You Installed the Panels.
Now Flatten the Curve.
South Africa’s grid load profile reveals a clear daily pattern of stress and relief. This article describes that problem — and one approach to addressing it. The principles are universal. The execution will vary by site, inverter platform, and client.
(18:00 average)
winter vs. summer
installed nationally
What the Load Curve Is Telling Us
The interactive chart below is not just a technical diagram. It is a map of exactly when South Africa’s electricity infrastructure is under stress — and by extension, when every poorly configured solar system on the grid is making things worse rather than better.
Two features of the curve demand attention from anyone who installs rooftop solar and battery systems. Use the controls to toggle between seasons and explore how the TOU tariff bands align with the actual demand peaks.
National Grid Seasonal Load Profile
Summer: Nov–Feb excl. 15 Dec–15 Jan (353 days) · Winter: Jun–Aug (368 days)
Reading the Curve
Look at the chart above and three things stand out immediately. First, a sharp morning spike from around 05:00 as the country wakes up — strongest in winter when heating loads stack on top of the usual morning routine. Second, a midday trough visible in the summer curve between 11:00 and 15:00, the fingerprint of embedded rooftop solar now suppressing grid draw during peak generation hours. Third, the most severe feature of all: the evening peak, where demand climbs hard from 16:00 and hits 29.3 GW at 18:00 in winter — at the exact moment solar generation reaches zero.
These three features define the grid’s daily stress pattern. They are as consistent as the sunrise. And they are precisely what a correctly configured battery system should be designed to address.
The Problem: What Most Systems Actually Do
Before describing a possible solution, it is worth being precise about what the problem actually is — because it is not the hardware. The panels, inverters, and batteries installed across South Africa are largely capable of far more intelligent behaviour than they are currently delivering. The problem is the default dispatch pattern that most systems follow after installation, and the absence of any deliberate strategy to change it.
The dominant pattern among installed solar-plus-battery systems follows a simple and deeply inadequate cycle:
Battery discharges after sunset through the evening. Once depleted, the system draws from the grid through the night and into the morning. Solar charges the battery back up during the day. Battery reaches 100% by mid-morning and then sits there — fully charged, doing nothing — until the sun goes down again. Repeat.
On paper this looks reasonable. In practice it means the battery is idle at 100% through the midday period when it should be absorbing surplus solar generation — and it means the morning peak, one of the two hardest periods for the grid, is covered entirely by Eskom because the battery exhausted itself the previous evening and solar hasn’t recovered it yet.
The battery is cycling once per day, serving one peak, and sitting unused through most of the period when it could be most useful. This is not a grid asset. It is a glorified UPS.
A Possible Solution: The Full-Day Dispatch Model
What follows is one approach to addressing the problem described above. It is not the only approach, and its execution will depend on the inverter platform, battery capacity, site load profile, and the client’s priorities. The underlying principles, however, are consistent: the battery should be cycling in response to the grid’s actual daily stress pattern, not simply reacting to sunset and sunrise.
The model described here targets two discharge events per day — one at the morning peak, one at the evening peak — with two corresponding recharge events: a slow overnight grid charge during the off-peak trough, and a solar midday charge during peak generation hours. The target state of charge before each discharge is 95%, with a 40% floor maintained as an emergency reserve that is never drawn into under normal operation.
On a 10 kWh battery, the usable window of 95% to 40% gives 5.5 kWh per discharge event — 11 kWh of active daily contribution across both events. The specific numbers will differ by system size and load profile. The principle does not.
On Overnight Grid Charging
Overnight grid charging is likely the most counterintuitive element of this approach — and the one most likely to need explanation to both clients and fellow installers. The principle behind it is worth understanding clearly, because the justification is not primarily financial.
Between 22:00 and 06:00, national demand drops to its daily low — around 19–21 GW. Generation capacity is in surplus. Coal stations that cannot be ramped down are running at minimum load. Pulling a slow, steady charge from the grid at this hour adds almost no marginal stress — it is absorbing capacity that would otherwise go to waste.
