Navigant Research Blog

Smart Grid Deployments Moving Ahead in Latin America

— June 3, 2015

Smart grid deployments in Latin America have struggled to gain traction in recent years compared to North America or Europe. But that is starting to change. Significant projects in two countries—Brazil and Mexico—are moving ahead, with vendors being selected in recent weeks.

Brazil

Eletrobras, Brazil’s leading electric utility, has chosen several technology vendors for a smart grid project that involves six of the utility’s distribution subsidiaries. The utility selected Itron’s new OpenWay Riva solution that enables a single network to support two communications technologies (radio frequency and power line carrier) in the same device. The result is an adaptive system that can dynamically choose the best path for communicating based on network conditions, type of data, or application requirements. The solution is supported by Cisco’s IPv6 network infrastructure.

Other vendors selected for the Eletrobras project include Siemens, Telefónica, and Telemont. Approximately 115,000 endpoints are expected to be deployed at the six subsidiaries in the states of Alagoas, Piaui, Acre, Rondonia, Roraima, and Amazonas. The goal of the project is to reduce theft of service, a chronic problem in Brazil. Full implementation of the project is expected to be complete in 2017.

Mexico

In Mexico, Comisión Federal de Electricidad (CFE), the state-owned electric company, has selected a number of vendors for its smart grid project in Mexico City’s Central District. Silver Spring Networks was chosen to provide its IPv6 network, which enables connectivity to cabinets that house a group of centralized meters. In addition, vendors chosen to support the project include Elster and Tecnologias EOS. Elster will provide its EnergyAxis software and field network devices in addition to its REX2, A3 ALPHA, and mREX2 smart meters. A total of 300,000 meters are expected to be deployed, according to Elster. Similar to Eletrobras, the goal of CFE’s project is to reduce theft of service, which can be substantial. Nearly 15% of CFE’s total electricity production was lost due to theft or defaults in 2013, according to the utility, and in some areas of Mexico City, that figure surges to more than 35%.

Theft Reduction and More

Clearly, the main driver for smart grid deployments in these two projects is the same: theft reduction. But beyond that, the technologies being deployed lay a foundation for additional smart grid applications. For instance, Eletrobras has indicated it will add outage detection and analysis along with improved transformer load management. And while these two projects do not necessarily portend a wave of similar deployments, they do represent a next step toward grid modernization by leading utilities and are likely to be imitated by others across Latin America in coming years.

 

Doubts Surface About U.K. Smart Meter Rollout

— March 26, 2015

Serious doubts have surfaced about the rollout of smart meters in the United Kingdom, with a key government committee raising the issue to a new and alarming level. In its most recent report, the Energy and Climate Change (ECC) parliamentary committee concluded the program “runs the risk of falling far short of expectations. At worst it could prove to be a costly failure.”

The smart meter rollout is large, expensive, and complex. By 2020, a total of 53 million electric and gas meters are to be installed in some 30 million British homes and small businesses. The estimated cost is $16.2 billion, which is to be passed on to consumers. The cost is supposed to be offset by an estimated savings of $25.5 billion, in part from greater energy efficiency. One of the more complex features of the rollout is a communications infrastructure that aims to coordinate meter data among the energy suppliers, network operators, and authorized service providers. A government-appointed company called Smart DCC is charged with setting up this infrastructure.

Shaky Foundation  

The rollout is still in its early stage, called the foundation phase. The committee’s report expresses disappointment with several unresolved issues to this point: meters unable to communicate in multiple occupancy and tall buildings; interoperability issues among different types of meters and in-home displays; a shortage of installation engineers; network rollout delays by Smart DCC; and delays in public engagement around the program. So far, about 550,000 smart meters have been installed and are in use, which is about 1.2% of all domestic meters under management by the country’s largest energy suppliers.

The start of the next phase, called the mass rollout, has been delayed twice, as noted in a previous blog. As of now, the mass rollout is to begin in the fall of 2016. However, with this latest government report and the ongoing technical issues, that start date could slip once again.

Eventually, smart meters will be deployed widely in the United Kingdom. But given the complexities involved, it’s a good bet that the 2020 target will be missed—and perhaps by a wide margin.

 

ConEd Details Its Smart Meter Plan

— March 11, 2015

Con Edison, also known as ConEd, one of the largest U.S. investor owned utilities, has provided details of its planned rollout of smart meters over the next several years. Contained in ConEd’s recent rate filing with the New York Public Service Commission, the plan reflects a comprehensive strategy to make smart metering the backbone of future customer engagement, as well as improve outage restoration, enhance operational performance, and ease the integration of distributed energy resources such as rooftop solar.

