Written evidence submitted by Sanjaya Singhal (PSM0010)

My background & experience:

I am the Chief Executive of and the entrepreneur behind Secure Meters Group (£180m last year sales; 2,100 employees; 590 strong R&D team) with the following interests relevant to the UK:

• Secure Meters (UK) Ltd: Installed / contracted for ~1m SMETS-1[1] compliant smart prepayment meters for the foundation phase in GB;
• Utilita Group Ltd: Pay-as-you-go specialist energy supplier in the UK serving >130,000 customers at the bottom of the economic pyramid with smart meters;
• Secure Meters Australasia Ltd: Supplied 1.2m smart meters in Australia; and
• Secure Controls Ltd (previously Horstmann Controls): Provides traditional and smart controls for central heating and hot water in the home.

Spanning metering technology, energy supply and heating controls in the UK gives me some unique insights. Experience in Australia allows the comparison of two very different approaches to smart meter deployment between the two countries. (In this paper Australian experience is summarized in Exhibit – 1 and cross-referenced as appropriate).

The context of GB’s smart metering program

1. Program scale & complexity with many world firsts:

• In scale, it is the world’s biggest smart meter mandate.
• It is the world’s most complex metering system. Four separate items (gas & electric meter, in-home display and communications hub), potentially from four different manufacturers, are required in a dual fuel home.
• It is the world’s biggest central database for managing security keys.
• It is probably the only large-scale mandate where communications providers (CSPs[2]) are not providing the head end IT systems, someone else (DSP[3]) is.
• It is the only mandate where communications technologies have been chosen without extensive trials / pilots by key stakeholders – the energy suppliers. (Also see Exhibit-1 para 3)

2. Smart meters operating within primitive energy settlement practices:

British energy industry practices remain rooted in the last century. Some examples:

1. Gas suppliers are “allocated” their gas purchase using annual quantity estimates and not customer meter readings.
2. Domestic electricity customers are settled using a deemed half-hourly profile not the real half hour usage.
3. Prepayment systems still cannot reach churned customers’ payments to their new supplier reliably.

These are critical market weaknesses today. These weaknesses are not being addressed as a part of the smart meter mandate. Smart meters ought to reduce the suppliers costs to serve customers, indeed this is a critical part of the benefits case. Without commensurate reform in industry practices as above, smart meter deployment will not really bring costs down. (For the approach in Australia, see Exhibit-1 paragraph 4)

3. Who owns the delivery of the benefits case? Can benefits be delivered?

For GB, benefits are expected from two main areas – users saving energy (and commensurate carbon benefits) and industry cost savings by the energy supply industry. From the program it is not clear who is responsible for delivering the benefits (for the approach in Australia, see Exhibit-1 paragraph 5) and whether the benefits considered are real.

Will customers achieve the average 3% energy savings?:

UK wide energy use has been reducing by ~3% per year without smart meters. There is at least two years real data from the pre-foundation and foundation phase smart meter programs. A rigorous study of this would establish whether the 2.8% energy savings considered in benefits case are realizable or not. Utilita’s experience in serving the three lowest income deciles of GB indicates no reduction in energy use by its customers. Possibly the opposite could be true, Utilita’s lower prices may have caused a slight increase in customers’ usage.

User feedback from IHDs[4] saves energy was undeniably established in N Ireland. Secure Meters provided the metering equipment to NI. There is a fundamental difference between the NI & GB deployments of IHDs. The NI deployment forced the customer to interact with the IHD frequently (that IHD is the most convenient way to credit pre-payments). For the GB deployment, interaction with the IHD is optional. There is anecdotal evidence to show that more than half the customer population ignores the optional IHD within a few weeks of its installation.

Begs the question – is there a robust assessment of the income stratified 3% savings in the benefits case? Income stratification is necessary because attitudes to energy in the upper two or three income deciles are comfort driven while the lowest three deciles demonstrate a price elasticity towards energy.

Will the industry achieve the expected cost savings?:

The full picture on capital costs of the metering equipment is now more or less clear. The cost of SMETS-2 specifications is higher than SMETS-1 primarily because of the complexity built into the specifications and installation.

