Smart Charging

Today, the grid would be unable to cope if a large number of commuters arriving home plugged in their cars more at the same time to recharge them. Yet if those same cars were recharged at three o’clock in the morning, when demand is low, it would benefit both consumer (who would get cheap power) and producer (who would be able to sell otherwise wasted electricity.)

In the Future, Vehicle Batteries Could Provide Grid Storage

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Back to Electric Vehicle Index
1. Background
2. Acronyms/Definitions
3. Business Case
4. Benefits
5. Risks/Issues
6. Success Factors
7. Next Steps
8. Companies
9. Links

1. Background

• Due to energy security concerns, President Obama has called for bringing one million plug-in hybrid electric vehicles on the road by 2015. To make this a reality, we must prepare the smart grid for this plug in hybrid electric vehicle load. If we get a million electric vehicles on the road the impact in areas like California and the Northeast, where they’re going to be sold, will be dramatic. Managed charging is not a desirable, it’s a critical, mandatory thing we’ve got to achieve.
• The upgrade to the 240V/30A connection that is needed for "fast charging" is going to cost roughly $1500-$2000 per home, but guess what? Anyone that buys an electric vehicle is going to want one of these outlets. We live in the age of broadband, and nobody is going to accept the charger equivalent of a dial-up connection for their car. We have to expect that these loads increasingly will be part of the overall equation; it is only through smart grid technologies and systems that we will have a chance to flatten the overall load curve in attempting to keep electricity affordable and meeting our other societal commitments in the face of skyrocketing EV charging loads.
• Utilities will need to have real-time insight into what is happening on their distribution grids down to the transformer level. Having some kind of Distribution Management System (DMS) in place will be the only way grid operators will be able to spot, or to know in advance, if a circuit is overloaded or experiencing any difficulties that could lead to wider disturbances. A mass rollout of EVs without smart grid would be inviting serious trouble.
• How can we maintain the reliability of the electric system if we have a million plugged-in electric cars drawing electricity off the system at different hours of the day? How do we provide incentives for vehicles to charge during off peak hours? Is it a simple price signal or something more?
• The Electric Vehicle probably represents the highest unpredictable residential load. This is a challenge as the consumer will want to choose when to charge (or when charging should be complete) and the utility will want to manage the load per transformer, especially as we move towards fast charging. This requires intelligence and prioritization both in the EVSE and the meter while making it transparent to the user.
• Without an integrated communications infrastructure and corresponding price signals, handling the increased load of plug-in hybrids and electric vehicles would be exceedingly difficult and inefficient. Smart Chargers, enabled by the Smart Grid, will help manage this new energy device on already constrained grids and avoid any unintended consequences on the infrastructure.
• PHEV add a significant load, but it is comparable a typical household. Typical U.S. households consumed approximately 11,000 kWh annually in 2001. The addition of a PHEV with 5–10 kWh of useable battery capacity that is charged once per day could add an additional 21–43% (2200–4600 kWh) per year to the household electricity load, comparable to average central air conditioning and refrigeration loads.

2. Acronyms/Definitions

1. ECA - Energy Cost Application – Calculates HAN Device energy consumption cost. The application may use information from multiple sources including:
• The AMI Meter(s)
• The AMI System
• Customer HAN Gateway
• Other application(s)
• Other HAN device(s)
• Human Machine Interface(s) (HMI)
2. EVSE - Electric Vehicle Service Element - The EVSE provides the direct interface with the PEV, including a charger and information exchange capabilities. The charger can either be on-board the vehicle or off-board. On-board chargers require AC energy transfer to the vehicle (either 120 or 240V single phase) and Off-board chargers are within the EVSE.
   
   In addition to the safety concerns, EVSEs will, depending on their level of intelligence, ease the
   integration of plug-in vehicles into the grid and offer consumer benefits. Simple EVSEs can control charging start time. More complex units enable variable charge control based on pricing or grid loading process user identification and payment; handle vehicle-specific metering; enable vehicle diagnostic reporting; and in the future will control vehicle-to grid capacity, among many other novel, and as yet unimagined functions.
3. Green Charging - Linking the electric vehicle charging to renewables production. The people who buy electric vehicles are going to be people who are motivated to reduce their personal carbon consumption, so they’ll be the kind of folks who would want to run their car with renewable energy. So how do we somehow? One of the Detroit automakers is looking into contracting for wind farms. And in the dealership, when you go buy the car, they’ll ask you do you want to sign up for our wind farm? They are not expecting to make money off the energy, but are promoting the value to the consumer of the car.
4. Grid-Aware Vehicles -Communicate driver requirements, battery requirements, SOC, etc. Grid and external inputs Schedule charging per driver, grid needs.
5. HomePlug Green PHY - A new specification that is a subset of HomePlug AV and is specifically designed for the requirements of the smart grid market. It has peak rates of 10 Mbit/s and is designed to go into smart meters and smaller appliances such as HVAC/thermostats,, home appliances and plug-in electric hybrid vehicles.[10] so that data can be shared over a Home Area Network (HAN) and back to the utility. For these applications, there’s not a great need for high capacity broadband; the most important requirements are for lower power, robust, reliable coverage throughout the home, smaller size and less costly Bill of Materials. GreenPHY uses up to 75% less energy than AV.[10] The HomePlug Powerline Alliance worked closely with utilities and meter manufacturers to develop this 700-page specification (downloadable from the HomePlug website). HomePlug Green PHY-based products will be fully interoperable with products based on HomePlug AV, IEEE 1901 or the upcoming HomePlug AV2 specification.
   
   In October 2011, Audi, BMW, Daimler, Ford, General Motors, Porsche and Volkswagen agreed to use HomePlug GreenPHY as the communication protocol for smart charging. This approach will facilitate integration of the electric vehicle into future smart grid applications
   
6. IBP - Increasing Block Pricing - May discourage PV adoption, The current IBP schedule does not account for energy savings and environmental benefits that may be gained from fuel switching from gasoline to electricity.
7. Orphaned Charge - A device that incurs a cost at a premise other than its registered, “home” premise and generates a billing charge to be reconciled through the Utility System. This term refers to proper premise association. For example, a plug-in hybrid that charges at a grocery store or a friend’s house.
8. SAE – Society of Automotive Engineers - Publishes automotive related standards in North America.
   
9. SAE J2836/1: Use Cases for Communication between Plug-In Vehicles and the Utility Grid. The standard, published in 2010, establishes use cases for two-way communication between plug-in electric vehicles and the electric power grid, for energy transfer and other applications.
   
   It also provides a set of communication requirements for use with various load management and rate programs that will be established by utility companies related to the charging of plug-in electric vehicles. The various utility programs will enable consumers to charge their vehicles at the lowest cost during off-peak hours, and helps the utilities reduce grid impacts by minimizing electric vehicle charging during peak periods.
10. SB 626 (Kehoe) Electrical Infrastructure Plug-in Hybrid and Electric Vehicles - This law passed in 2009 requires the CA Public Utilities Commission, in consultation with the CA Energy Commission, the CA Air Resources Board, electrical corporations, and the motor vehicle industry, to to develop infrastructure sufficient to overcome any barriers to the widespread deployment and use of plug-in and electric vehicles, and to adopt rules by July 1, 2011, on specified matters, including infrastructure upgrades necessary for the widespread use of plug-in hybrid and electric vehicles.
11. Trickle Charge - A method of recharging in which a secondary battery is either continuously or intermittently connected to a constant current supply that maintains the battery in a fully or near full charged condition. Typical trickle charges are between 0.03C and 0.05C.
12. V1G – Grid to Vehicle One Way Communication - Utilizing Electric Vehicles in demand response include providing proportional charge rate signals.
13. V2G –Vehicle to Grid - Letting the vehicle take and give power back to the grid Electric utility may be willing to purchase energy from customer during periods of peak demand.
14. V2H - Vehicle to Home– Linking the car to house rather than the grid. This potentially provides three benefits: it obviates the issue of exporting energy back to the grid; can reduce demands on the grid as a supplementary supply to the house; and could also provide emergency backup in the event of power outages.
15. V2L - Vehicle to Load - Use of the PEV storage to provide power to a remote site or load that does not otherwise have electrical service. Examples include construction sites or camp sites.
16. V2V – Vehicle to Vehicle - Use of the PEV storage to transfer electrical energy to another PEV

3. Business Case

• Analyst John Gartner of Pike Research anticipates that a growing need for “intelligent management” of electric vehicle charging will create a $297 million industry in the U.S. as of 2015. That forecast encompasses the market for tech ranging from applications, servers, networking equipment and other hardware, to ongoing services for collecting and monitoring data about vehicle charging. Globally, he expects revenue from EV management to climb to $1.5 billion in 2015, up from $383 million in 2010.
• Widespread consumer charging of PHEVs during peak periods in the day, for example, could increase peak load and increase utilities’ operational costs. The development of a Smart Grid is therefore vitally important to utilities, since it entails the intelligence to send signals to consumers on when to charge their vehicles or provide differentiated rates to encourage off-peak charging.
• To manage limited range and long charge time, the electric car must be smart
• Learn typical travel routines
• Up to date on travel plans
• Interact with grid and decide at real time if it can help or if it needs help
• Have up-to-date charge stations and optional locations Recommend best course of action Information cached while in your garage
• Know if to charge or discharge into house/work/hotel Process dynamic pricing information from charge station
• Integrate with spouse car to plan daily and weekly charging Keeps up to date on your weekend plans Talk to your refrigerator
• Use weather forecast to predict Relying on house solar Home energy needs
• Manage credentials and repel attacks
• In the new world of plugs-ins, your car should be able to sell energy you don't need back to the grid during times of peak power demand, such as in late summer afternoons, when both office buildings and homes are running air conditioning. Today, that peak demand is served by older, usually dirtier and less-efficient "peaker" generators that utilities fire up when needed. A national fleet of a million or more EVs, most sitting idle roughly 90 percent of the time, could serve as a massive national storage device that can be tapped as needed to meet peak demand.
• When the customer plugs the PEV into the grid at a location different from their “home” location, different scenarios will address who and how the PEV charging will be accounted for and billed. These roaming scenarios include:
1. The customer connects their PEV to the energy portal at another premise. The premise customer pays for the energy use.
2. The customer connects their PEV to the energy portal at another premise. The PEV customer pays for the energy use directly with the utility, such as with a credit or debit card. In this scenario, the customer would get billed at the rates in their PEV tariff.
3. The customer connects their PEV to the energy portal at another premise outside the enrolled utility's service territory. In addition to the previous 2 scenarios, the customer could become a “guest” of the external utility and pay rates as such a guest, or could indicate the PEV program they are enrolled in at their “home” utility, and pay those rates. The external and “home” utilities would then make a settlement between them on any differences.
4. The customer with a PEV that is not enrolled in any program (or cannot prove enrollment) connects their PEV to the energy portal at another premise. Either private party arrangements would be needed (first scenario) or “guest” arrangements (third scenario) would be used for payment.
5. The customer connects their PEV to the energy portal at a public location, multi-family dwelling, or workplace infrastructure. Either private party arrangements (first scenario) or direct utility interactions (second scenario), or “guest” arrangements (third scenario) would be used for payment.
• This kind of intelligence can be enabled by the Electric Vehicle but participation of a Clearing House and a nationwide effort on a common standard is also needed. Utilities need to be able to manage vehicle charging as with other major smart appliances (home A/C, pool pumps, refrigerators, etc.) and to verify the PEV load –to implement Smart Charging.
  
