Generator Connection Requirements

Generator connection requirements are the technical conditions — primarily frequency response, voltage ride-through, ramp rate, and control capability — that generating units must satisfy as a precondition for grid connection. In the EU, these are governed by RFG (EU 2016/631); in Sweden they are implemented by EIFS 2018:2. Requirements are graduated across four types (A–D) based on generator size and connection voltage.

Why this matters for flexibility

Generator connection requirements are not just a technical gateway — they directly determine which flexibility services a generator can provide and which markets it can access:

1. FSM capability (Types C and D only) is the technical prerequisite for primary frequency reserve participation. Only generators with FSM capability can qualify for FCR products in Balancing Markets. Small DERs (Type A, ≤1.5 MW in the Nordic area) have no FSM obligation and are therefore excluded from FCR by design.

2. Ramp rates define the speed at which a generator can respond to activation signals. Kraftparksmoduler (wind, solar, batteries) ramp at 100 %/min under EIFS 2018:2 — by far the fastest of any technology. This physical capability underpins the case for batteries in fast-response Flexibility services.

3. Type A simplicity means most small DERs connect with minimal technical requirements, supporting the aggregation model (Aggregation, Virtual Power Plant). The low barriers to connection were a deliberate policy choice to facilitate distributed generation.

Type classification (Nordic thresholds)

Generators are classified based on the voltage of their connection point and their maximum continuous power:

All four types face the same fundamental frequency operating range (47.5–51.5 Hz, unlimited at 49–51 Hz) and the same LFSM-O obligation (reduce power when frequency > 50.5 Hz). The differences compound upward from B to D.

Power park modules (kraftparksmoduler)

Kraftparksmoduler — a regulatory category covering wind farms, solar PV plants, and battery storage systems connected via power electronics — are technically distinct from synchronous generators:

• No natural inertia: they cannot slow a frequency decline the way a spinning turbine automatically does.
• Extremely fast ramp rates: up to 100 %/min under EIFS 2018:2 §31, compared to 4–40 %/min for conventional thermal or hydro.
• Fault ride-through parameters are different (and in some respects more lenient) than for synchronous machines.

FSM capability can be implemented synthetically in power electronics (“syntetisk tröghet”), allowing kraftparksmoduler to provide frequency response despite lacking physical inertia. Under EIFS 2018:2 §23, FSM must be activatable by TSO instruction — it is not a continuous operating mode.

Energy storage exclusion: RFG Art. 3.2.d explicitly excludes kraftlagringsenheter (energy storage units) from the regulation’s scope, except pumped hydro. In practice, grid-scale batteries operating in production mode are classified as kraftparksmoduler and subject to the PPM requirements. This creates some ambiguity for assets that operate in both storage and generation modes; Swedish practice treats the production-mode requirements as applicable. This exclusion is proposed for removal in NC RfG 2.0 — see NC RfG 2.0 — the Commission’s draft revised RfG (July 2026) below.

FSM and market access

FSM (Frequency Sensitive Mode / frekvenskänslighetsläge) is the active frequency-regulation mode:

• Required for: Types C and D (≥10 MW in Norden, or ≥110 kV).
• Activated by: TSO instruction only (Svk in Sweden). Generators have the capability but are not running it continuously.
• Droop range: 2–12 % statikfaktor; deadband ±100 mHz by default.
• Duration: Full response sustained for ≥ 15 minutes.
• Response delay for kraftparksmoduler: < 2 seconds.

In the Balancing Markets architecture, FSM capability is the technical precondition for FCR (Frequency Containment Reserve) prequalification. Generators that cannot provide FSM — primarily Types A and B — are excluded from FCR markets. mFRR (manual frequency restoration) does not require FSM but does require dispatchability and communication with Svk.

Derogation process

Ei may grant derogations from specific RFG requirements under Arts. 60–63 of the regulation. Seven criteria govern Ei’s assessment (see Source - Ei RFG Undantagskriterier (2017)):

1. Physical location in the network (grid strength)
2. Voltage at connection point
3. Maximum continuous power (MW)
4. Generator type (synchronous vs. kraftparksmodul)
5. Energy source (e.g. wind, hydro, nuclear)
6. Impact on local and national grid stability
7. Operational safety of the generating unit

Criteria are weighed together in each case. An application must include a detailed justification, a cost-benefit analysis, and evidence that the derogation would not negatively affect cross-border trade (Arts. 62–63).

Existing generators

RFG applies to new generating modules only. Existing generators are exempt unless substantially modernised (for Types C/D) or the NRA specifically extends the regulation to them. Sweden’s existing hydropower and nuclear fleet — the backbone of the balancing market — is not retroactively required to retrofit FSM or ramp capabilities under RFG. The existing fleet’s FSM provision is governed by legacy connection agreements and SO GL balancing market participation terms.

