By R. Bryan Seal, P.E., SmartSynch Inc.
Advanced metering infrastructure (AMI) systems are upon us. Over the past 20 years many of us have dreamed about remote meter reading, automatic meter reading, customer communications or whatever the dream may have been called at a particular time. And it always seemed to be lurking just “within the next five years.” While utilities still struggle with initial costs and the fear of obsolescence, they see the vision as well as the value and are beginning to invest heavily in AMI technologies. Finally, AMI is here and is gaining ground.
Just to show how fast things are moving, Chartwell reports that in 2004 just over 60 percent of electric utilities were at least in the consideration stage of AMI, if not already planning, piloting or installing AMI systems. In 2006, the number had jumped to approximately 85 percent. A recent article in Electric Utility Week (7/16/2007) reported that the percentage of North American households with a smart meter will grow from 6 percent today to 89 percent by 2012, according to London-based research group Datamonitor. Whether or not this prediction is accurate (the skeptic in me is always leery of optimistic five-year predictions), the industry is undeniably growing fast and is here to stay.
So where is AMI (or whatever it might be called) going next? What do we hear in the singing rails as this train gains speed? Let’s consider just a few of the drivers and perhaps we can draw some conclusions.
The Grid Is Straining
According to the North American Electric Reliability Corporation, electricity demand will grow 19 percent nationwide over the next 10 years while transmission capacity will grow by only 6 percent. So what is a body to do? Back in 2001, former EPRI president Kurt Yeager noted, “We need smarter methods of electricity generation, transmission, and delivery-not just more power. This isn’t about stringing more wires, or rallying around to make today’s technology work better. That’s trying to put Humpty Dumpty back together again” (WIRED, June 14, 2001). Some critics may not agree, but I think he was right then and still is.
A new combination of approaches will be needed to meet this gap as well as the ramping up of infrastructure investment; to be sure, base-load generation and transmission will have to be constructed. But a major consideration in this equation is this: How can we leverage increasingly widespread communications technology to enable utility customers to see and understand their electricity consumption, avoid demand peaks, conserve electricity and spend less money? Have you ever shown someone what their real-time energy use is? I have. Once shown, they tend to immediately walk around the house turning everything off. Simple cause and effect.
Part of our energy crisis solution involves making it worth the customer’s while, through innovative time-based rates, to help manage energy use. Technology placed in the home to help customers see energy cost and manage their homes efficiently is necessary and a hot topic for many utility regulatory bodies.
We only have to look to the adoption of the personal computer and the Internet to see rapid and widespread acceptance of new technologies. According to Internet World Stats, the Internet presently has a 69 percent penetration rate in North America with other groups reporting a slightly higher number. Connecting to the Internet via personal computer is now part of the fabric of our lives. Consumers expect technology to change. The fear utilities and regulators may have that “grandma will not be able to use technology” seems today more and more unfounded. The reality is that grandma has a cell phone, a computer and maybe a TiVo. She’s hooked up to the Internet, at least by dial-up, and is checking out what’s on eBay and trading e-mail and pictures of the grandkids with everyone on her list. While she may be amazed by technology, she is certainly capable of adopting it. She and her children and grandchildren rely on technological change to make their lives better, and if the benefits of new technologies are apparent, they will continue to do so.
Governments Are Set
Over the past couple of years, those of us in the AMI industry have been following the Ontario Ministry of Energy’s mandate for electric utilities to install smart electricity meters in 800,000 homes and small businesses by 2007 and throughout Ontario by 2010. The underlying objective beneath this 4-million-plus meter point initiative is to create a culture of conservation. The initial goal of 800,000 meters for this year is well on its way to being met and has gone a long way in moving the AMI industry out of the doldrums of past years and has positioned Ontario to take the next step into the smart grid arena.
Today’s “smart meters” will form the foundation for the rapidly approaching “smart grid.”
Another part of the legislative puzzle in the U.S. is the Energy Policy Act (EPAct) of 2005, which also played a part in AMI’s advancement. As pointed out in a recent Chartwell report, EPAct 2005, rather than merely mandating time-based metrics, created a new awareness of time-dynamic rates and opened an important dialog between electric utilities and state regulators. During this process, everyone involved has become better educated about AMI’s benefits. For utilities seeking approval in implementing smart meters and AMI, this could lead to a more favorable commission climate.
