OL3 outage · SE1 structural shift · Nordic hydrological deficit · CHP phase-out · Transmission failure — probabilistic framework and compound scenario assessment
This note documents seven concurrent structural risks in the Finnish electricity system and their compound interaction in the 2026–2030 window. Each risk is individually documented and monitored. None has been assessed in combination. The compound scenario — OL3 unplanned outage during a cold-still period, with SE1 transmission at saturation, Nordic hydrological deficit at historical low, and CHP capacity declining — produces an EPP shift from approximately 0.20 (live baseline, 4 May 2026) to 0.70–0.85 without additional load growth. With DC load growth of 1,500–3,000 MW by 2030 (Vattenfall estimate: DC share rising to 25% of total consumption; Mattila report November 2025 projects significant capacity growth through 2030), the same compound scenario approaches the BP-like threshold. This is not a forecast. It is a structural diagnosis: the system has no actor responsible for monitoring the compound state, and no instrument that aggregates these seven risks into a single posture indicator. TN-009 proposes a probabilistic risk component (FRP) for integration into WEM EPP v4.
Olkiluoto 3 contributes approximately 1,600 MW of firm capacity — the largest single generation unit in the Finnish system. Its contribution to EPP FirmShare is substantial: loss of OL3 reduces FS by approximately 20 percentage points, shifting EPP by 0.15–0.25 points independently of other conditions.
Outage probability follows a Poisson process. For an EPR-class reactor in early operational years, λ ≈ 0.7 per year is a conservative estimate, giving P(outage in winter window, 120 days) ≈ 0.23. Duration distribution is heavy-tailed: 70% resolve within 24 hours, 25% within 1–5 days, 5% extend beyond 5 days. The 5% tail dominates the risk distribution. Average expected duration E[D] ≈ 43 hours.
May 2026 update — EPR structural risk signal: Flamanville 3. Flamanville 3, the sister EPR reactor to OL3 (same technology generation, both commissioned 2024), was connected to the French grid in December 2024 and reached full power in late 2025. Tekniikka&Talous reported (May 2026) that Flamanville 3 requires a one-year repair period during which its reactor pressure vessel lid — approximately 100 tonnes — must be replaced. This is a significant EPR technology signal: a structural component failure requiring extended shutdown in the first year of full commercial operation. Flamanville 3 and OL3 share the same EPR design lineage (Areva/Framatome); whether the lid issue reflects a common-mode vulnerability or a plant-specific manufacturing defect is not yet publicly established. The duration estimate (one year) is substantially longer than the 5-day tail in the TN-009 baseline — if OL3 faces an analogous repair requirement, the tail of the duration distribution extends materially. This does not change the central estimate of λ ≈ 0.7/year, but increases the weight on the heavy tail: the 5% extended-outage scenario may have duration measured in months rather than days. The compound risk probability figure (0.5% per winter) is not mechanically revised pending more information on Flamanville 3's specific failure mode, but the qualitative conclusion strengthens: a long-duration OL3 outage is now an observed precedent in sister-reactor technology, not a theoretical tail event.
The scheduled maintenance window for OL3 in 2026 is 10 September–30 October (50 days). OL1 is in maintenance 19 April–13 June (55 days). The risk profile for winter 2026–2027 depends on whether unplanned outages coincide with the cold period.
OL1 is currently in planned maintenance (−900 MW). OL3 is operational. WEM §03 shows nuclear W24 at 2,798 MW — consistent with OL3 full output and OL2 operational. The planned OL3 autumn maintenance window (September–October 2026) creates a structural vulnerability during the early heating season, before typical winter demand peaks.
The SE1→FI interconnection has a nominal NTC of approximately 1,500 MW. WEM §12 recorded SE1→FI flow at ~1,576 MW on 4 May 2026; corrected TRR ~68% against Aurora-updated NTC of ~2,300 MW — the connection is operating at saturation during a normal spring day. This is not a stress event; it is the new normal.
