Congestion Management

The set of actions taken by system operators (TSOs and DSOs) when the physical grid cannot accommodate all requested power flows. Congestion occurs when demand for transmission or distribution capacity exceeds what the network can safely deliver. Managing it is a core driver of Flexibility needs.

Why congestion occurs

The Electric Power Transmission and Electric Power Distribution networks have finite capacity. Congestion arises when:

• Demand growth outpaces grid reinforcement (electrification of transport, heating, industry)
• Generation patterns shift — renewable generation in locations far from load centers (e.g., wind in northern Sweden, consumption in the south)
• Variable renewables create volatile, weather-dependent flow patterns
• Cross-border flows add to domestic congestion (Flow-Based Capacity Calculation determines available capacity)

In Sweden, the structural north-south imbalance across the Bidding Areas (SE1–SE4) is the most prominent congestion pattern — surplus hydro and wind generation in the north, growing consumption in the south. Svenska kraftnät‘s NordSyd initiative targets this bottleneck, part of Svk’s SEK 225 billion 2025–2035 transmission investment plan (of which ~82bn SEK/36% is system-reinforcement spend, the bucket NordSyd falls under). (Source - Svk Network Development Plan 2026-2035)

Congestion at different grid levels

Transmission (TSO)

At the transmission level, congestion management has well-established mechanisms:

• Bidding zones — structural congestion is reflected in price differences between zones (e.g., SE1–SE4). Market participants see different prices, which implicitly steers production and consumption. (Regulation Art. 14)
• Redispatching — the TSO orders generators or loads to adjust output/consumption to relieve specific constraints. The Clean Energy Package requires redispatching to be market-based (Regulation Art. 13), with non-market-based redispatching only as an exception. The SO GL explicitly lists redispatching of transmission or distribution-connected system users as a remedial action category (Art. 22(1)(e)).
• Countertrading — cross-border variant of redispatching (SO GL Art. 22(1)(f))
• Curtailment — last resort reduction of generation or load
• Cross-border cost-sharing — when redispatching or countertrading is ordered for cross-border relevance, costs are shared among TSOs under regional methodologies approved by national NRAs. In CCR Hansa (the Baltic Sea region), the core principle is that the TSO in whose control area the physical congestion occurred bears the cost — creating a direct financial incentive for TSOs to manage their own domestic constraints. HVDC interconnector faults/limits are split between cable owners by Annex 1 sharing keys; Baltic Cable AB uniquely bears 100% of costs for the SE4–DE/LU border. (Source - CCR Hansa RCCS Methodology and Ei Approval (2024))

Distribution (DSO)

At the distribution level, congestion management is newer and less mature:

• Flexibility Markets — DSOs procure flexibility from local resources to resolve congestion. Art. 32 of the Electricity Market Directive requires market-based procedures.
• Villkorade Avtal — conditional connection agreements where the DSO can curtail customers during congestion events. A rules-based backstop to market-based procurement.
• Network tariff design — time-of-use or capacity-based tariffs that incentivize consumption outside peak periods (implicit Demand Response)
• Grid reinforcement — the traditional but slow solution: building more capacity

DSO-level congestion is growing rapidly as distributed energy resources (solar, EVs, heat pumps, batteries) create bidirectional flows and local capacity constraints that didn’t exist in the traditional passive distribution grid. (Source - Electric power distribution (Wikipedia))

EU regulatory framework

The Clean Energy Package establishes clear principles:

1. Market-based is the default — both redispatching (Regulation Art. 13) and DSO flexibility procurement (Directive Art. 32) must use market-based procedures
2. Non-market measures require justification — rules-based approaches are only permitted where market-based procurement is “not economically efficient” or would cause “severe market distortions”
3. DSOs as neutral facilitators — DSOs cannot own storage (Directive Art. 36) or favor their own resources; they must procure flexibility on a level playing field
4. Transparency — DSOs must publish network development plans identifying congestion areas and flexibility needs (Directive Art. 32(3))

