Hello, ladies and gents, and welcome to the second issue of our signature series, Power Trip.
Last issue, we followed the gas that kept your lights on during the summer and the growing bill for buying it from abroad. This time, we look at what’s being built to take some of that load. The sun and wind come at no cost. Everything else has to be paid for: the developers who build the plants, the banks that lend for 20 years in foreign currency, the factories that make the equipment, and the companies willing to buy the power.
Welcome to The Transition, where we look at what it takes to build an electricity system that needs less of that scramble. The issue follows the people doing each of these jobs. Who is building Egypt’s new power plants, and why does the state want private developers to build most of them? Who lends the money for nearly 21 GW of renewables by the end of 2029, and who carries the risk? How much of a solar panel, a wind turbine, or a battery is made here, and what exactly is a “lego factory”? And lastly, has the energy crunch made anyone more eager to go solar?
Next issue, we head out to the ports, pipelines, and cables that would make Egypt a regional hub. After that, we come home to your bill, your roof, and your car.
Egypt’s next power plants need more than sunshine and a good breeze. They need someone willing to build them — and someone willing to buy the power. We’ve previously followed the gas that keeps the country running and the growing cost of buying it from abroad. Now, we turn to the companies building alternatives, the contracts that make their investments possible, and the state’s changing role.
The power brokers
Meet the independent power producer, or IPP: an electricity generator owned and operated outside the state utility’s fleet, though the state is usually still the one buying the power. “The private sector develops, finances, builds, and operates a power station, and sells the electricity under a long-term commercial arrangement rather than the government building the plant itself,” Infinity Power’s Deputy CEO Ahmed Mulla tells EnterpriseAM. Inside those four verbs sit land permits, resource and environmental studies, the electricity sale agreement, financing, equipment, and contractors — as well as involvement that runs through the asset’s operating life.
The developer, the owner, and the builder are not necessarily the same company: a dedicated project company owns the plant and raises its financing, specialist contractors build it, and separate arrangements govern operations. That’s what “build, own, and operate” means when it turns up in our daily reporting: the project company retains ownership and operates the asset under agreed terms. Add a “T” for transfer and an eventual handover is built in. A long-term electricity contract on its own doesn’t mean the state takes ownership when it expires.
SOUND SMART- An IPP doesn’t have to build from scratch. The 580 MW Gabal El Zeit wind farm in the Gulf of Suez near Ras Gharib was developed under the state’s New and Renewable Energy Authority, rather than as an IPP project. Alcazar Energy’s proposed acquisition — currently under financing consideration by the International Finance Corporation (IFC) — illustrates another route in: buying an existing public asset.
Joint custody of the watts
There’s often more than one name on the ownership papers. Partners bring different strengths — development expertise, local knowledge, capital, technology, financing — and the split reflects that partnership rather than a formula, Mulla says. The project company behind West Minya’s 1 GW solar plant and 600 MWh battery system is 51% Infinity Power and 49% Hassan Allam Utilities Energy, with a shareholders’ agreement determining how decisions get made.
A majority stake is not a freehand, though: “51% ownership does not necessarily mean one shareholder can simply make every decision,” Mulla says. Taking on substantial debt, changing the business plan, or materially altering contracts typically carries governance protections, with some issues requiring both partners’ consent, he adds. Some developers sell down stakes in operating assets to release capital for their next projects, while others hold them for decades.
Sunny, but still a few clouds
Before any of that comes a more basic question: is this project worth building? “Good wind or solar resources are necessary, but they are nowhere near sufficient [on their own],” Mulla says. A developer also needs secure land rights, workable permits, a buyer capable of paying, sensible contracts, a feasible construction plan, and financing that leaves an acceptable return for the risks involved. “A project being strategically attractive does not always make it investable,” Mulla says. Developers should not commit capital when payment protection is insufficient, returns do not compensate for the risks, or contracts leave them carrying risks they cannot control or price. Viable transmission capacity is another prerequisite: however good the resource, the electricity needs somewhere to go (a question we’ll come back to in the next issue).