The structural cause is documented in Svenska kraftnät's Grid Development Plan 2024–2033: electricity consumption in northern Sweden (SE1 bidding zone) is growing faster than generation, driven by Stegra (700 MW electrolysis), HYBRIT, LKAB expansion. Svenska kraftnät projects that the SE1→FI flow direction will shift from export to import in 2027 — meaning SE1 will move from being a supplier to being a competitor for the same interconnection capacity Finland currently relies on.
Historical precedent: Svenska kraftnät significantly curtailed SE1→FI capacity in 2021, in violation of EU Regulation 2019/943 (minimum 70% of operationally secure capacity for cross-zonal trade). The Finnish Energy Authority documented this as an illegal restriction. The mechanism for recurrence exists — it does not require political intent, only physical congestion in northern Sweden's internal grid.
SE1→FI TRR corrected to ~68% following Aurora Line commissioning (November 2025, +800 MW NTC). High utilisation on a normal spring day — not saturation. The emergency buffer exists but is substantially committed at normal load. Under peak winter demand with compound stress (OL3 outage, cold period), the corrected NTC is reached at approximately 2,100–2,300 MW total flow — still a binding constraint. The structural trend (SE1 industrial load growth) continues to erode this buffer towards 2028.
As of March–April 2026, the Nordic hydrological balance is at its lowest level in ten years, with a deficit of approximately −27 TWh relative to the long-term average. WEM §11 records Norjan reservoaarit at 32.4% versus a median of 58.0% (NVE Week 17 2026). The change is rapid: the hydrological balance was +17 TWh (surplus) in winter 2024–2025.
Finland's domestic hydropower capacity is approximately 3,200 MW installed, producing roughly 10–14 TWh annually. Finnish reservoirs follow the Nordic pattern. WEM §03 records Finnish hydro W24 at 763 MW — consistent with spring low-flow conditions. The Finnish hydro contribution to FirmShare is real but weather-dependent: in a dry year, FS(p) — the probabilistically adjusted FirmShare accounting for hydro reservoir level — is materially lower than the nominal FS value.
The critical T–W correlation applies here: cold, calm periods (which drive highest system stress) correlate with low precipitation and low snow accumulation. A dry winter that produces the hydrological deficit also tends to produce the wind drought. These are not independent risks.
Combined heat and power (CHP) provides approximately 3,200 MW of semi-firm generation capacity with a positive temperature correlation — output is highest precisely when winter demand peaks. WEM §03 records CHP W24 at 3,200 MW and CHP/kulutus at 41.3%. WEM §10 backtest data shows CHP share declining from 36.5% (January 2022) to 25.5% (December 2024).
Helen's planned transition from CHP to electric boilers (700 MW) replaces dual-output capacity (electricity + heat simultaneously) with single-output load (heat only, consuming electricity). The net effect on the electrical system is negative: the same heat demand now requires electrical input rather than generating electrical output. The ECI semi (firm + CHP / total production) masks this transition in aggregate statistics — it appears as a CHP reduction but the system effect is a simultaneous capacity loss and load increase.
§ 01eTransmission failure risk divides into two structurally distinct categories, each with different probability distributions, durations, and system impacts. Both are relevant to the compound scenario framework.
The Baltic Sea has experienced nine submarine cable and pipeline cuts in 14 months across three separate incidents (October 2023 NewNew Polar Bear, November 2024 Yi Peng 3, December 2024 Eagle S). The Estonia–Finland Estlink 2 cable failed on 25 December 2024, reducing cross-border capacity from 1,016 MW to 358 MW for six months at a repair cost of 50–60 million euros. A separate Estlink 2 fault in January 2024 required seven months of repair. Fenno-Skan 2 (800 MW, Finland–Sweden) experienced a substation fault in March 2026 (4-hour outage) and a construction damage incident in April 2023. Estlink 1 experienced a substation fault in September 2025.
The critical structural observation: whether a transmission failure constitutes an endurance risk for Finland depends on the direction of power flow at the moment of failure. The Estlink 2 December 2024 failure occurred while Finland was exporting 650 MW to Estonia — the result was a slight price decrease in Finland and a significant increase in Estonia. The same cable failure during a Finnish import period would have had the opposite effect. With SE1→FI at ~68% TRR under normal spring conditions (corrected post-Aurora NTC ~2,300 MW), a Fenno-Skan HVDC cable or Finnish 400 kV north–south transmission failure would constitute a direct endurance event under compound winter stress — when TRR approaches 100% — but not under normal spring operation.
