A solar system that produces power is easy. A solar system the distribution company will actually connect is harder. The gap between the two is filled by a net metering study in Pakistan — the engineering assessment that proves an exported-generation connection will not push voltage out of limits, blind protection, or feed a fault the utility cannot see.
Applicants often treat the study as a paperwork hurdle at the end of the process. That is the wrong order. The technical assessment determines whether the inverter rating you have quoted, the transformer you are connected to, and the point where you export can coexist with the grid — and getting it wrong means a rejected application, an oversized system stranded behind an undersized connection, or an approval that comes with conditions nobody priced.
This guide sets out what the study covers, why each part exists, and how the 2026 regulatory shift from net metering to net billing changes the commercial case without changing the engineering.
What the study is actually verifying
A distribution feeder was designed for power to flow one way: from the grid station down to the consumer. Connect distributed generation and, at times of high output and low local demand, power flows the other way — back up the feeder. That reversal is what every part of a net metering study is checking the network can tolerate.
The core questions are consistent regardless of system size:
- Will export raise voltage at the point of connection above the permitted band?
- Can the utility’s protection still detect and clear a fault with generation feeding it?
- Will the inverter disconnect reliably if the grid goes away, rather than energising a supposedly dead network?
- Is the connecting transformer and cable rated for reverse power flow at full export?
- Does the inverter’s harmonic output stay within limits at the point of common coupling?
Each of these maps to a specific piece of analysis. Skipping any one is where connection approvals stall.
Voltage rise: the limit most systems hit first
For rooftop and small commercial systems, voltage rise is usually the binding constraint — more often than thermal capacity. When a system exports, it lifts the voltage at its connection point above the feeder voltage. On a long or lightly loaded feeder, that rise can push the connection point past the statutory upper limit even when the conductor is nowhere near its current rating.
The study calculates the voltage rise from the export current and the impedance between the connection point and the grid station. The further out on the feeder, and the weaker the network, the larger the rise for a given export. This is why two identical systems can receive different answers: one sits close to the transformer, the other at the end of a rural feeder where the same kilowatts produce twice the voltage excursion.
Where the rise is marginal, mitigation is available before the system must be downsized — inverter power-factor control absorbing reactive power, an export limit, or a tap adjustment on the distribution transformer. A proper load flow assessment quantifies the rise across the daily generation and load profile rather than at a single snapshot, which is what separates a defensible study from an optimistic one.
Protection and anti-islanding
The most safety-critical part of the assessment is islanding. If the utility supply is lost — a fault upstream, a planned outage — the inverter must stop energising the network within the time the grid code allows. An inverter that keeps feeding a de-energised section creates an unearthed, uncontrolled island that endangers utility staff working on what they believe is a dead line, and that can reconnect out of phase.
Modern grid-tied inverters include anti-islanding protection, typically combining over/under voltage and over/under frequency detection with an active method. The study confirms the inverter carries the required certification and that its trip settings coordinate with the utility’s own protection — the generation must clear before the upstream device recloses.
For larger connections, the study extends to interface protection: reverse power, rate-of-change-of-frequency, and voltage-vector-shift functions, and a check that the addition of generation does not desensitise the DISCO’s existing overcurrent protection. On the transformer and feeder side, a short circuit analysis confirms the inverter’s fault contribution — modest for inverter-based resources, but not zero — does not exceed the interrupting rating of nearby switchgear.
Thermal capacity and the transformer
Reverse power flow loads the distribution transformer and the connecting cable in the direction they were not sized for. For a single small rooftop system this is rarely a problem. The concern is cumulative: where many systems sit on one transformer, their combined export at midday can approach or exceed the transformer rating.
The study checks the connection against the transformer’s capacity and against the aggregate distributed generation already connected to the same asset. This is precisely why utilities increasingly assess the feeder as a whole rather than each applicant in isolation — the tenth system on a transformer faces constraints the first did not.
Harmonics and power quality
Inverters are switching devices, and they inject current harmonics into the network. Individually small systems rarely trouble anyone; a cluster of inverters, or a single large plant, can push distortion at the point of common coupling toward the compliance limit.
The reference is IEEE 519, which sets both voltage distortion limits at the point of common coupling and current distortion limits scaled to the short circuit strength of the connection. A weaker connection — a lower short circuit ratio — tolerates less harmonic current before voltage distortion breaches the limit. A harmonic assessment confirms the inverter’s certified output, combined with existing background distortion, stays within the limit. Where a site already has non-linear load, this step matters more, and a dedicated harmonic analysis is worth commissioning rather than assuming compliance from the inverter datasheet.
The 2026 shift: net metering to net billing
The commercial ground moved in 2026. In February, NEPRA replaced the 2015 net metering framework with a net billing model under new prosumer regulations. Under the old arrangement, exported units were credited at close to the retail tariff. Under net billing, surplus energy is compensated at a rate linked to the national average power purchase price — materially lower than the retail rate it offsets. Consumers with valid net metering agreements dated before the changeover were addressed through a separate grandfathering provision.
The regulatory position has continued to attract debate and amendment, so any applicant should confirm the current rate mechanism and contract term with their DISCO at the time of application rather than relying on a figure quoted months earlier.
The engineering point is that none of this changes the study. Whether you are credited under net metering or net billing, the connection must still pass the same voltage, protection, anti-islanding, thermal and harmonic checks. What changes is the economics: with a lower export credit, the optimal system is sized closer to on-site consumption and away from large midday export. That sizing decision should be informed by the same load flow and connection assessment, so the study now carries commercial weight as well as regulatory — it tells you not just whether you can export, but how much export is worth engineering for.
FAQ
Is a study required for a small rooftop net metering system?
The DISCO requires a technical assessment for the connection regardless of size. For very small single-phase systems it may be a standardised check; for three-phase and commercial systems it is a full interconnection study covering voltage rise, protection and anti-islanding. The threshold and depth depend on system size and the connecting voltage level.
What most often causes a net metering application to be rejected or de-rated?
Voltage rise at the point of connection and insufficient transformer or feeder capacity — particularly on long rural feeders or transformers already carrying other distributed generation. Both are identifiable before installation through a connection study, which is why doing the assessment first avoids a stranded system.
Does the move to net billing mean solar no longer makes sense in Pakistan?
No. It changes the optimal design. With export compensated below the retail tariff, value shifts toward self-consumption, which favours sizing to daytime load and, in some cases, adding storage. The engineering assessment is the same; the economic sizing conclusion changes.
What standards govern the harmonic and power quality side of the connection?
IEEE 519 is the usual reference for harmonic voltage and current distortion at the point of common coupling. Inverters carrying recognised grid-connection certification are designed to meet it, but compliance still depends on the strength of the specific connection and any existing distortion at the site.
How long does a net metering connection study take?
For a straightforward small system, days. For larger commercial and industrial connections requiring load flow, protection coordination and harmonic assessment, typically a few weeks depending on how quickly the DISCO provides feeder and fault-level data.
SoftNitro Engineering carries out grid connection and net metering studies for solar and storage projects across Pakistan and the GCC, including load flow analysis, protection coordination and harmonic analysis to IEEE 519. See our full range of power system studies or request a scope and fee for your connection.
