Source - Nordic CCM Third Amendment Package (2026)

Package of documents submitted by the four Nordic TSOs (Svenska kraftnät, Statnett, Fingrid, Energinet) to Ei and the other Nordic NRAs on 19 May 2026. Constitutes the formal third amendment to the Nordic Capacity Calculation Methodology (CCM) under CACM Art. 20(2), replacing the October 2020 version that governed the Nordic flow-based go-live in October 2024. The Nordic NRAs have 6 months to jointly decide on approval (deadline ~November 2026). Ei reference: ärendenummer 2026-103735.

Documents in the package

Accompanying these five documents is an Ei news article (2026-05-20) confirming Ei has opened the review process, saved as a clipping: Raw/Clippings/Ei prövar ändringsförslag för flödesbaserad kapacitetsberäkning.md.

Background: amendment cycle

The CCM was first approved in 2018, then amended in 2019 (First Amendment) and 2020 (Second Amendment — the version governing flow-based go-live). The 2020 version contained explicit obligations to update several articles no later than 18 months after flow-based go-live in the day-ahead market (October 2024 → April 2026 deadline). The TSOs missed this deadline and submitted in May 2026 with a note on the delay.

This Third Amendment substitutes the 2020 version entirely.

Key changes

1. Costly remedial actions limited to 70% compliance (Art. 10)

The most significant policy change. The 2020 version required TSOs to offer “virtual capacity” — capacity backed by redispatch or countertrade — if it could be shown to be economically efficient. The Third Amendment abandons this entirely. Costly RAs (redispatching, countertrading) are now limited to three scenarios:

• To comply with regulatory requirements (principally the 70% minimum capacity rule under Regulation 2019/943 Art. 16(8))
• To manage temporary grid outages or investment delays
• To allow application of TATL in N-1 scenarios

Rationale cited: (a) The EU General Court ruling in BNetzA and Germany vs ACER (October 2025), which established that TSOs providing 70% of Fmax satisfy all regulatory obligations and have no legal obligation to go further. (b) TSO analysis showing that in the Nordic context (with many small bidding zones and scarce balancing reserves), providing virtual capacity and then redispatching in real time is more expensive than the market gains — a net welfare loss.

This is a significant reinterpretation: the 70% rule, previously understood as a floor, is now formally treated as the ceiling of TSO obligations for cross-zonal capacity provision.

2. Reliability margin formalized — FCR margin separated (Art. 3)

The FRM (Flow Reliability Margin) is now explicitly divided into two components:

• RM (reliability margin): uncertainty in load/generation forecasts, GSK assumptions, topology changes, grid model errors
• FCR margin: unintended deviations from FCR-N reserve activations within Nordic LFC areas and cross-border FCR exchange

A maximum 95% statistical risk level is set (the FRM value is the 95th-percentile prediction error). New rules:

• Until historical CGM snapshots are available, TSOs may use their own observed-state IGMs
• New CNECs without sufficient data: FRM ≤10% of Fmax (fallback cap)
• Operational security fallback: TSOs may use a 2-week data period for short-term FRM adjustment
• FCR margin starts at zero until assessed; then computed from historical FCR-N net positions and zone-to-slack PTDFs

3. Thermal limits: PATL replaces TATL (Art. 4)

Fmax on all CNECs is now based on the Permanent Admissible Transmission Loading (PATL) rather than the Temporary Admissible Transmission Loading (TATL). TATL — which allows short-duration higher loading — is instead captured as an RA flow contribution (FRA), not embedded in Fmax. Effect: clarifies the accounting without changing the actual RAM (the capacity shift from Fmax to FRA is neutral on the final available margin).

4. Combined dynamic constraints made permanent (Art. 7)

CDCs — constraints limiting the combined flow on a set of network elements — were temporary in the 2020 CCM (allowed for 2 years after FB go-live). They are now made permanent with a dedicated article and full technical justification covering three stability categories:

• Voltage stability: voltage collapse occurs across a section of lines, not a single CNE — best managed by limiting combined flow across a corridor
• Rotor angle stability (transient + oscillations): inter-area oscillations correlate with power transmission corridors, not individual lines
• Frequency stability: Nordic dimensioning incident (single large generator trip) requires operational limits that span multiple network elements

A fifth paragraph allows CDCs to be used as “border CNECs” — operational placeholders to facilitate Individual Validation Adjustments when individual CNEC-level adjustment would be impractical (e.g., in a major outage).

5. GSK strategies standardized (Art. 8)

Nine numbered GSK strategies are formally defined (strategy 0 = custom; 1–8 covering different generation/load participation weightings). TSOs must perform a comparative study and select the strategy that minimizes the reliability margin for each bidding zone. Results must be published.