SE1 transmission failure is an endurance risk for Finland if and only if TRR > 0 in the import direction at time of failure. Current state: TRR ~68% (corrected for Aurora Line). The directional risk condition is active when TRR approaches 100% — which occurs under compound winter stress, not normal spring operation. The same physical failure event is benign when Finland is exporting and critical when Finland is importing. WEM §12 TRR provides real-time monitoring of this condition.
Finland's main grid comprises approximately 14,900 km of transmission lines and 138 substations. Fingrid recorded 241 disturbances in 2025, of which 151 were caused by lightning or natural phenomena. Transmission reliability in 2025 was 99.99995% — a historical record. Under normal conditions, individual line faults are self-healing or resolve within minutes.
The compound risk mechanism is different. A sustained cold period (T < −15°C, duration > 72 hours) with concurrent storm activity creates simultaneous stress across multiple components: line icing increases fault probability, repair crews face operational limitations, and demand is at maximum precisely when system margins are thinnest. The 1975 Alajärvi 400 kV fault divided Finland in two for one hour during winter conditions — Kemijoki hydro was the sole supply for northern Finland. The historical record (Tapani 2011, Eino 2013, Seija 2013) documents storms exceeding 200,000 customers interrupted. None of these coincided with a nuclear unit outage and SE1 saturation simultaneously — the compound has not been empirically tested.
The weather conditions that maximise 5b risk (cold, storm, icing) partially overlap with the conditions that maximise OL3 risk and SE1 saturation. A severe winter storm during a cold-still period reduces transmission reliability, increases demand, and occurs in the same meteorological regime as wind drought. These are not independent risks in the compound scenario.
Individual assessment of each risk understates the system vulnerability because the risks share structural correlations. The worst compound scenario is not the sum of individual worst cases — it is the intersection of conditions that are physically correlated.
The 0.5% per winter figure appears small. The correct interpretation is actuarial: over a ten-year horizon, P(at least one compound event) ≈ 1 − (0.995)^10 ≈ 5%. With DC load growth adding 1,500–3,000 MW of flat load by 2030, the same compound trigger produces a materially worse outcome — the system has less margin to absorb the shock.
| Scenario | EPP Baseline | EPP Compound | Classification | CELP¹ |
|---|---|---|---|---|
| Current state (4 May 2026, live) | 0.20 | — | Normal | ~2% |
| OL3 outage, normal conditions | 0.20 | 0.35–0.40 | Tight | ~15% |
| OL3 + cold | 0.20 | 0.50–0.65 | Elevated | ~60% |
| OL3 + cold + wind drought | 0.20 | 0.70–0.85 | BP-like | ~90% |
| Same + 1,500 MW DC (2027) | 0.30 | 0.80–0.92 | BP-like | ~95% |
| Same + 3,000 MW DC (2030) | 0.45 | 0.87–1.00 | BP-like | ~99% |
| Two-unit outage: OL1+OL3 simultaneous (planned+unplanned overlap) | 0.20 | 0.65–0.80 | BP-like (no cold needed) | ~75% |
¹ CELP (Compound Event Loss Probability): conditional probability that, given the compound trigger occurs, demand exceeds firm generation capacity for ≥1 hour within the event window. This is not an annual outage probability — it is a within-event severity indicator. Finland's annual LOLP (per official Fingrid assessment) is <0.01%. CELP 2% at baseline reflects the small fraction of normal winter hours where spot spikes require demand response activation. CELP ~90–100% under the full compound scenario means that if OL3 fails during a cold-still-low-hydro period, capacity shortfall in at least one hour is nearly certain within that event window.