The main concern, however, is the operating cost of the specified smart meters. Present estimates of DCC costs indicate that annual operating costs on a per metering point per year are 2.5 times the cost in the Impact Assessment. See Exhibit-2 for details.

Complex services such as prepayment, multi-dwelling units, energy conservation equipment on the home area network etc. are yet to be designed and are excluded from the costs estimates so far declared. When these are added to the portfolio, operating costs will rise further.

What progress has been made on smart meter roll-out since our last report on this subject?

After the Government announced the foundation phase comprising SMETS-1 compliant meters supported by an SMSO[5] service would endure over their lifetime (i.e. beyond the commencement of the rollout specification), it has become easier and cheaper to raise finance for smart meter assets. Providers of finance needed the certainty that the Government provided.

Utilita was the first energy supplier to launch SMETS-1 meters based dual fuel pay-as-you-go energy product. Customer response has been very positive. Utilita has established that the operating cost of SMETS-1 with SMSO is very low. It now has over 130,000 customers. Other suppliers, including the one of the Big-6 have seen prepayment as good value for money and have contracted with Secure for SMETS-1 meters.

The Secretary of State wrote to all suppliers challenging them to prioritise prepayment customers for smart meter installation. While a few other suppliers are responding to this call, regulation is increasing the costs for these pioneers. Even though SMETS-1 meters are allowed to endure for their full useful life, this perverse regulation permits their removal, upon churn, by the new supplier if they are operated as pre-payment meters.

To what extent has the Government addressed the concerns we raised about smart-meter roll-out, and the concerns raised by other interested parties since we published our last report?

The two fundamental issues with smart meter rollout are: 1) will a robust DCC service be available in 2015; and 2) what are the operating costs for smart meters using the DCC service.

1. Will DCC be robust and ready in time?:

DCC is the contracting agency for three services Data Services (DSP), Communications Services (CSP) and Security Services. Good contractors with the appropriate pedigree but inadequate smart metering experience have been chosen for these services. DCC is a gigantic IT program serving many stakeholders, being put together in a great rush.

Such a program needed the collaborative and risk sharing methods of project management techniques that successfully delivered complex projects such as London 2012 and Heathrow T5 on time and within budget. Instead, the program is being run using transactional management methods with risks deferred or passed out to other stakeholders. Service specifications are so complex that if and when things go wrong, they will be very difficult to set right. The industry already knows the DCC program is running late, yet no one is acknowledging this delay that everyone already accepts.

After DCC achieves a satisfactory technical launch of its services, all energy suppliers will face a critical decision – is the service robust enough for them to trust their daily revenue and cash flows to it? This will be a difficult decision because the ultimate customer experience and the suppliers’ reputation will be determined by the quality and cost of the DCC service. The wrong decision for a small supplier like Utilita could threaten its survival. Utilita will not make the decision to switch to DCC merely because DCC has declared ‘go live’ or because of a regulation that drives it to do so. Utilita will test the service, gather industry experiences, build contingency plans – all of this will take time after go live. This time is not even in the project launch plans of DCC.

The plans themselves ignore the complexity of the metering solution required in each home. Four different devices are required to operate smoothly with one another to make the system work. Assuming there are five different device manufacturers, gives over a million test cases! Not every manufacturer will interpret the standards in exactly the same way. (For the approach in Australia, see Exhibit-1 paragraph 7)

It is highly unlikely that a complete range of DCC services will be available on time. It is more likely that the industry will be fed with a slow drip of delays and drip fed essential services over a period of time.

2. What are the operating costs of smart meters using the DCC?

The operating costs of the communications and data services so far published by DCC are already above the costs in the initial impact assessment and are sure to rise further as the program nears completion. (See Exhibit-2 for a comparison).

DCC has already published[6] an increase of 72% over the procurement baseline for its internal costs and a 33% increase over the procurement baseline external costs. This publication also lays the ground for further increases in the future.

DCC, rather than become the provider of data to the whole industry, has reduced the scope of its services (for paucity of time to deliver the complex services) and morphed into the provider of a ‘communications link’ between smart meters and energy suppliers. This metamorphosis requires suppliers to continue to incur existing costs on top of paying for DCC e.g. for moving meter reading data to settlement systems or operating a prepayment service in addition to pay for the DCC service. Thus, on top of DCC costs, suppliers will continue to incur costs for data collection, validation & aggregation, PPMIP services etc.

