Recipient information | Input |
---|---|
Total number of customers served by utility / utilities supporting the project | 672,860 |
Total number of residential customers served by utility / utilities supporting the project | 525,628 |
Total number of commercial customers served by utility / utilities supporting the project | 73,616 |
Total number of industrial customers served by utility / utilities supporting the project | 0 |
Total number of AMI smart meters installed and operational prior to the SGIG/SGD program | 0 |
AMI smart meters installed and operational | Quantity* | Cost |
---|---|---|
Total | 0 | $130,859,704 |
Residential | 574,277 | |
Commercial | 43,225 | |
Industrial | 0 |
AMI smart meter features operational | Feature enabled | # of meters with feature |
---|---|---|
Interval reads | Yes | 617,502 |
Remote connection/disconnection | Yes | 574,277 |
Outage detection/reporting | Yes | 617,502 |
Tamper detection | Yes | 617,502 |
AMI communication networks and data systems | Description | Cost |
---|---|---|
Backhaul communications description | The backhaul communications network for SMUD's Smart Meters Project consists of utilizing the Silver Springs Networks (SSN) wireless Access Point (AP) communicating through the AT&T wireless Data network. The wireless data network is the Third Generation (3G) AT&T network utilizing a commercial off the shelf Raven-X modem for the communication link. The data flows through the AP through the AT&T data network and is then connected to the data center hosting the head end through a virtual and hard-wired connection. Partners: Connectivity is available, but electro-mechanical meters are not capable of communication on the network. The communication network used between the collector/gateway to the headend would be a modbus TCP/IP (Ethernet) system. | $4,046,975 |
Meter communications network | "The meter communications network consists of utilizing the SSN AP as the collector and the SSN Relay device to communicate to the meters. Network Interface Cards (NIC) are installed in the meters which provide a communication link through a 900 MHz unlicensed Frequency Hop Spread Spectrum (FHSS) radio. The meters, AP's and Relay's formulate a ""mesh"" network design with each device having the FHSS radio capability built in. In this configuration meters can communicate with meters, directly with AP's through Relay's, Relay's to Relay's. This provides a robust architecture to ensure a communication path can be achieved for the meter data flow." | |
Head end server | The head end system for all of the data accumulation is the SSN application named Utility IQ (UIQ). The application is being hosted by SSN on SMUD assigned servers at their data center in San Diego. UIQ is an open standards based network operating system for utility information and control networks. UIQ provides a suite of utility networking services including addressing, routing/switching, quality of service, health, network time, security and encryption all of which can be implemented through a XML, based provisioning configuration, monitoring, control and management. SMUD will also host a disaster recovery system on servers located in SMUD's data center. | $10,117,324 |
Meter data analysis system | Itron IEE will be used for reviewing and reporting on meter data. In addition IEE will perform data validation and estimate when required.Partners: 0% existing meters are able to export data for analysis. Database can trend data, maintain historical records for time period to time period comparison, can apply utility rate structures, and can generate time-of-use reports. | |
Other IT systems and applications |
Web portal deployed and operational | Quantity* | Description |
---|---|---|
Customers with access to web portal | 137,244 | |
Customers enrolled in web portal | 26,332 | "Web Portal:Customers with access: is defined as the quarterly total of unique customers who have logged on to the Web Portal (My Account) at least once and have the ability to access any online information, including interval data. This number will fluctuate each season, depending on customers’ interest in reviewing their utility account.Customers with active accounts: is defined as the unique customers actively visiting the web portal at least once during the quarter to review their interval data. Through the web portal, customers have the ability to access data such as interval data, projected energy costs and usage, comparisons, bill alerts, home energy reports and estimated energy savings or specific improvements. 2012 Direct Load Control Pilot: 180 customers were given """"access"""" to the web portal during the time of the programmable communicating thermostat was installed. This occurred during the month of July 2012 with some participants starting to have access and then by the beginning of August 2012, all 180 customers had """"access"""" to the web portal. The web portal was used to change the temperature settings and schedules, opt-out of demand response events, see event history, and to get general information about the program. A total of 99 customers were """"active accounts"""" where these unique customers used the web portal at least once.2013 Direct Load Control Pilots: The web portal for customers to opt-out of events was not available due to the dependency and canceling of the Aclara contract. " |
