Why Do Solar Projects Get Rejected at TNB Interconnection Review?
Published by Quinn Lai | By InverPower Technical Team
Published 14 August 2026 · Last updated 14 August 2026
DIRECT ANSWER
Most rejections are not engineering failures — they are gaps between what a submission says and what the interconnection guidelines require. The recurring ones are protection settings declared loosely or not at all, single-line diagrams missing required detail, and relays or equipment outside TNB's accepted lists. All three are checkable before you submit.
A rejection at interconnection review is expensive in a way that is easy to underestimate. The cost is rarely the rework — it is where the project lands afterwards, with a roof finished, equipment on site and a date that has moved. Almost every recurring rejection reason is something the submitting team could have checked against a published document first.
It is worth being clear about what the review is for. TNB is assessing whether a generator can sit on a shared distribution network without degrading it for everyone else connected to the same feeder, and the requirements exist because the failure modes are real: unintended islanding endangers linesmen, poor power quality propagates, and a generator that will not disconnect on a fault complicates every protection scheme around it. The checks are a grid-safety function. Reading them as an obstacle is what produces submissions that get returned.
Where does a solar application actually get assessed?
Under TNB's published process, the developer prepares documents, completes the EG1 or EG1PV form and submits to the renewable energy department. TNB then receives and checks the submission for completeness — an incomplete pack goes back to the applicant at this stage, before any engineering judgement has been made on it. Only a complete submission is registered for the Power Systems Study, at which point the clock starts and a technical feasibility study runs before the study committee either issues an approval letter or a non-approval letter.
That sequence matters because there are two distinct ways to fail. One is engineering: the study finds the connection cannot be accommodated as proposed. The other is administrative: the pack was never complete enough to be assessed. The second is entirely within your control, and it is the larger of the two.
Reason one — are the protection settings actually declared?
The interconnection guidebook puts the protection scheme squarely on the developer: the scheme is the developer's responsibility, and the developer is required to declare the scheme and its settings to TNB. A submission that names an inverter model and leaves the protection behaviour implied has not met that requirement, and no amount of technically-correct hardware fixes it after the fact.
The settings themselves are not a matter of preference. For LV interconnection, inverters must comply with IEC 61727, which fixes maximum trip times against voltage at the point of common coupling:
| Voltage at PCC | Maximum trip time | What it means in practice |
|---|---|---|
| V < 50% | 0.10 s | Deep sag — near-immediate disconnection |
| 50% ≤ V < 85% | 2.00 s | Sustained undervoltage, ride through then trip |
| 85% ≤ V ≤ 110% | Continuous operation | The normal operating band |
| 110% < V < 135% | 2.00 s | Sustained overvoltage, ride through then trip |
| 135% ≤ V | 0.05 s | Severe overvoltage — fastest disconnection |
Frequency is bounded the same way. TNB operates a nominal 50 Hz system with a ±1 Hz band, and the PV system is expected to run in synchronism with it. Re-synchronising after a trip has its own thresholds: frequency difference under 0.2 Hz, voltage magnitude difference under 10%, and voltage angle difference under 10 degrees, with re-synchronisation proceeding only once TNB has given approval and the system is normalised.
Anti-islanding is the requirement that carries the least tolerance, because it is the one that protects people rather than plant. A PV plant is not permitted to energise during a loss of TNB supply, and the developer has to prove the anti-islanding capability rather than assert it. At commissioning the site test is witnessed by TNB personnel, performed by qualified parties, using test equipment with a valid calibration certificate — an uncalibrated instrument invalidates the result no matter what the result was.
Reason two — what does the single-line diagram have to carry?
Single-line diagram approval is a named step in TNB's equipment approval process, sitting alongside shop drawing approval, factory acceptance testing, site acceptance testing and commissioning testing. It is a gate in its own right, not a supporting attachment, and a drawing that does not show the interconnection scheme, the protection and metering arrangement and the interlocking as they will actually be built cannot pass it.
The interlocking logic is worth drawing rather than describing. The guidebook sets the required behaviour between developer-side and TNB-side devices explicitly — a trip on one trips the other, and closing permissives depend on the other device's position and the earth switch. A reviewer confirms that by looking at the diagram, so the diagram has to show it.
Reason three — is the equipment on the accepted list?
This is the rejection reason that hurts most, because it usually surfaces after the equipment has been bought. All protection relays must undergo and pass acceptance testing and be listed in the latest TNB Accepted Relays List. Remote terminal units carry a parallel requirement — every RTU must be listed in TNB's approved list — and equipment being handed over to TNB has to meet TNB's current technical specification.
Acceptance is a property of a specific make and version, and lists get revised — a relay that cleared a review two years ago is not automatically the same product today. Checking at procurement rather than at submission removes the whole category of problem.
Inverters sit slightly differently. Type-tested inverters that meet the stated harmonic requirements are deemed to comply without further testing, which is a genuine shortcut — but only if you hold the type-test evidence for the model you are installing and can produce it. This is where the compliance chain behind an inverter matters more than the brand on the enclosure, a point we go into properly in our post on SEDA-registered inverters.
