Category: Articles

Enerthia articles and perspectives.

  • The year the capital stack changed

    The year the capital stack changed

    Enerthia Energy works across four connected offerings — energy consultancy, business development, product and service endorsement, and funding origination. This briefing sits squarely in the last of them. Renewable energy financial close in South Africa is running at record pace in 2026, and the reason is not a sudden rush of appetite. It is a change in who writes the cheque, and in what a project has to look like before anyone will.

    • Eight projects reached financial close in the first four months of 2026, totalling 1 932 MW.
    • Every 2026 close was funded by South African banks and local institutions, including the DBSA.
    • Five of the six private closes were structured through an electricity trader, not a direct bilateral contract.
    • The binding constraint is now offtake shape and grid access — not access to capital.

    Renewable energy financial close in 2026: how much has actually landed?

    Eight projects reached financial close in the first four months of 2026, totalling 1 932 MW of generation and storage. A further twenty-six projects, around 3 320 MW, were sitting in advanced development at the end of April. If most of that pipeline lands, the year finishes near thirty-four closes and roughly 5 252 MW — comfortably past the previous record of 3 562 MW across thirty-five closes in 2024. Those are early-May figures, so the year-end number is a projection, not a result.

    Who is funding these projects now?

    South African banks and local institutions are funding all of it. Every project confirmed in 2026 was financed domestically, including by the Development Bank of Southern Africa. That is the structural change hiding behind the volume. A decade ago a project of any size assumed a development finance institution somewhere in the stack, with the hedging, covenants and timelines that come with it. Anthem’s 475 MW Notsi project in the Free State closed as a nine-billion-rand transaction backed by Standard Bank, Nedbank, Absa and the Vantage GreenX Note. Local lenders now carry deals at that scale.

    Why do so many deals run through a trader?

    Traders solve the offtake problem that used to kill private projects. Around eighty per cent of private-sector capacity closed in 2026 involved an electricity trader, and five of the six private projects that reached close were structured through one rather than a direct bilateral contract. A single corporate buyer has to match its own load to a single plant, which rarely fits. A trader aggregates many buyers behind one project, absorbs the shape mismatch, and presents the lender with a diversified revenue line instead of a single-counterparty risk. Notsi sells to Discovery Green and NOA on agreements running past twenty years, with Discovery Green alone taking 290 MW. We looked at how that choice plays out for a buyer in trader-led wheeling versus a negotiated price agreement.

    Storage is closing on the same logic. Mulilo’s Hartebeesfontein battery near Klerksdorp in North West — 77 MW and 308 MWh — took debt from Absa, Standard Bank and Nedbank against a fifteen-year ancillary-services agreement with the national transmission company. Local banks, a long contract, a known buyer. We wrote about that shift in storage stopped being exotic.

    What does a project need to look like to be one of them?

    It needs a bankable offtake shape and a credible grid position, in that order. Capital is no longer the scarce input; the split between roughly 3 112 MW of public procurement across twenty projects and 2 140 MW of private capacity across fourteen shows lenders are active on both sides. What stops a project now is a revenue line nobody can underwrite — an offtaker whose credit will not carry a twenty-year tenor, a load profile the plant cannot actually serve, or a connection that is years away.

    That reframes the early work on a project. The question is no longer “who will fund this?” but “what does this have to look like before a South African lender treats it as ordinary?” Those are different questions, and the second one is answerable long before you go to market.

    Enerthia originates and structures funding, and works with sponsors on the offtake and grid questions that decide whether a project is fundable at all. If you are weighing a project against this market, the conversation starts with your offtake and your connection — see funding origination for how we approach it.

    Decks and further reading: https://enerthiaenergy.co.za/resources/

    Post created by Vanessa Mann — Co-Founder and Director of Business Development at Enerthia Energy, working across solar and renewable energy in South Africa, the SADC region and the Indian Ocean Islands, based in Cape Town. Contact me.

  • Grid access is now the scarce resource

    Grid access is now the scarce resource

    For a South African business planning an energy project, grid access is now the scarce resource. Scarcer than capital or equipment. Enerthia Energy works across four areas — Energy Consultancy, Business Development, Product & Service Endorsement and Funding Origination — and in all four the same question keeps surfacing. Not whether a project can be built, but whether it can be connected, and on what terms.

