advanced distribution automation discussion topic 2014 electric t&d benchmarking community...
TRANSCRIPT
Advanced Distribution AutomationDiscussion Topic
2014 Electric T&D Benchmarking
Community Insights Conference
August 20-22, 2014
Vail, CO
2
Agenda -- Advanced Distribution Automation
◼ Background ◼ Overall Findings◼ 2014 Questionnaire Responses◼ 2014 Webinar Responses◼ Brief Comments Re: Measuring the Reliability Benefits◼ Company Presentations:
Wednesday, August 20:• BG&E – Demand Response – Recruiting & Engaging Customers• Austin Energy – ADMS Planning, Design and Implementation
Thursday, August 21:• PSE&G – DA’s Role Within the “Energy Strong” Program• KCP&L – DA Technology Training and Support
3
Background
◼ We conducted Research Topics on “Intelligent Grid” in 2008 and “Distribution Automation” in 2011.
◼ Information on what our panel companies have been doing in this area has been collected annually through the main T&D benchmarking survey
◼ Our panel companies apparently are not progressing as quickly in implementing advanced distribution automation systems as was anticipated several years ago
◼ This year, we made some modifications to the questionnaire and also conducted three discussion topic webinars to better understand:
What our companies have accomplished to date through their DA initiatives What obstacles and challenges our companies have encountered while
implementing these systems The specific goals, plans and business cases that will be driving activity in this
area over the next several years
4
Overall Findings
◼ Most of the companies in our community are progressing in implementing Advanced Distribution Automation technologies, with a particular focus on technologies that perform the following “core DA functions”: Remote Monitoring & Control of Feeder Devices (Breakers, Switches,
Sectionalizers, Reclosers) Automated Fault Location & Fault Isolation between Feeder Devices Automatic Restoration via Centralized or Field Localized Intelligence Remote Monitoring & Control of Capacitors Automatic Voltage & VAR Control at the Circuit Level
◼ DA technologies that fall under the umbrella of “Distributed Energy Resources” are also being implemented by a large subset of the community, primarily in response to legislative or regulatory priorities in their states/provinces. These technologies perform the following functions: Remote Monitoring & Control of Customer Load Shedding (Demand Response) Real-Time Communications from the Utility to the Customer (Energy Usage &
Pricing Data) Remote Monitoring and Control of Distributed Generation Integration of Distributed Storage (Batteries) Automatic Islanding and Resynchronization (Micro-grids)
5
Overall Findings (Cont.)
◼ The companies that participated in our Webinars have documented the benefits achieved through their DA installations to date and are using this information to develop business cases for further development. The benefit categories that these companies have identified match those listed in a 2009 research report from Navigant Consulting, Inc. (see page 6).
◼ Many companies on the Webinar acknowledged that they have not progressed as quickly on their DA programs as they were expecting several years ago, due to internal management issues and/or to technical problems that they encountered in the areas of data communication and system integration
◼ Most companies in our community will be working over the next five years to expand their core DA technologies to impact a much larger percentage of their customers and will be justifying their additional DA investments on a stand-alone basis, rather than including them within the scope of a broader “grid modernization/improvement” initiative
◼ Only a few companies in our panel expect to be introducing new DER technology to their operations over the next five years.
◼ The expansion of DA technology in the field is driving companies to upgrade and better integrate their control systems in the Distribution Operations Center. Companies are also forming central DA groups to support their expanded DA applications.
