Exhibit ___ (IIP-13) Page 1 of 82 0 0 . . 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 450 200.0 700.0 150.0 450.0 200.0 , 14500 1 3,749.9 1,450.0 1,600.0 1,800.0 1,650.0 1,550.0 2,100.0 3,700.0 2,325.0 2,250.0 7,300.0 5,199.8 13,449.9 5 Yr. Total 0 0 . . 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 300300 0 800.0 200.0 200.0 300.0 300.0 450.0 250.0 200.0 300.0 2,050.0 1,000.0 1,100.0 FY17 0 0 . . 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 300300 0 800.0 200.0 300.0 300.0 250.0 400.0 600.0 300.0 2,200.0 1,100.0 1,100.0 FY16 Working 0 0 . . Year Total 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 300300 0 700.0 200.0 200.0 400.0 300.0 750.0 400.0 400.0 199.9 300.0 999.9 Total Dollars ($000) Total Dollars 1,200.0 2,299.9 Current 5 Year Budget FY15 0 0 . . 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 250.0 700.0 300300 0 150.0 200.0 200.0 500.0 300.0 500.0 300.0 400.0 300.0 250.0 400.0 999.9 1,800.0 2,450.0 FY14 0 0 . . 0.0 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 700.0 250250 0 500.0 500.0 300.0 250.0 150.0 200.0 250.0 1,000.0 3,050.0 2,200.0 4,450.0 1,000.0 FY13 0 0 . . 0.0 0.0 0.0 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 250250 0 200.0 250.0 250.0 200.0 200.0 250.0 500.0 1,900.0 3,000.0 6,500.0 1,250.0 FY12 Year Total Year Forecast 2012 Forecast Total Dollars ($000) Total Dollars 0 0 . . 6.0 0.0 0.0 10 1 0.0 1.0 0.0 0.0 0.0 0.0 1.0 0.0 67.0 49.0 339 120.0 892.0 174.0 718.0 932.0 153.0 338.0 175.0 548.0 152.0 900.0 347.0 203.0 913.0 , (170.0) 13390 1 1,064.0 1,244.0 1,006.0 7,423.0 9,849.0 9,396.0 29,570.0 13,198.0 5 Yr. Total 0 0 . . 0.0 5.0 0.0 0.0 0.0 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3.0 0.0 0.0 0.0 0.0 0.0 IT 20.0 506.0 102.0 257257 0 199.0 298.0 287.0 245.0 519.0 2,054.0 1,295.0 FY11 0 0 0 . . 0.0 0.0 0.0 0.0 0.0 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.0 0.0 0.0 0.0 0.0 0.0 0.0 (84.0) 386.0 100.0 284.0 214.0 380380 0 330.0 524. 272.0 210.0 219.0 2,134.0 2,530.0 2,687.0 FY10 Year Total Year 0 0 .0 . . 0.0 0.0 0 0.0 0.0 0.0 0.0 0.0 0.0 00 0 0.0 0.0 0.0 0.0 8.0 0.0 0.0 1.0 1.0 0.0 (8.0) 37.0 33.0 13.0 230.0 434.0 629.0 172172 0 760.0 438.0 590.0 191.0 149.0 Total Dollars ($000) Total Dollars Previous 5 Year Actual FY09 0 0 .0 . . 2.0 1.0 0.0 0.0 5.0 00 0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 9898 0 45.0 28.0 51.0 (53.0) 298 297.0 245.0 253.0 310.0 137.0 151.0 FY08 0 0 .0 5,000.0 1,568.0 . . 6.0 0.0 0.0 0.0 0.0 0.0 5.0) 0.0 0.0 0.0 10 1 1.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 152.0 152.00.00.0 129.0 0.0 1,154.0 0.00.0 343.0 0.0 0.0 776.0 0.0 0.0 2,402.00.0 0.0 0.0 0.0 750.0 0.0 0.0 1,000.0 0.0 0.0 999.9 0.0 0.0 999.9 0.0 0.0 1,100.0 0.0 0.0 1,100.0 5,199.8 0.0 0.0 100.0 325.0 100.0 500.0 500.0 0.0 500.0 500.0 0.0 0.0 0.0 0.0 0.0 60.0 77.0 49.0 (1 136.0 138.0 432432 0 990.0139.0 1,360.0 139.0 4.0 0.0 2,493.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 583 125.0 149.0 151.0 (117.0) 7, 787.0 1,871.0 1,252.0 1,278.0 4,213.0 FY07 Sub-Total 10,567.0 9,624.0 4,795.0 Sub-Total Sub-Total 1,377.0 1,882.0 5,957.0 ** nhancements
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O ystem ystem Electric Transmission Electric Substations Central Engineering Maintenance & Construction Information Technology Information Technology Information If ti T h l Information Technology Operation Management System At Energy Control Center Control Energy At System Management Operation Outage Scheduling System Scheduling Outage System Management Energy SOCCS Program Replacement System Management Energy SOCCS-X Program Replacement Steam EMS FMS - Feeder Management System - Feeder Management FMS EMS for New Modification RTU SOCCS Operations Network For Ems Network Operations Ecc - Distribution Orders Automation E Automation Orders - Distribution Ecc Replacement - System Direct Oper District Conversion** PDF Microfiche 2** acement Repl Explorer - Metaphase Project District Operator Task Managing Operator District Model Steam Dynamic ECC SOCCS Visualization System Feeder Management System Management Steam GT Remote Start System Remote GT Plant Information System Information Plant Wiring Access Raceway System (WARS) System Raceway Access Wiring Ems Continuance Ecc Continuance Ems Disaster Recovery Replication - FMS Computerized Notification SystemComputerized Program)** Upgrade Equipment (Engineering AutoCAD Manuals** Equipment Digitized Compass Rewrite Plus** Cyber Security And Nerc Compliance Nerc And Security Cyber StS O tiEh Replacement CNS for ACC Network Communication t SOCCSX Continuance SOCCS-X RTU Conversion System Up Back Steam Technology Improvements Maximo Upgrade Asset Optimization** CCI Mobile Office** Rapid Restore Enhancements Restore Rapid SOCCS - RTU Replacement - RTU SOCCS Work Permit Processing Work Permit Exhibit ___ (IIP-13) Page 2 of 82 7,150.0 5,675.0 17,400.0 59,795.0 59,100.0 2,244.7 118,895.0 5 Yr. Total 250.0 1,750.0 4,000.0 4,000.0 2,750.0 FY17 250.0 1,750.0 2,750.0 12,947.0 12,947.0 FY16 Working Year Total Total Dollars ($000) Total Dollars 1,500.0 2,250.0 5,000.0 12,666.0 12,666.0 Current 5 Year Budget FY15 8,112.0 1,500.0 2,250.0 4,750.0 FY14 650.0 675.0 ,150.0 1,750.0 2 49,100.0 10,000.0 22,070.0 72,920.0 18,112.0 FY13 0.0 680.0 894.0 1,574.0 46,285.0 46,285.0 FY12 Year Total Year Forecast 2012 Forecast Total Dollars ($000) Total Dollars 0.0 0.0 20.0 580.0 720.0 50,794.3 64,381.8 5 Yr. Total purposes.
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Projects ‐ Electric Distribution Information Technology Note Budget Reference Number PR.6XC1302** Number Reference Budget IT Projects Reinforcement System System Information Efficiency Energy Budget Reference Number PR.6XC1304** Number Reference Budget Integrated GIS Solutions** Integrated GIS Work Mangement System Work Mangement Common Exhibit ___ (IIP-13) Page 3 of 82
2013 Capital - Central Operations/Transmission & Substation Operations
Project Name Cyber Security Project Number Work Plan Category Reg - Agency Mandated Priority Project Manager Threet, Michael Project Engineer Wernsing, David Budget Reference 4ET9704 Project Status Ongoing Program End Date Dec 31 2017 ERM Addressed Oper Risk 20 West End Ave. ECC Loss,Admin Risk 18 Prolonged Computing or Communication System Failure,Admin Risk 34 Unsupported Computer Systems,Oper Risk 29 Cyber Attack Materially Adverse Impact
Work Description: To improve our cyber security posture and to comply with expanding cyber security regulatory requirements, the current Operation Network needs to be divided into smaller security zones based on functionality. The current patch management and inventory control processes are labor intensive requiring repetitive manual entry and intervention. Several enhancements have been identified to automate processes and track program compliance thereby increasing productivity and decreasing the potential for errors. Additionally, several enhancements have been identified to expand and improve the current cyber security monitoring and event detection systems that will implement the next generation of event monitoring, detection, and reporting.
New systems and requirements will be identified as new technologies become available and the opportunity to automate is identified. It is also anticipated that the NERC (The North American Electric Reliability Council) requirements will continue expanding in scope and complexity. As these requirements are identified, solutions will be engineered and implemented.
Justification: System Operation relies heavily on its cyber assets for operation, analysis and day-to-day business. Nearly every tool used to operate Con Edison's electric system and support that operation is dependent on our cyber assets. r. As the sophistication of cyber threats increases so to must the systems that protect our systems from those threats.
Segregating systems by functionality into separate security zones Exhibit ___ (IIP-13) Page 4 of 82
follows industry best practices allowing each system’s protection scheme to be customized for its requirements only. This protection scheme protects each system from the vulnerabilities of other systems thereby limiting the exposure of each system.
The NERC Cyber Security regulations are expanding. These changes will drastically change the patch management, asset monitoring, and configuration control requirements, which are the most labor intensive portions of our compliance program. Several system enhancements will address some of the new asset monitoring requirements. One of the focuses of this project is to identify portions of our patch management and configuration control processes that can be automated. Collecting an active inventory of all of our assets is the first step toward automating our inventory and patch management processes.
The Intrusion Detection System (IDS) has been installed in both control centers. This system will be expanded and incorporated into our cyber security plan. As the above mentioned changes are implemented, the IDS will also require additional expansion to ensure all network traffic is monitored and modeled in the system.
* Alternatives: The alternative is to leave our systems as they are and rely on security controls that are not keeping pace with cyber security improvements in technology and awareness. * Risk of No Action: This will expose the Company to possible Cyber Security regulation violations and fines. Failing to maintain an updated security posture also increases the likelihood our control systems will be compromised. * Non Financial Benefit Explanation: * Technical Evaluation and Analysis: * Project Relationships:
Current Status: Current Working Estimate:
Funding: ($000s)
Funding 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Total Cost $0 $0 $0 $438 $524 $50 $300 $300 $300 $400 $300 $300 $350 $3,262
Benefit: ($000s)
* 2008 to 2012 Budget in $1,312 Thousands- Exhibit ___ (IIP-13) Page 5 of 82
* 2013 to 2017 Budget in $1,600 Thousands-
* Authorization- $1,000,000 * Appropriation- $700,000
Exhibit ___ (IIP-13) Page 6 of 82
Exhibit ___ (IIP-13) Page 7 of 82
2013 Capital - Central Operations/Transmission & Substation Operations
Project Name District Operator Task Managing System Project Number Work Plan Category Strat - Strategic IT Enhancements Priority Project Manager Scholz, Richard Project Engineer Hui, Sun Budget Reference 3ET9805 Project Status Ongoing Program End Date Dec 31 2017 ERM Addressed Oper Risk 06 Prolonged Electric Outtage Impact Customers
Work Description: This project has been established to enhance the issuance of operating orders and the tracking of status changes on the transmission and distribution system. The Task Management system will provide the District Operators (D.O.) with a timely and integrated view of all jobs within their specific jurisdiction requiring operator action. This task provides application oversight and reports to ensure timely operator and field response to work orders and feeder processing.
The new software functionality includes computerized warnings and other indications that will facilitate timely and error free feeder processing. New operator consoles will be added to support these new applications. The new 3G Feeder Networks will be modeled and integrated into the electronic order flow. The task manager implementation is planned to be implemented and completed in multiple phases. After initial rollout, interfaces with Rapid Restore, FeederBoard and HUD will need to be updated to reflect the changes in 3G field conditions and connections.
Justification: An enhanced D.O. environment will better facilitate continued efficiency. The District Operator coordinates and directs all switching operations on Con Edison's transmission and distribution system. To meet these job responsibilities, the D.O. must use multiple computer systems. These include the new XA system, Feeder Management System (FMS), Transmission Operation Management System (TOMS), Telephone Line System (TLS), and other corporate systems such as Rapid Restore, DO Direct, Outage Scheduling System (OSS), etc. Each of these systems has different user interface, and operates from different vendor platforms and operating systems. This enhancement project will allow the operator to more efficiently manage the varied and multiple systems needed to perform their critical tasks from a common graphical interface.
Exhibit ___ (IIP-13) Page 8 of 82
* Alternatives: * Risk of No Action: * Non Financial Benefit Explanation: * Technical Evaluation and Analysis: * Project Relationships:
Current Status: Current Working Estimate:
Funding: ($000s)
Funding 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Total Cost $168 ($15) $297 $33 $330 $250 $300 $250 $300 $300 $300 $300 $300 $3,113
Benefit: ($000s)
* 2008 to 2012 Budget in $1,210 Thousands- * 2013 to 2017 Budget in $1,450 Thousands-
* Authorization- $2,000,000 * Appropriation- $1,900,000
Exhibit ___ (IIP-13) Page 9 of 82
2013 Capital - Central Operations/Transmission & Substation Operations
Project Name Distribution Orders Enhancements Project Number Work Plan Category Strat - Strategic IT Enhancements Priority Project Manager Scholz, Richard Project Engineer Sun, Hui Budget Reference 2ET9801 Project Status Ongoing Program End Date Dec 31 2017 ERM Addressed Oper Risk 06 Prolonged Electric Outtage Impact Customers
Work Description: The Operations Management System (OMS) used by the District Operators for issuing operating orders requires enhancements. These enhancements are a collection of new capabilities which include, but are not limited to the following:
• improvements to the programming for electronic issuance of operating orders, • creation of new interfaces to corporate data and systems which interface with the existing programming, enhanced disaster recoverability, • increased automation of field operations • upgrades to the diagrams that help the operator visualize connectivity of the distribution feeders within the network. • appropriate upgrades and modifications will be developed and implemented during real-time use that further support reduction in feeder processing times, improvements to productivity, or aid in the prevention of operating errors,
Justification: In order to further reduce feeder-processing time, additional areas in distribution order automation need to be implemented and enhanced. Systems need to be upgraded to keep pace with technology requirements and to support increased needs.
The complexity of the transmission and distribution systems and their overlapping relationships rely heavily on informed operators equipped with state of the art tools. The interconnection of generation and the nature of interconnected operation continue to create challenges that require fast and well-informed responses to system conditions. The operators currently rely on the existing system to aid in processing work and making operating decisions. Therefore, it is beneficial and in the interest of the company that enhanced information technologies, upgrades to the existing system, Exhibit ___ (IIP-13) Page 10 of 82
and independent disaster recoverability be leveraged to support these objectives.
* Alternatives: Delay improvements to electronic order processing. * Risk of No Action: No action will limit work on systems to performing only corrective actions of the existing system in place. This could lead to decreased automation and limited functionality in the future. It would also prevent future improvements of the system applications with other users and systems. * Non Financial Benefit Explanation: * Technical Evaluation and Analysis: * Project Relationships:
Current Status: Current Working Estimate:
Funding: ($000s)
Funding 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Total Cost $52 $149 $151 $149 $219 $300 $350 $250 $400 $300 $300 $300 $300 $3,219
Benefit: ($000s)
* 2008 to 2012 Budget in $1,169 Thousands- * 2013 to 2017 Budget in $1,550 Thousands-
* Authorization- $2,000,000 * Appropriation- $1,622,000
Exhibit ___ (IIP-13) Page 11 of 82
2013 Capital - Central Operations/Transmission & Substation Operations
Project Name EMS Reliability AECC And ECC Project Number Work Plan Category Oper - Emergency Response Priority Project Manager Saad, Abdo Project Engineer Mostoslavsky, Alex Budget Reference 0ET9801 Project Status Ongoing Program End Date Dec 31 2017 ERM Addressed Oper Risk 06 Prolonged Electric Outtage Impact Customers,Oper Risk 20 West End Ave. ECC Loss,Admin Risk 18 Prolonged Computing or Communication System Failure,Admin Risk 34 Unsupported Computer Systems
Work Description: This program will provide XA21 software enhancements and the first operating system and hardware replacement for the Energy Management System (EMS). This first system replacement of the EMS for the transmission and distribution system will ensure that the latest improvements from the manufacturer are added to our system and that the hardware will support the needs of new operating systems. The systems first vendor software platform release and hardware replacement is planned for 2012 / 2013. Future years will support needed application enhancements as necessary to support operational needs.
Justification: The EMS for the transmission and distribution system needs to be replaced periodically to ensure that the latest improvements from the manufacturer are added to our system, and to avoid hardware obsolescence and incompatibility with routine software and operating system updates The current EMS was purchased in 2006 and is now 6 major versions behind the vendor’s latest software release, and the hardware does not support the latest operating systems.
In order to maintain the EMS at peak performance and to ensure that the latest advancements developed by the manufacturer are utilized, periodic system replacement needs to be planned and performed. Through continued periodic replacements, we will ensure that the manufacturer will be able to provide and maintain our systems for many years.
This needed system replacement will ensure that the system will remain compliant with cyber security guidelines and will provide improved features for operator and support staff use.
Exhibit ___ (IIP-13) Page 12 of 82
* Alternatives: Leave the system software and hardware at their current levels and do not take advantage of enhancements or system upgrades. This will also risk the loss of security patch support placing the system without antivirus / malware protection. * Risk of No Action: Not enhancing the EMS would cause the system to eventually become less effective in meeting our operational goals. In addition, by not maintaining operating systems and system hardware at industry standards, the EMS systems and software would no longer be supported by the vendor and its 3rd party suppliers. The loss of vendor support for security patch releases would make the EMS non- compliant with NERC CIP regulations which would likely impose financial penalties on the company. * Non Financial Benefit Explanation: * Technical Evaluation and Analysis: * Project Relationships:
Current Status: Current Working Estimate:
Funding: ($000s)
Funding 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Total Cost $0 $0 $0 $0 $386 $400 $3,000 $3,050 $300 $200 $0 $200 $2,500 $10,036
Benefit: ($000s)
* 2008 to 2012 Budget in $3,786 Thousands- * 2013 to 2017 Budget in $3,750 Thousands-
* Authorization- $500,000 * Appropriation- $400,000
Exhibit ___ (IIP-13) Page 13 of 82
2013 Capital - Central Operations/Transmission & Substation Operations
Project Name Operation Management System Enhancements Project Number Work Plan Category Reg - Agency Mandated Priority Project Manager Scholz, Richard Project Engineer Sun, Hui Budget Reference 7ET9804 Project Status Ongoing Program End Date Dec 31 2017 ERM Addressed Oper Risk 06 Prolonged Electric Outtage Impact Customers,Admin Risk 18 Prolonged Computing or Communication System Failure,Admin Risk 34 Unsupported Computer Systems
Work Description: This project will address upgrades to the Operations Management Systems (OMS) computer systems and provide for expansion of these systems to better support the needs of the operators and field services. This work will also support infrastructure needed for replication of systems at the Alternate Energy Control Center (AECC) for disaster recoverability.
