Smart Implementation of Smart Metering

The government has indicated that they would like to have 800,000 Smart Meters installed on homes by 2007 and on all homes by 2010. This statement indicates that the government is planning sweeping changes to the way these assets and systems will work in the future. As the voice of Ontario’s Electricity Distributors, the EDA has taken a keen interest in these announcements and is working to ensure that the interests of Local Distribution Companies are considered as this process moves forward.

The EDA has prepared this Fact Sheet in an effort to help audiences understand this complex issue as well as to illustrate some of the challenges that need to be addressed to ensure this initiative is successful. The EDA strongly believes that the distribution companies are in the best position to ensure that these new policies are implemented properly as they have the relationship with the customer, have extensive experience in metering and billing, and have an in-depth knowledge of their communities.

The ideas and numbers that are reported here reflect the EDA’s attempt to start dialogue amongst a broader audience. As this debate moves forward and more information becomes available the ideas and figures will become more concrete.

What is a “Smart Meter”?

Currently in Ontario, most homes are equipped with a meter that only measures how much electricity was used by the customer in a billing period, typically one or two months. A Smart Meter will be able to record not only how much energy was used, but also when it was used. This will allow for introduction of different electricity rates for different times of the day and should encourage customers to regulate their own usage of electricity during peak times.

There are fundamentally two types of Smart Meters. The first is called a Time Of Use Meter (TOU) which measures how much energy was used in preset time blocks such as on-peak and off-peak times. These meters provide readings to the LDC and are typically read manually like today’s meters but may be equipped with additional technology for automated readings. These meters have lower costs to purchase and to read, and low-end versions cannot be remotely reprogrammed and cannot communicate in real time. Any changes to rate “buckets” requires the meter to be returned to the manufacturer and a new verification seal applied.

The second type is an interval meter, which measures how much electricity was used in various intervals (typically every 15 minutes). These meters produce many hundreds of sets of data and are usually read remotely due to the large amounts of data collected. Typically the data is read using radio frequencies, internet, phone lines, or by using power line data transfer. These meters are more expensive and may require new computer and billing systems to manage, however they can be reprogrammed easily and can communicate with the customer and billing systems on a real time basis.

While the term “Smart Meter” is still a focus of debate, Time of Use and Interval meters are the two most referred to.

There are various other types of meters that may be considered “Smart” such as pre-paid meters and meters with various other systems that educate consumers and interpret data. As well, various companies have developed different variations of these technologies for potential use by LDCs in Ontario.

Recently there has also been speculation around Net Metering. Net Meters and “Smart Meters” are not the same thing. Net Meters allow customers who generate their own electricity to sell excess electricity back onto the grid. Net Meters are different from Smart meters and represent another set of challenges and costs.

How Will Smart Meters Work in Ontario?

With the current price cap regime in Ontario, measuring when electricity is used is irrelevant because all electricity is priced the same. The time a person uses electricity does not change the price they are charged or the total amount of their bill. The Government has signaled that they will work towards an on-peak and off-peak pricing plan. In this case, a Time of Use meter would be sufficient and would measure these two pre-defined blocks of time, however the meters may have to be manually reprogrammed if these blocks of time were to be changed. Interval meters can measure many more blocks of time and can relay that information to billing systems, however they are more expensive and may not be worth the investment if Ontario is only going to have two pre-defined prices and if these prices are static for long periods of time. If these defined blocks of time are to be changed on a regular basis (critical peak days, seasons, or monthly) then the ability to remotely re-program meters would be an invaluable asset.

Typically, an interval meter is used for a customer who is subject to the spot market price for electricity, which changes regularly to reflect demand and available supply. While the EDA believes that customers should pay the true cost of electricity, the EDA strongly opposes any move that would see household customers in the province subject to the spot market price again.

Challenges

There are three primary challenges that need to be addressed to ensure that this initiative is successful.

First, consideration needs to be given to the role of Measurement Canada which has jurisdiction over metering in Canada. Any new technology that is contemplated for Ontario meters needs to be in compliance with federal legislation governing these issues. Also, smart meters have a more frequent verification requirement, a shorter lifetime than standard meters, and need to be inspected more often. If left unchanged, these Measurement Canada rules could add significant costs to the consumer.

Second, LDCs will need to undertake massive billing changes in the short term to accommodate the new information that they will collect and distribute from the meters to the customers. As LDCs are still carrying the costs of new billing systems purchased for the opening of the market, this additional cost could pose a significant challenge.

Third, the roll out of these new meters may need to be done in whole communities at once. Since there has been little experience in the wide-scale use of these meters in North America, this wide-scale deployment could be troublesome if the technology fails or if the customers are not educated.

Province-Wide Costs

With any initiative of this size, there are obviously significant costs. This is not to say that the initiative should not be contemplated. Rather it is only responsible to look at the costs to ensure a common understanding.

As stated at the outset, critical information about technology options has not been articulated and as such these numbers may require revision as the province moves forward. The costs listed represent minimum costs to be expected and also represent high density residential settings. The EDA has provided costing on two types of meters based on our best information in order to provide an idea of the costs.

These costs do not include consumer education, a rate of return on the capital asset, or in the case of Time Of Use Meters, they do not include manual changes to time blocks. Also, they do not include incremental costs of new Measurement Canada regulations, monitoring, or approvals or the cost of the installation of new communication systems in the case of interval meters.

In addition to these considerations, it is estimated that it will cost about $3.00 per customer per month for the incremental costs of the billing. Province wide this would be about $12.9M.

EDA’s 10-Point Policy Position on Smart Meters

The EDA has a 10-point policy position to support the smooth implementation of the Smart Meter initiative across the province.

1. The EDA believes that the LDC / customer relationship should be maintained throughout the implementation of this initiative. LDCs should continue to be responsible for the meters and the billing agent, regardless of what type of meter is used. LDCs may use third parties at their sole discretion for their individual business reasons.
2. The EDA believes that distributors should be properly compensated for the premature retirement of existing meters.
3. The EDA believes the distributors should be able to recover the amounts in their variance accounts for previous billing changes prior to any new billing changes being contemplated.
4. The EDA believes that customers should pay the actual cost of electricity, but opposes residential customers being exposed to the spot market price.
5. The EDA believes that base functionality for meters should be set, but also believes that individual LDCs should be able to choose which technology works best for them and their community.
6. The EDA believes that a phased implementation should be used for the Smart Meter initiative. Consideration should first be given to conducting pilot programs in willing communities and/or a requirement that all new connections require smart meters.
7. The EDA believes that questions surrounding the approach Measurement Canada will take on smart meters need to be answered prior to any Regulator mandate.
8. The EDA believes that province-wide consumer education should be coordinated to ensure consumers are educated on smart meters.
9. The EDA opposes the creation of additional variance accounts to implement this initiative.
10. The EDA believes that the capital cost of the smart meters and associated systems should be allowed to be fully recovered within a timeframe that recognizes the rapid change in technology and in accordance with proper business principles and be placed in the rate base.