For the better part of two decades, summer air conditioning defined the annual peak in many electricity systems. Utilities planned generation portfolios, transmission limits, and distribution upgrades around a load that arrived predictably on hot weekday afternoons. That pattern is now changing in markets where electric heat pumps are moving from early-adopter retrofit to standard heating equipment. Alongside the broader question of why electricity demand is growing again, electrified heating is reshaping the load profile itself—and the part of the year when grids are most stressed.
A Different Kind of Heating Load
An air-source heat pump moves heat rather than generating it. Its coefficient of performance—the ratio of useful heat delivered to electricity consumed—typically ranges from around two to four in moderate heating conditions. A single unit of electricity delivers two to four units of heat, which is why heat pumps require far less electricity than resistance heating for the same comfort. But the performance is not constant. The coefficient falls as the outdoor temperature drops, because the machine works against a larger temperature difference. The same equipment is also reversible: in summer it operates as an air conditioner, which is why many heat pump installations replace both a gas furnace and a central air conditioner.
The Seasonal Peak Question
Whether heat pumps change a market’s seasonal peak depends on the starting point. In many mid-latitude and continental regions, summer cooling has set the annual maximum, while winter heating came from natural gas, oil, or district heating. Replacing those fuels with electric heat pumps adds winter demand without removing the summer cooling load—the same machine often provides both. The result is typically a higher winter shoulder and, in some cases, a new winter peak that approaches or exceeds the summer one. In markets that already heat predominantly with electricity, including several Nordic systems, the winter peak is not new; what changes is its size and duration as more homes and commercial buildings electrify.
The shift matters because winter peaks arrive under different system conditions than summer peaks. Cooling peaks usually occur in the late afternoon and early evening, a period when solar output may still be available in many regions. Heating peaks are often concentrated in the early morning and late evening, when solar output is low or absent. If a winter morning peak grows, the system may rely more heavily on dispatchable generation, storage, or imports at exactly the times when those resources are most constrained.
Cold Weather Behaviour and the Backup Resistance Detail
The part of heat pump performance that rarely appears in sales material is how capacity and efficiency decline together at low outdoor temperatures. As the outside air gets colder, the heat pump must lift heat from a colder source to the same indoor temperature. Compressor output falls, and the coefficient of performance drops. At some low-temperature threshold that varies by model and climate, the heat pump can no longer meet the building’s heat loss, and controls bring on electric resistance elements to supplement the output. In many installed systems, this backup stage draws several times more power per unit of heat than the heat pump itself under moderate conditions.
This creates a planning challenge that annual energy numbers do not capture. A building that uses a modest amount of electricity over a heating season may still impose a sharp load on the coldest winter mornings, when multiple units on the same circuit run their compressors near maximum and cycle resistance stages. Distribution transformers, service laterals, and secondary cables can see extended stress during these cold-snap periods. The peak is weather-driven, simultaneous across many customers, and often longer than a summer cooling peak, which creates different thermal loading on equipment. Ground-source heat pumps are less exposed to outdoor air temperature swings, but their higher installation cost has limited deployment in many markets.
What This Means for Generation Adequacy
Generation adequacy models have historically been built around summer peak demand in many jurisdictions. Electrified heating changes the input assumptions. A winter peak driven by cold weather may coincide with reduced output from solar and, in some regions, lower hydrological inflows; it may also arrive when thermal units are on scheduled maintenance or when natural gas supplies face competing demand from heating. In markets with capacity mechanisms, the resource mix may need to be assessed for both summer and winter conditions rather than a single seasonal extreme. Several grid operators have begun to include winter heating electrification scenarios in their reliability assessments, reflecting the fact that the historical summer-peak assumption is no longer sufficient everywhere.
Electrified heating does not necessarily overwhelm systems. What it changes is what counts as adequate. A generator or storage resource that is available during summer peaks may be less useful if the tightest hour occurs on a cold December morning at 6 a.m., when solar is absent and heating demand across an entire region is high. Some markets are already seeing dual seasonal peaks, where summer and winter maximums are close enough that planning for only one leaves the other under-provisioned.