  
• The automotive and utility industries have agreed for PLC- (power line carrier-) based wired interface to be the physical interface between the PEV and the AMI/HAN, with the PLC(HomePlug AV or IEEEP1901 are the currently adopted technologies) transceiver chipset and associated Smart Grid communications “application layer” software with requirements defined by SAEJ2836/J2847 and SE2.0, residing onboard. That would include a PLCto X bridge residing off-board, with X being the transport layer of the AM I/HAN network, which also implements SE2.0- based messaging as the application layer.
  
  EPRI estimates the per-vehicle cost overhead for PLC transceiver is about $20 per vehicle in the near term, reducing to $10 per vehicle longer term, as PLC is already a very widely deployed technology. On the PLC to X bridge aspect, the X in most cases is ZigBee, but WiFi (802.11x-based) is also rapidly emerging as the HAN contender. The per-unit PLC/ZigBee or PLC/WiFi chipset prices vary between $10 and 20 per unit as well.
  
  Given that there are likely to be 1.2 charging stations long term for every PEV sold, the per-PEV PLC to X bridge costs will run to $12 to $24. Therefore, the per-PEV infrastructure costs will run to between $25 and 50 for long-term and short-term volumes respectively. Assuming 2030 PEV installed base volume to be about 10 million vehicles, the cost of deploying Smart Grid infrastructure will approach $250 million ($25 per unit times 10 million
  vehicles) in 2030.
  

4. Benefits

1. Utility Gains
• Reduced grid stress
• Aggregated Distributed Applications can be “loads as resources” to help with renewable integration
• Robust anti-islanding
• Shared benefits with vehicle owner and manufacturer (like HVAC incentive programs)
2. Vehicle Owner Gains
• Lower-cost ‘electric fuel’
• Greener vehicle
• Grid-tied (V2G) See Blog
3. Vehicle Manufacturer Gains
• Reduced-cost charging for vehicle customer
• Green product-line enhancements

Smart Charging Helps – If Done Right
Badly Managed Charging Worse than Uncontrolled Charging Source: EPRI

5. Risks/Issues

• Fast Charging- Simultaneous fast charging of a significant number of EVs, directly from the grid, will impact on the grid and local distribution particularly at the peak generation period. Fast Charging equipment can charge at up to 500V and 125 amps, or 62.5 kilowatts (kW). Charging just one vehicle at this rate is equally to approximately 43 vehicles being charged via Level 1 (aka standard household current) or 9-18 vehicles at Level 2 using charging equipment. Complicating matters is that DC charging is by necessity immediate – delaying a 15-30 charge defeats the entire purpose. Plus, these charge locations are likely to be at truck stops, gas stations, or mini-marts, which aren’t places that most folks plan on spending a lot of time.
  
  While DC charging is a much bigger drain on the grid, charging stations won’t ordinarily be placed to impact residential transformers or transmission lines But if fast charge spots are connected to substations that experience peak demand, the potential for making a bad situation worse exists. For example, in California, the average peak demand per household in most service territories is between 1.3 and 1.9 kW, so one DC charging station is tantamount to about 30-45 houses.
  
  Fast charging stations will need to be planned to reduce any grid impacts, and located in areas where distribution networks can cope or are able to be reinforced. An alternative is to provide local energy storage (e.g. batteries or flywheels) at the charging station. These could be trickle charged from the grid at times of low grid utilization, and provide high energy transfer rates direct from the local storage. The capital cost of the charge stations is likely to be higher using this technique, although this could be balanced by the reduced need for grid reinforcement.
  
  If a consumer wants to charge her EV at 4pm on a hot afternoon, is a fast charge permitted at a full rate, partial rate (and how does that impact how much she pays?), or is it delayed? Whatever the choice, someone’s not going to be happy.
  
  
• Local Power Distribution Issues - There’s plenty of aggregate power capacity, but not in local areas. Five plugged in PEVs on the same street plugged can create a problem. They also need to verify and measure value –utilities want to pay incentives for verifiable conformance to load management programs. EVs are likely to be owned and used in city centers. These clusters of EVs could potentially all connect to the grid simultaneously, which may require the local distribution system to be reinforced. A detailed analysis of the local situation regarding distribution should be carried out in these areas, along with a series of pilot studies to assess the real-life effects of vehicle charging.
  
  
• Consumer Preferences - For consumers the preferred time (without any incentives to change their preference) is likely to be as soon as they are within easy access of a plug. This is both most convenient since they are at the vehicle already, and also improves their options since they may need the vehicle soon and would prefer a more fully charged battery.
  
  
• PEV Charging Needs to be Managed in Non AMI Territories - Hydro Quebec and large segments of United States will not deploy AMI anytime soon –but desire alternative options for load management of PEVs (i.e. OnStar) PLC offers several options capable of vehicle communications including: Eaton Smart Outlets with Home Heart Beat System, and Car Connect (Cordset Adapter)
  
  
• Regulatory Constraints - Currently regulations do not permit electricity to be resold. This means that all the accounting and settlement issues must be handled by utilities (or energy service providers) without the middleman reseller as is the normal market method. This puts the burden on the utility to manage the complex accounting and settlement processes usually handled by credit card companies or other retail accounting providers. However, if regulations were to change to allow the unbundling of electricity so that stored electricity could be resold, then the accounting model would change dramatically, since normal retail methods could be used.
  
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• Pricing Constraints - The current IBP schedule does not account for energy savings and environmental benefits that may be gained from fuel switching. Households using PEV's would be increasing their overall energy efficiency and conservation through switching from gasoline to electricity.
  
  
• Mobile Billing — it may be one thing for me to charge my EV at or near my home in El Cerrito. But what if I drive to Reno? Will I be able to buy and sell electricity in another state — or even another utility district in my own state? Much like the early days of cell phones, where calling from outside one's home territory resulted in onerous fees — remember roaming charges? — there's the potential for EVs to lose their luster if they can't affordably do buy and sell power wherever you go.
  
  
• Visibility - PHEV and EV load is behind the meter and there is currently no separate measurement and control.
  
  

6. Success Factors

• Dynamic Pricing - TOU rate, Demand Response, and Real Time Pricing signals Enabled through AMI would allow customers to recharge vehicles at reduced cost during off-peak hours. Communication of utility rate tariffs to the customer.
• Bi-directional Metering - Allows customers to purchase energy at off-peak hours and sell unused, stored energy back to the utility during peak periods at higher rates.
• Integrate billing systems while roaming including parking lots, work, malls friends
• Public Education - Can customers be encouraged to charge when it’s “best” for the utilities? Requires understanding consumer habits and market expectations.
• Identity Management - Data Collection –Expectations for road taxes and carbon credit allowances –Needs to evolve

7. Next Steps

• Model Impact of PEV’s on the Grid - Develop processes to model PEV impact on the grid operations along with impacts of other widespread distributed resource impacts (local storage, high penetration PV, demand response as a distribution resource, etc.) – NIST plans to work with DOE to explore the business and technical impact of these widely distributed resources (including aspects of PEV as highly portable demand/storage) on the grid with the objective of mitigating severe contingencies due to the widespread adoption and use of these technologies. Ensure that work includes transactional elements (settlement when charging/discharging away from “home”.

8. Companies

1. Ford - Has developed an intelligent charging system that previews how its production vehicles will interact with the grid. The unnamed system enables all-electric and plug-in hybrid vehicle owners to restrict charging to when electricity prices fall below a certain threshold, or even “when the grid is using only renewable energy such as wind or solar power,” according to Ford.
   
   Being able to drive “emissions free” could be a huge selling point for the upscale and eco-minded early adopters who will be buying EVs and plug-in hybrids during the next few years. There’s a natural synergy for customers to put solar on their homes and buy hybrids/EVs, who can then drive free of fossil fuel guilt.
   
   In its ongoing testing of converted PHEV Ford Escapes, the company is leveraging communications systems it designed including SYNC, SmartGauge, and Ford Work Solutions. The vehicles are communicating with the grid through smart meters over a wireless network using the Zigbee protocol, but Ford hasn’t committed to a network platform for its production vehicles.
   
   Ford has lined up some impressive utilities to help with the tests, including Southern California Edison, American Electric Power, Progress Energy, and 10 others, which will each receive some of the test fleet. The agreement is to continue testing for three years, which is interesting because the company plans to have a commercial PHEV for sale in 2012 — you might think that testing of PHEV grid interaction would be moot at that point. Ford received $30 million in DOE grant money to pay for part of the testing.
   
   
2. General Motors' ATOMS (OnStar Advanced Telematics Operations Management System) In July 2011, GM announced the launch of a pilot program that can let utilities and customers skip the need to install physical smart grid points to manage recharging of their EVs. The new OnStar service will act as a remote brain, wirelessly tracking and governing the EV's charging behavior, coordinating the timing and billing, and potentially dramatically lowering the costs to extend smart-grid management features to EVs.  GM estimates that by skipping the need to install physical smart apparatus, the OnStar system can save utilities some $18 million per 1,000 customers. Since it doesn't matter whether the EV is connected to a smart-grid charge point, OnStar should let utilities more accurately model how to manage peak versus non-peak charging too.
• Data Gathering - With customer permission, OnStar will provide the utility with overall charge level as well as charging history—by time and location—for the Volt pilot fleet, without the vehicles having to connect to a charging station. This will give the utility better insight for forecasting demand, setting rates and determining the best location for charging infrastructure
• Demand response - OnStar will allow the utility to actively manage EV charging for those who opt in to the service. The utility can then reduce peak loads by offering discounts or other incentives to encourage drivers to charge their EVs when overall electricity demand is lowest, typically in the early morning hours.
  
  
  
  
  
  
3. General Electric Digital Energy Atlanta, GA - General Motors’ OnStar announced at the Plug-In 2011 conference, that the company’s wireless vehicle communications platform is being connected to General Electrics’ Grid IQ Demand Optimization System. Data from thousands of Chevrolet Volt PHEVs will be made accessible to GE’s software, which is used by utilities for managing the load on the power grid. By enabling the platforms to share information in both directions, utilities can incorporate Volts into their existing systems for shedding load while studying customers’ driving and charging habits.  An aftermarket version of OnStar, to be sold by Best Buy, was announced in July 2011, enabling owners of competing models to use the communications system. While other PEV makers are developing their own wireless communications platforms, new models could incorporate OnStar as their platform and gain access to GE’s utility platform as well.GE is purchasing 25,000 PEVs, including 12,000 that will be leased by its fleet customers, including utility companies (GE Finance has a large fleet business). The smart grid pilot program, which will start with one unannounced utility, will provide access to charging history – including location, time, and amount of energy consumed by the vehicle – and will be made available to understand how PEVs will impact the grid.
   