On top of these costs, energy suppliers are incurring huge costs (far greater than the £30m envisaged in the Impact Assessments) for changing their IT systems to work with DCC. Since DCC costs apply equally to all suppliers, they are not seen as a competitive disadvantage by any one supplier. All suppliers will raise their tariffs to accommodate this cost increase. Even if some absorb all or part of this increase, this will at best be short term. The DCC cost will only hurt the efficient and innovative suppliers, who have a simpler, more capable and interoperable SMETS-1 products.

If DCC costs are not controlled, the benefits case from industry cost savings will simply disappear and industry operating costs will go up, not down. The key question is – who is the gatekeeper for DCC costs and where is the incentive for DCC to keep its costs as low as possible?

What problems have emerged during the foundation stage and how are they been addressed?

A number of issues have emerged during the foundation phase and many have either been ignored or have been ‘transferred’ to the industry. Some examples:

3. Communications within multi-dwelling units and tower blocks: Received wisdom on smart meter communications is ‘one size does not fit all’. With the geographic distribution of a single technology, CSP providers are, predictably, struggling with achieving effective communications within tower blocks. This will cause yet another communications technology to be brought in and add to the complexity of the rollout. Faced with this, the DCC project has taken the view to consider tower blocks as an evolution for the future.
4. Prepayment metering: Also perceived to be a hard problem to solve, has similarly been marked for later considerations and launch.
5. Replacing radio-teleswitch: To the best of my knowledge, this issue has not received any attention at all.

Critically for an innovative smart meter supplier like Secure, a different problem has arisen. Our customers who use our SMETS-1 meters with our SMSO service are telling us that in the SMETS-2 and DCC world they will not be able to support their customers with same levels of service. Compared to SMETS-1, when using DCC their customer service levels will drop. (Some examples: Install time drives install costs. Secure’s products allow completion of the installation even in the absence of a Wide Area Network signal. No WAN installs reduce costs but are not being offered by DCC. Another service called “Over the air firmware upgrade” is promised post DCC for 96% completion in five days, Secure’s customers get this at 99% in two days today)

What are the remaining challenges (technical, communication or other) associated with launching the mass roll-out of smart meters in 2015, and completing it by 2020?

1. Everything in the rollout phase is different from the foundation phase and is as yet untested – new meter specifications (SMETS-2), new communications hubs (provided by CSPs), new data systems (provided by DSP) and new contracting counterparties (DCC). Experience from the foundation phase is just not replicable in the rollout. It will be prudent for the industry to provide for time to test and prove that everything works smoothly so that customers the good experience they deserve. The 2020 end date does not take this industry time into consideration. Typical pilot deployments of smart meters take around a year to iron out issues. Given the complexity of the GB mandate, the author feels one year may be a big underestimate.
2. Major technical and commercial risks remain in the program. The presence of these risks is pushing contract costs higher. Each contracting party is passing these risks to other participants and someone at the end of this value chain pricing those risks in their contract prices. Communications hubs remain computer models, DSP remains a service promise, meter manufacturers have no ability as yet to test their designs, new communications protocols are yet not firm, HAN chips for 868 MHz and new HAN protocols are non-existent – highly unlikely that mass scale deployment can launch at the speeds predicted.
3. Difficult to solve problems such as prepayment, communications in tower blocks, radio teleswitch replacement, no WAN areas, metering for district heating etc. are being deferred to a later date in the program. Once again, such afterthoughts in smart meter deployment will lead to both higher costs for these solutions and little room for innovation. Sadly, a number of these issues impact poorer sections of society who will again face higher costs because they were overlooked in the initial design of systems.

In this writer’s considered opinion and experience, DCC will be late, much later than it is being projected. Validation of the new kit and DCC services will take very much longer than it is considered today. There is no chance that the rollout can be completed by 2020. If we continue down this path, a more likely date for completing the rollout is probably 2024.

How can these challenges be overcome?

