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 — firm deadline 19 November 2026 (previously tracked here as “~November 2026”; confirmed by Ei’s 26 August 2026 public-consultation notice). Ei review case: ärendenummer 2026-103735. The proposal document itself is filed separately in Ei’s e-diarium under ärendenummer 2026-103688.

Public consultation (added 26 August 2026)

Ei opened a public comment window on the proposal: market actors (branschorganisationer, elhandlare, elanvändare, producenter) can submit questions or comments by email to Ei’s Grossistmarknader unit — or request a meeting with Ei to discuss the proposal — by 1 October 2026, citing ärendenummer 2026-103735 in the subject line. (Ei news, 26 Aug 2026)

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 three scenarios (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. Under Art. 10(2) each TSO may define costly RAs (redispatching, countertrading) only in three scenarios (the supporting document also says the TSOs decided not to apply costly RAs to allocate capacity beyond 100% of physical Fmax or beyond what Art. 16(8) of Regulation 2019/943 requires):

• 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 for the application of TATL (the legal text says only that; “N-1” comes from the supporting document’s explanation)

Rationale cited: (a) The EU General Court ruling in BNetzA and Germany vs ACER (Cases T-600/23 and T-612/23, 1 October 2025; Raw/Clippings/General Court BNetzA and Germany v ACER T-600-23 press release (2025-10-01).md), in which the court held that once the 70% minimum is reached an extra economic-efficiency test is legally irrelevant and not binding; the TSOs’ supporting document reads this as TSOs providing 70% of Fmax having 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.

The supporting document’s reasoning is that TSOs providing 70% “comply with the relevant regulation” — 70% is treated as compliant, not as a maximum; the ceiling in the raw is 100% of Fmax. (An earlier version of this page called 70% “the ceiling of TSO obligations” — that framing is not in the raw.) The consequence and welfare-loss arguments are the TSOs’ own assertions.

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 for the reliability margin and the FCR margin, though TSOs may validate whether 95% “can be lowered” using operational information (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, per the FI–NO4 note Fingrid “does not have any oversight on F0 flows originating in NO4” and does not apply these measures in its planning-stage processes — 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 and 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. Statnett alone (in the bilateral phase; Energinet and Svk join only on the CACM Art. 29.3(b) legal argument) argued that permanent inclusion when PTDF < 5% could materially limit NO4 export possibilities — overloads occur in only a limited number of market time units per year and Statnett says it is willing and able to redispatch.

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 “the establishment of a common dynamic security assessment, based on a common dynamic CGM, and common tools” (the raw does not say “pan-European”; regional IGM-based merging with an option to expand to a pan-EU CGM is from the Art. 12 discussion). The Third Amendment removes this, the other milestones having been achieved, with the reasoning that the effort is “unprecedented, extremely complex, 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 Nordic cross-border capacity is calculated (an earlier “~600 TWh/year” figure is in no raw document; “first comprehensive post-go-live update” is the page’s own claim). The shift on costly RAs (Art. 10) has direct market consequences: the TSOs say they will not apply costly RAs to provide capacity beyond 100% of Fmax / beyond what Art. 16(8) requires (the 70% figure is the compliance level, not a stated cap). 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