This will include the replacement of the current Feeder Management System (FMS) replication system by Virtual Machine platforms for improved reliability and disaster recoverability.
Justification: This project is needed to maintain OMS computer system hardware and operating systems near current industry levels to continue to maintain high system performance, and to ensure cyber security related patches are supported by vendors.
The Operations Management Systems needs to be maintained and expanded to meet the growing operational needs and to maintain a reliable work management system. As application needs grow, efficiencies will be maintained by providing frequent upgrades of operating systems and hardware so that software issues related to older operating system conflicts are avoided. System expansion is also planned to provide fully independent support systems at the AECC.
The use of Virtual Machines will improve the reliability of replicating databases which is critical for redundancy and disaster recoverability.
Note: Virtual Machine architecture is a newer technology where multiple software images exist on a single physical server instead of Exhibit ___ (IIP-13) Page 14 of 82
several computers. The applications reserve a portion of the physical server’s resources for their specific use.
* Alternatives: * Risk of No Action: * Non Financial Benefit Explanation: * Technical Evaluation and Analysis: * Project Relationships:
Current Status: Current Working Estimate:
Funding: ($000s)
Funding 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Total Cost $0 $0 $298 $434 $214 $200 $400 $150 $400 $400 $400 $450 $450 $3,796
Benefit: ($000s)
* 2008 to 2012 Budget in $1,546 Thousands- * 2013 to 2017 Budget in $1,800 Thousands-
* Authorization- $2,000,000 * Appropriation- $1,000,000
Exhibit ___ (IIP-13) Page 15 of 82
2013 Capital - Central Operations/Transmission & Substation Operations
Project Name Operations Network For EMS Project Number Work Plan Category Reg - Agency Mandated Priority Project Manager Threet, Michael Project Engineer Wernsing, David Budget Reference 9ET9708 Project Status Ongoing Program End Date Dec 31 2017 ERM Addressed Oper Risk 20 West End Ave. ECC Loss,Admin Risk 18 Prolonged Computing or Communication System Failure,Admin Risk 34 Unsupported Computer Systems,Oper Risk 29 Cyber Attack Materially Adverse Impact
Work Description: This program's focus is to ensure that the network infrastructure at the primary and alternate Energy Control Centers are continuously improved and expanded to support operational reliability of our systems. As necessary firewalls, routers and switches will be replaced and/or additional devices added. The network infrastructure will periodically be evaluated and enhanced to support data transmission at wider bandwidths, as required. Systems will also be indentified and added to facilitate centralized management and process automation to improve support efficiency.
To take advantage of server virtualization a Storage Area Network (SAN) will be installed and several SAN storage arrays identified and procured in 2011 for installation in 2012. These initial installations will be expanded in 2012 as more of our Infrastructure and Operational systems start taking advantage of virtualization.
It is anticipated that the Infrastructure supporting the connections between the ECC and AECC will need to be enhanced to take full advantage of virtualization. These requirements will be further specified in 2012 for procurement and implementation in 2013 and 2014. Part of the planning and specification will include plans to replace the current network switches, routers, and infrastructure that will be at end-of-life by 2015.
Justification: Increased demands on the existing network infrastructure, increased firewall protection and more communications between application systems necessitate continued improvement. In order to take advantage of newer technologies, supporting infrastructure needs to be deployed that will accommodate increased data transfer. As more Exhibit ___ (IIP-13) Page 16 of 82
network-based systems are installed, data traffic on the existing infrastructure is subject to bottlenecks. To maintain the integrity of the network and to provide uninterrupted system communication for operational systems, these enhancements need to be pursued. The addition of a fully functional and independent alternate control center requires the ability to manage all IT resources from either center. This and expanding regulatory requirements require the centralized management, monitoring, and process automation to meet operational commitments.
* Alternatives: The alternative to keeping the System Operation control center's infrastructure and support systems updated would be to discontinue making operational enhancements or introducing new tools that enable operations to maintain operational excellence. * Risk of No Action: The major risks of no action are exposure to not being able to meet our operational or regulatory requirements because the infrastructure is unable to support the required bandwidth, process monitoring, or security obligations * Non Financial Benefit Explanation: * Technical Evaluation and Analysis: * Project Relationships:
Current Status: Current Working Estimate:
Funding: ($000s)
Funding 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Total Cost $21 $0 $5 $230 $285 $200 $200 $200 $250 $400 $600 $200 $200 $2,791
Benefit: ($000s)
* 2008 to 2012 Budget in $920 Thousands- * 2013 to 2017 Budget in $1,650 Thousands-
* Authorization- $1,400,000 * Appropriation- $1,306,000
Exhibit ___ (IIP-13) Page 17 of 82
2013 Capital - Central Operations/Transmission & Substation Operations
Project Name Plant Information System Project Number Work Plan Category Oper - System Capacity Priority Project Manager Saad, Abdo Project Engineer Del Re, Joseph Budget Reference 1ET9705 Project Status Ongoing Program End Date Dec 31 2017 ERM Addressed
Work Description: Two existing servers serving as data historian for the energy management system (EMS) will be replaced. The PI software will be installed on them and the whole archiving and replication process will be tested. Testing will involve data archival and retrieval of EMS data to the new servers and data replication to and data retrieval from the server outside the electronic security perimeter (ESP).
Justification: The ECC's PI system is used for historical data archival and retrieval of EMS information, and for presenting the current status of equipment on the Transmission, Distribution and Steam system. External interfaces such as Status Central and DIS have taken advantage of PI's superior data storage and graphical presentation capabilities, creating multiple web interfaces for use by operating and planning organizations.
The new servers will better support the new features available from OSISoft that will allow two servers to be updated at the same time and to work as a high availability collective. This capability will tremendously shorten the interruption time if the primary server goes down as the other server will be up to date and ready to take over.
The current servers are provided by Stratus Inc and have proprietary software installed on them. As such, they require a standalone contract with Stratus that costs approximately $36k per year. The new servers will be standard servers recommended by IR and will be supported through the existing IR maintenance contract reducing the cost by approximately 50%.
* Alternatives: Not replacing the PI servers inside the ESP would jeopardize the Exhibit ___ (IIP-13) Page 18 of 82
availability of these servers. It would also affect the availability of data to the general corporate users and it would regular maintenance work such as failover and patching harder. * Risk of No Action: The existing servers have become limited in the ability to keep up with the archival needs of the current EMS. Archival would need to be restricted or limited to extend life, leaving potentially critical data unavailable. * Non Financial Benefit Explanation: * Technical Evaluation and Analysis: * Project Relationships:
Current Status: Current Working Estimate:
Funding: ($000s)
Funding Cost 2010 2012 2014 2018 2011 2013 2015 2016 2017 Total $0 $200 $200 $250 $0 $0 $0 $0 $0 $650
Benefit: ($000s)
* 2008 to 2012 Budget in $200 Thousands- * 2013 to 2017 Budget in $200 Thousands-
* Authorization- $1,600,000 * Appropriation- $900,000
Exhibit ___ (IIP-13) Page 19 of 82
2013 Capital - Central Operations/Transmission & Substation Operations
Project Name System Operation Enhancements Project Number Work Plan Category Strat - Strategic IT Enhancements Priority Project Manager Scholz, Richard Project Engineer Sun, Hui Budget Reference 1ET9808 Project Status Ongoing Program End Date Dec 31 2017 ERM Addressed Oper Risk 06 Prolonged Electric Outtage Impact Customers
Work Description: The District Operation Automation process will allow the District Operator (D.O.) to issue groups of switching moves simultaneously to involve field operating groups. Major software changes and new applications need to be developed to support this enhanced processing sequence and its system dependencies. This project provides tools and applications that focus on improving the operator’s effectiveness at the energy control center, and tools for management of operation staff work (SR Process). These tools provide the operators with improvements that reduce manual transfer of data between systems, that provide automated guidance when actions are necessary and that check work orders against predetermined rules to ensure proper instructions are given to field organizations.
This project will increase automation of parts of the electrical operating order process by utilizing a computer directed format for setting up in advance an automated sequence of operating orders. This will be accomplished by making use of existing systems and also through deployment of new interfaces. These systems, new and existing, will work seamlessly with one another. This project provides tools and applications that focus on improving the operator’s effectiveness at the energy control center, and tools for management of operation staff work (SR Process). These tools provide the operators with improvements that reduce manual transfer of data between systems, that provide automated guidance when actions are necessary and that check work orders against predetermined rules to ensure proper instructions are given to field organizations. For example, an Out of Service Work Permits (OSWP) request application that is given to the control center by email and manually transferred by the operator will now be directly uploaded into FMS/TOMS for the District Operator to review and process, eliminating the manual data transfer step.
Justification: Exhibit ___ (IIP-13) Page 20 of 82
The District Operator coordinates and directs all switching operations and permits to work on Con Edison's transmission and distribution systems, ensuring safety to personnel and safe operation of equipment while minimizing downtime. District Operators perform over 500,000 operations per year. The sheer volume of work, coupled with the complexity of the systems, the variety of equipment types, and associated set of operating rules and requirements have made the District Operator's job extremely challenging.
Process Automation will enhance the operating environment. By eliminating routine handoffs, the D.O. can afford to devote more time to analyzing complicated situations thoroughly prior to issuing orders, lessening opportunity for an operating error while also reducing feeder restoration time.
These system enhancements support the effort to continuously improve our operating efficiency, by increasing the productivity of field and substation personnel and reducing feeder-processing time.
* Alternatives: * Risk of No Action: * Non Financial Benefit Explanation: * Technical Evaluation and Analysis: * Project Relationships:
Current Status: Current Working Estimate:
Funding: ($000s)
Funding 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 Total Cost $154 $432 $98 $171 $380 $280 $300 $250 $300 $300 $300 $300 $350 $3,615
Benefit: ($000s)
* 2008 to 2012 Budget in $1,229 Thousands- * 2013 to 2017 Budget in $1,450 Thousands-
* Authorization- $4.500,000 * Appropriation- $2,750,000
Exhibit ___ (IIP-13) Page 21 of 82
2013 Capital - Central Operations/Transmission & Substation Operations
Project Name Technology Improvements Project Number Work Plan Category Strat - Strategic IT Enhancements Priority 52 Project Manager P. DiScala Project Engineer N/A Budget Reference 1ES7500 Project Status Ongoing End Date Dec 31 2017 ERM Addressed
Work Description: This program funds the technology improvements needed to upgrade, enhance, automate, or establish substation processes with the goal of increasing efficiency and improving reliability. Substation Operations has established numerous procedures, instructions, and guidelines to ensure the safe operation and maintenance of the equipment. Many processes developed to ensure adherence to a governing course of action involve data/information collection, transfer, and storage. As technology advances, this program serves to identify and take advantage of opportunities to improve the efficiency of these processes by implementing new tools or upgrading existing ones to enhance how data is collected, transferred, and/or stored.
Justification: The implementation and upgrade of new technology is instrumental in ensuring Substation Operations continually improves efficiency and reliability. The use of technology to streamline processes results in better resource utilization and a reduction in task time requirements. Better data collection and storage, facilitates enhanced data analysis and trending which ultimately leads to improved reliability and equipment performance.
Data Splice - DataSplice is a work management software that works with Maximo to gather important equipment inspection and maintenance data. DataSplice provides functionality not available in Maximo and greatly enhances our ability to improve maintenance practices and track and trend equipment conditions. Customization of this software is performed to expand functionality with the goal of improving maintenance effectiveness. Exhibit ___ (IIP-13) Page 22 of 82
Substation Dashboard allows for a real time view into the work being performed at the various substations and allow for improved allocations of resources. The Substation Dashboard system creates a centralized view of the events, activities, and work being performed at the various substations. This single point of view allows for improved allocation of resources which, in turn, facilitates in the timely restoration of feeders by avoiding delays in feeder processing. Work will be performed to extend the Substation Dashboard system to incorporate feeder “bogey” times.
Rapid Restore - An update to Rapid Restore is recommended that will create a training environment so that employees can learn how to process operating orders and work permits. Another upgrade will enable PST technicians to use Rapid Restore to receive written work permits.
Dielectric Switching Order (DSO) application - a new computerized application that will replace paper logs as well as the oral transmission of orders over the telephone to be more in line with the process used by System Operations personnel to issue operating orders and work permits on the electrical system. The DSO will help maintain the reliability of our transmission system and improve its efficiency and safety. It will improve the quality of our normal operating practices and readiness to deal with emergencies. It will assist in preventing the loss of a dielectric facility which can avoid a catastrophic failure from occurring on the transmission system. A true simulator has the promise to be able to anticipate the exact status of the feeders in real time, prevent failure, and reduce costs. The creation of a seamless automated work order system that can validate orders via a true dynamic simulator has never been attempted by the company or elsewhere in our industry. The R&D component of this system will combine both an operating and training tool with near time historical event replay capability.
Smart Procedures: This project will convert all SSO word document procedures into a database format. The advantages gained include a reduction in labor needed to maintain procedures, more accurate procedures, faster response times to change requests, and greater flexibility in accessing and utilizing procedures.
Firstcall: Rewrite the existing Firstcall system to track substation personnel. The current system is used primarily to track the availability and location of substation operators. The rewrite should contain the following improvements: a robust scheduling component for the schedulers to handle scheduling conflicts and adjustments; integration to the Substation Log system to better track resource availability at each station and to simplify the sign in process to multiple systems; and the viewing of station information Exhibit ___ (IIP-13) Page 23 of 82
(e.g. operator availability and scheduling data) from any computer. The current Firstcall system has not been enhanced with any new functionality improvements since 2002. Substations requires that the data for the aforementioned requirements be made available to the user from any computer. Currently, pertinent information (i.e. stations that are occupied by an operator) is only available through dedicated machines.
* Alternatives: The alternative to take no action is not recommended. Technology improvements are sometimes necessary to ensure existing systems work as designed and originally intended. The failure to do so could render the systems obsolete. Other improvements are necessary to support process changes intended to improve efficiency and productivity of maintenance and operations.
Datasplice: An alternative is to take no action. This is not recommended as proposed enhancements to this software will improve maintenance effectiveness and help manage costs.
Substation Dashboard: The alternative is to take no action which is not recommended. This enhancement will provide the capability to alert personnel of feeder processing problems thereby raising awareness so that swift corrective action can be taken.
Rapid Restore: The alternative is to take no action which is not recommended. A training environment is necessary to simulate the process improving employee performance. Creating the ability for PST to use Rapid Restore will allow them to get written work permits without an operator.
Dielectric Switching Order (DSO) application: An alternative is to take no action. This is not recommended as the current method of using tracking Dielectric System Orders via paper logs and telephone communication is not efficient.
Smart Procedures: An alternative is to take no action. This is not recommended as this project will reduce manpower requirements needed to maintain procedures as well as improving quality and access to procedures. The payback period for this project is less than 3 years.
Firstcall: An alternative is to take no action. This is not recommended as this system has not been updated since 2002 and enhancements are necessary to ensure the system continues to function effectively.
Exhibit ___ (IIP-13) Page 24 of 82
* Risk of No Action: The risk of no action would be the failure to support and therefore benefit from these changes.
Current Status: Datasplice: Datasplice was implemented in 2010 and continues to be refined to improve features and functionality. An inventory module for the control of consumables, tools, and parts was implemented in 2011. Further refinements to the inventory module as well as software enhancements that will enable a mobile will be completed in 2012 and 2013.
In 2013 we will be extending the scope of work for Datasplice and Smart Procedures to enable a mobile work force. In conjunction with this, we anticipate an equipment labeling effort that will include a technology such as bar coding or RFID. Mobile devices, smart phones and tablets would be employed.
Rapid Restore: A training environment for this application will improve employee performance and reduce errors. Enabling PST to use the system to lead to efficiencies since an operator will not need to be present to issue a written work permit. Smart Procedures: This project began in 2011 with the purchase of the software licenses and initial configuration of the software. Customization of the software, procedure conversion, and system roll-out is planned for 2012.
Firstcall: In 2012, a Phase 0 analysis will be conducted to determine the actual cost for this project. Work is then expected to commence in 2013.
Funding: ($000s)
Funding 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Total Cost 536 124 139 1154 343 1440 750 1000 1000 1000 1100 1100 9686
* 2008 to 2012 Budget in $3,826 Thousands- * 2013 to 2017 Budget in $5,200 Thousands-
Exhibit ___ (IIP-13) Page 25 of 82
2013 Capital - Central Operations Project Name Project Explorer - Metaphase Replacement 2 Project Number TBD Work Plan Category Strat - Strategic IT Enhancements Priority 1 Project Manager Sia Vafegh Project Engineer Mariana Mekhaiel Budget Reference 2XC9726 Project Status Planning End Date Dec 31 2017
Work Description: As part of a second phase to update its document management system, Central Engineering (CENG) will continue to work with Siemens to migrate other supporting applications under the TeamCenter umbrella. The unification of CENG applications under the enterprise system will provide reliability and process efficiency to our customers. In addition, the product will receive equal technical support and maintenance.
Justification: At the core of CENG ability to create, document and track project information is Project Explorer (PE). The application, which is supported by a single individual, has been frequently displaying data delivery issues. When creating new projects or selecting older projects, the respective project information is absent from view.
The solution to any of these software errors rest with a single individual who is the application developer. The cost for alternative software developers to support PE far exceeds the cost of working with the product creator. This arrangement is unpredictable and unreliable. It exposes CENG to severe consequences in the event of any conflict with the product creator.
