Financing the Energy Transition: How Deals Are Getting Done in 2026

1 Energy transition project analysis

1.1 What is being financed in 2026

In 2026, the largest volumes of transition investment continue to concentrate in a handful of categories:

Solar power (utility-scale and rooftop)

Solar attracts more capital than any other technology line item. The IEA estimated around USD 450 billion of solar investment in 2025; in 2026, that scale continues to shape how solar projects are financed.

Batteries and flexibility

Batteries are increasingly financed as part of “solar plus storage” packages or as standalone assets that support system stability. The IEA estimated around USD 66 billion of investment in batteries for power-sector storage in 2025; in 2026, financing is increasingly shaped by revenue-stack design (for example, contracted offtake alongside grid or market-based revenues) and performance and degradation assumptions.

Grids (electricity networks)

Grid investment is rising, but not fast enough. The IEA notes that around USD 400 billion is spent on grids each year, compared with around USD 1 trillion on generation assets—creating connection delays and constraints that can undermine project timelines and bankability. In 2026, grid readiness and connection terms are therefore routinely treated as core diligence items and key conditions precedent to funding.

Demand-side investment (electrification and efficiency)

This includes electric vehicles, building renovation and efficiency measures, and electrification of industrial processes. The IEA estimated demand-side investment at about USD 800 billion in 2025; in 2026, this continues to influence financing through stronger corporate demand for clean power, more direct procurement and long-term offtake arrangements.

Emerging areas (important, but smaller in absolute terms)

The IEA estimated investment in low-emissions fuels at below USD 30 billion in 2025; in 2026, these projects remain especially dependent on policy clarity, credible demand signals and contract structures that allocate pricing and volume risk in a bankable way.

1.2 The regional reality: capital remains unevenly distributed

Global totals obscure a persistent imbalance. In Africa, the IEA highlights that, as recently as 2023, the continent accounts for around 20% of the world’s population but attracts less than 2% of global clean energy spending.

This is central to the financing story: in many emerging markets and developing economies (the IEA’s “EMDE” grouping), the issue is not whether projects exist, but whether bankable structures can be built around payment risk, currency risk, permitting and grid delivery.

2Financing as the new bottleneck

2.1 Why the cost of capital is decisive

The IEA’s work on financing conditions in EMDEs is clear: the cost of capital for utility-scale solar in EMDEs is well over twice that of advanced economies, driven by higher real and perceived risks at country, sectoral and project levels.

This matters because clean energy projects are highly front-loaded in capital expenditure. The IEA notes that financing costs for utility-scale solar in EMDEs can constitute around half or more of the overall cost of electricity.

2.2 What a small pricing shift unlocks

The IEA estimates that narrowing the cost-of-capital gap between EMDEs and advanced economies by 1 percentage point could reduce average annual clean energy financing costs in EMDEs by USD 150 billion. That logic is now visible in deal-making: improving risk allocation and credit quality—even incrementally—can determine whether a project reaches financial close.

3 Emerging financing trends and instruments in 2026

3.1 Guarantees and credit enhancement move closer to the mainstream

The World Bank Group has consolidated elements of its guarantee offering through the World Bank Group Guarantee Platform housed at the Multilateral Investment Guarantee Agency (MIGA), launched on 1 July 2024, with the stated aim of streamlining access to guarantees.

The World Bank Group reports that, in the platform’s first year, USD 12.3 billion of guarantees were issued supporting 77 projects in 40 countries.

3.2 Concessional capital is being used more deliberately

The IEA estimates that a tripling of concessional funding will be required for EMDE energy transitions to align with energy and climate goals, and emphasises that concessional support is most effective when used to remove barriers and mobilise much larger volumes of private capital.

3.3 Bankability increasingly turns on delivery risk: permitting and grid connection

The IEA warns that grid investment is not keeping pace with rising electricity demand and renewables deployment, and that maintaining electricity security requires a rapid increase in grid spending.