Swedish context

• Ei issued EIFS 2018:2 on 8 November 2018; in force 27 April 2019.
• Svenska kraftnät proposed the Nordic-specific thresholds (Type B ≥1.5 MW, C ≥10 MW, D ≥30 MW) in consultation with adjacent TSOs.
• The Nordic Type B threshold (1.5 MW) is set higher than the 1 MW baseline ACER referenced when it considered (and ultimately rejected) lowering the type A/B boundary (Source - ACER Recommendation 03-2023 NC RfG DC (2023)) — reflecting the relatively robust Nordic grid’s ability to admit larger generators under lighter Type A requirements before the stricter Type B rules apply.
• The low Type C threshold (10 MW vs. 50 MW in Continental Europe) means mid-sized Swedish generators face FSM requirements earlier — a system security choice given the large share of hydropower and the importance of FCR.
• EIFS 2018:2 is separate from and should not be confused with EIFS 2022:1 (mandatory effektavgifter for DSOs), which is in the process of repeal as of 2026.

NC RfG 2.0 — the Commission’s draft revised RfG (July 2026)

ACER submitted Recommendation 03-2023 to the European Commission on 19 December 2023, proposing comprehensive amendments to both NC RfG (EU 2016/631) and the Demand Connection Code (EU 2016/1388). The recommendation was the formal outcome of a two-year amendment process that began in spring 2022. (Source - ACER Recommendation 03-2023 NC RfG DC (2023))

Status update (July 2026): the Commission has now published its draft implementing act. A draft Commission Delegated Regulation establishing a network code on requirements for grid connection of generators and repealing Regulation (EU) 2016/631 is out for public consultation, closing 25 August 2026. The Commission states the technical requirements are based on ACER’s recommendation, with lessons from the April 2025 Iberian blackout also incorporated. This resolves the comitology-status data gap previously noted below. (Source - EU Commission Draft Revised RfG and Annexes (2026))

In industry discussions, the amended regulation is called “NC RfG 2.0” or “CNC 2.0”. During comitology, ACER advises the Commission through Grid Connection European Stakeholder Committee (GC ESC) workstreams.

Application timeline (per the draft): power-generating modules generally — 2 years after entry into force (RfG (EU) 2016/631 continues to apply until then). V2G EV/EVSE — 3 years after entry into force for new vehicle types, 4 years for all new vehicles placed on the market.

Swedish regulatory response: Ei began its own revision of EIFS 2018:2 in 2025 and issued a remissförslag in February 2026 (coordination requirements between system operators, converting some national generally-applicable requirements into site-specific ones, clearer cross-references to RfG articles). Because the Commission’s draft covers much of the same ground, Ei has decided to hold off on the substantive EIFS 2018:2 changes rather than risk double regulatory change, and is urging Swedish market actors to comment directly on the Commission’s consultation instead. See Source - EIFS 2018-2 Nätanslutning av generatorer.

What NC RfG 2.0 changes

1. Energy storage explicitly included in scope (removes Art. 3.2(d) exclusion) The existing exclusion is proposed for deletion. BESS and other electricity storage systems would be subject to NC RfG requirements — the first EU-level mandatory technical connection requirements for grid-scale batteries. Requirements apply to both “input” (charging) and “off-take” (discharging) modes. This is the single most significant change for the Swedish market: it gives BESS the same legally binding technical obligations as other kraftparksmoduler, resolving the interpretive convention currently used.

2. Grid-forming capability — new obligation, mandatory outright for large Type B/C/D The mandate is two-tier, not a flat threshold. Type C and D PPMs are mandated directly (Arts. 31–32 cross-reference the grid-forming article unconditionally), as are Type B PPMs that are either connected at ≥110 kV or ≥10 MW connected below 110 kV to a feeder/substation transforming up to 110 kV or above (Art. 30(3)) — including in-scope BESS meeting those criteria. Smaller Type B PPMs and all Type A PPMs only become subject to grid-forming once the TSO has proposed, and the regulatory authority has approved, a national phase-in roadmap (Art. 29(1)–(2)) — there is no fixed date for these until that roadmap process completes. Grid-forming requires the inverter to act as a voltage source rather than a current-follower, enabling autonomous voltage and frequency stabilisation, going beyond the existing FSM (frekvenskänslighetsläge) obligation which only requires reactive frequency response. ENTSO-E published its Phase II technical report on grid-forming implementation in November 2025.

