South Africa’s energy pipeline is not short of ambition, capital, or need. What it is short of is projects that make it from heads of terms to financial close without losing six to eighteen months to problems that were visible – and unresolved – from the start.
The issues that break deals in this market are not the obvious ones. Sophisticated teams know that grid constraints are real, that approvals take time, and that billing needs to be clear. The problems that actually cause projects to stall or collapse are more specific, and they tend to cluster in a few places that don’t get enough structured attention early enough.
1) Wheeling agreement complexity is underestimated until it’s on the critical path
For behind-the-meter and embedded generation projects involving third-party network access, the wheeling agreement is frequently the most technically and commercially complex document in the transaction – and it is routinely left too late.
The issues that surface are not abstract. They include the treatment of network losses, whether they are fixed or variable, and who bears the risk of actual loss factors diverging from modelled assumptions. They include the question of curtailment priority – specifically, in a constrained network, whose generation gets curtailed first and on what basis, and how deemed energy provisions in the PPA interact with actual curtailment events on the network. They include grid code compliance obligations, who is responsible for ensuring the generating facility meets the applicable technical standard at connection, and what happens if the network operator’s requirements change post-connection.
None of these are resolvable in a standard PPA without the wheeling agreement being substantially progressed first. Projects that sequence the PPA before the wheeling agreement are building on an incomplete foundation.
2) Municipal off-taker credit risk is structural, not just financial
When a municipality is the off-taker, the credit analysis is not simply a question of whether the municipality has the financial capacity to pay. The question is whether the procurement and payment mechanism is legally and institutionally sound enough to survive a change in political leadership, an audit finding, or a Section 139 intervention.
Municipal PPAs must be structured within the MFMA framework, which imposes specific requirements on multi-year financial commitments, budget appropriation, and the approval process for long-term contracts. A PPA that is commercially sound but procedurally non-compliant with MFMA requirements is not bankable – it creates the risk that a future council, a new municipal manager, or a provincial intervention can challenge the validity of the contract itself.
The security package for a municipal off-taker therefore needs to go beyond a payment guarantee. It needs to include a defensible record of the procurement process, confirmation of budget appropriation in terms of Section 17 of the MFMA, and ideally a National Treasury opinion or guidance note where the structure is novel. Lenders who understand the SA municipal landscape will require this. Lenders who don’t will discover it during due diligence.
3) Shape risk and deemed energy interact in ways that aren’t resolved at heads of terms
The revenue model for most SA energy projects is built on an annual energy yield. The PPA is negotiated on a tariff per kWh. But what actually drives cashflow is the shape of generation – when power is produced relative to when it is consumed, how that interacts with time-of-use tariff structures where applicable, and how the billing mechanism treats the inevitable divergence between modelled and actual generation profiles.
The specific provisions that require resolution before financial close – and that are frequently left ambiguous at heads of terms – are the deemed energy mechanism and its trigger conditions, the treatment of buyer-side curtailment versus grid-imposed curtailment versus plant unavailability, the measurement period for performance calculations and whether it is monthly, quarterly, or annual, and the interaction between availability guarantees and force majeure definitions.
A project that achieves its annual P50 yield but delivers it in the wrong shape – too much at off-peak periods, too little during the buyer’s critical load hours – may still trigger performance shortfall payments. A project that is curtailed by the network operator but has a poorly drafted deemed energy clause may not recover the revenue it modelled. These are not drafting technicalities. They are cashflow risks that lenders will model and price, and buyers will negotiate hard on once they understand the implications.
4) Construction risk allocation in EPC contracts is frequently misaligned with PPA obligations
The interface between the EPC contract and the PPA is one of the most technically demanding aspects of SA energy project structuring, and it receives less attention than it deserves in the pre-heads-of-terms phase.
The specific misalignments that create problems at financial close include: the definition of completion in the EPC contract and whether it aligns with the conditions for commercial operation under the PPA; the liquidated damages regime in the EPC contract and whether it is sufficient to cover delay costs under the PPA, including any capacity payments or deemed energy obligations that begin at a specified COD; the performance guarantees in the EPC contract and whether they are bankable in the sense of being capable of being assigned to lenders as part of the security package; and the interface with the grid connection agreement and who bears the risk of grid readiness delays that affect COD.
Projects that negotiate the PPA and the EPC contract as separate workstreams, brought together only at drafting stage, routinely discover at financial close that the risk allocation is inconsistent – and that fixing it requires reopening negotiations with multiple counterparties simultaneously.
5) NERSA licence conditions carry obligations that affect project economics and aren’t always modelled
The generation licence issued by NERSA for a project above the registration threshold is not a passive authorisation. It is a document that imposes ongoing obligations – on reporting, on technical compliance, on any material change to the project – and may include public interest conditions that affect how the project operates and what it costs to operate.
The conditions that most frequently create downstream problems are public interest undertakings related to local content, employment, or community benefit that were agreed during the licensing process and are now binding obligations with compliance and reporting requirements. Changes to project scope, technology, or ownership structure that require NERSA approval and can trigger a new licensing process if not managed carefully. And the interaction between the NERSA licence and any other regulatory approvals – specifically NEMA environmental authorisations – where conditions in one document may constrain what is permissible under the other.
These obligations need to be modelled into project economics and reflected in the contractual framework. A project that has NERSA licence conditions creating community investment obligations, for example, needs those obligations properly accounted for in the financial model that goes to lenders – not discovered during lender due diligence as an unquantified liability.
What this means for deal structuring
The common thread across all five of these issues is that they are known unknowns – the experienced teams in this market understand that these problems exist, but the pressure to move quickly on commercial terms creates an incentive to defer resolution. The result is that projects reach financial close with open items that should have been resolved at heads of terms, and the cost of resolving them at that stage – in time, in negotiating leverage, and in lender confidence – is disproportionate.
The discipline that separates projects that close from projects that stall is not drafting speed. It is the structured resolution of technical and regulatory complexity before it becomes a critical path problem. That requires legal, commercial, and technical workstreams to run in parallel rather than in sequence – and it requires a legal team that understands the substance of what it is documenting, not just the mechanics of how to document it.
Caveat Legal works with IPPs, off-takers, project finance teams, and transaction advisors on SA energy transactions from early-stage development through to financial close. If you are working on a project and want to pressure-test the risk allocation before heads of terms are signed, get in touch.