4Jurisdiction snapshots

Germany

Janka Schwaibold and Simon Waldbröl, Schalast LAW | TAX (Partners)

How projects are most commonly financed:

Energy transition projects are primarily financed through non-recourse or limited-recourse project finance, combining long-term senior loans from German (and international) banks, including syndicated loans, with subsidised funding from development banks. Equity is typically provided by utilities, energy companies and infrastructure funds, increasingly backed by institutional investors seeking long-term, ESG aligned assets – both rated (investment-grade) and unrated.

Bankability-critical issue(s):

Key bankability issues have shifted from technology and counterparty risk to delivery risk, particularly grid connection delays, curtailment exposure and permitting timelines.

For PPA-backed and partially merchant projects, lenders scrutinise the creditworthiness, liquidity provision and contract design, including change-in-law protection and step-in rights.

Anonymised example / trend:

Recent financings of on-shore wind and solar portfolios increasingly include explicit grid-related conditions precedent, extraordinary termination rights and long-stop dates. A key trend is the rise of large, subsidy-free renewables projects financed on the basis of long-term corporate PPAs with investment-grade industrial offtakers. In recent years, there has been a growing trend of private individuals making investments as part of the decentralisation of energy supply – supported by relevant subsidy programs. The triggering idea is to strengthen the independence from major energy suppliers and become more resilient. For example, they are acquiring their own generation systems or collectively participating in large-scale projects, which also contributes to greater acceptance of the energy transition.

PPA = power purchase agreement.

4.2 Guinea

Amadou Barry, Icarus Legal (Managing Partner)
Francis-Eric Monye, Icarus Legal (Senior Associate)

How projects are most commonly financed:

In Guinea, energy projects are most commonly financed through structured project finance or PPP/IPP arrangements implemented via dedicated special purpose vehicles (SPVs). These SPVs are typically incorporated as public limited companies (Sociétés Anonymes – SA) under the OHADA Uniform Act, a corporate form well-suited to large-scale infrastructure projects and capable of supporting robust governance structures, including a board of directors.

SPVs are generally wholly owned by offshore holding companies controlled by the project sponsors, who act as majority shareholders and principal financiers through a combination of equity and long-term debt provided by Development Finance Institutions (DFIs), commercial lenders, and, where applicable, export credit agencies. Financing structures are typically supported by long-term offtake agreements, sovereign or quasi-sovereign guarantees, and other risk-mitigation instruments to ensure predictable cash flows.

A pertinent example of an energy project structuration is the Souapiti hydroelectric power station (450 MW), developed through an SPV under a PPP arrangement, with participation from the China Three Gorges Corporation (CTGC), and financed with a £911 million ($1.1 billion) loan from the Export-Import Bank of China.

It is also notable that while sponsors generally retain economic control, the State often seeks to enhance its governance rights through shareholders’ agreements, including veto rights at board level and the appointment of directors, with State-appointed directors frequently serving as chairperson. Accordingly, investors negotiate balanced governance arrangements with the State to reconcile sponsor control with bankability requirements and the need for predictable, risk-adjusted returns.

Bankability-critical issue(s):

In Guinea’s energy projects, the main bankability risks are concentrated in the offtaker risk and the tariff risk, both of which directly affect the predictability and sustainability of the project’s cash flows.

Offtaker risk arises from the limited creditworthiness of the public purchaser of the electricity produced, typically the national energy operator or the State, acting directly or through a dedicated public entity, and exposes the project to payment delays or defaults that may impact debt service. For this reason, lenders systematically treat this risk as an indirect sovereign risk, requiring the implementation of appropriate mitigation mechanisms, such as State guarantees, escrow accounts, or multilateral-backed instruments.

Closely related, tariff risk stems from the potential gap between the project company’s cost of production and the sale price applicable to the public purchaser or, where relevant, end-users. Tariffs that are not cost-reflective or are politically sensitive may compromise coverage of operating costs and debt service, particularly in the absence of adequate indexation mechanisms (foreign exchange, inflation, fuel costs) or effective protections against unilateral tariff revisions. Failure to manage these two risks can materially undermine the project’s bankability, regardless of its technical viability.