Advanced Distribution Automation – Major Benefit Categories
6
*
* DER = Distributed Energy Resources – this term often encompasses Distributed Generation, Distributed Storage and utility controllable Demand Response
Report titled “The Value of Distribution Automation” prepared for the California Energy Commission (CEC) in March, 2009
2014 Questionnaire Responses
Distribution Automation
8
2014 Questionnaire Responses – Current Status of Technology
* This table shows the percent of responding companies reporting each technology now installed at each status level
2014 Company Technology Status* :Now Pilot /Limited
Now Widespread TOTAL
AMI: Smart meters 15% 54% 69%AMI: AMI DMS integration 8% 31% 39%AMI: Summer Saver Air conditioning 8% 13% 21%AMI: Net Metering program 8% 31% 39%DA: Remote controllers of switches and breakers 54% 38% 92%DA: DMS/OMS 15% 46% 61%DA: Automated capacitor controllers 46% 15% 61%DA: Voltage and VAR control 54% 8% 62%DA: Fault location based on wave shape analysis 31% 0% 31%DA: Demand Response 0% 15% 15%DG: Distributed Storage [battery] 38% 0% 38%DG: Distributed Generation Integration 38% 31% 69%DG: Plug-in Hybrid vehicles 31% 15% 46%Other DA Technology 8% 0% 8%
This chart provides an overview of technology status at the 13 responding companies as of 2014. 60% or more have installed the technologies shaded in dark blue and at least 40% have installed the technologies shaded in light blue.
Source: Question DP15
9
2014 Questionnaire Responses -- System Impact of DA Technology
% of Substation BreakersRange: 0% to 100%
% of Line SwitchesRange: 0% to 62%
% of Cap BanksRange: 0% to 100%
Source ST Report pages 21-23, question ST110
The responses show wide ranges in the % of various types of feeder devices that can now be operated remotely via SCADA
10
2014 Questionnaire Responses -- Customer Impact of DA Technology
% on circuits with remotely operated substation breakersRange: 15% to 100%
% on circuits with remotely operated line switchesRange: 0% to 27%
% on circuits with automatic FLISR schemesRange: 0 to 8%
Source ST Report pages 24-26, question ST115
The responses also show wide ranges in the % of customers that are on circuits with different types of remote or automatic switching
11
2014 Questionnaire Responses – Demand Response Impact
% of C/I LoadRange: 0% to 25%
% of Residential LoadRange: 0% to 1.25%
Source DP Report pages 8 and 9, question DP25
The responses that we received from 8 companies indicate that most are not able to interrupt very large blocks of load during periods of peak demand.
12
2014 Questionnaire Responses - Advanced Distribution Management Systems (ADMS)
Total Respondents 5
VoltVar Optimiization 4
Fault Location Isolation and Service Restoration (FLISR) 3
Network configuration 2
Training simulator 2
Other * * Includes Feeder Load Transfer (1 company) and AMS-OMS Interface (1 Company)
3
Source DP Report pages 83 and 84, questions DP290 and DP295
DP290: Do you have an ADMS?
DP295: If you have an ADMS, what modules do you use?
Five companies reported that they have implemented Advanced Distribution Management Systems to integrate core DA functions on a common platform. For these companies, Volt/VAR Optimization is the most commonly used ADMS module, followed by Fault Location, Isolation and Service Restoration (FLISR)
Total Respondents 10
Yes 5
No 5
13
2014 Questionnaire Responses – Current Plus Planned Installations Within 5 Years
* This table shows the percent of responding companies reporting that each technology is currently installed or is planned to be installed on a pilot/limited and/or a widespread basis within the next 5 years
Technology Implementation Plans :Total Currently
InstalledPlanned
Pilot/LimitedPlanned
WidespreadFORECASTED 2019 Status
AMI: Smart meters 69% 0% 31% 100%AMI: AMI DMS integration 39% 8% 15% 62%AMI: Summer Saver Air conditioning 21% 8% 0% 29%AMI: Net Metering program 39% 0% 8% 47%DA: Remote control – switches & brkrs 92% 8% 8% 100%DA: DMS/OMS 61% 8% 31% 100%DA: Automated capacitor controllers 61% 15% 15% 91%DA: Voltage and VAR control 62% 15% 8% 85%DA: Fault location 31% 23% 0% 54%DA: Demand Response 15% 8% 0% 23%DG: Distributed Storage [battery] 38% 15% 0% 53%DG: DG Integration 69% 0% 0% 69%DG: Plug-in Hybrid vehicles 46% 0% 0% 46%Other DA Technology 8% 0% 8% 16%
