In a recent article in Smart Grid News, Robert Dolin, CTO of Echelon, looks back at a smart meter deployment project initiated in 2001 in Italy by Enel, the dominant utility in that country. This meter centric project included time of use pricing, integrated pre-pay and meter disconnect capability, support for in-home displays, power quality measurement and other features. It involved deployment of 30 million smart meters and, although it cost € 2.2 Billion, the return on investment was € 500 million per year in operational savings to the utility so, at least in theory it paid for itself in a little over 4 years. This project underscores a key point in the debate about Smart Grid: this is good business for the utilities regardless of whether the customers are engaged.
Dolin goes on to ask the all-important question: what’s next? In answering that question he points to the emergence of two way distributed communications and increased intelligence within the grid and consumer premises in what he refers to as Smart Grid 2.0. A key element of this Smart Grid 2.0, according to Dolin is demand response which generates a lot of animated debate in Smart Grid circles and in consumer groups. Dolin, however, brings to the fore an important argument concerning demand response that is very often missed in those debates. Utilities have a regulated responsibility to deliver secure reliable power to meet demand at all times. The effect of this is that utilities have to build generating capacity (or purchase contracts from independent generators) to accommodate peak demand. As Dolin points out, in the US, utilities experience peak demand just 2% of the year but their ability to meet that demand accounts for a full 15% of their annual costs. Regulated utilities are allowed to pass on these costs to consumers so when we think about the cost savings to consumers that result from demand response, we need to think not only in terms of the possibly minimal savings that accrue directly from the demand reduction at an individual consumer’s level but also the aggregated savings that accrue to all consumers by reducing the excess capital and operating costs associated with building or purchasing capacity to meet peak demand.
Phil Carson at Intelligent Utility Daily also jumped back into the debate over Smart Grid recently. In an article entitled “Who ‘Believes’ in Smart Grid”, posted on July 1, he summarized a long discussion that occurred on LinkedIn’s Smart Grid Executive Forum. You can read the article to see the comments that Carson found particularly insightful but I want to focus on just one of those. One correspondent in the LinkedIn forum stated: “How about starting with a few simple things like giving the customer a rate and a bill they can understand?”
This is a key step in getting customer engagement. How many utilities that are rolling out smart meters are using the data collected from those smart meters to inform the customers on their existing bills what their payments would be on various rate plans that are available to them? I envision a bill which shows the actual billed cost on the customer’s current fixed rate plan with one or two alternative billing options showing alternate costs based on actual utilization by that individual customer under a time of use or critical peak pricing plan.
By doing this, the utility could educate customers about the true variable cost of electricity and either demonstrate to them the potential cost savings or prove to themselves that there is no cost incentive for the average customer in their service area in which case they need to find an alternative marketing strategy.
I participated in another long and sometimes strident discussion on the merits of time of use pricing on LinkedIn’s Smart Grid, AMI, HAN group. Kat Shoa initiated the discussion with a reference to her article on achieving consumer behavior change around Smart Grid dynamic pricing. In her article she notes that electricity prices are lower in the US than in many other parts of the world. As a consequence of this low-cost market for electricity in the US, she predicts that engagement in demand response will be limited to high use commercial and industrial entities and a few highly engaged consumers. Price rises that would make demand response attractive to residential consumers would likely spark serious backlash against the utilities that implement them.
Some of the comments in the LinkedIn discussion ranged from unequivocal (but also unsubstantiated) statements that time of use and critical peak pricing models were already obsolete, to nuanced discussions of the differences between real-time dynamic pricing, pre-determined time of use pricing and critical peak pricing based on day-ahead projections. A particularly informative comment came from a contributor who referred to himself as a Dumb Old Utility Guy (DOUG) who demonstrated the sort of keen understanding of the industry that comes with many years of experience. In comments similar to those referred to above from Robert Dolin, he noted that
“while there are fluctuations of energy cost throughout the day, week, month and year – the extreme cost comes from trying to serve load over the course of about 40 hours per year for most utilities, occurring for 4 to 6 hours per day on peak days. The transmission and distribution system is built for these hours and generation resources are purchased or committed to serve these loads. There may be something in it for industrial customers to manage load against system marginal prices for the next 1000 hours, but the residential customer can only be enticed to respond for these 40 hours. “
“It’s easy enough to select a representative price for these peak hours at the beginning of each summer and then work with customers to allow limited load curtailment during these brief periods. It’s best to give the customers a tight window, perhaps no more than four hours. If necessary, customers across the system can have staggered response times with some called on from 2 pm to 6 pm and others from 4 pm to 8 pm. “
“Residential customers have neither the time nor the interest to follow the daily fluctuations in energy prices. They will respond to a limited number of calls from a utility – if the reward from the utility is sufficient.”
In the middle of this discussion came news that the regulatory authority in Maryland had rejected Baltimore Gas and Electric’s rate case for cost recovery associated with a Smart Grid Initiative. Some in the LinkedIn discussion seized on this news as evidence to support their view that demand response based on variable pricing was dead but a closer reading of the decision reveals that, in fact, BGE’s application was seriously flawed and this was not in any way a rejection of Smart Grid, demand response or variable pricing by the regulator.
In their announcement the regulator stated “The Proposal asks BGE’s ratepayers to take significant financial and technological risks and adapt to categorical changes in rate design, all in exchange for savings that are largely indirect, highly contingent and a long way off. We are not persuaded that this bargain is cost-effective or serves the public interest, at least not in its current form.”
The BGE proposal, which would have cost $482 million up front and a further $353 million over the life of the program would have replaced all existing meters with smart meters, deployed a two way communications network between the utility and the consumer premises via the meters, and instituted a mandatory time of use rate schedule for the summer months. The regulator found among other things that:
- The proposed plan would not in and of itself achieve the results that BGE were claiming and that further expenditure would be required to automate the distribution infrastructure.
- The scope and proposed price tag also did not include the integration of smart appliances within consumer premises.
- BGE’s proposal for a customer surcharge to recover the costs of the program, as opposed to recovery in the rate base at a later date unfairly transferred all of the risk to consumers.
- The BGE proposal was motivated by the availability of stimulus funding but, despite an approved stimulus grant of $136 million from the federal government, the proposal did not demonstrate that it was in the best interests of PGE customers.
More significantly however, the regulator noted that they were unwilling to approve any proposal that imposed mandatory time of use rates on all customers. In this they quoted Maryland Energy Administration witness, Fred Jennings ,in saying that before transitioning to time of use rates, it is critical that customers are provided:
- sufficient education so as to understand the new tariff and how their behavior and decisions will affect their energy bill, and
- the equipment and technology, such as in-home displays, orbs, electronic messaging, etc. to receive the requisite information that triggers behavior changes.
So, the debate continues. Various people are staking out their claims on either side based on what outcome is most beneficial to them. As with any new technology we will have to wait and see. There will be successes and there will be failures. Those failures may be the result of inappropriate technology choices but they are more likely to be the result of ill-conceived plans that fail to take the customers into account and secure buy-in from all stakeholders. One thing is clear, with stimulus money on the table, we are going to see more applications for Smart Grid deployments from utilities that are anxious to get a piece of that action. I just hope that other utilities take note of BGE’s failure and design their Smart Grid projects with the customer in mind and start to tackle the very real issues of how to get the customer engagement that will decide whether their projects succeed or fail.