    • The approved congestion curtailment allowance is 4 per cent, not the 10 per cent originally sought.
    • It unlocks about 1 100 MW of hosting capacity in the Western Cape and 400 MW in the Eastern Cape, taking those provinces to 7 205 MW by 2028.
    • Curtailment instructions rose from roughly 100 a month to more than 1 000 a month during 2026.
    • Compensation claims under verification fell from about R2-billion in mid-June to R1.5-billion by late July, with the balance targeted for clearance by the end of August 2026.

    What does congestion curtailment mean for grid access in South Africa?

    Congestion curtailment is a trade: a project accepts that the system operator may instruct it to hold back a capped share of its output when the network is congested, and in exchange it receives a grid allocation years earlier than a new transmission line could deliver one. The regulator approved the mechanism as a constrained generation ancillary service on 29 April 2025, running to 31 March 2028, and generators instructed to curtail are compensated for the energy they were prevented from producing.

    This is arithmetic, not policy. Along the Cape corridor the 2025 capacity assessment showed no conventional headroom at all. Curtailment is what turns a zero into a number.

    How much grid capacity does the 4 per cent allowance actually unlock?

    It unlocks roughly 1 100 MW of additional hosting capacity in the Western Cape and 400 MW in the Eastern Cape, taking total capacity in those two provinces to 7 205 MW by 2028. That figure comes from the revised addendum published on 31 October 2025, which settled the allowance at 4 per cent rather than the 10 per cent the original application sought.

    The ceiling is lower than the industry hoped, but the route is open now. The mechanism applies to wind projects other than those already holding valid budget quotes, and two dates sit ahead of it: curtailment procedures were to be finalised by 31 March 2026, and the automatic curtailment system is due by 31 October 2026.

    Why did curtailment volumes climb so sharply in 2026?

    Because of the shape of the day, not a failure of the plants. Solar output peaks at midday while coal-fired units keep running to guarantee capacity for the morning and evening demand peaks. Flexible sources such as hydro and pumped storage are adjusted first; once those are exhausted, curtailing self-dispatching renewable plants is the last balancing tool available. Instructions to independent power producers rose from roughly 100 a month earlier in the year to more than 1 000 a month, against a backdrop of Eskom carrying a surplus of around 5 GW.

    The volume surge tested the compensation machinery rather than the mechanism. Claims under verification came down from about R2-billion in mid-June to R1.5-billion by late July 2026, with the remainder targeted for clearance by the end of August. Some producers were reported to be carrying revenue shortfalls of around 9 per cent while they waited. The fix agreed in July pays the full estimated value of a claim upfront, with technical verification following afterwards.

    What should a buyer ask before signing a grid allocation?

    Three questions, and they are the ones our energy consultancy work returns to on every mandate. First, what curtailment exposure sits inside this allocation, how is it measured, and who carries it? A grid connection offer is no longer a yes or a no; it has terms. Second, has the energy at risk been modelled separately from the compensation lag? A capped allowance is quantifiable, and the two effects land on different lines. Third, where does the compensation lag sit in the cash-flow model, rather than in the assumptions annexure?

    Those answers change the shape of a deal, and they interact with the route to market you choose. The structural answer is well known: storage at scale, market signals that reward daytime consumption, and grid planning built around the generation mix the country actually has.

    Grid access has become a commercial negotiation rather than a queue. Businesses that treat it that way will secure better allocations than those still waiting for capacity to appear.

    More briefings are available on our Resources page.

  • Two doors: trader-led wheeling or a negotiated price agreement

    Two doors: trader-led wheeling or a negotiated price agreement

    Enerthia Energy works across four connected offerings — energy consultancy, business development, product and service endorsement, and funding origination. This briefing sits where the first two meet: South Africa’s electricity market has reached a fork, and large industrial users are being asked to choose a side.

    Door one: trader-led wheeling

    Participation rules have been clarified and processes standardised across utilities. Portfolio-based aggregation is replacing the traditional one-to-one bilateral power purchase agreement, and trader-led aggregation is set to become the dominant commercial model in the South African private power market in 2026.

    Aggregation is the part that matters commercially. It lets renewable supply be bundled, balanced and shaped around your own demand profile. It simplifies contracting, it reduces counterparty risk, and it spreads intermittency and balancing risk across a diversified portfolio instead of leaving that risk sitting on a single asset.