   
4. Juice Technologies - Columbus, OH - A leading provider of products and technologies that enable the intelligent charging of electric and plug-in electric vehicles as well as products to optimize home and business energy use. Juice Technologies' products are sold under the brand Plug Smart and are distributed worldwide through electric utilities and the consumer electronics channel.
   
   In February 2010 GE and Juice Technologies announced a joint development agreement to create intelligent plug-in electric vehicle (PEV) charging devices for U.S. and global markets. The chargers integrate GE's smart meters with Juice Technology's Plug Smart(TM) engine to help consumers charge their cars during low-demand, lower cost time periods.
   
   
5. GridPoint , Arlington, VA - Developing version 3 of its Smart Charging software (due to ship to customers in September) that will schedule and monitor vehicle charging while keeping track of the grid’s health. The software includes tools that enable utilities to understand how vehicles individually and in aggregate are impacting power demand. Utilities can compare recent vehicle demand on the grid with what would have happened with no control over vehicle charging to see how well their attempts at shifting the load are doing. The Smart Charging software also provides day-ahead demand projections based on previous charging data.
   
   For over two years, GridPoint has been delivering the smart grid software utilities require to easily and cost-effectively support the wide-scale adoption of plug-in vehicles. GridPoint, Inc. received $15 million of VC funding in 2008 for their management of distributed storage, renewable generation, and load, bringing the firm’s total funding to over $100 million.
   
   
6. Silver Spring Networks, Redwood City, CA -  Unveiled in January 2011  a prototype tomorrow of a charging station enabled with its technology for the 2012 Toyota Prius Plug-In Hybrid. The charging stations are made by ClipperCreek and are a part of a smart grid and electric vehicles pilot announced in July 2011, in conjunction with PG&E and Electric Power Research Institute. The pilot aims to integrate electric vehicle charging with Silver Spring’s smart grid platform, allowing for the charging station to relay electricity usage data to PG&E. From there, PG&E can monitor energy usage of the charger (looking at it separately from the energy consumption of the home), and also give consumers a snapshot of their charger’s energy use.
   
   
7. Virtual Vehicles Company - Virtual Test Drive, still in beta testing, uses smartphone GPS functions to monitor driving patterns. The app then feeds the data into a website, which analyzes factors such as routes, cost savings and range issues to suggest which EVs would be best suited to the driver
   
   

9. Links

1. Connectivity Week 2010 - Plug-In Electric Vehicles
2. BERR – UK Department for Business Enterprise and Regulatory Reform - Investigation into the Scope for the Transport Sector to Switch to Electric Vehicles and Plugin Hybrid Vehicles October 2008
3. California's Cooperative PHEV Research Center - UC Davis is the new hub of collaboration and research on plug-in hybrid electric vehicles in California. The university’s new Plug-in Hybrid Electric Vehicle (PHEV) Research Center, administered by ITS-Davis, is funded by a three-year, $3 million grant from the California Energy Commission’s Public Interest Energy Research (PIER) Program
4. Yang, Christopher and Ryan W. McCarthy (2009) Electricity Grid: Impacts of Plug-In Electric Vehicle Charging. Environmental Management 2009, 16 - 20
5. Plugin2010.com – San Jose (July 26-29, 2010)

Ancillary Services Markets

How will frequency regulation and load management be monetized?

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Back to Markets & Pricing Index
1. Background
2. Acronyms/Definitions
3. Business Case
4. Benefits
5. Risks/Issues
6. Success Criteria
7. Frequency Regulation Technologies
8. Companies/Organizations
9. Next Steps
10. Links

1.Background

• Frequency regulation service is the injection or withdrawal of real power by facilities capable of responding appropriately to a transmission system operator’s automatic generator control (AGC) signal. When dispatched generation does not equal actual load plus losses on a moment-by-moment basis, the imbalance will cause the grid’s frequency to deviate from 60 Hertz, the standard in the U.S. While the system does deviate from 60 Hz in the normal operation of the grid, frequency deviations outside an acceptable range negatively affect energy consuming devices; major deviations caus generation and transmission equipment to disconnect from the grid, in the worst case leading to a cascading blackout. Frequency regulation service can help to prevent these adverse consequences by rapidly correcting deviations in the transmission system’s frequency to bring it within an acceptable range. The system operator calibrates the AGC signal sent to frequency regulation resources to respond to actual and anticipated frequency deviations or interchange power imbalance, both measured by area control error (ACE)
  
  
• Today, frequency regulation is largely provided by generators (e.g., water, steam and combustion turbines) that are specially equipped for this purpose. Provision by other resources is emerging, as technologies develop and tariff and market rules adapt to accommodate new resources. For example, the Texas Interconnection and MISO currently use controllable demand response in addition to generators to provide frequency regulation service. Such “regulation capable” generation, storage devices, and demand response resources can respond automatically to signals sent by the RTO or ISO, through AGC, to increase or decrease real power injections or withdrawals and thereby correct actual or anticipated frequency deviations or interchange schedule imbalance, as measured by the ACE. The faster a resource can ramp up or down, the more accurately it can respond to the AGC signal and avoid overshooting. Alternatively, when a resource ramps too slowly, its ramping limitations may cause it to work against the needs of the system and force the system operator to commit additional regulation resources to compensate
  
  
• The United States Federal Energy Regulatory Commission (FERC) defines the ancillary services as: "those services necessary to support the transmission of electric power from seller to purchaser given the obligations of control areas and transmitting utilities within those control areas to maintain reliable operations of the interconnected transmission system." and identifies six different kinds of ancillary services:
1. scheduling and dispatch
2. Reactive power and voltage control
3. Loss compensation
4. Load following - slower-ramping resources that ramp with the load over a five minute period
5. System protection
6. Energy imbalance
   
   
• In the RTO and ISO markets, compensation for frequency regulation service has been based on several components. Depending on the RTO or ISO, these payments include consideration for capacity set aside to provide the service as well as some of the following:
  
  • the net energy that the resource injects into the system
    
  • accurately following the RTO’s or ISO’s dispatch signal
    
  • the absolute (rather than net) amount of energy injected or withdrawn.
    
    
  These payments are intended to cover the range of costs incurred in providing frequency regulation service, e.g., operation and maintenance costs, and loss of potential revenue from foregone sales of electricity.
  
  
• The payment for capacity is essentially an option payment to the resource to keep a certain amount of capacity out of the energy or other markets in order to provide frequency regulation service, typically based on a market clearing price per MW of capacity sold. ISO-NE, NYISO, MISO, California ISO, and PJM incorporate into this payment the opportunity cost of foregone energy sales incurred by a resource that provides frequency regulation service. However, ISO-NE and PJM do not apply the opportunity cost payment uniformly to all cleared resources, but rather make ex post resource-specific opportunity cost payments.
  
  
• Compensation for frequency regulation service also includes payments or charges for the net energy the resource injects into or withdraws from the system. All RTOs and ISOs currently provide a payment for the net energy injected by a resource providing regulation service during the operating hour, calculated as the amount of energy injected less energy withdrawn multiplied by the real-time energy price.
  
  
• Accuracy of performance can also be incorporated into payments for frequency regulation service. Currently, NYISO incorporates accuracy into its compensation for frequency regulation service through a penalty that reflects the accuracy with which the resource follows its dispatch instruction. This is done through a performance index that tracks how accurately a resource follows the dispatch signal.
  
  
• On October 20, 2011, FERC issued a final rule establishing a two-part market-based rate compensation methodology for the provision of frequency regulation service in RTO and ISO markets. The cost of providing regulation service generally is borne by customers serving load in the balancing authority area where the relevant resources are located. At present, different markets have different methods for compensating providers of frequency response service. Order No. 755 reforms the approach used to compensate these suppliers.
  
  

2. Acronyms/Definitions

1. ACE – Area Control Error – Measures frequency deviations and interchange power imbalance. A measure of the quality of operation of the grid. ACE must be kept within grid operating requirements.
   
   
2. Ancillary Services - Balancing services used to balance generation and demand in tightly limited situations to maintain the alternating current (AC) system frequency of 60 Hz. Energy storage is perfectly suited to provide this service by absorbing electric energy (charging cycle) whenever there is too much generation for a given demand and by injecting electric energy into the power grid discharging cycle) when there is too little generation. Traditionally, these services have been performed by conventional gas or steam turbine technologies. But rather than varying the torque of large rotary turbo-machinery on a second-by-second basis, electrochemical EES is much better suited to quickly respond to the grid needs.
   
   
3. AGC - Automatic Generator Control - Frequency regulation service is the injection or withdrawal of real power by facilities capable of responding appropriately to a transmission system operator’s AGC signal.
   
   
4. Ancillary Services Demand Response
• In the Ancillary Services DR market, end-use customers are allowed to bid load curtailments in ISO/RTO markets as operating reserves. Accepted bids are paid the market price for committing to be on standby. In order to participate in ancillary-service markets, end-use customers must be able to adjust load quickly during a DR event. The response requirement depends on the nature of the event and the type of reserve being supplied.
  
  
• Loads typically have a very short response time, usually specified in minutes, rather than in hours. These short timeframes and program requirements limit the type of resources that can participate. End-use loads that qualify for participation as an ancillary services option could include large industrial processes that can be curtailed safely and quickly without harm to equipment. Examples of loads are air products or electric arc steel furnaces, large water pumping load, or remote automatic control of appliances such as air conditioners.
  
  
• End-use customers participating in the ancillary services market receive a capacity payment for committing loads to be on standby. The capacity payment is based on the market clearing price for capacity (MCPC). If load curtailments are needed, and they are called by the ISO/RTO, participants are paid the spot-market energy price. There is typically a higher minimum size for reductions and customers are required to install advanced real-time telemetry because of the stringent program requirements.
  
  
• End-use loads that qualify for participation in the ancillary service option require capability to respond to an event notification that is going to occur within 30 minutes of the notification.
  
  
5. Dispatchability - The ability of a given power source to increase and/or decrease output quickly on demand. This should be contrasted with certain types of base load generation capacity, such as nuclear power, which may have limited capability to maneuver or adjust their power output, or intermittent power sources such as wind power which cannot be controlled by operators. The time periods in which dispatchable generation plant may be turned on or off may vary, and be considered in time frames of minutes or hours.
   
   In general, when a resource submits its frequency regulation bid to the RTO or ISO, the bid is typically required to include its ramp rate in MW/min, its cost per megawatt-hours (MWh) of ramping ability, and the total capacity it is offering for frequency regulation.
   