* Alternatives: Continue with the current system. However, this application is outdated, and lacks maintenance and support. Project Explorer is a legacy system that is in an outdated operating system that is no longer supported by Microsoft.
* Risk of No Action: System or hardware failure and the possibility of the developer going out of business. Reduced or non-functionality due to software errors and lack of technical support.
The current system cannot be configured to ensure compliance with new operating environment requirements and will not be supported by Microsoft. .
* Non Financial Benefit Reduced multiple systems use. Support of Business Continuity and Explanation: Disaster Recovery.
1 Exhibit ___ (IIP-13) Page 26 of 82
Current Status: Planning
Current Working Estimate: $2,100,000
Funding: ($000s) Funding Cost 2013 2014 2015 2016 2017 Total 1000 500 200 200 200 2100
* 2013 to 2017 Budget in $2,100 Thousands-
2 Exhibit ___ (IIP-13) Page 27 of 82
2013 Capital - Central Operations Project Name AutoCAD (Engineering Equipment Upgrade Program) Project Number 21761-05a Work Plan Category Strat - Strategic IT Enhancements Priority 2 Project Manager Sia Vafegh Project Engineer Carlos Walton Budget Reference TBD Project Status On-Going Program End Date Dec 31 2017
Work Description: AutoCAD, various specialized CAD applications, is the the main drawing tools used by Designers. The CAD Project requires periodic upgrades of applications and hardware to keep abreast with current technology. The current version of AutoCAD used by Central Engineering's designers is 2010, while AutoCAD 2013 is the latest version of the software on the market.
Autodesk only supports up to the last three versions of their software. To ensure vendor support the CAD program upgraded the software applications early in 2010 from AutoCAD 2006/Autodesk Building Systems 2006 to AutoCAD MEP 2010/Autodesk Raster Design 2010. Autodesk has changed their licensing schema to a subscription format that entitles their clients all future releases of their software for a determined period. The funding requested in the five-year capital plan includes upgrade and replacement of office/stations plotters, wide format scanners, CAD 2D/3D workstations and servers. With the new deployment of Windows 7 x64 scheduled for the next few years, new equipment with more resources is required to run all CAD applications effectively.
Justification: The Administrative Services and Cost Management section of Central Engineering’s Environmental Engineering and Program Support Group is responsible for supporting over 200 CAD workstations used by designers and contractors to support our work. In addition, this group also administers Metaphase 3.2, Con Edison's current drawing management system, which contains over 1,500,000 drawings. To take advantage of new technology and productivity enhancements in software and hardware, the CAD system is scheduled to be upgraded to AutoCAD 2012 along with upgrades to plotters, workstations, monitors, servers, storage systems, scanners and peripherals. An upgrade will increase the designers’ productivity, maintain AutoDesk support on the AutoCAD 2013 and 3D platform, and maintain file compatibility.
Productivity improvements are expected to be achieved through simplifying the designers interface, by making the administration of CAD peripherals simpler and more intuitive, and by incorporating intelligent 3 Exhibit ___ (IIP-13) Page 28 of 82
vectorized data – which in conjunction with 3D design - will allow for identifying interferences. In addition, upgrades provide for links to Excel spreadsheets with dynamic updates – making data extraction more powerful. The new applications allow for smaller file sizes which conserve server storage and permit simple file sharing and communication between designers. The dash board provides enhanced 2D/3D tools for drafting and annotations. which in conjunction with 3D design - will allow for identifying interferences. In addition, upgrades provide for links to Excel spreadsheets with dynamic updates – making data extraction more powerful. The new applications allow for smaller file sizes which conserve server storage and permit simple file sharing and communication between designers. The dash board provides enhanced 2D/3D tools for drafting and annotations.
* Alternatives: Taking no action would increase the cost of maintaining older equipment (plotters, scanners and CAD workstations) and put Central Engineering at the risk of not being able to support CERC/BC activities and result in loss of productivity.
* Risk of No Action: No action on these items would discontinue our receiving of updated patches and software revisions and upgrades from AutoCAD. Central Engineering (CE) would not be able to keep pace with industry standards, our contractors and our A/E vendors. In addition the cost of maintaining older equipment (plotters, scanners and CAD workstations) would be enormous and put CE at the risk of not being able to support CERC activities and a loss of productivity.
* Non Financial Benefit Productivity improvements are expected to be achieved through the Explanation: simplifying the designers interface, by making the administration of CAD peripherals simpler and more intuitive, and by incorporating intelligent vectorized data – which in concert with 3D design - will allow for identifying interferences. In addition, upgrades provide for links to Excel spreadsheets with dynamic updates – making data extraction more powerful. The new applications allow for smaller file sizes which conserve server storage and permit simple file sharing and communication between designers. The dash board provides enhanced 2D tools for drafting and annotations.
Current Status: On-Going Program
Current Working Estimate: $3,700,000
Funding: ($000s) Funding Cost 2013 2014 2015 2016 2017 Total 700 700 700 800 800 3,700
* 2013 to 2017 Budget in $3,700 Thousands-
4 Exhibit ___ (IIP-13) Page 29 of 82
2013 Capital - Central Operations Project Name Wiring Access Raceway System (WARS) Project Number TBD Work Plan Category Strat - Strategic IT Enhancements Priority 3 Project Manager Sia Vafegh Project Engineer Carlon Walton Budget Reference TBD Project Status Not Started End Date Dec 31 2014
Work Description: Replace WARS with a web-based application using current technology and an Intelligent Drawing Management System. WARS is an enterprise, text- based plant-engineering tool developed initially over 20 years ago specifically for Con Edison. It gives the end-user the ability to engineer plant configuration by identifying all major infrastructure components such as conduit, cables, equipment and connection data points. Once a configuration is developed, WARS can create, from its database, the reports necessary to provide the construction technician with the appropriate documentation required for construction.
WARS is organized by location and project and provides existing conditions information for locations as a starting point for future design.
WARS is also utilized to develop the various material lists required for procurement. These various reports are driven from the design model. Procurement works from these printed WARS reports. Today, there is no automated integration between these documents and procurement.
WARS also provides the necessary reports to develop the equipment nameplates that are used for tagging equipment during construction.
Justification: WARS was developed over 20 years ago and utilizes the APL (Array Processing Language) programming language. APL is no longer viewed as a mainstream programming language and has limited support or scalability capabilities.
WARS, being a custom-developed solution, is supported by a small private consulting firm. Future support will become more difficult as APL programming skilled users become increasingly uncommon in the marketplace today.
Due to WARS dependency on its legacy architecture, its interface is very primitive and difficult for end-users accustomed to navigating more modern interfaces. It does not leverage any graphical or CAD like interface to streamline the creation of design data or provide the user 5 Exhibit ___ (IIP-13) Page 30 of 82
with a more intuitive interface.
WARS provides a comprehensive suite of automation tools to assist in the development of necessary reports for construction. These reports are also very antiquated in their appearance and sometimes difficult to read. WARS relies heavily on the roles of administrators to keep the system operational. There are many areas of support information that the system requires for operations. The administrator must also maintain this information. The upkeep of this essential support information requires a highly skilled administrative user. These administrative skills are not easily passed on to potential future administrators.
Due to its nature of repeatedly utilizing existing information as the starting point for future designs, the accuracy of the data is vital for successful future design constraint analysis.
While WARS provides adequate plant engineering functionality, its primary limitations lie in the architecture of its legacy information and future viability. As Central Engineering adopts new applications tools both for inside and outside plant, e.g., AutoCAD 2010 and an Enterprise Document Management, , WARS will become an island of data not easily accessible to these other systems.
WARS is an essential component to an integrated Information Lifecycle Management (ILM) solution. However, we feel that the legacy architecture, interface, and delivery mechanisms of WARS hamper the ability to leverage the benefits of today’s leading technical capabilities, i.e., the integration with EDMS, AutoCAD, intelligent drawing management and remote web access. In summary, the capabilities and functionality provided by WARS should be replaced.
* Alternatives: The alternative is to not replace WARS and continue to use the antiquated application that was developed based on an obsolete programming language by a single vendor. The application resides on a server with obsolete operating systems Windows sever 2000 and SQL server 2000. These are no longer supported by Microsoft and the server and application have therefore been placed behind the “Ring Fence” (quarantined) for protection against cyber attacks. The current corporate standard is Windows server 2008 and SQL server 2008.
* Risk of No Action: The system crashes and the vendor is out of reach or business and no support can be provided for WARS.
* Non Financial Benefit Having a more robust system with proper support. Explanation:
Current Status: Planning.
Funding: ($000s) Funding Cost 2013 2014 2015 2016 2017 Total 500 200 0 0 0 700
6 Exhibit ___ (IIP-13) Page 31 of 82
2013 Capital – Electric Operations
Project/Program Title Energy Services Case Management Project Manager Joseph Zillitto Project Engineer Status Planning Estimated Service Date June 2012 pilot rollout with WMS Full Deployment Work Plan Category Customer Service
Work Description: Energy Services is committed to improving the processes and information systems used to manage new business service cases. In 2008, Energy Services made substantial strides in this area by streamlining new business processes and launching an internet-based project center to provide a self-service facility for contractors, developers and customers to process and track new service requests. Going forward, Energy Services will integrate a New Case Management System with the new Work Management System (Logica). The new Case Management System will enforce and facilitate a streamlined case workflow, leverage new technology and provide enhanced updates to customers and contractors. In addition, the new case management tool will interface with future work management systems and provide improved project management capabilities that will allow Energy Services personnel to better plan and achieve customer service dates. The new case management system will be based on a leading commercial software platform.
Units per Year: 50,000+/- Customer Work Requests (CWR’s), unit processing costs estimated at $700.00 per request.
High-level schedule: Construction began in 2011 and will be completed in 2012.
Justification: The Company recognizes the need to improve its new business case and work management processes and information systems.
Energy Services implemented the current case management system, CORS (Commercial Operating Reporting System), in 1985. The system was based on the technology and workflow that existed at that time. Energy Services and Electric Operations need to continue to streamline their business processes and leverage new workflow and telephony technologies to improve their ability to process new business installations in a timely manner.
Alternatives: In lieu of a comprehensive program management tool, the Company could implement a reporting and analysis tool. This approach would allow us to satisfy the reporting needs for internal analysis as well as regulatory requirements. However, it would prevent us from integrating with Oracle Financial to process incentive payments and streamline forecasting in the short term.
Risk of No Action: Without the proper infrastructure to support the management of our various demand side management programs, the Company runs the risk of having high cost and poor performance. The risk of no action reduces the ability of Con Edison to effectively manage our programs
Exhibit ___ (IIP-13) Page 32 of 82
Summary of Financial Benefits and Costs: The introduction of a new case management system will provide an opportunity to operate more efficiently and create value for the customers we serve and their contractors. In addition, the new system will provide better information to determine more precise business staffing requirements. Initial costs to purchase, and implement the new system are estimated to be approximately $8 million. These costs include all software and hardware acquisition costs, as well as the cost to retire the CORS system and construct interfaces to the Customer Information System (CIS) and new electric work management system, Logica. Costs for training and ongoing software license and maintenance costs are also included. While additional analysis must be completed, implementation of the new case management tool is expected to provide substantial savings and cost avoidance through the automating and streamlining of processes and optimized use of resources. Preliminary expected annual savings are estimated at $1,600,000.
Non-financial Benefits (if applicable): The implementation of the new case management system is expected to increase customer satisfaction by streamlining the new business process and leveraging new workflow technologies. The savings noted above would allow Energy Services to reallocate FTEs to other activities, reduce OT or avoid new hires for pending attritions.
Technical Evaluation/Analysis: The new solution will be based on a leading commercial case management and customer relationship management platforms that are used by other utilities/companies. It will leverage the latest software, database and server technologies and include improved workflow functionality and interfaces to customer service and work management systems. While additional analysis must be completed the Company expects the use of new case management solution to ensure compliance with PSC incentive goals and improve overall customer satisfaction.
Sensitivity Analysis (if applicable):
Project Relationships (if applicable): Target deployment for the new case management system will take place simultaneously with the full deployment of new work management system for Electric Operations. These two systems will interface with each other and eliminate the need to train Energy Services personnel on the use of both systems.
Estimated Completion Date: June 2012 will be the targeted initial rollout for the case management system along with WMS Full Deployment. (Will be validated once detailed Project Plan is developed)
Status: In 2008, Energy Services made streamlined new business processes and launched an internet-based project center to provide a self-service facility for contractors, developers and customers to process and track new service requests. After installation of the project center, Energy Services initiated a comprehensive review of leading case management and customer relationship management products and developed a detailed cost estimate and implementation schedule. In February 2011, the new Logica WMS system rolled out to Energy Services. Energy Services seeks to select a new Case Management System to integrate to Logica.
Exhibit ___ (IIP-13) Page 33 of 82
Current Working Estimate (if applicable): Our 2012 CWE is $6,717,000 which does not include $629,000 in expenditures for work by the CPMS team related to WMS integrations. We expect to transfer this cost to the WMS project. Additionally, the WMS revised testing schedule is undetermined at this time; further delays to testing or rollout schedule could result in CPMS retaining vendors longer than currently anticipated. This would increase our 2012 CWE and result in exceeding our KPI for this project.
Funding ($000s) (Capital or O&M):
Actual Actual Actual 2009 2010 2011
225 0 3,153
2012 2013 2014 2015 2016 2017 5 yr Budget Request Request Request Request Request (13-17) Capital Funding 4,000 5,100 0 0 0 0 5,100 ($000s)
Exhibit ___ (IIP-13) Page 34 of 82 2013 Capital – Electric Operations
Project/Program Title Power Quality (PQ) System Upgrade Priority Number Project Manager Cristiana Dimitriu Project Engineer Griffin Reilly Budget Reference 7XC9837 Project Number 22378 Status Engineering Estimated Start Date Estimated Service Date 2013 Work Plan Category Strategic IT Enhancements ERM Addressed
Work Description: The original Substation Power Quality Node Installation project specified one PQNode and one PQPager per station. The PQPager monitors only voltage, so there is no Reactance-to-Fault calculation based on the PQPager data, only based on that one PQNode monitoring one transformer. This project work, meant to make the PQ system more reliable and faster, will include: • Replacement of the existing power quality pagers in forty six (46) substations with new DataNodes • Installation of one more node (DataNode) on a second transformer in each station • Enhancements of the reactance-to-fault (RTF) software / website • Development of an interface between the monitoring data management / analysis system (PQView), and substation monitors (DataNodes) • Server upgrade
Units per Year: 16 Mandatory: N/A High-level schedule: N/A
Justification: In 2005 Distribution Engineering and the Power Quality group developed an application, Reactance-To-Fault (RTF). It uses power quality data collected from substations during feeder faults and automatically indicates a fault location, to reduce fault-locating time on the primary feeder system. PQView software together with PVL impedance data is used to assist our Control Centers personnel with fault locating. This program, initiated in Manhattan, has demonstrated the capability of narrowing the location of feeder faults by utilizing data from the existing PQNodes and calculating distances to the faults based upon the reactive impedances. The results from this effort have been very impressive. The project reduced fault-locating time during the summer months by more than one hour. RTF is an important tool for improving our company reliability.
• Alternatives: Since this project began there were 28 new PQ monitors installed in 14 substations. The only alternative would be the installation of PQ monitors on all area substation transformers.
• Risk of No Action: Fault locating time could increase, and that means longer feeder outages, less reliable system. Fault locating consumes precious time, manpower and prolongs the feeder outage; any reduction in fault locating time is therefore extremely beneficial, especially during the summer months when feeder restoration is key for system reliability. For the time being a lot of the substations have only one PQNode monitoring one transformer. If that substation transformer has an outage, or that PQ monitor is defective, the RTF program can not provide any fault locating calculation on the network(s) fed from the respective area substation.
Exhibit ___ (IIP-13) Page 35 of 82
• Summary of Financial Benefits and Costs: The project reduced fault-locating time during the summer months.
• Non-financial Benefits (if applicable): RTF is an important tool for improving our company reliability.
• Technical Evaluation/Analysis: The data collected from the Power Quality monitors is very important for our Con Edison system. Distribution, Relay Protection, PQ, Equipment Engineers, Customer Reps and technicians, are using the PQ data to confirm, check, and analyze events and trends.
For PQ data (RTF included) to be more reliable there are improvements to be made. 1. The original Power Quality Substation Project specified one PQNode and one PQPager per substation. The PQPager monitors only voltage, so there is no RTF calculation based on the PQPager data. So each substation has one Node monitoring one transformer. If that transformer has an outage, the Node cannot provide any information on the network(s) fed from that station. Replacing the Pager with a new DataNode (the PQNode is now obsolete - the manufacturer, Dranetz-BMI, designed and produced a new version, the DataNode, more powerful, with Ethernet communication that would offer faster, real- time data) and installing one more DataNode on a second transformer in each station will be very beneficial. 2. Further enhancements of the RTF software / website are required, to improve accuracy from a more detailed model, a refinement in the error range estimation, development of a graphical representation to ease operator interface, and development of an automated fault type/signature recognition feature. 3. The need for more timely monitoring data from the monitoring equipment has become very important. When the system is providing information such as fault location directly to operations, the information becomes very critical and it must be available as quickly as possible. New methods of interfacing with the actual monitoring equipment are needed. The new methods must be extremely reliable and they must be able to obtain the data immediately following disturbances or some other alarm condition. What’s needed is an interface between the monitoring data management and analysis system (PQView), and substation monitors (DataNodes) that provide information for real time applications. 4. A server upgrade is required to handle and store the increased volume of data to be collected from the 200 PQ monitors
• Sensitivity Analysis (if applicable): Fault locating consumes precious time, manpower and prolongs the feeder outage; any reduction in fault locating time is therefore extremely beneficial, especially during the summer months when feeder restoration is key for system reliability. For the time being a lot of the substations have one PQNode monitoring one transformer. If that transformer has an outage, or the Node is defective, the RTF program can not provide any information on the network(s) fed from that station.
