IEA Special Report on Electrification (2026)

International Energy Agency, Special Report on Electrification (typeset September 2026, about 198 pages, CC BY 4.0). Requested by Türkiye and Australia within the IEA’s strategic partnership with the COP31 Presidency, to support the presidency’s proposed global goal of a 35% share of electricity in final energy consumption by 2035. A global report: Sweden appears only in a table of national policies (support for electrifying public vehicle fleets) and the Nordics only in one sentence. This page keeps to the parts that bear on flexibility and grids; the sector chapters (transport, buildings, industry), emerging-economy access, critical minerals and employment are not summarised.

Headline findings (global)

• Electrification’s share of global final energy consumption is about 23% today. Sector-by-sector analysis at 2025 costs finds about 33% cost-effective today; a scenario on today’s policy settings reaches about 30% by 2035, and the IEA’s High Electrification Scenario (HES), built to reach 35%, is derived from its net-zero-by-2050 pathway.
• Roughly half of oil-based road transport demand, half of space-heating demand and about 40% of low- and medium-temperature industrial energy use could be electrified cost-effectively today.
• Europe: exploiting cost-effective potential would raise the electrification rate by almost 15 percentage points, to more than 35%; “further potential exists in countries with low electricity prices, such as the Nordic countries”. One in three cars sold in Europe in the first half of 2026 was electric.
• In the HES electricity demand grows by about 1,400 TWh a year to 2035, nearly twice the pace of the past decade, and average household energy bills fall by about 15% by 2035, but only after large one-off household investments that may need support for lower-income households.

Demand flexibility (section 2.2.5, pp. 58–60)

• Electrified end-uses are flexible demand; the report says this lowers electrification costs for consumers and the system and can strengthen electricity security. Its example is France, where about 15 million consumers subscribe to a time-of-use tariff and the automated signal to electric water heaters avoids more than 3 GW of evening peak (RTE, 2026).
• Negative prices: in more than 60 markets the number of negative-price hours rose from about 110 a year on average in 2019 to over 450 in 2025. This creates a pattern that time-of-use tariffs and flexible demand can use; in the HES demand equivalent to about 10% of average demand is shifted towards hours of high renewables output by 2035.
• For network planners flexible demand “can help to optimise network utilisation and so reduce or defer” expensive grid investment, though structural investment may still be needed for sustained load growth, reliability or asset renewal. Making EVs and heat pumps flexible matters because nearly two-thirds of grid investment is in distribution networks, a significant share of consumer bills.
• Consumer value: flexible operation could save households up to USD 300 a year, as much as 15–30% of the operating cost of an EV, heat pump or electric water heater, on the condition that consumers can access lower wholesale prices. EVs offer the largest saving; water heating can shift through storage tanks; space heating depends on building thermal inertia.
• The expansion of demand-side flexibility depends on user awareness and acceptance, interoperable digital controls with privacy safeguards, and incentives and market frameworks; in the HES all are assumed in place by 2035. Then EVs and heat pumps average about 450 GW but about 900 GW at peak; the equivalent of 15% of total peak demand is controllable, against 2,900 GW of installed batteries and 1,600 GW of gas plants.

Grids (section 3.3, pp. 114–121)

• Grids as a constraint. Delayed grid expansion means longer connection queues, more congestion and curtailment and slower electrification. Distribution grids, which hold most installed lines, must handle higher peak loads, bidirectional flows from rooftop PV and batteries, and variable EV, heat-pump and data-centre demand. Many still lack real-time visibility, automated control and the digital capability needed to use demand-side flexibility.
• Pace and money. Grids must expand and modernise about 40% faster to 2035 than over the past decade (about 2 million km a year in the last decade). Grid investment rose from about USD 295 billion (2020) to USD 450 billion (2025) and reaches about USD 930 billion by 2035 in the HES with the net-zero mix (p. 145).
• Lead times. Major grid projects can take 5–13 years to plan, permit and complete, against 1–5 years for renewables and under two for EV charging infrastructure.
• Solutions. Grid-enhancing technologies (dynamic line rating, topology optimisation, power-flow control, reconductoring, voltage uprating) could unlock 450–700 GW of hosting capacity; dynamic line rating could raise line capacity by 20–30% for about 90% of the year. Demand response, storage, smart charging and automation ease constraints, and flexible or non-firm connections allowing earlier connection in exchange for limited curtailment could enable 750–900 GW (IEA, 2026). Regulatory trends noted: investment frameworks that let operators build ahead of demand with clearer cost recovery and risk sharing, permitting reforms, and connection reforms replacing first-come-first-served with readiness-based requirements. Planning should look “well into the future”, not react to individual connection requests, and be co-ordinated across borders in interconnected systems.
• Data centres (Box 3.1). Campuses can go from announcement to operation in two to three years, faster than network reinforcement; regulators are considering connection charges, minimum payments and stranded-asset protections so other consumers do not carry the cost, and data centres can also act as flexible resources. Google reports 1 GW of contracted data-centre demand response in the United States.
• The report’s conclusion on grids: “The biggest challenge now is implementation rather than a lack of available solutions.”

Policy asks touching the vault’s topics

The ten key actions include cross-cutting electrification strategies, addressing price distortions between electricity and alternatives (with high electricity taxes named as a possible reform target), and enhancing electricity system readiness by scaling up investment in generation, grids and “smarter and more flexible electricity systems”.

Relevance to existing wiki topics

• Flexible Connection Agreements and the Swedish queue reform — an outside estimate of what non-firm connections and readiness-based queues could unlock globally, and the move away from first-come-first-served that the EU proposal COM(2026) 600 Art. 18d also reflects.
• Demand Response — quantified consumer savings, negative-price hours and the peak/average gap of EVs and heat pumps.
• Dynamic Line Rating — the 20–30% capacity gain claim for about 90% of the year at global scale.
• Distribution System Operator — distribution as the majority of grid investment and the place where visibility and automation gaps sit.
• The DSO Entity’s reaction argues for investment ahead of demand; the IEA report supports that direction and treats flexibility as a complement to build-out, not a substitute.

Limits of this source

Global and scenario-based: the HES and its assumptions (all enabling conditions in place by 2035) are the IEA’s constructions, not forecasts, and the hosting-capacity figures are global totals cited to an IEA 2026 analysis not held here. Nothing here is Swedish-specific, so it should support EU and global context, not claims about Swedish DSOs or prices.