How merchant markets, trading, batteries and supply-demand dynamics are changing renewable energy investment in Africa

– By Dominic Goncalves, Advisory Partner for Energy Strategy at Cresco Project Finance

13 August 2026

In our previous article we wrote that the renewable energy market in Southern Africa is transitioning from PPAs to Power Markets.

For the last 15 years, the PPA has been the central business contract that underpins renewable energy projects in the region. While the PPA is unlikely to disappear, what is changing is the dominance of one particular model: a long-term, fixed or indexed tariff agreement with a single utility or corporate offtaker, often supported by sovereign guarantees or extensive credit enhancement.

That structure helped mobilise the first major waves of independent power investment across Africa, by reducing market risk and creating predictable cash flows. But the traditional PPA also concentrated risk in a single buyer and treated renewable electricity largely as a uniform block of energy.

Southern Africa’s emerging electricity markets are beginning to challenge those two assumptions and cause a fundamental reinvention of the PPA for a new era:

1. Corporate procurement, open access, wheeling, regional SAPP trading, South Africa’s planned wholesale market and the deployment of battery storage are creating more routes to market, beyond a single buyer.

2. Developers and IPPs are beginning to consider not only who will buy the electricity, but how the project’s output can be divided, shaped, firmed, traded and reallocated over its operating life.

The next generation of renewable projects may therefore have several revenue components rather than one PPA. A project could combine a medium or long-term corporate offtake agreement with sales through a trader, short-term market exposure, a merchant tail and storage-related revenues. A price floor or contract-for-difference structure could protect downside risk while preserving some market upside. A solar project paired with a battery could sell a shaped evening product rather than undifferentiated daytime energy. Multiple industrial consumers could be aggregated to reduce reliance on one offtaker.

These structures are particularly relevant in markets where conventional utility creditworthiness has constrained investment. Pooling buyers, diversifying revenue and introducing credible intermediaries can reduce concentration risk. Zambia’s emerging merchant and aggregation models offer an early example how a trader can sit between generators, industrial customers and the regional market.

This does not mean that projects will become completely merchant. In fact, the phrase ‘merchant renewable energy’ can appear misleading. Banks will still require predictable cash flow, downside protection, credit support and clear allocation of market and operational risk. The difference is that predictability may increasingly come from a portfolio of contracts and hedges rather than one take-or-pay agreement.

That change has important consequences for every participant.

Developers will need to design projects around products rather than megawatts alone. The generation profile, storage duration, grid location, curtailment exposure and access to trading counterparties will affect commercial value. A project producing summer daytime energy when the market is already saturated with competition during those time periods may be less valuable than a smaller project capable of delivering during constrained or peak periods.

Corporate buyers increasingly demand more flexibility. Instead of purchasing a fixed percentage of output from one plant, an industrial customer could procure a firm renewable block assembled from solar, wind, storage and market purchases. This could better match actual consumption while transferring forecasting and balancing responsibilities to a specialist supplier or aggregator.

Lenders and investors will need new underwriting capabilities. They will have to evaluate capture prices, basis and shape risk, merchant tails, imbalance exposure, congestion, counterparty substitution, collateral requirements and the effectiveness of hedging arrangements. Financing documentation may need to accommodate multiple contracts, counterparties and revenue priorities.

Lawyers will face a corresponding shift. Future agreements may need more sophisticated provisions for dispatch, nominations, balancing, replacement power, market suspension, change in law, curtailment, credit cover and termination compensation. The bankability question will no longer be limited to whether a PPA is enforceable, but whether the complete contractual and market structure produces resilient cash flow.

Battery storage accelerates this evolution because it separates the time of generation from the time of delivery. Storage can firm renewable output, manage imbalance, reduce peak purchases and support trading strategies. As ancillary and flexibility markets mature, batteries may also earn revenues for services that a conventional energy-only PPA does not recognise.

There are significant risks. Many Southern African markets remain illiquid, transmission constrained and institutionally immature. Open access does not guarantee unconstrained grid capacity, and a market price does not automatically create a bankable revenue stream. Poorly allocated merchant exposure could make projects less financeable rather than more innovative.

So, is the traditional PPA dying? Not exactly. But it is being unbundled, supplemented and redesigned.

The PPA will remain an important risk allocation instrument, but it may become one layer within a broader commercial revenue stack.

The winners will be participants capable of combining contracted revenues, market access, storage and risk management into products that meet customers’ real requirements.

Africa’s renewable energy market is moving beyond selling megawatt-hours.

It is beginning to sell firmness, flexibility, timing and energy security.

As also reported by PV Magazine – Is the traditional PPA dying in Southern Africa?