Let’s talk terms
A developer considering a plant needs a credible answer to who will buy its output and how it will get paid. That’s the job of the power purchase agreement, or PPA — the contract that turns a proposed asset into a business with an identifiable revenue stream. It sets out both parties’ obligations, the payment mechanism, the duration, and how risks are divided, which is what lets investors and lenders judge whether the project can recover its costs and repay its borrowing. Terms often run 20-25 years, Mulla says, because most of the investment happens before the first unit is sold.
A contract still leaves plenty of risk: “A PPA does not simply ensure the developer a return regardless of performance,” Mulla says. Weaker-than-forecast wind or sunshine risk generally sits with the project, as does technical unavailability within the operator’s responsibility. PPAs can also include deemed-generation or curtailment provisions covering electricity the plant could have produced but was prevented from supplying. Under take-or-pay, the buyer commits to paying for an agreed quantity even if it takes less, subject to the contract’s conditions — which doesn’t excuse the producer from its own obligations. Scatec describes its Dandara agreement with EgyptAlum that way, while its Energy Valley agreement as pay-as-produced, linking compensation to generation.
Why this model sits at the center of the transition
Three forces come together: The scale of investment Egypt needs, the economics of renewable generation, and energy security, according to Mulla. Private developers bring capital and delivery capability to a buildout that would otherwise fall to the state, and the commercial case has improved, as solar, wind, and increasingly storage can be deployed at scale and at competitive costs. Readers of our first issue will recognize the purpose: Egypt’s conventional energy bill is mounting, and renewable investments are directly linked to reducing costly LNG imports and pressure on foreign currency reserves.
Independent, with the state on speed dial
The state is changing jobs, but it isn’t clocking out. Developers take on development, construction, financing, technology, and operating-performance risks — they arrange the capital, appoint contractors, and are accountable for delivering the plant, Mulla explains. Government entities remain central to regulation, land allocation, permitting, system planning, and, under the traditional utility PPA model, supporting the electricity buyer’s ability to pay. “We expect government offtake backed by a sovereign commitment to remain an important demand driver,” Scatec Business Development Director Mahmoud Shata tells EnterpriseAM. Having a project company raise money and build the plant changes the state’s upfront responsibilities; it doesn’t erase the public buyer’s obligation to pay for electricity over the contract’s life.
The factories would like a word
The next shift is who gets to be the customer. Shata points to the government’s pilot framework for private-to-private (P2P) projects. Under this model, an eligible renewable producer contracts directly with an industrial consumer and pays for use of the transmission network to deliver the electricity, Mulla explains. EgyptERA’s published pilot framework allowed for five projects totalling 500 MW, capped at 100 MW each — with four projects qualifying, according to Mulla. It is a controlled opening with eligibility conditions, rather than a market where every customer can immediately choose a generator.
Why would a factory bother? Mulla identifies three priorities: competitive electricity, price certainty, and lower carbon intensity. He sees potential demand from aluminium, steel, cement, data centers, and export manufacturing, with Europe’s carbon border adjustment mechanism adding another incentive for affected exporters to reduce emissions. Mulla expects direct industrial sales to grow while stressing that government-backed utility PPAs will remain extremely important.
Generating power or just headlines?
“Signing a PPA is an important milestone, but it is not the same thing as having a project under construction,” Mulla says. What remains can include permits, environmental approvals, land and connection arrangements, and engineering, equipment, and construction contracts — then the lenders’ examination and the conditions required to access financing. Financial close is a distinct milestone, with construction, testing, and commissioning still to follow.
REMEMBER- The government’s July roadmap put installed renewable capacity at about 9.5 GW and targeted roughly 11.2 GW by end-2026, 16.8 GW by end-2027, and 27.7 GW by end-2028, with renewables accounting for 45% of electricity generation. That’s close to a tripling from the reported July baseline in around two years.
How much of the expansion can IPPs deliver? “I think the answer is most of it, provided the enabling infrastructure and project pipeline move at the same pace,” Mulla says. His progress report would track five things: capacity reaching financial close, transmission upgrades entering service, workable PPAs being executed, storage and other flexibility being deployed, and a functioning P2P market emerging.