    The regulatory groundwork is in place. The updated rules on network charges for third-party transportation of energy now permit cross-jurisdictional wheeling between Eskom and municipalities in both directions — a change the Minister of Electricity and Energy called the most consequential intervention in the electricity sector. The regulator counts more than a hundred wheeling agreements over the past fifteen years and around ten licensed traders already operating. Municipal wheeling tariffs are designed to be surplus neutral, so a municipality’s cost to serve stays the same whether the energy is wheeled or bought from Eskom.

    It already works at industrial scale

    Naos 1, near Viljoenskroon in the Free State, pairs 300 MW of solar — 435 MWp installed — with 660 MWh of battery storage. It has reached financial close, construction has started, and it sells to Sasol and Air Liquide under long-term agreements. It is the first utility-scale solar-and-battery project purpose-built to wheel power across the national grid to private end users, storing daytime output and dispatching it into the evening peak. Commercial operation is targeted for 2028.

    Door two: the negotiated pricing agreement

    The regulator approved a temporary 35.6% tariff reduction for ferrochrome producers, taking them to 87 c/kWh for twelve months against an average standard tariff of about 220.92 c/kWh. The producers argue that sustainable operation needs a number closer to 62 c/kWh. The 2021 agreement covering the Hillside aluminium smelter — 10.3 TWh a year, roughly 5.6% of Eskom’s total sales — carries an effective discount near 50%.

    The case for that route is jobs and export earnings. The case against it is that Meridian Economics puts the same grid flexibility at under R3bn a year using 1.2 GW of two-hour battery storage.

    Which door are you standing in front of?

    The useful test is not which route looks cheaper on a spreadsheet. It is which one you can actually contract for. A negotiated tariff depends on a decision you do not control and a relief window that closes. Wheeling depends on your load shape, your grid connection, and finding a counterparty willing to carry the balancing risk.

    Enerthia advises on which route fits an operation, builds the business development around it, and originates funding where a project needs it. That conversation starts with your load profile, not with a tariff table.

    Decks and further reading: https://enerthiaenergy.co.za/resources/

  • Two years, eighteen percent: the tariff maths nobody budgets for

    Two years, eighteen percent: the tariff maths nobody budgets for

    Enerthia Energy works across four offerings — Energy Consultancy, Business Development, Product and Service Endorsement, and Funding Origination. This week’s briefing sits squarely in the first of them, because the question in front of most commercial and industrial operations right now is an analytical one before it is a technical or a commercial one: what have South Africa’s approved electricity tariff increases already committed your business to over the next two years, and what does that do to a budget built on something gentler?

    The electricity tariff increases are approved, not forecast

    On 5 March 2026 the National Energy Regulator of South Africa approved an average electricity price increase of 8.76% for customers supplied directly by Eskom, effective 1 April 2026. Municipal bulk purchasers received an average of 9.01%, implemented from 1 July 2026 — the gap between the two percentages is a matter of financial-year timing under the Municipal Finance Management Act, not a separate decision. In the same redetermination the regulator approved 8.83% for the following financial year, effective 1 April 2027, in place of the 6.19% originally set out under MYPD6.

    Compound the two and R100 of electricity in March 2026 becomes R108.76 from April 2026, and R118.36 from April 2027. That is 18.4% across two financial years, already decided and already scheduled.

    What that does to a budget

    Take an operation spending R1 million a year on electricity and hold the budget line flat. The first year costs R1 087 600. The second costs R1 183 635. The shortfall is R87 600 in year one and a further R183 635 in year two — R271 235 of unbudgeted operating cost across twenty-four months, on a single line item, for a business that changed nothing about how it buys energy.

    That is not a variance to explain after the fact. It is a known quantity, and there is still time to act on it.

    Why the national average is the wrong number to plan on

    The municipal increase is an average across 176 licensed municipal and private distributors, and the spread beneath it is wide. Cape Town approved the lowest increase in the country at 7.5%. Johannesburg’s City Power came in at 8.63% and Tshwane at 8.7%. Nelson Mandela Bay approved 9.5%, eThekwini 10.09%, Ekurhuleni 12.7%, and Buffalo City the steepest at 14%.

    A group with sites in Cape Town and East London is absorbing two very different cost curves under one budget. Planning off the national figure understates one and overstates the other, and neither error is cheap.