What else gets checked that teams forget?
Beyond the three big ones, a set of quieter limits catches submissions that are otherwise sound:
- Power factor — LV systems must hold a leading or lagging power factor better than 0.9 when output exceeds 10% of rated inverter output; MV systems must hold better than 0.9. The plant power factor setting is fixed during the power system study.
- DC injection — the system must not inject DC current greater than 1% of rated inverter output current into the utility interface under any operating condition.
- Harmonics — total harmonic current distortion must stay below 5% at rated inverter output measured at the cable connected to the PCC, with individual odd harmonics limited below that.
- Steady-state voltage — LV systems are expected to operate within +10% and −6% of nominal at the point of common coupling, on both 400 V and 230 V.
- Penetration limits — allowable capacity depends on the connection point. Connection at 11 kV via PE or SSU, for example, is capped at 50% of the cable capacity to the source and a maximum of 2 MW.
- Inverter as UPS — using the PV inverter as a UPS to the grid is prohibited outright for any TNB interconnection.
Penetration limits are the ones that force a redesign rather than a resubmission, because they belong to the connection point rather than the equipment. Establishing them early changes what you propose; discovering them late changes what you have already built.
What should you check before you submit?
Run this before the pack leaves your office, not after it comes back:
- The protection scheme and every setting is written down and submitted, not implied by the equipment selection.
- Every relay and RTU model has been checked against the current TNB accepted lists, at the version you are actually buying.
- The single-line diagram shows the protection, metering and interlocking arrangement as built, and matches the shop drawings.
- Type-test evidence for the inverter is in the pack, covering the exact model on the bill of materials.
- Power factor, DC injection and harmonic performance are demonstrable from the datasheet rather than assumed.
- The connection point and its penetration limit were confirmed before the array capacity was fixed.
- The application form is the current EG1 or EG1PV version and every required attachment is present — completeness is checked before engineering is.
How does InverPower support the compliance pack?
We supply the components and the paperwork that travels with them — datasheets, type-test reports and certification evidence for the inverters, cable and protection hardware we distribute, so your submission is assembled from documents rather than assurances. The design, the settings and the submission stay with the EPCC. What we can do is get that evidence into your hands earlier than the programme usually assumes it will be needed.
Frequently Asked Questions
What is the most common reason a solar interconnection submission is returned?
Incompleteness. TNB checks a submission for completeness before it is registered for the Power Systems Study, so a pack missing required documents is returned before any engineering assessment happens. Protection settings and single-line diagram detail are the usual gaps.
Does TNB publish a list of accepted protection relays?
The guidebook requires all protection relays to pass acceptance testing and be listed in the latest TNB Accepted Relays List, and requires RTUs to be on TNB's approved list. Check the current version with TNB at procurement stage, because listings are revised over time.
What trip settings must a grid-connected inverter meet in Malaysia?
For LV interconnection, inverters must comply with IEC 61727: continuous operation between 85% and 110% of nominal voltage, 2.00 s maximum trip time in the bands either side, 0.10 s below 50% and 0.05 s at or above 135%. TNB operates 50 Hz with a ±1 Hz band.
Can a PV system keep running when TNB supply is lost?
No. A PV plant is not permitted to energise during an outage of the TNB grid, for the safety of anyone working on the network. The developer must prove anti-islanding capability, and the site test is witnessed by TNB using calibrated test equipment.
Sources
- TNB — Technical Guidebook on Grid-interconnection of Photovoltaic Power Generation System to LV and MV Networks — https://policy.asiapacificenergy.org/sites/default/files/TNB%20Technical%20Guidebook%20on%20Grid-interconnection%20of%20Photovoltaic%20Power%20Generation.pdf
- TNB — Technical Guideline for Interconnection of Distributed Generator to Distribution System (2018) — https://www.mytnb.com.my/-/media/Project/TNB/myTNBportal/Documents/Guides-and-Booklets/Technical-Guideline-for-Interconnection-of-Distributed-Generator-to-Distribution-System-2018.pdf
- TNB — Renewable Energy Application Handbook, Revision 2020 — https://www.mytnb.com.my/-/media/Project/TNB/myTNBportal/Documents/Guides-and-Booklets/TNB_RENEWABLE_ENERGY_APPLICATION_HANDBOOK_REVISION_2020.pdf
- SEDA Malaysia — TNB PV Interconnection guideline listing — https://www.seda.gov.my/download/seda-guidelines/tnb-pv-interconnection/
About InverPower
InverPower is Malaysia's A–Z solar component distributor — Sungrow Preferred Distributor and Sunkean Sole Distributor — supplying EPCCs, installers, and government projects nationwide.
Explore the InverPower resource hub at inverpower.com.my
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- TNB Grid Code for Solar: What Must EPCCs Do Before Energization?
- Which Solar Inverters Are SEDA-Registered in Malaysia (2026)?
- Where Do EPCCs Source Solar PV Components in Malaysia?