Beyond the foregoing, additional risks should be considered, notably political risks, risks of nationalisation or expropriation of private companies, foreign exchange risk, risks arising from changes in law or regulation, risks related to fuel or natural resource supply, as well as construction risks during the EPC phase.

Anonymised example / trend:

In Guinea, a floating thermal power plant intended to address electricity supply shortages temporarily suspended its operations due to the public offtaker’s failure to settle service invoices. The resulting accumulation of unpaid amounts significantly increased the project’s effective operating costs, ultimately rendering the project financially unviable under the existing public sector framework, in particular that of Électricité de Guinée S.A. (EDG S.A.).

Consequently, in 2024, the parties agreed to renegotiate the terms and conditions governing the supply of electricity from the floating power plant, while also approving an upgrade of the plant’s generation capacity from 105 MW to 150 MW. The revised contractual arrangements included the introduction of enhanced credit support mechanisms in favour of the service provider, notably through escrow account structures.

This case study illustrates how public energy projects in Guinea may fail to achieve full operational capacity, or may even fail to materialise altogether, where the offtaker does not duly perform its payment obligations. It underscores the critical importance of financially sustainable offtake arrangements and appropriate risk allocation in project structuring, particularly under PPP and IPP frameworks.

More broadly, this example demonstrates that energy project structuring must anticipate a wide range of contingencies to ensure that adverse events do not undermine the project’s bankability or its ability to generate sustainable returns once implemented. Key risks must therefore be systematically addressed, notably through the establishment by the project company (SPV) of robust payment and cash flow structures capable of ensuring the continuous operation of the infrastructure and the servicing of debt throughout the life of the project.

4.3 Ireland

Niall Donnelly, Philip Lee LLP (Partner)

How projects are most commonly financed:

Renewable electricity has an increasingly important role in Ireland. In 2024, Ireland supplied approximately one-third of its electricity from wind. Ireland’s core renewable electricity target is to supply 80% of electricity demand from renewable sources by 2030.

Large-scale renewable projects are primarily supported through the Renewable Electricity Support Scheme (“RESS”) auctions, which operates as a contract-for-difference that provides revenue support to developers. RESS has promoted the construction of new renewable power projects with RESS 5 recently awarding financial support to over 1072.22 MW of projects, led by 822.32 MW of solar. Corporate power purchase agreements (“PPAs”) continue to have an important role in providing a route-to-market for projects, which may increase in the near term driven by the new regulatory mandate for data centres to source 80% of their annual electricity demand from additional Irish renewable generation. These large-scale renewable projects are often project financed by domestic Irish pillar banks and international banking institutions.

Bankability-critical issue(s):

Ireland’s planning system remains a major barrier to delivering energy projects (and therefore the pipeline of projects available for project financing). Uncertainty around securing planning approvals and the risks brought by judicial reviews drive up costs and can undermine the viability of projects, particularly where off-take support schemes or PPAs contain milestone and/or longstop dates for achieving commercial operations. The Draghi report on competitiveness in the EU identified that Ireland has long and complex planning procedures that delay renewable energy deployment, identifying that onshore wind permitting take an average of nine years in Ireland compared to the EU average of six years.

To mitigate planning-related bankability risks, certain features have been included in the RESS packages. Projects are required to have planning permission as a pre-condition to participation in the auction. In addition, under more recent RESS auction terms and conditions, successful generators can request an extension to the longstop date and any affected milestones if planning permission for the grid connection is subject to a third-party judicial review challenge that impacts the ability to achieve commercial operation.

Irish grid investment has not kept up with the demands of increasing renewables. Accordingly, levels of dispatch down of renewables on the island of Ireland (as a result of constraints (local network issues) or curtailments (system wide issues)) remains high and a key bankability issue. Dispatch down is an instruction to renewable electricity generation to produce less electricity than it can or to shut down entirely. This is to ensure the operational security of the grid. Dispatch down levels were at 12.2% (on average) on the island of Ireland for 2025. Constraints and curtailment are a material bankability risk for Irish renewable projects because they directly erode energy yield, undermine P50/P90 cases and reduce the stability of cashflows.