1. Reassess the cost - benefit case: The annual operating costs are higher and expected to rise further. Both the energy saving and industry cost saving benefits are seriously doubtful. Energy savings can be assessed using real data from the foundation phase. High DCC costs are likely to jeopardise most of the industry cost savings. Ensure DCC has real competition to give it the incentive to keep its costs down.

Will this program mean higher customer bills? This frequently asked question must be answered with certainty. If bills will go up, then an informed choice on forcing yet another ‘policy cost’ on customers’ bills must be made.

2. Extend the mandated end date beyond 2020: Legislation requiring all customers to have smart meters by 2020 is today unachievable. If this was accepted now, then suboptimal design and deployment decisions being made for the sake of speed will stop.
3. Change wholesale market mechanisms first: Introduce the changes to electricity and gas settlement such that all smart meters are settled on half-hourly data and gas meters on real readings. Reduced uncertainties in settlement, easy change of supplier administration etc. will all lead to reduced costs for suppliers.
4. Amend the mandate: Rather than mandate 100% of customers, let suppliers install smart meters where the business case for suppliers is robust. When suppliers see benefits, either to themselves or to their customers, they will actively support deployment. SMETS-1 compliant prepayment meters, deployed correctly, reduced the cost to serve prepayment customers. Customer benefits are not necessarily in saved energy, they may come from lower tariffs, greater convenience or in other ways. Let the market determine this. In a competitive supply market, one or two suppliers with the right energy product for their customers will cause their competitors to respond. That response will either lead to copy-cat behaviour, i.e. more suppliers installing smart meters, or will lead to innovation in the smart metering space. Both are desirable outcomes for customers.
5. Adopt a data level inter-operability model for the market: Suppliers should be permitted to install any metering device / communications technology they want as long as they appoint an arm’s length and certified service provider that can exchange data with that device. If that customer churns to another supplier, the service provider switches the provision of the service to the new supplier. This is how the PPMIP service works today. Data level interoperability will eliminate the risks to deployment schedule and reduce operating costs by an order of magnitude. (For the Australia approach see Exhibit – 1, para 7)

What are the best approaches to monitoring the mass roll-out of smart meters?

-

What contribution can smart meters make to expanding the use of Demand Side Response as a means of addressing possible capacity shortages?

Smart meters can make a big impact on shaping demand curve[7], i.e. demand side management and in making changes to demand in response to specific supply side or network events (demand response).

The key to demand side management is getting distribution network operators (DNOs) engaged in the process. They are not fully involved today. With the data level interoperability model, and with arm’s length service providers exchanging data with meters, engaging the DNOs will become easier. If customers agree that their data be used not just by their supplier but also by their DNO, passing data from service providers to DNOs becomes straightforward.

To realise the full potential benefits of smart meters, is it necessary to introduce time of use pricing for electricity?

Time of use (TOU) pricing, as opposed to time of day (TOD) pricing, helps in times of critical supply side shortages only. While TOD pricing can help shape the average load curve and address chronic supply side constraints, TOU pricing responds acute shortages caused by extreme weather or station / system outage events reflected in the wholesale / balancing market prices to rise sharply.

Benefits from TOU pricing will only arise once electricity settlement is based on real half hour data and not deemed profile. Even though smart meters can administer TOU pricing, this essential market mechanism to enable it, is missing.