6. Data update timing aligned with CACM Art. 14(3) (Art. 24)

Case-specific inputs (CNECs, RAs, CDCs, allocation constraints) can now be updated up to D-1 in line with CACM Art. 14(3), which allows updates once grid conditions are known. Previously the 2020 CCM required 1-month advance notice for changes even to case-specific parameters.

One-month notice is retained for RM and GSK updates (which are statistical/long-term parameters).

7. Article 14 reverts to 2020 wording — the FI–NO4 dispute

Article 14 governs which CNECs appear in the final flow-based domain: CNECs with maximum zone-to-zone PTDF ≤5% are removed (they are not “significantly influenced” by cross-zonal trade, per CACM Art. 29.3(b)).

The TSOs could not agree on whether cross-zonal CNECs should be exempt from this 5% threshold. The specific trigger: the FI–NO4 border CNEC (Finland–Northern Norway).

Fingrid’s position: The FI–NO4 interconnection must always remain in the flow-based domain, even when its PTDF falls below 5%. It is a structurally relevant cross-border constraint taken into account in operational security analysis. Critically, Fingrid cannot apply countertrade or redispatch on flows originating in NO4 — so its only tool is persistent inclusion in capacity calculation. This aligns with Regulation 2019/943’s distinction between internal and cross-zonal network elements.

Statnett + Energinet + Svk’s position: CACM Art. 29.3(b) requires exclusion of CNECs not significantly influencing bidding zone net positions, regardless of whether they are internal or cross-zonal. A blanket exemption for cross-zonal CNECs is legally unjustifiable. Permanent inclusion when PTDF < 5% could materially limit NO4 export possibilities.

Resolution: All TSOs agreed to submit a joint CCM with the unchanged 2020 wording for Article 14 (standard 5% threshold, no cross-zonal exemption). Fingrid separately signalled it will pursue clarification of ACER Decision 08/2023 regarding the NO4–FI border as a distinct matter.

8. Pan-European CGM milestone abandoned (Art. 26)

The 2020 CCM included a milestone for a common dynamic security assessment using a pan-European CGM. The Third Amendment removes this, with the reasoning that the effort is “unprecedented, extremely complex, and depending on very scarce TSO resources” — larger than the entire flow-based implementation project and not needed for a well-functioning daily capacity calculation process.

Regional IGM-based merging continues, with the option to expand to the pan-EU CGM when it reaches sufficient quality.

9. Intraday transitional ATC optimization formalized (Art. 20)

The day-ahead flow-based domain is converted to ATC values for the intraday market, because SIDC (single intraday coupling) cannot yet handle flow-based parameters. The optimization objective (maximize the product of bidding zone border ATCs) and the domain relaxation feature (expand RAM values before extraction) are now formally specified in the CCM rather than only described in a separate Nordic RCC handbook.

10. Advanced hybrid coupling for Viking Link and North Sea Link (Art. 18)

The CCM formalizes the treatment of HVDC interconnections to non-coupled third countries (UK). Viking Link (DK1–UK) and North Sea Link (NO2–UK) are not subject to SDAC/SIDC coupling; their flows are forecast and reserved via standard hybrid coupling (capacity reserved on Nordic CNECs based on forecast flows). Advanced hybrid coupling (PTDFs computed for HVDC exchanges competing for AC grid capacity) applies to other interconnections.

Regulatory significance

The package is the first comprehensive post-go-live update to the methodology governing how ~600 TWh/year of Nordic electricity cross-border trade capacity is calculated. The shift on costly RAs (Art. 10) has direct market consequences: it means TSOs will not provide capacity beyond 70% of the physical flow limit even when doing so might increase market efficiency. The BNetzA court ruling provides legal cover but also signals that the Nordic TSOs have concluded virtual capacity is operationally counterproductive.

The FI–NO4 Article 14 dispute, though resolved in the submission, indicates an open question about how CACM’s significance threshold should apply to cross-zonal CNECs — a question Fingrid has flagged for further regulatory clarification.

Related wiki pages

• Flow-Based Capacity Calculation — the methodology this CCM governs
• Congestion Management — TSO-level context; the 70% rule
• Svenska kraftnät — submitting TSO for Sweden
• ACER — ACER Decision 08/2023 relevant to the FI–NO4 dispute
• Balancing Markets — Nordic FCR/aFRR/mFRR context for FRM methodology
• Source - CACM Regulation (EU) 2015-1222 — legal basis (Art. 20)
• Source - Electricity Market Regulation 2019-943 — 70% rule (Art. 16(8)); distinction between EU Regulation vs CACM