Grid-forming is directly relevant to the microgrid fault current challenge: the low fault current from grid-following inverters (≤2 p.u. vs ~6 p.u. from synchronous generators) is a consequence of not having grid-forming capability. Mandatory grid-forming for large new BESS would, over time, improve fault current contribution from threshold-size inverter-based assets.

3. RoCoF ride-through requirements for storage Storage must withstand rate-of-change-of-frequency events: ±4.0 Hz/s (0.25 s) / ±2.0 Hz/s (0.5 s) / ±1.5 Hz/s (1 s) / ±1.25 Hz/s (2 s).

4. V2G electric vehicles and EVSE in scope, with a dedicated certification framework V2G-capable EVs and EVSE that export power are brought within NC RfG as a new regulated category — “electricity storage module” (ESM), which explicitly includes “V2G electric vehicle and associated V2G electric vehicle supply equipment with bidirectional functionality” and is subject to the same requirements as other power-generating modules unless otherwise justified. V2G units below 1 MW are treated separately from other PPMs for type classification (not classified as type B/C/D on individual unit size).

The Commission’s draft (Annex III) sets out a certification framework built on a functional split: the V2G EV and the V2G EVSE (AC or DC) are certified individually, based on each component’s contribution to grid-code compliance. Conformity assessment uses test setups and acceptance criteria from EN 50549-10:2022, adapted for V2G. Certification is performed by bodies accredited under EN ISO/IEC 17065; for AC V2G EVs, compliance is normally demonstrated via the Whole Vehicle Type Approval (WVTA) framework, with a direct Annex-III certification route available before WVTA becomes effective for this purpose. Product-family rules let one certified representative product cover others within ±50% of rated power that share the same communication protocol and grid-code-relevant control algorithm — avoiding repeat testing for every model variant. See Vehicle-to-Grid for the broader V2G standards landscape this slots into (ISO 15118-20, OCPP 2.1, OpenADR).

What NC RfG 2.0 does NOT change

Type A threshold unchanged: ACER considered reducing the type A/B threshold from 1 MW (Nordic: 1.5 MW) but reverted to keeping it at 1 MW. The type A gaps — no LVRT, no fast fault current injection — are not addressed. Small DERs remain as they are.

Negative sequence injection: No harmonized mandate proposed. The Germany vs Sweden gap remains.

NC DC 2.0 — demand connection amendments

The Demand Connection Code (NC DC) is simultaneously amended to include: EVs and EVSE (smart charging, V2G), heat pumps, and power-to-gas/electrolysers. This provides the connection-side regulatory foundation that the Network Code on Demand Response builds on for market participation.

Regulatory gaps for microgrid applications

The Swedish/EU generator connection requirements were designed for conventional grid-connected operation. Microgrid and island operation exposes three specific gaps, identified in Energiforsk 2023:957 and endorsed by ACER in a 2022 policy paper: (Source - Energiforsk 2023-957 Felbortkoppling i Mikronät (2023))

1. Type A generators (<1.5 MW) — no fault ride-through or fast fault current requirements
EU 2016/631 and EIFS 2018:2 impose no fault ride-through (feltålighet) or fast fault current injection requirements on type A generators. Type B and above must demonstrate LVRT via simulation and testing; type A does not. In a Swedish microgrid, the majority of distributed generation (rooftop solar, small wind, small BESS) is type A — meaning the DSO cannot rely on any RFG-mandated protection behavior from these assets. Each protection design must assume worst-case inverter behavior (no fault current beyond thermal limit, no sustained injection).

2. Energy storage — explicitly excluded from RFG
EU 2016/631 Art. 3.2(d) explicitly exempts kraftlagringsenheter (energy storage units) from the regulation’s scope, except pumped hydro. This means grid-scale BESS have no RFG-based requirements for fault ride-through, fault current injection, or negative sequence contribution. Swedish practice classifies BESS operating in production mode as kraftparksmoduler and applies PPM requirements, but this is an interpretive convention, not an explicit mandate. For island protection, the BESS is the only fault current source — but no binding standard specifies its behavior during faults.

3. Negative sequence current injection — no Swedish requirement
During asymmetric faults, inverter-based generators produce minimal or zero negative sequence current unless the inverter control explicitly implements it. Many protection relay algorithms use negative sequence current to identify the faulted phase (phase selection). The absence of negative sequence current degrades relay performance for single-line-to-ground and double-line-to-ground faults. Germany mandates negative sequence injection for inverter-based generators (VDE-AR-N 4110, VDE-AR-N 4120). Sweden has no equivalent requirement. ACER’s 2022 policy paper recommended investigation of harmonized negative sequence requirements across the EU; this has not yet been implemented in RFG or EIFS.

