Category: Articles

Enerthia articles and perspectives.

  • Eskom Green wants 6 GW of partners: who gets the grid?

    Eskom Green wants 6 GW of partners: who gets the grid?

    Enerthia Energy works across Energy Consultancy, Business Development, Product & Service Endorsement and Funding, so we watch closely when the market’s biggest player changes how it builds. On 2 October 2026 Eskom issued a request for qualification to find partners for Eskom Green: up to 6 GW of utility-scale renewables and battery storage by 2030. It also raises the question every large energy buyer is asking. If Eskom is building, does its customer get first call on the grid?

    • Eskom’s RFQ (E3612GXR) pre-qualifies a five-year panel of co-development and co-investment partners for up to 6 GW by 2030.
    • Eskom brings at least 2 GW of solar PV and 1 GW / 4 GWh of battery storage; each project sits in its own ring-fenced SPV on project finance.
    • Offtakers get no formal grid priority. NERSA allocates scarce capacity first-ready, first-served, and treats all projects equally.
    • Readiness, not the name on the PPA, decides your place in the queue.

    What is Eskom Green asking partners to do?

    Eskom Green is asking developers, EPCs and investors to co-develop, finance, build and operate utility-scale plants with Eskom. The RFQ is stage one. It pre-qualifies a panel for five years, and panel members are later invited to bid on specific projects through requests for proposals. The closing date has been reported as 16 November 2026.

    Eskom contributes at least 2 GW of solar PV and 1 GW / 4 GWh of battery storage on its own land, and partners may add projects they originate. Every project sits in a ring-fenced special purpose vehicle, financed mainly on a limited-recourse or non-recourse basis. Respondents must show technical capability, a development track record and the financial capacity to see projects through to operation.

    Why did Eskom create a separate renewables business?

    Because its old model was not getting projects built fast enough. Eskom says only about half of the renewable projects awarded since IRP 2019, with grid allocation and offtake agreements, have actually been built. After benchmarking more than 20 utilities, it concluded that renewables need faster decisions, several sources of capital, partner-led delivery and bankable project structures, which a vertically integrated generator does not easily provide.

    Eskom launched Eskom Green on 9 June 2026 with 17 high-priority projects on its coal-fired station footprint. The 75 MW Lethabo solar plant in the Free State is under construction, Komati is the next co-location site, and Eskom sees up to 32 GW of renewables and storage by 2040. The early phases were funded on Eskom’s balance sheet; the RFQ now brings in partner capital.

    Phase one sells to large mining and manufacturing customers through Section 34 allocations and bilateral take-or-pay PPAs. Phase two reaches eDX Edge, SAWEM, the Southern African Power Pool and municipalities. Energy is priced separately, with network and wheeling charges passed through at cost.

    Do offtakers get priority on the transmission grid?

    No. Nothing in the rules gives an offtaker, a buyer or an Eskom project a place at the front of the queue. NERSA’s Grid Capacity Allocation Rules, approved on 12 November 2025 and gazetted on 24 December 2025, allocate scarce capacity on a first-ready, first-served basis through project registration, capacity reservation and capacity allocation.

    NERSA says all projects, regardless of size or type, are treated equally. The gazetted rules carry no carve-out for Section 34 projects, Eskom projects or particular customers, and allow different treatment only where the regulator approves it on objective grounds. Capacity can be revoked from projects that miss their milestones, except for force majeure. The industry is still watching: in June 2026 SAPVIA chief executive Dr Rethabile Melamu asked for an assurance that limited grid capacity will be shared equitably by all independent power producers.

    What should buyers, property owners and EPCs do now?

    Treat readiness as the currency. Land rights, environmental authorisation, a lodged grid application and a bankable offtake are what move a project up the queue, whoever the buyer is. Our earlier work on grid access and curtailment in South Africa and on congestion and grid capacity sets out what that looks like in practice.

    For EPCs and developers with a track record, the Eskom Green panel is a new route to scale, and our business development team can help you weigh it against private offtake. For large energy users, Eskom Green is another supplier to compare with private PPAs and wheeling. Enerthia Energy can help you assess the options, prepare for grid access and structure the funding behind your project company.

    The grid does not reward who you are. It rewards how ready you are.

    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.

  • Off-grid solar in Africa: 450% growth by 2035, and finance decides what gets built

    Off-grid solar in Africa: 450% growth by 2035, and finance decides what gets built

    Enerthia Energy works across four offerings — Energy Consultancy, Business Development, Product & Service Endorsement and Funding — for commercial, industrial and mining clients in South Africa, the SADC region and the Indian Ocean Islands. This week’s briefing looks at off-grid solar in Africa: a market set to grow by 450% by 2035, where demand is no longer the question and finance decides what actually gets built.

