Wind outage patterns matter more than total hours lost. A single 200-hour drought within a year can raise firm renewable power costs by up to 337% above a no-outage baseline, while the same hours in short blocks raise costs by under 5%.
The key risk to producing firm, low-cost power using a solar-wind-battery system is not the total annual wind downtime but its shape – that is, the duration of individual outages, their frequency and how they are distributed throughout the year. Short, scattered outages of one-to-three hours, even adding up to 600 hours in total, can be absorbed with negligible cost impact – averaging 1.8% cost increase across the modelled countries.
In comparison, a single contiguous wind drought of ~200 hours can raise the cost of 98%-firm power by 51–337% above a no-outage baseline depending on location. Our analysis shows that, for stand-alone mixed solar-wind systems without backup generation, regions within roughly 35° of the equator have a structural advantage under decarbonisation because their higher optimal solar shares make them more resilient to wind outages.
Wind outages disrupt dispatchable power supply
Grid connection bottlenecks are driving consideration of stand-alone renewable systems, such as microgrids and captive renewable plants, among industrial consumers. For these systems, wind outages are a critical design consideration. Wind profiles used in conventional modelling are often nationally aggregated and, therefore, artificially smoothed, as explored further in this previous Insight. In stand-alone system design, this can obscure the real-world effects of site-level wind intermittency, erroneously favouring wind-heavy mixes and understating the true cost of firming.
The outage durations modelled here reflect realistic conditions – in Northern Europe, IEA Wind notes that low-wind periods lasting several days occur annually, and events approaching one to two weeks are not uncommon – particularly at individual wind sites, which experience greater variability than nationally aggregated wind data suggests.
Overlooking site-level wind disruptions can lead to material cost uplifts
We modelled hybrid solar-wind-battery systems across ten countries using hourly wind and solar generation profiles, optimising the solar:wind ratio, battery size and load availability to minimise the levelised cost of electricity (LCoE) under typical conditions. The results discussed in this Insight are based on 98% firmness – meaning the system must deliver at least 98% of the required load every hour. Although modelled for standalone microgrids, these conclusions are likely relevant to broader grid design.
To test sensitivity to wind intermittency, we applied 129 outage patterns – varying total lost wind hours, event frequency, duration and distribution – to baseline wind profiles while holding the no-outage system design fixed. We also modelled the cost of adding gas-fired backup (i.e. gas engine or OCGT) with a 15-minute ‘bridge’ battery, sized to the maximum firm load and activating only during shortfall – as a fixed-cost alternative to battery-only firming.
Cost inputs are country-specific 2030 values in real 2025 dollar terms from CRU’s Carbon Price Service and CRU's Cost Macro, with a 25-year lifetime and 7% WACC assumed across all jurisdictions. Gas units assume uniform capex. and opex., 40% efficiency and are sized to provide full demand and ~5% of annual power supply. Battery capex. values account for the full range of storage duration needs in a standalone system – including long-duration requirements that are expected to be higher cost than Li-ion.
For firm power, outage shape matters more than duration
Holding annual wind downtime constant at 200 hours and varying only the outage pattern shows how strongly the outage profile drives cost. A 200-hour outage – roughly eight consecutive days of near-zero generation – is not a theoretical extreme. In the UK and Germany, low-wind periods of this duration are a recognised feature of historical wind records.
When those 200 hours are scattered in short one-to-three-hour events, the cost uplift is negligible, averaging just ~0.1% across all ten countries, because a baseline-sized battery can absorb short interruptions and recharge between events. However, when concentrated into a single contiguous block, costs rise sharply. The reason is simple – the battery-based system must be sized to survive its worst outage, leaving much of the capacity underutilised for most of the year.
This effect persists even when total downtime doubles. Ten 40-hour events totalling 400 hours cost less than a single 200-hour block in every country modelled – a result explored in the table below.
Regions further from the equator pay a steeper price for every extra hour of wind drought
The chart below isolates the effect of a single contiguous wind outage of increasing length across different countries.
Across the countries modelled, we define a ‘low-impact zone’ in which a single outage raises costs by <10%. Solar-rich countries, such as South Africa (i.e. 45% solar in its optimal mix), can tolerate much longer outages before leaving the low-impact zone (i.e. at ~73 hours), while most European countries (i.e. optimal solar shares <25%) cross that threshold after roughly 26–32 hours.
As outages lengthen, costs diverge sharply. Solar-rich systems, such as those in Chile and South Africa, remain more resilient, while wind-heavy European systems face steep cost escalation. The chart below shows how this effect amplifies the latitudinal cost gradient for 98%-firm power.
At baseline, countries within ~35° of the equator offer the lowest-cost 98%-firm renewable electricity and retain more of that cost advantage as outages worsen. As outage severity increases, the cost penalty diverges significantly – at a 24-hour outage, the difference between best and worst performers is ~9%. At 600 hours it soars to over 1,000%.
Fixed-cost backup undercuts battery-only systems at higher latitudes
The shaded band in the chart above shows the cost of a natural gas-based backup option defined previously – a fixed uplift of ~$35–41 /MWh (i.e. 17–34% above the no-outage baseline). Because this cost is unaffected by outage severity, it becomes increasingly competitive as outage risk grows. Above ~35–40° latitude, backup undercuts even the least severe outage scenarios modelled. Below ~35° latitude, an optimally configured solar-wind-battery system alone could provide the lowest-cost option for all but the most extreme events.
Replacing gas with biomethane at a uniform cost of $25 /GJ (n.b. ~$9–22 /GJ above natural gas depending on country) raises the backup cost to ~$45 /MWh above baseline – marginally more costly but a lower-emissions option that may be competitive in markets subject to carbon pricing.
The table below compares the gas-based backup option against each location's lowest achievable solar-only LCoE and two contrasting outage scenarios – a single 200-hour wind drought vs. ten 40-hour long events adding up to 400 h (i.e. double the downtime).
A solar-only system providing 98%-firm power costs $122 /MWh in Chile – comparable to the no-outage mixed baseline – but reaches ~$642 /MWh in Germany and ~$787 /MWh in the UK. Chile is the only country modelled where solar-only may undercut a mixed system with backup, although similar economics may apply in other high-irradiance regions outside this analysis, such as parts of Northwest Australia and the Gulf states. Even countries with strong solar resources, such as Brazil and South Africa, can unlock materially lower costs by harnessing the complementarity between wind and solar – confirming wind’s essential role in cost optimisation despite its outage risks.
Implications for the location of power-intensive industries are significant
The same wind drought that has negligible impact in Chile can more than triple firm power costs in the UK. For industrial consumers evaluating captive renewable supply, it is not just average resource quality that matters, but also how a system performs during its worst event.
Systems beyond ~35° from the equator – which tend to be wind-heavy – face compounding difficulties in the form of higher baseline costs, weaker solar resources and greater vulnerability to prolonged wind droughts. In these regions, the cost of overlooking realistic outage profiles in system design rapidly exceeds the fixed cost of backup generation, making gas backup the most cost-effective route to firm dispatchable output in stand-alone systems.
For industrial consumers and developers, this analysis points to three practical conclusions:
- Standalone systems must be designed around their worst wind event, not average conditions – a single multi-day drought drives cost far more than total annual downtime.
- Europe and regions beyond ~35° from the equator should budget for backup – battery-only systems cannot economically bridge multi-day wind droughts; dispatchable backup generation is the cost-effective baseline.
- Location is a strategic decision – the cost gap between systems closer to and further from the equator widens significantly under realistic outage conditions.
To discuss CRU’s work on renewable power costs, power mixes and industrial decarbonisation, please get in touch with us.