If the reported plans are carried out, 85% or more of the responding companies will have installed the technologies shaded in dark blue by 2019 and at least 50% will have installed those shaded in light blue
Source: Question DP15, responses from 13 companies
Summary of 2014 Webinar Responses
Distribution Automation
15
Overview of Advanced DA Webinars – Discussion Outlines
Webinar #1 Where are We?June 18, 2014
Webinar #2How Did We Get Here?June 25, 2014
Webinar #3Where are We Going?June 26, 2014
• Technologies now in place o Pilotso Widespread
• Customer impact and acceptance
• System integration levels
• Time in service• Documented benefits
• Driving forces for initiatives
• Evaluation of progress• Biggest obstacles
encountered• System performance
issues• Organization and
staffing impacts
• Planned installations over next 5 years o Pilotso Widespread
• Expected costs• Business cases• Regulatory or legislative
mandates• Integration with other
asset management plans
Advanced DA Discussion Topic Scope
Functions:
1. Remote Monitoring & Control of Feeder Devices (Breakers, Switches, Sectionalizers, Reclosers)
2. Automated Fault Location & Fault Isolation between Feeder Devices
3. Automatic Restoration via Centralized or Field Localized Intelligence
4. Remote Monitoring & Control of Capacitors
5. Automatic Voltage & VAR Control at the Circuit Level
6. Automatic Protection Reconfiguration
7. Remote Monitoring & Control of Customer Load Shedding (Demand Response)
8. Distribution Transformer Monitoring
9. Remote Monitoring & Control of Distributed Generation
10. Integration of Distributed Storage (Batteries)
11. Automatic Islanding and Resynchronization (Micro-grids)
12. Real‐Time Communications from the Utility to the Customer (Energy Usage & Pricing Data)
Related Systems:
13. GIS
14. OMS
15. D-SCADA
16. DMS
17. AMI
18. Demand Response
16
System Integration Model
17
18
Webinar Participants
B.C. HydroWei Fu
CenterPoint EnergyRichard Moffatt
KCP&LBill Menge
Northwestern EnergyGeorge HorvathBill Endy
Oncor Electric DeliveryNathan KasseesAlex Machoka
PECO EnergyMickealia BracyJohn Reid
Tucson Electric PowerChris FleenorTom Dudgeon
Westar EnergyAaron SmithJim Gurney
19
Summary of Responses
Current installed technologies: Companies reported differing levels of implementation for various types of DA technology. The responses can be summarized as follows:
◼ Remote control of substation breakers - All companies on the webinar except Northwestern Energy now control most or all of their distribution substation breakers via SCADA. Northwestern Energy is currently extending its communications system to reach distribution substations that serve about 90% of its customer base by 2020.
◼ Remote control of line devices (switches, sectionalizers and reclosers), remote control of capacitors, automatic voltage/VAR optimization and fault location, isolation and restoration (FLISR) - These are core functions that are included in all of the companies’ active DA initiatives.
◼ Distributed generation, distributed storage and automatic islanding/resynchronization (micro-grids)– B.C. Hydro and Tucson Electric have implemented all three of these technologies. KCP&L has implemented the first two and Oncor has implemented a distributed storage pilot. The other four companies on the webinar have not implemented any of these technologies
◼ Demand response and real time communications to customers – KCP&L, Northwestern Energy and Tucson Electric have implemented demand response systems and KCP&L and Northwestern Energy also provide real-time communication of energy usage and cost information to customers. The other five companies have not implemented either of these DA technologies, although some did mention their Outage website as an example of real time communications to customers.
◼ Distribution transformer monitoring (condition-based maintenance)– B.C.Hydro is the only company on the webinar that has implemented this technology
DA Webinar #1 Where are We?June 18, 2014
20
Summary of Responses (Cont.)