“The challenge now is converting an exceptionally large development pipeline into bankable projects, and bankable projects into operating MWs quickly enough to meet the 2030 ambitions,” Mulla says. Behind every announcement, that is the business to follow: who commits the capital, who promises to buy power, and when the plant starts earning its keep.
For an industrial site, agriculture project, hotel, or real estate development, the first solar question is whether the economics work. Load profile, available space, and commercial structure determine project size — and whether the numbers hold up over time. TAQA Arabia’s solar arm, TAQA PV, has developed more than 120 MW of renewable-energy projects, with more than 200 MW in the pipeline. Its portfolio avoids more than 120k tons of carbon emissions annually.
The math changes with the site. Under self-consumption or power purchase agreement (PPA) models, businesses match renewable energy to their operating profiles, while system size and financing are tailored to each project. The project has to work for one customer, in one location.
TAQA PV’s project mix makes the point. The company developed a 6 MW solar plant for Dina Farms, a 7 MW project for calcium carbonate producer Ascom, and a 13 MW project serving an industrial zone, alongside other renewable-energy projects tailored to a wide range of client needs. Loads vary, and so do the economics and designs.
The commercial structure matters just as much as the panels. Long-term financing can support the upfront investment, while PPAs define the commercial relationship with the customer. The technology may be familiar; the business case still has to be built site by site.
Sometimes solar sits behind another utility altogether. TAQA Water serves more than 170k customers across residential, tourism, industrial, and agricultural sites, including Palm Hills in New Cairo, SODIC on the North Coast, Rixos Sharm El Sheikh, Makadi Heights, and La Vista, among many others. Its desalination systems are designed to use 50% less energy, while at Somabay, TAQA Water powers its desalination plant entirely with solar energy, demonstrating how renewable integration can reliably serve energy-intensive developments and tourism infrastructure.
The portfolio also includes utility-scale projects. In Nabq, Sharm El Sheikh, TAQA Arabia operates a 20 MW solar plant alongside a distribution concession for the area. The plant generates more than 42 GWh of clean electricity a year, which TAQA Power delivers to hotels, residential communities, and other customers across Nabq.
Scaling solar — and the utilities it can power — means repeating the calculation, not copying the project. Before construction starts, the load, site, financing, and commercial model all have to add up. TAQA Arabia’s job is to find the combination that does.
To learn more about TAQA Arabia, your trusted energy and utility partner,click here.
Somebody has to lend Egypt the money to more than triple its renewables capacity by 2029 — and how that lending gets structured will help decide what the electricity costs at the end of it. Right now, “debt financing is predominantly provided by development finance institutions (DFIs), as commercial lending appetite is still lagging,” VP of Business Development at Scatec Mahmoud Shata tells EnterpriseAM.
The shape of the debt explains why: These projects run on long-term project finance, foreign currency lending, debt at 70-80% of total project costs, and repayment periods extending up to 20 years, Mahmoud Morsy, principal banker in the SI MEA team at the European Bank for Reconstruction and Development (EBRD), tells EnterpriseAM. “Providing this type of long-tenor financing at competitive pricing remains challenging for many commercial banks, particularly in local and regional markets,” he adds. Because renewables combine high upfront costs with “relatively compressed returns,” even small reductions in the cost of financing “can have a meaningful impact on project viability and affordability,” Morsy says.
Development lenders take the first risk
A DFI’s job is to make a project safe enough that someone else will lend to it. Renewables in Egypt are typically financed on a non-recourse basis, with debt making up most of the capital stack, Shata says. The local market can’t carry that alone, so DFIs step in as the first lender. “Sponsors often view EBRD as an anchor lender whose involvement provides comfort on the project’s structure, risk allocation, and overall bankability,” Morsy says. EBRD financed 16 of the 31 projects that reached financial close under Egypt’s feed-in tariff program, Morsy says, and has kept lending since. DFIs have also been first in on newer technologies like battery storage, setting a precedent that brings the rest of the market in behind them, Shata adds.