For several years, the state of Texas has been aggressively pursuing open electricity markets. On the retail side, this is to be accomplished utilizing time-based rates and enabling customer choice. The key to making this all happen is-you guessed it-communication of time-based electricity usage data to customers, retail electric providers (REPs), and all other entities involved in the transaction. To obtain the desired electric meter functionality as well as the flow of information necessary for an even playing field and open market, the Public Utility Commission of Texas (PUCT), in a decree heard throughout North America, issued a set of smart meter standards that investor owned utilities (IOUs) in Texas must meet in order to recover smart meter costs. The minimum standards for smart meters include:
- two-way communications;
- a remote disconnect/reconnect capability for residential meters;
- providing time-stamped meter data for wholesale settlement;
- providing direct, real-time access to customer usage data to the customer and the customer’s REP;
- a means by which the REP can provide price signals to the customer;
- the capability to provide 15-minute or shorter interval data to REPs and other organizations needing such granular data;
- supporting American National Standards Institute (ANSI) C12.19 tables;
- supporting ANSI C12.22 communications protocol, including future revisions;
- the capability to communicate with devices inside the customer premises through a home area network (HAN) based on non-proprietary standards such as ZigBee or HomePlug; and,
- the ability to upgrade all these minimum capabilities as technology advances.
At the time of this writing, the U.S. House of Representatives is considering legislation to hasten the smart grid’s development. Called the “Smart Grid and Demand Response,” this legislation currently opens by saying, “It is the policy of the United States to support the modernization of the Nation’s electricity transmission and distribution system to incorporate digital information and controls technology and to share real-time pricing information with electricity customers….”
Yep, I think the smart grid movement is starting to roll.
So where do we go from here? I think this is becoming increasingly clear, but only time will tell. Having worked for an electric utility for 23 years, I know utility folks as very sharp, competitive and practical. They want technology to solve problems, not create them. Most don’t want to be early technology adopters, but neither do they want to run behind the pack. And any technology implemented must meet core business case requirements (in addition to billing reads, power outage, power restoration, etc.). The swing toward AMI has indeed been a significant step, but more is needed and more will surely be demanded.
I’ll venture a few predictions. Within the next year, AMI as we talk about it today will morph into the backdrop of the smart grid. When we say “smart grid” (or maybe “SG” because we love acronyms), we will mean AMI together with line monitors, capacitor control, automatic line switches, regulator controls, and a host of other ingredients, including front-end systems and web portals that will make up the smart grid strategy. No more requests for quotes for simply “AMI”; it will be for smart grid components, of which AMI will be an important subset. This should make for some interesting partnering in the industry.
And in this smart grid world, the meter will serve a dual purpose: it will be the portal into the home, and it will also be part of an array of intelligent electronic devices (IEDs) that will make up what will become the smart grid. These smart grid IEDs will necessarily extend into the home. Wide area networks and local area networks will connect and blend into home area networks. We see this happening in the PUCT order with real-time data access of meter data by the customer and REP. Also we see it in the House bill in the form of demand response equipment. But as on-site energy storage, distributed generation, and other technologies step into the limelight, utilities will have no choice but to play a major role in managing smart grid assets for the sake of overall system stability.
So how will all this connectivity be achieved? Good question. It will most likely be achieved with a variety of communications media, but one thing is certain: Utilities do not like being painted in a corner with proprietary systems. And the PUCT demonstrated that it doesn’t like utilities placing themselves in that corner either. Expect other commissions to follow.
The smart grid (whether utility side or customer side) will be built, in the end, on open systems and standard protocols. With the pervasiveness of the Internet, it follows that Internet technology will come to our rescue with each IED being Internet protocol (IP) enabled. But even some changes will need to happen here. Because of the number of IEDs deployed and increased security needs, IPv6 will move to the forefront. In the end, all devices deployed by the utility or customer will become part of one huge “collective.”
Whatever your vision for the future may be, the grid-the world’s most complex machine-will indeed become one of the world’s most interactive as it evolves into what we will soon refer to as the “smart grid.”
Bryan Seal joined SmartSynch in May 2005 to lead SmartSynch’s software, hardware and firmware development efforts as vice president of engineering and was named Chief Knowledge Officer in January 2007. Mr. Seal brings 23 years of utility distribution and meter engineering experience to SmartSynch from Mississippi Power Company (MPC), a subsidiary of The Southern Company. At MPC, he led the Metering Services Group’s automatic meter reading (AMR) projects from 1986 until 2005. Additionally, he served on The Southern Company Metering Services Technical Committee that oversaw all metering technology solutions deployed throughout The Southern Company’s four-state service region.