To mitigate these bankability risks, RESS 3 and later auctions included a compensation mechanism known as unrealised available energy compensation (“UAEC”). UAEC compensates participants at the RESS strike price for availability not converted to generation for reasons of either curtailment or oversupply, including during periods of negative pricing.

UAEC is not available for constraint, which in the view of the government remains an important locational signal for participants. It is also only applicable to RESS supported projects and not PPA projects.

These auction based mitigants sit alongside a separate and still evolving EU law framework on dispatch down, and bankability is now also shaped by the ongoing “dispatch down” litigation in which the Irish Supreme Court has referred questions to the Court of Justice of the EU (“CJEU”) on how Article 13(7) of the EU Electricity Regulation should be interpreted, including whether generators with firm access must be fully compensated for all revenue lost when they are redispatched downwards, potentially including foregone support payments and PPA revenues. Until the CJEU provides clarity on the extent of those compensation rights for both constraints and curtailment, lenders will continue to treat dispatch down risk as a key risk in Irish project finance structures.

Anonymised example / trend:

The Private Wires Bill 2025 (the “Bill”) represents an emerging trend toward the liberalisation of electricity line ownership in Ireland by establishing a legal framework for privately owned electricity lines. The Bill, if passed, moves away from a purely public-grid model, allowing private entities to develop infrastructure in specific, policy-defined circumstances, such as connecting new renewable generation or battery storage directly to customers. Currently, the development of private wires is effectively prohibited to Ireland.

By introducing a structured regulatory regime, the Bill ensures these private wires meet the same safety and technical standards as the national grid while remaining legally distinct from the public transmission and distribution systems. For developers, lenders and investors, this trend creates potential opportunities by providing a pathway for renewable energy integration and the development of large-scale industrial connections, such as green energy industrial parks. The Bill’s tiered licensing architecture, which includes full licences for large-scale use cases and “lighter-touch” permissions for shared grid connections or contiguous premises, offers a flexible regulatory environment for financing and constructing decentralised energy assets in Ireland. With respect to bankability issues for these structures, the identity and creditworthiness of the long-term offtaker will be crucial.

4.4 Nigeria

Okechukwu Okoro, G Elias (Deputy Managing Partner), Peace Adeleye (Senior Associate), and Samuel A. Dunmade (Associate)

How projects are most commonly financed:

Energy transition projects in Nigeria are mostly financed through a combination of public and concessional funding, with private capital participating primarily through blended finance and risk-mitigated structures. The discussion below examines the financing sources, instruments, and bankability considerations that underpin this model.

Public Sector and Concessional Finance

Public Funding and Government Backed Support

Over the years, the Nigerian governments have continued to support strategic energy projects through direct fundings, reform initiatives, sovereign borrowing, and on-lending arrangements to sector institutions. For instance, the federal government of Nigeria have launched different initiatives to support transition projects including the US$2 billion Climate Investment Fund announced in January 2026, the NGN140 billion (approx. US$96.6 million) Central Bank of Nigeria Solar Connection Intervention Facility launched in post Covid-19 in 2020, among others. In 2017, the federal government of Nigeria issued NGN10.7 billion (approx. US$29 million at the time) sovereign green bond to support solar power projects becoming the first African country to issue sovereign green bond. Since then, the federal government of Nigeria has issued three sovereign green bonds aimed at financing transition projects. Some transition projects have been financed through sovereign loans. For instance, the Gurara II Hydroelectric Power Station is financed partly through sovereign loans, including a reported USD$1 billion facility from the Export–Import Bank of China. Such sovereign-backed financing reflects the Nigerian government drive for renewable energy sources.

Still on public funding of transition projects, the Nigerian government through the Rural Electrification Agency (REA) have also supported transition projects in the Nigeria market through grants and supports from the World Bank and the African Development bank. So far, the REA has mobilised over US$500 million in concessional funding for transition energy.