    • Wood Mackenzie forecasts Sub-Saharan Africa’s off-grid solar capacity to rise 450% by 2035, across ten modelled markets.
    • Much of the growth is businesses and mines replacing diesel, not only first-time access — Nigeria alone is about 35% of installations.
    • Finance is the biggest barrier: currency risk and double-digit borrowing costs hit upfront-heavy solar and storage hardest.
    • For buyers, the funding structure and ownership model now matter as much as the engineering.

    Prefer to listen on YouTube?

    How fast is off-grid solar in Africa growing?

    Fast enough that the research firm Wood Mackenzie now calls off-grid solar Sub-Saharan Africa’s primary electrification engine. Its September 2026 analysis, Off-grid solar PV in Sub-Saharan Africa: a multi-gigawatt growth opportunity, projects that the region’s off-grid solar capacity will grow 450% by 2035. Three forces sit behind it: falling module prices, rising diesel costs and growing private capital. More than 27 GW of solar modules have been imported into the region since 2022, not counting South Africa.

    The need is just as large. Around 600 million people in Sub-Saharan Africa still lack reliable electricity, and the International Energy Agency found in October 2025 that eight in every ten people worldwide without electricity live in the region.

    Where is off-grid solar in Africa growing fastest?

    Nigeria leads, with close to 35% of the region’s forecast installations — and much of that is existing commercial and industrial users cutting diesel after the 2023 removal of the fuel subsidy, rather than first-time access. In the Democratic Republic of Congo, mining loads displacing diesel sit alongside rural electrification; the Kamoa-Kakula copper mine’s solar and storage plant alone is 233 MWdc. Zambia’s demand is tied to mining, Kenya is shifting from first-time access to cost savings for users who already have power, and Ghana, Tanzania and Ethiopia add commercial and rural demand.

    For SADC buyers the pattern is familiar: wherever diesel sets the marginal cost of power, solar and storage now compete on price. We saw the same logic in South Africa’s own battery storage financial close, where storage is paid for the value it adds to the system rather than for kilowatt-hours alone.

    Why is finance the biggest barrier?

    Because solar and storage cost most on day one, and the cost of money in many African markets is high. Wood Mackenzie names financing as the biggest barrier to its 2035 forecast. Currency depreciation and double-digit interest rates — above 30% in some markets — make an upfront-heavy asset expensive to fund.

    The answer it points to is lowering the cost of capital through blended finance and development-finance guarantees, rather than relying mainly on subsidies. Local-currency financing matters most: dollar debt repaid from naira or shilling revenue is a common reason projects fail. Predictable, long-term rural electrification policy also helps bring private investment in.

    What should a commercial, industrial or mining buyer do now?

    Start with an honest baseline of what diesel really costs per kilowatt-hour today, including fuel logistics and maintenance. Then match the funding structure to the currency the business earns in. Next, choose the ownership model deliberately: owning the system, leasing it or buying the power under a solar-as-a-service agreement each puts the upfront cost and the risk in a different place — the same choice we explored when looking at who is buying private power in South Africa.

    Finally, bring the engineering and the funding conversation together early. The cheapest system on paper is not always the cheapest system to finance, and a structure that fits the client’s cash flow is often what gets a project from proposal to construction.

    Demand for off-grid solar in Africa is not in doubt. How much of it is built depends on getting the money right. Enerthia Energy can help — from the energy assessment to the right partners and the funding model that fits your project, with funding capacity of up to R10 billion through a network of 40 renewable energy investment partners.

    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.

  • Who polices the South African wholesale electricity market?

    Who polices the South African wholesale electricity market?

    The South African wholesale electricity market now opens in April 2027, and the more useful question for an energy buyer is no longer when, but who keeps it fair. At Enerthia Energy we work across energy consultancy, business development, product and service endorsement and funding, and this briefing looks at the governance detail most coverage skips: the referee.

    • SAWEM is scheduled to begin operating in April 2027, moved from April 2026 to finalise the market code and the vesting contracts.
    • NERSA made market surveillance a condition of NTCSA’s Market Operator licence, so NTCSA is building an internal but ring-fenced surveillance unit.
    • Around 30 Eskom Generation power stations already trade on the platform, with Eskom Distribution as offtaker.
    • Eighteen months is a preparation window, not a waiting period.

    When does the South African wholesale electricity market open?

    The South African Wholesale Electricity Market, SAWEM, is now scheduled to begin operating in April 2027. It was originally due in April 2026. According to the National Transmission Company South Africa (NTCSA), the launch moved to allow time to finalise the market code and complete other regulatory requirements, including the vesting contracts that carry existing generation into the new market.

