U.S. Investor-Owned Utility Automation Market

Report
43 Pages
July 2018
Region: United States
Newton-Evans Research Company
ID: 4746635

“U.S. Investor-Owned Utility Automation Market: Opinions from 30 U.S. Investor-Owned Utilities Collected from Four Survey-Based Reports” is a 43-page compilation of findings from some of the researcher's largest flagship studies.

A recently published compilation of survey findings highlights electric power automation trends among investor-owned utilities (IOUs).

For control systems, IOUs tend to use more OMS analytics, are more likely to have an advanced DMS (or have plans for one), use synchrophasors for wide area monitoring, and want cybersecurity features designed as an integrated part of the control system rather than added on.
For system protection and control, IOUs are capable of budgeting more for protective relay hardware; half of IOUs surveyed budgeted over $2.5 million for the years 2016-2018.
For substation automation, IOUs use more encryption on data sent from the substation to the external host than within the substation; 75% of respondents indicated that no encryption is used for communication within the substation.

There are fewer than 200 IOUs in the U.S. comprising less than six percent of all electric utilities. However, IOUs account for providing electricity to just over two-thirds (102 million) of the 151 million U.S. end-use customers while more than 1,800 public power utilities account for about 15% and 834 electric distribution cooperatives account for another 13% of customers.

1. Introduction2. Overview of U.S. Investor-Owned Utilities3. Power Generation4. Power Transmission5. Power Distribution6. Operational Technology7. Control Systems8. Substation Automation9. Protection and Control10. Distribution Automation

11. EMS/SCADA/DMS/OMS

Which of these systems does your company use? (Check all that apply)
What vendors do you use for the systems you have?
Do you plan to add any new/replacement or upgraded/retrofitted systems by 2019?
What is your planned estimated budget range from 2017 to Year End 2019 for EMS?
What is your planned estimated budget range from 2017 to Year End 2019 for SCADA?
What is your planned estimated budget range from 2017 to Year End 2019 for DMS/ADMS and/or OMS?
Do you have an Advanced DMS (ADMS)? (i.e. does it provide SCADA, DMS, and OMS together in one user interface)
If you have an ADMS, does the SCADA functionality and network modeling include Distributed Energy Resources?
What applications do you use as part of your DMS or ADMS?
Does your utility currently have real-time linkages between SCADA and GIS or OMS?
Is the support group for EMS/SCADA/DMS part of a corporate IT department or managed by the line of business?
Has your utility converged SCADA/DMS and OMS functions?
What types of networks do you use for communication from the substation to the external EMS/SCADA/DMS host/network?
For communication from the substation to the external EMS/SCADA/DMS host/network, do you use an “in-house” network or rely on a commercial carrier network?
Current and planned use of communication protocol(s) within the substation, and from the substation to external EMS/SCADA/DMS host/network.
Reasons for NOT using or planning to use IEC61850
Communications method(s) used for connecting SCADA substations
External assistance or third-party services needed for control center activities
Number of currently installed RTUs, PLCs, substation platforms, etc. on EMS/SCADA/DMS
Number of RTUs, PLCs, substation platforms, etc. on EMS/SCADA/DMS planned for installation from 2017-2019
Use of analytics
Agree or disagree
Open-ended comments regarding the statements/topics in the previous “agree/disagree” question.
For which of the following applications does your utility use synchrophasors?
What are the Operating System preferences for the platforms on your system?
Latest technologies incorporated into EMS/SCADA/DMS platforms
With experienced personnel leaving the workforce due to retirements, how is your utility able to maintain a “Qualified Support Staff” for EMS/SCADA systems?
How are distribution circuit designs captured and transferred?
How are distribution circuit designs updated?
What standard is used to update distribution circuit designs?
What system is master?
How are distribution circuit designs captured and transferred?
When distribution circuit designs are captured and transferred, how are they updated?
When distribution circuit designs are captured and transferred, what standard is used?
When distribution circuit designs are captured and transferred, which system is master?

12. Protective Relays

Number of Protective Relay Systems to be Purchased: 2016-2018
Average % of microprocessor relays among the installed base
Estimated Annual Budget Allocation for Protective Relay Hardware
Estimated Annual Budget Allocation for Protective Relay Hardware
Approaches used for operating WAN remote access to relays
Relay Protocols Used for SCADA
Relay Protocols Used for Substation Automation
Relay Protocols Used for Controlling Actions Issued Externally To or Through the Relay
Relay Protocols Used For Communications-Assisted Protection and/or Automation
Relay Protocols Used for Engineering Access
Ranking of “top three” relay manufacturers from 1-3
11 & 12. Types of Relay Redundancy Schemes CURRENTLY USED for microprocessor-based relaying terminals
Uses of IEC 61850
Use of IEC-61850 Process Bus (Analog values) or Goose Messages (Digital values) among 61850 users
Features of IEC 61850 to be used in new projects
Planned level of implementation of IEC 61850 in substations by YE 2018
Use of PMUs
Where PMUs are used on the system
Time Synchronization Methods CURRENTLY USED for PMUs by location
Time Synchronization Methods PLANNED for PMUs by location
Please indicate your level of agreement with the following statements:
Number of Relays Currently Installed, and Number of Relays >15 Years
Percent of installed relays that have been in service for more than 15 years
Percentage of relays to be replaced in the next 3 years
Use of CT sensors instead of traditional CT to eliminate saturation concerns
Use of VT sensors instead of traditional Voltage Transformers
Ethernet topologies used for redundancy
Management of IT and OT Ethernet Networks separately
If so, what department in your organization is responsible for the design, performance, and maintenance of your OT networks?
Who in your organization monitors, diagnoses, and troubleshoots OT Ethernet networks to verify their real-time performance and identify and correct communications systems misoperations?
Who in your organization detects, alerts, reports, and records communications systems misoperations?
The demarcation between physical IT and OT networks
For reliability & availability of Ethernet OT networks, which methods do you use to avoid a single point of failure?
Maximum signaling times