    It is worth understanding why the increases exceeded the original schedule. In late 2025 the High Court rejected a closed-door settlement between the regulator and the utility over an additional R54.7 billion, ruling that the public had to be consulted. The regulator ran that consultation and completed a redetermination in February 2026, phasing recovery at R12 billion in 2026/27, R23 billion in 2027/28, and the remaining R19.7 billion beyond the current determination period. That is what moved 2026/27 from the 5.36% originally scheduled to the 8.76% actually implemented.

    Measure before you install

    The conversation usually jumps straight to solar, storage or wheeling. It should not, at least not first. The first move is a measurement decision, not a technology one.

    Energy Consultancy is where that starts: the actual tariff structure each site sits on, the approved increase for that specific municipality, the load profile behind the account, and what the next two years do to it. Business Development builds the commercial route, because knowing the number is not the same as having a counterparty, a structure and a timetable. Product and Service Endorsement puts the technical solution and the suppliers behind it under scrutiny before capital is committed. And Funding Origination arranges the capital, so a project that survives the analysis does not then stall waiting for a balance sheet.

    An operation that installs before it measures buys a solution to a problem it has not defined. One that measures first knows which sites carry the steepest increase, which sit on the wrong tariff structure, and which would genuinely benefit from generation, storage or wheeling.

    The most expensive option on the table is the one that requires no decision at all. Absorbing an approved 18.4% over two years, on top of average annual increases approaching 15% over the past five years, is still a decision — it is simply one taken by default. The arithmetic is public and the decisions have been taken. What remains open is what each operation chooses to do with the two years it can still see clearly.

    Further briefings are available in the Enerthia Energy Resources library.

  • Storage stopped being exotic

    Storage stopped being exotic

    Enerthia Energy works across four connected offerings — energy consultancy, business development, product and service endorsement, and funding origination. This briefing sits where energy consultancy and funding origination meet: battery storage in South Africa has stopped being a pilot project and started being routine infrastructure.

    Prefer to listen on YouTube? Play this episode there.

    Battery storage: the signal is the repetition, not one deal

    Mulilo reached financial close in June on the Hartebeesfontein battery — 77 MW / 308 MWh near Klerksdorp in North West. It was the company’s fifth financial close of 2026. The debt came from Absa, Standard Bank and Nedbank. The project sells ancillary services to the National Transmission Company under a 15-year agreement. Local banks, a long contract, a known buyer. That is not experimental. That is project finance behaving normally.

    The public pipeline is large, with caveats

    Government has secured close to 1.7 GW / 11 GWh of grid-scale storage across its programmes. The battery procurement programme alone has run three bid windows — the most recent closing in May — procuring roughly 1,744 MW / 6,976 MWh, contracted to be online by 2027/28. Commentators have raised fair questions about whether all of it lands on time, and that scepticism is worth holding.

    The private side is where it gets interesting

    SOLA’s Naos-1 reached financial close in February: 300 MW of solar paired with 660 MWh of battery near Viljoenskroon in the Free State, selling to Sasol and Air Liquide under long-term agreements. It is the first utility-scale solar-plus-storage project in the country purpose-built for wheeling to private end users, and the largest privately contracted hybrid project to reach financial close here. Commercial operation is targeted for 2028.

    What it changes for a large user

    Solar on its own gives you cheap energy while the sun is up. Storage is what turns it into supply you can actually run a plant on, including through the evening peak. It moves the conversation from how many megawatt-hours you can buy to what shape they arrive in.

    The structures have settled: local bank debt, long-tenor offtake, ancillary-services revenue, and hybrid wheeling to private buyers. The question for a large user is no longer whether storage is proven. It is what your load profile actually needs, and how you contract for it.

    Enerthia originates and structures funding, and advises on where storage genuinely earns its place in a supply strategy. If you want to know what firming actually buys you, that conversation starts with your load shape.

    Decks and further reading: https://enerthiaenergy.co.za/resources/

  • Private solar has quietly overtaken the grid’s own renewable fleet

    Private solar has quietly overtaken the grid’s own renewable fleet

    Enerthia Energy works across four connected offerings — energy consultancy, business development, product and service endorsement, and funding origination. This briefing sits squarely in the first: what South Africa’s privately owned solar fleet has become, and why most businesses are still sizing it for the wrong problem.