Customer impact and acceptance : ◼ Companies reported relatively low customer impact percentages (<20%) for much of the DA
technology that they have implemented. The exceptions are remote control of distribution substation breakers and remote control of capacitors – installed functions which now typically impact much higher percentages of the customer base.
◼ Companies reported that customers are generally not aware of the DA technology that is in place “before the meter”. Acceptance of DA technologies that directly impact and engage customers, such as demand response and real-time communications, varies across the customer base. More technically oriented customers like having the ability to interact with these systems but the majority seem to be indifferent and/or more happy with a “set it and forget it” solutions
System integration levels:◼ CenterPoint reported that they are currently engaged in a large scale effort to convert/integrate
their OMS and D-SCADA systems into a new Advanced DMS system. They plan to do a “flash cutover” in November of 2014
◼ PECO is installing a new DMS system in the fall of 2014 which will be tied to their D-SCADA◼ B.C. Hydro and KCP&L are also working on plans to integrate their OMS, DMS and D-SCADA ◼ Oncor reported that their OMS, DMS and D-SCADA are already fully integrated◼ The other companies reported more modest levels of system integration, typically focused on
one or both of the following areas: Using extracts from GIS systems to create and update the network models used by OMS and
DA-related systems Feeding outage detection data from AMI or AMR systems into OMS and DMS systems
DA Webinar #1 Where are We?June 18, 2014
21
Summary of Responses (Cont.)
Years in service:◼ Companies reported that that SCADA control of distribution substation breakers has
been in service for decades. Oncor’s technology for remote control of switches, line reclosers and capacitors has also been in service for about 10 years. The other companies indicated that their current DA technology other than substation SCADA is relatively new --- in service for three years or less.
Documented benefits:◼ Several companies reported that they are tracking the customer minutes of
interruption (CMI) that were saved through remote switching and/or the operation of their automated switching schemes. A question that was asked but not answered during the webinar is whether companies can attach a dollar value to these CMI savings.
◼ Northwestern Energy reported that they are currently developing a method to determine the dollar value of energy savings achieved through Voltage/VAR optimization on their current pilot system
◼ In addition to savings in the above two areas, Oncor has documented O&M labor cost reductions attributable to their remote switching capabilities
DA Webinar #1 Where are We?June 18, 2014
22
Summary of Responses
Driving forces for company DA initiatives:◼ Companies reported that the primary driving forces for their DA initiatives were internal goals to
improve reliability indices, restore customers more quickly, improve energy efficiency, reduce field operating labor costs, and defer capital expenditures for additional substation capacity.
◼ Four of the eight companies on the webinar advanced their DA initiatives through demonstration projects partially funded by the U.S. Department of Energy (CenterPoint, KCP&L, Northwestern and Westar). These demonstration projects are now coming to a close and the companies are determining whether the various technologies that were evaluated through the demonstration projects will be implemented on a wider-scale basis.
◼ CenterPoint also mentioned it’s 2008 Hurricane Ike experience, which focused attention on the potential “grid resiliency” benefits of DA, as an important factor in its DA program momentum.
◼ PECO said that the DA initiatives of its sister Exelon utilities (ComEd and BG&E) have also influenced what PECO has been doing in this area
Evaluation of progress to date:◼ Six of the eight companies on the webinar stated that their DA initiatives have not progressed as
quickly as they were expecting several years ago. They attributed the delays in progress to internal management issues (e.g., budget and manpower constraints, difficulties in quantifying benefits and developing project justifications) as well as technical problems that have been encountered in the areas of data communication and system integration
◼ KCP&L and Westar both stated that their progress is on track with their expectations from several years ago. It should be noted that KCP&L’s DA program is relatively advanced and mature while Westar has been proceeding at a relatively slow and deliberate pace
DA Webinar #2How Did We Get Here?June 25, 2014
23
Summary of Responses (Cont.)