Sensitivity of the compound probability estimate. The 0.5% per winter figure is sensitive to the input assumptions. OL3 failure rate λ=0.7/year is based on early EPR operating experience; TVO data from 2023–2026 would improve this estimate. P(T < −15°C) = 0.08 is a Finnish climatological approximation; the threshold definition (duration matters: a 2-hour excursion differs from a 5-day cold spell). P(wind drought | cold) = 0.25 is a rough T–W correlation estimate. Combining uncertainties, the compound probability range is approximately 0.1–2.0% per winter (factor-of-4 uncertainty). The qualitative conclusion — that the compound risk is not negligible and is structurally unmonitored — is robust across this range. The specific numbers (0.5%, EPP values) should be treated as order-of-magnitude estimates, not precise forecasts.
The fat-tail structure dominates. The P90 Expected Energy Not Served (EENS) is approximately 8 GWh; the P99 is 80–150 GWh. A standard reliability planning exercise based on expected values systematically underestimates this risk by 2–3x because it does not model the T–W–hydro correlation structure.
§ 03Each individual risk is monitored by a competent institution. Fingrid monitors OL3 outage probability and adjusts SE1 NTC accordingly. NVE publishes weekly reservoir statistics. Svenska kraftnät publishes capacity plans. TEM monitors CHP decommissioning timelines.
No institution monitors the compound state. No instrument aggregates these seven risk indicators into a single posture assessment. The Mattila data centre report (November 2025) assessed the electricity system from a data centre perspective and concluded that electricity will not run out. This conclusion is defensible on its own terms — it was not the wrong answer to its question. The question did not ask what happens when OL3 is offline during a cold–still–dry period with SE1 at capacity and CHP declining. That question was not in the commission.
May 2026 — fiscal integration empirical anchor. Verohallinto Director General Markku Heikura disclosed that Finland's 44 registered data centres produce very little net tax revenue. The largest single tax yield from one data centre is €11 million; the largest single VAT refund paid to a data centre is €240 million. Heikura stated that in some cases the net fiscal effect is negative. Seven of 44 data centres employ more than 20 people. The mechanism is structural: intra-group transfer pricing, sales booked outside Finland, investment depreciation, and VAT refunds combine to produce negative fiscal integration at present operating scale. This finding is significant for compound risk assessment because it confirms that the dominant dynamic of Finland's DC growth is cost absorption by the electricity system — in transmission capacity, grid reinforcement, and reserve adequacy — without corresponding fiscal or employment return that might justify the systemic exposure. The compound risk calculus does not change, but the policy context changes: the implicit assumption that DC growth produces fiscal benefit to offset systemic cost is not supported by current data.
This is not a criticism of Mattila, Fingrid, NVE, or Svenska kraftnät. It is a structural observation: the commission architecture guarantees that the compound question is never asked, because no single actor's mandate covers the compound state. This is the measurement gap in SM-009 §09 applied to physical infrastructure risk.
The Finnish electricity system faces four concurrent structural pressures in 2026–2030, each individually monitored and each individually manageable. Their compound interaction — particularly the OL3 × cold × wind drought × SE1 saturation scenario — produces a system state that has no current monitoring instrument and no owning institution. The probability of the full compound scenario is low (~0.5% per winter) but the tail risk is severe (LOLP approaching 100%, EENS P99 at 80–150 GWh). With DC load growth of 1,500–3,000 MW by 2030, the same compound trigger operates with zero margin. The diagnostic recommendation is not a specific policy action — it is first to measure the compound state. An actor must be designated to monitor it.
The compound risk framework identifies when a system is structurally vulnerable. What is missing is an explicit decision trigger — a rule that converts the monitoring state into an action signal. Without this, TN-009 remains an analytical instrument rather than an operational one.
The Compound Alert Trigger (CAT) is a binary signal derived from the existing WEM components. It fires when the compound state crosses an operationally significant threshold:
CAT condition (A) captures the normal compound: high endurance pressure sustained over multiple hours. CAT condition (B) captures the dynamic compound: a system moving rapidly toward stress regardless of current absolute level. CAT condition (C) captures the specific compound scenario of TN-009 §02 — the three-factor intersection that produces CELP approaching 90%.