The Network Code on Demand Response (NC DR) adds an operational layer: detailed rules for local services markets, TSO-DSO coordination on shared congestion, observability areas, and congestion forecasting across multiple time horizons. (Source - NC DR Proposal (ENTSO-E and EU DSO Entity, 2024), Source - ACER Recommendation 01-2025 on NC DR)

The 70% minimum capacity rule (Regulation 2019/943, Art. 16(8)) — which requires at least 70% of each CNEC’s physical capacity limit to be available for cross-zonal trade — has historically been interpreted as a floor: TSOs were expected to use costly remedial actions (redispatch, countertrading) to provide more than 70% where economically efficient. The EU General Court ruling in BNetzA and Germany vs ACER (1 October 2025) changed this: once 70% is reached, further economic-efficiency testing is not legally binding, which the Nordic TSOs read as meaning that TSOs providing 70% have no legal duty to go further. The Nordic TSOs incorporated this reinterpretation into the Nordic CCM Third Amendment (submitted May 2026): costly remedial actions are now limited to meeting the 70% minimum, managing temporary outages, and enabling TATL in N-1 scenarios — virtual capacity above the physical limit is abandoned. This means the 70% rule now functions in practice as the limit of what costly remedial actions are used to achieve in the Nordic CCR (70% is the compliance level, not a stated cap), constraining available capacity in congested periods. (Source - Nordic CCM Third Amendment Package (2026), Flow-Based Capacity Calculation › The 70% rule: floor or ceiling?)

The European Grids Package (COM/2025/1005, 2025) adds two further EU-level instruments relevant to congestion management:

• Cross-border cost allocation reform in COM(2025) 1006 — enables use of congestion income (flaskhalsinkomster) to finance cross-border infrastructure; Sweden objects to this restriction on national flexibility in using these revenues (see Svenska kraftnät › Key initiatives)
• 2-way CfD guidance (C/2025/8479) — non-binding guidance for member states on designing contracts for difference between generation operators and a public counterpart; draws on Art. 19d Reg 2019/943 (as amended by the Electricity Market Design Reform 2024) which from 2027 requires public interventions for new generation to use 2-way CfDs. Relevant to Sweden’s debate on capacity mechanisms for dispatchable fossil-free production (see Elmarknadsutredningen and Svenska kraftnät › Strategy 2030)

Congestion management vs grid expansion

A key strategic question: when should congestion be managed through flexibility, and when should the grid simply be expanded?

• Grid expansion is permanent, expensive, and slow (5–15 years for major transmission projects)
• Flexibility is faster to deploy but has operating costs and requires digital infrastructure
• In practice, both are needed: flexibility bridges the gap while grid expansion proceeds, and in some cases permanently defers investment where congestion is infrequent

Svenska kraftnät‘s experience illustrates this: the connection queue exceeds 175 GW against ~25 GW peak load. Even with the massive NordSyd investment, flexibility is essential to manage interim congestion and may permanently reduce the need for some reinforcement. (Source - Svk Network Development Plan 2026-2035)

A third option sits between the two: freeing more usable capacity in the existing grid before any new build. Energiforsk’s Kapacitet för tillväxt (2026) finds 20–40% can be released in congested sections via technical (dynamic rating), operative (active system operation), and contractual (conditional/flexible agreements) measures — the first 10–15% relatively easy — reframing capacity as a system/governance question rather than a fixed technical limit. See Grid Capacity Utilization. (Source - Energiforsk 2026-1190 Kapacitet för Tillväxt (2026))

N-1 and the shift toward probabilistic security margins

Underneath all congestion management sits a prior question: how much of the grid’s physical capacity is even offered to the market as “available” in the first place? At transmission level that answer is governed by the N-1 criterion — the deterministic rule that the grid must survive the loss of any single component. N-1 has never quantified how much risk a given operating state carries, which cuts both ways: some capacity currently held back to satisfy N-1 may be genuinely necessary, but some may not be, given the actual (rather than worst-case) probability of the triggering contingency. The EU is moving TSOs toward stochastic, probability-weighted risk assessment instead — a mandate traced to ACER’s 2019 decision and led by ENTSO-E, which must jointly draft and propose the methodology by end-2027 (CSAM Art. 44.1); actual implementation is explicitly slated for post-2027, with no fixed date yet. One concrete link to congestion management specifically: Energiforsk’s report (2026:1165) lists day-ahead operational risk assessment as one possible input to deciding whether flexibility markets need to be activated (a listed use case, not a described implementation). See N-1 Criterion for the full mechanics and regulatory timeline.