Biggest obstacles and challenges encountered: Company responses to this question were quite diverse:
◼ B.C. Hydro’s, CenterPoint’s, KCP&L’s and Northwestern Energy’s responses focused on technology compatibility issues and “bugs” – they noted that the technology is complex and all components did not initially perform as expected and promised, particularly with regards to integration and interoperability. It took some time to work through all of the technology issues.
◼ PECO’s response focused on problems related to its communications links with field devices◼ Oncor and Tucson Electric responses focused on difficulties that they have encountered in
quantifying system benefits, developing project justification and getting internal stakeholders “on board” with the developments
◼ Westar’s response focused on resource constraints with regards to the field labor needed to install and maintain the field technology
◼ B.C. Hydro and KCP&L also referenced “culture change” issues, in particular the educational and training efforts that are needed to help ensure that operations personnel will accept and make good use of the technology
◼ CenterPoint, Oncor and Westar also spoke about overall system planning and integration issues, in particular the need to install a Distribution Management System (DMS) as a key foundational element. In this area, Oncor also mentioned the need for systems that monitor performance of the communications links between field devices and connecting the field devices to systems in the company’s control center.
DA Webinar #2How Did We Get Here?June 25, 2014
24
Summary of Responses (Cont.)
System performance issues: ◼ All of the companies reported that they have been able to troubleshoot and fix any system
performance and communications issues that have been encountered with the assistance of their technology vendors and telecommunications providers. Overall, the installed systems are performing as expected.
Organizational and staffing impacts:◼ B.C. Hydro, KCP&L, Oncor and Westar have established centralized Distribution Automation
Engineering Groups which are responsible for the planning, design, implementation and monitoring of all of their DA systems. The other four companies are contemplating that organizational step as they complete pilot projects which were handled by special ad-hoc project teams.
◼ All companies reported that they use their regular in-house and/or normal contract field employees (e.g., line crews and substation relay technicians) to install and maintain field devices. Most have relied on vendors to provide technical support and training to their field employees. However, Oncor has created an internal “Field Tech” group to provide that type of support and KCP&L is also considering that organizational step.
◼ Companies stated that they have used and/or plan to use outside consultants for the design and installation of large scale automation control systems (e.g., D-SCADA, DMS) and two (KCP&L and PECO) are using service providers to host portions of their communications and control system architecture that supports DA.
DA Webinar #2How Did We Get Here?June 25, 2014
25
Summary of Responses (Cont.)
Planned installations over the next five years:◼ Remote control of substation breakers - Northwestern Energy will be extending SCADA
communications to its rural distribution substations, covering 90% of its customer base by 2020. KCP&L is also considering an initiative to extend communications to its more rural substations.
◼ Remote control of line devices (switches, sectionalizers and reclosers), remote control of capacitors, automatic voltage/VAR optimization and fault location, isolation and restoration (FLISR) - All of the webinar participants except Northwestern Energy plan to further develop and expand the coverage of these core DA technologies over the next five years. The company plans typically include adding large numbers of smart line devices to break circuits down into smaller load segments and implementing new or enhanced control systems (e.g., ADMS, OMS systems linked to D-SCADA) to monitor and control the devices via communications ties.
◼ Remote controlled and/or automated protection reconfiguration - Both B.C. Hydro and Tucson Electric plan to implement advanced technology in this area to better support their relatively extensive plans for automated FLISR and distributed generation
DA Webinar #3Where are We Going?June 26, 2014
26
Summary of Responses (cont.)
◼ Distributed generation, distributed storage and automatic islanding/resynchronization (micro-grids)– B.C. Hydro currently makes extensive use of these technologies and Tucson Electric plans to expand its applications due to state regulation that is requiring the expansion of renewable energy sources. KCP&L has formed a non-regulated subsidiary to do solar installations and is looking for a location to pilot micro-grid technology. None of the other companies on the webinar plan to implement any of these technologies over the next five years
◼ Demand response and real time communications to customers – Tucson Electric is the only company on the webinar that plans to implement a wide-scale load shedding capability with time of use rates. The other companies on the webinar that now have these technologies in place (KCP&L and Northwestern Energy) have no current plans to expand their applications
◼ Distribution transformer monitoring (condition-based maintenance) – B.C. Hydro has this technology in place. None of other companies on the webinar plan to implement this technology over the next five years
DA Webinar #3Where are We Going?June 26, 2014
27
Summary of Responses (Cont.)