13. Substation Automation

“potential obstacles” to implementing substation automation and integration “1 = don’t stand in our way” to “5 = formidable obstacle.”
External spending estimates for new and retrofit substation automation and integration programs between 2017 and 2020 - NEW SUBSTATIONS
External spending estimates for new and retrofit substation automation and integration programs between 2017 and 2020 - RETROFITTED SUBSTATIONS
Number of substations in operation, to be retrofitted, planned to be built, and levels of automation
Percent of substations in operation, to be retrofitted, and planned to be built by their levels of automation
Are you currently using or planning to implement control logic in your RTUs?
If you are either currently using or planning to use control logic in RTUs, how is it used?
Are you planning to replace your legacy hardwired I/O?
If you are planning to replace your hardwired I/O, what will you replace it with?
Reasons for replacing legacy hardwired I/O
Need for Analog Outputs
Substation Protocols in use and planned for use by year end 2020
Encryption of substation communication data
What are your alternate methods of communication with the remote site in the event of loss of the routine communications pathways?
Substation Ethernet LAN architectures in use and planned for use by YE 2020
Routable paths to end devices in 2017
Communication architectures used within substation and for communicating to the substation
Types of communications links used
How primary information processing tasks “inside the fence” are handled
Do you have (or plan to have) a Vendor Security Certification Program?
If you currently have/plan to have a Vendor Security Certification Program, what does it involve?
Applications for substation-based computing platforms
External assistance needed for substation automation and integration related activities
Please indicate your utility’s preferred vendors for each equipment type.

14. Distribution Automation

Total number of distribution feeders reported by utilities answering the survey
Average Percent of feeders with SCADA controlled sectionalizing switches that are manual only, semi-automatic (upstream restoration is automatic and downstream restoration is manual), fully automatic (upstream and downstream restoration are both automatic)
Approximately what percentage of all your feeders have Fault Detection Isolation Restoration (FDIR)/Fault Location Isolation Service Restoration (FLISR)? (Average)
Average percent of feeders equipped with VVC, VVO or CVR
What is driving your decision for VVO? Check all that apply.
Where are the controls located for FDIR/FLISR on your distribution system?
In the future, where do you anticipate the logic to be located for FDIR/FLISR?
Where are the controls located for Volt/Var control on your distribution system?
In the future, where do you anticipate the logic to be located for Volt/Var control ?
Does your utility use automatic fault sensing devices (hot line status, fault indicators) in your feeder design?
If you do use automatic fault sensing, do you utilize the status of the communicating automatic fault sensing devices in your distribution automation applications?
Have you integrated any communication/controls for distributed generation into your DA system architecture?
Are you considering a trial deployment to manage distributed energy resources (e.g. inverters, energy storage, EV chargers, etc.) within the DA system?
Does your utility integrate sensing and/or Volt/Var control at the LV side of the distribution transformer within the DA system?
Does your utility plan to use sensing and/or Volt/Var control at the LV side of the distribution transformer to support any of the following applications?
What other DA do applications use the same telecommunications infrastructure being used by feeder automation? (check all that apply)
How are you notified of a feeder main fault event?
Does your utility run distributed software applications (like S&C Intelliteam II, L+G Grid Stream; SCADA center product suite, Cooper/Yukon Feeder Automation, G&W/Survalent Lazer Automation)
Do you use a centralized (control center based) tool for communication network management and security management?
Please check any of the following functions you would like to have integrated into a communications/security management tool for MV Feeder Device management (like recloser controller, capacitor bank controllers, remote controlled switch)
Do you currently use (or plan to use) encryption on your communications network for distribution automation?
Do you plan to upgrade the existing Feeder Automation network to a newer, wireless technology that allows for features like higher bandwidth, IP enabled radios (i.e. 4G, LTE or WIMAX) by the end of 2020?
If you plan on upgrading your Feeder Automaton network, which wireless technology do you plan to use?
Three-year total budget for DA projects from 2018-2020 as indicated by the survey sample
Average % of DA budget
Allocation of DA expenditures by category
Do you currently use (or plan to use) bi-directional regulators on your system?
Do you currently use/plan to use bi-directional reclosers on your system?
Do you currently use (or plan to use) dynamic protection (real time modification of protection settings) on your system?

15. List of IOUs Surveyed

Samples

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Companies Mentioned

ABB
ACS
American Transmission Company
Areva
Avista Utilities
Baltimore Gas and Electric
Central Hudson Gas and Electric
CGI
Commonwealth Edison Company
Consumers Energy
DTE Electric
Duke Energy Florida
Duke Energy Indiana
Duke Energy Progress
Empire District - Liberty Utilities Central
Eversource Energy
FirstEnergy
GE
Georgia Power
In house
Indianapolis Power and Light
Intergraph
ISO New England
ITC Midwest
Monarch
National Grid
Oracle
Orange and Rockland Utilities
OSI
Otter Tail Power Company
Pacific Gas and Electric Co.
PacifiCorp
Portland General Electric
PSE&G
San Diego Gas & Electric
Schneider
Siemens
Southern California Edison
The Empire District Electric Company
The United Illuminating Company
Unitil
Xcel Energy

Table of Contents

Samples

Companies Mentioned

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