Phantom congestion: luftbokning and the faktisk belastning doctrine

A structural source of apparent congestion in Swedish distribution grids is luftbokning (air booking) — defined narrowly in Ei’s own glossary as large grid-planning margins added because of uncertainty about existing customers’ future transmission needs. Closely related, but distinct, is DSOs tying allocated grid capacity to customers’ contracted power (abonnerad effekt) rather than their actual physical load (faktisk belastning). After dialogue with Svk and the regional DSOs, Ei found no substantial potential to free grid capacity by changing the regulation of agreements or compensation; it did, however, receive indications that some DSOs still deviate from the connection obligation when their risk analyses show an overload risk.

Ei‘s government assignment report (R2024:14) reaffirms the faktisk belastning doctrine: DSOs must calculate available capacity using actual physical load with diversity (sammanlagring) effects, not the sum of contracted capacities. The report does not prescribe an AMI-data methodology for this; the concrete change since Ei’s earlier R2020:06 report is legal — ellagen 4 kap. 2 § now puts the burden of proof on the DSO to show a shortfall cannot be resolved in a socioeconomically justified way before refusing a connection.

Conclusion: Ei R2024:14 proposes no new rules on refunding connection charges to let DSOs use unused capacity (section 5.2), assesses that Ei already has sufficient mandate to issue more detailed requirements or guidance, and recommends that the earlier proposed rule changes (SOU 2023:64) be implemented (section 5.1). It points to existing tools (the faktisk belastning doctrine, the forthcoming Article 6a FCA framework, and revenue-framework incentive reform for RP5 2028–2031) rather than new rules. Planned follow-up is largely supervisory: Ei noted indications that some DSOs still deviate from the connection obligation over overload risk and said this may warrant closer tillsyn review, alongside continuing supervision of tariff compliance and connection-within-reasonable-time obligations.

See also Distribution System Operator › Capacity calculation doctrine: faktisk belastning.

Swedish redispatching framework

Ei‘s analysis (Source - Ei Villkorade avtal (2023)) establishes the regulatory hierarchy for distribution-level congestion management in Sweden:

1. Kostnadsreflektiva tariffer (cost-reflective tariffs) — first line of defense for predictable congestion; EIFS 2022:1 had required capacity tariff reform by January 2027, but is being repealed by June 2026; permissible under Art. 18 EU reg; Ei’s proposal for a new model is due 12 April 2027 (not yet a mandatory model’s effective date) (Source - Ei Effektavgifter webb (2026)). Ei’s ställningstagande Ei2025:06 (Source - Ei Ställningstagande Tariffer Ei2025-06) clarifies the aggregate-load principle: the time-differentiation of the effektavgift must reflect the sammanlagda belastningen (aggregate load) on the DSO’s entire grid — not only the individual customer’s load curve. Setting high-price periods solely from each customer’s own peak hours, without checking whether those hours coincide with high total grid load, is explicitly non-compliant. A four-component structure applies: energiavgift (losses, per kWh), effektavgift (forward-looking capacity signal, time-differentiated), kundspecifik avgift (metering/admin), and fast avgift (residual fixed recovery).
2. Market-based redispatching (marknadsbaserad omdirigering) — competitive procurement on Flexibility Markets; required as default by Art. 13 of the Regulation
3. Non-market-based redispatching — including Villkorade Avtal; only permitted when Art. 13(3) exceptions are met (no market available, resources exhausted, too few providers, or congestion too predictable for market solutions)

DSOs must report their redispatching activities annually to Ei, including volumes, prices, and procurement method — creating a transparency mechanism for tracking the transition from non-market to market-based approaches.

