Chapter 15: Flexibility, Balancing and Storage - The Grid's Hidden Challenges

Why Timing Matters: The 9-5 Problem

If you ask a typical well-informed Brit when the electricity grid feels the most strain, chances are they'll respond with the old story about balancing the spike in kettle use that happens during must-watch TV events and especially knock-out Euros and World Cup England football matches. While it's a memorable story that explains the need for hydro pumped storage (and these days, batteries) on the grid quite poignantly, it's never really been true.

The reality is rather less charming. Much of the electricity spike comes from fridge compressors in pubs and homes as spectators grab cold drinks during the match. And yes, there's also a surge from water companies as everyone rushes to the toilet during half-time, forcing pumping stations to work overtime to refill cisterns. Neither of these explanations has quite the same romantic appeal as the tea-making story, so it's no wonder the kettle myth persists - it's much more British.

The bigger explanation as to why this isn't true however is that major England football matches, which in the age of Netflix are about the last remaining collective live TV event, represent the wrong kind of stress on the grid. These events create short-term demand spikes lasting perhaps 15-30 minutes - the kind that can be managed with quick-response storage like pumped hydro or batteries. The grid is never under much strain at 8-9pm on a summer evening, when the World Cup or Euros matches are typically held.

Instead, the real challenge comes from sustained high demand that stretches the entire generation system for hours on end. This happens between 4pm and 7pm on winter weekday evenings and during school term times - a completely different type of stress that requires the grid to operate near its maximum capacity for extended periods. There are a number of complementary reasons for this sustained high demand:

1. It gets dark from 3pm onwards, especially in mid-winter, further north and on overcast days. This drives a need for lighting both in buildings and on streets that doesn't exist to the same degree in the rest of the year. And while the development of LED lighting has dramatically cut the use of electricity in this space, lighting remains a significant contributor to UK electricity demand during winter months.

2. It's colder in winter, which created greater demands for heating.

3. Families begin the preparation of evening meals, especially those with younger children. Cooking appliances use lots of electricity, especially ovens!

4. The end of the school working day at 3-4pm and office working day at 5pm creates a particular spike in home heating demand as thermostats warm-up homes in preparation for people arriving home.

5. The mismatch of the end of the school working day (3-4pm) and office working day (5pm) creates an overlap period from 4 to 5:30pm when most offices are still open and using electricity for computers, lighting or machinery, but many households and especially those with children are at home and using appliances there e.g. for cooking. This coincidence, the use of electricity in both sets of locations at once, albeit only for a relatively short period of time, is what drives the need for a lot of the investment in our energy system and the costs we see on our bills.

Two Types of Grid Stress

Understanding this distinction is crucial for energy policy. There are fundamentally two different types of stress on the electricity grid:

Short-term spikes (like football matches) last 15-30 minutes and can be managed with:

• Quick-response storage (batteries, pumped hydro)
• Demand-side response (asking consumers to reduce usage briefly)
• Fast-start gas plants

Sustained peak demand (winter evenings) lasts 2-3 hours and requires:

• Significant generation capacity to be available and running
• Multiple backup systems to be on standby
• The entire grid infrastructure to operate near maximum capacity

The winter peak is far more challenging because it requires sustained operation of the entire generation fleet at high levels, not just quick-response backup systems. This is why the grid needs so much investment in generation capacity, transmission lines, and distribution networks - not because of occasional TV events, but because of the predictable, sustained demand patterns of modern life.

There are laudable attempts by suppliers to discourage use of electricity in peak periods. Smart tariffs reward customers for this and this is possible because the suppliers can avoid more expensive wholesale energy prices in the peak hours, when the least efficient power stations and batteries are needed to meet demand, as well as punitive charges from the electricity networks. Over time, automation and remote control of home batteries, heat pumps and EVs is likely to extend this sort of demand response much further and without any conscious behaviour from end users. Indeed, given the spike in electricity demand over the 4-7pm period is often only 5-8 GW, it would only take around 2-3 million homes installing a standard 3kW battery to completely eliminate this peak. That said, as we use more power and especially power from renewables, the goal posts may shift higher further into the future.

It begs the question of whether a more root-and-branch review of how we structure our working day might be called for. The norms we have - such as the 9-5 working day for adults and 13 weeks of school holidays per year - are a legacy of Victorian industrial practices, for example when children were needed to gather summer harvest crops. Recent evidence has called into question the productivity of knowledge-focused work in particular, with research suggesting that an 8-hour working day may not be optimal for cognitive tasks. Closing offices earlier would significantly reduce electricity demand during peak periods, allow working parents to more easily collect children from school, and bring substantive improvements to mental health and road safety (fewer journeys completed in the dark).

