Results of the smart meter trial

There’s a peculiar piece in today’s Independent. The reports of the CER’s 18 month smart meter trial were published in May.

The trial found statistically and economically significant changes in consumer behaviour due to the introduction of time-of-day pricing, with cost savings for both producers and consumers that together more than offset the costs of metering (unless the wrong communication network is chosen).

The trial also found that in-house displays further modify electricity use, but insufficiently so to justify the additional cost.

Real-time pricing was not trialed, nor were smart devices, micro-generation, electric vehicles, and micro-storage.

13 replies on “Results of the smart meter trial”

The overall reduction of 2% is not significant. It is likely that the participants in the trial were motivated by the fact they belonged to a small group of customers selected for the trial. It is likely that once the roll out is effected across all consumers this reduction would be smaller. This is supported by one of the findings which shows that the reduction of use was smaller later in the trial. This can hardly be surprising as the overall potential saving on a household electricity bill is negligent compared to overall cost of living and incomes.

Much more significant finding is that the customers reacted to time-of-use tariff which priced the 5pm to 7pm peak use at a premium. Also, unsurprisingly, everyone has a clock so they had little use of the fancy in-house display to tell them that they should use the dishwasher and the washing machine after 7pm.

Significant savings from this peak shifting is, again unsurprisingly, resulting from savings that can be achieved from reducing the need for costly standby generation required to kick in during the peaks and from reducing the need for T&D network capacity reinforcements required to carry this extra capacity. This applies only in the winter period as you can see if you log on to Eirgrid website that the system demand is relatively flat during the summer and the 5-7pm peak is emphasized in winter months.

In conclusion, a simple system with most cost-effective digital meters capable of TOU tariffs, based on DLC/GPRS and DLC/RF as appropriate with monthly billing has the potential to reduce investments required in system peak capacity.

Further research with real-time pricing and automated smart devices is required to see if there is further potential for savings. This is a bit premature because unlike smart meters, smart devices are not yet widely commercially available.

I have a doubt as to why RF turned out to be cheaper than GPRS to link concentrators with front ends but as the report says this is highly sensitive to assumptions of use. In studies I participated in, GPRS was always more cost effective when monthly registers only were being interrogated monthly. Things change when the utility starts downloading monthly 30min profile data. This is due to key difference between RF and GPRS being that that RF requires higher initial investment and then gives you flat cost for entire bandwidth available while GPRS requires smaller initial investment but then pay per volume of use applies. It could be also that the initial cost of RF is underestimated in the study possibly because ESB already owns nation-wide radio infrastructure and it is not clear that the full investment in RF capacity has been adequately taken into account.

Excellent points.

The price signal was designed for demand shift rather than demand reduction, so it is not surprising that that is what was found.

Smart devices are indeed not on the market, but that will soon change. As replacing meters is expensive, one would want to install forward-compatible meters now — or rather after the communication standards for smart devices have been agreed.


I would not expect the meter to have a significant role in the smart device setup. Like all other devices the meter is likely to be receiving price signals from other applications in the same way smart devices will be receiving the price signals from the same applications. Depending how dynamic the real-time pricing is the meter may require more memory and processing power. Some seem to think the meter will be the hub of the smart home – but why would it go beyond simply recording your consumption for billing purposes?

Smart devices only meet their potential with real-time pricing. I would think that you want to get the price signal once into the house (using the smart meter) and then distribute the signal locally, probably via a separate hub.

Rethinking my previous point, you may of course also include the smart meter replacement/upgrade in the sale of the smart device.


I would anticipate that the smart home network will have features like web interface to utility portals, energy trading platform, smart device management, historical consumption data, perhaps even a weather station input to help you anticipate micro-generation and your own demand.

This would require a hardware platform and I wonder what would be the benefit of putting this platform in a meter. It is more likely another device (essentially an embedded PC) will materialise in your house with internet connection and a WIFI to all smart devices.

I would not see today’s smart meter surviving this change firstly because the future requirements will require a significant change to its hardware platform and more importantly because DLC is not suitable communication media to propagate real time pricing.

So the options today are to go ahead with the current setup proven to have a capacity to achieve peak shifting or to wait for smart home platform to materialize.

The expected life of solid state smart meter is 10 years (compared to 20+ expected from mechanical meter used today) so I would say we are quite safe to proceed with what we have as the commercial availability of smart devices is 3-5 years ahead and the benefits of this future platform are far from clear. Unless significant automation is built in in the future platform I would say the benefits of dynamic pricing will not materialize as the trials have shown that the effort people are ready to put into managing the consumption is not significant.

There was a question on the previous thread as to how the in house display could be realized in apartment blocks where meters sit right next to the building entry. Wireless connection is obviously not going to work for top floors and it is unlikely running extra wires would make much sense. The technology that can be used is to employ the building low voltage electricity network. All is needed that the display is plugged into the AC socket and it can use DLC to communicate with the meter. I am not aware what they actually did with the apartment blocks in the ESB trial.


You may even end up with micro markets in which case a lot of communications will be between you and other market participants in the micro market for the purpose of synchronising smart devices across a consumer region and for the purpose of trading electricity from your micro-generation or that accumulated in your Prius during low-price period and also provided you do not intend to drive the damn thing.