    The platform itself is still being built, with IT, cybersecurity and process specialists working towards readiness. For context on how the date moved, see our earlier briefing on why the SAWEM launch date slipped.

    Who will police trading in the new market?

    NTCSA will police it first, through a market surveillance unit that sits inside the company but is ring-fenced from its other functions. That is not a voluntary gesture. NERSA approved NTCSA’s Market Operator licence in November 2025 and asked for an independence roadmap showing how NTCSA would manage the conflicts that come with its ownership.

    NTCSA is now setting up an internal, yet ring-fenced, market surveillance unit to guard against abuse of dominance, and creating that capacity was a condition the regulator set when the licence was approved.

    Why does market dominance matter to an energy buyer?

    Dominance matters because the market is not starting from an empty field. Around 30 Eskom Generation power stations are already trading on the platform, with Eskom Distribution as the offtaker, and Eskom Generation will be by far the largest participant at launch.

    A market where one seller holds most of the supply needs a referee who can see the trading data and act on it. Without credible surveillance, price signals are harder to trust, and private sellers and large buyers have less reason to commit capital or sign long contracts.

    Andrew Etzinger of NTCSA has said he wants surveillance capacity built outside NTCSA too, because NTCSA remains inside Eskom Holdings ahead of its unbundling. He suggested the Competition Commission should have access to market information alongside NERSA.

    The regional comparison is sobering. In the Southern African Power Pool, the surveillance role is currently played by one person working behind a locked office door in Harare. A national market with Eskom’s fleet, independent producers, traders and large buyers needs far more than that.

    What should energy buyers do before April 2027?

    Energy buyers should treat the next eighteen months as preparation time rather than a date to wait for. Understand your load profile and tariff exposure, and test which supply options fit, from on-site solar to wheeled energy and private power purchase agreements.

    Read the governance as closely as the launch date: surveillance, the vesting contracts and the independence of the market operator will shape how fair prices are. Contracts signed now should anticipate the new market, with clear price mechanisms, change-in-law clauses and exit terms. Our guide to choosing your electricity supplier in South Africa sets out the options already open to buyers.

    Enerthia Energy supports that preparation end to end. Our energy consultancy work assesses options and exposure, business development connects buyers, sellers and partners, product and service endorsement identifies credible technology and suppliers, and funding brings projects to financial close.

    A new market needs a trusted referee. Prepare now, and read the rules as closely as the date.

    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.

  • Choosing your own power company: how far away is South Africa, really?

    Choosing your own power company: how far away is South Africa, really?

    Enerthia Energy works across four areas — energy consultancy, business development, product and service endorsement, and funding. This briefing, from our business development and energy consultancy work, answers one question: when can you choose your electricity supplier in South Africa? The short answer is that it depends on how much power you use. Large users have a stated design and a target year. Households have neither yet.

    • South Africa’s market design opens supplier choice to large “eligible customers” first; everyone else stays with their current distributor for now.
    • The 1 MW figure in the design paper is an illustration of where a threshold might sit, not a decided number.
    • Market opening beyond Eskom is targeted for 2027. Household choice depends on a retail code that has not yet been drafted and carries no date.
    • Singapore took 17 years and Great Britain roughly a decade to reach full household choice — both opened to large users first.

    Prefer to listen on YouTube?

    When can you choose your electricity supplier in South Africa?

    If you are a large commercial or industrial user, the door is scheduled to open from 2027; if you are a household or small business, there is no date yet. The market design paper gazetted for public comment in August 2026 sets out the sequence plainly. Choice opens first to large users, called eligible customers. Everyone else stays with the retail arm of whichever distributor already serves them, and eligibility widens “over the longer term” under a retail code that, as the gazetted design paper reportedly states, has not been drafted.

    The wholesale layer comes first. The South African Wholesale Electricity Market was originally targeted for 1 April 2026 and moved to the third quarter, with launch reported as due by the end of September. The Market Code was submitted to NERSA for approval on 25 February 2026. Monde Bala, chief executive of the National Transmission Company of South Africa, said in March that adjusting the timeline ensures the market is introduced responsibly. Our earlier briefing on planning around the SAWEM launch date covers that wholesale timeline in detail.

    Is the 1 MW eligible-customer threshold fixed?

    No — the 1 MW figure is an illustration, and the design paper does not commit to it. It appears twice as an example of where a threshold might sit. It does show the scale of customer the first phase has in mind. One megawatt is a business connection: a factory, a mine, a large retail centre or a portfolio of sites. A large home rooftop solar system is typically around 16 kVA, nowhere near it.