The CAT threshold values (0.65, 6h, +0.15/24h) are initial estimates requiring calibration against historical data. The structural logic is independent of specific threshold values: the trigger should fire when compound conditions are building, not after they have peaked.
§ 04The compound risk can be approximated within the WEM EPP framework by adding a Failure Risk Premium (FRP) component to EPP v4:
This extension is operationally compatible with the existing WEM §11 structure. SP_cluster and FS(p) are already computed. The NVE proxy is already integrated. FRP requires only the addition of a scalar multiplier applied to the existing EPP calculation when regime conditions are met.
§ 05OL3 λ calibration: The λ = 0.7/year estimate is based on EPR-class reactor operating experience in early commercial years. TVO's actual outage history for OL3 since April 2023 commissioning should be used to calibrate this parameter. Planned maintenance windows are known (ENTSO-E REMIT); unplanned outage rate is the key uncertainty.
SE1 NTC reduction mechanism: Svenska kraftnät's Grid Development Plan projects the flow direction change by 2027. The precise mechanism — whether through reduced NTC allocation, internal congestion management, or market design — determines how quickly the transition occurs and whether it is gradual or step-change.
Finnish domestic hydro reservoir data: WEM currently proxies Finnish hydro via Norjan NVE data. A direct Finnish reservoir level data source (Kemijoki Oy, TVO, Fortum) would improve FS(p) accuracy. The correlation between Norwegian and Finnish reservoir levels is high but not perfect.
CHP retirement timeline: Helen's electric boiler transition affects Helsinki's system. Tampere, Oulu, and other cities have their own CHP timelines. The aggregate national CHP retirement schedule is not published in a single source.
§ 06In structural testing, individual component tests — static load, dynamic load, fatigue — each produce pass results. System integration testing under combined loading reveals failure modes that no individual test predicts. The standard test protocol for a composite structure does not ask "what happens when all load cases apply simultaneously during a temperature excursion?" — because that question exceeds the scope of any single component specification.
The Finnish electricity system has passed its component tests. OL3 operates. SE1 transmits. Fingrid balances. Helen heats. Each actor within its mandate. The integration test — what happens when these systems interact under compound stress — has not been specified, and no actor has been assigned to run it.
This is not a prediction of failure. It is a diagnosis of an untested condition. In structural engineering, the appropriate response is not to assume the structure will hold — it is to run the test.
Finland is not only a recipient of transmission risk — it is also a critical infrastructure provider for the Baltic states. Following the April 2025 Baltic desynchronisation from the BRELL grid, Estlink connections to Finland are the primary security anchor for Estonian, Latvian, and Lithuanian power systems in a crisis scenario. Finnish decisions on domestic generation capacity, transmission investment, and grid resilience therefore carry systemic consequences beyond Finland's own endurance window. This interdependence runs in both directions: Baltic instability affects Fingrid's balancing operations and Estlink utilisation patterns. The compound risk framework in this note is necessarily Finland-centric; a complete regional analysis would model the mutual exposure across the Nordic-Baltic system as a whole.
Architectural note: OCC is not an independent additive risk in the same dimension as Risks 1–6. Risks 1–6 describe physical or energetic stressors — capacity deficits measured in MW or TWh. OCC describes a control-plane failure — a degradation of decision-making quality that changes the conditional probability and severity of all other risks materialising. Adding OCC as a seventh independent component would introduce double-counting: the same meteorological regime that triggers Risk 5b (storm-induced line failure) also triggers telecom degradation, and both escalate the same L3→L4 transition. Instead, OCC is structured here as a multiplicative modulator on EPP*: when OCC conditions are met, the effective EPP is scaled upward and all sectoral endurance thresholds are shifted earlier. This preserves causal clarity and avoids redundancy in the FRP calculation.
Definition: Risk that telecommunications degradation leads to loss of real-time grid observability and partial failure of SCADA-dependent control functions, causing the power system to transition from closed-loop to degraded open-loop operation during compound stress. This is distinct from Risk 5b (physical transmission infrastructure failure): OCC describes a control-plane failure — the physical grid remains intact but can no longer be reliably observed or directed.