ACER formal recommendation: ACER’s 2022 consultation paper on RFG revision (the policy paper that preceded the formal recommendation) identified: (1) harmonizing type A/B thresholds; (2) adding fault ride-through and LFSM-U requirements for type A; (3) investigating BESS-specific requirements for system stability; (4) adding negative sequence injection mandates. ACER then submitted its formal Recommendation 03-2023 to the European Commission in December 2023. Of the four areas raised: item (3) was substantially addressed (BESS explicitly included in NC RfG 2.0 scope); items (1), (2), and (4) were not included in the formal recommendation — type A threshold unchanged, no fault ride-through for type A, no negative sequence mandate. See NC RfG 2.0 — the Commission’s draft revised RfG (July 2026) for full detail.

Practical consequence for DSOs: Every Swedish microgrid with inverter-based generation must be designed and analyzed individually, without being able to rely on standardized protection behavior from type A generators or BESS. This increases per-project engineering cost and creates barriers to replicating successful microgrid designs.

Islanding detection requirements

Unintentional island operation creates specific obligations for generator owners and DSOs under both RFG and EN 50549. (Source - Energiforsk 2025-1128 Oavsiktlig ö-drift med Distribuerad Generering (2025))

RfG Articles 15–16 (Type C and D)

For type C generators (≥10 MW in Sweden) and type D generators (≥30 MW or ≥110 kV), Articles 15 and 16 of EU 2016/631 require:

• An islanding detection method agreed with the TSO/DSO
• The method cannot rely solely on switchgear position signals — active detection is required
• This applies to both synchronous generators and power park modules (inverter-based DER)

EN 50549 (Type A and B)

European standard EN 50549 covers type A and B generator connection to distribution networks. Requirements:

• Islanding detection protection function mandatory
• Must not conflict with fault ride-through (FRT) requirements

IEC 62116 — the applicable test standard in Sweden

IEC 62116 is the test procedure standard required for inverters in Sweden:

• Detection time limit: 2 seconds from islanding event
• Test setup: DC source simulating PV + RLC load tuned to resonance at 50 Hz + simulated grid connection that can be disconnected
• Inverter must detect disconnect and shut down within 2 seconds under multiple balanced and unbalanced test conditions
• Must recover normally when grid is restored

International standards comparison:

Standards are not interoperable. Compliance with IEEE 1547 does not imply IEC 62116 compliance. Equipment for the Swedish market must be tested per IEC 62116.

Non-Detection Zone (NDZ) and method selection

The NDZ (Non-Detection Zone) is the frequency/voltage envelope — 47.5–52 Hz, 0.9–1.1 Un per RfG — in which generators must not trip. If the isolated network achieves power balance within this envelope at the moment of disconnection, passive monitoring cannot detect islanding.

Inverter-based resources face a larger NDZ than synchronous generators: lower fault current (~1–1.5× rated for inverter-based sources vs 4–7 p.u. for synchronous machines, per Source - Energiforsk 2023-957 Felbortkoppling i Mikronät (2023)) means frequency/voltage perturbations are smaller, and grid-forming BESS actively suppresses deviations.

Practical guidance:

• ROCOF (df/dt) and ROCOU (dU/dt) are common triggers for activating active detection methods — should be configured conservatively to avoid false trips from large generator disconnections on the mainland grid
• For Type C/D generators, the islanding detection method must be agreed with the TSO/DSO; SCADA-based monitoring of breaker positions is a valid complement to local detection (not a substitute)
• Live testing at commissioning of new large generation installations is recommended (both inverter-based and synchronous)

See Unintentional Islanding and Anti-Islanding Protection for detailed treatment of detection methods (passive, active, hybrid, communication-based) and real events.

Data gaps

• EIFS 2018:2 revision — Ei has paused its own planned amendments pending the EU-level revision (see above); what consequential updates (if any) Ei makes once the Commission’s RfG text is finalised, and whether Swedish national threshold decisions (type B: 1.5 MW, type C: 10 MW) get revisited, remains open
• Outcome of the Commission’s public consultation (closes 25 Aug 2026) — whether Swedish market actors (via Energiföretagen or individually) submit comments, and whether the draft’s technical requirements change materially before adoption
• Whether any Swedish DSO has applied for an Ei derogation specifically for microgrid island operation requirements
• Negative sequence current injection requirement — whether ENTSO-E or Ei is considering adoption ahead of any EU-level mandate (not included in ACER Recommendation 03-2023)
• Updated Swedish implementing provisions for islanding detection under EIFS 2018:2 — does Ei or Svk publish specific guidance on active vs passive method acceptance criteria for type C/D generators?