Beyond project-specific funding, sector reform initiatives and facilities have been deployed as tools to support transition projects. These reform-linked initiatives have become increasingly central to Nigeria’s energy transition, as they seek to address structural weaknesses that undermine private sector participation. For instance, the Nigerian Sustainable Banking Principles (NSBP) launched in 2012 by the Central Bank of Nigeria was among others aimed at fostering green initiatives, low-carbon and sustainable project. In 2025, the African Development Bank approved a USD$500 million financing package to support Nigeria’s economic governance and energy sector reforms, with components explicitly designed to improve sector liquidity, tariff discipline, and investment conditions.

Multilateral and Bilateral Concessional Funding

Multilateral development banks (“MDBs”) and bilateral development partners constitute the most reliable source of long-term capital for Nigeria’s energy transition. Institutions such as the World Bank Group, African Development Bank (“AfDB”), International Finance Corporation (“IFC”), and bilateral agencies provide concessional loans, grants, guarantees, and technical assistance that materially reduce the cost of capital and extend loan tenors beyond what domestic financial markets can offer.

Concessional funding is most prevalent in renewable energy projects with an emphasis on energy. In 2023, the World Bank’s Distributed Access through Renewable Energy Scale-up (DARES) programme illustrates this approach, channelling approximately USD$750 million in concessional finance into off-grid solar, mini-grid, and hybrid systems. These funds are typically blended with private developer equity and commercial debt, thereby crowding in private capital while addressing affordability and demand risks.

In practice, MDB involvement often serves as a de facto signal of project credibility. Market participants frequently view MDB participation as a prerequisite for bankability, particularly in first-of-a-kind projects or jurisdictions with perceived regulatory fragility.

Private Sector Investment

Private sector investment is emerging as a critical financing mechanism for energy transition projects in Nigeria, driven by the country's substantial renewable energy potential and the limitations of public funding. With Nigeria's ambitious target to achieve net-zero emissions by 2060, private capital, including foreign direct investment, venture capital, private equity, and green bonds, have become essential for deploying solar, wind, hydro, and other clean energy solutions across the nation. The private sector brings not only capital but also technical expertise, innovation, and efficiency in project execution, particularly through public-private partnerships (“PPPs”) and independent power producer (IPP) models.

Commercial Debt, Local Financial Institutions, and Capital Markets

Domestic commercial banks and leasing institutions have gradually increased exposure to renewable energy and distributed energy projects. For instance, in 2025, First City Monument Bank (“FCMB”) in partnership with the REA entered into a strategic collaboration to provide a ₦100 billion loan facility targeting electricity access for about two million households in unserved and underserved areas across Nigeria. Nevertheless, local financing is typically characterised by short loan tenors, high interest rates, and conservative collateral requirements. As a result, sponsors frequently rely on foreign currency debt sourced from Development Finance Institutions (“DFIs”) or international lenders, thereby introducing foreign exchange and refinancing risk.

Capital market instruments such as green bonds and infrastructure bonds have also emerged as alternative financing routes, but their deployment remains limited. While policy advocacy by industry participants, including calls for green bond frameworks and blended finance vehicles, has gained momentum, Nigeria’s capital markets have yet to provide a scalable source of long-term energy transition finance.

Blended Finance, Guarantees, and Risk Allocation

Blended finance has become the most common mechanism for mobilising private capital into Nigeria’s energy transition. Under these structures, concessional funding often provided by MDBs or climate funds absorbs first-loss or early-stage risk, thereby improving the risk-adjusted returns for commercial investors.

Guarantee instruments are central to this approach. The Multilateral Investment Guarantee Agency (“MIGA”), for example, has issued political risk guarantees to support renewable energy trading platforms and solar projects in Nigeria. In a recent deal, a mid-sized solar generation project reached financial close only after a political risk guarantee was introduced to cover breach of contract and currency transfer risks, enabling participation by an international lender that had previously declined involvement.

This pattern reflects a broader market reality: without guarantees or credit enhancement, many otherwise viable energy transition projects struggle to achieve bankability.