   The resource’s total amount of capacity is based on and limited by its ability to ramp up or down. For example, a resource with a relatively large amount of capacity, but a relatively slow ramp rate would be limited in how much capacity it could offer as frequency regulation capacity. If the resource can ramp one MW per minute, it would only be able to offer five MW of regulation capacity (for a five minute dispatch) regardless of its total capacity. On the other hand, a smaller capacity, faster ramping resource might not face such a constraint. For instance, a storage device that can hold a 20 MW charge and ramp at 10 MW per minute, could offer its full 20 MW of capacity for five minutes.
   
   
6. Dispatchability - The ability to provide a DR-inducing signal within a limited timeframe. Some argue that dispatchability is a requirement of a DR option. Time-of-use (TOU) rates are sometimes considered a demand-response option. TOU rates are non-dispatchable and produce a consistent reduction in peak demand.
   
   
7. FERC Order 755 - Issued October 20, 2011 - Pursuant to section 206 of the Federal Power Act (FPA), ;the Commission is revising its regulations to remedy undue discrimination in the procurement of frequency regulation in the organized wholesale electric markets and ensure that providers of frequency regulation receive just and reasonable and not unduly discriminatory or ;preferential rates.
   
   Order No. 755, generators or other entities providing this service will be compensated in a two-part structure. 
1. Capacity Payment  - Regulation service providers will receive a capacity payment reflecting the opportunity costs of the marginal resource providing frequency regulation service during the settlement period. This approach acknowledges that a frequency response resource must hold some of its capacity in reserve to provide frequency regulation service when such service is needed, and therefore the resource forgoes the revenue it could otherwise earn through energy market sales.
   
   Order No. 755 also allows for the recovery of inter-temporal opportunity costs, such as costs incurred by an energy storage device that must provide frequency response service at a time of day when it would be more cost-effective for it to buy energy to recharge the storage device. Order No. 755 leaves the specific methods for calculating such opportunity costs to individual regional markets, explaining that the operators of the separate regional organized markets are "in the best position to perform accurate cross-product opportunity cost calculations." With regard to inter-temporal costs, Order No. 755 requires that such costs be verifiable, but it allows individual regional market operators to determine whether these costs should be determined by the ISO or RTO or by market participants.
   
   
2. Performance Based - The second component of regulation service compensation is "performance-based" and will reflect the amount of the up or down movement a resource provides in response to the system operator's dispatch signal and the resource's accuracy in responding to the dispatch signal. This approach accounts for the fact that a resource with faster ramping capability can provide a greater amount of capacity into the regulation market than can a slower-ramping resource.
   
   
8. Frequency Regulation - Electric frequency must be maintained very close to 60 hertz (Hz), or cycles per second (50 Hz in Europe and elsewhere). When the supply of electricity exactly matches the demand (or "load"), grid frequency is held at a stable level. Grid operators, therefore, seek to continuously balance electricity supply with load to maintain the proper frequency. They do this by directing about one percent of total generation capacity to increase or decrease its power output in response to frequency deviations.
   
   
9. ISO - Independent System Operator - In a deregulated marked, although utilities retain the ownership of transmission lines, they no longer control access to them. This responsibility has been transferred to a non-profit organization called an "Independent System Operator" which controls transmission of all electricity in the region.
   
   An RTO or ISO is defined as an electric utility regulated by FERC, and most are non-profit. It is
   funded by a grid management charge approved by FERC and paid by generators and load serving entities within the RTO/ISO’s balancing authority. It operates the electric transmission acilities under its authority in compliance with NERC approved mandatory reliability standards. In so doing, it provides nondiscriminatory access to transmission services for all qualified market participants.
   
   Historically, some RTO/ISOs evolved from power pools, for example PJM, while others were created by state legislation which also mandated electric industry restructuring, for example CAISO, or through other voluntary associations, such as the Midwest ISO.
   
   An RTO/ISO designs and administers within its balancing authority several types of auction markets, including day-ahead and real-time wholesale spot markets (including five minute dispatch) for electric energy and ancillary services, and forward markets for financial transmission rights; several also operate forward markets for capacity. These markets are characterized by transparent prices and have both ex ante and ex post rules that support workably competitive market outcomes.
   
   
10. Regulation -The continuous adjustment of AC electricity frequency (60 Hz)
    
    
11. Regulation Ancillary Service – The continuous matching of supply with demand in a control area. This would represent an economic opportunity for Vehicle to be available for short bursts of charge and discharge. Power plants provide regulation today, but they have slow response, low efficiency, energy and economic.
    
    
12. VAR Support - Reactive power support can be provided on either a unitary or small-system basis, or as a secondary overlay application for a full-scale 20 MW frequency regulation power plant. For industrial and commercial end users, potential benefits include lower fees from utilities resulting from improvement of power factor levels that would otherwise fall below specified minimums, as well as higher power quality for sensitive industrial and commercial applications. For grid operators or utilities, potential benefits include the ability to defer investments in transmission and/or distribution infrastructure.
    
    

3. Business Case

• On October 20, 2011, pursuant to section 206 of the Federal Power Act, FERC revised its regulations to remedy undue discrimination in the procurement of frequency regulation in the organized wholesale electric markets and ensure that providers of frequency regulation receive just and reasonable and not unduly discriminatory or preferential rates. Frequency regulation service is one of the tools regional transmission organizations (RTOs) and independent system operators (ISOs) use to balance supply and demand on the transmission system, maintaining reliable operations. In doing so, RTOs and ISOs deploy a variety of resources to meet frequency regulation needs; these resources differ in both their ramping ability, which is their ability to increase or decrease their provision of frequency regulation service, and the accuracy with which they can respond to the system operator’s dispatch signal.
  
  
• The Commission found that current frequency regulation compensation practices of RTOs and ISOs result in rates that are unjust, unreasonable, and unduly discriminatory or preferential. Specifically, current compensation methods for regulation service in RTO and ISO markets fail to acknowledge the inherently greater amount of frequency regulation service being provided by faster-ramping resources. In addition, certain practices of some RTOs and ISOs result in economically inefficient economic dispatch of frequency regulation resources.
  
  
• For example, that CAISO, NYISO, MISO, and PJM pay a capacity payment to all resources that clear the frequency regulation market, and then net the amount of regulation up and regulation down provided by these resources in order to compensate for the energy costs they incur. A simplified example would be to consider two resources that clear with the same amount of capacity and are directed to provide regulation up and regulation down over the course of a five-minute interval. The fast-ramping resource might be directed to move around an initial output level up five MW, then down three MW, up one MW, down ten MW, and finally up nine MW. A netting approach to compensation would determine that the resource provided an additional two MW of energy to the system (+ 5 – 3 + 1 – 10 + 9 = +2) during that five minute interval. Meanwhile, a slower ramping resource may be directed to move up three MW and then down one MW for a net of two MW in relation to its initial output level. The operator is not able to direct more movement because the slower-ramping resource would not be able to respond in the requisite time frame. Both resources would receive identical compensation for their movement, despite the first resource providing more ACE correction
  
  
• By remedying these issues, the Commission is removing unduly discriminatory and preferential practices from RTO and ISO tariffs and requiring the setting of just and reasonable rates. Specifically, this Final Rule requires RTOs and ISOs to compensate frequency regulation resources based on the actual service provided, including a capacity payment that includes the marginal unit’s opportunity costs and a payment for performance that reflects the quantity of frequency regulation service provided by a resource when the resource is accurately following the dispatch signal

4. Benefits
The primary economic benefit that some commenters expect to see is reduced costs of procuring frequency regulation capacity, with a secondary benefit of reduced energy costs. fFaster-ramping resources are able to provide more frequency regulation service from the same amount of frequency regulation capacity because faster-ramping resources can provide more ACE correction in real-time.

• Control Frequency - Provides frequency regulation to maintain the balance between the network's load and power generated. Provides stability, VAR support, power quality and transfer-leveling, and reliability.
  
  
• Faster Ramping Resources Cost Less - The final rule serves to remove barriers to the participation of faster-ramping and more accurate resources in the frequency regulation markets. The utilization of these more accurate resources will lead to reductions in the amount of regulation capacity that each balancing authority must procure – savings which can then be passed on to consumers. Furthermore, the rule will also allow the mostly thermal generation fleet that currently provides regulation to instead more efficiently operate in the energy markets at their optimum heat rates, where they can submit lower offers to supply energy and thus further lower costs to consumers. Because the energy market is much larger than the regulation market, this is where there may be greater savings.
  
  
• Improved Reliability - The final rule should enhance reliability as it incents new resources to come online and provide system operators in the ISOs and RTOs with additional tools and flexibility to manage the grid. As I have repeatedly indicated, we are asking our aging grid infrastructure to do more and more as regional electricity markets expand and we seek to transmit power over long distances from location constrained resources. We need to make sure that the operators of the grid are prepared to deal with these challenges with tools like the enhanced regulation market design we are directing today.
  
  
• Reduced Emissions - The final rule will result in an overall reduction in emissions from the generation fleet. Some of the new resource technologies that are faster and more accurate produce no emissions themselves. Further, the mostly thermal generation that traditionally has provided regulation will now be able to bid their capacity into the energy markets at their optimum heat rates. This will enable the thermal generators to maximize their efficiency, which in turn will reduce their emissions.
  
  

5. Risks/Issues

• The two-part rate is likely to be administratively-determined. There is no straightforward way for both the mileage payment and the capacity payment to be established through competitive offers. Therefore, the subjective judgment of the Commission and the operators of RTOs and ISOs will replace market forces in determining the value of frequency regulation service.
  
  
• Subjectivity = Controversy - Bbecause the rate will be administratively-determined, it will be controversial and subject
  to litigation.
  
  
• The performance payment will increase payments that must be recovered through uplift, complicating existing settlement procedures and efforts to reduce uplift.
  
  
• Penalize Existing Technology A performance payment will unduly discriminate against existing technologies that could respond faster but for the presence of barriers that have not, to date, presented themselves as obstacles. These barriers include the use of static ramp rates that reflect typical performance under all conditions rather than peak performance under conditions that exist at a point in time.
  
  
  
• Potential for Manipulation - Multi-part offers require complex rules to deter market manipulation because it is difficult to differentiate between legitimate and illegitimate bidding behavior.
  
  


• Regulatory Treatment of Storage & Asset Classification - Today's regulatory structure and utility processes disfavors energy storage. Storage is neither supply nor demand in a traditional sense and existing regulatory framework is not set up to manage it. It is a matter of debate whether the cost of energy storage technologies utilized to shift transmission utilization to match capacity should be a generation or a transmission asset because of its multifaceted implications for business models, sources of financing, and regulatory cost recovery.
  