Multi-level congestion: which DSO bears the obligation?

Ei‘s ställningstagande Ei2025:01 (Source - Ei Ställningstagande Ei2025-01 Villkorade avtal (2025)) clarifies a common ambiguity in multi-level grid congestion:

The DSO in whose own network the physical constraint exists bears the obligation to resolve it. This is true at all grid levels — from local DSO to regional DSO to TSO.

Practical consequence: when a local DSO’s connection queue is blocked because the overlying regional grid lacks capacity, it is the regional DSO (or TSO if the constraint is at transmission level) that must act — not the local DSO. The local DSO cannot sign Villkorade Avtal to work around a constraint it doesn’t control and isn’t responsible for resolving.

What the local DSO can do:

• Request raised subscription/connection capacity from the overlying operator
• If unreasonably delayed: report to Ei for review (4 kap. 13 § ellagen)
• Procure flexible resources in its own network
• Design tariffs that relieve the connection point to the overlying grid

What the overlying DSO can do: contract flexibility directly with resources in the underlying network, with the underlying DSO administering procurement and activation — but the financial responsibility stays with the overlying operator (since flexibility service costs are generally not customer-specific and spread across the overlying DSO’s customer collective).

A key practical driver of Swedish DSO congestion management has been the subscription to the overlying grid (abonnemang mot överliggande nät): regional DSOs have fixed power subscriptions from Svenska kraftnät, and exceeding them during peaks creates the primary motivation for local flexibility procurement. Svk’s temporary subscription increases sometimes act as a price cap on flexibility, suppressing willingness to pay on local markets. (Source - Ei Flexibility in Distribution Grids (2023))

The subscription mechanism as market driver

The CoordiNet demonstration provides concrete evidence of how the subscription mechanism shapes market outcomes. (Source - CoordiNet D4.7.2 Swedish Demonstration (2022))

The subscription level (abonnemang mot överliggande nät) is the annually contracted maximum power a regional DSO may draw from the TSO grid without prior notice. It differs from physical capacity — the physical components allow higher flows, but the subscription defines the operational limit. The TSO also grants temporary subscriptions (up to 7 days ahead, retractable at any time) for short-term needs.

This creates two distinct market equilibria:

1. Low-price, high-volume equilibrium (Uppland model): When the TSO frequently denies subscription raises, the DSO must use the market regularly. Flexibility priced below the temporary subscription fee (~240–280 SEK/MWh) is attractive → DSO buys routinely → stable market with meaningful volumes (9,965 MWh over three winters, avg 248 SEK/MWh in Uppland).

2. High-price, low-volume equilibrium (Skåne model): When the TSO routinely grants temporary subscriptions, the DSO only buys flexibility when subscription is denied (penalty ~2,800 SEK/MWh for exceedance without permission) → small volumes, high prices (206 MWh over three winters, avg 2,285 SEK/MWh in Skåne). The market tests processes but doesn’t regularly manage real congestion.

This suggests that the TSO’s subscription policy (how readily it grants temporary subscription increases) is a more important determinant of DSO flexibility market liquidity than market design choices.

A third example — Arvika (subscription optimization as its own lever, distinct from flexibility procurement): the 2026 Arvika Flex pilot study (Flexia Consulting with Glava Energy Center and Teknik i Väst) modelled the cost picture of Arvika’s own subscription level booked against its overlying grid, independent of any flexibility-market activity. The core insight (from Darijan Jelica, who performed the calculations): reducing the subscription level can be economically favorable even though it sometimes triggers överuttagsavgifter (over-consumption penalty fees) — the DSO should balance fixed subscription costs against occasional penalty fees, based on precise, long-term forecasts, since load varies significantly between warm and cold winters. This is the same abonnemang-vs-penalty tradeoff underlying the Uppland/Skåne equilibria above, but applied as a standalone optimization lever a DSO can pull on its own subscription contract, rather than as a driver of flexibility-market liquidity. Teknik i Väst’s grid expects rising capacity need going forward, making this analysis increasingly relevant. (Source - Arvika Flex Pilot Study (Glava Energy Center, 2026))

SE4 vs SE3 and Swedish redispatching data

Sweden’s structural SE4/SE3 congestion price gap (roughly 2–67× higher in Skåne), the market-closure dynamic as grid reinforcement completes, the “chicken race” barrier between grid levels, and the national redispatching volume trend (2022–2024, including the 48× growth in demand-response redispatching and the “increase-decrease game” risk) are covered in full, with charts, at Swedish Congestion Management — Redispatching Data and Regional Patterns.

