Engineering Recommendation G99 sets the technical and process requirements for generation that runs in parallel with a licensed distribution network in Great Britain. This guide follows G99 Issue 2, published on 10 March 2025. Issue 2 applied in full from that date, except for new storage requirements that came into force on 1 March 2026. Clause numbers below refer to Issue 2. Northern Ireland has its own Distribution Code and uses G99/NI.
The guide is for engineers who design, commission or monitor commercial and industrial PV, battery and CHP sites. It covers classification, protection, storage and export limitation in detail, and the Type C and D recording requirements in outline.
G98 or G99
G98 covers Fully Type Tested micro-generators up to and including 16 A per phase. At 230 V that is 3.68 kW on one phase, or 11.04 kW across three. G99 covers everything else: larger units, several units whose total exceeds 16 A per phase, units that are not type tested, and units designed to run in island mode.
Storage is a power-generating module when it can export. Vehicle-to-grid chargers are too. Storage commissioned on or after 1 September 2022 must comply with G99 in full. Older storage has a short list of exclusions in Annex A.4.2.
Existing generation counts. So does plant that you substantially modify, which Annex A.6 defines with examples. Plant connected before 27 April 2019 stays under G59 until it is substantially modified.
Types A to D
G99 assigns a type to each power-generating module, not to the site.
| Type | Registered Capacity | Connection point |
|---|---|---|
| A | 0.8 kW to below 1 MW | Below 110 kV |
| B | 1 MW to below 10 MW | Below 110 kV |
| C | 10 MW to below 50 MW | Below 110 kV |
| D | 50 MW or more, or any capacity at 110 kV and above | Any |
The grouping rule decides the type. Each synchronous machine that can run on its own is a separate module. All inverter-connected and asynchronous units behind one connection point form a single Power Park Module, and their ratings add. G99 Figure 4.2 shows three 400 kW gas engines as three Type A modules in a 1.2 MW facility. Figure 4.3 shows one 400 kW inverter and two 400 kW asynchronous units as one 1.2 MW Type B module.
The Registered Capacity of a Power Park Module is the lower of the inverter rating and the energy-source rating. A 700 kWp array on 600 kW of inverters has a Registered Capacity of 600 kW.
Some thresholds sit outside G99. A facility reaches the Grid Code "large" threshold at 10 MW in the north of Scotland, 30 MW in the south of Scotland and 100 MW in England and Wales. In England and Wales, a facility of 50 MW or more is an Embedded Medium Power Station. Any module in the Balancing Mechanism must also meet the relevant parts of the Grid Code.
Worked classification examples
A house with PV and a battery. A 3.68 kW PV inverter and a separate 3.68 kW battery inverter are each Fully Type Tested to G98. Together they are 32 A on one phase, and G99 Figure 4.7 treats them as one 7.36 kW Power Park Module. The pair qualifies as a Small Generation Installation: each unit is no more than 32 A and the aggregate is no more than 60 A. Procedure SGI-3 in clause 6.2.2.4 applies without a G100 scheme, because the aggregate is no more than 32 A. The installer submits Form A1-2. Within 10 working days, the DNO says whether it needs site-specific studies. Commissioning must fall between 10 working days and 3 months after the application. Form A3-2 goes to the DNO within 28 days of commissioning.
A factory adding a battery. A food plant has 600 kW of PV inverters and plans a 500 kW, 1 MWh battery on its own 500 kW inverter. The battery joins the PV in one Power Park Module of 1.1 MW, which is Type B. The site moves from Type A paperwork to a Power Generating Module Document with simulation studies for frequency capability, fault ride-through, fast fault current and reactive capability (clause 17.2.3).
If the battery shares hybrid inverters with the PV, it adds nothing to the Registered Capacity, because the inverters set it (G99 Figure 4.6). The module stays at 600 kW and Type A. The cost is that PV and battery then share 600 kW of export.
A G100 export limit caps what crosses the connection point. It does not change the inverter ratings the module is built from. Agree the declared Registered Capacity with the DNO before you design around a lower type.
Application and commissioning by type
| Type | Application | Compliance evidence | Commissioning and operation |
|---|---|---|---|
| A | Form A1-1 below 50 kW three-phase or 17 kW single-phase; otherwise the DNO's Standard Application Form. Form A1-2 for SGI-2 and SGI-3 | Type test reports on the ENA Type Test Register: Form A2-1 or A2-2 for synchronous units, A2-3 for inverters. Form A2-4 for site tests where needed | Installation Document Form A3-1 (A3-2 or A3-3 for an SGI) within 28 days, or at commissioning if witnessed |
| B | Standard Application Form with Distribution Data Registration Code Schedule 5 data | Power Generating Module Document, Form B2-1, at least 28 days before first synchronisation, with Annex B.4 simulation studies. Site tests on Form B2-2 | Form B3, normally within 28 days of first synchronisation. Final Operational Notification before permanent operation |
| C | As Type B | Form C2-1 with Annex C.7 studies. Site tests on Form C2-2 | Form C3. Final Operational Notification. Annex C.6 recorder |
| D | As Type B | As Type C | Energisation, Interim and Final Operational Notifications (Section 19). Annex C.6 recorder |
Give the DNO at least 28 days' notice of Type B and Type C compliance tests. G99 sets DNO response times only for the SGI procedures. Other applications follow the DNO's standard process.