    Private solar is bigger than the programme

    South Africa’s privately owned rooftop and embedded solar capacity has passed 8.3 GW. That figure comes from the National Transmission Company of South Africa and was reported in June 2026. It is not a forecast or an industry estimate — it is the operator of the national grid describing what is already installed and running.

    For scale: rooftop solar alone now exceeds the total operational solar capacity contracted under the country’s flagship public procurement programmes, REIPPPP and the Risk Mitigation programme, which together sit at roughly 2.8 GW operational. The crossover happened earlier still. By September 2025 the transmission company put private rooftop capacity at 7 345 MW against 7 172 MW of renewable generation bought from independent power producers — private capacity having grown 23% in a single year. Nationally, total installed solar has now passed 10 GW, roughly 1.6 GW of it added last year, making South Africa the largest solar market on the continent.

    Most of it is not on houses

    The bulk of that 8.3 GW sits on shopping centres, distribution warehouses, farms and light-industrial roofs. Households are a smaller share than most people assume: Statistics South Africa counted 675 000 homes with solar panels in 2025, an 86% increase in three years, more than two-thirds of them in Gauteng and the Western Cape. Commercial and industrial uptake is what moved the national number.

    There is a caveat worth understanding. The transmission company measures this using the residual load method — comparing grid demand on sunny days against cloudy days and inferring what sits behind the meter. It cannot see individual installations and cannot separate a household’s 5 kW system from a distribution centre’s 3 MW roof. The figure is an inference rather than a register, and it is almost certainly conservative.

    The reason people buy has changed

    Load shedding effectively ended in early 2024 and installations kept climbing anyway. The driver now is tariffs. Successive above-inflation increases have made self-generated electricity cheaper than grid electricity for a large share of commercial users. That turns solar from an insurance policy into a procurement decision with a return profile — and those are different questions.

    A generator replacement asks how long you can keep the lights on. A procurement decision asks what share of annual consumption can realistically be displaced, what the load profile looks like at four in the afternoon when output falls away, whether storage or a wheeled supply covers the gap, how the asset is owned and financed, and what happens to that arrangement if the site is sold or the lease ends. Those are balance sheet questions, not installer questions.

    The utility is now competing for the same customer

    Because most private systems carry no storage, output collapses at sunset exactly as evening demand rises, forcing a steep and expensive ramp from conventional plant every day. That daily manoeuvre is part of why connection rules and tariff structures are being rewritten around distributed generation rather than against it. Registration for small-scale systems up to 50 kVA has been eased, with the connection fee waiver extended and a smart meter provided at no charge.

    More significantly, the utility is standing up a separate renewable energy business and has launched an offtake programme aimed at retaining large commercial customers by selling them low-carbon supply rather than watching them build their own. So a large energy user now has several routes: self-generate, buy a wheeled supply, contract with the utility’s renewable arm, or combine them. Each carries a different capital structure, risk allocation and set of counterparties.

    The practical failure at this point is not scepticism. It is sizing. Specified like a generator — match the peak, cover the outage, move on — a rooftop array is a resilience asset that happens to save some money. Specified against a real load profile and a real tariff forecast, with storage and wheeling considered as options rather than afterthoughts, it becomes a supply strategy with a measurable effect on unit cost.

    8.3 GW is what happens when a market makes that decision one site at a time. The question is no longer whether private generation works. It is whether the version on your roof was designed for the problem you actually have.

    Decks and further reading: enerthiaenergy.co.za/resources

  • SAWEM is coming: how a wholesale electricity market changes the maths for large users

    SAWEM is coming: how a wholesale electricity market changes the maths for large users

    Enerthia Energy works across four connected offerings — energy consultancy, business development, product and service endorsement, and funding origination. This briefing sits where the first two meet: the coming shift from a single buyer to a competitive wholesale electricity market, and what it changes for anyone buying power at scale.

    Prefer to listen on YouTube? Open this episode on the Enerthia Energy channel.

    What is actually being built for the wholesale electricity market

    The South African Wholesale Electricity Market will let generators, traders and large customers trade power directly rather than routing everything through Eskom. The National Transmission Company South Africa was granted its Market Operator licence in December 2025 and submitted the Market Code — the rulebook for how power is bought and sold — to the regulator in February 2026. Written comments closed in June and a public hearing was held on 1 July.