  


1. Energy Storage is a transmission application because it is directly linked to the transmission system and its operation, without any bias towards its classification as such for regulatory or business model questions.
2. Storage can also be used for energy price arbitraging and production leveling, which are normally generation functions and which developers prefer to perform on a merchant basis so that they can access market prices. Also, the operator takes ownership of the energy in redelivering it which isn’t a transmission function.
   We need appropriate regulatory, market, and incentive treatments to encourage storage in support of renewable energy. When Storage is used in a multi-purpose application (as at a substation), it is unclear how to allocate costs and benefits for cost recovery. Because these benefits address different functions (generation vs. transmission), it may be difficult to measure the different benefits and allow for full cost recovery based on these benefits.
3. FERC rules for energy storage asset class
   
   
• Cost Competitiveness - High cost of energy storage technologies due to the small scale of production. The costs of energy storage options need to be compared to other options, including the construction of new transmission infrastructure.
  
  


• Value Not Monetized - Failure of the current marketplace to monetize the true value of storage. Storage has over 30 different elements of value and, right now, very few of those elements of value are monetized in the marketplace.
  
  


• Market Information - Information on energy balance, requirements for ancillary services and related market values may not be available. In the case of longer term storage (minutes to hours) for energy arbitrage, load following and ramping, market information on both the current value of energy and the expected future value will be required to effectively schedule changing and discharging. Since all storage systems will have both a capital and an operational cost component, its dispatch will depend primarily on capacity and on energy value. Also the capacity and energy limits of the storage systems will need to be communicated back to either a dispatcher or aggregator.
  
  

6. Success Criteria

1. Communications - In the case of short-term storage (seconds to minutes) for ancillary services, including frequency regulation, reactive supply and voltage support, requires fast and secure communications that allow for automatic control of the resource.
   
   

7. Frequency Regulation Technologies

• Battery Storage (See my Blog Article - Battery Storage) - Utilities typically use batteries to provide an uninterruptible supply of electricity to power substation switchgear and to start backup power systems. However, there is an interest to go beyond these applications by performing load leveling and peak shaving with battery systems that can store and dispatch power over a period of many hours. Batteries also increase power quality and reliability for residential, commercial, and industrial customers by providing backup and ride-through during power outages.
  
  
• EDLC - Electrochemical Double Layer Capacitors - (Also known as supercapacitor, supercondenser, pseudocapacitor, or ultracapacitor) (See my blog article - Supercacitors)  Store energy directly as charge. An EDLC is an electrochemical capacitor with relatively high energy density. Compared to conventional electrolytic capacitors the energy density is typically on the order of hundreds of times greater. In comparison with conventional batteries or fuel cells, EDLCs also have a much higher power density.
  
  
• Flywheel (See my Blog Article) – Flywheels are designed to smooth out transient fluctuations in load and supply, Changing power output causes greater wear and tear on equipment, and fossil generators that perform frequency regulation incur higher operating costs due to increased fuel consumption and maintenance costs. They also suffer a significant loss in "heat rate" efficiency and produce greater quantities of CO2 and other unwanted emissions when throttling up and down to perform frequency regulation services.
  
  
• SMES - Superconducting magnetic energy storage systems (See my blog article SMES) store energy in the magnetic field created by the flow of direct current in a superconducting coil which has been cryogenically cooled to a temperature below its superconducting critical temperature. A typical SMES system includes three parts: superconducting coil, power conditioning system and cryogenically cooled refrigerator. Once the superconducting coil is charged, the current will not decay and the magnetic energy can be stored indefinitely. The stored energy can be released back to the network by discharging the coil. The power conditioning system uses an inverter/rectifier to transform alternating current (AC) power to direct current or convert DC back to AC power.
  
  Supercapacitors are DC energy sources and must be interfaced to the electric grid with a static power conditioner, providing 60-Hz output. A supercapacitor provides power during short duration interruptions and voltage sags. By combining a supercapacitor with a battery-based uninterruptible power supply system, the life of the batteries can be extended. The batteries provide power only during the longer interruptions, reducing the cycling duty on the battery. Small supercapacitors are commercially available to extend battery life in electronic equipment, but large supercapacitors are still in development, but may soon become a viable component of the energy storage field.
  
  
• Vehicle-to-grid (V2G) - (See my blog article V2G) - Describes a system in which power can be sold to the electrical power grid by an electric-drive motor of a hybrid vehicle that is connected to the grid when it is not in use for transportation. Alternatively, when the car batteries need to be fully charged, the flow can be reversed and electricity can be drawn from the electrical power grid to charge the battery
  
  

8. Companies/ Organizations

1. FERC - The Federal Energy Regulatory Commission - United States federal agency with jurisdiction over interstate electricity sales, wholesale electric rates, hydroelectric licensing, natural gas pricing, and oil pipeline rates. FERC is also responsible for ensuring the reliability of the nation’s high-voltage interstate transmission system.
Not all transmission is subject to FERC jurisdiction. Public power entities such as the Los Angeles Department of Water and Power are not under FERC jurisdiction. Federal agencies also self-govern, so the Bonneville Power Administration, the Western Area Power Administration and the Tennessee Valley Authority all fall outside FERC’s authority. Finally, most of Texas and all of Hawaii and Alaska are outside FERC jurisdiction because they are not connected, or not tightly connected, to the interstate transmission grid.

9. Next Steps

• While Order No. 755 applies only to organized ISO and RTO markets, FERC may act to broaden its application. On June 11, 2011, FERC issued a Notice of Inquiry ("NOI") seeking comment on whether the cost-based compensation methods for frequency regulation in regions outside of organized markets should be adjusted to address the same issues addressed in Order No. 755. Third-Party Provision of Ancillary Services; Accounting and Financial Reporting for New Electric Storage Technologies, Notice of Inquiry, 135 FERC ¶ 61,240 (2011). In the NOI, FERC sought comments on different frameworks under which the speed and accuracy of frequency regulation resources might be appropriately valued in non-RTO and non-ISO markets. The matter is pending before FERC.
  
  

9. Links

1. FERC - Final Rule October 20, 2011 - Frequency Regulation Compensation in the Organized Wholesale Power Markets Docket Nos. RM11-7-000
   
   
2. CPUC - Demand Response Cost-Effectiveness Protocols - Final (MS-Word) - These protocols have been developed with the understanding that DR is in a transitional period.  Historically, DR was largely employed for reliability purposes during system emergencies in the form of interruptible programs for large industrial customers, which could be triggered when an ISO would otherwise have to shed load during a system emergency or when a utility was faced with a serious distribution system emergency.  However, the deployment of advanced metering technology and development of new energy markets is enabling greater use and flexibility of demand response by all types of customers.  Increasingly, customers are able to manage their loads to provide different levels of load reduction in response to price signals or other incentives.  These load reductions provide value to the grid not only during emergencies, but also during times of high energy prices or in the ancillary services market.  As a result, the methods used to measure the costs and benefits of demand response must be flexible enough to capture these emerging benefits.

Advanced Meter Infrastructure (AMI)

By 2012, every electricity consumer of the three big utilities in California will have smart meters which will give consumers detailed information about how they use energy and will enable new technologies automating customers’ responses.

California AMI Deployment Timetable

Navigate this Report
Back to Distribution Index
1. Background
2. Acronyms/Definitions
3. Business Case
4. Benefits
5. Risks/Issues
6. Next Steps
7. Companies
8. Links

1.Background

• People are often confused by the terms “Smart Grid” and “Smart Meters.” Metering is just one of dozens of possible applications that constitute the Smart Grid. The idea of two way communications from suppliers to consumers to of energy is not new, and systems for commercial and industrial customers have been implemented using analog technology for many years. In recent years digital communications have become cheap enough for wider deployment.
• Advanced Metering Infrastructure (AMI) systems are the primary means for utilities to interact with their meters at customer sites. In addition to basic meter reading, AMI systems provide two-way communications that can be used by many functions and, as authorized, by third parties to exchange information with customer devices and systems.
• The number of smart electricity meters with two-way communications is increasing rapdily. A 2009 study by Research company Park Associates found that there are 8 million smart meters installed in the U.S, about 6 percent of all meters. The eMeter Smart Grid Watch blog tracks the progress of smart meter installations around the world. In May 2011, total U.S. smart meter installations passed the 20-million meter mark. There are commitments in place to install nearly 50 million smart meters by 2015.
  
• Estimated advanced metering penetration increased to 8.7 percent in 2009 versus 4.7 percent in 2007, an 85 percent increase in penetration in two years. (FERC 2010). While it is difficult to assess precisely which functions these AMI deployments support, the penetration rates indicate that this enabling technology is being positioned to support greater participation by distributed energy resources to the benefit of operational resiliency
  .
  
• In 2009 the Department of Energy completed awards for 31 AMI grants worth $817 million under the American Recovery and Reinvestment Act (ARRA) Smart Grid Investment Grant
  Program. (See my blog articled Smart Grid Stimulus)
  
  The ARRA grants allow recipients to recover up to 50 percent of the eligible project costs and are designed to accelerate the commercial use and implementation of AMI technologies. The ARRA AMI grants support projects with a total value of $2 billion in 29 states. The projects are focused on providing AMI to retail consumers and, in some cases, information and pricing mechanisms that will allow consumers to reduce their energy use and costs, and improve the reliability of systems.
  
  
• The DOE also awarded $2.1 billion of funding under the ARRA Integrated and/or Crosscutting Systems Grant Program to support 39 demonstration projects that focus on adding intelligence and integrating smart grid and AMI capabilities in specific utility transmission and distribution systems throughout the United States. These system-based projects are valued in excess of $4.9 billion and are located in 31 jurisdictions. The projects include activities such as installing open, interoperable, two-way communications networks, deploying smart meters for customers, developing demand response and price responsive demand programs, automating advanced distribution and transmission applications, developing "self-healing" and power restoring properties on the grid, developing improved pricing programs, and supporting the deployment of plug-in electric vehicles.
  
  
• In addition, the DOE awarded grants supporting 16 regional demonstration projects that include smart meters in nine states. These large demonstration projects are designed to provide industry with business models, data to assess technical capabilities, and actual cost and benefit information associated with integrating these systems and components on a network level.
  