Network Reinforcement Starts at the Service Panel
The distribution impact is often more immediate than the generation impact. In older residential areas, the local network was designed for a mixture of lighting, appliances, and perhaps air conditioning—not for every home drawing heating load at the same time. Replacing a gas or oil furnace with an air-source heat pump can require upgrading the customer’s electrical panel and service entrance. When several homes on the same street electrify, the shared distribution transformer and low-voltage circuits may also need reinforcement. In many cases, this work is more time-consuming than the heat pump installation itself, involving utility service orders, permits, and coordination with local construction.
Utilities are increasingly applying hosting-capacity analysis and load forecasting at the street level to anticipate where these reinforcements are needed. This is different from building a new transmission line; the constraint is often a distribution transformer sized decades ago, and the fix is localized. The cost recovery for these upgrades also varies by tariff and jurisdiction, creating uncertainty for utilities and installers about how quickly a neighbourhood can fully electrify. This is part of the same electrification-driven load growth now appearing across buildings and transport.
Load Flexibility and the Comparison with EV Charging
Heat pumps are often grouped with electric vehicle charging as part of the broader electrification load growth, but their flexibility characteristics differ. An EV can often shift its charging window in response to price signals, and much of the early discussion around EV charging impact on the grid focused on whether drivers would all charge at once. A heat pump is tied more tightly to weather and occupant comfort, but it is not entirely inflexible. Building thermal mass, hot water storage, and preheating schedules can move some of the demand without affecting comfort, provided the controls and price signals are in place to encourage it.
The difference matters for peak management. Electric resistance backup, in particular, is the least flexible part of the load and the most expensive for the system when it runs. Some utilities have begun to offer heat pump-specific tariffs or demand response programmes that preheat before a winter peak or cycle heat pumps while preserving indoor temperature within a band. These approaches are still early, but they point to a key distinction: the grid challenge is less about how much electricity a heat pump uses over a year and more about when it uses it.
Regional Differences Explain the Options
Heat pump penetration and winter peak risk vary by climate, building stock, and existing heating fuel. Regions with long, cold winters and historically electric heating already manage winter peaks and have less fuel-switching to do. Regions with mild winters and summer cooling peaks may see heat pumps add load without overturning the seasonal pattern. The planning changes are likely to be concentrated in mid-latitude areas where winter temperatures are cold enough to create high heating demand but not so cold that air-source heat pumps were traditionally avoided. There, moderate efficiency loss, backup resistance, and dense residential electrification can combine to produce a winter peak that was not anticipated a decade ago.
The same technology can therefore have very different grid consequences depending on local context. A heat pump in a well-insulated Nordic home may add modest load; the same equipment in a poorly insulated building with a colder climate may drive a much higher demand during cold snaps. Building envelope efficiency is one of several variables that shape that outcome, alongside climate severity, cold-weather equipment performance, the amount of resistance backup, and how much of a neighbourhood electrifies at once. It is also one that utilities can influence only indirectly, through programmes and codes.
What Happens Next
The most useful planning variable in the near term is not the number of heat pumps installed but the shape of the load they create. Utilities that can monitor winter demand at the transformer level, model heating degree days against electricity consumption, and compare summer and winter peaks are better positioned to decide where reinforcement is needed. Building codes, equipment standards, and utility tariffs all shape whether heat pump adoption smooths the winter peak or sharpens it. The direction of travel in many markets is toward electric heating, but the grid outcome depends on how the load is managed, not simply on how much of it there is.
References
- IEA — Electricity 2025: demand trends from building electrification and heat pumps.
- NERC — Long-Term Reliability Assessment: winter peak considerations in jurisdictions with growing electrified heating.
- IEA — World Energy Outlook 2025: scenarios for electrified heating’s contribution to annual and seasonal electricity demand.