    If your load sits near that range, the wholesale market is the layer to watch, because it sets the prices eligible customers will contract against. We explained the cost maths for large users in SAWEM is coming: what a wholesale market means for large users.

    How long did supplier choice take in other countries?

    Everywhere it has been done, supplier choice reached households years after it reached large users — South Africa’s sequence is the normal one. Singapore began opening its market to competition in 2001, starting with larger businesses with higher consumption, and rolled the open electricity market out nationwide from 1 November 2018. That is 17 years from first opening to full household choice.

    Great Britain privatised its electricity industry in 1989, opened domestic supply to competition in stages between 1996 and 1999, and reached full national domestic competition by April 1999. Industrial and commercial customers came first there too. In the United States, the Energy Information Administration counts 13 states plus the District of Columbia with active statewide residential retail choice programmes. Texas sits outside that count because choice is mandatory for customers on the grid managed by ERCOT.

    What should a business near the threshold do now?

    Find out where your own site load sits relative to the threshold under discussion, because that is the door actually opening on a stated timetable. If you are near it, three questions are worth answering before 2027: what your connection and metering would need to change, what your load profile looks like to a supplier, and whether several of your sites could be aggregated into one position.

    Our business development team works through those questions with clients and EPCs preparing for the eligible-customer market, and our consultancy team assesses where a client’s load sits against market-design thresholds. And when a project needs capital, we fund it: funding capacity up to R10 billion, backed by a network of 40 renewable energy investment partners, with the best-fit funding model recommended for each requirement.

    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.

  • Rooftop solar registration: the 30 September deadline

    Rooftop solar registration: the 30 September deadline

    Enerthia Energy works across four areas — Energy Consultancy, Business Development, Product & Service Endorsement, and Funding. This one sits in the consultancy space: rooftop solar registration is paperwork that protects an asset a business already owns, and the free window closes on 30 September 2026.

    • South Africa has passed 8.3 GW of installed rooftop solar, most of it on commercial roofs.
    • Registration is free until 30 September 2026, for systems up to 50 kW.
    • Eskom will not automatically fine or disconnect anyone who has not registered.
    • The real exposure is the insurance claim, not the fee.

    What is rooftop solar registration, and who has to do it?

    It is the formal declaration of a grid-tied solar system to the distributor that supplies the property. Eskom requires registration of grid-connected rooftop systems below 100 kW, and until 30 September 2026 it has waived the registration fee for systems up to 50 kW, having extended that window by six months from the end of March. A smart meter comes at no cost under the same process — worth up to R10 000 urban, R36 000 rural.

    The reason it catches businesses out is framing. A plant bought during load shedding felt like equipment: a private purchase, a line on the asset register. But once it is connected on the same side of the meter as the utility supply, it is part of the distribution network, and the distributor wants it on record.

    What happens if a system is not registered?

    Less than most owners fear, and more than they realise. Eskom has confirmed it will not automatically fine or disconnect customers for failing to register, and it has dropped its earlier requirement that a registered professional sign off every installation. Nobody is coming to throw a switch. The fee simply returns once the waiver lapses, and the system stays undeclared.

    The cost lands elsewhere. An undeclared generating asset has no paper trail, and the moment an underwriter, a buyer or a lender needs that trail, its absence stops being theoretical.

    Which documents does a rooftop solar registration need?

    The core file is short: a Certificate of Compliance, an inverter test certificate, and a test report for the installation. Insurers routinely ask for more — the full invoice listing panel brands, types, sizes and quantities, the inverters and batteries, and, where the roof carries load, a structural engineer’s certificate.

    Where the application goes depends on who supplies the property. An Eskom-supplied site applies to Eskom. A site in a municipal supply area goes through that municipality, which runs its own forms and requirements, and those differ from town to town. It is the same split that governs municipal grid connection in South Africa, and where multi-site portfolios lose the most time.

    How does registration affect insurance, resale and refinancing?

    This is what decides whether the exercise is worth an afternoon. Insurers have changed how they look at these systems. Marius Kemp, Head of Personal Underwriting at Santam, put it plainly: insurers are no longer covering electrical upgrades, they are underwriting decentralised power plants. A rooftop array carries fire risk, structural load and a live interface with the grid, and underwriters price that against evidence — the same evidence registration asks for.

    Resale and refinancing follow the same logic on a longer fuse. A building changes hands, a lender refinances, a tenant runs due diligence before a long lease. Somebody asks for the documents on the solar plant. An undocumented generating asset does not lift the value of that building; it raises questions, and questions cost time. The same discipline applies to the contractual side of any generation on a property, including an electricity wheeling arrangement across a property portfolio.

