In this day and age where information is always at our fingertips and we are constantly connected, the lack of customer engagement in the electric utility industry - on which all our smart electronic devices depend - is mind-blowing. In 2014 alone, the electric utility industry in the United States had revenue of over $389 billion from end use customers. In spite of that level of outlay, it is estimated that the average residential customer only spends about nine minutes a year engaging with an electric utility. Smart meters can change all that. These sophisticated meters have the potential to transform how customers and utilities manage electricity delivery and use. Whether they will, however, depends on how they get put to use - and both utilities and their regulators have a role in that.
The key to all this is not the meter itself, but rather the integrated network of smart meters, communication systems and data management that makes up advanced metering infrastructure (AMI). AMI connects a home to the electric grid through a two-way communication system capable of recording and transmitting data between the end user and the utility. AMI opens the door to a world of possibilities, including real time energy tracking, load forecasting, time varying rates, demand response, real time outage detection and restoration notification, dynamic voltage control, and enhanced customer service.
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Source: AEE Analysis of EIA-861
But it all starts with the meter. According to the EIA, there are currently 52 million smart meters (classified as AMI by the EIA) in the U.S., about 37% of all meters. This represents significant deployment, but far from the universal usage that would allow for major changes in rates and programs. As shown in the graphs below, California leads the nation in AMI meters installed, followed by Texas. But only Maine, Nevada, and Washington, D.C. have more than 90% smart meters installed. Furthermore, only 1% of meters in the U.S. are AMI-connected to a home area network (HAN) gateway - which allows the meter to communicate with devices within a customer's home. Also, 35% of meters are Automated Meter Reading - allowing the utility to collect data for billing either through a fixed cellular network or through a drive-by van with remote capability, but not two-way communication and other more advanced capabilities. Then there are the 27% meters still in service that are an iteration on Hungarian Otto Titusz Bláthy’s 1889 electric meter.
This scatter-shot installation does not facilitate the optimal use of smart meter technology. With full blown AMI, customers can save energy and money by making informed decisions by tracking their appliances’ energy use (when coupled with a HAN) and adjusting their overall energy use based on price signals provided by the utility. The utility can save operating costs by not having to employ meter readers. They can optimize energy distribution by using dynamic line rating technology, and also diagnose and fix line faults automatically.
As great as this sounds, there are numerous hurdles to be overcome in AMI adoption and utilization, and these hurdles weigh heavily on regulators. Are advanced meters cost effective, and on what basis? Who will pay for the new meters? Should everyone have a smart meter or only those who benefit the most? Should they be opt-in or opt-out, considering that some people have privacy concerns, and others assert that smart meters threaten their health? How do utilities get customers to utilize the technology? Who will have access to the data the meters produce - which is key to privacy concerns, but also to development of new business offerings that could benefit consumers?
Public Utility Commissions (PUCs) are now beginning to struggle with these questions. In Illinois, the Citizens Utility Board (CUB) and the Environmental Defense Fund (EDF) are asking the Illinois Commerce Commission to adopt an open data access framework, in which customers would be the principal owners of their energy data while the utilities would be the guardians of the data. This data access question is tricky, but supporters of open access point to the enormous potential for third party product offerings if even bulk, anonymized data were made available to the broader market.
In Massachusetts, the Department of Public Utilities (DPU), as part of its grid modernization proceeding, coined a new term, Advanced Metering Functionality (AMF), and ordered each electric distribution company to submit a 10-year grid modernization plan. The plans incorporate a short-term (five-year) roadmap that outlines planned capital investments, including the rollout of AMF across the state. By calling for AMF instead of AMI, the DPU is telling utilities that they want the capabilities that AMI offers but without prescribing any particular set of enabling technologies. In layman's terms, if a third party can develop a tool that can relay near real-time usage data by some other means other than smart meters, why stop them?
The New York Public Service Commission outlined its framework for AMI deployment in a February 2015 order under its Reforming the Energy Vision (REV) proceeding. The PSC for the most part aligned with the joint filings by AEE Institute, New England Clean Energy Council and Alliance for Clean Energy New York. The PSC adopted the Massachusetts terminology and said that AMF, as opposed to AMI, was preferred because it allows for a variety of enabling technologies and may be more readily supplied by competitive providers, avoiding the need for a ratepayer-funded rollout. They also touched on implementation issues, saying AMI/AMF will be considered on a case by case basis and that cost allocation will ultimately depend on who benefits - ratepayers and/or market participants. The PSC also noted privacy and health concerns by adopting an alternative opt-out program for customers. Finally, the PSC aligned with our position that utilities should work with third parties or contracted agents to use customer data in order to identify and make customers aware of cost effective saving opportunities. Implementation will be laid out in more detail in PSC staff guidance for the development of distributed system implementation plans on September 8.The bigger question facing PUCs is justifying the upfront cost of AMI, when full benefits may only be realized after programs are implemented that take full advantage of smart meter functionality. (This is a particular issue in jurisdictions that have already replaced old meters with automated reading meters, as eliminating manual meter reading is a major source of savings from meter replacement.) Still, based on a conservative analysis by the Edison Foundation, a utility with a service territory of 1 million households over a 20 year period could achieve operational savings of $77 million to $208 million, with consumer-driven savings of $100 million to $150 million and a net benefit of $21 million to $64 million, with far less than full customer utilization. Still, where smart meters have been installed, some people complain that they are paying a surcharge for new meters without seeing reductions in their bills. Unless utilities adopt (with regulatory approval) time varying rates that give customers price signals to reduce their usage and educate customers on the benefits of tracking their electricity usage, it is hard to show savings for customers.
To prove its value to regulators, and then to customers, AMI has to be paired with programs and rate structures that show benefits in customer engagement and bill savings . It shouldn’t be that hard to do. Utilities need to be incentivized to increase customer participation in demand response and TVR programs in order to improve reliability and resiliency and reduce peak demand, all facilitated by AMI. With consumers more technology savvy than ever before, the time is ripe.
For more information on AMI penetration for individual utilities check out AEE’s Powersuite under the utilities tab and click on advanced energy metrics.