SCADA systems in the Finnish transmission grid operate over TCP/IP-based telecommunications backhaul. When telecom backbone availability falls below 60–70% at critical nodes — a condition that can develop within hours of a compound stress event — four control functions degrade simultaneously:
The trigger conditions for OCC are: telecom backbone availability below 60–70% at SCADA-critical nodes, sustained for more than 3–6 hours during compound stress, with SP_cluster elevated (≥ 6h). The combination matters: OCC during normal operation is manageable. OCC during compound stress — when operators most need accurate visibility to make load-shedding and reserve deployment decisions — is when it becomes a system-level failure mode.
Physical network faults (Risk 5) are local and correctable. Observability collapse is system-wide — it affects all decisions simultaneously. An operator who cannot see the grid cannot optimally activate CHP reserves (Risk 6), cannot direct flexible loads to compensate for OL3 absence (Risk 1), and cannot coordinate cross-border import adjustment as SE1 capacity shifts (Risk 2). Risk 7 is not an additional LELF layer; it is a control-plane failure that shifts all sectoral endurance thresholds earlier and invalidates the optimisation logic that would otherwise limit cascade propagation.
When observability collapses, manual operation — slower and operating on stale data — replaces automated dispatch. This effectively shortens each sector's operational endurance by 20–40% depending on its dependence on remote monitoring and control:
| Sector | Nominal θ (L3 threshold) | OCC-adjusted θ |
|---|---|---|
| Water (pumping stations) | 6 h | 4 h |
| District heating (Helsinki-type) | 48 h | 30–36 h |
| Rail dispatch | 0–15 min | 0–15 min (unchanged — but dispatch accuracy degrades) |
| Hospital (non-ICU) | 12 h | 8–10 h |
| CHP reserve activation | immediate (market signal) | delayed — reserves not visible, not called |
The most operationally significant effect: OCC removes the possibility of optimal load shedding. Flexible actions — DC load reduction, CHP dispatch, demand response — are delayed or missed entirely because the operator cannot identify in real time where the system is most critical.
Risk 7 operates as a multiplier on all other risks. OL3 absence (Risk 1) becomes harder to compensate because reserve deployment requires observability. SE1 import-margin assessment (Risk 2) degrades because real-time cross-border flows are uncertain. Hydro dispatch (Risk 3) loses precision. CHP reserve activation (Risk 4/6) is delayed because the capacity is not visible to dispatch. Risk 7 does not add a new failure mode — it degrades the system's ability to respond to all existing failure modes simultaneously.
OCC does not add an independent loss component to CEL. Instead it scales the realised CEL of all other compound risks. Formally: EPP*(OCC=1) = EPP × (1 + OCC_penalty), where OCC_penalty ∈ [0.20, 0.40] depending on telecom degradation depth and duration. In a 48h compound scenario (baseline CEL ~€2.4B without OCC), the OCC multiplier raises CEL₉₀ to €2.9–3.4B. This increment represents the cost of suboptimal decision-making under information scarcity — delayed CHP activation, missed load-shedding opportunities, slower reserve deployment — not additional physical damage. It is currently unmodelled in TN-009's FRP and CAT formulation.
Conditional probability structure: P(Risk 1 impact | OCC=1) ↑, P(SE1 import compensation effectiveness | OCC=1) ↓, P(CHP activation within response window | OCC=1) ↓, P(L3→L4 transition | OCC=1) ↑. OCC shifts all thresholds simultaneously — which is precisely why it cannot be treated as an additive seventh risk without double-counting.
A minimal WEM extension would add two indicators: Telecom_health (estimated operational availability of SCADA-critical telecom nodes, 0–100%, sourced from FICORA/Traficom network resilience data or proxy indicators) and OCC_risk (binary flag activated when Telecom_health < 60% AND SP_cluster ≥ 6h). When OCC_risk = 1, EPP* calculation should apply OCC-adjusted sectoral thresholds and add a control-plane risk premium to the compound probability estimate. Data availability for Telecom_health is a known gap — no real-time public data source currently exists for SCADA backbone status. This is itself a governance gap worth documenting.