Bankability-critical issue(s):

Bankability challenges remain a central constraint to the development and financing of energy transition projects in Nigeria. Some of the key issues include:

Offtaker’s Credit Risk: Generally, government-backed grid offtakers, principally the Nigerian Bulk Electricity Trading, continue to face persistent liquidity constraints driven by tariff shortfalls, market inefficiencies, and systemic payment delays. These weaknesses create material uncertainty around revenue predictability and debt serviceability, which are core requirements for project finance. As a result, lenders increasingly treat offtaker risk as existential: even projects with technically sound designs and long-term power purchase agreements are unable to reach financial close without explicit credit enhancement mechanisms that protect against offtaker default.

Foreign Exchange and Currency Volatility: Energy transition projects typically incur capital expenditure and debt service obligations in foreign currency, while revenues are earned in local currency and subject to regulated tariff caps. The depreciation of the naira, coupled with concerns over capital controls and access to foreign exchange, exposes projects to significant currency mismatch risk that cannot be adequately hedged within Nigeria’s domestic financial system. Consequently, international lenders often require political risk guarantees covering currency inconvertibility and transfer restrictions, and in the absence of such protections, many decline participation altogether.

Macroeconomic and Market Risks: Macroeconomic volatility and market illiquidity compound these risks. Elevated domestic interest rates, persistent inflationary pressures, and shallow capital markets significantly erode project returns and restrict financing options. Nigerian commercial banks generally offer loan with short to medium tenor, which are fundamentally misaligned with the lengthy years’ revenue profiles of renewable energy assets. Regulatory and Political Risk: This also plays a major role in weakening bankability. While Nigeria has undertaken sector reforms, investors remain concerned about evolving policy frameworks, inconsistent tariff-setting methodologies, and the perceived fragility of contract sanctity. The risk of adverse regulatory changes, contract renegotiation, or shifts in energy policy following political transitions elevates risk premiums and discourages long-term capital deployment. These concerns make political risk insurance and sovereign-backed guarantees a practical necessity rather than a financing enhancement.

Limited Domestic Long-Term Capital: The absence of deep domestic long-term capital markets constrains the financing ecosystem for energy transition projects. Infrastructure-suitable instruments such as green bonds remain underdeveloped and is limited by regulatory constraints, and commercial banks favor short-tenor, collateral-backed lending. This structural deficit in domestic institutional capital forces projects to rely heavily on foreign or concessional funding sources, increasing exposure to external shocks and further complicating bankability.

Anonymised example / trend:

The anticipated transition to long-term debt financing proved significantly more complex. While a power purchase agreement was negotiated with the Nigeria Bulk Electricity Trading Plc, the agreed tariff became a major impediment to bankability. Tariff levels were subsequently questioned by fiscal authorities as being above acceptable thresholds, resulting in prolonged renegotiations and delays in securing final governmental approvals. This uncertainty undermined the project’s revenue predictability and prevented lenders from reaching credit approval, as tariff stability is central to debt sizing and cash-flow certainty in project finance transactions.

Compounding these challenges was the absence, for an extended period, of effective sovereign risk mitigation instruments to support the offtaker’s payment obligations. The delay in issuing government-backed contractual protections materially weakened lender confidence and led to the withdrawal of multilateral risk support that had been expected to underpin the financing structure. As a result, the project remained unable to achieve financial close despite having progressed significantly through development stages.

Macroeconomic conditions further affected bankability. The project’s capital expenditure is largely denominated in foreign currency due to reliance on imported photovoltaic modules and equipment. Currency volatility and foreign exchange shortages increased project costs and introduced additional uncertainty into financial models, making it more difficult to achieve acceptable returns or maintain debt service coverage ratios acceptable to lenders.

Operational bankability risks also influenced financing outcomes. Although grid connection was technically feasible, the project faced exposure to Nigeria’s historically unstable transmission network, characterised by frequent grid collapses and infrastructure constraints. These risks translated into potential curtailment and revenue loss scenarios, which lenders were required to factor into downside case analyses, further constraining debt availability.

Overall, the project illustrates the structural financing challenges faced by utility-scale energy transition projects in Nigeria. While sponsor equity and development finance capital can advance projects through early stages, bankability ultimately depends on stable tariffs, credible offtaker support, sovereign risk mitigation, and macroeconomic stability. The prolonged development timeline of the project reflects how unresolved bankability issues can delay financial close for years, even where resource potential, policy alignment, and technical feasibility are otherwise strong.

