Source - SO GL (Regulation 2017/1485)

Commission Regulation (EU) 2017/1485 of 2 August 2017, establishing a guideline on electricity transmission system operation. One of the EU’s eight electricity network codes/guidelines under Regulation (EC) No 714/2009. In force since 14 September 2017.

Overview

The SO GL establishes harmonized rules for how TSOs operate the interconnected European electricity system. It covers four main areas:

1. Operational security (Part II) — system states, remedial actions, voltage control, contingency analysis, protection
2. Operational planning (Part III) — grid models, security analysis, outage coordination, adequacy assessment
3. Load-frequency control and reserves (Part IV) — FCR, FRR, RR dimensioning, procurement, prequalification, TSO-DSO cooperation
4. Data exchange (Title 2 of Part II) — structural, scheduled, and real-time data between TSOs, DSOs, and significant grid users (SGUs)

Scope (Art. 2)

Applies to:

• TSOs
• DSOs (for data exchange, reserve delivery, coordination)
• Power generating modules type B, C, and D (as defined in Regulation 2016/631)
• Transmission-connected demand facilities
• Demand response providers — including third parties and aggregators
• Providers of redispatching of power generating modules or demand facilities by means of aggregation

The explicit inclusion of demand response providers and aggregators in the scope is significant — it establishes their obligations alongside traditional generators.

Key definitions (Art. 3)

Load-frequency control structure (Part IV)

Reserve hierarchy

The SO GL establishes the three-tier reserve hierarchy used across Europe:

1. FCR (Frequency Containment Reserve) — automatic, stabilizes frequency within seconds after a disturbance (Art. 142)
2. FRR (Frequency Restoration Reserve) — restores frequency to 50 Hz and releases FCR (Art. 143)
   • aFRR (automatic) — closed-loop controller, proportional-integral behavior (Art. 145(4))
   • mFRR (manual) — instruction-based activation (Art. 145(5))
3. RR (Replacement Reserve) — restores FRR, optional per LFC block (Art. 144)

LFC structure

• Synchronous area → one or more LFC blocks → one or more LFC areas → one or more monitoring areas
• Nordic synchronous area: Sweden, Finland, Norway, eastern Denmark — each TSO is typically its own LFC area within a single Nordic LFC block
• All TSOs must implement both aFRP and mFRP (Art. 145(1))

System states (Art. 18)

When reserves are insufficient, TSOs have the right to require changes in active power production or consumption of power generating modules and demand units (Art. 152(7), (8), (11)-(13), (16)) — a backstop authority that applies to all connected demand.

FCR provisions — Nordic flexibility implications

Dimensioning (Art. 153)

• Nordic reference incident: largest instantaneous change from a single generating module, demand facility, or HVDC interconnector (Art. 153(2)(b)(ii))
• Probabilistic dimensioning approach permitted for Nordic area, aiming at FCR insufficiency ≤ once in 20 years (Art. 153(2)(c))
• FCR obligation allocated by share of net generation + consumption (Art. 153(2)(d))

Limited energy reservoirs (Art. 156(8)-(11))

Critical for battery participation in FCR markets:

• FCR providing units with limited energy reservoirs (batteries, demand response) must sustain full activation continuously during alert state (Art. 156(9))
• Minimum activation period: 15–30 minutes, determined by cost-benefit analysis (Art. 156(10-11))
• Default is 15 minutes if no period has been determined, though each TSO may set it up to 30 minutes (Art. 156(9))
• Energy reservoir recovery must occur within 2 hours after alert state ends, for CE and Nordic areas (Art. 156(13)(b))

The cost-benefit analysis (Art. 156(11)) must consider:

• Experiences with emerging technologies in different LFC blocks
• Impact on total FCR cost
• System stability risks from prolonged/repeated frequency events
• Technological developments reducing costs for limited energy reservoirs

This provision directly shaped the Nordic FCR market design for batteries.

FCR technical requirements (Art. 154)

• FCR providing groups can include demand units with “demand response active power control” (Art. 154(8)(c))
• TSO may exclude groups based on geographical distribution (Art. 154(4))
• FCR providing units <1.5 MW may aggregate monitoring data (Art. 154(9))

Prequalification (Art. 155)

• Each TSO must develop and publish an FCR prequalification process
• 8-week application review + 3-month evaluation
• Re-assessment every 5 years or on equipment/requirement changes

FRR provisions (Art. 157-159)

Dimensioning (Art. 157)

• Based on historical LFC block imbalances over at least one full year
• Must cover ≥99% of positive and negative imbalances
• Ratio of aFRR to mFRR determined by TSOs
• Sharing between LFC blocks may reduce FRR by up to 30% of the dimensioning incident (Art. 157(2)(j)(i))

Technical requirements (Art. 158)

• aFRR activation delay ≤30 seconds
• Real-time monitoring required for all FRR providing units ≥1.5 MW within a group
• Ramping rate requirements set per LFC block

Prequalification (Art. 159)

• Same structure as FCR: 8-week review + 3-month evaluation
• Qualification valid for entire LFC block
• TSO may exclude groups based on geographical distribution of demand units (Art. 159(7))

TSO-DSO data exchange (Part II, Title 2)

DSO observability area (Art. 43)

Each TSO determines which parts of distribution systems are in its observability area — i.e., where distribution-level data is needed for accurate state estimation. This can include non-transmission-connected distribution systems if they significantly influence the transmission system (Art. 43(2)).