The trick is stacking lenders by how much risk each can stomach: Scatec’s solar-and-storage project in Upper Egypt, costing more than USD 590 mn, closed with USD 479.1 mn from development finance institutions: USD 184.1 mn from AfDB, up to USD 173.5 mn from EBRD, and financing from BII. The concessional layer is what pulls private money in behind it: “in many cases, a relatively small amount of concessional or risk-sharing support can unlock a significantly larger volume of private capital,” Morsy says. Those structures also extend tenors and cover specific risks that would otherwise keep lenders out, he adds.
None of this makes the risk disappear — it changes who prices it: Guarantees and risk-sharing facilities move all or part of a project’s financial risk to another party, according to the IFC, and the World Bank says they can cut financing costs and improve terms. Somebody still carries the risk: a commercial lender, a developer, a DFI, or a guarantee provider, each with its own cost and appetite. If none of those structures makes a project bankable, the financing doesn’t materialize.
Commercial banks follow under a DFI’s umbrella
Here’s how a commercial bank gets comfortable enough to join: On the 1.1 GW Suez Wind project, jointly owned by Saudi Arabia’s Acwa Power and Hassan Allam Utilities, EBRD arranged a USD 275 mn syndicated loan. It comprises a USD 200 mn A loan and USD 75 mn in B loans from Arab Bank and Standard Chartered, alongside co-financing from AfDB, BII, DEG, the Opec Fund, and Apicorp. The two banks lend under the EBRD’s lender-of-record and preferred creditor status. The structure is designed to attract “commercial financing that might not otherwise be available to the market,” Morsy says.
What lenders need to see before they say yes
Is a signed contract enough on its own? Lenders want confidence in the offtaker’s creditworthiness, tariff certainty, currency protections, and contractual remedies, and the sponsor’s balance sheet has to show enough cashflow to service debt and still return something. Those are usually the sticking points at financial close, Morsy says.
Currency is the exception: FX has been “the largest source of uncertainty over the past years for both developers and lenders alike,” Shata says. A USD-denominated tariff guards against a weaker EGP, but it doesn’t ensure greenbacks will be available when repayment falls due. That exposure sits with the off-taker and, behind it, the sovereign. Developers and lenders handle it through structural mitigants in the financing and project agreements, Shata says.
The state is also rethinking how it issues that backing. The government is working with the World Bank on a proposed Infrastructure Finance Guarantee Facility that would route risk cover through a defined pool instead of a fresh sovereign guarantee for every project. That matters more as the pipeline grows, since each new project adds to the guarantees outstanding. The USD 520.38 mn facility pairs USD 150 mn from the World Bank with USD 370 mn in unguaranteed commercial financing: the state covers specific project risks, and private lenders carry the rest. Renewables are among the first targets.
The model works, now it has to scale
OUR TAKE- Egypt has shown it can close large renewable projects — the question is whether it can do it at 21 GW scale. So far, it has drawn on a limited pool: DFI debt, concessional finance, guarantees, and sovereign-backed PPAs. Meanwhile, regional conflict and inflation are raising debt costs, and “heavy competition continues to drive energy prices lower, creating a more challenging business case,” Shata says. The missing piece is domestic capital, Morsy says. Creditworthy private off-takers would help, and so would local supply chains, which would cut reliance on imports and foreign-currency funding and open the door to local-currency lending.
Since we last spoke with Rosatom Egypt Country Director Murad Aslanov (LinkedIn) inNovemberlast year, Dabaa has moved further toward generating its first electricity. We caught up with Aslanov to discuss where nuclear fits alongside renewables and what local companies are gaining from the buildout.
EnterpriseAM: What role will Dabaa play alongside solar, wind, and battery storage, and does nuclear justify its high upfront cost and long construction timeline?
Murad Aslanov: The goal is a diversified system where each technology does a different job. Nuclear provides firm, low-carbon power around the clock and keeps the grid stable. Solar and wind supply growing volumes of clean power, batteries add flexibility, and a stronger grid ties it together. Nuclear’s cost has to be judged over the plant’s full life, and Dabaa is built to run for more than 60 years. Over that period, it delivers large volumes of predictable power, cuts exposure to fuel-price swings, and redirects natural gas toward industry or export. It also creates long-term demand for engineering, manufacturing, and training, which builds skilled people and local supply chains. So the case for nuclear goes well beyond megawatts.