    The timeline has moved, twice

    NTCSA confirmed in April that the 1 April 2026 launch would not be met and shifted it to the third quarter. Industry expectation has since slipped further: energy strategy advisor Dominic Goncalves of Cresco Project Finance told pv magazine in late July that the first phase is now likely to go live in April 2027.

    Seven reforms running at once

    NERSA’s regulation dashboard, updated 7 July 2026, tracks seven parallel projects. Trading rules are in a second round of consultation and targeted for finalisation by the end of September 2026. A vesting contract framework and a wholesale tariff methodology are both out for comment with hearings in August, alongside transmission planning rules and a price and tariff rule for unbundled prices.

    What changes for a large user

    Today most buyers hold one contract with one counterparty. In a traded market, demand shifts from the cheapest renewable energy towards firmed, dispatchable energy delivered when it is needed. Transmission rights, grid access and where generation sits start to matter as much as the asset itself. Developers have to treat route to market as part of project design. Corporate buyers can shape procurement around their actual load. Funders move from underwriting one offtaker to assessing a portfolio of contracted and market revenues.

    The work happens before the market opens, not after.

    Enerthia originates and structures funding. If you want to understand what a competitive wholesale market does to your load and your contracting position, that conversation starts now.

    Decks and further reading: enerthiaenergy.co.za/resources

  • New rules of the game: what NERSA’s electricity trading rules mean for your business

    New rules of the game: what NERSA’s electricity trading rules mean for your business

    Enerthia Energy works with clients across four connected offerings — Energy Consultancy, Business Development, Product & Service Endorsement, and Funding Origination. This briefing sits where they meet: the rules that will govern how South African businesses buy electricity are being finalised now, and the first phase of competition is aimed squarely at large users.

    What changed in the electricity trading rules

    On 26 June 2026 the National Energy Regulator of South Africa released Version 3 of its draft Rules for Electricity Trading for public comment. This was a second round of consultation, following objections from Eskom to the first draft published in November 2025. Written comments closed on 27 July. The regulator has said it aims to have the rules gazetted in August.

    NERSA describes the revised rules as a comprehensive regulatory architecture designed to enable the phased implementation and operationalisation of bilateral electricity trading arrangements, supporting the transition towards a fully competitive electricity retail market. The stated aims are competitive neutrality, preventing uneconomic bypass of network and policy-related costs, and protecting consumer interests — delivered through mechanisms such as non-bypassable charges, volume restrictions and wheeling arrangements.

    How the phasing works

    Competition does not arrive all at once. Retail contestability is introduced in phases, starting with large electricity users and eventually expanding to all customers. The latest draft is more detailed and market-focused than its predecessor: direct supply agreements, electricity trading agreements, virtual wheeling, top-up customers and balance responsible parties are now clearly defined, and the treatment of wheeling credits, top-up energy and non-bypassable charges has been expanded.

    Analysts at the law firm Bowmans note that the draft now acknowledges large commercial and industrial customers have different needs and capabilities from residential consumers — a shift from earlier drafts that were largely built around consumer protection.

    What is still open

    Bowmans also flags several points that may concern market participants. Eskom Distribution and municipal distributors do not hold separate trading licences, yet the rules allow them to remain the default retailers through the first two phases; full separation of distribution and trading is deferred to Phase 4, at least six years after the South African Wholesale Electricity Market launches. Licensed traders cannot buy or sell directly in that wholesale market during Phases 1 and 2, and may only apply from Phase 3, which cannot begin until the wholesale market has been operating for at least three years. Virtual wheeling becomes available only once the wholesale market goes live, and only for customers with connections larger than 100 kVA.

    The direction of travel is settled. The pace of liberalisation is deliberately cautious.

    What it means for you

    For large energy users, offtakers and the businesses that supply them, the practical consequence is that the structure you will buy power inside for the next decade is being drawn now, while the market is still being designed. Decisions about load profile, contracting route and wheeling readiness taken today determine which options are actually available when contestability opens. Waiting for the Gazette is not a neutral choice — it narrows the field of what can be arranged in time.

    This is the ground Enerthia works across. As an energy consultancy we assess your load profile and the right technical and commercial structure; through business development and product and service endorsement we connect you to trusted delivery partners and technology; and as a funding originator we help structure and source the capital that makes a project bankable. Enerthia originates funding — it does not fund from its own balance sheet, and it is not an EPC contractor. Its role is to line up the right partners around a project so it can be built and financed.