2. Acronyms/Definitions

Aclara's AMI Glossary

1. AMI – Automated Meter Infrastructure - Systems that measure collect and analyze energy usage, from advanced devices such as electricity meters, gas meters, and/or water meters, through various communication media on request or on a pre-defined schedule. This infrastructure includes hardware, software, communications, customer associated systems and meter data management software. First generation smart meters, which were only capable of meter readings, don't qualify as AMI systems
   
   
2. AMR - Automatic Meter Reading - The technology of automatically collecting consumption, diagnostic, and status data from water meter or energy metering devices (water, gas, electric) and transferring that data to a central database for billing, troubleshooting, and analyzing. AMR technologies include handheld, mobile and network technologies based on telephony platforms (wired and wireless), radio frequency (RF), or power line transmission. When metering residential customers, drive-by and walk-by meters (AMR) are considered a competing technology and currently are out-shipping AMI products. Other than the more-convenient data gathering over traditional meters, AMR meters offer very few to none of the benefits and functions necessary to enable residential customers to meaningfully participate in a smart grid
   .
3. Four Quadrant Metering - The process of measuring reactive and either real or apparent
   energy accounting for both forward and reverse flows.
   • Quadrant I is defined as an area where both energies flow positively (both
     are delivered to the service)
   • Quadrant II = reactive energy is positive and the other energy flows negatively.
   • Quadrant III = reactive energy flows negatively as does the other energy (both energies are received from the service).
   • Quadrant IV = reactive energy flows negatively, and the other energy flows positively
     .
4. MDMS – Meter Data Management System - Performs long term data storage and management for the vast quantities of data that are now being delivered by smart metering systems. This data consists primarily of usage data and events that are imported from the head end servers that manage the data collection. An MDM system will typically import the data, then validate, cleanse and process it before making it available for billing and analysis. The more flexible the MDM application, the better it is able to integrate to existing enterprise applications and help to streamline utility business processes. Benefits can be seen in billing, customer service, outage management and analysis of utility operations. Smart meters can collect customer readings as often as every 15 minutes, rather than every month, so utilities need new software to cope with all the extra data.
   
   
5. Smart Grid - A form of electricity network using digital technology. A smart grid delivers electricity from suppliers to consumers using two-way digital communications to support energy consumption efficiency, real time management of power flows and to provide the bi-directional metering needed to compensate local producers of power. The "Smart Grid" is envisioned to overlay the ordinary electrical grid with an information network. Smart meters may be part of a smart grid, but alone do not constitute a smart grid. There is some debate as to whether smart meters are actually needed for smart grids.
   
   
6. Smart Meter - Usually an electrical meter that records consumption of electric energy in intervals of an hour or less and communicates that information at least daily back to the utility for monitoring and billing purposes. Smart Meters provides higher granularity of meter interval data. Also, voltage levels, and power events can be tracked and logged across the entire customer base.

3. Business Case

• Smart meters establish a two-way data connection between the customer and the power company, by sending information over a communications network that may include power-line, radio or cellular-network connections. Once smart meters are installed, power companies can determine the location of outages more easily, and no longer need to send staff to read meters, or to turn the power on or off at a particular property.
• Transforming today’s “dumb” electric meter into a smart consumer portal that allows price signals, decisions, communications and network intelligence to flow back and forth through the two-way energy/information portal is a key to achieving consumer control of electricity costs and consumption.
• Advanced devices such as two-way communicating meters, communicating thermostats, and home automation devices such as programmable and communicating outlet controllers will assist energy customers in managing their demand for energy.
• Vendors are building “last mile” AMI communications solutions around wired and wireless technologies. A wireless technology is needed to reach any device not receiving electric service. The major disadvantage of wired technologies for last mile communication is that they are often incompatible with water and gas meters due to their use of the electrical distribution wires as the transmission media. Five technologies are being used:
1. Wireless Star - Wireless star technologies are available in both licensed (200 MHz, 900MHz) and unlicensed spectra (900 MHz, 2.4GHz). Advantages of licensed technology include greater allowable transmission power (2 Watts vs. 1 Watt) and blocking of interference sources. The principal disadvantage is the need to obtain a jurisdiction-by-jurisdiction license to operate. The desired frequency may also have been already allocated. Advantages of unlicensed technology are elimination of licensing requirements due to the use of the “free” spectra and more choices in which set of frequencies to use within the spectral bands. These two aspects often offset the potential interference and lower allowable transmission power.
2. Wireless Mesh – A communications network made up of radio nodes organized in a mesh topology. Wireless mesh networks often consist of mesh clients, mesh routers and gateways. A mesh network is reliable and offers redundancy. When one node can no longer operate, the rest of the nodes can still communicate with each other, directly or through one or more intermediate nodes.
3. PLC - Power Line Carrier - the principal hurdle is propagation of the signal across power system equipment such as transformers. Transformers act as natural filters to the radio frequency signal. Another difficulty is maximizing the bi-directional communication rate.
4. BPL - Broadband over Power Line - the communications rate is solved by choice of the frequency band; however, equipment often interferes with other wireless communication technologies (amateur radio). (See my blog article Broadband over Power Line)
5. Fiber Optics. It is often difficult to justify “fiber to the home” for a single purpose use, such as advanced metering. Smaller utilities, including municipalities, have successfully invested in fiber optics as they can then offer cable television, phone service, and internet service first with enough bandwidth available for their utility operations.
   
• AMI Cost Assumptions
  • Residential meter costs are based more on volume than other factors
  • Meter + AMI $40-80/unit
  • Meter + AMI + Disconnect $70-130/meter
  • Meter + AMI + Disconnect+ HAN $80-140/meter
  • Commercial and Industrial meter costs are based more on features selected than other factors - Meter + communications $120-150/meter
  • Installation costs
  • Residential $7-10/meter
  •  Commercial and industrial $20-65/meter
  • AMI network and backhaul equipment $3-11/endpoint
  • Head end software and integration $4-10/endpoint
  • System initiation and management $2-4/endpoint
  •  Ongoing maintenance $3-11/year/endpoint

Source: EPRI

Source: EPRI

4. Benefits

• Remote Meter Readings - AMR mainly saves utility providers the expense of sending out employees to take readings. This reduction in transportation requirements means less fuel consumption and less carbon emissions from the vehicle tailpipe. Advanced metering will also virtually eliminate meter reading errors
• Remote Configuration - Diagnostics, software and firmware changes including: upgradeable WAN/HAN communications, leveraged open architecture principles in system design and future customer service offerings. In other words the thing will work like a Sky or TiVo set-top box, under the control of its master authority outside the home.
• Improve Reliability – Remote diagnostics can detect a service outage. Today, a utility may not know about an outage until the customer calls to complain. Similarly, they may not know when service is restored.
• Remote Cut Off - The ability for energy firms to cut off supplies remotely. Gas meters would probably include a remotely-operable shutoff valve for this purpose.
• Enables Real Time Visibility - Home-network abilities, allowing an in-home meter display and possibly the ability to watch one's meter reading on other devices such as computers, TVs etc.
• Requisite for Distributed Generation - Intelligent net metering , the ability to measure "exported" electricity, as when a house sells electricity back to the grid - perhaps from a plugged-in electric car or other storage system. Similarly the meter must be able to work with micro-generation equipment so as to let people sell electricity to the grid.
• Enables Conservation through ADR (Auto Demand Response) - The "ability to remotely [i.e. from outside the premises] control electricity load for more sophisticated control of devices in the home". AMI can lower electricity costs to consumers from flatter load curves that result from smart meter applications and changes in consumer behavior in response to tariffs that provide incentive to use less electricity during peak hours, but more than just installing smart meters is required to achieve this benefit.
• Improved Billing - Billing can be based on near real time consumption rather than on estimates based on previous or predicted consumption. This timely information coupled with analysis, can help both Utility providers and customers better control the use and production of electric energy, gas usage, or water consumption. AMI can change the maximum amount of electricity that a customer can demand at any time; and remotely change the meter's billing plan from credit to prepay as well as from flat-rate to multi-tariff.
• Theft Prevention- Smart meters can detect the unauthorized use of electricity and help to curtail the theft of electricity.
• Operational Efficiencies - Including; field communication links to distribution, revenue cycle improvements, situational data in near real-time, and wholesale - retail markets integration.
  
  

5. Risks/Issues

• Consumer Backlash - In this video, from January 2011, members of West Marin Citizens Against Smart Meters literally block the road to the small town of Inverness to prevent contractors from installing smart meters in homes there. This 2010 KCBS video reports on how some homeowners in Oakland's Manzanita neighborhood are putting Pacific Gas & Electric on notice: "Keep those Smart Meters away." This anti-Smart Meter you tube video has already gained almost 300,000 views.
• Inaccuracy - Bills suddenly doubling
• RF Health Problems have not been scientifically substantiated, but many consumers are very worried. Smart meters pose a much lower danger than other RF sources in our environment such as cell phone towers. While many think fears of RF are silly, there have been other cases where a technology previously seen as safe turned out not to be.



Source: Environmental Defense Fund

• Many consumers believe there are more problems than utilities have admitted to
• Fears of Big Brother surveillance
• AB 37 Huffman. Smart grid deployment: smart meters. As of May 2011, in committee in the California Assembly. This bill would require the CPUC, by January 1, 2012, to identify alternative options for customers of electrical corporations that decline the installation of wireless advanced metering infrastructure devices, commonly referred to as smart meters, as part of an approved smart grid deployment plan. The bill would also require the CPUC, when it has identified those alternative options, to require each electrical corporation to permit a customer to decline the installation of an advanced metering infrastructure device and make the alternative options available to that customer.



Relative RF Exposure Source: Texas PUC

• Vendor Lock In - Although many communications systems talk Internet Protocol (IP), they do so over proprietary hardware. Utilities did not insist on plug-and-play compatibility at the hardware level. their failure to take a standardized approach has cost them dearly. And will continue to do so for many years.
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• Overspending - In America, typical prices are $110 to $120 per meter and about $50 for the communications. . California’s investor-owned utilities alone are spending about $4.5 billion on deploying smart meters over the next few years. That implies that a nationwide implementation could cost around $50 billion. But PNNL estimates that $450 billion would have to be poured into conventional grid infrastructure to meet America’s expected growth over the next decade anyway. In contrast, the typical cost in Europe is $40 per meter (plus $15 for the communications by the way). To make the math easier, let's say American utilities will install 50 million smart meters over five years and they will spend $40 more than the Europeans., that comes out to $2 billion.
  
  Municipal and co-op organizations such as APPA and NRECA often do joint research and sometimes joint buying. Federal agencies such as BPA and TVA have run a few buying programs over the years. For the most part, smart meter cost is passed through to the consumer and American utilities don't have a lot of incentives to cooperate and collaborate, even with $2 billion at stake. Despite a few early conversations, the big three California utilities couldn't successfully collaborate on a joint procurement strategy for the millions of smart meters they are installing
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• Meter Upgradeability - Utilities need to ensure that technologies or solutions that are selected will be interoperable and comply with the yet-to-be-established national standards. Utilities also want to ensure that the system they select will allow for evolution and growth as Smart Grid standards evolve. It is essential to be able to upgrade firmware, such as meters, in the field without replacing the equipment or "rolling a truck" to manually upgrade the meter firmware
  
  
• First Generation Functionality - Many of the "smart" meters on the market today are nothing more than electronic versions of the 100 year old electromechanical meter equipped with remote reading capability. A truly smart meter needs much more
  • Information for the utility about service status and power quality
  • Apps for the consumer to provide not only truly useful cost (not price) information
  • Information about on=premises devices (e.g., PHEV, solar generation, majore appliances) along with automated EMS functions to act upon the information
  All of them must eventually be eMeters with the ability to communicate via TCP/IP over any available public or private network. Utilities that put in yesterday's AMR/AMI technology today will be severely disadvantaged.
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• Technological Complexity- Deployment of technologies still under development. Although most of the technologies necessary to build AMI already exist, products for cost-effectively applying some of them in the power system have only become available in the past few years. Utilities wishing to deploy AMI technologies right now often need to work in partnership with vendors to define requirements, provide design feedback and evaluate prototypes. After downsizing and deregulation, many utilities do not have the research and development resources available to make this happen
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• Stranded Investment – If the wrong technologies are selected, the rate payer may have to pay for technology write-offs
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• Gold Plating - You don’t necessarily need to have a Smart Meter with communications functionality built into it to be able to realize smart grid functionality and benefits. There are a lot of AMR meters out there that have one way communication what their usage information is, and there are other ways to communicate back to the utility or whoever that third party service provider may be
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• Market Access - Degree of Utility Control in Home - A 2006 survey of utility executive by GF Energy showed that nearly 90% if the executive believe that it is the utility companies that will be introducing end user electricity controls rather than independent entrepreneurs.
  
