There is a version of energy cost management that consists entirely of reading documents, and this is one of its better examples. No equipment is optimized, no load is shifted, nothing about the plant changes. A clause in the tariff offers a lower rate to customers who take service at a higher voltage and own the transformer that steps it down, and the only question is whether the discount exceeds the cost of the obligation.
Where the discount comes from
The distribution system delivers power at a primary voltage and steps it down close to the point of use. Somebody has to own that transformer.
If the utility owns it, the utility carries the capital, the maintenance, the losses and the replacement, and recovers all of it in the rate. If the customer owns it, the utility does not — and a tariff that continued to charge as though it did would be collecting for equipment it does not have.
Hence the discount. It is not a reward for good behavior; it is the removal of a cost that is no longer being incurred. Two components make it up.
Equipment cost. The utility no longer provides, maintains or replaces the transformer.
Losses. A transformer loses a small percentage of what passes through it, continuously. With primary metering, those losses are measured on your side and you pay for them. With secondary metering, they occur before the meter and are borne by the utility. That is a real and permanent transfer, and it works against the discount rather than with it.
The arithmetic
The discount is a percentage of a large number, which makes it look decisive. The obligation is a set of smaller numbers spread over decades, which makes it easy to underweight.
Primary service against secondary service
A site evaluating transformer ownership.
- Annual bill on secondary service$612,000
- Primary service discount from the tariff4.2%
- (Gross annual discount)$25,704
- Transformer losses now on the customer's side of the meter1.1% of consumption
- (Cost of those losses, annually)$6,732
- (Net tariff benefit)$18,972
- Transformer capital, installed$290,000
- Assumed service life30 years
- (Straight-line capital recovery)$9,667 / year
- Maintenance, testing, oil analysis and insurance$4,400 / year
Net annual position$4,905
Positive, and thin enough that outage risk and the cost of a spare deserve to be in the decision rather than in a footnote. A larger site with the same percentage discount would clear far more comfortably, because the discount scales with the bill and the transformer cost does not. Figures illustrative.
The final observation is the general rule: the economics improve with size, because the benefit scales with consumption while the obligation is broadly fixed. Primary service tends to be clearly right for large sites, marginal for medium ones, and wrong for small ones.
The obligations, stated honestly
Ownership is not a paperwork change.
Maintenance and testing are ongoing: oil sampling, thermal inspection, protection testing, to a schedule.
Failure is your problem. When a utility-owned transformer fails, the utility restores service. When yours fails, you are out until you can replace it, and lead times on distribution transformers are not always short. Many sites that take primary service hold a spare, which is capital sitting still.
Protection coordination on the primary side becomes your responsibility, and it is specialist work.
Safety and access obligations follow ownership. High-voltage equipment on your site is your equipment, with everything that implies for qualified personnel and permits.
None of these is prohibitive. All of them are costs, and a comparison that counts only the discount and the losses is not a comparison.
The metering point matters separately
There is a related provision worth checking even where transformer ownership is not on the table.
Where the customer owns the transformer but the meter remains on the low-voltage side, some tariffs apply a loss adjustment — grossing up the measured quantities by a fixed percentage to estimate what was delivered on the primary side. That factor is stated in the tariff, and it is applied to demand as well as energy.
It is worth confirming which arrangement you have, because a loss adjustment applied to a site that is in fact primary-metered would be double-counting, and it would inflate every determinant on the bill. Verifying the metering point and any adjustment factor sits naturally alongside verifying the meter multiplier: meter multipliers and CT ratios.
How it interacts with everything else
Primary service is usually a different rate schedule rather than a discount bolted onto an existing one, and different schedules mean different determinants. The demand definition, the ratchet, the power factor clause and the rider set can all differ.
So the comparison cannot be a percentage applied to last year's bill. It has to be the same modeling exercise as any other tariff change: run your interval data through the full rule set of the primary schedule and compare totals: how to choose a rate schedule.
The power factor treatment is worth particular attention. Measurement at the primary side includes the transformer's own magnetizing reactive power, which a secondary-side measurement does not. A site sitting just above a power factor threshold on secondary metering can find itself just below it on primary metering, for no reason connected to its own equipment: power factor penalties explained.
And, as with any tariff move, the switching provisions govern how and when it can be done and how long you are committed afterward: switching rate schedules.
Whether to look at all
The screening question is short. If your annual electricity spend is large, if you already have qualified electrical resources on site or under contract, and if your service is at a scale where primary supply is offered, the tariff is worth reading.
If any of those is missing, the arithmetic above will almost certainly come out negative, and the hour is better spent on the load curve.