The utility envisions an advanced metering infrastructure (AMI) deployment over 8 years at a cost of about $1.5 billion—about $8 million this year, $69 million in 2016, $174 million in 2017, $317 million in 2018, and $306 million in 2019. Projected spending details beyond that have not been made available. The approximate number of meters involved is 3.4 million.

Aligned With the Vision

Con Edison’s AMI deployment plan also aligns with the state of New York’s wide-ranging Reforming the Energy Vision (REV) initiative, which was announced last year by Governor Andrew Cuomo. The REV initiative is aimed at transforming the state’s electric grid into a more customer-oriented industry, featuring “market-based, sustainable products and services,” with an emphasis on enabling clean distributed power generation. Smart metering, with its two-way communications functionality, is a key technology for facilitating this type of flexible, modern grid.

Even though smart meters have been around for a number of years, no deployment lacks naysayers, nor controversy. Con Edison is likely to face opposition from consumers who have concerns over health risks, privacy, and the accuracy of the data smart meters provide—concerns the industry says are unfounded.

Take Your Time

For smart meter manufacturers and infrastructure players like Landis+Gyr, Itron, General Electric, Elster, and Sensus among others, the ConEd deployment represents a significant potential opportunity. The utility is expected to announce the bidding process in the coming weeks. Given the large scale of this project, it is possible the utility will choose several vendors or a primary contractor and various partners.

At 8 years, the anticipated timeline for ConEd’s smart meter deployment appears prolonged. Other large U.S. utilities—such as Pacific Gas & Electric, San Diego Gas & Electric, Oncor, and CenterPoint Energy—have rolled out smart meters in 4–6 years. But ConEd may be playing it safe, giving itself enough of a time cushion to overcome the inevitable hurdles and detours.

ConEd’s smart meter plan hinges on regulatory approval, but regulators are inclined to be in favor, especially since the deployment fits in with the state’s REV initiative. And despite the considerable costs involved, smart meters provide benefits to both customers and the utility, and tend to outweigh any drawbacks.

 

New York Details Its Vision for the Future of Energy

— March 2, 2015

On February 26, the New York Public Service Commission (PSC) released its long-awaited Phase 1 Order on its Reforming the Energy Vision (REV) proceeding. The order lays out the PSC’s vision for how the future retail electricity market in the state should operate to maximize efficiency, improve reliability, engage customers, and create clean, affordable energy products and services. I can’t cover the entire 328-page order in one blog, but I’ll hit on the major decisions that affect the current utility world order.

The biggest variable in the REV equation was whether the PSC would require an independent party to perform the function of the distributed system platform (DSP), the central role of REV. According to the order, the DSP’s functions include load and network monitoring, enhanced fault detection/location, and automated voltage and volt-ampere reactive (VAR) control. That list covers a lot of what the utilities currently do, so taking those tasks away from them would have caused a major shift in the market landscape. However, the Phase 1 Order outright supports utilities acting as the DSP as a way to minimize the redundancy of actions. This singular decision vastly limits the potential impacts to the state and the utilities. Utilities must be breathing a sigh of relief.

Metering Alternatives

A second thorny issue was whether utilities should be able to own distributed energy resources (DER) or whether DER should be the sole domain of the competitive marketplace. Many market players wanted to prohibit the utilities from competing with them when they might have a natural advantage in acquiring customers. Under the order, utilities will be able to own DER if they run a solicitation to meet a system need and they are able to show that competitive alternatives are inadequate or more costly than a traditional infrastructure alternative. They will also be able to invest in storage to the extent it functions as part of the transmission and distribution (T&D) system. This seems like a reasonable compromise that should work for most parties.

The last major component is advanced metering infrastructure (AMI). Earlier communications from the PSC hardly mentioned metering at all, so it was unclear how the final rule would play out. In fact, the Phase 1 Order does not mandate AMI deployment by utilities. Rather, the PSC prefers the term “advanced metering functionality” (AMF)—meaning that other technologies, including ones provided by third parties, may be able to achieve the desired functionality cheaper and more efficiently than AMI. It states that “each utility Distributed System Integration Plan (DSIP) will need to include a plan for dealing with advanced metering needs; however, plans that involve third party investment may be preferred over sweeping ratepayer funded investments.” This indicates that utilities should consider AMI alternatives before choosing a path forward.

Ticking Clock

As far as next steps, the utilities’ integration plans must be filed by December 15, 2015, so the clock is ticking. Phase 2 of REV will consider reforming the PSC’s ratemaking process so that utilities do not have disincentives to further developing DER. Utility income is tied to bond funds now, but they should depend more on creating value for customers and achieving policy objectives. A draft proposal is expected by June.

It was interesting trying to guess which way the PSC would fall on these and other major issues. Now the real fun begins: implementing the vision.

 

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