    Most of that 8.3 GW went up fast, and it went up on shopping centres, warehouses and farms rather than household roofs. For one building the file is an afternoon. For a property group with fifteen sites across three municipalities, it is a project that needs an owner. That is the kind of work our energy consultancy does — taking an existing asset and making it documented, compliant, insurable and transferable. Enerthia also supports business development, endorses proven products and service providers, and funds projects through a network of 40 renewable energy investment partners with capacity up to R10 billion.

    If the panels are already on the roof, this week is about the paperwork, not the plant.

    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.

  • Battery storage financial close: paid for stability, not kilowatt-hours

    Battery storage financial close: paid for stability, not kilowatt-hours

    Enerthia Energy works across four offerings — energy consultancy, business development, product and service endorsement, and funding — and this week’s battery storage financial close sits exactly where the last two meet. Hartebeesfontein, 77 MW and 308 MWh near Klerksdorp in the City of Matlosana, reached close on a contract that pays for stability rather than for energy sold. The capacity is not the story. The revenue model is.

    Enerthia Energy Insights — Friday briefing, 18 September 2026 (4:49)
    • Hartebeesfontein is 77 MW and 308 MWh, awarded under Bid Window 2 of the Battery Energy Storage Independent Power Producer Procurement Programme.
    • The offtake is a 15-year ancillary-services agreement with the National Transmission Company of South Africa — availability and response, not kilowatt-hours.
    • Mulilo secured five of the eight projects awarded in that window; Absa, Standard Bank and Nedbank provided the debt.
    • Storage is now closing standalone, because a system-services contract underwrites differently from an energy offtake.

    That difference is worth reading closely, whether you are a sponsor taking a project to funders or an industrial buyer being shown a hybrid solar-and-storage proposal.

    Prefer to listen on YouTube?

    What reached battery storage financial close?

    Mulilo reached financial close on the Hartebeesfontein battery energy storage project, 77 MW and 308 MWh, near Klerksdorp in the City of Matlosana Local Municipality in North West, sited close to Eskom’s Hermes main transmission substation. It is the developer’s fifth project to reach close in 2026. The project was awarded under Bid Window 2 of the Battery Energy Storage Independent Power Producer Procurement Programme, in which Mulilo secured five of the eight projects awarded. Absa, Standard Bank and Nedbank provided the debt.

    Why does an ancillary-services contract underwrite differently?

    Because it pays for a capability held ready rather than for volume sold. Hartebeesfontein carries a 15-year agreement with the National Transmission Company of South Africa for ancillary services. A solar power purchase agreement earns against a resource and a load; a system-services contract earns against availability and response, measured, with a single creditworthy counterparty on the other side. Volume risk largely falls away and is replaced by availability and performance risk, which is an engineering and operations question rather than a market one. That is a shorter conversation with a lender, and it is part of why the capital stack has been shifting toward contracted, service-based revenue.

    What is the private market doing in parallel?

    It is buying the same physics under different paper. SOLA reached financial close on Naos-1 — 300 MW AC of solar, 435 MWp DC, with 660 MWh of storage — contracted to Sasol and Air Liquide in the Free State and targeting commercial operation in 2028. It is described as South Africa’s largest utility-scale solar and battery project built for private offtakers. Here the storage is not sold to the transmission company at all; it shapes a private supply profile for two industrial buyers. Two routes, two different underwriting conversations. When storage stopped being exotic, this is what it became.

    What should a sponsor or an offtaker take from it?

    Describe the service, not the megawatt-hours. A sponsor who can say exactly what is being sold, to whom, for how long and how availability is measured is far closer to a funded project than one leading with capacity alone. For an industrial or commercial offtaker the honest framing matters just as much: storage buys shape, firmness and power quality, and the ability to hold a profile through a cloudy hour or a tariff peak. It does not on its own buy independence from the grid, and it does not turn an intermittent resource into a baseload one at any scale you like. What it buys should be written into the contract and measured against it.

    Enerthia Energy works with sponsors, developers, funders and offtakers on exactly this framing — what is being sold, who is buying it, how it is contracted, and whether a funder will lend against it. That is the heart of our funding work.

    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.

  • Congestion curtailment: 1 580 MW of grid capacity, at a 4% cap

    Congestion curtailment: 1 580 MW of grid capacity, at a 4% cap

    Enerthia Energy works across four connected offerings — Energy Consultancy, Business Development, Product & Service Endorsement and Funding. Congestion curtailment sits in the first of those, because it has quietly changed the answer a South African project gets when it asks for a grid connection, and with it the yield model that sits behind every wheeled or self-generation business case.