Expected spending:◼ The companies that were willing to discuss their projected DA spending cited figures in the range
of $10 million to $100 million in total spending over the next five years, covering both the development of communications and control systems and the installation of field devices
Business cases for further development:◼ Companies reported that their business cases for additional DA development over the next five
years will focus on the same types of measureable benefits as were discussed previously: improving reliability indices, restoring customers more quickly, improving energy efficiency, reducing field operating labor costs, and deferring capital expenditures for additional line and substation capacity.
◼ The non-measurable benefits that some companies will be referencing in their business cases include increased customer satisfaction, improved safety and regulatory compliance
Legislative or regulatory mandates:◼ Tucson Electric indicated that its DA plans relating to distributed generation and demand
response are being driven in part by regulatory mandates in Arizona. ◼ Oncor reported that Texas regulation provides a capital cost recovery mechanism for DA
investments but that mechanism is not particularly attractive from an earnings perspective. Oncor has not made use of it to date.
◼ KCP&L reported that the ability to use DA to monitor critical field equipment such as capacitor banks reduces its costs of complying with regulations in Missouri regarding mandatory equipment inspections.
◼ None of the other companies on the webinar referenced any legislative or regulatory mandates related to DA
DA Webinar #3Where are We Going?June 26, 2014
28
Summary of Responses (Cont.)
Integration with other Asset Management plans:◼ Companies reported that their DA initiatives have generally been presented and
justified on a standalone basis or as individually justified parts of an overall automation plan for the distribution business.
◼ Northwestern Energy is the only company on the webinar that is currently engaged in a large-scale “Distribution Infrastructure Improvement Program”. One of the major goals of that program is constructing a high-speed communications backbone across their widely disbursed territory in order to make their distribution system “automation ready”
◼ None of the companies on the webinar are currently engaged in any large scale “grid hardening” and/or “grid resiliency” initiatives that encompass DA.
DA Webinar #3Where are We Going?June 26, 2014
Measuring the Reliability Benefitsof DA Investments
Distribution Automation
30
2013 Annual SAIDI Results versus Percent of Customers on Circuits with Remote Switching Capability
Source: Questions DR5 and ST115
Our correlations of company 2013 SAIDI results to the percentages of customers on circuits with remote switching capabilities do not illustrate any benefits from this technology.
31
10 Year SAIDI Trends – First Quartile T&D Community Averages
We know that the companies in our community have been adding various types of automation over the past several years, yet it is hard to demonstrate that these investments have resulted in any SAIDI improvements (Note: there have been some changes in panel composition)
Source: Question DR5, calculated mean values for entire panel each year
32
Challenges To Measuring the Impact of Distribution Automation on Reliability Indices *
Issues encountered when attempting to measure overall systemperformance “With or Without” or “Before and After” DA: No two utility systems are alike No two DA solutions are alike Background year-to-year outage variability Combination effects with other investments Data collection system changes (e.g., new vs. legacy OMS) Isolating “abnormal” outage events including major storms Current pilot/limited-scale applications focus only on selected individual circuits
Issues when attempting to predict the impact of planned DA installations: Prototype circuit simulation is commonly used to isolate extraneous effects and predict
the direct impact of a given DA scheme. However, these simulation models are based on predictions or estimates of equipment failure rates, mean times to repair and manual switching times which may not be accurate for the system being studied nor extendable to other utility distribution systems