• Project Relationships (if applicable): N/A
Status: Engineering
EH&S Overview: N/A
Analysis of prior year funding request versus actual: Exhibit ___ (IIP-13) Page 36 of 82
2008 2009 2010 2011 Original request ($000s) 1,650 1,650 1,650 795 Actual ($000s) 467 434 1,544 1,725
Data Reports issued that support program: N/A Specifications & procedures pertaining to Program/Project: N/A
Benefits/Outcome of Program/Project: The data collected from these area substation monitors is very important for our Con Edison system. Distribution, Relay Protection, PQ, Substation Equipment engineers and technicians are using the PQ data to analyze system events. The RTF project reduces fault-locating time by more than one hour, and is predicting feeder faults within 1 manhole for 68% of the events. RTF is an important tool for improving our system reliability.
Is this a mandated program? If yes, include verbiage associated with mandate: N/A
Current Working Estimate (if applicable):
Funding Forecast (Capital or O&M)
Actual Actual Actual 2009 2010 2011 434 1,544 1,725
2012 2013 2014 2015 2016 2017 5 yr Budget Request Request Request Request Request (13-17) Funding 1,559 1,560 0 0 0 0 1,560 ($000s)
• Authorization – 3/13/2008 - $4,950,000 • Appropriation – 3/13/2008 - $4,950,000 • Authorization – 5/4/2012 - $6,509,000 • Appropriation – 5/4/2012 - $5,872,000
Exhibit ___ (IIP-13) Page 37 of 82
2012 Capital – Electric Operations Project/Program Title RMS Data Acquisition System Project Manager Kevin Oehlmann Project Engineer Guy Tourangeau (DE) / Charles Cuomo (IR) Status Planning Estimated Service Date September 2013 Work Plan Category Operationally Required
Work Description: The Electric Distribution Control Centers are a 24/7 operation requiring the highest level of reliability and security. Each control room has significant reliance on several critical SCADA systems to properly maintain and operate the electric network. One of those systems is the RMS/VDAMS Data Acquisition application which is used to collect critical transformer information. Currently, VDAMS cannot support significant technology improvements which allow electric companies to take advantage of “intelligent” field devices that better control and operate the electric network. Electric Operations, Distribution Engineering and IR are recommending a three (3) year plan to address the replacement of VDAMS.
VDAMS continuously polls the underground network transformers and collects instantaneous load readings. This data, utilized with other analysis tools, provides accurate access to the underground primary (feeders) networks and enables operators to quickly and accurately detect transformer overloads, perform analyses, and perform next case scenarios.
The project will entail the implementation of GE’s XA21 SCADA Emergency Management System. This vendor-supported platform is currently used at WEA for transmission control. The new system will provide significant improvements for the control center operators, engineering and designers, while at the same time providing high availability so that any control room can manage the electric network.
Justification: The Electric Distribution Control Centers and Engineering rely heavily on the VDAMS (RMS) data to make critical decisions on network upgrades, as well as to troubleshoot problems. Each regional distribution-engineering group maintains specific and static information pertaining to each transformer and network. Currently, there are many limitations within VDAMS that hinder a more robust analysis process, as well as general operational issues (i.e. VDAMS requires a system restart to have any changes either to system or data parameters and any configuration changes require lengthily code changes). In addition, the operating system which VDAMS resides on will no longer be supported after June 2012. After this date, no patching will occur and as a result it will present a significant risk for cyber security issues. New alarm capabilities, intelligent physical equipment and enhanced operator interaction are all areas that will assist Electric Operations in developing improved analytics and operating procedures. These enhancements cannot be provided with the existing VDAMS application. Alternatives: Possible alternatives include developing a similar system in house, purchasing a similar system from another supplier or keeping the existing system ”as is”. Con Edison does not have the resources to develop a system in house. The XA21 system was compared to systems from other suppliers when it was installed in West End Avenue. The XA21 system was selected as the best option and has become the standard SCADA system used at CECONY and Orange and Rockland Utilities.
Risk of No Action: Exhibit ___ (IIP-13) Page 38 of 82
The current data acquisition system, VDAMS, was introduced in the late 80’s and further enhanced over the past 20 years. It has been patched and modified to address additional demands from the data it manages, well beyond its original intended design. Changes are increasingly difficult to make within reasonable time frames and the application is not efficient in processing data as is currently demanded. VDAMS now contains more than 350 modules outside of the base code, making it impossible to take advantage of the new technology being introduced with Digital Grid and ETI RTU receivers in the area substations. The current request to incorporate AMI power quality data acquisition functionality cannot be achieved within the VDAMS applications. The technology does not support the upcoming needs for increased storage capacity. The additional functions provided by the vendor, Digital Grid, will not be available to engineering nor the control center operators for network design or network troubleshooting and restoration. Other additional functionally required for alarms and equipment changes will not be available. These functions are needed for the netRMS and graphical programs like VCAP and Visual WOLF
Non-financial Benefits (if applicable):
Technical Evaluation/Analysis:
Sensitivity Analysis (if applicable):
Project Relationships (if applicable): • Smart Grid Investment and Demonstration Grants • Electric Control Center Upgrade project.
Estimated Completion Date: September 2013 Note: If the Electric Control Center Upgrade project (Space, HVAC, UPS) is not completed then this will impact the completion date of this project.
Analysis of Prior Year Funding Request Versus Actual: Total Project Breakdown 2009 Original Funding Request: $4,500k 2009 Approved Funding: $3,000k
(GE) estimate for hardware/software $2,500k The project has been re-appropriated for $4,953,000. Spent (As of 12/31/11) 2009 Approved Funding: $0 n/a 2010 Approved Funding: $1000k $356k* 2011 Approved Funding $1000k $239k *Analysis with vendor (GE) resulted in lower costs
Exhibit ___ (IIP-13) Page 39 of 82
Funding Forecast (Capital or O&M) ($000s):
Actual Actual Actual 2009 2010 2011 0 0.4 239
2012 2013 2014 2015 2016 2017 5 yr Budget Request Request Request Request Request (13-17) Funding 2,380 2,389 0 0 0 0 2,389 ($000s)
Exhibit ___ (IIP-13) Page 40 of 82
2013 Capital – Electric Operations
Project/Program Title Decision Aids - Decision Optimizer - Contingency Analysis Program (CAP) Project Manager Maggie Chow Project Engineer Maggie Chow Status In Progress Estimated Service Date 2013 - 2014 Work Plan Category Strategic IT Enhancements
Work Description (Includes units per Year and a high level schedule): The broad goals of this initiative involve: • Extract and combine vital information from DIS, RMS, WOLF, DOS, USA, VDAMS etc. and integrate this critical information with thresholds and dynamically prioritize the importance with pre-determined business rules and provide this information to the operator • Integrate data across separate applications, and provide this critical information to operators. • Present the information combined from multiple applications to operators in a single view.
CAP has been a success throughout the regional Control Centers and received recognition in the form of a Team award. CAP I and II focused on the underground network systems in Manhattan, Brooklyn/Queens and the Bronx and have been in production in their control centers since 2008. The focus on the non- network system began in 2010 with CAP III & IV on the overhead auto-loop system in Brooklyn/Queens, Bronx, and Westchester. In 2012, with CAP IV, we began to target the 4KV primary grid systems, as well as the CAP design to include Staten Island and Westchester. The work needed to accomplish this goal involves:
• Integrate 4kv SCADA from USA/XA21 to summarize the equipment status and the potential for loss of customers in a single view in CAP • Integrate 4kv PVL contingency output to CAP – for the summary of next worst , overloaded equipment and pro-active preparation for customer outages • Introduce a Decision Aid Action Engine to identify action for operators or field crews
Future modules of CAP (CAP V and CAP VI) to be developed in 2013 and 2014 include:
Multi-year plan for Distribution Contingency Analysis
Module Description Target
Incorporate SI NNW as test pilot to include NNW into CAP Module 1 Provide 4kv and Autoloop contingency analysis 2013 Enhance visualization to improve user’s Module 2 Situational Awareness (SA) design 2013 Module 3 Expand CAP to BQ and WX NNW regions 2013-2014
Provide indications of load areas and networks in voltage reduction (low voltage report from Module 4 Wolf) both on main display and summary 2013 Calculate and display now and next worst Module 5 contingency for secondary cable overloads 2014 Exhibit ___ (IIP-13) Page 41 of 82
Establish SA summary page to include 4KV Module 6 now and next worst contingency overloads 2014 Correlate multibank contingency with secondary Module 7 status 2013 Provide Seamless capability to run test cases from the main display for "what if" scenarios in Module 8 NNW (similar to Manual Cap for NW) 2014
Module 9 Filter PTOs Alarm from maintenance issue 2013
Module 10 Provide interface with HTV SCADA 2014 Provide interface with XA 21 DAS for Module 11 autoloops 2014 Provide interface with XA 21 for unit Module 12 substations 2014 Correlate secondary status with multi-bank Module 13 contingency 2013-2014 Provide capability/logic to trigger to run contingency on any combination of equipment Module 14 and feeders (other than from feeder OA) 2014
Justification (Technical Evaluation/Analysis): The Contingency Analysis Program was developed as a decision aid to Control Center Operators to analyze system contingencies by presenting them with the most vital information on current system status and next worse conditions. System contingency analysis and response by operators in our Control Centers is a human-intensive process. That process must quickly address the following concerns:
• What is the current abnormal state of the distribution system? • What is the current impact? • What is the impact and severity of the next event? • What are our best options for getting the system back to a normal state?
To address these concerns operators currently gather information that is contained in as many as 20 separate applications. It is a laborious process because each application requires navigation and in most cases a separate login with a user ID and password.
We developed and implemented a display for operating personnel that provides an integrated view of network and/or load area system conditions. The application allows the operators to navigate between the various applications as though they are all part of a single tailored application. The application facilitates the processing of primary distribution feeders from outage to restoration and analyzes the network or load area contingency for the “now” case and the “next worst” cases.
Currently Operators rely on several sources of information (hardcopy maps, USA, High Tension, ECS, Outage Manager, STAR etc) for analyzing contingencies involving the 4 KV grid. There is no modeling tool integrated to allow contingency analysis in the non-network systems to be summarized. The problem is compounded in combination feeders which have overhead, network and 4KV components. This latest module to CAP will bring this capability to the operators by automatically pulling information from these disparate data sources and feeding them to PVL which will quickly analyze the current and next worse scenarios and push this information to the Operators through the CAP V in the non-network system.
Exhibit ___ (IIP-13) Page 42 of 82
Alternatives: Contingency analysis requires an integrated view of the condition of the distribution system which CAP provides. Operators are currently reliant on accessing multiple data sources to piece together vital information in deciding on a particular course of action. CAP is the only tool available currently which pushes the vital system information to the operator in the form of current conditions and next worse scenarios and the future impact to customer outages.
Risk of No Action: If CAP effort discontinues, our Control Operators will have to rely the current disparate applications to collect every bit of information. Currently, we do not run continuous running WOLF and populate the concise information for operator into a simple format in Control Room environment. Operators have to read through a 60 + pages wolf report to pick out information, then they will have to combine SCADA information from 4kv, auto loop systems, extract information from the mapping data to figure out what customers are in the danger zone in HT, MultiBank, and NNW system. For example, in BQ distribution system, which the same feeder frequently supplies both the NW and NNW systems; operators have to go to many systems to research all the pieces together to create the view of “danger zone of contingency” if we don’t do CAP. This is a tedious process and could lead to error (or extended outages) during stressful contingency situations, particularly by less experience operators.
Summary of Benefits (financial and non-financial): CAP V is estimated to cost $250K. This requires a shift from a very manual paper process for contingency analysis when we lose a primary feeder on the 4 KV grid. The current process involves pulling out a feeder map, manually identifying the ATS, HT, using an Excel Spreadsheet to determine the possible next worse. CAP V will automatically push all contingencies by seamless display that summarizes the effect on ATS, Auto Loop, HTV, and Isolated Multi-banks. An automatic representation of field conditions and next worse analysis will greatly reduce the time to take corrective action to either bring the system back to normal or prevent further contingencies/customer outages. We estimate 5 minutes critical time reduction per outage with CAP V. This corresponds to a 0.08 reduction in CAIDI, equivalent to an average reduction of 8 customer outage hours per 100 customers interrupted.
The importance of having a complete and integrated knowledge of system conditions during contingencies is essential to successfully bringing the system back to normal status in a timely manner. Targeting the 4KV primary grid will complete the loop by providing operators with the ability to quickly analyze system contingencies and assess next worse scenarios to respond more efficiently. Operators will also have a more accurate representation of the customer outages related to the system contingency and the next worse event.
Project Relationships (if applicable):
EH&S Overview:
Analysis of prior year funding request versus actual:
Data Reports issued that support program:
Specifications & procedures pertaining to Program/Project:
Is this a mandated program? If yes, include verbiage associated with mandate: No Exhibit ___ (IIP-13) Page 43 of 82
Funding Forecast (Capital or O&M):
Actual Actual Forecast 2010 2011 2012
210 197 235
2013 2014 2015 2016 2017 2018 5 yr Budget Request Request Request Request Request (13-17) Funding 250 250 250 250 250 0 1,000 ($000s)
Exhibit ___ (IIP-13) Page 44 of 82
2013 Capital – Electric Operations
Project/Program Title Enhanced Customer Communication Storm Outage Management System Phase II Priority Number Project Manager Rubab Ashraf Project Engineer Donald Smith Budget Reference Project Number Status Planning Estimated Start Date 2013 Estimated Service Date Ongoing Work Plan Category Strategic IT Enhancements
ERM Addressed
Work Description (Includes units per Year and a high level schedule): Con Edison is committed to developing best practice outage restoration processes and information systems. These processes and systems help facilitate the correct assessment of customer outages, effective restoration planning and timely return of service to customers. In the past few years, the Company has made significant improvement in its ability to understand the number of customers impacted by power disturbances and provide customers with estimated time of restoration. These accomplishments were achieved through a series of process improvements and enhancements of the Outage Management suite of systems including STAR (System Trouble Analysis and Reporting). STAR is based on Oracle’s Distribution Management System software suite. The Oracle product continues to be one of the leading outage management software suites and is utilized worldwide by many large utilities.
In 2012 a comprehensive review of the primary outage management processes was conducted. The goal of the review was to identify areas of improvement in the processes and in technology. The review identified several high priority improvement opportunities across all areas of the OMS process. The following are items identified to be addressed starting in 2013.
• Evaluate improvements available with the latest release of the Star customer call module (IVR adapter). Outbound calls directly from STAR will be investigated and plans developed to eliminate these calls from ECS to the CSS VRU. • Evaluate and implement additional functionality available in the StormMan module to improve the accuracy of customer ETRs. This will require a user team to focus on the capabilities and determine a new process for developing ETRs. • Continue work on the removal of special Con Edison specific coding extensions to the product. These extensions increase the cost and complexity of supporting the system and migrating to new releases. The vendor, Oracle, needs to provide the appropriate functionality to make their product a long term viable solution for electric operations • Continue to replace the need for and the use of ECS screens and functions. Need to identify all the functions and develop a plan to migrate away from ECS. • Implement improvements to the Site Safety application to enhance functionality and to improve integration with STAR and Outage Dashboard (Obvient) • Implement improvements to the Damage Assessment functionality in Star. Damage assessment needs to be enhanced and integrated with Outage Dashboard (Obvient). Exhibit ___ (IIP-13) Page 45 of 82
• Investigate and determine if the Automated Switch Plans module (DSS) will improve the OMS process • Investigate and identify improvements to the mapping and model build process – with particular focus on improving the quality, timeliness, and accuracy. • Investigate new testing tools to cover all functionalities within OMS including model viewer • Investigate features and advantages of the New Obvient Base Product with additional modules • Investigate use of more dashboard matrices to reduce the dependencies from the spreadsheets used during storms and also giving more transparency into the entire process. • Implement improvements to training by creating more e-learning modules and having more in class training for use in both process and system.
The use of STAR will allow Electric Operations to continue to comply with the recommendations contained within the NYS DPS LIC and Overhead Storm Reports.
Justification (Technical Evaluation/Analysis): The enhancements detailed here will allow us to follow best practices across all areas of the OMS process.
Alternatives: Remain on the current version of STAR and other outage management systems with existing functionality. Another alternative is to replace STAR with a competing outage management product. Acquisition and development costs are expected to be substantially more than requested funding.
Risk of No Action: Remaining with the current systems with little or no enhancements will increase the cost and difficulty of maintenance. In addition, the Company is committed to using best practices in outage management. By not implementing major enhancements, the Company will fall behind in this effort.
Summary of Benefits (financial and non-financial): The continued use and enhancements of STAR and the related outage management systems will continue to enable Electric Operations to efficiently evaluate, prioritize and manage electric outages on both the network and non-network distribution systems. The use of STAR will continue to help facilitate improved outage impact assessment and response.
Project Relationships (if applicable):
EH&S Overview:
Analysis of prior year funding request versus actual:
Data Reports issued that support program:
Specifications & procedures pertaining to Program/Project:
Is this a mandated program? If yes, include verbiage associated with mandate:
Funding Forecast (Capital or O&M)
Actual Actual Actual Exhibit ___ (IIP-13) Page 46 of 82
2009 2010 2011 6,251 1,244 1,577
2012 2013 2014 2015 2016 2017 5 yr Budg Requ Requ Requ Requ Requ (13- et est est est est est 17) Fundi 1,800 1,800 2,000 1,500 1,500 0 6,8 ng 00 ($000s )
Exhibit ___ (IIP-13) Page 47 of 82
Project/Program Title Electronic Feeder Sign On (Integrated System Model) Priority Number Project Manager Maggie Chow Project Engineer Rachael Tlumak Budget Reference Project Number Status Estimated Service Date Work Plan Category Strategic IT Enhancement ERM Addressed
Work Description:
Extend the Rapid Restore system to support the following business requirements:
1. Allow splicing instructions jobs to be sent electronically from the Feeder Control Representative (FCR) to a “queue”, where it can be assigned by the operating supervisor to a qualified Distribution Splicer for work completion.
2. Allow spear and cut jobs to be sent electronically from the Feeder Control Representative (FCR) to a “queue”, where it can be assigned by the operating supervisor to a qualified cable crew or Distribution Splicer for work completion.
3. Allow cable pulling jobs to be sent electronically from the Feeder Control Representative (FCR) to a “queue”, where it can be assigned by the operating supervisor to a qualified cable crew for work completion.