Compare that to the morning peak at 07:00, when demand climbs toward 26 GW and every available generation unit is running hard. A battery that is still recovering from the previous evening — drawing from the grid at this moment to recharge — is adding load at exactly the wrong time. The overnight charge eliminates this entirely.
The motivation for overnight grid charging is not primarily financial, though on TOU tariffs the off-peak rate saving is a genuine client benefit. The motivation is grid timing. Charging slowly through the night at low-demand hours, and discharging at the two daily peaks, is what active grid participation looks like. A battery configured this way is doing something useful 24 hours a day — not just for four hours after sunset.
On flat-rate and IBT installations, overnight charging costs the same per kWh as any other time. There is no financial penalty for the client. The grid benefit is identical. The case for doing it is purely about responsible system configuration.
The 40% Floor — Always Hold the Reserve
The 40% state of charge floor is not a soft guideline. It is a hard limit that should be programmed into the inverter’s depth-of-discharge setting and never overridden.
It serves two functions. The first is practical: it preserves genuine emergency capacity. An unplanned grid outage at 19:30, a client’s medical equipment, a power cut that runs longer than expected — the 40% reserve is what covers those events without the system being caught empty. The second is technical: consistent deep discharge below 40% accelerates battery degradation, particularly in lithium iron phosphate chemistry. Holding the floor protects the battery investment and maintains usable capacity over its service life.
The usable window — 95% to 40% — represents 55% of nominal capacity per discharge event. On a 10 kWh battery that is 5.5 kWh. On a 15 kWh system, 8.25 kWh. Twice daily that is a meaningful and consistent contribution. Do not be tempted to squeeze the floor lower to extend evening coverage — size the battery correctly instead.
This Applies to Every Installation
The full-day dispatch model described above applies equally to TOU-billed clients and to those on flat-rate or inclined block tariffs. The grid does not differentiate. The morning peak at 07:00 is just as real for a client paying a flat rate per kWh as for one on Megaflex (TOU). The battery’s state of charge at that moment has the same effect on grid stress regardless of the bill.
TOU billing provides a financial signal that reinforces good behaviour — cheaper overnight charging, more expensive peak-hour grid draw — but the underlying configuration logic is identical. An installer who only applies active dispatch management to TOU clients is doing a disservice to the majority of their installed base and to the grid they all share.
“The load curve is your configuration brief. It tells you exactly when the grid needs help. Your client’s tariff structure does not change that — it only changes whether the client notices the benefit on their electricity bill.”
Principles for Implementation
The following points describe what a system configured along these lines should achieve, and the considerations relevant to each phase of the daily cycle. How each is implemented will depend on the inverter platform and its scheduling capabilities — the intent here is to describe the desired outcome and the reasoning behind it, not to prescribe specific menu paths or parameter values.
Overnight Grid Charge — Off-Peak Window, Slow Rate, Target 95%
The intent is to enter the morning peak with a full battery, charged during the period of lowest national demand. The charge rate should be spread across the available window rather than concentrated at the start — a slow, steady draw is what makes this benign to the grid. On most platforms this means setting a charge current that would fill an empty battery over six to eight hours, not two. The specific current value depends on battery capacity and inverter capability.
Morning Discharge — Battery as Primary Source, 40% Floor
During the morning peak the battery should be the primary source, with grid draw minimised or eliminated until either the 40% floor is reached or solar generation takes over. The 40% floor should ideally be enforced at the inverter firmware level rather than purely as a schedule parameter — this ensures the floor is respected regardless of what the schedule is doing. On most winter mornings solar will not be generating meaningfully until well after the peak begins, so the battery carries the full load for this period.
Midday Solar Charge — Battery Before Export, Deferred Start
During peak solar hours the charge priority should be: serve loads → charge battery to 95% → export only the genuine surplus. This is the setting that enables the second daily discharge event — without it, the battery arrives at the evening peak partially charged. Most factory defaults favour export over charging; this behaviour should be explicitly reviewed and changed where necessary.
The solar charge should be deferred — not started at first light. Between early morning and approximately 10:00, solar should serve loads directly while the battery rests at its morning floor. Starting the bulk charge when irradiance is approaching its daily peak means faster charging, better panel efficiency, and — across the installed base — a more pronounced midday demand dip on the national grid curve. How this deferral is implemented depends on the inverter platform: some support a self-consumption period type that achieves it natively; others require a charge current limit or a scheduled block.
