Transcript Distribution Automation Recap Presentation

2014 Electric T&D Benchmarking
Advanced Distribution
Automation
Discussion Topic
Community Insights Conference
August 20-22, 2014
Vail, CO
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
2
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
3
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)
4
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.
5
Advanced Distribution Automation – Major
Benefit Categories
*
Report titled “The Value of Distribution Automation” prepared for the California
Energy Commission (CEC) in March, 2009
* DER = Distributed Energy Resources – this term often encompasses Distributed
Generation, Distributed Storage and utility controllable Demand Response
6
2014 Questionnaire Responses
Distribution Automation
2014 Questionnaire Responses – Current Status of
Technology
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.
Now Pilot
2014 Company Technology Status* : /Limited
AMI: Smart meters
15%
AMI: AMI DMS integration
8%
AMI: Summer Saver Air conditioning
8%
AMI: Net Metering program
8%
DA: Remote controllers of switches and breakers
54%
DA: DMS/OMS
15%
DA: Automated capacitor controllers
46%
DA: Voltage and VAR control
54%
DA: Fault location based on wave shape analysis
31%
DA: Demand Response
0%
DG: Distributed Storage [battery]
38%
DG: Distributed Generation Integration
38%
DG: Plug-in Hybrid vehicles
31%
Other DA Technology
8%
Now
Widespread
54%
31%
13%
31%
38%
46%
15%
8%
0%
15%
0%
31%
15%
0%
* This table shows the percent of responding companies reporting each technology now
installed at each status level
8
Source: Question DP15
TOTAL
69%
39%
21%
39%
92%
61%
61%
62%
31%
15%
38%
69%
46%
8%
2014 Questionnaire Responses -- System Impact of
DA Technology
The responses show wide ranges in the % of various types of feeder devices
that can now be operated remotely via SCADA
% of Substation Breakers
Range: 0% to 100%
Source ST Report pages 21-23,
question ST110
% of Line Switches
Range: 0% to 62%
% of Cap Banks
Range: 0% to 100%
9
2014 Questionnaire Responses -- Customer Impact
of DA Technology
The responses also show wide ranges in the % of customers that are on
circuits with different types of remote or automatic switching
% on circuits with
remotely operated line
% on circuits with remotely
operated substation breakers switches
Range: 0% to 27%
Range: 15% to 100%
Source ST Report pages 24-26,
question ST115
% on circuits with
automatic FLISR schemes
Range: 0 to 8%
10
2014 Questionnaire Responses – Demand Response
Impact
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.
% of C/I Load
Range: 0% to 25%
Source DP Report pages 8 and 9,
question DP25
% of Residential Load
Range: 0% to 1.25%
11
2014 Questionnaire Responses - Advanced
Distribution Management Systems (ADMS)
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)
DP290: Do you have an
ADMS?
DP295: If you have an
ADMS, what modules do
you use?
Total Respondents
10
Yes
5
No
5
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
12
2014 Questionnaire Responses – Current Plus
Planned Installations Within 5 Years
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
Total Currently
Planned
Planned
FORECASTED
Technology Implementation Plans :
Installed
Pilot/Limited Widespread 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%
* 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
Source: Question DP15, responses from 13 companies
13
Summary of 2014 Webinar
Responses
Distribution Automation
Overview of Advanced DA Webinars – Discussion
Outlines
Webinar #1
Where are We?
June 18, 2014
Webinar #2
How Did We Get Here?
June 25, 2014
•
•
•
•
•
•
Technologies now in
place
o Pilots
o 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
Webinar #3
Where are We Going?
June 26, 2014
•
•
•
•
•
Planned installations
over next 5 years
o Pilots
o Widespread
Expected costs
Business cases
Regulatory or legislative
mandates
Integration with other
asset management
plans
15
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:
1.
2.
3.
4.
5.
6.
GIS
OMS
D-SCADA
DMS
AMI
Demand Response
16
System Integration Model
17
Webinar Participants
B.C. Hydro
Wei Fu
Oncor Electric Delivery
Nathan Kassees
Alex Machoka
CenterPoint Energy
Richard Moffatt
PECO Energy
Mickealia Bracy
John Reid
KCP&L
Bill Menge
Tucson Electric Power
Chris Fleenor
Tom Dudgeon
Northwestern Energy
George Horvath
Bill Endy
Westar Energy
Aaron Smith
Jim Gurney
18
Summary of Responses
DA Webinar #1
Where are We?
June 18, 2014
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 (microgrids)– 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
19
Summary of Responses (Cont.)
DA Webinar #1
Where are We?
June 18, 2014
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
20
Summary of Responses (Cont.)
DA Webinar #1
Where are We?
June 18, 2014
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
21
Summary of Responses
DA Webinar #2
How Did We Get Here?
June 25, 2014
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
22
Summary of Responses (Cont.)
DA Webinar #2
How Did We Get Here?
June 25, 2014
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.
23
Summary of Responses (Cont.)
DA Webinar #2
How Did We Get Here?
June 25, 2014
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.
24
Summary of Responses (Cont.)
DA Webinar #3
Where are We Going?
June 26, 2014
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
25
Summary of Responses (cont.)
◼
◼
◼
DA Webinar #3
Where are We Going?
June 26, 2014
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
26
Summary of Responses (Cont.)
DA Webinar #3
Where are We Going?
June 26, 2014
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
27
Summary of Responses (Cont.)
DA Webinar #3
Where are We Going?
June 26, 2014
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.
28
Measuring the Reliability
Benefits
of DA Investments
Distribution Automation
2013 Annual SAIDI Results versus Percent of
Customers on Circuits with Remote Switching
Capability
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.
Source: Questions DR5 and ST115
30
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
31
Challenges To Measuring the Impact of
Distribution Automation on Reliability Indices *
Issues encountered when attempting to measure overall system
performance “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”
32
Examples of External Research On SAIDI Reductions
From Distribution Automation Applications
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
http://www.publicpower.org/files/PDFs/Presentation_Slides_Smart_Grid
_Impact_on_Distribution_Reliability.pdf
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
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
https://www.smartgrid.gov/sites/default/files/doc/files/Distribution%20Re
liability%20Report%20-%20Final.pdf
33
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
34
Q&A
Outlines of Company Presentations Wednesday, August 20
Presentation
BG&E -- “Successful Approaches for
Engaging Customers in Demand
Response Programs”
Cheryl Hindes
Manager – Load Analytics
Heather Anderson
Manager – Energy Efficiency Programs
Austin Energy --- “Planning, Design and
Implementation of an Advanced
Distribution Management System
(ADMS)”
David Tomczyszyn, P.E.
Power System Consulting Engineer
Discussion Outline







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








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
36
Outlines of Company Presentations –
Thursday, August 21
Presentation
Discussion Outline
PSE&G— “DA’s Role Within the Energy
Strong Program”

Richard Wernsing
Manager, 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 “





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
Bill Menge
Director, SmartGrid
37
Thank you for your Input and Participation!
Your Presenters
Dave Canon
[email protected]
817-980-7909
Debi McLain Cook
[email protected]
760-272-7277
Ken Buckstaff
[email protected]
310-922-0783
Dave Carter
[email protected]
414-881-8641
Tim. Szybalski
[email protected]
301-535-0590
About 1QC
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
Satellite Offices
Corporate Offices
California
400 Continental Blvd. Suite 600
El Segundo, CA 90245
(310) 426-2790
Maryland
New York | Texas | Washington | Wisconsin
3 Bethesda Metro Center Suite
700
Bethesda, MD 20814
(301) 961-1505
38