Justification:
These improvements will reduce the phone call traffic to the Control Centers and accelerate the current "call in" sign on and sign off process. Additionally, the electronic sign-on process will enforce standardization and additional checks and balances for feeder sign-on/off.
Alternatives:
Currently there are no alternatives being considered for expediting the feeder sign on process for Spear/Cut, Cable, and Splice work.
Risk of No Action:
In June 27, 2004, the Company reached an agreement with the Union to expand the range of positions and job categories authorized to sign on to electrical work. This included the set of workers known as “Distribution Splicers”. Previously, Supervisors had been responsible for signing crews on to all splice work. Adding this responsibility to the Distribution Splicers was intended to make sign-on more efficient by eliminating the need for Supervisors to be at each job location in order for sign-on to occur. Sign-on was no longer limited by the number of Supervisors available and crew no longer had to wait for a Supervisor to arrive to begin working. Exhibit ___ (IIP-13) Page 48 of 82
However, significant challenges existed. With more people signing on concurrently, this creates a greater load on the sign on process at the control center. Also, adding new Distribution Splicers requires training and experience. Figure A shows the significant increase in the Distribution Splicer sign on rate from 23 % in 2007 to 85% in 2010.
The human element challenges, such as designing new spears to fit in the company trucks, developing additional training requirements with the Learning Center, and culture change, have been addressed by the Edison Project Team to ensure a safe and efficient sign-on process. However, there still remains a bottleneck at the control center that limits the benefits of these efforts.
Currently, the process by which Con Edison workers sign on to perform feeder repair work is manually-driven, involving direct two-way verbal communication with the Control Center in all cases. Each control center has one regional FCR on a shift to sign workers on manually. Delays occur as crews wait their turn to sign on with the single FCR and this delay could be quite significant. Delays are exacerbated by the interdependent nature of the work itself – downstream delays result when work is not completed on time, on shift, or in time for other work to begin on schedule. As indicated in Figure A, the Edison Project team led the efforts with the Regional Management to steadily increase the Distribution Splicers sign on rate from 23% (in 2007) to 85% in 2012. This effort highlights the need for an Automatic Electronic Feeder sign on application. Schedule gains (time for completion), schedule improvement (ability to meet expectations) and resource utilization could all be improved if the sign on process could be made more efficient.
Though crews are no longer delayed by waiting for a Supervisor to arrive before signing-on/off, they still experience a delay waiting for the Control Center Feeder Control Representative to become available for a verbal sign-on/off. Electronic Feeder Sign-On is intended to address this delay and additional bottleneck. Without it, the benefits of allowing crews to sign-on for feeder work cannot be fully realized.
Figure A.
Distribution/Chief Splicer Sign On 2008 - 2010
120%
97% 100% 95% 90% 89% 85% 80% 79% 78% B Q M 61% 60% X W 50% S 47% System
Sign On Percentage 40% 40% 38%
24% 20%
3% 0% Q1 08 Q2 08 Q3 08 Q4 08 Q1 09 Q2 09 Q3 09 Q4 09 Q1 10 Period
Exhibit ___ (IIP-13) Page 49 of 82
Summary of Benefits (financial and non-financial):
The Electronic Feeder Sign-On process will create and enforce consistency across the organization in how workers are authorized to sign on, how they are trained, and the sign on procedure itself. This will in turn increase the safety and transparency of the sign-on process.
Cost
Phase I of the Electronic Feeder Sign On application between 2012-2014 is estimated to cost $2.05 M without overhead. In order to contain the current scope, provide future enhancement and anticipate integration with WMS, in Phase II - additional funding of $312K and $305K are allocated in 2015 and 2016 respectively.
Savings
In 2009 there were 36995 DS sign on and sign off total events (multiple sign on locations per feeder). Since all sign-ons and sign-off s for authorized personnel (Underground crews, Cable crews, Distribution Splicers) are currently processed via one FCR at each of the Control Centers, and these calls are mostly concentrated in the first 2-3 hours of the beginning of a shift and the last 2 hours before the end of the shift, this creates a major traffic jam on the phone line of the FCR.
By using the queuing theory calculation, the estimated waiting time is 22.5 min per sign on/off event.
A crew is typically made up to two workers. Man-hour rate is $120
Savings (only includes DS) • Sign On/Sign Off events in 2009: 36995 • Queuing theory, average wait time = 22.5 minutes • Man-hr rate = $120, 2-man crews • Estimated percentage of Electronic sign on/off = 50% (conservative assumption to exclude some complex job that might route to phone call directly to FCR)
Savings = 2 X 120 X 36995 X (22.5/60) X 0.5 = $1,664,775
This translated to Return of Investment of 15 months; this also will provide COST SAVINGS of $1.66 mil annually after the application is completed.
One of our main goals has been to reduce the feeder processing times; by reducing the time the feeder is kept out of service the occurrence of cascading feeder outages is also reduced. The bottleneck that occurs during sign on also occurs during sign off, after the crew is done with their work. The Electronic Sign On application will allow crews to sign off within a few minutes of completing their jobs. Increased crew productivity is also one of our main targets. By reducing the waiting time for sign on and sign off events, it will increase the availability of crews to perform additional productive work before the end of their shift.
Exhibit ___ (IIP-13) Page 50 of 82
The Feeder Sign On application will eliminate most of this delay by automatically alerting the FCR that sign off is complete so they can review the package and send it to the DO to continue our feeder restoration process. Thresholds will be established to ensure that this review takes place in a timely manner.
Project Relationships (if applicable):
EH&S Overview:
Analysis of prior year funding request versus actual:
In 2010, the ISM budget was totally eliminated in order to secure funding for the Corporate Work Management System. In the first 6 months of 2011 IR dedicated resources to completing work on HUD which was to be delivered before the summer. As a result IR anticipates spending $405K out of the budgeted $ 1 mil for this year.
Data Reports issued that support program:
Specifications & procedures pertaining to Program/Project:
Is this a mandated program? If yes, include verbiage associated with mandate:
Completion Date: May 2014
Funding Forecast (Capital or O&M)
Actual Actual Actual 2009 2010 2011 2,776 0 258
2012 2013 2014 2015 2016 2017 5 yr Budget Request Forecast Forecast Forecast Forecast (13-17) Funding 1,152 1,200 450 312 305 0 2,267 ($000s)
NOTES: • The estimate for this project addresses the budget for the work to be performed and controlled by IR. • This estimate will be re-evaluated after analysis and design phase is completed in 2012. • The 2013 estimate includes 20K for enhancements System Operations needs to initiate to the Feeder Management System (FMS).
Exhibit ___ (IIP-13) Page 51 of 82
Project/Program Title Electric Distribution Control Center Upgrades Line Number 59 Project Manager William Washington Project Engineer (IR) Charles Cuomo Status In Progress Estimated Service 2016 Date Work Plan Category Operational Required
Work Description: The Manhattan (MECC), Brooklyn/Queens (BQCC), Bronx/Westchester (XWCC), and Staten Island (SICC) Distribution Electric Control Centers' server rooms are 24X7 operations requiring the highest level of reliability, availability, and security focused mainly on our SCADA environments. The operations of Electric’s Control Centers are fully dependent on the computer room infrastructure which is vital to maintaining our ability to deliver safe and efficient services to our customers. Currently, the HVAC and UPS in these facilities are not adequate and the IT infrastructure has reached end of life.
The original scope of this project entailed the replacement or enhancement of the UPS, server, network, and application infrastructure of all four control centers as well as an enhancement of the electrical and HVAC design to support current and future demands. The scope also included a small physical expansion of the server rooms. However, based on detailed engineering analysis (by both Facilities Engineering and an outside consultant) the required HVAC and floor loading designs along with the SCADA system requirements could not be accommodated in the existing space. As a result, new physical space was required. After several meetings and discussions with facilities, new space was identified for both the MECC and BQCC. Bronx/Westchester and SI are under review. Once the new space was finalized, the project team began the effort to acquire engineering designs for MECC and BQCC. Currently, Engineering drawings are 100% complete for MECC and BQ drawings are in progress.
Justification: The existing power, HVAC and underlying computing infrastructure are not adequate to continue meeting the support required for the Electric Distribution Control Centers, and the HVAC systems’ ineffective performance have been cited in audits. Since 2008, the Control Centers have experienced multiple UPS and HVAC failures resulting in temporary interruptions. In addition, many of the underlying server architecture are at end of life and critical vendors have issued notifications for ending support.
Alternatives: Operate “As Is” with known vulnerabilities.
Risk of No Action: • The Distribution CCs will not be able to comply with corporate cyber security designs and policies because underlying server architecture will not be supported and no updates for security patches or communication protocol technologies will be issued. • Insufficient HVAC systems in the Control Centers. HVAC failure could result in excessively high temperatures in the server rooms causing systems to fail or shut down preemptively rendering applications unavailable. This occurred in the MECC LAN room in June 2012. • No current UPS redundancy in the Control Centers. As a result, if power is lost and the single UPS fails, applications will fail until a backup power source is online. UPS failures have occurred in three of the four Control Centers in the past 4 years. Exhibit ___ (IIP-13) Page 52 of 82
• Non-financial Benefits (if applicable): This project to upgrade the underlying infrastructure for the Electric Distribution Control Centers is not based on financial justification. The project is to ensure the CCs operates in an environment that provides a high level of availability to allow the operators, designers and engineers to make proper decisions during major distribution system events.
• Technical Evaluation/Analysis: n/a
• Sensitivity Analysis (if applicable): n/a
• Project Relationships (if applicable): This project has significant impact to the Company’s Smart Grid Investment and Demonstration Grants as well as the VDAMS Replacement project (CDMS). These projects will not meet their goals if the Control Center’s upgrade project is not fully implemented.
Due to scope changes, revised completion dates below: Manhattan: June 2013 Brooklyn/Queens: June 2014 Bronx/Westchester & Staten Island Dec 2016
Issues: • At the MECC, delays in the restacking of 4IP resulted in delays with the engineering design. • At the BQCC, after the engineering review the original design was determined to have inadequate floor load capability. As a result, a new location had to be identified and engineered as well as obtaining a new lease for that area (1st fl 30 Flatbush). • Delays due to changes in oversight regulations resulted in Facilities Engineering having to redesign and rebid the CCs designs. • At the BQCC, after the engineering review of HVAC requirements, the original design (small expansion of existing space) was determined to be unfeasible. As a result a new location was acquired to be designed as new computer room. • At the MECC, due to original HVAC requirements not being met in the first design (20-ton chiller provided to satisfy 30-ton requirement); an additional engineering review proved current space could not accommodate requirements. Redesign and new space were needed to meet the requirements. • Due to the delays in the MECC and BQCC, it is not feasible to upgrade BQ and SI CC at the same time. As a result, IR is currently investigating options for centralizing our systems into the new MECC and BQCC facilities to reduce or eliminate extensive construction at those locations.
Based on the facilities delays, this project will need funding into year 2016 for the work on the physical space and the HVAC, UPS installation in BQ. Project managers are currently working with Facilities Engineering to develop updated delivery estimates based on bidding process.
Funding: ($000s)
Total Project Breakdown of Budget/Spend: 2009 Original Funding Request: $13,000,000 2009 Approved Funding $ 7,000,000
Exhibit ___ (IIP-13) Page 53 of 82
Approved Funding by Year: Spent 2009 Approved Funding: $ 500k $250k (Computer Infrastructure Equip) 2010 Approved Funding: $1,500k $900k * (Portable HVAC, Computing Equip) 2011 Approved Funding: $2, 000k $1,300k (Estimated: HVAC, UPS, Computing) 2012 Approved Funding: $3,000k $250k YTD ($3m planned for IT equipment) 2013 Requested Funding: $5,500k - 2014 Requested Funding: $1,600k -
*Money not fully spent due to facilities work being delayed
Funding Forecast (Capital or O&M) ($000)
Actual Actual Actual 2009 2010 2011 411 915 1,292
2012 2013 2014 2015 2016 2017 5 yr Budget Request Request Request Request Request (13-17) Funding 3,000 5,500 1,600 8,000 6,000 0 21,100 ($000s)
Exhibit ___ (IIP-13) Page 54 of 82
2013 Capital – Electric Operations
Project/Program Title Area Profile System (APS) Priority Number Project Manager Cary Pshena Project Engineer Mahendra Nandkishore Budget Reference 7XC9707 Project Number Status Enhancements Estimated Service Date December-2013 Work Plan Category ERM Addressed
Work Description:
The Company uses the Area Profile System (APS) to systematically collect, assess and evaluate critical population and household impact during a contingency or system emergency, as required by one of Staff’s recommendations in Case 06-E-0894 (LIC Outage Investigation). APS identifies population and household information, and also commercial and industrial information, down to specific geographic levels (e.g., zip code, block group, M&S Plate) in accordance with the Company’s account information. The system is currently undergoing remediation (calendar year 2012) to bring it up to Information Resources’ standards for supportability and maintenance.
While APS was originally designed to, and currently does meet, the Commission requirements of the Long Island City network outage proceeding, the system is currently unable to provide the analysis and segmentation functions needed to support the planning and execution of capital deferment and demand side management programs. For this, a transformation of the existing system is needed. To support Energy Services, Targeted Demand Side Management, Customer Engineering and Distribution Engineering, APS will obtain the following new data: customer data from various sources internal and external, including CIS and CuFLink; distributed generation data from various internal sources;; Westchester real estate data from the NYS Office of Real Property Services; and, possibly, benchmarking data from the City's Greener, Greater Buildings Plan. APS will put this new data into a geographic context and provide analysis tools to enable engineers and analysts to determine where best to prioritize resources to achieve their goals. Analysis tools such as user-defined queries and thematic mapping will be invaluable during planning and operations. To support the expansion in user base that will result from the addition of the new data and tools, APS will feature an expanded infrastructure including additional production and test servers, new security procedures, user and group profiles, collaboration tools for users to share work among teammates and with managers, and more frequent data updates. To support the transformation of the existing system, $150,000 will be needed in 2013 and $100,000 in 2014. The first year’s funds will be allocated to software development and additional hardware and software purchases that Market Research projects will be necessary to support an increased user base. The second year’s funds will continue the software development to satisfy user requests.
Information Resources is carrying out an analysis of consolidating the Company’s various mapping platforms, including APS. While this effort is still in the early phases, Market Research needs to allocate funds for integrating APS into the larger system in the 2015/2016 timeframe. Depending on the results of the analysis there is a potential cost of an additional $50K in 2015 Exhibit ___ (IIP-13) Page 55 of 82
and $50K in 2016 in additional capital to support integration of APS with the corporate mapping platform.
Units per Year: N/A Mandatory: N/A High-level schedule: N/A
Justification:
Transformation of the existing APS system will include new visualization tools available to Energy Efficiency, Demand Response and Targeted Demand Side Management as well as Distribution Engineering and other departments. For example, the thematic mapping capability will allow program managers to see which areas (networks, block groups, census blocks) and customer segments (hospitals, hotels, office buildings) of the service territory have greater potential for energy efficiency or have acquired energy efficiency savings. This capability becomes more powerful when combined with the planned addition of more data to the system and a feature that would allow administrators to add queries customized to a specific department’s needs. Another enhancement will allow Distribution Engineering analysts to track the locations of distributed generation installations. Altogether, these features enable powerful analysis methods, not currently employed, that would provide greater insight into where to concentrate resources to better attain departmental goals. This ability is timely, as distributed generation and capital deferment efforts are becoming more important each year as additional load is added to the distribution system.
Additional features were specifically requested by emergency operating groups, such as Staten Island Emergency Management and the Gas Emergency Response Center, to aid them in better gauging the impact of outages to sensitive customers, e.g., customers with medical hardship conditions or with life-saving equipment installed at home. Yet more upgrades will make the application more robust than it currently is and able to support a larger user base. The more robust design will ensure solid performance during system emergencies.
• Alternatives: The alternative to these enhancements is to use a general-purpose professional Geographic Information System (GIS) tool such as MapInfo Pro or ArcGIS Desktop to perform geographic analysis and segmentation on an as-needed basis. Disadvantages of using a general purpose professional GIS tool include: o Specialized training in the GIS tool and concepts would be required, resulting in only a small subset of personnel capable of using the GIS tool and the potential for a bottleneck in the workflow; and o The GIS specialist would need to manually combine customer, census, business and/or real estate data necessary for each project, tasks which are time consuming and will necessarily be done multiple times as data is updated. Advantages of using APS include: o It is a special-purpose tool custom developed for the Company’s needs and can be used by a wider range of company personnel with minimal training; o It provides a central location where data is collected, processed and used in an automated fashion; and o Use of APS results in a significant reduction in time and resources compared to the time needed for the GIS tool manual tasks.
Exhibit ___ (IIP-13) Page 56 of 82
• Risk of No Action: Distributed generation and capital deferment efforts are becoming more important each year as additional load is added to the distribution system. Without APS, the Company will not have an in-house application that will enable it to systematically analyze demand side management, distributed generation and capital deferment potential geographically in order to efficiently prioritize resources. This can result in increased cost and time to obtain deferments, and in some cases may result in lost deferment opportunities.
The current APS system has been found to exhibit infirmities when supporting 10 or more simultaneous users. This is a potential problem for system emergencies that affect multiple Company services (electric, gas, steam), because in such cases APS information is needed by multiple organizations including Steam Distribution, Gas Operations, Distribution Engineering, the Distribution Engineering Control Centers, Emergency Management, Customer Operations and Public Affairs.
• Summary of Financial Benefits and Costs: N/A
• Non-financial Benefits (if applicable): N/A
• Technical Evaluation/Analysis: N/A
• Sensitivity Analysis (if applicable): N/A
• Project Relationships (if applicable): Although there are other mapping applications within the company, they all concentrate to some extent on tracking company facilities, e.g. pipes, wires, mains, services and manholes. APS is the only mapping application enabling the combination of internal customer data and distribution system boundaries with externally sourced data such as census population, real estate data, business data and political jurisdiction boundaries.
Estimated Completion Date:
Status: The remediation effort to meet IR standards is underway.