Another aspect of why our current working day adds so much to energy bills is that we only really put significant pressure on the energy system for a relatively short period of time. So the fixed cost of maintaining an energy system capable of meeting these peak demands is spread over a relatively limited number of hours and days. The main winter season lasts from early November (just after the clocks go back) to late February. During this period, there is much less pressure on the grid on weekend evenings (which account for 2 out of 7 days). There is also significantly less pressure on Friday evenings, as people are more likely to head out straight from the office, eat later, or dine out. This pattern is further interrupted by the Christmas fortnight and, to some extent, the February half-term week, which also sometimes falls in a different week around the country. And from the start of March, even if the weather isn't much warmer, the lighter evenings are enough to cut the use of much lighting. Putting all this together, there are only really around 70 potential evenings - Monday to Thursdays between November and February. And if the weather is particularly mild and windy, which with climate change it often is, this can further reduce the strain on the grid as heating demand is lower and there is abundant wind generation on the grid. In many winters, we might realistically only face 20 evenings when we put much strain on the grid.

However, adopting a model where we require dynamic behaviour change in response to strains on the grid has risks. It is likely to be inherently disruptive, like the overnight routine changes faced by many families during COVID. The alternative - blackouts - are vastly more disruptive, so it would always be worth even very drastic action to avoid this eventuality. But even with automated solutions like smart batteries and EVs, there's still a strong case for a more joined-up approach that considers broader social, education, and health policy. The 9-5 working day and school hours that create our peak energy demand aren't just energy policy issues - they affect family life, mental health, road safety, and educational outcomes. A coordinated approach that addresses these multiple benefits could be more effective than relying solely on technological fixes. Moreover, making an overall and permanent change - such as shifting typical working hours earlier - would be more predictable for both the energy system and for families, rather than requiring constant adaptation to grid conditions.

The Technical Challenge: Grid Flexibility

Britain's electricity grid faces a fundamental challenge that has grown dramatically in recent years: the need for flexibility to balance supply and demand in real-time. As we've increased our reliance on intermittent renewable sources like wind and solar, the traditional model of matching generation to demand has become increasingly complex and expensive. We're also moving more of our heating from fossil fuels to electricity (mostly heat pumps), meaning in winter especially, our demand for electricity might start to grow dramatically (to date it hasn't).

The Balancing Challenge

Unlike fossil fuels, electricity cannot be stored easily, at not without other technologies and investment in big hydro dams and batteries. Grids are inflexible, supply and demand must be balanced second-by-second. The grid can only tolerate energy imbalances of about 1% - roughly 400-500MW in Britain's system - before automatic load-shedding kicks in to prevent cascading blackouts. When this balancing fails, the consequences can be severe: Iberia's grid collapse in April 2025, triggered by a combination of unexpected demand spikes and insufficient backup generation, left millions without power and demonstrated how quickly a modern electricity system can fail when the balance between supply and demand breaks down.

This balancing act has become significantly more challenging as our energy mix has shifted from predictable fossil fuel plants to variable renewable sources.

The Scale of the Problem

In 2024, wind and solar now provide over 40% of Britain's electricity, up from less than 10% in 2010. This transformation has created new challenges:

• Wind variability: Wind output can vary from near-zero to full capacity within hours
• Solar intermittency: Solar generation drops to zero every evening and is reduced on cloudy days (and winter!)
• Demand patterns: Peak demand still occurs on winter evenings when renewable generation is typically low

The result is a system that requires far more sophisticated balancing mechanisms than the simple "turn up the gas" approach that worked when fossil fuels dominated.

Current Balancing Mechanisms

Britain's electricity system uses several mechanisms to maintain balance:

1. The Balancing Mechanism

National Grid ESO operates the Balancing Mechanism, where generators and demand-side response providers can offer to increase or decrease output to help balance the system. This operates in real-time, with offers typically made 1-4 hours ahead.

2. Frequency Response Services

These services respond automatically to frequency changes on the grid:

• Primary Response: Automatic response within 10 seconds
• Secondary Response: Automatic response within 30 seconds
• High Frequency Response: For when generation exceeds demand

3. Reserve Services

• Short-term Operating Reserve (STOR): Gas and diesel plants that can start within 20 minutes. In the recent past, there have also been special reserve contracts for coal plants approaching retirement, though these have now all lapsed.
• Dynamic Containment: Fast-acting batteries and other technologies responding within 1 second

The Cost of Flexibility

The increasing need for flexibility has created a significant new cost category in the electricity system. In 2023, balancing costs reached over £2 billion annually, up from around £200 million a decade ago. These costs are passed through to consumers via network charges.

Why Costs Are Rising

1. Reduced inertia: Traditional thermal plants provide system inertia naturally. As these close, we need to pay for synthetic inertia from batteries and other technologies such as grid-forming inverters.

2. More volatile prices: With intermittent renewables, electricity prices can swing from negative (when wind is high and demand low) to over £1,000/MWh (when demand is high and wind is low).