    • NERSA approved congestion curtailment as an ancillary service on 29 April 2025, running as a pilot to 31 March 2028.
    • The approved 4% curtailment cap releases about 1 580 MW of connection capacity: 1 180 MW in the Western Cape and 400 MW in the Eastern Cape.
    • Scope is narrow — wind projects in the two Cape provinces only, and projects already holding valid budget quotes are excluded.
    • Curtailed energy is compensated, but in 2026 the claims ran ahead of the administration, and that is a cash-flow question as much as a yield one.

    What is congestion curtailment, and what did NERSA approve?

    Congestion curtailment is a deal: the network operator connects more generation than the wires can carry at peak, and in exchange reserves the right to instruct those generators to reduce output when the network is congested. The National Energy Regulator of South Africa approved it as an ancillary service on 29 April 2025, effective from 1 April 2025 to 31 March 2028 and sitting inside the sixth multi-year price determination. It is explicitly a pilot, which matters for anything with a tenor longer than the pilot.

    How much capacity does the 4% cap release, and where?

    The approved cap is 4%, and on that basis roughly 1 580 MW of additional connection capacity is released — 1 180 MW in the Western Cape and 400 MW in the Eastern Cape. A larger number circulates in commentary, drawn from a 10% curtailment scenario modelled in the application rather than granted in the decision; it is worth checking which figure a developer is quoting. The scope is also narrower than the headline suggests: wind technology projects in the Eastern and Western Cape only, excluding projects that already hold valid or effective budget quotes, because that capacity was already built into the upstream network plans. Eligible projects are new applications, those awaiting cost estimate letters, those in grid capacity assessment evaluation, and those holding provisional capacity allocation.

    Who carries the curtailment risk in a power purchase agreement?

    Contractually, whoever the agreement says carries it — which is why this belongs in the term sheet rather than in due diligence. Public programme projects receive deemed energy payments; for private projects the offtaker’s account is credited for the curtailed energy as though it had been supplied, with cost recovery capped at the approved ancillary services allowance. So the compensation is real, but it is a claim that has to be evidenced, verified and paid, and 2026 showed what happens when volume outruns process. Curtailed energy in the first half of 2026 was roughly an order of magnitude higher than in all of 2025, and by late July the transmission company was working through a R1.5-billion backlog of curtailment claims, down from R2-billion in mid-June. Some producers reported revenues running about 9% below budget as a result. Curtailment risk and curtailment cash-flow risk are two different line items.

    What should you ask before you sign?

    Five questions cover most of it. What curtailment assumption sits in the yield model, and who prepared it — 4% is a cap, not a forecast, so the model needs a sensitivity rather than a footnote. Is the project actually eligible, or does it hold a budget quote that excludes it? How is curtailed energy evidenced and claimed, and on what timetable? What happens to the tariff, and to debt service cover, if compensation arrives late? And what is the assumed position after March 2028, when the pilot ends? These are the same questions we work through in an energy consultancy mandate, and they sit alongside the wider grid access picture and the shape of the private offtake market.

    Capacity in the Cape provinces is no longer simply unavailable. It is available on terms, and the terms are now the commercial work. A project that models a flat production curve is not modelling the connection it has actually been offered.

    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.

  • Corporate PPA South Africa: who is actually buying the power now

    Corporate PPA South Africa: who is actually buying the power now

    Enerthia Energy works across four offerings — energy consultancy, business development, product and service endorsement, and funding — and this year one shift runs through all four: the corporate PPA South Africa market is no longer the alternative route to a renewable energy project, it is the main one. In the first half of 2026, seventeen independent power producer projects reached commercial operation, and ten of them sold their output straight to mining and industrial buyers rather than into a public procurement round. The counterparty has changed, and with it the shape of the deal.

    Enerthia Energy Insights — who is actually buying the power now
    • 17 IPP projects totalling 1 920 MW reached commercial operation in the first half of 2026 — the largest half-year addition on record.
    • 10 of those projects, 1 046 MW, supplied mining and industrial buyers directly; the other seven, 874 MW, came through government programmes.
    • The previous full-year record was 1 472 MW, set in 2016.
    • A further 28 projects, 2 202 MW, are due in the second half, for a projected 4 123 MW across the year.

    Prefer to listen on YouTube? The episode is below, and on the Enerthia Energy channel in the Podcasts Insights playlist.

    Who is buying South Africa’s new generation capacity now?

    Private companies are. Of the seventeen projects that reached commercial operation between January and June 2026, ten were privately procured and supply mining houses and industrial users directly, with a combined 1 046 MW. The remaining seven, 874 MW, came through Bid Windows 5 and 6 of the Renewable Energy Independent Power Producer Procurement Programme and the Risk Mitigation programme. Wind carried much of the volume, with seven wind farms adding 815 MW. Research from the Power Futures Lab at the University of Cape Town Graduate School of Business puts the half-year total at 1 920 MW, the highest capacity added in any half-year period.

