are invoiced. When the DisCos under-remit, NBET does not receive enough to pay the Gencos in full. When the Gencos are not paid in full, they cannot fully pay their gas suppliers or fund the maintenance their turbines need. The cash stops moving, and the physical system degrades behind it. This is the vicious circle that has defined the sector since 2013.

The scale of the resulting hole is enormous. The Association of Power Generation Companies has put the total owed to generation companies at roughly ₦6.5 trillion ($4.7 billion). To begin clearing this backlog, President Tinubu approved a ₦4 trillion ($2.9 billion) bond programme to settle legacy debts across the value chain. Those are not the numbers of a functioning commercial market. They are the numbers of a system that has been quietly accumulating unpaid bills for over a decade.

The formal name for the mechanism that decides who eats the shortfall is the Distribution Companies' Remittance Obligation, or DRO, framework. Under it, DisCos are required to remit only the portion of their invoices that matches their allowed revenue recovery, and the Federal Government absorbs the rest: the gap between what electricity actually costs to produce and what customers are charged for it. That government-absorbed gap has a name familiar to most Nigerian’s by now… You guessed it, it's another “subsidy”.

Before we get to the subsidy, it is worth noting that the sector is in the middle of a second wave of reform aimed squarely at this cash problem.

The Electricity Act of 2023 decentralised the market, giving Nigeria's states the constitutional power to regulate and build their own electricity markets rather than leaving everything to the federal centre. Lagos and several other states have begun creating their own frameworks, and some have achieved extremely positive outcomes. The Act also enabled a further unbundling of the grid operator, separating out a Nigerian Independent System Operator to run market and system operations.

The more visible change arrived in April 2024, when NERC moved a slice of customers onto cost-reflective pricing. Under the "Band A" classification, customers on feeders that receive 20 or more hours of supply a day were moved to a much higher tariff, around ₦225 per kilowatt hour, a rise of over 300% for that group; cheaper than most of our neighbours, but dismal for a country with an abundance of gas, solar and hydro power. The logic was that customers getting the best supply should pay something close to the true cost of it, which would reduce how much subsidy the government had to inject to keep the market solvent.

Band A raised real money. NERC data indicates the tariff migration brought in an additional ₦1 trillion or more per year. But the policy has come under visible strain. Reporting through 2026 describes the band regime unravelling in places, with DisCos failing to deliver the promised supply hours that justify the Band A rate, and NERC effectively freezing the feeder-downgrade and compensation provisions that were meant to protect customers when supply falls short, because doing otherwise would collapse revenue further. The push toward cost-reflective tariffs is great, but it is running ahead of the sector's ability to actually deliver the power that pricing assumes.

Now put Geregu back into this picture, and the default stops looking like a company-specific accident and starts looking like the structure doing exactly what was expected when under stress.

Geregu attributed its trouble to a planned ₦61.47 billion turbine maintenance programme. Taking turbines offline for a major overhaul strips out billable capacity, and the financial results show how violently that fed through. Revenue for the first half of 2026 fell by roughly 79%, and profit after tax collapsed by 88%, to ₦2.54 billion from ₦20.27 billion a year earlier. A large capital-intensive maintenance programme collided with a sharp drop in the output the company could bill for.

In a healthy commercial market, a well-run generator could absorb a scheduled overhaul. It would have been paid reliably during the good years, built a cash buffer, and drawn it down. But this is NOT A HEALTHY MARKET. This is a sector where generators are owed trillions, where the buyer in the middle cannot always pay, and where cash has always arrived late and incomplete. In a system with structurally thin buffers, a Genco that loses most of its billable output for a period has nowhere to hide.

This is why the sharpest way to read the Geregu numbers is the gap between the balance sheet and the cash. The company could point to some balance-sheet resilience, including ₦16.12 billion of impairment reversals and total liabilities falling to ₦239.33 billion. GCR Ratings even held its long-term rating at A(NG) with a stable outlook, betting on recovery once the turbines return. And yet the company still missed the payment. A firm can look solvent on paper and still fail to meet an obligation on the day it falls due, because solvency is an accounting position and payment requires cash in the account.

Which brings us back to the power subsidy, and to the reason this default should matter to anyone watching the sector rather than just this one company.

The subsidy is the prop holding the whole structure upright. It is the government money that fills the gap between what power costs and what customers pay, the injection that lets NBET pay the Gencos even when the DisCos do not remit enough. And the government has now signalled it wants to remove that prop. In late July 2026, the Minister of Power, Joseph Tegbe, said the Federal Government plans to phase out electricity subsidies from 2027, framing it as part of restoring the commercial viability of the market. The subsidy has been a heavy fiscal burden for years, estimated at around ₦3 trillion as of February 2024, and the IMF has repeatedly urged Nigeria to end it. The government says there will be no immediate tariff increase, and that a Power Consumer Assistance Fund will cushion vulnerable users.

All good in theory, but NERC's own data shows the government's subsidy obligation fell from ₦418.79 billion in the final quarter of 2025 to ₦358.32 billion, roughly $262 million, in the first quarter of 2026. On the surface, that looks like progress: the subsidy bill is shrinking. But NERC was explicit that the decline came mainly because DisCos took less power off the grid, not because tariff recovery genuinely improved. The subsidy did not fall because the market got healthier. It fell because less electricity moved.