Dabaa is on schedule and already contributing to the economy during construction. The next milestone is the arrival and loading of the first nuclear fuel, with the site being prepared to receive the first shipment in May 2027. Once fully operational, the plant should generate about 35 TWh a year, saving roughly 7 bn cbm of gas annually.
EnterpriseAM: Where do talks on the two additional reactors stand, and what would decide whether they go ahead?
MA: What has been officially confirmed is that Egypt and Rosatom are continuing discussions on the future development of peaceful nuclear technologies. The Egyptian side expressed interest in following developments with additional nuclear units and assessing their possible future application. Any decision on additional nuclear capacity would naturally be led by the Egyptian side and would require a comprehensive assessment. From Rosatom’s perspective, the crucial point is that the cooperation framework exists and that we are ready to discuss different technological solutions if and when Egypt determines that additional nuclear capacity is needed. The priority today remains the successful and safe completion of the four units at El Dabaa according to the agreed schedule.
EnterpriseAM: What role are Egyptian companies and workers playing at Dabaa, and what skills and capabilities will stay in Egypt once it’s built?
MA: Egyptian participation rises from around 20% on Unit 1 to as much as 35% on Unit 4. The aim is to help local companies qualify against the nuclear industry’s demanding technical, quality, and safety standards. As of August, more than 25k people were working on site daily, over 70% of them Egyptian, and that number will rise as construction accelerates. Around 220 local companies are subcontracting in civil, mechanical, and electrical work, as well as supply and supporting infrastructure, while major local contractors are building experience under nuclear-grade requirements. Egyptian staff will operate Dabaa, with Rosatom providing operational and maintenance support for the first 10 years. The long-term outcome is qualified people, capable companies, and industrial know-how that can carry Egypt’s next generation of technology projects.
Two substations can have the same capacity on paper and do entirely different jobs in the economy. At KAHRABA, we see that clearly in Belbeis and New Borg El Arab. In Belbeis, KAHRABA has approval for a project serving a water-intake pumping station supplying communities east of Cairo. In New Borg El Arab, another approved project will serve the Fifth Industrial Zone. Each has 80 MVA of contracted capacity, expandable to 120 MVA. Their capacity profiles may look similar, but the demand behind them is very different.
For industry, power is local. National generation figures tell us how much electricity the system can produce. They do not tell a manufacturer whether a particular industrial plot can connect at the capacity it needs. What matters on the ground is whether the network can deliver that power to the site.
The next question is when that demand will arrive. Factories come online at different times, install different equipment, and expand at different rates. For us, planning means looking beyond what the network carries today to what it may need to carry next.
We can already see that demand rising across our networks. KAHRABA, Valmore Holding’s power generation and distribution business, serves more than 1.5k industrial, agricultural, and commercial clients, and it increased electricity distribution volumes by over 40% y-o-y in 1H 2026. Its total installed capacity stands at around 710 MW. Planning what comes next means looking at where capacity is available, what new connections will require, and which parts of the network will need reinforcement.
Building the substation is only part of the job. Under the approved public-private partnership framework, KAHRABA will assume the right to utilize and operate the substations, interconnection lines, and feeding networks. That makes us responsible for what happens after construction too: maintaining asset performance and making room for future demand as the areas they serve grow.
For industrial growth, the map matters as much as the megawatts. More generating capacity can coexist with local bottlenecks, and those constraints have to be addressed where they occur. That is why we plan around where future demand is likely to emerge, rather than looking at national capacity alone.
10th of Ramadan shows why that planning has to stay ahead of growth. KAHRABA supports more than 900 factories there. As the industrial base expands, the network has to be ready for the demand that follows, rather than reinforced after the pressure appears.
That is the job behind the megawatts: anticipating where demand is going next and making sure the infrastructure is ready when it gets there.
The transition has a shopping list: We've looked at who is building the plants and who is putting up the money. Now we look at the equipment: panels, turbines, and batteries. Egypt already makes or assembles a fair share of it, and the government wants local factories to supply projects at home and sell abroad. The harder part is making what goes inside: the wafers in a solar cell, the core of a wind turbine, the cells in a battery.