    What does a corporate PPA South Africa deal change about credit?

    It moves the credit question from a programme to a single company. Under a public round the offtake sits behind standardised documentation and programme-level support, so much of the diligence is about compliance with that framework. A private offtaker is assessed on its own terms instead: its financial position, its sector cycle, its customer concentration, and how its revenue behaves in a downturn. Lenders price that counterparty directly rather than pricing a procurement round, which is why developers are increasingly building a portfolio of buyers rather than relying on one. The same logic runs through the capital stack, where the mix of funders behind this year’s closes has shifted alongside the mix of buyers.

    How does a private buyer change tenor, sizing and security?

    It shortens and individualises all three. A public round sets a twenty-year term; a corporate buyer contracts against its own planning horizon, licence period or mine life, and a shorter, less certain tenor changes both debt sizing and the equity return profile. The plant is sized to one user’s load profile rather than to a grid-wide need, so the route the electrons take — direct connection, wheeled to a site elsewhere on the grid, or traded — becomes part of the commercial design rather than an afterthought. Without programme guarantees, the parties negotiate their own security package: parent support, credit enhancement, termination provisions and step-in rights.

    What should a developer, funder or energy user do differently?

    Start with the buyer rather than the site. For a large energy user, this is the moment the market comes to them: a creditworthy load is now the scarce input, which is standing to negotiate rather than accept a standard offer. For a developer, the work moves upstream into origination and credit, because the valuable thing is a matched pair — a buyer whose load suits an asset, and a funder comfortable with that specific counterparty. Timing belongs in the plan too. Financial close activity slowed through the middle of 2026, with only the Hartebeesfontein battery project closing in the second quarter, which researchers attribute to grid-connection approvals and commercial clearances rather than to weaker investor appetite.

    A further 28 projects representing 2 202 MW are scheduled for the second half of 2026, which would take the year to 4 123 MW. The projects that reach commercial operation in 2028 are being originated now, around buyers who do not yet know they are the counterparty — which is where our business development work begins.

    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 bill is being restructured, not just raised

    The bill is being restructured, not just raised

    Enerthia Energy works with commercial and industrial energy users across four offerings — energy consultancy, business development, product and service endorsement, and funding. All four turn on one regulatory notice this month. The National Energy Regulator of South Africa has opened public comment on a proposal that would take Eskom fixed charges to the full level of a three-year glide path, without changing the headline increase at all.

    • The 8.83% average increase is already approved. What is open for comment is how that revenue is collected, not how much of it there is.
    • Fixed charges move from 66.6% to 100% of their target, and the service and administration charge rises by close to 50%.
    • Variable energy rates fall to hold the average, so a site’s exposure now turns on its load factor rather than the headline number.
    • Written comments close at 16:00 on 2 October 2026.

    What is Eskom actually asking to change?

    The structure, not the total. The allowable revenue for 2027/28 was determined at R419.438 billion against a forecast 160 395 GWh of sales, and that determination is not reopened here. NERSA gazetted the Retail Tariff Structural Adjustment on 2 September and is asking how the approved revenue should be split between what a customer consumes and what a customer is connected for. Written submissions close at 16:00 on 2 October, a public hearing follows on 8 October, and a decision is expected on 26 November. If approved, the new structure applies from 1 April 2027 for customers supplied directly by Eskom, and from 1 July 2027 for municipal customers on the 8.84% average.

    How much are Eskom fixed charges going up?

    To 100% of a three-year glide path, from the 66.6% they sit at now. Alongside that, the service and administration charge rises by close to 50%. Because the overall average is being held near 8.83%, more weight on the fixed side means less on the variable side: energy rates come down as connection charges go up. The headline moves from 240.28c to 261.50c per unit, a rise of 21.22c, but that blended figure describes almost nobody’s actual bill. For municipal customers the Generation Capacity Charge has to reach 30% of the benchmark set in the 2025 Retail Tariff Plan by FY2028, and it is already there, so no further structural adjustment is proposed for them next year.

    Which sites are most exposed to the change?

    Low-load-factor sites. Load factor is simply how evenly a site uses its connection across the hours it is billed for, and it decides who gains and who loses in a fixed-for-variable swap. A cold store, a continuous process plant or a data centre spreads the same fixed charge across a very large number of units, so a lower energy rate can leave it flat or slightly better off. A shopping centre, an office park, a school or a single-shift warehouse carries an identical fixed charge over far fewer units, so its effective cost per unit rises even though the published average did not. Multi-site operators should look twice: where charges apply per point of supply, a business with many small connections carries the fixed component many times over.

