At first glance, 2014 wasn’t such a great year in the world of smart grid, with slowdowns in deployment of smart meters, distribution automation and other key new grid technologies, a lackluster record of VC investment compared to years past, and growing uncertainties over the financial viability of traditional utilities.
But these challenges also helped define the opportunities for companies, utilities and regulators working on building the next stage of smart grid — a “smart grid 2.0,” if you will. From building on the prior wave of investment in AMI networks and grid intelligence, to bridging the gaps between utilities and their customers, and laying the groundwork for a marriage of distributed energy and utility operations, 2014 saw some key developments that help indicate where the industry must go from here, if it’s to grow.
- Enabling the smart meters, from back-office analytics to in-the-field intelligence. Some 50 million smart meters have been deployed across the United States so far, and tens of millions more are coming to Europe, Japan, China and other big international markets. But are they being put to their fullest use? The past year saw a continued focus on enabling the first mass-deployed smart grid systems for uses beyond essentially functioning as a digital cash register. Some of the advances are operational, starting with the core data aggregation and network management capabilities to make sure the meters are functioning as expected, as we highlighted with San Diego Gas & Electric’s new AMI analytics effort, or the work Cisco is doing with AMI partner Itron and software startup Bit Stew. Others are expanding to using smart meters as voltage optimization sensors or transformer health monitors. On the broader analytics front, startups like C3, AutoGrid, DataRaker (bought by Oracle last year) Verdeeco (bought by Sensus in April) are lining up utility customers and metering partners with promises of advanced theft detection, energy disaggregation and other data-heavy applications now being tested in the field.
- Utility-engaged consumers and a utility-grade smart home. But customer-facing applications are the most popular way for utilities to put smart meters and their data to use today, according to GTM Research. The smart meter is a critical utility link to homes and businesses, and companies like Silver Spring Networks, Itron, Siemens’ eMeter and Toshiba’s Landis+Gyr are enabling more advanced load forecasting, consumer engagement, and demand response, as well as linkages to smart thermostats, solar inverters, electric vehicle chargers and other key distributed energy assets. Meanwhile, startups like Tendril, Opower, Ceiva, Alarm.com and others are tapping their home automation and connectivity expertise to deliver more energy insight and control to customers, and potentially to utilities as well. It’s all part of enabling more interactivity with customers and their energy systems as they become an increasingly important part of the grid equation.
- Renewable power and energy storage — and the smart grid to marry them. Among the biggest energy storage developments of 2014 is the marriage of solar PV and batteries as a potentially cost-effective grid-tied solution. GTM Research projects that the U.S. solar-plus-storage market will grow from $42 million in 2014 to more than $1 billion by 2018, mainly behind the meter, with companies like SolarCity, Sunrun, Enphase, SunPower, Sonnenbatterie, Sunverge, Solar Grid Storage, Panasonic and Sharp getting into the game. While these systems rely on building-side benefits and revenues to justify themselves today, we’ve seen efforts to link these behind-the-meter batteries as aggregated grid assets, with megawatts set for deployment in California, Hawaii and Japan. Smart solar inverters, now being run through their paces in pilot projects in California and Hawaii, could expand the capabilities of distributed solar systems as well. And utility-scale solar and wind power are starting to come with energy storage built in, as power quality, ramping capability and other “dispatchable” grid power capabilities become more important to utilities and grid operators.
- Microgrids and virtual power plants: From islands in the storm to nodes of the transactional grid? The term “microgrid” can mean many different things, from a simple backup power or onsite generation system at critical facilities like hospitals and military bases, to a complex interconnection of local solar power, batteries, combined heat and power (CHP) systems and integrated building energy management at more modern sites. GTM Research predicts that these more advanced microgrids will become an important part of the urban smart grid landscape, driving total U.S. capacity from 1,051 megawatts today to 1,843 megawatts by the end of 2017. In the wake of Superstorm Sandy, states including New York, New Jersey, Connecticut and Massachusetts have launched multi-million-dollar microgrid initiatives, and green-powered projects are starting to come on-line. Meanwhile, there’s another kind of microgrid meant to more or less always be connected to the grid — call it a virtual power plant, or VPP, for short. A new form of utility software platform, the distributed energy resource management system, or DERMS, is being created to manage this close connection between the utility’s distribution grid operations, and the energy and load control devices at the edges of the network. The past year saw some important strides made on projects of this nature, from community-scale microgrids at Toronto Hydro and Duke Energy, to DERMS deployments from SDG&E and New York utility Consolidated Edison, to regional VPPs like Canada’s PowerShift Atlantic project or France’s Nice Grid project. Providers of this software and integration expertise range from major grid players like Alstom, Siemens and General Electric to quiet specialists such as Spirae, Causam’s Power Analytics, Toshiba’s GRIDiant, and Integral Analytics.
- The virtualized distribution grid: Planning ahead, making it real-time. All of these technical capabilities will be important to the next challenge facing utilities and regulators on the grid edge. That’s adapting the nearly century-old rules for how grid and energy assets are built and paid for, and how the benefits of those investments are shared, in order to include distributed and customer-owned energy assets. In California, this process has taken the form of innovative long-term investment plans that allow utilities like Southern California Edison to sign power-purchase agreements with providers of distributed energy and aggregated energy storage systems, and a revamp of the distribution grid planning process that governs some $6 billion per year in infrastructure investments. Hawaiian utility regulators are taking similar steps, and New York state’s Reforming the Energy Vision process represents the most radical restructuring effort underway in the United States today. Other states are working on new value-of-solar tariff structures to create new ways to share the costs and benefits of rooftop solar. Meanwhile, solar-rich countries like Germany and Japan are facing similar challenges and working on their own sets of solutions.
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