    Explore our decks and profiles at enerthiaenergy.co.za/resources.

  • The 14 GW hole: why storage, why now

    The 14 GW hole: why storage, why now

    Enerthia Energy works across four offerings — Energy Consultancy, Business Development, Product & Service Endorsement, and Funding Origination. This briefing sits where they meet: a widening gap in South Africa’s firm power, and what it means if you’re weighing solar-plus-storage.

    Installed coal capacity is scheduled to fall from about 40 GW today to 26 GW by 2035, while peak demand climbs from around 30 GW to 40 GW — leaving a firm-supply deficit of up to 14 GW by the mid-2030s. Gas was meant to help, with 11 GW of gas-to-power targeted by 2035, but it’s largely unsecured and supply-constrained. The gap will be filled mainly by renewables, firmed with batteries.

    Storage is the mechanism. Solar is the cheapest power to build but it’s intermittent; a battery turns it into firm, dispatchable power that covers the evening peak. Yet the market is barely started — the region has fewer than 30 battery projects delivering a little over 50 MWh — while installed capacity across Africa could grow up to 700% between 2025 and 2030 (Rho Motion), with South Africa in the lead.

    The template already exists: Naos-1, near Viljoenskroon in the Free State, pairs 300 MW of solar with a 660 MWh battery (SOLA Group, WBHO and Envision), designed for wheeling. One project against a 14 GW gap — the demand is structural and only starting to be met.

    For offtakers, the question is whether to firm solar with storage while capacity is scarce; for EPCs, developers and funders, the pipeline ahead is large and largely unbuilt. Enerthia originates funding and lines up the right partners around a project — it does not fund from its own balance sheet and is not an EPC contractor.

    Listen to the short briefing above, or explore our decks at enerthiaenergy.co.za/resources.

  • The 2.7 GWh already on South Africa’s roofs

    The 2.7 GWh already on South Africa’s roofs

    Enerthia Energy works with clients across four connected offerings — Energy Consultancy, Business Development, Product & Service Endorsement, and Funding Origination. This briefing sits where they meet: one of South Africa’s largest energy assets is already installed, already paid for, and has been sitting idle — and it changes the storage question for offtakers, property companies, EPCs and funders.

    What changed for rooftop solar

    South Africa has just gained one of its largest new sources of grid-supporting storage without pouring a single new foundation. Plentify has been appointed the exclusive virtual power plant (VPP) partner to Deye, a manufacturer of residential solar inverters and batteries. The partnership sets out to coordinate 160,000 Deye residential batteries already installed across the country into a single, digitally managed resource of about 2.7 GWh of controllable capacity. That is almost twice the 1.4 GWh of Eskom’s current Battery Energy Storage Programme — a multi-year, multibillion-rand infrastructure build.

    How a virtual power plant works

    A virtual power plant links thousands of small, distributed energy resources — home batteries, and even electric water heaters — and operates them together as though they were a single power station. Nothing new is built; software does the coordinating. Deye has already run VPP programmes in mature markets including Australia and France, and is now bringing that operational experience to its South African installed base.

    Why it matters now

    South Africa’s energy transition has been shaped by load-shedding, and the result is unusual: batteries are included with more than 90% of local solar systems, a higher proportion than almost anywhere in the world. But with load-shedding receding, those batteries now sit idle for large parts of the day. The cheapest grid asset in the country may be the one already bolted to the wall — and aggregation is what turns it into capacity the grid can lean on.

    What it means for you

    For offtakers, property and facility companies, EPCs and funders alike, this reframes the storage question. Value can be unlocked from assets that are already in place, not only from new capital projects. It also signals where the market is moving: storage increasingly earns its keep by being coordinated, not merely installed. If you are weighing solar plus storage, the right question is no longer only what to build, but how what you build will be used once it is live.

    This is the ground Enerthia works across. As an energy consultancy we assess your load profile and the right technical and commercial structure; through business development and product and service endorsement we connect you to trusted delivery partners and technology; and as a funding originator we help structure and source the capital that makes a project bankable. Enerthia originates funding — it does not fund from its own balance sheet, and it is not an EPC contractor. Its role is to line up the right partners around a project so it can be built and financed.

    Explore our decks and profiles at enerthiaenergy.co.za/resources.