    What should a buyer do before 2 October?

    Model the two components separately, then comment. Split the bill into its fixed and variable parts rather than working from a blended rate, because a blended rate hides exactly what is being proposed. Calculate load factor per site, not per portfolio, since the portfolio average conceals the sites most exposed. Count the points of supply and check the notified capacity at each, because capacity that no longer matches how a site is used is a cost that carries forward. Re-run the self-generation, efficiency and wheeling case against the proposed split rather than the current one — when cost moves from consumption to connection, the portion of the bill that own generation displaces gets smaller, and a model built on last year’s tariff maths will overstate the benefit.

    A tariff structure outlasts any single annual increase, and this is the point at which a buyer’s own consumption pattern can be put on the record. NERSA has invited comment on whether the increase has been applied reasonably across customer categories, on cost-reflectivity, and on the effect of the structure on competition as a wholesale market develops. Submissions must reach the regulator by 16:00 on 2 October 2026.

    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.

  • Eskom negotiated pricing agreement: three deals, one signal

    Eskom negotiated pricing agreement: three deals, one signal

    Enerthia Energy works across four offerings — energy consultancy, business development, product and service endorsement, and funding — and one question runs through all four: what does a large user actually pay for electricity? The answer is changing. An Eskom negotiated pricing agreement, once a rarity, has now been approved three times in four months, and pricing at the top end of the South African market is being settled case by case rather than simply published.

    • Three Negotiated Pricing Agreements have been approved in four months, on three different terms.
    • The 62c/kWh ferrochrome tariff runs five years for Samancor Chrome and three for the Glencore-Merafe Venture.
    • Manganese Metal Company’s two-year agreement bridges to a renewable PPA covering 70 percent of its consumption.
    • Your costed alternative — wheeling, a PPA or own generation — is what sets the floor in any negotiation.

    Prefer to listen on YouTube? The full briefing is below.

    What is an Eskom negotiated pricing agreement?

    It is a bespoke electricity price agreed between Eskom and a single large customer, outside the published tariff schedule, and approved by the National Energy Regulator of South Africa before it can take effect. The current wave sits inside an amended framework that lets Eskom tailor pricing and contract structure to one customer’s commercial circumstances, assessed from the bottom up on production cost, electricity intensity and commodity exposure. The regulator has been explicit that this is not a uniform discount: each agreement is judged on its own facts, and the revenue variance is ring-fenced so it cannot be recovered through later tariff mechanisms or the Regulatory Clearing Account.

    Which agreements has NERSA approved?

    Three, in quick succession. On 29 May 2026 the regulator approved the amended framework together with a 62c/kWh tariff for the Samancor Chrome and Glencore–Merafe Chrome ferrochrome smelters, following Eskom’s application of 10 April and public hearings on 25 May. The terms differ even within that single approval: five years for Samancor Chrome, three for the Glencore-Merafe Venture, with the core pricing mechanism and risk-sharing conditions held constant across both. Then on 30 July 2026 the regulator approved a separate two-year agreement with Manganese Metal Company in Mbombela, running from 1 August 2026 to 31 July 2028, with the tariff itself undisclosed and escalation set at producer price index plus one percent each April.

    Why does the Manganese Metal Company term matter most?

    Because the two-year length was chosen for a reason, and the reason is instructive. Electricity accounts for roughly 41 percent of that company’s production cost, and it draws about 360 GWh a year against a minimum consumption payment set at 80 percent of normal offtake. The agreement runs only until a renewable energy power purchase agreement it has already concluded takes over 70 percent of its consumption. In other words it negotiated a bridge rather than a destination — the same fork we set out in trader-led wheeling or a negotiated price — and it did so from a position where most of its future supply was already secured. The alternative was real, costed and contracted before the conversation started.

    What should a large energy user do before negotiating?

    Three things, in order. Know your load profile in detail, because that profile — baseload, load factor, seasonality — is what you are actually offering. Cost your alternatives properly before you discuss price, not after: wheeling across a municipal network, a power purchase agreement or own generation is what sets your floor, and an uncosted alternative sets no floor at all. And treat term length as a commercial position rather than an administrative detail, because a shorter term that bridges to a better supply is a different deal from a long one that locks you in. Context helps here too: Eskom’s sales to industrial customers fell 22.5 percent year on year in its 2026 financial year, so the appetite to retain viable demand is genuine.

    None of this means every large user is heading for 62c/kWh. It means the number on the table is now a function of what you can credibly do instead — and that is work you do before you sit down, not during. Building and costing that position is exactly what our business development work is for.

    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.