Economic value and cost of DSO congestion

Quantified economic value of DSO flexibility procurement

FlexAbility (2025) provides three Ellevio case studies quantifying DSO flexibility procurement value — among the first concrete Swedish cost comparisons: abonnemangsoptimering (subscription reduction, up to ~122,000 SEK/MWh at the margin), utnyttjandegrad (revenue-incentive load-flattening, avg. 10,711 SEK/MWh), and alternativkostnad (grid investment deferral, ~2× NPV advantage using the report’s own revised/realistic flexibility-cost estimate — a naive calculation implies ~17:1, but the report itself revises the flexibility cost upward once transformer overload tolerance is factored in). Full figures, both stations’ data, and the generalized transformer-upgrade rule of thumb (1 MW ≈ 100–200 flex-hours/year) are at DSO Flexibility Valuation. (Source - FlexAbility Delrapport 3 (2025))

The macro cost of grid capacity constraints — an early estimate

Before granular Swedish DSO-level valuations existed (see above), a 2017 Pöyry study estimated the economy-wide cost of grid capacity constraints in Sweden (bottlenecks specifically — not production shortage) at roughly 8B/year, potentially rising to ~15B/year by 2030 absent improvement (the citing paper states this without a currency unit — neither ”€” nor “SEK” is specified) — a figure noted at the time as “close to the net worth of the entire grid structure in Sweden.” Cited in a 2019 CIRED paper by DSO practitioners at the outset of CoordiNet, this is the earliest macro-scale estimate in the wiki of what the underlying capacity problem was costing before any of the flexibility-market or tariff-reform responses now documented on this page existed. (Source - Backe Bjarup Ruwaida Change Management Sweden Capacity Challenge (CIRED 2019))

Nodal pricing as a theoretical benchmark

The Elmarknadsutredningen analyzed nodal pricing as an alternative to Sweden’s zone-based price system and rejected it (liquidity, hedging, and investment-uncertainty concerns), while endorsing Flow-Based Capacity Calculation as a partial substitute benchmark. Full analysis on Bidding Areas › Nodal pricing as a theoretical benchmark — SOU 2025:47 analysis.

Kapacitetszoner — upstream congestion prevention at TSO level

Svenska kraftnät‘s April 2026 government assignment report introduces a prospective upstream tool for preventing transmission congestion: kapacitetszoner (capacity zones) within the proposed Anvisningssystem. Rather than managing congestion after connections are made, kapacitetszoner shape which customer categories connect where, steering new large-scale connections toward areas where their load profile reduces rather than exacerbates transmission constraints. (Source - Svk Anslutningsprocessen Rapport (2026))

This is a locational congestion prevention mechanism rather than an operational congestion management tool. Key features:

• Reserved capacity zones for specific customer categories at defined transmission connection points
• A kapacitetskarta (capacity map) showing available capacity at current, 5-year, and 10-year horizons
• Zone entry conditions can require flexibility provision, voltage regulation capability, or production profile matching — directly embedding congestion management capability as a connection condition
• Complements Villkorade Avtal and Flexibility Markets, which manage congestion operationally after connection

Data gaps

• Svk subscription policy: criteria for denying vs granting temporary subscriptions
• Whether abonnemangsoptimering creates net system benefits or merely redistributes costs from DSOs to Svk — Arvika Flex gives a first concrete DSO-level cost calculus (fixed subscription cost vs. occasional överuttagsavgifter, forecast-dependent), but doesn’t itself answer the systemic net-benefit-vs-cost-shifting question