  
• Lack of market power for smaller utilities. Deploying advanced technology is easier for bigger utilities for two reasons: firstly, they simply have more internal resources to apply to the project; and secondly, they must deploy to a larger number of sites and therefore can offer bigger incentives to vendors to implement the features they need. Smaller utilities do not have economies of scale, cannot offer large incentives and therefore must often take off-the-shelf technology. This may mean their Smart Grid projects are “not as smart”, or must be deferred because they are not yet cost-effective
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• Information Security - One deficiency common among many of the meters is the use of insecure programming functions, such as memcpy() and strcpy(), which are two of the most common sources of exploitable software bugs. In many cases, the devices use general purpose hardware and software that aren't designed for highly targeted or mission critical systems. Security firm IOActive, claimed in March 2009, it had proven that networks of smart meters, which allow two-way communications and controls between customers and utilities, could be hacked to boost or cut power to millions of homes at once. That could crash the grid, all with as little as $500 worth of equipment and the proper training, the firm said
• Decoupled Alternatives – As an alternative to AMI system, market information such as prices and grid conditions can be decoupled from communication of energy consumption. Thus, the meter can be separate while pricing signals and the like can be transmitted via other public communication mechanisms such as phone, internet, cable, and wireless radio. A decoupled situation can make sense for commercial buildings and industrial uses where energy savings can be significant, while a more traditional bundled AMI package may be more desirable for residential consumers due to its “all-in-one” and “plug-and-play” aspects
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• Regional Customization - AMI billing techniques and the machines themselves may require regional customization reducing potential economies of scale in production and deployment. Regional customization may be required because of differences in consumer preferences, aggressiveness of service providers, state and local regulations, and the speed with which smart grid structures and technology change over time. Not all regions are likely to respond identically and may have different needs.
  
  

6. Next Steps

• More Smart Meters - IDC counts roughly 230 AMI projects underway or scheduled in North America. When they are all completed in 2015, they will account for 50% of the total addressable market. The other half of the market will be the beneficiaries of better standards, lower prices and lessons learned.
• HAN Communication - Virtually all smart meters being installed in the US come with a second built-in radio — the Home Area Network interface — that can send information to one or more devices in the home. This is separate from the other radio in the meter that sends data back to the utility.
  
  But in most places, including California, this HAN interface is not yet “live”. This means the meter is equipped to transmit or receive data to devices in the home, but it cannot do so until either:
• The utility starts transmitting data to home devices via the HAN interface
• A device in the home starts sending messages to the meter requesting data.
In either case, the utility must enable HAN communication by authorizing a password between the HAN in-home device and the meter. This is very much like a password protection for a home wi-fi router, except that the utility controls this password (not the homeowner).
• Plug & Play - Whichever company or partnership asserts a true plug-and-play standard has a gigantic opportunity. The Itron/Cisco partnership is currently best positioned to break the proprietary stranglehold.
• Meter Upgradeability - In 2007, Congress declared in the Energy Independence Act (EISA) that modernizing the grid is national policy. EISA requires the National Institute of Standards and Technology (NIST) to develop a consensus on the standards and protocols necessary to ensure Smart Grid functionality and interoperability (See My blog article Standards Development Process for details). In 2009, NIST created the Smart Grid Interoperability Panel (SGIP), a group of public and private organizations, to coordinate the development of consensus-based Smart Grid standards.
• One of the high priority requiring immediate attention was the need for a meter upgradeability standard. The National Electrical Manufacturers Association (NEMA) led an effort to develop standards for smart meter firmware upgradeability and the standard was completed in less than 90 days, It will be titled NEMA Smart Grid Stanards Publication SG-AMI 1-2009 -Requiremnets for Smart Grid Upgradeablity
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• In April 2011, the governing board of SGIP voted in favor of a new standard and a set of guidelines important for making the long-planned “smart” electricity grid a reality. The documents address the need for wireless communications among grid-connected devices as well as the ability to upgrade household electricity meters as the Smart Grid evolve.
  
• The standards and guidelines resulting from PAP 0 (Meter Upgradability Standard) and PAP 2 (Wireless Communications for the Smart Grid) are crucial to ensuring that metering devices can be upgraded remotely and reliably, and that the sort of fast, efficient wireless communications typical today with cell phones becomes a part of the future electricity grid. Almost every house has an electricity meter, and the PAP 0 standard is designed to ensure that the new generation of smart electricity meters does not quickly become obsolete.
  
  
• Developing Opt Out Policies - Whether or not consumer fears of RF radiation are based on science, utilities need to respond to their customers. For example, Pacific Gas & Electric will disable smart meters for customers concerned about health and safety hazards from meter radio wave emissions, but the utility's March 2011 proposal to the California PUC also included a kicker those customers probably won't like. The utility wants to charge an upfront fee plus an additional monthly charge or rate increase to cover the cost of turning off meter communications radios, manual meter readings and the additional cost to "strengthen" its SmartMeter network.
  
  The CPUC told PG&E earlier in March that it had two weeks to provide an opt-out plan because of the continuing backlash and controversy over the new meters. While the commission at the time said it had seen no evidence that the meters' radio emissions were dangerous, it did want customers to have a choice, according to a news story in the Santa Rosa Press Democrat.
  
  PG&E spokesman Jeff Smith told the newspaper, "For customers who want it, we will turn off the communications radio and that removes them from the grid. The ongoing fees cover the costs, primarily the labor but also the cost to strengthen the SmartMeter network."
  
  The fee plus monthly charge options offered by PG&E include either an upfront fee of $270 and a $14 monthly charge or rate increase or an upfront fee of $135 and a $20 monthly fee or rate increase.

7. Companies

All the smart meter and AMI vendors are faced with some daunting challenges. The U.S. AMI market is currently in full deployment mode, initiated by regulatory mandates in Texas, California, Pennsylvania, and elsewhere, and fueled by $3.5 billion in stimulus funding. This party will subside in the not-too-distant future, as smart meters approach their terminal penetration rate of the overall electric meter installed base, which in itself is not growing much. Continued growth will require diversification in target markets (i.e. beyond electric AMI), products (software and services), and/or geography (i.e. Europe, Latin America, Asia).

1. Aclara, Hazelwood, MO - Part of the Utility Solutions Group of ESCO Technologies (NYSE: ESE), St. Louis- Provides device networking, data-value management, and customer communications to water, gas, and electric utilities globally. Over 500 utilities in nine countries rely on Aclara solutions to connect with their customers
   
   Aclara has mesh RF for urban areas and can reach rural areas with its low-bandwidth powerline technology (the legacy TWACS system). It is finally beginning to merge the two systems. If it gets its unification act together, it could offer utilities a low-cost transitional system. Aclara could sell a combination of mesh and powerline for now, as long as it could promise a seamless transition to WiMAX or LTE or another high-bandwidth, long-distance technology at some point in the future.
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2. Echelon, San Jose, CA - (NASDAQ: ELON) - Develops, markets, and sells energy control networking solutions primarily in the Americas, Europe, the Middle East, Africa, and the Asia Pacific/Japan. Its solutions enable everyday devices, such as air conditioners, appliances, electricity meters, light switches, thermostats, and valves to be inter-connected. Its networked energy services (NES) system comprises smart meters and other smart devices; edge control node and data concentrators; the NES networking operating system software; and the infrastructure and support required to implement and deploy network solutions.
   
   A heavyweight in Europe, Echelon has begun making inroads in the U.S. The company takes a different approach to the hardware than most others, designing more functionality into the meter’s “motherboard” instead of employing add-on modules. Its communications strategy draws on its European heritage. Rather than using RF or cellular to communicate with every smart meter, Echelon uses “distribution line carrier,” a more advanced form of old-school power line carrier. (See my blog article Broadband Powerline Communication) The power line relays information from each home to the transformer, which then uses any of the popular communications pipes to backhaul the data to the control center. They save the cost of putting a radio into every smart meter and the cost of troubleshooting meters that can’t communicate because of difficult reception.
   
   According to Pike Research’s market share analysis, Elster was the sixth biggest smart meter manufacturer in 3rd Qtr 2010 holding a 3% share of the market.
   
   
3. Elster - Essen, Germany - (NYSE: ELT) - Elster Solutions, Raliegh, NC – Has delivered over 2 million smart metering devices worldwide with systems located in North America, Europe, Central America, Australia, New Zealand and the Caribbean. Elster smart metering system solutions provide utilities with energy conservation capabilities via demand response programs, smart grid applications, and operational efficiencies resulting in significant value creation across the utility enterprise.
   
   Elster sees itself as a solution provider, not a product company. Within the next five years they want to be working with utility partners on everything – from testing to going to regulatory commission meetings.
   
   According to Pike Research’s market share analysis, Elster was the fifth biggest smart meter manufacturer in 3rd Qtr 2010 holding a 5% share of the market.
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4. GE Energy. Atlanta, GA - (NYSE: GE) - Provides a full line of single phase and poly-phase meters to meet utility requirements for form factors and functionality. Meters come equipped with various options for communications technology, home area network options, remote service switch, as well as a number of embedded features such as load profile, demand, and TOU tariff.
   
   GE still has some integration work to do, but I they have the resources to be a force
   
   According to Pike Research’s market share analysis, GE was the fourth biggest smart meter manufacturer in 3rd Qtr 2010 holding a 20% share of the market.
   
   
5. Itron, Liberty Lake WA - (NasdaqGS: ITRI ) Leading provider of solid-state meters—electricity, water, gas and heat—and data collection/communication systems, including automated meter reading (AMR) and advanced metering infrastructure (AMI) technology. Itron offers enterprise-wide software platforms, project management, installation and consulting services.
   
   Itron was the clear leader in first-generation AMR initially based on propitiatory standards, and the early leader in next-generation AMI contract wins. Given that nearly 8,000 utilities around the world already rely on Itron technology, the company has a large installed base from which to draw.
   
