Category: Podcasts

Enerthia podcast episodes.

  • 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.

  • 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.

  • 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.

  • 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.

  • 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.

  • 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 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.

  • 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/

  • 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/

  • 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