SOUND SMART- Manufacturing has layers: Across solar, wind, and batteries, raw materials are processed into specialized inputs, made into components, then assembled into working equipment. Assembly alone brings jobs, tax revenue, and industrial activity, renewable energy expert Yana Hryshko tells EnterpriseAM. Cutting reliance on foreign suppliers means making the parts further up the chain, which is harder and costs more.
There’s a wafer-thin difference
The parts that turn sunlight to electricity are made here. Cells (that generate power) and modules (finished panels that package them together) are produced domestically, but the wafers and silicon ingots behind them mostly aren't. Elite Solar’s 5 GW Sokhna complex, with 2 GW of annual cell capacity and 3 GW of module production, puts cell manufacturing on Egyptian soil, not just the assembly of imported cells. Local content in modules has topped 65% in some projects, Elite Solar's International Market Development GTM Manager Mohammed Diab tells EnterpriseAM, though gaps remain upstream and around local suppliers and engineering. Egypt imports around USD 150 mn worth of solar panels annually, while the government wants local content in solar-panel manufacturing to rise to 80% by 2030.
Follow the chain backward, and the imports return: Conventional solar manufacturing starts with quartz, which is processed into silicon, grown into ingots, sliced into wafers, made into cells, and then assembled into the modules you see on a roof. Each step back from that roof is harder and more capital-intensive, and each one leaves a country less dependent on others. Going upstream only works if every stage has a customer. “Making wafers or cells in Egypt will be more expensive than in China,” Hryshko argues. Wafer producers need cell makers, who need panel makers, who need orders from developers. If developers can import finished panels for less, the factories further up the chain struggle to find buyers. Manufacturers need certainty before they expand, including visibility on procurement, the project pipeline, financing, customs and local-content rules, Diab says.
Heavy lifting ahead
Wind starts with a very practical advantage: big things are expensive to ship. Wind localization moves in stages: towers first, blades next, nacelle assembly after. “With towers, you’re basically transporting a lot of air — it’s just a hollow steel tower,” Hans Bruins, CEO of Ras Ghareb Wind Energy and Red Sea Wind Energy, previously told us. Egyptian suppliers have already made towers for his project, saving moving huge structures across oceans. “From a handling perspective, the blades are the most critical ones because they can be easily damaged during transport,” Bruins noted, adding that, at around 100 meters long, they carry high logistical costs and significant risk.
The engineering gets trickier further up the turbine: The hardest step is manufacturing the turbine’s core: the generator, gearbox, and control systems — which are the most complex and capital-intensive elements; they only make sense once volumes and tariff structures justify the investment. For now, local assembly is the likely starting point. “You first start with assembling components, and once you’re good at that, then you can start to manufacture them locally,” Bruins said, drawing a parallel to the automotive industry. China’s own wind cluster took 5 to 10 years to build. Few manufacturers have committed so far in town. China’s Sany proposed a factory paired with a 2 GW wind project, and Scatec also discussed wind manufacturing earlier this year. But as Bruins notes — and Diab agrees — the broader point is that factories need a dependable pipeline and project economics that hold up.
Some chemistry would help
A battery factory can make very different things. The lithium-ion chain starts with extracting and refining materials, then producing the chemical components used inside cells. Those cells are manufactured and combined into packs or larger storage systems. Assembling the system locally adds value, but the cell — where the energy is stored — can still be imported. BME's CATL-backed plant shows the split: it targets 40% local content through pack assembly, battery management integration, thermal management, and systems integration, while the cells still come from CATL in China. Kemet's USD 200 mn tie-up with Cornex targets 5 GWh of cell production, which would move Egypt further upstream if it goes ahead and would require expertise beyond the assembly line.
Salt offers another route — with some chemistry required: Draschem's Alexandria project adds sodium-ion battery components in a later phase. Sodium could remove the need for lithium, widening the choice of raw materials, but it still needs specialized materials, cell factories, and technology. Sodium-ion batteries are not yet generally cheaper than lithium-ion, and their manufacturing remains concentrated in China, the IEA notes.
Made in Egypt, but do we know-how?