Current Working Estimate (if applicable):
Funding ($000):
Approved Approved Total
2012 2012 400 400
Forecast Forecast Forecast Forecast Forecast Forecast 2013 2014 2015 2016 2017 Total 2013-2017 150 100 50 50 0 350
Exhibit ___ (IIP-13) Page 57 of 82
2013 Capital – Electric Operations
Project/Program Title Customer Energy Management Tool Priority Number Project Manager Vicki Kuo Project Engineer Budget Reference Project Number Status Implementation Estimated Service Date December, 2013 Work Plan Category ERM Addressed
Work Description:
The Energy Efficiency and Demand Management Department (the Department) is tasked with meeting the Company’s energy efficiency and demand response regulatory and internal goals. To effectively meet this challenge, the department must enhance its infrastructure. The Customer Energy Management Tool (CEMT) is an information system that supports the management of design, delivery and evaluation of a portfolio of demand side management programs and other initiatives such as energy efficiency (EE), targeted Demand-Side Management (targeted DSM) and Demand Response (DR) programs. The CEMT will be the primary program management tool (i.e., and comprise the system of record) as well as the primary source of information for demand side management (EE, DR, Targeted DSM) related regulatory reporting. The CEMT will provide business intelligence to support management and operational decisions, vendor activity, targeted marketing campaigns, and program design. The proposed Solution Architecture for the CEMT is comprised of five components: • Program Management Tool (PMT) – this is the transaction processing engine and system of record for energy efficiency and demand response programs. • Business Intelligence (BI) – this component of the architecture is a repository for a wide variety of information pertinent to the overall operations, marketing, and evaluation of EE, DR, and DSM programs. • Interfaces – there are a variety of interfaces that connect the solution architecture to the internal Con Edison infrastructure (CSS, CIMs, Project One, etc), as well as to provide interchanges of information with external parties and between architectural components. • Customer Relationship Management (CRM) – this component provides management tools to enhance our customer relationships and for the sales and related marketing processes necessary to drive program performance. It is essential to drive more collaborative relationships with our customers so that we gain a better understanding of their demand side needs and better our ability to forecast results for long term peak forecasting as well as marketing plan adjustments can be undertaken with certainty of the need and expected results. • Portal – the portal provides secure access to customers to participate in Con Edison programs, as well as certain, appropriate components of the architecture Exhibit ___ (IIP-13) Page 58 of 82
for partners engaged in the Con Edison portfolio of programs including, implementation contractors, trade allies, and employees.
These components together provide the basis for a strong, resilient, and reliable platform to scale program activities and support the Energy Efficiency and Demand Management Department for years into the future.
The project was proposed as a multi-year project costing $9.821 million. The functionality of CEMT will be used to support all the programs managed by the Department. This includes not just EEPS funded programs, but also Demand Response programs and Targeted DSM, and general account executive activity. There are functionalities built into the system that will be utilized for electric distribution operations. Examples include the ability to forecast energy efficiency savings impact on the grid by network or feeder and the ability to forecast demand response market potential by network. The proposed breakdown of funding allocation is as follows: Funding Source Percentage* Amount Orange and Rockland 4% $400,000 SBC 66% $6,600,000 MAC (DR and Targeted DSM 20% $2,000,000 programs) Electric Operations Capital 8.21% $821,000 • Estimate pending final development
Units per Year: Mandatory:
High-level schedule: PMT implementation – reviewing BI Implementation – 9/2012 – 6/2013 Portal Implementation – 5/2013 – 9/2013 CRM Implementation – 8/2013 – 12/2013
Justification:
There are two primary reasons to implement this system: First, there are two relatively new and quickly growing functions within Con Edison, energy efficiency and demand response, that need systems infrastructure in order to effectively operate the business. Currently the Department is operating on a set of internal business-supported small applications with little central infrastructure or technical support. These applications are basically spreadsheets and Access databases. This is a very time-consuming and resource-intensive manner and does not allow for the data manipulation and mining needed to effectively implement programs. Second, involves stringent regulatory requirements associated with energy efficiency and demand response operations. The programs are closely monitored by the PSC and DPS Staff, and Exhibit ___ (IIP-13) Page 59 of 82
failure to perform will may penalties to Con Edison. Without a system we do not have the tools to tack programs, success, improvements and the like. With the level of regulatory scrutiny that energy efficiency departments receive across the country and the level of detail often required by the NY PSC and DPS Staff during the first phase of program development and implementation, it is likely that this scrutiny will continue. In addition to these strategic drivers, there are a number of other factors that are important. These factors are primarily operational in nature such as administrative cost reduction, timely program corrections, program results verification, and report automation driving down the unit cost of delivering energy efficiency and demand response programs at Con Edison.
Alternatives:
In lieu of a comprehensive program management tool, the Company could implement a reporting and analysis tool (Business Intelligence Module). This approach would allow us to satisfy the reporting needs for internal analysis as well as regulatory requirements. Delaying the implementation of the program management component, would prevent us from integrating with Oracle Financial to process incentive payments and streamline forecasting in the short term. Upon completion of the Business Intelligence module, the Company could then address the remaining modules and the integration to Oracle Financial.
Risk of No Action:
Without the proper infrastructure to support the management of our various demand side management programs, the Company runs the risk of having high cost and poor performance. The risk of no action reduces the ability of Con Edison to effectively manage our programs.
Summary of Financial Benefits and Costs:
CEMT implementation will bring a significant set of benefits to Con Edison and greatly assist in the operation, marketing, and evaluation of Con Edison’s $100 million per year portfolio of energy efficiency (EE), targeted Demand-Side Management (DSM) and Demand Response (DR) programs. The benefits will be in the areas of reducing program and departmental operating cost and improved efficiency of the department. The business estimates a cost benefit ratio of greater than 3.0 for this investment.
Non-financial Benefits (if applicable): The benefits will be in the areas of reducing program and departmental operating cost and improved efficiency of the department. The business estimates a cost benefit ratio of greater than 3.0 for this investment.
Technical Evaluation/Analysis: N/A
Sensitivity Analysis (if applicable):
Project Relationships (if applicable): N/A
Estimated Completion Date:
Exhibit ___ (IIP-13) Page 60 of 82
December, 2013
Status:
Presently, the Department is examining the implementation priority of the various components of the system. The design phase of the BI tool has completed and a Request for Proposal (RFP) for the development of the BI module is scheduled for later part of 2012. Target service date for the BI development will be completed in 2013.
Current Working Estimate (if applicable):
Funding ($000):
The portion of the project that is allocated to Electric Operations is $821,000 (See table on page 2). The capital budget request per year is as follows:
Actual Actual Actual 2009 2010 2011 0 0 231
2012 2013 2014 2015 2016 2017 5 yr Budget Request Request Request Request Request (13-17) Funding 400 190 0 0 0 0 190 ($000s)
Exhibit ___ (IIP-13) Page 61 of 82
2013 Capital – Electric Operations
Project/Program Title Demand Response Management System Priority Number Project Manager Col Smart Project Engineer Budget Reference Project Number Status RFI development Estimated Service Date Feb, 2014 Work Plan Category ERM Addressed
Work Description:
The Energy Efficiency and Demand Management Department (the Department) is tasked with meeting the Company’s energy efficiency and demand response regulatory and internal goals. The lack of the appropriate infrastructure is negatively impacting the effectiveness of this effort.
A Demand Response Management System (DRMS) is a system that supports the management of enrollment, event initiation and settlement of the Company’s Demand Response (DR) programs. The DRMS will be the key transformational tool to support the transition from prior relatively rudimentary DR product offerings to the need to manage a portfolio of complex offerings with ever increasing customer participation. The Company has recently, over the past two years, expanded from a commercial and residential contingency event program to having contingency and peak-shaving programs, and to expanding the residential market from only central air conditioning to include room air conditioning offerings. While the MW enrollment has grown by over 10% for each of the past two years, we expect a considerable customer increase with the deployment of 10,000 room air conditioning controllers (ModLet) in 2012.
2012 has also seen the requirement to enable the delivery of real time meter data to commercial customers during demand response events and inclusion of customer’s export of energy from distributed generation units during events. All such developments have increased the complexity of managing the Company’s DR programs.
The proposed Solution Architecture for the DRMS comprises 5 essential components: • Program Enrollment – this is the transaction processing engine and system of record for both commercial and residential customer enrollment. Complex validation protocols need to be followed and effective interaction enabled with third parties via a web portal (commercial demand response aggregators, residential program administrators, direct customers). • DR Event Initiation – events and tests will be initiated by a DR operator generating a simple message to the aggregator, customer, or program administrator. The solution will also provide functionality to support direct equipment piece control via standard and secure control protocols (machine to machine). Events will be initiated on real-time and time delayed protocols. • Customer Settlement – this is the process of paying customers and/or aggregators for the availability of their committed capacity (kW) and performance (kWh) Exhibit ___ (IIP-13) Page 62 of 82
during events. The process involves complex calculations of the customer’s actual load as compared to a calculated baseline. • Business Intelligence (BI) – this component of the architecture is a repository for a wide variety of information pertinent to the overall operations, marketing, and evaluation of DR programs. • Interfaces – there are a variety of interfaces that connect the solution architecture to the internal Con Edison infrastructure (CSS, CIS, MDMS, LPDS, Project One, DMS, etc), as well as to provide interchanges of information with external parties and between architectural components. The DRMS will be an open-standards based system and will be capable of two-way communication while meeting industry standard security requirements.
These components together provide the basis for a strong, resilient, and reliable platform to scale program activities and support the Company’s objective for demand response and peak shaving programs for years into the future.
The project was proposed as a multi-year project costing no more than $2.8 million. It is anticipated that an RFI will be developed and deployed in Q3 of 2012 so that a RFP may be initiated in Q4 2012. The functionality of DRMS will be used to support all the DR programs managed by the Department. There will be functionalities built into the system that will be utilized for electric distribution operations. Examples include the ability to forecast DR resource impact and potential on the grid by network or feeder and provide system operators with information on resource availability.
Units per Year: Mandatory:
High-level schedule: RFI dispatch – 6/2012 – 9/2012 RFP dispatch – 10/2012 – 12/2012 Project award – 1/2013 – 2/2013 Project implementation – 4/2013 – 3/2014
Justification:
There are two primary reasons to implement this system: First, the complexity of operating demand response programs is growing as the customer volume, product offering and technology (controllable devices, machine to machine initiation) involved all evolve. This evolution requires systems infrastructure in order to effectively operate the business. Currently the Department is operating on a heavily manual basis which constrains product offering and customer service levels. The tools used are basically spreadsheets and a web-based customer contact system (SendWordNow). This is a very time-consuming and resource-intensive process and does not allow for the data manipulation and mining needed to effectively manage and enhance programs. Second, as DR evolves to be more important operational resource more operational and reporting stringency will be required. A consequence of the increase in importance will be the need to provide better vision to operators and to the PSC and DPS Staff. It is also a requirement as of 2011 that DR program performance must be reported twice a year to NERC. Without a system Exhibit ___ (IIP-13) Page 63 of 82
we do not have efficient tools to tack programs, success, improvements and the like. With the level of regulatory and general market scrutiny that demand response solutions receive across the country it is likely that this scrutiny will continue. In addition to these strategic drivers, there are a number of other factors that are important. These factors are primarily operational in nature—such as administration, cost reduction, timely program corrections, program results verification, and report automation. All drive down the unit cost of delivering demand response programs at Con Edison.
Alternatives:
We are investigating what solution pieces may be available as a consequence of the Smart Grid Demonstration Pilot (SGDP). It appears that enrollment and performance measurement tools may be able to be utilized on an operational basis but this has not been confirmed as yet. We are working with the SGDP team to determine the viability of this alternative to mitigate the cost of this budget request.
A further alternative is to continue with a heavily manual approach to managing demand response. While this remains an option it is anticipated that the evolving complexity of the demand response products and customer interfaces (direct customer enrollment, customer equipment control) will continue and our ability to expand in this market will be restricted by the lack of automation and real-time processing capability. The deployment of technology also allows for greater transparency which, while to some extent continues to evolve on a manual basis, will be advantageous for management oversight.
Risk of No Action:
Without the proper infrastructure to support the management of our various demand response programs, the Company runs the risk of having higher costs and poorer performance. The risk of no action is the reduced ability of Con Edison to effectively manage our programs and to take advantage of new customer-side control technologies (building management systems, controllable resources). In addition, we expect regulatory scrutiny of demand response performance to increase and accurate measurement of performance and timely reporting on that will be essential.
Summary of Financial Benefits and Costs:
DRMS implementation will bring a significant set of benefits to Con Edison and greatly assist in the operation, marketing, and evaluation of Con Edison’s portfolio of DR programs which have a collective annual budget of more than $15 million. The benefits will be in the areas of reducing program and departmental operating cost and the improved efficiency of the department.
Non-financial Benefits (if applicable):
The DRMS will create the ability to recruit and integrate more effective customer resources, both directly and indirectly, taking advantage of customer side technology.
Technical Evaluation/Analysis: N/A Exhibit ___ (IIP-13) Page 64 of 82
Sensitivity Analysis (if applicable): N/A
Project Relationships (if applicable):
This project will be complementary to the deliverables of the Smart Grid Demonstration Project and will enable better support of various groups (Distribution Engineering, System & Transmission Operations, Forecasting, Customer Operations, etc.) prior to, during, and after event periods.
Estimated Completion Date:
March, 2014
Status:
Presently, the Department has no effective automation for managing any aspect of the DR programs. Importantly this includes the complex and time consuming enrollment process, which will commence again in April 2013. Effort is being initiated in conjunction with IR to develop an appropriate RFI documents.
Current Working Estimate (if applicable):
Funding ($000):
The portion of the project that is allocated to Electric Operations is $2,950,000. The capital budget request per year is as follows:
2011 2012 2013 2014 2015 Total Request Request Request Funding 0 0 2,250 700 0 2,950 ($000s)
Exhibit ___ (IIP-13) Page 65 of 82
2012 Capital – Electrical Operations
Project/Program Title SCN Replacement Project Project Manager Mofid Gerges Project Engineer Mofid Gerges Status Estimated Service Date 2013 Work Plan Category
Work Description (Includes units per Year and a high level schedule):
This project plans to replace 205 SCN data concentrators in our unit substations with NTX data concentrators (manufactured by EFACEC ACS) which will be able to communicate using multiple protocols. This funding request is for phase I of the project which will replace 20 of the 205 SCN data concentrators. Currently there are 239 unit and multibank substations in the 4kV distribution system. 34 units are equipped with Network Terminal Unit (NTU) data concentrators from EFACEC ACS (also known as ACS units) that poll either GE Multilin microprocessor relays or RTUs from SATEC. These stations utilize DNP 3.0 as the communication protocol. 205 units are equipped with Station Control Node (SCN) data concentrators from PowerCom. The SCN units poll older RTUs that utilize an outdated HDLC protocol. These older RTUs cannot communicate using the DNP protocol, which is an open source protocol widely used by other utilities and the standard communication protocol on our Con Edison distribution SCADA systems. The plan is to replace the 205 SCN data concentrators in two phases over 5 years as follows: Phase I: this phase will include developing a prototype data concentrator and replacing the first 20 units. Phase II: upon successful completion of phase I, Distribution Engineering and Tech services will start ordering and replacing 186 data concentrator.
Schedule: Phase I Only 2012 2013 Material Ordering 20 units for none phase 1 Labor Testing 1st 2 units & Installing 10 installing the 1st 10 units units for phase 1
Justification (Technical Evaluation/Analysis): In order to ensure a reliable, durable and cost effective communication method to and from the 4kV Unit substations, the vintage SCN data concentrator must be replaced with a modern data concentrator that is equipped with up-to-date technology. The SCN data concentrators were originally installed in 1997 in the 4kV USS to provide SCADA communication to our 4kV USS. The SCN failure rate is increasing every year (in 2009 was 1 failure/month, 2010 was 2 failures/month, 1st 6 months of 2011 was 2.2 failures/month) making the SCN a highly unreliable device which affects the reliability and the availability of the 4kV SCADA system. The SCN devices are getting older and we anticipate 36 – 40 failures per year for the upcoming years. Exhibit ___ (IIP-13) Page 66 of 82
In addition to the failure rate, the SCN manufacturer is no longer in business, so there is no new SCN devices available in the market to replace the failed units, SCN repairs are done in house in conjunction with three outside companies which makes the predicted reliability for the repaired units unknown. On the technical side, the SCN data concentrator is a slow, single task device that cannot perform more than one task at a time which results in slow communications between the control center and the unit substations. The average down time of a unit substation due to SCN failure is between 24 – 48 hours, during which there is no remote control for the station and no data collection. Furthermore, SCN communicates with the station RTUs in HDLC protocol, this protocol is old and not utilized by other T&D companies. The support for the HDLC protocol is very limited. The experience within Con Edison in this protocol is also very limited. All new IEDs are using either DNP 3.0 or Modbus communication protocols. Since the SCN communicates using the HDLC protocol, it is incapable to communicate with any new IEDs.
Alternatives:
1- Retrofit all Electromechanical relays & HDLC RTU’s with microprocessor Relays and replace SCN with an approved DNP data concentrator. The average replacement cost per USS (5 feeders) will be approximately $100,000. This solution will require a station’s extended outage time for about 2 weeks.
2- Upgrading the old system is not an option because the SCN is using an obsolete technology and the manufacturer is out of business. Tech services department is just managing the repairs by replacing the old vintage parts with an exact match.
Risk of No Action: The existing system is becoming unreliable due to aging data concentrators. The high failure rate of the SCN causes loss of SCADA to these associated stations for extended periods of time. Also, there is limitation on using new SCADA devices since the new IEDs do not use the outdated HDLC protocol. The amount of data that can be collected from the station is limited due to the old SCN & RTU units. In other words, the old system has limited capacity that cannot be upgraded, and the system cannot accommodate new data points needed to serve new applications. Keeping the existing system will lead to increasing failures, making repairs more challenging because of limited availability of the older components and because the original SCN manufacturer is out of business.
Summary of Benefits (financial and non-financial): This project will improve the 4kV SCADA system: the new data concentrator unit will be a multitask device with much faster components; it can perform many tasks at the same time. The high communication speed will help improving the performance of many critical Control Center applications like the Load Shed and Restoration program (LSR) in XA21 system. Also, it will be able to communicate with all IEDs via the latest communication protocol like Modbus and DNP 3.0. This feature will allow replacing the old RTU and the electromechanical relay with a new microprocessor relay with no restrictions because of the communication protocol. The Exhibit ___ (IIP-13) Page 67 of 82
microprocessor relays are more accurate, faster, and more reliable; provide more data points for the SCADA system which can be used in many engineering applications. The project will enhance the reliability of the SCADA system because the new data concentrator will reduce the down time of the stations and the number of failed units will be reduced as well.