Evening Discharge — Battery as Primary Source Through the Peak
The evening peak is the critical window — the highest national demand period of the day. The battery should be the sole source through this period, with grid draw suppressed and export disabled. The same 40% floor applies. In winter this window runs broadly from 17:00 to 20:00; in summer the peak shifts later, broadly 18:00 to 21:00. Both seasonal variants should be considered at commissioning and documented clearly. If battery capacity is insufficient to maintain the floor through a typical winter evening peak, that is a design conversation, not a configuration adjustment.
Geyser and Large Loads — Out of Both Peak Windows
The geyser is typically the largest controllable load on a residential installation. Running it inside either peak discharge window forces the battery to cover it at the expense of other loads, or draws from the grid at the worst possible moment. Scheduling it during solar midday or deep overnight off-peak removes it from the battery’s discharge burden entirely. The same principle applies to any other large schedulable load — pool pumps, underfloor heating, EV charging. The specific scheduling method will depend on what controllable switching is available on site.
Seasonal Variation — Summer and Winter Profiles Differ
As the load curve makes clear, the summer and winter demand profiles are meaningfully different in shape and timing. Evening peak starts earlier in winter, morning peak is sharper, and solar generation windows are shorter. A system configured for summer conditions will not behave optimally through winter. Whatever approach is used, the seasonal difference should be considered — whether through dual seasonal configurations, a scheduled review, or a platform that adapts automatically.
The Bigger Picture
South Africa has approximately 5 GW of embedded rooftop solar installed, growing by over 1 GW per year. The midday dip now visible in the national load curve is direct evidence that the installed base is having a measurable effect on grid demand. That is a meaningful achievement.
But the morning and evening peaks — the two moments of greatest daily grid stress — remain almost entirely served by Eskom’s conventional generation fleet. At 18:00 on a winter weekday, the grid is carrying 29+ GW. The sun is down. Solar contributes nothing. At 07:00 the following morning, demand is surging toward 26 GW and most battery systems are still recovering from the night.
The hardware to change this is already installed on rooftops across the country. The potential is tens of gigawatt-hours of active daily dispatch capacity sitting in residential batteries, cycling once a day at best, configured to serve the client’s convenience rather than the grid’s need.
The gap is not hardware. It is not cost. It is configuration knowledge and the professional standard to apply it on every job. That is entirely within the control of the installer.
A flatter load curve means less strain on generation and transmission infrastructure, fewer emergency generation events, a more stable grid frequency, and a lower average cost of electricity production for everyone. For your clients it means genuine energy independence at the moments that matter — morning and evening, every day, not just during load shedding. For the industry it means installations that can be pointed to as a demonstrated contribution to grid stability rather than a rooftop accessory that happens to reduce one person’s electricity bill.
The following summarises the intent behind each phase of the dispatch approach described
above. How each is achieved depends on the inverter platform, site conditions, and
available controls. The goal in each case is clearly stated; the method is for the
installer to determine.
◎ Overnight: charge battery to ~95% using slow grid draw during low-demand hours
◎ Morning peak: battery as primary source; minimise grid draw; hold 40% reserve
◎ Early solar: serve loads from PV directly; defer bulk battery charging
◎ Midday solar: charge battery to ~95% before exporting surplus
◎ Pre-evening: battery fully charged and held in reserve
◎ Evening peak: battery as primary source; suppress grid draw; hold 40% reserve
◎ Large loads (geyser, pool): scheduled outside both peak discharge windows
◎ Seasonal difference: addressed — whether through dual configs or platform adaptation
◎ All of the above regardless of tariff structure
The panels are the easy part. Anyone can put panels on a roof. The value you add as an installer is in the intelligence of what sits behind them — a dispatch strategy that puts stored energy into the grid at the moments of greatest need, twice a day, every day, summer and winter.
A battery configured for active full-day dispatch is doing its job. Everything else is leaving the work half done.