4.5 Canada

Aaron Atcheson, Miller Thomson LLP (Partner)

Renewable energy projects in Canada are generally financed through non-recourse/limited recourse project finance. While all the major Canadian banks are now lending to renewable energy projects, the first Canadian project lenders included pension funds and insurance companies. The government-funded Canada Infrastructure Bank is now financing projects in partnership with commercial bank partners, or solely in the case of indigenous-led projects. Equity is provided by infrastructure funds and power generation groups, and subordinated loans and other contributions are provided by federal and provincial government programs. Federal incentives also include investment tax credits, to a maximum of 30% of the cost of certain classes of project assets.

Critical issues include grid connection and, in respect of corporate PPAs, counterparty risk. PPA issues for lenders include curtailment exposure, change in law clauses, step-in rights, etc.

Recent financings of renewable energy projects in Canada, especially solar projects in the province of Alberta, have been completed on the basis of corporate PPAs, provided grid connection has been received, which has been limited based on system congestion. Relatively new investment tax credits provide significant incentives to project constructors, and lenders have recently started providing bridge financing to cover the time period from project construction until the receipt of federal tax credits. “Behind-the-meter” projects have also become more popular with large industrial consumers, as well as virtual PPAs, where the power generating assets are physically separate from the load.

4.6 South Africa

Wildu du Plessis, Alchemy Law (Senior Partner)

South Africa’s energy transition has entered a decisive new phase. Legal reforms that came into effect in January 2025 have fundamentally reshaped what was once one of the most autocratic and restrictive electricity markets in the world, unlocking private capital, innovation, efficiency and competition across the energy value chain.

The Electricity Regulation Amendment Act 38 of 2024 significantly expanded the mandate of the National Energy Regulator of South Africa (NERSA), enabling competitive multi-market electricity trading and laying the groundwork for a more diversified and resilient energy system. With the stated objectives of enhancing energy security and broadening access to energy, the reforms have accelerated opportunities for financial investors, independent power producers (IPPs) and large energy users to participate meaningfully in South Africa’s energy mix.

Against this backdrop, energy transition projects (predominantly solar, wind and battery energy storage) are now being financed at scale through well-established project finance structures, supported by a rapidly evolving regulatory framework.

Financing routes and structures

The South African market currently reflects two primary pathways for financing energy transition projects: Government-led procurement, most notably through the Renewable Energy Independent Power Producer Procurement Programme (REIPPPP); and a fast-growing private or “corporate” market, where electricity is sold directly to large commercial and industrial off-takers.

Across both routes, the overwhelming majority of projects are financed on a limited-recourse project finance basis, where lenders rely primarily on the project’s future cash flows rather than the balance sheets of the sponsors.

Most energy transition projects are funded on a debt-to-equity ratio of approximately 70:30 to 80:20, reflecting a mature and lender-friendly risk profile when supported by robust contractual arrangements.

Senior debt: This is typically long-term (15–20 years) and provided by: South Africa’s major commercial banks (Standard Bank, Absa, Nedbank, FirstRand/RMB and Investec); and Development Finance Institutions (DFIs), including the Development Bank of Southern Africa (DBSA), the Industrial Development Corporation (IDC), and other transnational DFIs such as the IFC and Afreximbank. DFIs often play a catalytic role, particularly in newer technologies such as green hydrogen, battery storage, or in grid-constrained regions, by offering concessional or patient capital.

Equity: This is commonly provided by Independent Power Producers (IPPs), international energy companies and local Black Economic Empowerment (BEE) partners. Equity investors rely on long-term, predictable revenue streams, most often secured through Power Purchase Agreements (PPAs), to achieve acceptable risk-adjusted returns. These PPAs are at the heart of project bankability. Whether the off-taker is Eskom under a public procurement programme or a private corporate buyer, the PPA underpins the project’s revenue certainty and forms the primary security package for lenders.

