Category: Articles

Enerthia articles and perspectives.

  • R20 billion in one quarter: the municipal grid connection question

    R20 billion in one quarter: the municipal grid connection question

    Enerthia Energy works across energy consultancy, business development, product and service endorsement, and funding. All four keep arriving at the same question, and it is no longer whether a project gets built. It is which network it plugs into. A municipal grid connection in South Africa carries different tariffs, different timelines and different metering to an Eskom one, and the latest quarterly registration figures show exactly how the market is splitting.

    • NERSA registered 124 new generation facilities in the first quarter of 2026/27: 804 MW and an estimated R20.18 billion of investment.
    • 63 of those facilities connect through municipal distribution networks. The other 61 connect through Eskom.
    • The municipal 63 carry 47 MW and R639 million — under six percent of the quarter’s capacity.
    • Registration follows capacity and connection: 100 kW or less goes to the distributor, above 100 kW goes to NERSA.

    What did NERSA register this quarter?

    NERSA registered 124 generation facilities in the first quarter of the 2026/27 financial year, with a combined capacity of 804 MW and an estimated investment value of R20.18 billion. Of those, 122 were solar photovoltaic facilities totalling 236 MW and two were wind facilities totalling 568 MW, and they were registered across all of South Africa’s provinces. The regulator processed the applications in an average of ten working days, an improvement on the eleven working days it took for 111 applications in the same quarter a year earlier. Since the registration regime began in 2018 it has registered 2 619 facilities, 20 131 MW and roughly R409 billion of investment.

    Why does a municipal grid connection in South Africa matter now?

    Because half the new projects chose that route. Of the 124 facilities, 63 connect to municipal distribution networks, carrying 47 MW and R639 million of investment. The remaining 61 connect to the Eskom network and account for 757 MW and approximately R19 541 million. Half the projects, under six percent of the capacity. That is the commercial and industrial market described in a single line. The average municipal-connected facility this quarter was about three-quarters of a megawatt; the average Eskom-connected facility was over twelve megawatts. Factories, retail centres, office parks, cold stores and farms connect locally. Utility-scale generation goes to Eskom.

    Who do you register with, and when?

    Registration is determined by installed capacity and by whether there is a point of connection to the grid, not by whether the electricity is exported or consumed on site. A facility of 100 kW or less with a grid connection registers with its distributor, meaning Eskom or the licensed municipality. Above 100 kW with a grid connection, registration goes directly to NERSA. A facility with no grid connection at all is exempt. A registration is also not the same thing as an electrical certificate of compliance: the two serve different purposes and both may be required. That distinction is where projects quietly lose weeks.

    What should you check before committing to a connection route?

    Five questions decide it. Does the network at the point of connection have capacity, confirmed in writing rather than assumed? What is the distributor’s tariff for embedded generation, and how is surplus treated — credited, wheeled, or not accepted at all? What is the realistic approval timeline, measured against the distributor’s own record rather than its brochure? What metering is required, who owns it, and what does it cost? And what happens to the tariff or the wheeling arrangement if consumption changes?

    Municipalities differ enormously from one another. Some publish embedded generation and wheeling frameworks and move applications briskly; others have thin technical capacity and long queues, so the same project can be routine in one metro and stalled in another. Our energy consultancy work covers exactly this ground, and it sits alongside two related shifts: what electricity wheeling means for property portfolios, and why grid access has become the scarce resource.

    The connection route is not a technical detail bolted on at the end. It sets the tariff, the timeline and the revenue model, and it is expensive to change once a site is committed. Half the projects registered this quarter chose the municipal door. Before you choose yours, know what is behind it.

    Our offerings

    Visit our Resources page for our offerings profiles:
    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.

  • The market that keeps moving: planning around the SAWEM launch date

    The market that keeps moving: planning around the SAWEM launch date

    Enerthia Energy works across energy consultancy, business development, product and service endorsement and funding, and this week’s audio briefing sits squarely in business development territory. The SAWEM launch date has moved twice — from April 2026 to the third quarter of 2026 — and senior market advisers now expect the first phase only in April 2027. This episode looks at what a moving date does to a project’s assumptions, and how to structure a deal that does not depend on it.

    The market that keeps moving — an Enerthia Energy audio briefing, 28 August 2026.

    Prefer to listen on YouTube? The full episode is there too.

    • SAWEM was set to open on 1 April 2026; the launch moved to the third quarter of 2026, and senior market advisers now expect the first phase around April 2027.
    • The building blocks are real — a licensed market operator, a market code with the regulator, and participants in certification — but the trading rules were still in public comment at the end of August.
    • A moving date is a planning problem: revenue assumptions, parked procurement decisions and funders pricing timing risk.
    • The answer is structural: bilateral PPAs, wheeling and trader aggregation work under today’s rules and get better if the market opens.

    Where does the SAWEM launch date stand now?

    Officially, the South African Wholesale Electricity Market is still scheduled to open before the end of September 2026; unofficially, senior market advisers now expect the first phase to go live around April 2027. The original date was 1 April 2026. In March, the National Transmission Company confirmed it would not be met after an assessment with NERSA and industry participants found more work was needed on market, operational and regulatory readiness. That is two moves in six months, with the official window now weeks from closing.

    Why does the market keep slipping?

    Because a credible market needs every piece working before the first trade, and several pieces are still being finished. The market code has been submitted to NERSA. The third version of the trading rules only closed for public comment on 28 August. The trading platform and its price-formation algorithms still need final approval, and only participants certified through the market school will be eligible to trade. Each item is progress — the National Transmission Company holds its Market Operator Licence and the phased design is settled — but a launch is the last domino, not the first. We covered what SAWEM changes for large users in July; all of it still stands. Only the date has moved.