This is a long way off and requires a significant change in the way the transmission and distribution networks are managed. Currently the system is designed to shift generation to the points of consumption while maintaining frequency stability and while optimizing the economy of dispatch. This includes choosing the cheapest available generation to match the consumption wile maintaining short transfer distances to optimize transmission losses. Current systems for network monitoring and energy management used by Eirgrid and ESB to manage transmission and distribution networks are designed for this purpose with generation largely being concentrated, except for wind which posed significant challenges to network operation. A more fundamental change with generation and storage significantly dispersed will require a radical change. The infrastructure for network management consists of control centres and substation automation. Currently automation is installed as a rule in transmission stations while on the distribution level 110kV is covered 38kV is largely covered while 20kV is rarely included in remote management. To facilitate this radical shift energy applications would have to change and significant investment would be required to propagate remote management deeper into the distribution network.

This is another reason why I would not hold my breath and put the current metering projects on hold in the expectation of this radical change.

There’s a peculiar piece in today’s Independent.

Typical Tol comment.

I’ll bite. What, exactly, is so “peculiar”, then…?

The conversation is going into the area of ‘smart devices’. First there is no prospect of the communications standards for smart devices being agreed this side of 2014. The area is just too complex and the interests are too diverse. Secondly, I have my doubts about your ideas on network architecture. Will there still be GPRS after 2013 for instance? There are no licences in issue beyond that date. Why does the dynamic price information have to come through the meter? Why not directly through the Internet or by radio broadcast?

Finally there is a statistical issue. My hunch is that most of the benefit of smart meters comes from the heaviest users. Most electricity users don’t really use much at all. If the objective is to streamline the load, it would be better to concentrate on the heavy users (who typically will have Internet connections).

The smart meters also have operational benefits and this is where a lot of the value comes from. In particular, they can be used to switch off the supply remotely. this means you can have prepay electricity deals and basically eliminate bad debt. Personally I think being able to knock out electricity by remote control is not a good idea for national security reasons and the regulator should not permit such meters until the sector has developed deep information security knowledge and safeguards.


Most concentrators have GPRS/UMTS communication so once GPRS is phased out (if that happens – to my knowledge existing licenses will still be valid and GPRS will continue to coexist) they can communicate via 3G.

Secondly I doubt the dynamic price info will come through the meter. Programming of TOU tariff is currently done through meter via DLC but this not done frequently and DLC is not fast or reliable enough for dynamic pricing. I made the point already that future dynamic pricing (which only makes sense with smart devices) will be coming through a smart house hub of some sort.

Remote disconnection is a feature I have seen on international projects already. The central infrastructure used for issuing disconnection commands is normally not connected to the internet (just like SCADA and energy management apps) so to issue a mass disconnection command a hacker would have to break into each individual concentrator and these normally cover up to 300-400 customer meters. I don’t think this feature is used in ESB trial as this is normally required in countries with serious energy theft and non-payment problems. A decent level of security is already built into the systems as remote disconnection is not the only issue – if someone was to interfere with tariff programming, this would be just as serious as mass disconnection.


Also, this is not my idea of a network architecture. This particular architecture (GPRS to concentrators and DLC to meters) is the most feasible architecture rolled out in Montenegro, Italy, Sweden and now also a part of the ESB trial. This is one of the options producing greatest savings.

I can see serious issues with the use of internet for propagation of dynamic pricing. Who will assume liability when internet connection to a household is down and potentially incorrect pricing info is used for settlement billing? Will internet provider or energy supplier assume liability? I am not so sure.

For many reasons, dynamic pricing is way down the line. Time of Use tariffs however will very soon become a reality as current systems and technology are available.

I agree this architecture will work. However, there are no GSM licenses beyond 2012, though there almost certainly will be an extension to 2013 and most likely beyond. After 2018, I doubt there will be GPRS. UMTS is certainly an alternative, with concentrators, although reception is more of an issue than with GPRS.

I don’t know much about DLC (basically running the signal over the electricity line). DLC is a great idea at the moment, but it all depends on the amount of interference on power lines remaining constant. If PLC/DLC systems become popular within buildings, it could make these systems less reliable. The power network is not really designed to carry data signals although it may be a workable solution.

The Stuxnet debacle showed how SCADA could be hacked to take control of a nuclear plant. SCADA is definitely hackable, and a direct connection to the Internet is definitely not required.

I can’t see why the Internet is any worse than any other network for propagating the dynamic tariff data. There is never a guarantee of network availability on any domestic network of any kind. It is really up to the householder to obtain timely data and verify it by checking the cryptographic signature. I cannot see any difficulty with doing this.

Why program the TOU tariff on the meter? Is this actually used for billing, or only indicative? Surely it would be more sensible to calculate the bill at the head-end, not at the meter?

If dynamic pricing is so far down the line, why bother with smart meters at all at this stage? Time metering can be done with a dual meter, and a discounted period in the middle of the day (which there used to be).

If dynamic pricing really is so far away, and will require new equipment, then all the business cases presented so far are wrong, since the first generation of smart meters will need to be replaced or upgraded before the end of the payback period.

If there were a port from which a pulse could be read from the device, that would seem like a better basis for a smart metering setup. This rollout could then be confined to larger households, which would improve the cost-benefit of the project a lot. When dynamic pricing is actually ready, the project can be looked at again.

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