Reflecting a broader market trend of large energy users leveraging long-term PPAs to secure price certainty, decarbonise operations and progress sustainability, Alchemy Law recently advised Impala Platinum Limited on the conclusion of a Renewable Energy Supply Agreement with Discovery Green, under which Discovery Green will supply renewable electricity to Impala Platinum’s Rustenburg mining operation. This transaction was one of the first green energy projects for an industrial smelter and is also one of the first PPAs concluded following NERSA’s confirmation that private producers may be licensed for the commercial generation and sale of electricity.

Other notable trends we are seeing include a clear shift towards battery storage solutions, alongside the emergence of virtual wheeling and multi-buyer trading models. These structures are becoming central to the next phase of South Africa’s energy transition.

5 Risk and mitigation insights

5.1 Risks that most often affect pricing and bankability

Across markets, the same categories repeatedly drive risk premiums:

Payment and revenue risk (contract enforceability, offtaker credit, practical termination outcomes).

Regulatory and policy risk (stability of rules over the investment horizon). The IEA highlights regulatory uncertainty as a material investor concern, particularly in areas such as storage and privately financed grids.

Infrastructure delivery risk (especially grid connection and curtailment).

Country and macro risk (a core driver of the higher EMDE cost of capital).

5.2 Mitigation approaches increasingly used

Credit enhancement (including multilateral tools where available).

Targeted concessional support where it reduces the price of risk and catalyses private capital.

Sharper allocation of grid/permitting risk through milestones and remedies, reflecting the growing grid constraint.

6Practical checklist

(questions to ask before committing capital in an unfamiliar market)

1. Revenue model: What contract underpins revenues, and what happens on termination?

2. Payment security: Who pays, what is the track record, and what security is realistic?

3. Regulatory stability: How is change in law handled, and is the framework predictable?

4. Permitting: What are the true critical-path approvals and realistic timelines?

5. Grid: Is connection capacity secured; what is the curtailment position; what happens if the grid is late?

6. Risk tools: Are guarantees or other credit enhancement tools available, and what risks do they cover in practice?

7. Capital stack: Is concessional capital available, and what conditions attach to it?

Conclusion

In 2026, the transition is scaling, but financeability increasingly determines what reaches financial close. The IEA shows that the cost of capital in many EMDEs remains materially higher, and that financing costs can represent half (or more) of the overall cost of electricity for otherwise competitive clean power projects. The deals that get done most reliably combine: credible payment frameworks, predictable regulation, realistic treatment of grid readiness, and—where available—targeted instruments that reduce the price of risk.

Published: February 2026

Disclaimer: This article is provided for general information purposes only and does not constitute legal or other professional advice. Readers should seek specific advice from qualified legal advisers in the relevant jurisdiction, including appropriate Multilaw member firms, before taking or refraining from any action based on the content of this article.

Source tracker

S1 International Energy Agency (IEA) – IEA release/summary of World Energy Investment 2025 Supports: global energy investment USD 3.3tn; USD 2.2tn clean vs USD 1.1tn fossil

S2 IEA – World Energy Investment 2025 (Executive summary) Supports: solar USD 450bn; batteries USD 66bn; grids USD 400bn vs ~USD 1tn generation; demand-side ~USD 800bn; low-emissions fuels < USD 30bn; grid bottleneck framing

S3 IEA – Financing Clean Energy in Africa (Executive summary) Supports: Africa ~20% of population; <2% of global clean energy spending

S4 IEA – Reducing the Cost of Capital (Executive summary) Supports: EMDE cost of capital well over 2×; financing costs ~half+ of overall electricity cost for utility-scale solar; 1pp reduction saves ~USD 150bn/yr; tripling concessional funding; regulatory uncertainty themes

S5 World Bank Group (MIGA) – Guarantee Platform explainer Supports: platform launch (1 July 2024); streamlining intent

S6 World Bank Group (MIGA) – Annual reporting page on guarantees/platform Supports: USD 12.3bn guarantees; 77 projects; 40 countries

S7 IEA – Powering Ireland’s Energy Future: Approaches for a secure, renewables-led electricity system to 2035