    What does a moving date do to a project?

    It quietly undermines every assumption that was pinned to it. A revenue model that counts on trading income from a fixed quarter is now a guess. Procurement decisions parked “until the market lands” stay parked, and every month of waiting is a month of tariff exposure. Funders are asked to price a timing risk that nobody — not the developer, not the offtaker, not the regulator — actually controls. None of this means the reform is failing. It means the launch date is the wrong foundation to build a deal on.

    How do you structure a deal that does not depend on the date?

    Contract under today’s rules, and let the market be upside rather than a dependency. Bilateral power purchase agreements, trader-led wheeling and aggregation structures all work now, and bilateral contracting is expected to continue alongside SAWEM well after launch. A deal built this way gets better if the market opens on time — more routes to sell, sharper price discovery — but it does not need the market to open at all. That is the test worth applying to any term sheet this year: if the launch slips again, does this deal still work? Structuring that answer is the business development work we do with developers, offtakers and funders every week.

    Plan for the market. Contract for today. That is how you stay ahead of a date that keeps moving.

    Visit our Resources page for our offerings profiles:
    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.

  • The roofs are full: electricity wheeling is what comes next

    The roofs are full: electricity wheeling is what comes next

    Enerthia Energy works across Energy Consultancy, Business Development, Product & Service Endorsement and Funding, and one question is reaching us from South African property owners more often than any other this year: what happens once the roof is full? Rooftop solar has passed 8.3 GW nationally, the largest listed landlords are running out of roof space, and electricity wheeling in South Africa is what the next increment of clean power now looks like.

    • South Africa’s installed rooftop solar has passed 8.3 GW, most of it on shopping centres, warehouses, farms and office parks, and more than the operational solar contracted under the state procurement programmes combined at about 2.8 GW.
    • Redefine Properties, the country’s second-largest listed landlord, is running out of rooftop space and is exploring other ways to deploy solar.
    • Growthpoint, Etana Energy and the City of Cape Town completed South Africa’s first pooled wheeling allocation in April 2026, across five buildings, with a stated plan for more than 30 Cape Town properties.
    • By April 2026 Nersa had registered close to 19.6 GW of private generation capacity, most of it aimed at private buyers across the grid rather than a single meter.

    What happens when a landlord runs out of roof space?

    The cheap electricity does not stop, but the way you buy it changes completely. Up to that point solar is a procurement exercise: size the array to the daytime load, sign, and watch the bill fall. In May 2026 it was reported that Redefine Properties, South Africa’s second-largest listed property group, had run out of rooftop space for further installations and was looking at other ways to deploy solar. That is not a funding problem and not a technology problem. The panels work and the appetite is there — as we set out when private solar overtook the grid’s own renewable fleet. The roof simply ran out, and the next megawatt has to come from somewhere else on the grid.

    How does electricity wheeling in South Africa actually work?

    Wheeling moves electricity from a generator somewhere else in the country, across the Eskom and municipal networks, to a building that agrees to buy it. Growthpoint installed its first rooftop plant in 2011 and has since put more than R1 billion into solar. In November 2023 it signed a power purchase agreement with the licensed trader Etana Energy for 195 GWh a year, roughly 32 per cent of its total electricity consumption, structured as the country’s first multi-jurisdiction, multi-building, multi-source wheeling arrangement. The generation sits far from the tenant; the contract, the metering and the municipal framework are what connect them, and there are two doors into a wheeling deal.

    Why does pooled wheeling change the arithmetic for a portfolio?

    Because it moves the unit of negotiation from the building to the fund. In 2026 Growthpoint, Etana Energy and the City of Cape Town completed the first pooled wheeling of renewable electricity across multiple properties inside one municipal network, with the first allocation settled in April 2026. Power generated at the Boston hydroelectric plant in the Free State is wheeled across the Eskom network into the City’s grid and allocated across a pool of buildings. Five participate today, including the refurbished 36 Hans Strijdom, which now draws all of its grid electricity through the pooled allocation. More than 30 Cape Town properties are planned. Matching supply and demand across a portfolio, rather than site by site, is what makes the structuring effort worth funding.

    What should a property owner decide first?

    Start with grid position, then aggregation, then the contract. A building inside a municipal network sits under a different framework to one connected directly to Eskom, and municipal frameworks differ from each other. A single property rarely justifies the structuring effort, while a portfolio usually does. A power purchase agreement runs for years, so trader credentials, generation mix, curtailment exposure, escalation and settlement mechanics all matter. Metering, billing and the lease have to carry the wheeled electricity through to the tenant. And timing is real: the Cape Town pilot took more than eighteen months of collaboration between the landlord, the trader and the municipality.

    The pipeline says the generation is coming. By April 2026 Nersa had registered close to 19.6 GW of private capacity, with 132 new projects totalling 1.34 GW registered in the first four months of the year alone. The question is no longer whether clean electricity is available — it is whether a portfolio is structured to receive it. Electricity wheeling in South Africa is now a portfolio-design decision, not a rooftop decision. That is where our energy consultancy work begins. The roofs filling up is not the end of the story; it is the point at which cheap electricity stops being a purchase and starts being a structure.

    Visit our Resources page for our offerings profiles:

    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.

  • 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. 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 funds and structures projects, 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 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 — 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. 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 funds the project where it 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. 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 provides 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. This briefing sits where energy consultancy and funding 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 funds and structures projects, 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. 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. 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 funds and structures projects. 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