Egypt wants private developers to build most of its new power. Here’s how that business works

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.