   Itron, leveraging its existing Automated Meter Reading (AMR) dominance, established an early AMI lead with its OpenWay system, but was especially hurt by the strength of Silver Spring Networks’ IP story. This was the catalyst for the Itron/Cisco partnership that may yet position Itron to ultimately “out IP” Silver Spring.
   
   In September 2010, Itron and Cisco announced a strategic alliance that will advance the transformation of the world's energy infrastructure. Together, the two will deliver a definitive 21st century Internet Protocol (IP)-based communications platform to the smart grid market and help advance more consistent and reliable delivery of energy across the electric distribution system and into homes and businesses. Under terms of the agreement, Itron and Cisco will jointly develop the reference design that defines a standard for smart grid field area and smart metering network communications, utilizing the latest version of the Internet Protocol (IPv6). A key standard identified by the National Institute of Technology, IPv6 integrates network security into its framework; allows for simplified processing of data by routers and other network devices; and offers a wealth of extensibility options over the current and widely-used IPv4 implementation.
   
   Noteworthy for having pioneered the radio mesh technology that has emerged as the preferred way for smart meters to "talk to" one another in neighborhood area networks – though Itron's "OpenWay" RF mesh system isn't part of every deployment (Silver Spring Networks has been the chosen vendor for that function for many projects). New York Times November 2009 Itron Article
   
   
   
   According to Pike Research’s market share analysis, Itron was the second biggest smart meter manufacturer in 3rd Qtr 2010 holding a 24% share of the market.
   
   
   
6. Landis + Gyr, Zug, Switzerland - Although the metering company can trace its roots back to 1896 in Switzerland, it became a conglomerate of networking and metering companies consolidated by Australian private equity firm Bayard Capital in 2008. Worldwide leader in electricity metering with a preeminent position in advanced or “smart metering" systems. Privately held with US$1,364 million sales in 2008. Over 5,000 employees, 600 full-time professionals dedicated to R&D, and operations in 30 countries across five continents.
   
   Landis+Gyr earned about $200 million on about $1.5 billion in annual revenues in 2010, Reuters’ anonymous sources report.
   
   In May 2011, Landis+Gyr was reported to be on the auction block with big smart grid suitors bidding on the company. Reuters reported that General Electric was offering $2 billion for the Swiss-based smart metering giant, an offer that was followed by Toshiba’s 200 billion yen ($2.48 billion) counter-offer, and entry by strategic bidders including Honeywell and ABB. GE’s smart meter business relies on partners for communications and networking, while L+G has its own 900-megahertz communications system, as well as back-end software to manage it all. On May 19, Toshiba announced it was the successful bidder at $2.3 million
   
   According to Pike Research’s market share analysis, Landis+Gyr is the market leader in terms of utility vendor selections, accounting for 26% of total endpoints as of the end of the third quarter 2010. During the past year, Landis+Gyr surpassed Itron as the number one smart meter supplier to utilities in the U.S., and Itron now holds a 24% share of the market
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7. Sentec, Cambridge, England - Develops tailored smart metering solutions in partnership with metering and utility companies. With more than five million smart meters worldwide incorporating its smart sensor technology, Sentec combines technical expertise with an in-depth understanding of grid and metering infrastructure to deliver upgradeable metrology solutions.
   
   For years the company has been a behind-the-scenes partner to meter manufacturers such as Sensus. Now the company hopes to convince utilities to ignore those manufacturers and specify their own systems with Sentec as their consulting partner to spec the design and have it built via the company's network of contract manufacturers.
   
   Sentec alleges utilities can have the superior meters at little or no extra cost. For one thing, Sentec claims to be expert in designing ultra low-power, low-cost solid-state meters. Second, it works with contract manufacturers and takes advantage of their economies of scale.
   
   The Sentec formula is lots of flash memory, plus a more powerful processor, plus an operating system that would be the same from meter to meter. In theory, this means "apps" developed for one brand of meter would run on others, provided they used the Sentec operating system. Internally, Sentec calls its operating system for meters "Breeze," though it has not yet launched it formally to the outside world.
   
   If the idea catches on, the meter will evolve from a relatively dumb measurement device into a smart, sophisticated, upgradable platform for multiple applications – more like a home gateway. It is certainly true that meters should ideally be field upgradable. And capable of posting new applications as we dream them up. That need is being addressed to a limited extent by many of today's vendors. The Sentec approach would be like the move from "feature phones" to "smart phones" in the cellular world.
   
   
8. Sensus, Raleigh, NC - Employs almost 4,000 people in 41 facilities on five coinents. A one hundred year old privately held company that issues publicly traded, SEC-registered bonds. Sensus is now running at more than $1 billion in annual sales, with more than 200 projects and 8 million smart meters in the field.
   
   Sells meters under the iCon brand, along with a growing range of hardware and software for distribution automation. But it is with its FlexNet communications network that the company truly sets itself apart. FlexNet has also been used with meters from GE, Landis + Gyr and Elster.
   
   Most Sensus competitors sell radio frequency (RF) mesh systems, typically running over a public spectrum (like the spectrums used for roam phones or for WiFi). A few years back, Sensus acquired point-to-point radio RF technology and the rights to private spectrum across most of the U.S. In theory, point-to-point private spectrum offers several advantages:
   • Less interference from other devices (since you are not sharing the spectrum)
   • Longer range
   • Lower latency (great for time-sensitive grid applications)
   • Better penetration inside buildings (for things such as apartment sub meters)
   • Stronger security
   • Lower operations and maintenance costs
     
   
   In July 2011, Sensus announced that it will integrate encryption and key management technologies from IBM into its FlexNet™ advanced metering infrastructure, a step that Sensus says will not only enhance its existing security capabilities, but will also help advance data security as a critical element of the smart grid.
   
   According to Pike Research’s market share analysis, Sensus was the third biggest smart meter manufacturer in 3rd Qtr 2010 holding a 21% share of the market
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9. Silver Spring Network - Redwood City CA - Makes the radio card and provides services to its customer utilities, but the meters themselves come from other manufacturers. SSN communications modules are compatible with most major meters, so utilities feel they are not locked in to any one meter manufacturer. But they are locked in to Silver Spring Networks. Sure, they can swap in a different meter. But they can't swap in a different communications module. Most of SSN's competitors use a similar strategy.
   
   Silver Spring Networks’ undisputed lead in U.S. utility AMI was built by its strong commitment to the IP communications protocol at a time when competitor’s products were universally proprietary. This success drove a dramatic change in the industry, where virtually all AMI vendors have now adopted the IP protocol in one way or another. This has not yet approached the goal of multi-vendor interoperability for smart meters, as key parts of even the Silver Spring Networks implementation, such as the “meshing” protocols, are “pre-standard” (i.e. proprietary).
   
   SSN has raised over $275 million from investors. Their rumored 2010 IPO did not take place and in July 2011 Silver Spring Networks filed an S-1 for its long anticipated IPO. Expected pricing for the IPO was not announced, but the $3 billion target valuation rumored at the beginning of 2010 would seem rich given the $2.3 billion price for the more diverse Landis+Gyr, and the current $1.8-2 billion valuations for Elster (who IPO’ed last fall) and for industry powerhouse Itron.
   
   Provides the hardware, software and services that allow utilities to deploy and run applications, including Smart Metering, Demand Response, Distribution Automation and Distributed Generation, over a single, unified network. Silver Spring's Smart Energy Network is based on open, Internet Protocol (IP) standards, allowing continuous, two-way communication between the utility and every device on the grid. SSN has successful deployments with leading utilities in the US and abroad, including Florida Power & Light, Pacific Gas & Electric, Pepco Holdings, Jemena and United Energy Distribution.
   
   SSN is the clear leader in RF mesh, which is the clear favorite with large, investor-owned utilities in the U.S. But some analysts believe public cellular networks could catch on, especially when 4G arrives. Meanwhile, parts of Europe seem set on powerline carrier and parts of Australia are using WiMax. If other transports catch on, SSN will have to be quick about supporting them.
   
   In home area networking, Silver Spring purchased Greenbox has a "technology alliance program" that includes many home energy-monitoring companies, including Tendril, Greenbox, Control4, Energate, Radio Thermostat and, most recently, Onzo.
   
   
   
10. Trilliant - Redwood City, CA - Provides intelligent network solutions and software to utilities for advanced metering, demand response, and Smart Grid management.
    
    More than 20 years old, but reformed in 2004 to concentrate on the smart grid space. Trilliant has over 200 utility customers, including Hydro One in Ontario, Canada. Hydro One has deployed Trilliant smart communications to over 1.1 million customers in support of the largest operating time-of-use billing program in the world.
    
    Secured $40 million VC funding from MissionPoint Partners and Zouk Ventures in 2008 toward the development of intelligent networks powering smart grid related functions. In July 2010, closed financing totaling $106 million from a global syndicate of industry and financial leaders. The financing round was led by two highly-respected financial investors, Investor Growth Capital (the wholly-owned venture arm of Investor AB of Sweden) and VantagePoint Venture Partners and two leading global grid-related equipment companies, ABB and GE.
    
    Trilliant acquired SkyPilot in 2009. It has effectively merged its NAN-oriented RF mesh network with SkyPilot’s WAN-oriented WiMAX, and done so with multipurpose boxes that can handle both technologies.
    
    The company builds a "multi-tiered network" that uses a beefed-up version of the 802.15.4 wireless standard – which the ZigBee protocol uses for in-home equipment – as its primary home-to-utility concentrator point communications technology, according to Eric Miller, Trilliant's chief solutions officer. Using an altered version of the 802.15.4 wireless standard to allow meters to mesh with each other and with concentrator points. SecureMesh gives device vendors a standards-based way to rapidly deploy mesh technology in dense urban smart grid applications. Trilliant is one of the first AMI communications vendors to use a commodity IEEE 802.15.4 PHY and MAC layer for mesh purposes. Click here for Erich Gunther's analysis and scorecard of Trilliant's SecureMesh technology.
    

8. Links

1. An April 2011 report from IDC Energy Insights offers a detailed assessment and ranking for seven major vendors in the smart metering communication network market.
   Leaders: Landis+Gyr
   Major Players: Elster, Itron, Silver Spring Networks, Trilliant and Sensus
   Contenders: Aclara
   
   
2. US Smart Meter Projct Status May 17, 2011 by Chris King, President, eMeter Strategic Consulting © eMeter Corporation
   
   
3. Electricity Smart Metering Business Drivers A 2009 PDF White Paper by Atos Origin. A good non-commercial assessment. Presents a dedicated method to assess the financial returns of particular smart metering projects
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4. Coincident has developed an interactive web application to help users discover and explore advanced metering projects occurring around the world. Presently in a free beta period with coverage maps for the United States and Canada
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5. CPUC 2009 Decision on PG&E’s Proposed Upgrade to the Smart Meter Program
   CPUC 2008 Decision on SCE’s Proposed Smart Meter Program
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6. FERC - Federal Energy Regulatory Commission. 2010 Assessment of Demand Response and Advanced Metering Staff Report.