Interface protection settings
Table 10.1 sets the interface protection for long-term parallel operation. LV settings use 230 V phase-to-neutral. HV settings use the phase-to-phase nominal voltage of the connection point.
| Function | Type A to C, LV | Type A to C, HV | Time delay |
|---|---|---|---|
| Under-voltage | −20 % (184 V) | −20 % | 2.5 s |
| Over-voltage stage 1 | +14 % (262.2 V) | +10 % | 1.0 s |
| Over-voltage stage 2 | +19 % (273.7 V) | +13 % | 0.5 s |
| Under-frequency stage 1 | 47.5 Hz | 47.5 Hz | 20 s |
| Under-frequency stage 2 | 47.0 Hz | 47.0 Hz | 0.5 s |
| Over-frequency | 52.0 Hz | 52.0 Hz | 0.5 s |
| Loss of mains (RoCoF) | 1 Hz/s | 1 Hz/s | 0.5 s |
Type D modules, and facilities above 50 MW, use the HV voltage and frequency settings without the second over-voltage stage, and intertripping in place of RoCoF. The under-voltage delay may need to be shorter than 2.5 s where DNO auto-reclose times are below 3 s.
The RoCoF relay must see the rate above 1 Hz/s continuously for 500 ms before it trips. Do not get that delay by setting the number of cycles the relay averages over. At a high rate of change, that relay trips in less than 500 ms. Vector shift is not an acceptable loss-of-mains method (clause 10.4.11), a change made by Distribution Code modification DC0079 in 2018.
The delays are relay settings. Breaker opening adds about 100 ms. Type tested interface protection must measure voltage to ±1.5 % and frequency to ±0.2 %. Changes to agreed settings need the DNO's written agreement and go into the Connection Agreement (clause 10.6.10).
Frequency and power requirements
Every module must stay connected for at least 20 s between 47 Hz and 47.5 Hz, and for at least 90 minutes between 47.5 Hz and 49 Hz. It must run continuously between 49 Hz and 51 Hz. It must stay connected for 90 minutes between 51 Hz and 51.5 Hz, and for 15 minutes between 51.5 Hz and 52 Hz. It must also ride through a rate of change of up to 1 Hz/s measured over 500 ms.
Above 50.4 Hz, a module reduces output with a 10 % droop, which is 2 % of output per 0.1 Hz (LFSM-O). For excursions up to 50.9 Hz, at least half of the reduction must arrive within 10 s. An initial delay above 2 s needs technical justification to the DNO.
At Registered Capacity, a Type A module must operate between 0.95 lagging and 0.95 leading power factor unless the DNO agrees otherwise. It also needs a logic interface: when the DNO opens the contact, active power falls to zero within 5 s (clause 11.1.3).
Issue 2 added import-mode rules for storage first connected on or after 1 March 2026 (clause 11.2.3.3 for Type A). A battery that is charging must reduce its import as frequency falls below 49.5 Hz, with a droop between 0.6 % and 1.2 %. As much of that reduction as possible must happen within 10 s. If the battery cannot move from import to export within 20 s of the frequency reaching 49.2 Hz, it cuts import to zero. If it is still importing at 48.9 Hz, it trips.
Export limitation under G100
A G100 customer limitation scheme (CLS) holds export below the Maximum Export Limit (MEL) or import below the Maximum Import Limit agreed with the DNO. G100 Issue 2 describes its behaviour in operating states.
In state 1, the scheme keeps the connection point inside the limit. State 2 is an excursion above it, for example when a large load trips. The scheme must bring the current back inside the limit within 1 minute, or 3 minutes for slow plant such as gas engines where the DNO is notified. State 3 is the failed state. The scheme must enter state 3 within 5 s of any of these events:
- an internal failure;
- a communication failure, including an open CT secondary at the connection point;
- one excursion longer than 1 minute;
- more than three excursions of 10 s to 1 minute in 24 hours;
- two excursions longer than 10 s within 10 minutes of each other.
In state 3, the controlled devices go to a level that cannot breach the limit, usually off, within 10 s. The counters must survive a power loss. Wireless links may drop out for up to 5 s before this counts as a communication failure.
At an LV connection point, the scheme also goes to state 3 at 112 % voltage for 60 s, 114 % for 1 s, 80 % for 2.5 s and 87 % for 60 s. At HV, the first two limits are 108 % and 110 %. G100 advises a state 1 setpoint below the MEL if the site often touches the limit. A setpoint on the MEL invites repeated excursions and a lockout.