Customer systems installed and operational | Quantity* | Description | Cost |
---|---|---|---|
Communication networks and home area networks | N/A | N/A | |
In home displays | 4,209 | SMUD is installing the following IHDs: The EnergyAware Power Tabs in an In-Home Display (IHD) that provides real-time feedback on a customer's electricity consumption. The display communicates wirelessly wit the smart meter. It allows the user to view the following: * Current household electricity use* Cumulative consumption and costs to run individual appliances* Estimate consumption and costs to run individual appliances* Receive and acknowledge messages from the utility | $7,867,299 |
Energy management device | 367 | EMS installed at the Partners' Sites:This represents the number of buildings that have received additional controls and/or additional control strategies through programming efforts and / or have been connected to a centralized control network operated by the Partner. Note that with SCUSD and EGUSD, the number of buildings is approximate, as some of the buildings are very tiny. | N/A |
Direct load control devices | 903 | 2012 Direct Load Control Pilot Program: 2012 3rd quarter: 180 one-way programmable communicating thermostats (Honeywell UtilityPro) were installed on residential homes to test various precooling strategies before a demand response event. All used a temperature reset strategy. All the thermostats were installed by the end of July 2012. These PCTs receive a one-way paging type signal from the Cooper Power System Headend system.2012 4th quarter: Five participants dropped out of the program during this period. As a result, 175 participants/thermostats remained. 2013 1st quarter: The 2012 pilot program ended so these devices are not being counted for this quarter. For the 2013 pilot program, this quarter 239 PCTs were installed on 219 residential customers. Some customers had more than 1 PCT installed in the home.2013 2nd quarter: For the 2013 residential and small commercial pilot programs, a total of 860 residential customers had a total of 919 PCTs installed (some customers had more than 1 thermostat install at their home. A total of 15 small commercial customers had a total of 16 PCTs installed. Overall, 875 customers had 935 PCTs (devices) installed. All devices were installed by June 30, 2013.2013 3rd quarter: For the 2013 residential and small commercial pilot programs, a total of 836 residential customers had a total of 897 PCTs installed (some customers had more than 1 thermostat install at their home. A total of 12 small commercial customers had a total of 14 PCTs installed. Overall, 848 customers had 911 PCTs (devices) installed. 2013 4th quarter: For the 2013 residential and small commercial pilot programs, a total of 828 residential customers had a total of 889 PCTs installed (some customers had more than 1 thermostat install at their home. A total of 12 small commercial customers had a total of 14 PCTs installed. Overall, 840 customers had 903 PCTs (devices) installed. 2014 1st quarter: For the 2013 residential small commercial pilot | $8,695,702 |
Programmable communicating thermostats | 919 | SMUD is installing the following three types of PCT: EcoFactor is an energy management solution that uses an internet-enabled, wireless thermostat (Computime) and gateway (Digi). The gateway provides a connection between the thermostat and the EcoFactor service via the Internet. EcoFactor uses real-time weather data, thermal characteristics of the home and temperature preferences to optimize energy use. EcoFactor enables the thermostat to be controlled remotely through a smartphone, tablet or computer.The Nest Learning Thermostat is a Wi-Fi enabled, sensor-driven, self-learning, programmable wireless thermostat that learns temperature preferences and automatically adjusts when the home is unoccupied. If connected to a Wi-Fi network, energy use can be controlled remotely through a smartphone, tablet or computer and the thermostat can receive over-the-air firmware updates.Allure Energy is an energy management solution that uses a wireless, communicating thermostat (Computime) to communicate with a gateway (Allure Energy Home Controller). Using a patented Proximity Control Technology and a smartphone, the thermostat automatically adjusts based on the smartphone or tablet’s proximity to the home. The thermostat can be controlled remotely through a smartphone or tablet. | $7,867,299 |
Smart appliances | 0 | $0 |
Customer system communication networks | Description |
---|---|