3. Backup capacity: We still need enough dispatchable capacity to meet demand when renewables aren't available, but this capacity earns less revenue when renewables are generating.

Storage Technologies

Battery Storage

Battery storage has emerged as a key technology for providing flexibility, though adoption varies significantly across markets. The cost of battery storage has fallen dramatically, from over £1,000/kWh in 2010 to under £200/kWh in 2024, making it increasingly competitive with traditional energy storage. With a lifetime of 6,000-8,000 cycles, and a finance (cost of capital) cost of 7.5%, a battery charging and discharging every day (called cycling) can typically achieve a payback if it can charge at 8-12 pence/kWh less than it can discharge, over a lifetime of 16-22 years. This calculation accounts for 10-15% of the energy to be lost during the charging and discharging process (called a round-trip efficiency of around 85-90%) - the rest is lost as heat. This 8-12 pence/kWh spread (£80-120/MWh) is roughly the same as the cost of generating power for a few hours every evening from a medium efficiency gas power plant.

Battery Storage Deployment: Britain vs. Europe vs. US

United States: The Battery Leader

The US leads global battery storage deployment, particularly in California and Texas. California's aggressive renewable targets and high electricity prices have created strong economics for battery storage, with over 6 GW installed by 2024. Texas has become the second-largest market, driven by its deregulated electricity market and extreme weather events that create high price volatility. The US benefits from federal tax credits and state-level incentives, making battery projects highly attractive to investors.

Europe: Catching Up

European battery deployment has been slower, constrained by regulatory barriers and fragmented markets. Germany leads European deployment, driven by high electricity prices and strong renewable integration needs. Britain has been catching up rapidly, with over 2 GW of battery storage deployed by 2024, supported by capacity market mechanisms and frequency response services. However, European projects face higher costs due to more complex permitting and grid connection processes compared to the US.

Britain: Unique Challenges and Opportunities

Britain's battery market has unique characteristics. The country's high electricity prices and significant renewable capacity create strong arbitrage opportunities, but high interest rates and complex grid connection processes have slowed deployment compared to the US. Britain's capacity market provides revenue certainty, but the lack of long-duration storage incentives has focused investment on shorter-duration applications. With continued cost reductions and market reforms, Britain could see accelerated battery deployment, particularly for grid-scale applications.

Types of Battery Storage

• Grid-scale batteries: Large installations installed by utilities and connected directly to the power grid. These installations are increasingly common, particularly alongside conventional power generators (like wind and solar farms), to share the existing grid connection.

• Behind-the-meter storage: Household and commercial batteries can be installed where power is already being consumed. When combined with onsite solar PV, such storage allows a site to extend the self-sufficiency potential of the PV by charging during the daytime and using the electricity stored in the evening and nighttime, a process which typically makes significant additional bill savings through significant grid levy savings on electricity.

• Electric vehicles: Mobile storage that can in-theory provide vehicle-to-grid services. To date, this is still a technology in its infancy and the mass adoption of it isn't expected for some years yet due to regulatory and technical issues. Almost all existing car chargers (and most cars) are not able to do this, so we're some way off it having an impact.

The Case for Low-Hanging Fruit

Rather than pursuing the most ambitious battery storage projects, there's a strong argument for focusing on the low-hanging fruit - investments that offer lower risk and more stable returns. These include behind-the-meter storage combined with solar PV, where the economics are more predictable and the returns more certain. A household with solar panels and a battery can avoid grid charges and time-of-use pricing, creating a guaranteed return that doesn't depend on volatile wholesale electricity markets. Similarly, commercial and industrial sites can use batteries to reduce peak demand charges, which are often the largest component of their electricity bills. These applications provide steady, predictable returns that are less exposed to market volatility than grid-scale storage projects that rely entirely on wholesale price arbitrage. By focusing on these lower-risk applications first, the industry can build experience, reduce costs, and create a foundation for more ambitious grid-scale projects as technology matures and markets develop.

Pumped Hydro Storage

Britain has four major pumped hydro facilities in Snowdonia (Wales) and Scotland. These each hold enough energy when fully loaded (charged) to run at full tilt for 5-7 hours:

• Dinorwig (1,728 MW -> 5.3 hours, 9.1 GWh)
• Ffestiniog (360 MW -> 5.6 hours, 2.0 GWh)
• Cruachan (440 MW -> 7.3 hours, 3.2 GWh)
• Foyers (300 MW -> 6.7 hours, 2.0 GWh)

A major new pumped storage project, Coire Glas near Loch Ness, has been approved and could add 1,500 MW with 30 GWh of storage capacity, with nearly double the energy storage of all existing British facilities combined it should hopefully be able to run for 20 hours at full capacity. Coire Glas could rival some of Europe's largest pumped storage schemes like Grand Maison in the French Alps.