* This list is an expansion of ideas presented in a February 26, 2014 DEED/DSTAR webinar titled “Discussion of Smart Grid Impact on Distribution Reliability”
33
Examples of External Research On SAIDI Reductions From Distribution Automation Applications
http://www.publicpower.org/files/PDFs/Presentation_Slides_Smart_Grid_Impact_on_Distribution_Reliability.pdf
DEED/DSTAR Research – Results presented to APPA on February 26, 2014:Simulation study on an urban residential feeder predicted SAIDI reductions of 9.7% to 67.8% on “blue-sky” days, depending on what automated designs were implemented. Costs of automated designs ranged from $5,000 to $256,000
EDD Research by Dr. Robert Broadway – December 3, 2013 Presentation:Simulation study on a combined commercial/residential feeder predicted 0.4% to 4.3% SAIDI reduction on storm days, depending on the type and severity of the storm (only one automated design was analyzed)
http://www.bnl.gov/wius2013/talks/pdf/RBroadwater.pdf
https://www.smartgrid.gov/sites/default/files/doc/files/Distribution%20Reliability%20Report%20-%20Final.pdf
U.S. Department of Energy Report – “Reliability Improvements From The Application of Distributed Automation Technologies – Initial Report”, December, 2012: Documented actual SAIDI changes ranging from a 2% increase to 43% decrease on four completed Smart Grid Investment Grant (SGIG) projects
34
The Design and Impacts of Automation Projects Vary
This chart from the DOE report shows that all four of the evaluated SGIG projects significantly reduced SAIFI. Three of the four also reduced SAIDI, while one resulted in slightly higher SAIDI. Three of the four resulted in higher CAIDI, while one resulted in slightly lower CAIDI for the circuits in the project scope
Q&A
36
Outlines of Company Presentations - Wednesday, August 20
Presentation Discussion OutlineBG&E -- “Successful Approaches for Engaging Customers in Demand Response Programs”
Cheryl HindesManager – Load AnalyticsHeather AndersonManager – Energy Efficiency Programs
Background on current and planned demand response programs Customer research and segmentation Customer outreach and recruitment Customer choices offered – technology options and cycling
strategies Customer interface Metrics Current status, lessons learned and future plans
Austin Energy --- “Planning, Design and Implementation of an Advanced Distribution Management System (ADMS)”
David Tomczyszyn, P.E.Power System Consulting Engineer
Evolution of systems in the Distribution Operations Center System architecture pre-ADMS New system architecture with ADMS Business case for ADMS Hardware and software choices Overall project timeline Operator training Current status, lessons learned and future plans
37
Outlines of Company Presentations – Thursday, August 21
Presentation Discussion OutlinePSE&G— “DA’s Role Within the Energy Strong Program”
Richard WernsingManager, Asset Strategy - Electric
Background on program – impact of 2011 and 2012 storms; rationale to make additional investments on top of all existing reliability-related programs and investments
Energy Strong program overview – hardening and resiliency work Storm restoration strategy using DA Detail on DA components of Energy Strong program Planned future automation investments to improve storm response
KCP&L — “DA Technology Training and Support “
Bill MengeDirector, SmartGrid
Overview of installed and planned DA technologies Identified training and support requirements Formal training programs Support for troubleshooting and fixing technology problems Lessons learned and future plans
Thank you for your Input and Participation!
38
Corporate Offices
California
400 Continental Blvd. Suite 600El Segundo, CA 90245(310) 426-2790
Maryland
3 Bethesda Metro Center Suite 700Bethesda, MD 20814(301) 961-1505
New York | Texas | Washington | Wisconsin
First Quartile Consulting is a utility-focused consultancy providing a full range of consulting services including continuous process improvement, change management, benchmarking and more. You can count on a proven process that assesses and optimizes your resources, processes, leadership management and technology to align your business needs with your customer’s needs.
Visit us at www.1stquartileconsulting.com | Follow our updates on LinkedIn
About 1QC
Satellite Offices
Debi McLain [email protected]
Tim. [email protected]
Dave [email protected]
Dave [email protected]
Your Presenters
Ken Buckstaff [email protected]