Two structural trends are converging on the same 2027–2030 window and reinforcing each other. Neither is visible in the four-risk compound scenario above. Together they represent a fifth structural exposure that is qualitatively different from the short-duration risks modelled in §04–05.
SE1 (Northern Sweden: Luleå, Piteå, Skellefteå, Boden) has been Finland's primary transmission partner — Aurora Line provides ~2,300 MW NTC. But SE1's own electricity consumption is growing at unprecedented scale: Stegra (Boden, direct electrolytic steelmaking, ~700 MW), HYBRIT (Gällivare, hydrogen-based iron reduction), H2 Green Steel, Northvolt (Skellefteå battery manufacturing). These are not speculative projects — investment decisions are taken. Their aggregate new demand likely exceeds 1,500 MW within SE1 by 2030.
The consequence is structural: the surplus capacity that historically flowed from SE1 toward Finland will be competed for locally before it reaches the border. This does not mean SE1→FI flows become zero, but it means the margin available for Finland's import needs in cold-still conditions shrinks materially. Flow-based capacity calculation (in force since 29.10.2024) will reflect this dynamically — when SE1 demand is high, the commercial capacity allocated to SE1→FI will decrease.
Finland's CHP fleet retains approximately 2,500 MW of sähköntuotantokapasiteetti (Energiateollisuus 2025). This is substantial — roughly one-sixth of peak demand. But a critical structural shift has occurred: the capacity exists but is not used for electricity production. Between 2010 and 2025, the share of district heat produced by CHP fell from 71% to 34%. The remaining heat production is shifting to heat-only boilers, heat pumps, and electrode boilers — all of which either do not produce electricity or consume it.
The mechanism is straightforward: when wholesale electricity prices are low (as they have been with surplus Nordic wind and the expansion of OL3), the economics of running a CHP turbine deteriorate. Many plants have turbine bypass capability — the steam is routed directly to district heating without generating electricity. Older plants have limited bypass flexibility; modern and modernised plants are more flexible. The result is that the 2,500 MW of CHP capacity is increasingly a standby reserve that the market does not call upon under normal conditions.
The compound risk emerges from the temporal coincidence: SE1 demand growth accelerates precisely in the 2027–2030 window when CHP alasajo (decommissioning of older fossil CHP units driven by ETS and Fit for 55) reduces the activated capacity. Helen has closed Hanasaari (2023) and Salmisaari (2025). Vantaan Energia is exiting fossil CHP by 2026. The remaining bio-CHP fleet (Kuopion Energia Haapaniemi 118 MW, Lahti Energia Kymijärvi ~100 MW, Oulun Energia ~100 MW) is ageing — Haapaniemi 2 dates from 1982 and faces decommissioning by 2035.
The structural problem is not capacity shortage — it is activation failure. The CHP reserve exists, is already grid-connected, is temperature-correlated (produces most electricity precisely when SE1 export is lowest — cold, high-demand conditions), and is geographically distributed. But it does not activate without a market signal that adequately prices its endurance value. The wholesale electricity market prices real-time energy, not 168-hour endurance contribution. This is the same market failure identified in WP-001 and SM-010: the market correctly allocates today's hour but systematically undervalues the multi-day buffer.
P(SE1 demand growth reduces FI import margin) × P(CHP reserve not activated by market signal) → uncompensated endurance gap in cold-still-dry conditions, 2027–2030 window. Unlike the four binary risks in §04, this risk is structural and continuous — it does not require a specific event, only the persistence of current market and regulatory conditions.
Analogy: the fuel is in the tank. The engine is connected to the grid. But no one has purchased the fuel for today, because the spot market does not require it today. When the storm comes, the activation takes time the system may not have.
SM-011's flexibility quota mechanism is directly relevant here. If data centres occupy the scarce grid connection capacity that would otherwise go to SGFA-type CHP retrofit nodes — nodes that combine heat production, reserve market participation, and demand response — the SE1–CHP compound risk deepens. The flexibility quota creates the institutional signal that the market cannot: flexibility has structural value, and that value should be priced into the connection decision, not discovered only when the margin is gone.