DSOs must provide:

• Structural data: substations, lines, transformers, SGUs, reactive compensation — updated every 6 months (Art. 43(3-4))
• Aggregated generating capacity of type A modules, annually (Art. 43(5))

Real-time DSO → TSO data (Art. 44)

DSOs must provide real-time:

• Substation topology, power flows, tap positions, voltages
• Aggregated generation per primary energy source
• Aggregated demand in the DSO area

Demand response data exchange (Art. 53)

Distribution-connected demand facilities participating in demand response must provide to both TSO and DSO:

• Structural min/max active power for DR, duration limits
• Forecast of unrestricted power available for DR
• Real-time active and reactive power
• Confirmation that actual DR values are estimated/applied

Third-party DR aggregators (Art. 53(2)) must provide the same data on behalf of all their distribution-connected demand facilities, in a specific geographical area defined by TSO and DSO. This is a direct precursor to the NC DR’s Service Provider framework.

TSO-DSO cooperation on reserves (Art. 182)

The most directly flexibility-relevant article for the DSO context:

1. Cooperation obligation: TSOs and DSOs shall cooperate to facilitate and enable reserve delivery from distribution systems (Art. 182(1))

2. Prequalification terms: Each TSO must develop terms with its reserve connecting DSOs and intermediate DSOs for the exchange of information in prequalification. Required information includes:

   • Voltage levels and connection points
   • Type of active power reserves
   • Maximum reserve capacity per connection point
   • Maximum rate of change of active power (Art. 182(2))

3. Timeline: Maximum 3 months for prequalification of distribution-connected reserves (Art. 182(3))

4. DSO right to limit or exclude: Each reserve connecting DSO and intermediate DSO may:

   • Set limits to or exclude delivery of reserves from its distribution system, based on technical reasons (e.g., geographical location) — during prequalification (Art. 182(4))
   • Set temporary limits before reserve activation, in cooperation with the TSO (Art. 182(5))

This DSO veto right on reserve activation is a key tension point that the Network Code on Demand Response seeks to formalize through observability areas and TSO-DSO coordination protocols.

Remedial actions and demand-side (Art. 20-23)

Categories (Art. 22)

Remedial actions include redispatching of transmission or distribution-connected system users (Art. 22(1)(e)) — explicitly covering demand-side resources at both grid levels.

TSO-DSO coordination (Art. 23(3-4))

• In normal/alert state: TSO must assess impact of remedial actions on transmission-connected SGUs and DSOs, coordinate with them, and select actions maintaining all parties’ secure operation (Art. 23(3))
• In emergency/blackout: coordination “to the extent possible”; impacted DSOs and SGUs must execute TSO instructions (Art. 23(4))

General principles (Art. 4)

Art. 4(2)(d) establishes that TSOs shall use market-based mechanisms as far as possible to ensure network security and stability — mirroring the market-first principle of the Clean Energy Package.

Relationship to other legislation

The SO GL sits in a hierarchy:

• Above: Clean Energy Package (Regulation 2019/943 and Directive 2019/944) — sets market design principles
• Alongside: EB GL (Regulation 2017/2195) — balancing market design; CACM (2015/1222) — capacity allocation; FCA (2016/1719) — forward capacity
• Below: Network Code on Demand Response (forthcoming) — will add detailed rules for demand-side participation that elaborate on SO GL’s reserve framework
• Connection codes: RfG (2016/631) — generator requirements; DCC (2016/1388) — demand connection requirements

The SO GL’s reserve providing unit/group definitions and prequalification framework are the foundation that the NC DR builds upon with its CU/SP/SPU/SPG structure.

Relevance to the wiki

The SO GL is the operational backbone connecting grid operation to flexibility:

• Defines the reserve products (FCR, FRR, RR) that Balancing Markets trade
• Establishes the prequalification framework for demand-side reserve participation
• Creates the TSO-DSO data exchange obligations that enable visibility into distributed resources
• Formalizes the reserve connecting DSO role that the NC DR extends
• Sets limited energy reservoir rules critical for Energy Storage participation
• Provides the remedial action framework (including demand-side redispatching) that connects to Congestion Management
• Its observability area concept is adopted and extended by the NC DR

Data gaps

• Nordic synchronous area operational agreement: specific FCR activation period chosen (15 vs 30 min)
• Swedish implementation of Art. 182 TSO-DSO cooperation: Svenska kraftnät’s agreements with DSOs
• Nordic aFRR/mFRR dimensioning parameters and current volumes
• How the SO GL prequalification framework maps to NC DR’s proposed prequalification in practice