Network characteristics within customer premise |
Pricing program | Customers with access | Customers enrolled | Description |
---|---|---|---|
Tiered rate with Critical Peak Pricing | 11,537 | 1,288 | Residential Critical Peak Pricing activated on 12 event days during 4-7 PM weekdays afternoons for a total of 36 hours during the June - September summer season. All other hours subject to off-peak pricing at tier levels. Tier levels for off-peak energy set at < 700 kWh for Tier 1 and > 700 kWh for Tier 2. Customers with domestic wells receive an additional 300 kWh Tier 1 allowance. |
Time of Use Rate | 44,348 | 4,851 | Residential Time of Use Rate consists of a higher price each summer weekday between 4-7 PM, excluding the July 4th and Labor Day holidays. Remaining hours subject to off-peak pricing at designated tier energy allowances. Tier levels for off-peak energy set at < 700 kWh for Tier 1 and > 700 kWh for Tier 2. Customers with domestic wells receive an additional 300 kWh Tier 1 allowance. |
Time of Use rate with Critical Peak Pricing | 55,571 | 740 | This combination residential rate consists of Time of Use pricing each summer weekday between 4-7 PM, except during holidays and during the 12 Critical Peak events when CPP pricing applies. Remaining hours subject to off-peak pricing at designated tier energy allowances. Tier levels for off-peak energy set at < 700 kWh for Tier 1 and > 700 kWh for Tier 2. Customers with domestic wells receive an additional 300 kWh Tier 1 allowance. The number of SPO customers is 452. The number of residential PowerStat customers enrolled in this rate as of 6/30/13 is 280 . Small Commercial: This combination small commercial rate (GSN_TCPP) consists of a two-period time of use pricing all the time and a critical period between 3-6 PM during the summer when critical peaks events can be called. Up to 12 events can be called. The number of small commercial PowerStat customers enrolled in this rate as of 6/30/13 is 4. Commercial AutoDR: Applicable commercial customers may opt-into Demand Response Peak Pricing Program rate (GPD_2). This rate is a TOU with CPP. During the critical peak there is 50¢ adder to the super peak price and a 2¢ adjustment downward to the off-peak price. The number of customers enrolled in this rate as of 6/30/13 is 0. |
Distributed energy resources | Quantity* | Capacity | Description | Cost |
---|---|---|---|---|
Distributed generation | 0 | 0 kW | $0 | |
Energy storage | 0 | 0 kW | $0 | |
Plug in electric vehicle charging points | 185 | 1,009 kW | $2,461,075 | |
Distributed energy resource interface | N/A | N/A | 2012 Direct Load Control Pilot Program: 2012 3rd quarter: 180 one-way programmable communicating thermostats (Honeywell UtilityPro) were installed on residential homes to test various precooling strategies before a demand response event. All used a temperature reset strategy. All the thermostats were installed by the end of July 2012. These PCTs receive a one-way paging type signal from the Cooper Power System Headend system.2012 4th quarter: Five participants dropped out of the program during this period. As a result, 175 participants/thermostats remained. 2013 1st quarter: The 2012 pilot program ended so these devices are not being counted for this quarter. For the 2013 pilot program, this quarter 239 PCTs were installed on 219 residential customers. Some customers had more than 1 PCT installed in the home.2013 2nd quarter: For the 2013 residential and small commercial pilot programs, a total of 860 residential customers had a total of 919 PCTs installed (some customers had more than 1 thermostat install at their home. A total of 15 small commercial customers had a total of 16 PCTs installed. Overall, 875 customers had 935 PCTs (devices) installed. All devices were installed by June 30, 2013.2013 3rd quarter: For the 2013 residential and small commercial pilot programs, a total of 836 residential customers had a total of 897 PCTs installed (some customers had more than 1 thermostat install at their home. A total of 12 small commercial customers had a total of 14 PCTs installed. Overall, 848 customers had 911 PCTs (devices) installed. 2013 4th quarter: For the 2013 residential and small commercial pilot programs, a total of 828 residential customers had a total of 889 PCTs installed (some customers had more than 1 thermostat install at their home. A total of 12 small commercial customers had a total of 14 PCTs installed. Overall, 840 customers had 903 PCTs (devices) installed. 2014 1st quarter: For the 2013 residential small commercial pilot | $0 |
Recipient information | Input |
---|---|
Total number of customers served by utility / utilities supporting the project | 672,860 |
Total number of residential customers served by utility / utilities supporting the project | 525,628 |
Total number of commercial customers served by utility / utilities supporting the project | 73,616 |