Project Relationships (if applicable):
EH&S Overview:
Analysis of prior year funding request versus actual:
Data Reports issued that support program:
Specifications & procedures pertaining to Program/Project:
Is this a mandated program? If yes, include verbiage associated with mandate:
Funding Forecast (Capital or O&M)
Actual Actual Actual 2009 2010 2011 0 0 0
2012 2013 2014 2015 2016 2017 5 yr Budget Request Request Request Request Request (13-17) Funding 1,000 92 0 0 0 0 92 ($000s)
Exhibit ___ (IIP-13) Page 68 of 82 2013 Capital – Electrical Operations
Project/Program Title PQView System Upgrade Project Manager Cristiana Dimitriu Project Engineer Cristiana Dimitriu Status Engineering Estimated Service Date 2014 Work Plan Category Strategic IT Enhancements
Work Description (Includes units per Year and a high level schedule):
Con Edison currently uses PQView 3 with power quality monitors at distribution substation transformers to locate faults on its 13 and 27kV underground network feeders. The power quality monitors serve as the voltage and current monitors in an automatic fault location system. Fault measurements captured by the meters are downloaded automatically, integrated into a PQView 3 database, and impedances are calculated. PQView 3 then combines impedance calculations with up- to-date distribution circuit models and geographic information system data to build estimated fault location tables and map displays. The systems are integrated on Con Edison’s intranet and real time email notifications are sent to numerous individuals within Con Edison including electric operations, system protection, and power quality. The system detects and locates incipient and permanent single-phase and multi-phase faults. PQView 3 also sends email alerts when subcycle faults and magnetizing inrush current transients are detected. For single-phase faults in Con Edison, the system’s accuracy regularly exceeds 65% success in placing the fault location within 10% of the total number of the feeder structures. In 2008, the system was expanded to incorporate data from feeder relays and in 2009 it was expanded to include data from transmission digital fault recorders. In 2009, data from the PQ monitors, microprocessor relays, and digital fault recorders was integrated with operations data from the SCADA historian (PI) using PQView 3.
Analysis provided by PQView 3 has also been integrated into control center and operations systems including the Heads Up Display (HUD), Visual Distribution Information System (VDIS) and the Feeder Management System (FMS). Integration in these systems has provided operators with automated decision support in key areas such as fault locating and determination if a Cut-In-Open- Auto is due to a fault or magnetizing inrush. Data analyzed by PQView 3 is also being integrated into an automated bus fault analysis and correlation tool for System and Electric Operations.
In addition to the information described above, PQView 3 also analyzes and provides ready access to critical operating information including fault duration, overvoltage conditions, relay targets, digital fault recorder oscillography, and smart meter data (from High Tension metering). PQView has also been improved to analyze “follow on faults” which can cause cascading in networks, and to analyze capacitor switching transients, breaker restrike, and breaker fault duties which will help drive asset management decisions. Additionally, as we migrate to additional devices such as microprocessor relays and PQNodes being installed at our 4KV unit substations; additional feeders and systems can be quickly and fully enhanced with the same functionality and decision support that is available now at area and transmission substations.
Attachment 1 shows the relationship between the intelligent electronic devices, other data sources, PQView 3 and the major functionalities and systems in Con Edison supported by PQView.
Exhibit ___ (IIP-13) Page 69 of 82 Also, PQView 3 is the primary analysis tool which has allowed us to do long term characterization of the Harmonic Distortion Levels on the primary and secondary distribution systems as well as the development of voltage sag and momentary interruption performance indices.
Further, PQView 3 is playing a key role in developing a new tool, StationSpec. By integrating data from the PQNodes and other intelligent electronic devices in our area substations and secondary networks, and the SCADA historian (PI) data, we are developing statistical process control tools in PQView that will facilitate continuous monitoring and performance reporting for the voltage and var control systems at area substations.
One of the primary reasons that Con Edison has chosen to build its fault location, inrush detection and other grid asset health diagnostic system on the PQView 3 architecture is because of the wide variety of sensors and other instruments that can be integrated into a PQView system, and its ease of learning and use. As described above PQView 3 integrates data from an unlimited array of power quality monitors, digital fault recorders, electronic relays, revenue meters, data historians, and SCADA systems. First and foremost, Con Edison uses PQView because it is a highly advanced system for processing IEEE Std 1159.3-2003 PQDIF files and IEEE Std C37.111-1991/1999 COMTRADE files. However, it also includes functionality for integrating devices using generic communication protocols such as Modbus. Furthermore, PQView has a large number of drivers for integrating data from many proprietary systems. This is critical as we progress into a smarter grid with more and more advanced intelligent electronic devices.
Justification (Technical Evaluation/Analysis): Con Edison plans to expand the number of intelligent electric power system monitors by about 300% in less than five years. PQView is a critical component to provide automatic integration and analysis of measurements from these sensors for prognostics, diagnostics, analytics, and decision support for system restoration. However, the current PQView 3 design limitations make it a weak link in the overall goal of having greatly expanded data acquisition of grid parameters that focus on disturbance prevention and reliability improvement. Therefore, Con Edison sees a reengineering of PQView as a critical need for a smarter, more reliable Con Edison grid.
Expansion of the number of intelligent electronic devices on our systems makes the upgrade of PQView by the creation of the PQView 4 platform more urgent: features such as PQView 4’s scalability, its ability to import and process data more autonomously and reliably, its greater support for various device integration standards (e.g., IEC 61850), and its extensibility platform via a software development kit, make PQView 4 a key component to moving forward in this arena.
PQView 4 This project will reengineer and extend the domain models, database schema, software libraries, algorithms, services, and applications used in PQView 3 into a new application suite that will be known as PQView 4.
New Technology Platform Moving to a new technology platform is a primary and critical driver for PQView 4, and is required in order to ensure PQView’s longevity and to allow it be a host for diverse smart grid prognostic and diagnostic applications, which are both critical capabilities for sustaining reliable power delivery. A new platform will be the key enabler to allow for improved features, flexibility, performance, availability, and needed scalability. PQView 4 will be based on Microsoft’s modern Exhibit ___ (IIP-13) Page 70 of 82 development platforms. It will include built-in support for modern versions of Microsoft Windows, including support for 64-bit processing architectures.
User Interface While very functional, the PQView 3 user interface (UI) has a twenty-year history, and in places appears cluttered and unintuitive. For PQView 4, the UI will be re-factored with the goals of improving ease of use and consistency. The PQView 3 user interface and controls appear dated in their look and feel; PQView 4 will provide a fresh, modern interface. The PQView 4 user interface will be more layered and modular, facilitating consistency, flexibility, maintainability, and extensibility. A powerful, highly interactive PQView 4 user interface will be available via a lightweight deployment and update option, extending application reach and ease of use, and greatly facilitating maintainability. As an example, fault location modules will provide integrated, interactive GIS map and aerial imagery to expedite fault understanding and remediation.
Data Federation and Enhanced Integration For the most part, PQView 3 only analyzes and reports on data that has been imported into a PQView database. Additionally, a single instance of PQView 3 can work only with one PQView database at a time. There is a growing need to integrate the power systems measurements imported into a PQView database with large external data stores such as SCADA systems, data historians, and more. Integration of these data stores is important in order to provide a comprehensive solution for analyzing all of the assets needed to sustain reliable system operations.
PQView 4 will add support for a generic model for “federating” with external data stores. An example of a federated system would be if one or more native PQView databases are combined with a SCADA database or an OMS database that could be accessed simultaneously using the same PQView 4 domain model. A single PQView 4 instance will be able to access data from both integrated and federated data stores, including multiple PQView databases.
Enterprise-Class Features and Performance Although PQView 3 stores its power systems measurements in a powerful SQL Server 2005 or 2008 database system, its data management module runs a single-threaded, desktop application. PQView 3 does not utilize longer-running, more robust modules, such as Windows services, which are commonly used for enterprise-class processes. Instead, imports occur within an interactive process, mostly without failure recovery. Key goals of PQView 4 will be to embrace key enterprise-class server features to improve performance and availability. Its architecture will support reliable, long-running, recoverable, unattended data import and server processing. It will have the built-in processing ability to effectively utilize multiple threads, processors, and machines to distribute and handle dynamic work load. Its architecture will support high availability operation, allowing the automatic shift of workload to currently available systems. Furthermore, as more distributed sensors are added to the monitoring system, high scalability features will become more critical for grid operation.
Improved Standards Support PQView 3 currently allows integration with smart grid standards including IEEE 1159.3 PQDIF and IEEE C37.111 COMTRADE. It also offers indirect integration with open industry standards such as Modbus. PQView 4 will have deeper, better-aligned integration with numerous industry standards; candidates include IEC 61970 Common Information Model (CIM), MultiSpeak for Distribution Modeling, IEC 61968 Information Exchange between Distribution Systems, and IEC 61850 Electrical Substation Automation. Tighter integration of IEEE 1159.3 PQDIF, IEEE Std 519, IEEE Std 1453 will be considered. PQView 4 will offer real-time and historical data exchange Exhibit ___ (IIP-13) Page 71 of 82 via OPC. Software standards such as WSDL, SOAP, WS-*, and XML will be key to service- oriented systems. Integration with some of these standards will require redefinition of the domain model used by PQView itself. Embracing such standards will greatly facilitate the much needed interoperability that the smart grid objectives demand.
Richer, .NET-Based Developer Framework/Software Development Kit The PQView 3 architecture allows third-party software development using ActiveX libraries and Component Object Model interfaces. Some third-party developers also directly query a PQView database using SQL statements. PQView 4 will be built on a “PQView platform” that uses the .NET framework and concepts such service orientation, loose coupling, and modularization. The resulting PQView 4 platform will provide an extensible framework for building additional advanced applications for both proactively maintaining the grid and responding to failures.
Security PQView 3 supports a certain level of database-level authorization support when used with SQL Server, which can use SQL Server or Windows authentication. PQView 4 will move to a capability/role based user authorization scheme implemented at the service layer. It will function and provide security independently of any database-based security mechanisms, providing access consistently, even across federated data stores. By leveraging the power of .NET’s Windows Communication Foundation (WCF), PQView 4 should be able to provide flexible and powerful security functionality. It will be designed to optionally integrate with Windows security, allowing the user to have a single sign-on shared by their workstation and PQView when used within the corporate intranet.
Prognostic Health Management and Distribution Sensing using PQView 4 The sensors and intelligent electronic devices that can be integrated by PQView monitor the equipment critical to ensuring reliable grid operations, including transformers, switchgear, cables, lines, and feeders. PQView 4’s added support for both distribution system interoperability standards such as IEC 61850 and enhanced security will securely extend its reach further into areas critical for improving grid reliability, efficiency, and security. The algorithms developed for PQView 3 will be migrated to PQView 4 and will be enhanced and extended. These algorithms and applications focus on monitoring substation equipment and distribution feeders and transformers for signatures of forthcoming failure, such as self-clearing and intermittent faults, unbalanced regulator operation, unbalanced reactive power delivered by capacitors, incorrect regulator setting based on load level, detection of tap changer degradation, and abnormal switching of circuit breakers.
Alternatives: We know of no other commercial alternative to the data gathering, analytics and information visualization provided by the PQView suite of programs and data bases. Maintaining PQView3 might work for the short term, but it is not scalable and will not be a reliable or secure plan for the longer term as noted below in the Risk section.
Risk of No Action: As powerful and flexible as the present PQView 3 architecture is, it is based on dated and superseded technologies which are not scalable to the level needed to sustain our emerging smarter grid. Many of the PQView 3 libraries are based on enterprise development tools that have passed out of mainstream support by Microsoft. These older technologies are not the best fit given the current state of technology and IT industry focus, and the current and future needs of PQView. The Exhibit ___ (IIP-13) Page 72 of 82 current PQView 3 platform was developed 20 years ago. The database structure, user interface, scalability, inability to acquire data directly from intelligent electronic devices, and security concerns are making the system more and more difficult to maintain. Meanwhile the number of devices from which it will have to manage and analyze data for automation, decision support and engineering analysis is about to increase geometrically. Not upgrading the PQView 3 system will put at risk the ability to support such basic applications as feeder fault location, automated inrush detection, bus fault trip out analysis, and the voltage regulation statistical process control analysis.
Summary of Benefits (financial and non-financial):
Develop scalability and stability to continue to sustain the gains achieved with decision support, situational awareness and feeder processing duration reduction, including:
• Reactance to Fault Analysis by PQView (Reduces Fault Locating time, especially in the critical summer period) o Fault Locating Accuracy approaching 80% within 1-3 manholes o Fault Locating time trending to 50% of values before RTF introduced o Key factor in reducing feeder processing time and cascading network event risk • Automated inrush detection (allows rapid restoration of CIOA feeders which are not faulted) o 55 CIOA Feeders restored promptly after PQView detected and analyzed inrush currents in 2009 through 2011 (data presented to operators via email notifications and the HUD system). This represents savings of approximately $1.125M annually in avoided repairs. o Key factor in reducing feeder outage time and cascading network event risk. • Incipient fault detection on underground circuits will allow proactive repairs on the distribution feeder • Transmission Event DFR automated notifications • Statistical Process Control Analysis to support voltage regulation at area substations • Develop new tools, including: o Bus Section Trip Out/Bus fault correlation analysis and decision support o Asset Management applications for transformers, breakers, capacitor banks and other equipment o Fault Location on 4kV feeders
Project Relationships (if applicable): • Smart Grid Investment and Demonstration Grants • Electric Control Center Upgrade project. • PQNode System Upgrade
EH&S Overview: N/A
Analysis of prior year funding request versus actual: Exhibit ___ (IIP-13) Page 73 of 82 N/A
Data Reports issued that support program: N/A
Specifications & procedures pertaining to Program/Project: Various control center applications and systems including portions of HUD, VDIS, FMS, and operating procedures including EO-4095.
Is this a mandated program? If yes, include verbiage associated with mandate: N/A Funding Forecast (Capital or O&M)
The goals of upgrading PQView are grouped into three phases. This authorization / appropriation will fund PQView 4 Development Phases 2 and 3. We also fund Phase 1 through EPRI.
Objectives of Phase 1 – Initial Development In this initial phase of development, key aspects of the project are being developed. The high-level requirements and overall system architecture will be defined, and initial versions of key components of the core system will be developed and tested. Partial functionality in a few areas critical to PQView functionality will be developed into a demonstrable, proof-of-concept form. Objectives of Phase 2 – Core Development After the initial phase, development of PQView 4 will transition into a core development phase, where core components of the infrastructure, models, and services are developed, and basic functionality for numerous critical functional areas is developed. One or more PQView Explorer 4 Edition applications will be created to demonstrate the evolving functionality. Objectives of Phase 3 – Release Development The objective of this phase is the creation of the first viable release of PQView 4 applications. In this final phase of development, release versions of the infrastructure, domain models, etc. are developed, and enough functionality for the product to be considered viable is completed and stabilized. This phase ends with the delivery of the release version of PQView 4.0.
The total cost to Con Edison for Phases 2 and 3 would be $2,750,000.