That is the balance-sheet-versus-cash problem again, only now it is a policy risk rather than a company one. A subsidy figure that falls for the wrong reason can flatter a market without improvement. If the government withdraws the subsidy while the underlying collection and remittance problem is unfixed, the shortfall simply moves onto the books of the DisCos and, behind them, the Gencos.

🏭 Ajaokuta Steel gets its gas after 50 idle years. Nigeria signed a 20-year supply deal with NNPC in July 2026 to deliver up to 50 million standard cubic feet of gas a day to Ajaokuta Steel, resolving a demand investors have pressed for years. The complex has swallowed more than $8 billion since 1979 without rolling a single commercial coil, despite reaching 98% completion back in 1994. The 2026 budget allocated N6.69 billion to the plant, 90.4% of it for personnel costs. The Tinubu administration is in advanced talks on a production-sharing partnership with a Chinese investor, with a deal expected before year-end. A working Ajaokuta could trim Nigeria's iron and steel import bill, which ran between $225 million and $298 million across 2024 and 2025, and ease pressure on forex. The half-century track record still counsels caution: watch for the Chinese deal to close and for any sign of blast-furnace commissioning.

💳 NGX chief pushes Tinubu for a fintech listing mandate. NGX chief executive Temi Popoola has asked President Tinubu to back policies requiring high-growth companies, especially fintechs, to list at home or dual-list. Speaking at a State House meeting, Popoola warned that firms earning large revenues in Nigeria plan to float abroad, locking out local investors, and named OPay and PalmPay as candidates weighing overseas listings. Nigeria's top nine fintechs, including Flutterwave, OPay, Moniepoint and Paystack, are worth a combined $10.6 billion as of January 2026; listing them all would add roughly 8% to NGX market cap. Popoola projected market cap could reach N230 trillion ($170 billion) by year-end, up from N160 trillion ($120 billion) now and about N30 trillion ($22 billion) when Tinubu took office in 2023. No fintech unicorn trades locally today, so a listing wave could reshape an index still dominated by banks. Watch for concrete rules on mandatory or dual listings, and any tax incentives for domestic IPOs.

🛢️ Tinubu revives the NNPC listing plan. President Tinubu told the Nigerian Exchange Group on 6 August 2026 that NNPC Limited will be reformed and floated in full, promising "the totality of it, not just arms and legs". The idea dates to 2016 and was mandated by the 2021 Petroleum Industry Act, whose 2022 listing deadline the company missed. Group chief executive Bayo Ojulari has pointed to a 2028 listing, and NNPC has begun an IPO beauty parade, though there is still no approved transaction, no NEC endorsement, no SEC registration and no NGX filing. A 10% float at a conservative $40 billion valuation would dwarf current heavyweights such as Airtel Africa and Dangote Cement and roughly double the energy sector's weight on the index. One complication: in February 2026 Tinubu stripped NNPC of its 60% share of production-sharing proceeds, aiding fiscal discipline but raising questions about cash flow ahead of a float. Watch for a NEC endorsement, a transaction adviser mandate and audited 2025 accounts before treating it as real.

🌍 Africa wants the solar factories, not just the panels Africa's largest economies are pushing to manufacture solar equipment at home rather than import it, mostly from China. Chinese renewable energy investment and construction across the continent reached $66 billion between 2010 and 2024, according to ODI Global. South Africa brings in more than 3 gigawatts of solar equipment a year, largely Chinese, making it one of the strongest candidates for local production. Morocco has doubled output to around 1 gigawatt a year, and Egypt has gigawatt-scale projects coming online. The catch, according to Benjamin Clarke of the Africa Solar Industry Association, is that most new plants assemble imported Chinese parts rather than make the high-value cells, leaving the continent dependent on foreign technology for the hardest part of the chain.

🇰🇪 Dangote takes his Nigeria lessons to Kenya Aliko Dangote is carrying the hard-won lessons from his Nigerian refinery into Kenya, where he plans a $16 billion, 700,000 barrels-per-day refinery at Lamu to serve East African markets. He intends to fund roughly 70% of it with debt. Having watched cheap imports undercut his Lagos plant, Dangote says the Kenyan project will need state protection from imported fuel to stand a chance. The move comes as he prepares an initial public offering of the Nigerian refinery, and forms part of a wider $46 billion push across refining, cement and fertiliser between 2026 and 2028. Forbes puts his net worth at $28.5 billion.

🇪🇬 Qatar bets $30 billion on Egypt's coastline Qatar's sovereign wealth fund is backing one of the largest foreign real estate ventures in Egypt's history. Through its property arm Qatari Diar, it plans to invest around $29.7 billion in Alam El-Roum, a stretch of Mediterranean shoreline in Matrouh Governorate about 480 kilometres northeast of Cairo. The masterplan calls for luxury residences, marinas, golf courses and public infrastructure, turning a remote coastline into a year-round tourism hub. A first phase of roughly $4.5 billion is due to begin. It is Qatar's biggest single investment in Egypt, and part of a broader Gulf bet on the country's roughly 3,000 kilometres of coast as Cairo works to steady a strained economy.

If this is useful, don't gatekeep. Forward this to one person who needs it. That's how we grow 🍞