What G99 requires you to record
For witnessed compliance tests, clause 15.9 sets the resolution of the signals the generator gives the DNO, unless the DNO agrees otherwise:
| Test | Signal resolution |
|---|---|
| Reactive range | 1 Hz |
| Frequency control | 10 Hz |
| Voltage control | 100 Hz |
| Fast fault current on Power Park Modules | 1 kHz |
| Other Power Park Module tests | 100 Hz |
A facility with any Type C or D module needs a recorder at the connection point that meets Annex C.6. It records three-phase voltage and current with sequence components, active and reactive power, frequency, and protection and plant status from digital inputs. The DNO agrees the exact scope in the Connection Agreement, including whether power-quality monitoring is needed.
Dynamic monitoring needs RMS voltage to 0.1 %, active power to 0.5 %, reactive power to 1.0 % and frequency to 0.005 % (2.5 mHz at 50 Hz). Power-quality and fault records must meet BS EN 61000-4-30 Class A. Every value carries a time tag with 1 µs resolution, synchronised to UTC by GPS or an equivalent. Triggers must catch disturbances shorter than 10 ms. A 2 % active-power oscillation at up to 5 Hz, measured over 1.2 s, must start a recording. The CTs are Class 0.2/5P10 dual class.
Where EpiSensor monitoring fits
EpiSensor hardware does not meet Annex C.6, and it is not interface protection. It does not provide G99 approval, certify an inverter or replace the DNO's network study. The ZEM-65 measures to Class 0.5S (IEC 62053-22), reports frequency to ±0.01 Hz and timestamps at 1 s resolution, with its clock synchronised by NTP through the Gateway. The ZDR-21 and ZDR-22 add GPS time, frequency sampling at 100 ms or faster and 20 ms event recording. These specifications suit operational measurement that sits alongside the compliance equipment.
That measurement answers four questions the compliance forms do not.
Is the export limit working? A ZEM electricity monitor on the incomer logs export against the MEL through its own CTs, independent of the CLS. An excursion that the ZEM log shows and the CLS does not record points to a CLS CT or wiring fault. A site whose export sits on the MEL for long periods is at risk of the three-excursion lockout. Lower the state 1 setpoint.
Why does the inverter trip on over-voltage? Log phase voltage at the connection point and at the inverter board. The difference is the voltage rise in the site cable. G99 clause 7.7.4 notes that the 262.2 V stage 1 setting is only 4 % above the statutory maximum of 253 V, so a long or undersized cable can push the inverter terminals past it.
Did the battery respond to low frequency? A ZDR on the battery feeder records frequency and power with GPS time. After a frequency event, check that import started to fall below 49.5 Hz and that most of the reduction arrived within 10 s. See dynamic frequency response for the balancing-service side.
Why did export go to zero? A ZDI digital input on a spare contact of the relay that drives the DNO logic interface records when the DNO opened it. Edge reads inverter and protection-relay status over Modbus where the device publishes it. Together they separate a DNO instruction, a protection trip and a G100 state 3.
For the measurement points on a PV site, use the solar PV monitoring guide. For CT sizing and phase checks, see high-accuracy electricity metering.
Common failures
- Wrong grid profile. An inverter set to a non-GB profile trips at different values from the ones in the accepted forms. Read the settings back from the inverter at commissioning and compare them with Table 10.1 and the type test report.
- Settings change after a firmware update. A replacement inverter or a firmware update can change protection settings. Type tested parameters must be locked by password, PIN or a sealable switch (clause 16.3.4). Check them again after any service visit.
- Voltage optimiser on the wrong side. A voltage management unit between the connection point and the generation is not acceptable (clause 7.7.3), because the protection can see normal voltage while the connection point is outside the limits.
- Export CT wrong way round or in the wrong place. A reversed G100 CT reads export as import, so the scheme lets the site export at full output. A CT on the PV feeder instead of the incomer limits generation, not export, and curtails the site for no reason. Prove the CT position and direction with a known export before handover.
- Low-frequency import on new storage. A battery connected after 1 March 2026 with firmware that ignores the import-mode rules keeps charging at 49.4 Hz. Ask for type test evidence that covers clause 11.2.3.3, not only the export-mode tests.
Before applying or commissioning
- Identify the DNO and the connection voltage.
- List every generating unit, storage device and existing source behind the connection point, with inverter and source ratings.
- Group the units into modules, then assign a type to each module.
- Check the type test register entries for the exact model, firmware and settings.
- Agree interface protection settings, any G100 limits and the logic interface with the DNO.
- List every form, study, witness test and notification the type requires.
- Agree the Annex C.6 recording scope for a Type C or D module.
- Record the as-commissioned settings, and check them after every firmware change.