Actual Actual Actual 2009 2010 2011 0 0 0
2012 2013 2014 2015 2016 2017 5 yr Budget Request Request Request Request Request (13-17) Funding 650 950 1,150 0 0 0 2,100 ($000s)
Exhibit ___ (IIP-13) Page 74 of 82 Attachment 1
Exhibit ___ (IIP-13) Page 75 of 82
Attachment 2 2009 through 2011 CIOA Feeders Restored Rapidly after Non-Fault Inrush Conditions were identified by PQView 2010 Data 2009 Data Fresh 01-05- 01-05- 01-05- West Kills 2010 2010 2010 110th St. 12-15- 12-16- 12-15- # 1 HARLEM 2009 2009 2009 33R08 CIOA Closed 33/13kV 17:09 19:03 17:09 Details non Fault 2M41 CIOA Closed 13.2kV NWK 23:49 02:13 23:49 Details Non fault Plymout BORO 01-22- 01-22- 01-22- MADISO h St. HALL 2010 2010 2010 East 29th N 12-09- 12-09- 12-09- 1B56 CIOA Closed 27kV NWK 12:52 13:17 12:53 Details non Fault St. SQUARE 2009 2009 2009 Plymout BORO 01-22- 01-22- 01-22- 6M42 CIOA Closed 13.2kV NWK 13:21 15:55 13:21 Details Non fault h St. HALL 2010 2010 2010 West 110th St. 10-18- 10-18- 10-18- 1B56 CIOA Closed 27kV NWK 13:18 14:13 13:17 Details non Fault # 1 HARLEM 2009 2009 2009 LONG 2M41 CIOA Closed 13.2kV NWK 07:22 12:55 07:22 Details Non fault North ISLAND 02-10- 02-10- 02-10- West Queens # CITY 2010 2010 2010 110th St. 10-18- 10-18- 10-18- 1Q21 CIOA Closed 1 27kV NWK 21:50 22:11 21:50 Details non Fault # 1 HARLEM 2009 2009 2009 MADISO 2M41 CIOA Closed 13.2kV NWK 05:38 07:22 05:38 Details Non fault West LINCOLN 06-13- 06-13- 06-13- East 29th N 02-16- 02-16- 02-16- 65th St. # SQUARE 2009 2009 2009 St. SQUARE 2010 2010 2010 23M59 CIOA Closed 2 13.2kV NWK 14:19 16:38 14:33 Details Non fault 6M38 CIOA Closed 13.2kV NWK 05:23 06:13 05:26 Details non Fault COOPER 04-06- 04-06- 04-06- Plymout BORO 03-27- 03-27- 03-27- Avenue SQUARE 2009 2009 2009 h St. HALL 2010 2010 2010 7M56 CIOA Closed A 13.2kV NWK 17:17 18:17 17:31 Details Non fault 1B65 CIOA Closed 27kV NWK 23:06 23:17 23:05 Details non Fault COOPER 04-06- 04-06- 04-06- Plymout BORO 03-27- 03-28- 03-27- Avenue SQUARE 2009 2009 2009 7M56 CIOA Closed A 13.2kV NWK 15:46 17:31 16:29 Details Non fault h St. HALL 2010 2010 2010 East 40th GRAND 01-31- 02-01- 01-31- 1B65 CIOA Closed 27kV NWK 23:18 02:54 23:18 Details non Fault St. # 1 CENTRAL 2009 2009 2009 Greenwo 04-03- 04-03- 04-03- 4M67 CIOA Closed 13.2kV NWK 22:54 00:54 22:54 Details Non fault od 27kV - BAYRIDG 2010 2010 2010 Brownsvi RICHMO 12-31- 01-01- 12-31- 8B84 CIOA Closed E NWK 11:14 11:21 11:14 Details non Fault lle # 2 ND HILL 2009 2010 2009 Plymout 04-21- 04-22- 04-21- 9B10 CIOA Closed 27kV NWK 21:18 04:01 21:20 Details Non Fault Greenwo 12-07- 12-07- 12-07- h St. 2010 2010 2010 od 27kV - BAYRIDG 2009 2009 2009 1B93 CIOA Closed 27kV 22:06 01:30 22:06 Details non Fault 8B87 CIOA Closed E NWK 17:15 23:11 17:17 Details Non Fault West Plymout BORO 11-26- 11-26- 11-26- 110th St. 05-30- 05-30- 05-30- h St. HALL 2009 2009 2009 # 1 HARLEM 2010 2010 2010 1B52 CIOA Closed 27kV NWK 01:48 05:54 01:48 Details Non Fault 2M41 CIOA Closed 13.2kV NWK 15:33 16:44 15:35 Details non Fault Greenwo 11-14- 11-14- 11-14- 06-06- 06-06- 06-06- od 27kV - BAYRIDG 2009 2009 2009 8B80 CIOA Closed E NWK 03:31 04:31 03:31 Details Non Fault Jamaica JAMAICA 2010 2010 2010 Greenwo 09-07- 09-07- 09-07- 5Q30 CIOA Closed 27kV NWK 01:52 02:48 01:51 Details non Fault od 27kV - BAYRIDG 2009 2009 2009 Brownsvi RICHMO 06-08- 06-08- 06-08- 8B90 CIOA Closed E NWK 04:42 05:22 04:41 Details Non Fault lle # 2 ND HILL 2010 2010 2010 WILLIAM 08-21- 08-21- 08-21- 9B12 CIOA Closed 27kV NWK 18:51 19:29 18:52 Details non Fault Water St. SBURG 2009 2009 2009 Brownsvi RICHMO 06-22- 06-22- 06-22- 6B44 CIOA Closed 27kV NWK 17:34 17:47 17:34 Details Non Fault Greenwo PARK 08-19- 08-19- 08-19- lle # 2 ND HILL 2010 2010 2010 od 27kV - SLOPE 2009 2009 2009 9B09 CIOA Closed 27kV NWK 15:54 16:21 15:53 Details non Fault 2B09 CIOA Closed NWK 18:28 18:49 18:34 Details Non Fault East 63rd TURTLE 07-28- 07-28- WILLIAM 07-05- 07-05- 07-05- St. # 2 BAY 2010 2010 Water St. SBURG 2009 2009 2009 25M41 CIOA Closed 13.2kV NWK 05:52 07:05 Details non Fault 6B44 CIOA Closed 27kV NWK 21:30 21:35 21:29 Details Non Fault MADISO Greenwo 06-24- 06-24- 06-24- East 29th N 10-25- 10-25- 10-25- od 27kV - BAYRIDG 2009 2009 2009 8B90 CIOA Closed E NWK 00:22 01:01 00:23 Details Non Fault St. SQUARE 2010 2010 2010 LONG 6M31 CIOA Closed 13.2kV NWK 11:46 12:14 11:47 Details non Fault North ISLAND 05-06- 05-06- Bensonh SHEEPSH 11-22- 11-22- 11-22- Queens # CITY 2009 2009 urst # 1 EAD BAY 2010 2010 2010 1Q14 CIOA Closed 1 27kV NWK 18:19 18:54 Details Non Fault 10B67 CIOA Cut In 27kV NWK 03:00 10:41 02:59 Details non Fault Brownsvi RICHMO 04-25- 04-25- Greenwo 12-15- 12-15- 12-15- lle # 2 ND HILL 2009 2009 od 27kV - 2010 2010 2010 9B12 CIOA Closed 27kV NWK 00:21 00:21 Details Non Fault Plymout BORO 03-03- 03-04- 03-03- 2B91 CIOA Closed 03:37 12:45 03:37 Details non Fault h St. HALL 2009 2009 2009 Greenwo 12-15- 12-16- 12-15- 1B56 CIOA Closed 27kV NWK 22:48 14:40 22:59 Details Non Fault od 27kV - 2010 2010 2010 01-13- 01-13- 01-13- 2B91 CIOA Closed 11:58 14:02 12:45 Details non Fault Jamaica JAMAICA 2009 2009 2009 Greenwo 12-16- 12-18- 12-16- 5Q42 CIOA Closed 27kV NWK 11:21 12:25 11:21 Details Non Fault od 27kV - 2010 2010 2010 01-10- 01-11- 01-10- Corona # FLUSHIN 2009 2009 2009 2B91 CIOA Closed 14:02 07:59 14:02 Details non Fault 7Q66 CIOA Closed 1 27kV G NWK 08:44 10:38 08:44 Details Non Fault 12-20- 12-20- 12-20- 01-10- 01-10- 01-10- Jamaica JAMAICA 2010 2010 2010 Corona # FLUSHIN 2009 2009 2009 5Q30 CIOA Closed 27kV NWK 18:54 22:16 18:54 Details non Fault 7Q66 CIOA Closed 1 27kV G NWK 05:06 08:44 05:06 Details Non Fault 12-24- 12-24- 12-24- 01-10- 01-10- 01-10- Jamaica JAMAICA 2010 2010 2010 Corona # FLUSHIN 2009 2009 2009 5Q30 CIOA Closed 27kV NWK 02:18 03:03 02:20 Details non Fault 7Q66 CIOA Closed 1 27kV G NWK 03:49 05:04 03:54 Details Non Fault
2011 Data
Exhibit ___ (IIP-13) Page 76 of 82 Attachment 3 Summer 2011 Con Edison RTF Accuracy
Exhibit ___ (IIP-13) Page 77 of 82
2013 Capital – Electrical Operations
Project/Program Title System Enhancements to Support Conservation Voltage Optimization Project Manager Elie Chebli Project Engineer Chris Comack, Leeman Hong Status Engineering Estimated Service Date 2013 Work Plan Category Strategic Enhancements, System and Component Performance
Work Description (Includes units per Year and a high level schedule): Con Edison conducted a pilot program designed to gain experience in operating our network distribution system in a Conservation Voltage Optimization (CVO) mode to reduce real and reactive energy supplied to and consumed by customers, and to decrease demand as well. The CVO pilot was implemented in eleven (11) area substations and thirteen (13) networks. This pilot encompassed four major areas of focus including:
• Voltage Control Methods and Optimization, including statistical process control techniques • Energy and Demand Savings Measurement • System Testing and Modeling • Economic Analysis
This funding request provides for the development of software tools, and procurement and installation of equipment to utilize new control chart metrics for quantifying the impact of our normal scheduled voltage on customer equipment along with energy savings that result from optimizing the delivered voltage. The scope of work encompasses enhancements to the following systems: • Deployment of statistical process control systems for area substation voltage regulation and other automated reporting systems • Installation of end of line monitors in the secondary distribution network and overhead system. Data supplied by these monitors and process control systems are necessary to assure proper delivery voltage to our customers.
Efforts are underway in a collaborative effort with NYU/Poly to test customer end use equipment, field survey various customer facilities in different rate classes to catalog equipment usage, and update our PVL models with the objective of having an 8760Hr/Year model for CVO energy savings.
Engineering will utilizing a mobile voltage regulator to test selected customer composite demands. The data collected will quantify the customer equipment response to both CVO and non-CVO delivered voltage, and will help engineering improve customer modeling and generate two daily demand curves for a single 24 hour period.
Justification (Technical Evaluation/Analysis): Electric utilities (Con Ed included) typically deliver more voltage than customers need, to ensure that the customer at the very end of the distribution line gets enough. There are many reasons in history for this practice, but in general and as is the case here, supply voltage can be reduced and still be within the range for providing safe and reliable service. Generally, power consumption varies linearly with supply voltage, i.e. higher voltage results in higher consumption. In this CVO program, voltage optimization is achieved through the operation of substation voltage regulators in order to regulate the voltage at specific end of line points within a prescribed range. In this way annual energy consumption is reduced as is peak demand. Implementation of CVO calls for an average reduction of 2.25% to the bus voltage regulation Exhibit ___ (IIP-13) Page 78 of 82
schedules which are applied through engineering standards to the Voltage Var Control system in the Energy Management System (EMS). Additionally, settings are applied locally at area substation power transformer Contact Making Voltmeter (CMVM) controls. The CMVM provides transformer voltage control when the voltage cannot be controlled from the EMS. It is critical to providing adequate customer supply voltage via CVO that a system be developed which will properly identify times at which the voltage regulation goes “out of control” so that that these excursions can be tracked down, and the root causes identified and corrected. Three process control variables have been identified which are key to maintaining control:
• Deviation from scheduled voltage – which will be tracked against an upper and lower control limit • MVAR range – out of balance of reactive power flows among area substation banks which will be tracked against an upper control limit • Tap Range – maximum spread of taps among transformer banks in service which will be tracked against an upper control limit
The control limits will be designed to identify times when the voltage regulation process is “out of control”. This will help identify design, maintenance or operational issues with the system so that corrective action may be taken. It is likely that some transformer CMVM and other equipment at substations will exhibit control issues which cannot be addressed via normal maintenance and will need to be addressed by upgrading the local control system.
Presently, data to help validate the voltage regulation process are available from existing substation monitoring, and from “masterpoint” and other transformer secondary buses in the network. This project will also select representative locations in each low voltage network which represent the electrical “end of line” and install a high resolution monitoring device to monitor voltage regulation impacts down through the secondary mains and to the service conductor level. Similar monitoring will be installed at the “end of line” locations on the overhead system.
Alternatives: Some alternatives include the additional deployment and expansion of Demand Response programs to both reduce annual energy consumption and customer energy costs. Additional deployment of smart meters and associated infrastructure to gather and process data is an alternative to installing ‘end of line’ monitors, but would not provide the same high resolution data points to best monitor the system voltage performance and improve the voltage regulation process.
Risk of No Action: The risk of not implementing these system enhancements may result in a decline or poor voltage regulation.
Summary of Benefits (financial and non-financial): Through the deployment of statistical process controls, Con Edison will achieve voltage optimization through more efficient operation of substation voltage regulators in order to regulate the customers supply voltage at all points in the electrical system. With the addition of ‘end of line’ monitors in the secondary distribution system, the data collected from the high resolution devices will be used to validate the voltage regulation process and ensure customers receive both the design and mandated service delivery voltage.
Project Relationships (if applicable): Electric Control Center Upgrade Project RMS Data Acquisition System High Tension Monitoring Data Acquisition System Exhibit ___ (IIP-13) Page 79 of 82
Heads Up Display Power Quality (PQ Nodes) System Upgrade PQView System Upgrade Unit Substation Automation
EH&S Overview: Distribution system total carbon footprint is directly reduced by the estimated energy savings. This benefit has not yet been fully quantified.
Analysis of prior year funding request versus actual:
Data Reports issued that support program: Some of the pilot data analysis is shown in the attachments and detailed analysis, presentations and supporting material is on the project sharepoint site: http://ceintranet/sites/electricops/DistEngineering/ConservationVoltageOptimization/Pages/default.aspx
Specifications & procedures pertaining to Program/Project: Voltage Var Control system, various substation feeder bus voltage and capacitor switching schedules, engineering procedures and instructions relating to CMVM operations, EO-2065 “Low Tension A.C. Service Voltage Limits”
Is this a mandated program? If yes, include verbiage associated with mandate:
Funding Forecast (Capital or O&M)
Actual Actual Actual 2009 2010 2011 0 0 0
2012 2013 2014 2015 2016 2017 5 yr Budget Request Request Request Request Request (13-17) Funding 500 500 0 0 0 0 500 ($000s)
Exhibit ___ (IIP-13) Page 80 of 82
2013 Capital - Electric Operations
Project Name Work Management Project Tracking Project Number 10027226 Work Plan Category Strategy - Efficiency &Standardization; Process and Applications Improvements Priority High Project Manager Pete Cooney Project Engineer Richard Jackson Budget Reference 9XC1801 Project Status Ongoing End Date 2Q 2014 ERM Addressed
Work Description: Con Edison maintains a suite of applications that support the core work management processes within Electric Operations. New applications and enhancements to the existing systems have introduced new technologies, enhanced functionality and improved integration between the applications that comprise the work management suite. While these systems remain viable and technically supportable, they do not provide the level of visibility that would be desirable to better facilitate the management of all aspects of work. Users still need to access and interact with a number of systems to support work planning, execution and completion. Enhancements in these areas would help users in Electric Operations to facilitate improved cost tracking, work scheduling, status reporting and productivity analysis.
The scope and magnitude of Electric Operations’ capital construction projects and the complexities associated with its maintenance and inspection programs require new business processes, organization structure and the implementation of improved information systems to support the planning, execution and tracking of these comprehensive work programs. The improved information systems will provide the following functionality for Electric Operations personnel: • A single repository for all planned and emergent work within Electric Operations so users no longer need to access multiple systems to process work • An interface that provides detailed information about electric distribution assets that work is being performed against • A comprehensive facility that helps manage all maintenance and inspection programs • A mechanism to match project work requirements and tasks to worker skills and other resources such as vehicles and other equipment • Trending and analysis of workforce and equipment performance • A summary of all associated costs by work activity or project • Interfaces to Finance, Supply Chain and HR systems that reduce clerical input and further streamlines processes • A resource scheduling and planning assistant • Integration with mobile technologies allowing the transmission of data to/from the field
Con Edison completed a Phase 0 Assessment for Electric Work Exhibit ___ (IIP-13) Page 81 of 82
Management Business Processes and Information Systems in December 2009. The team was comprised of key business users in Electric Operations, Information Resources support staff and consultants. The team reviewed all work management business processes, conducted the planning and analysis necessary to streamline the business processes as appropriate and finalized a technology strategy for processing work within Electric Operations. This study addressed all work processed by Electric Operations including: • Emergency repairs • Maintenance and inspection • New construction and customer connections • System performance/reliability programs
The Phase 0 Assessment Team identified opportunities to streamline processes and effect the changes necessary to establish a best practice work management program. The Phase 0 Assessment Team produced a detailed business case cost estimate, implementation plan and change management strategy for the implementation of process and organization structure changes as well as the deployment of Oracle Primavera P6, Logica ARM Suite and Obvient Focal Point.
Justification: Deploying new work management processes, applications and organization structure will result in standardization of process throughout Electric Operations as well as provide the ability to forecast, plan and schedule work in a more efficient manner. Electronic data capture results in data being entered once and seamlessly updating all systems and reduces back-office administrative tasks.
* Alternatives: Retain current work management processes and continue to utilize current work management systems. Modify current work management systems to provide incremental improvements
* Risk of No Action: Retaining the current work management processes and systems will not facilitate adoption of best practice work management processes nor allow the company to leverage the technical capabilities offered by new solutions. * Financial Benefit The adoption of best practice work management processes and information Explanation: systems will facilitate improved cost tracking, work scheduling, status reporting and productivity analysis. In addition, the consolidated work management system platform will provide: - A single repository for all planned and emergent work within Electric Operations so users no longer need to access multiple systems to process work - An interface that provides detailed information about electric distribution assets that work is being performed against - A comprehensive facility that helps manage all maintenance and inspection programs - A mechanism to match project work requirements and tasks to worker skills and other resources such as vehicles and other equipment - Trending and analysis of workforce and equipment performance
Benefits include additional supervisor time with crews to address safety, quality and efficiency, pre-requisite planning, standardized process and compatible unit redesign for engineering, and elimination of manual back- Exhibit ___ (IIP-13) Page 82 of 82
office administrative functions. * Technical Evaluation and The Phase 0 Assessment Team evaluated the leading utility work Analysis: management solutions including those offered by IBM, Logica, Ventyx and Oracle. The products are used by leading utilities worldwide and leverage the latest software, database and server technologies. These products also include comprehensive asset management capabilities and help to facilitate the adoption of best practice work manage processes. Complex integration with customer service, mapping and outage management systems can also be accomplished through the use of products. The applications selected are Logica ARM Suite, Oracle primavera P6 and Obvient Focal Point. * Project Relationships: The new ERP and Supply Chain applications were assessed during the Integrated Design initiative of the Work Management Project. Logica ARM Suite Work Manager will be fully deployed in June 2011, as a CORS replacement. The new Work & Resource Management department was deployed in September 2011. This organization will utilize the Oracle Primavera P6 application for forecasting and long term planning. Microsoft Excel and Project will be utilized for short term scheduling and planning. Full deployment of the Logica ARM Suite will begin in the 4th Quarter of 2012 and complete in 2013. The Mobile – Field Manager application in the Logica ARM Suite will deploy in the second half of 2013 and complete in 2014.
Current Working Estimate:
Funding: ($000s)
Actual Actual Actual 2009 2010 2011 3,599 22,065 25,417
Total 2012 2013 2014 2015 2016 2017 5 yr Spent & Budget Request Request Request Request Request (13-17) Requested
39,800 49,100 10,000 0 0 0 59,100 149,981
Benefit: ($000s)
Cum Cum Cum Cum Cum 2012 2013 2014 2015 2016 2017 2013 2014 2015 2016 2017 O&M 6.0 6.0 12.0 7.6 19.6 3.9 23.5 0 23.5 0 23.5 Cap 5.5 0.0 5.5 12.5 18.0 3.6 21.6 0 21.6 0 21.6
Total 11.5 6.0 17.5 20.1 37.6 7.5 45.1 0 45.1 0 45.1
* 2007 to 2012 Budget in $105,000 Thousands- * 2013 to 2017 Budget in $59,100 Thousands-
* Authorization- $159,600 * Appropriation-2009-2012 $112,800