Page type: primary-anchored (mirrors Grid Code Operating Codes, OC1--OC12)

Grid Code -- Operating Codes (OC)

The Operating Codes are the section of the Grid Code that governs the day-to-day operational procedures between NESO and Users of the National Electricity Transmission System. There are 12 numbered OCs, of which 10 are active (OC3 and OC4 are "Not Used").

Source file: grid-code.md Parent page: Grid Code

Overview of all Operating Codes

OC2 -- Operational Planning and Data Provision (deep dive)

OC2 is the operational planning workhorse of the Grid Code. It governs the multi-year outage co-ordination cycle and the daily availability and margin data obligations.

Scope (OC2.3)

OC2 applies to NESO and to: - Generators (Large Power Stations or directly-connected stations only) - Network Operators - Non-Embedded Customers - HVDC System Owners and DC Converter Station owners - Interconnector Owners - Restoration Contractors (party to a Local Joint Restoration Zone Plan with a CUSC Contract)

Outage co-ordination cycle (OC2.4.1)

The outage planning process runs on a rolling multi-year cycle:

Years 2--5 ahead (OC2.4.1.3.1--OC2.4.1.3.2): - By week 8: Network Operators notify proposed outages - By week 13: Generators notify proposed generator apparatus outages - By week 28: NESO provides Network Operators with proposed outage impacts - By week 30: Dispute resolution for proposed outages - By week 34: NESO issues draft NETS outage plan (Years 2--5)

Year 1 ahead (OC2.4.1.3.3): - By week 13: Generators and Non-Embedded Customers notify proposed Year 1 outages - By week 28: NESO notifies Network Operators of outage impacts - By week 32: Network Operators notify proposed Year 1 outages (detailed) - Weeks 32--34: NESO draws up revised NETS outage plan - By week 34: NESO notifies Users of NETS outage programme aspects affecting them - Between weeks 34--49: final NETS outage plan drawn up - By week 49: final plan completed; Year 1 becomes Year 0 by expiry

Year 0 / Programming Phase (OC2.4.1.3.4--OC2.4.1.3.5): - Users may request outage changes at any time; NESO determines feasibility within 14 days - Load transfer capability data: >=12MW (E&W) or >=10MW (Scotland) - Weekly cycle: - Thursday by 1600: preliminary 8-week-ahead, provisional next-week, final day-ahead programmes - Friday by 1000: Users confirm acceptance of outage requirements - Friday by 1600: finalise up to 7th week ahead; finalise next week; finalise weekend - Mon-Thu by 1600: final day-ahead programme - Nuclear Large Power Stations: NESO must endeavour to give maximum notice of outages

Availability data provision (OC2.4.1.2)

Generation Planning Parameters (OC2.4.2)

Generators must submit Generation Planning Parameters and Generator Performance Charts: - At Statement of Readiness (initial connection) - Annually in calendar week 24

These include Genset data, CCGT Module data, Power Park Module data, Cascade Hydro data. They must meet the requirements of CC.6.3.2 or ECC.6.3.2 and reasonably reflect true operating characteristics.

Planning matrices must be submitted: CCGT Module Planning Matrix (Appendix 3), Power Park Module Planning Matrix (Appendix 4), Synchronous Power Generating Module Planning Matrix (Appendix 5).

Negative Reserve Active Power Margins (OC2.4.3)

NESO must calculate and publish daily (by 1600, up to hourly): - System NRAPM: 2--14 days ahead (daily) and 2--52 weeks ahead (weekly) - Localised NRAPM: England/Scotland boundary constraint, same time horizons

When NRAPM is low, NESO contacts generators to discuss outage adjustments. Special protections apply to nuclear plant: - NESO will not de-synchronise Existing Magnox or AGR plant unless NRAPM is critically low and interconnection flows are at zero or exporting (OC2.4.3(d)) - AGR plant may be de-synchronised if gensets have failed to offer flexibility and the request is within the AGR Plant Flexibility Limit (OC2.4.3(d)(i))

OC1 -- Demand Forecasts

NESO's obligations to forecast national electricity demand at various time horizons. Feeds into the OC2 outage planning process.

OC5 -- Testing and Monitoring

Governs commissioning tests for new/modified plant, periodic operational tests, and NESO's monitoring rights. Links to the Compliance Processes (CP) section.

OC6 -- Demand Control

Defines the methods of demand reduction available to NESO in emergencies: - Customer voltage reduction (by Network Operators) - Customer demand disconnection (by Network Operators) - Demand reduction instructed by NESO - Automatic low frequency demand disconnection - Emergency manual demand disconnection

OC7 -- Operational Liaison

Governs the reporting of scheduled and planned operational actions, unplanned occurrences (faults), and Events between Users and NESO.

OC8 -- Safety Co-ordination

Governs the procedures for safe isolation and earthing of plant and apparatus. Requires Safety Rules and Local Safety Instructions at each Connection Site. Cross-references Site Responsibility Schedules (CC.7/Appendix 1).

OC9 -- Contingency Planning

Covers system restoration following a Total Shutdown or Partial Shutdown. References the Electricity System Restoration Standard. Defines Black Start procedures and Restoration Plans.

OC10 -- Event Information Supply

Requires written reports on significant Events (faults, system disturbances) to be supplied to NESO within specified timescales.

OC11 -- Numbering and Nomenclature

Standard naming conventions for HV apparatus at certain transmission sites. Ensures consistent identification across operators.

OC12 -- System Tests

Gives NESO the power to conduct system-wide tests, subject to appropriate notice and safety procedures.

Character positions

(None yet captured.)

Last updated: 2026-04-05