Total number of industrial customers served by utility / utilities supporting the project | 0 |
Total number of distribution circuits within utility service territory | 577 |
Total number of distribution substations | 228 |
Portion of distribution system with SCADA prior to SGIG/SGD program | 52 |
Portion of distribution system with distribution automation (DA) prior to SGIG/SGD program | 0 |
Electric distribution system | % | Description |
---|---|---|
Portion of distribution system with SCADA due to SGIG/SGD program | 17.10% | The numerator of this calculation is equal to the number of substations that had SCADA installed as part of the SGIG project (162). The denominator is equal to the total number of substation transformers in the service territory (234). This system is not being upgraded as part of the SGIG project it is being expanded. Therefore, all the capability of this system is described above. |
Portion of distribution system with DA due to SGIG/SGD program | 18.84% | The numerator of this equation is equal to the number of feeders that have DA equipment installed as a result of this project. The denominator is equal to the total number of feeders in the service territory (584). The devices being installed will allow the automated operation of switches and the automated optimization of voltage. It will also provide real-time information about substation and feeder conditions. This information can be used to improve load models and manage distribution system loads better. The automated recloser will also improve reliability be clearing and isolating faults sooner. |
DA devices installed and operational | Quantity* | Description | Cost |
---|---|---|---|
Automated feeder switches | 156 | The automated switches will enable us to implement automated switching schemes and improve FLISR. Feeder monitors and fault indicators will provide real-time data, improving system performance during peak loads and improved reliability by enabling fast isolation and restoration of faulted lines (FLISR). This information will also be used to improve load models and better manage distribution loads (especially at peak). Substation regulators in tandem with line Capacitors will enable automated voltage/VAR control. These assets along with measurements from AMI meters will enable more optimal voltage control. This will improve power quality and improve efficiency. | $25,369,557 |
Automated capacitors | 177 | $5,568,927 | |
Automated regulators | 0 | $0 | |
Feeder monitors | 0 | $0 | |
Remote fault indicators | 26 | $0 | |
Transformer monitors (line) | 0 | $0 | |
Smart relays | 155 | ||
Fault current limiter | 0 | $0 | |
Other devices | 0 | $0 |
SCADA and DA communications network | Cost |
---|---|
Communications equipment and SCADA | $16,904,153 |
Distribution management systems integration | Integrated | Description |
---|---|---|
AMI | No | |
Outage management system | No | |
Distributed energy resource interface | No | |
Other | No |
Distribution automation features / functionality | Function enabled | Description |
---|---|---|
Fault location, isolation and service restoration (FLISR) | No | This project is currently using the DA equipment installed to help identify faulted feeders and operate switches remotely from the Distribution Dispatch Center. This will help restore service quicker. In the future the goal is to implement complex automated switching schemes that will reduce the scope of outages by automatically restoring service to the maximum portion of customers after an event. |
Voltage optimization | Yes | This application allows more optimized control of voltage and Var levels of the distribution system. This will lead to better power quality and improved system efficiency. Regulators and capacitors are controlled remotely by an operator currently but will be controlled automatically in the future. All devices will be centrally controlled. Station Regulators and line capacitors will be coordinated to improve levels over the entire feeder. They will accomplish this by utilizing data from feeder monitors, and monitors that are part of other DA devices. When the system is automated the DMS will be primarily responsible for controlling the capacitor and regulator assets. |
Feeder peak load management | No | This application is not implemented at this time. When it is implemented a description of the benefits or capabilities will be approved |
Microgrids | No | |
Other functions | No |
* In some circumstances, costs are incurred before devices are installed resulting in a reported cost where the quantity is zero.
* All dollar figures are the total cost, which is the sum of the federal investment and cost share of the recipient (the recipient cost share must be at least 50% of the total overall project cost).
** In some cases the number of entities reporting is greater than the total number of projects funded by the Recovery Act because some projects have multiple sub-projects that report data. View list of sub-projects.