Chinese manufacturers now sit across almost every segment Egypt is trying to localize, but a factory arriving isn't the same as technology arriving. “Genuine technology transfer does not happen automatically simply because a foreign company establishes a factory,” Diab argues — it takes training engineers, developing suppliers, and investing in R&D. Egyptian manufacturers compete directly with Chinese producers whose edge comes from automation and integrated clusters rather than cheap labor. And a factory that arrives can leave — Chinese producers build plants quickly, dismantle them, and move the equipment when incentives change, a model Hryshko calls “lego factories.”
ZOOMING OUT-.The transition comes with an import bill of its own, trading one form of import dependence for another. During times of conflict, higher shipping and ins. costs can make imported equipment more expensive to bring in, raising the upfront bill for reducing fuel dependence. This makes local manufacturing part of the energy-security equation, but does not mean building every component at home. It means deciding which capabilities are worth building here — provided local suppliers and engineers gain the capabilities behind it. The prize is an industry with more control over its energy supply.
The regional disruption has made a solar panel look like more than a way to cut your electricity bill. It is also a way to buy less of the fuel whose price — and passage — someone else controls. For gas-dependent Egypt, that brings the transition down to a practical business decision: how much of your power can you afford to make yourself? Our first issue followed the scramble to secure fuel. This is another response to the same problem: needing less of it. When businesses generate their own power, they take pressure off a grid that is already short on gas. Demand for rooftop solar is up across every segment Cairo Solar sells into, Managing Director Hatem Tawfik tells EnterpriseAM. Tawfik also sits on the board of the Sustainable Energy Development Association (SEDA).
The big projects offer a more complicated answer: “We do not sequence projects according to geopolitical events,” Infinity Power Deputy CEO Ahmed Mulla tells EnterpriseAM. What does move with the market is cost: large projects are developed “against changing market conditions, including movements in equipment costs, financing costs, and foreign exchange,” he says.
Taking matters into their own roofs
The keenest buyers are the plants that never switch off: Cement, steel, and ceramics factories running around the clock have steady daytime demand that can absorb solar generation. Other factories, homes, and farms trying to get off diesel are signing up too, Tawfik tells us. A MW now runs around EGP 20 mn to install, up c. 38% from EGP 14.5 mn, as the stronger greenback and the regional escalations pushed up the cost of imported panels and equipment. That has stretched payback periods and slowed some industrial demand, a renewable energy company source previously told us.
Generating your own power also means deciding what happens when you don’t need it: A factory’s panels keep producing through weekends, holidays, and quieter shifts. Net metering allows electricity exported to the grid to be credited against electricity purchases, improving the economics for customers whose consumption does not always match production. Losing this arrangement could leave 30-50% of a plant's output unused, lengthening payback periods from five years to more than 10, SEDA's Ayman Haiba previously told us. Batteries are a harder sell, for now. On a factory roof, they take about a decade to pay for themselves, and “nobody is installing them” unless the state requires them, Tawfik says.
What gets buyers off the fence
For industry, the policy needs to become a usable offer: The proposed Industry Sun program would put panels on c. 7k factory roofs — awaiting Cabinet approval — while a 15% subsidized lending scheme for industry is being reworked, and the Electricity Ministry would like to limit it to plants that use all the power they make, an industry source tells us. Plans for factories to obtain a share of their electricity from renewables still need clear implementation structure. Manufacturers deciding whether to invest need to know what counts toward that share, which projects qualify for support, and how surplus generation will be treated.
Households face the same upfront hurdle.Higher electricity tariffs can improve the savings from solar, but customers still have to finance the installation. SEDA’s proposed Shams Misr scheme would offer interestfree financing and tax breaks for up to 5 GW, while Industry Sun is designed to extend to residential buildings. But interest in a lower electricity bill is easier to establish than the ability to pay for the equipment that delivers it.
The bottom line: The war can get a business to ask for a solar quote as a resilience measure, but it can't make the numbers work. Turning that interest into installations depends on affordable financing, workable regulations for surplus electricity, and savings that justify the upfront cost. The clearest sign of a lasting shift will be customers continuing to place orders even when fuel prices ease.
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