Exhibit – 1

Smart meter experience in Australia

1. In Australia, provision of customer metering is the responsibility of the Distribution Network Operators (DNOs). In 2009 the Government of Victoria mandated that DNOs provide smart electric meters to all customers in a defined timeframe. The Victoria program was completed on time by four out of five DNOs by December 2013 with 2.1 million customers receiving smart meters. There was a lot of customer resistance to the program as it progressed and it remained a stop-start program till these issues were dealt with by a big publicity campaign. The program has come in much higher in cost, partly because initial cost estimates were erroneous and partly because of the start-stop program, but the expected benefits have been delivered. The higher program cost has meant that customers have seen an increase in their bills (~A$100 per household) and this was politically unpopular.
2. Towards the later stages of the Victoria program, the Commonwealth Government started work on a national mandate for smart meters. After much debate, probably the higher bills in Victoria also played their part, the Government decided against making a national mandate. Policy has shifted towards a market led deployment of smart meters. To enable that, current policy is that metering will move from being the responsibility of DNOs to being the responsibility of energy retailers. It is expected that retailers will assess the benefits for themselves and their customers and roll out smart meters where justified.
3. In Victoria, Australia, the key stake holders, DNOs tried different communications technologies before shortlisting two technologies that went to pilot trials. Both had the communications and head end IT systems provided by the same supplier. Having chosen a winner from these pilots, they asked meter manufacturers to integrate with that communications technology. Four out of five DNOs took this approach and chose the same technology. The fifth chose a different approach. It went with a big name supplier offering communications and head end systems technology but did not pilot it enough to show its weaknesses. When issues were revealed, it opted for a second communications technology and apparently, that too is struggling. While information on this fifth supplier is an assessment by knowledgeable observers, the exact contracts are confidential. One thing is certain though, this is the only DNO in breach of license conditions for not completing the rollout on time.
4. Markets and settlement methods vary across different states in Australia. Market regulations across all states require that any electricity meter reporting on half hourly profiles, wherever installed, must be settled using the real half hour data. Improvements to the settlement systems preceded smart meter deployment.
5. The business case for smart meters in Victoria, Australia, was explicitly made out for the DNOs in Victoria. DNOs are regulated monopolies and rational regulatory action allowed the investment to be made up front with DNOs obliged to deliver the benefits over a timeline. DNOs believed in the business case and set about running the program in the knowledge that benefits had to be delivered. Their attitude to the mandated deployment was a positive one. Though the costs of deployment have been higher than expected, the expected benefits have been achieved.
6. Learning from this mandated deployment, Australia has chosen a retailer led smart meter deployment. The benefits case has thus been left to the markets. If retailers think there is a benefit to them or their customers, they are free to deploy smart meters. This has changed thinking amongst retailers and many are going ahead with deployment once regulations are in place. Within a few months of this policy being announced and even before regulations are final, at least 2 million metering points have been put out to tender by the early movers amongst the energy retailers.
7. Australia is not looking for device level interoperability. As far as meter specifications are concerned, the plan is specify a very high level of meter functionality such as the need for a switch, load profiles etc. With no device level interoperability needed, zero test cases will be needed for this reason in the proposed Australia retailer led rollout.

8. Australia has moved to a retailer led smart meter deployment without a government mandate. The need for meters interoperable between suppliers is as real there as it is in GB. The Australian approach though, is very simple. There is only a guideline on the desired result from smart meters. Thus the guideline states that meters must be able to be remotely read, remotely connect / disconnect, store load profiles etc. There is no prescription on the detailed specification of the meter itself nor one to cover its communications protocols. The prescribed result is itself quite simple - any metering equipment, installed by any supplier, must be able to exchange data with established industry data systems (MSAT, the system that links retailers, DNOs, settlements etc.). A data interchange dictionary is in extensive use today. Each supplier is free to choose any metering or communications technology provided the data being received can be moved around the industry based on this dictionary. The whole cost and complexity of CSP, DSP etc. and of specifying what millions of interoperable devices spread throughout the country has been replaced by the simple imperative of an existing data exchange protocol. This approach is forcing suppliers to look for smart meters with the lowest cost to serve and integrating them into their existing system which already link up to industry systems.

Exhibit – 2

Comparison of operating costs

* Cost per household determined by dividing the total cost by the number of households receiving electric supply (27.8m) and the period considered in the Impact Assessments (18 years)

† DCC have published[10] per metering point indications of costs. Total cost has been determined by multiplying the per household costs by the number of households and the time as above.

DCC have held workshops with industry participants over the last few weeks to discuss their expectations of operating costs going forward. At present their cost projections go only as far as the Regulatory Year (RY) 15-16 with no indications yet of costs further out in the future. These projections come with a proviso that they are indicative and with strong indications that because of the complexity introduced by the new standard (GBCS) the costs are likely to go up further.

Against a projected total operating cost of DCC of £2,374m, DCC projections indicate the cost has risen to £6,017m, an increase of £3,643m. The net (undiscounted) benefit in the Impact Assessment Jan-14 was £6,876m. If the present operating costs are to continue, the net undiscounted benefits from the program will be £3,233m.

November 2014