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Multi-Part Newton-Evans Research Study Reveals Significant Growth Likely for Advanced DMS Systems and Applications

The Newton-Evans Research Company continues to assess its findings from the firm’s comprehensive 2017 study of EMS, SCADA, DMS and OMS usage patterns among utilities from more than 30 countries.

Current status of Advanced DMS (ADMS)
The Newton-Evans’ survey asked respondents to indicate whether their DMS installation provided SCADA, DMS and OMS functionality together in one user interface and this served as our definition of ADMS for this study.

Overall, 69% of international electric utilities who responded to the survey either currently have or plan to have an Advanced DMS that provides SCADA, DMS and OMS together in one user interface. Thirty-five percent currently have ADMS, and 34% plan to implement ADMS in the near future.

This contrasts with only 9% of North American survey respondents who reported having an ADMS as of the first quarter of 2017. Twenty percent of North American respondents indicated they will have an ADMS by the end of 2019, and another 17% indicated plans for implementing an ADMS sometime after 2019. Overall, 46% of the North American sample either currently has or plans to have an ADMS. Some of the North American sample included “transmission-only” utilities/ISOs.

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The Role of ADMS/SCADA in Building a Resilient & Reliable Distribution Grid: Part 1

This is part one of a four part series on ADMS and Distribution Automation. Part one discusses Advanced DA, differences between Distribution SCADA and ADMS, market participants, usage patterns, challenges, priorities, and comments from users.

What utilities have said
Based on a mid-2014 study of the market for Distribution Automation (along with multiple earlier studies), increasing numbers of large utilities have indicated the following:

  • Integrated systems are becoming more desirable
  • Entrenched suppliers of large control systems (EMS primarily) have an “in” but often cannot provide the required component systems for an integrated approach to DMS-OMS-GIS.
  • Many mid-size utilities consider their DSCADA systems (primarily the ACS, OSI and Telvent communities) as suitable platforms for DMS/DA.
  • A high proportion of all respondents do not yet see a need for a separate DMS. This is especially true among the mid-tier utilities.
  • DMS systems can be (and most often are) implemented in a single control center that cuts across state lines in the United States.
  • Typically, operating companies under a large holding corporation operate their own DMS or DSCADA installations.

10 attributes of advanced DA
Here are the 10 attributes of an advanced distribution automation capability based on Intelligrid’s definition:

  1. Real-time Distribution Operation Model and Analysis (DOMA)
  2. Fault Location, Isolation and Service Restoration (FLISR/FDIR)
  3. Voltage/var Control (VVC/VVO)
  4. Distribution Contingency Analysis (DCA)
  5. Multi-level Feeder Reconfiguration (MFR)
  6. Relay Protection Re-coordination (RPRC)
  7. Pre-arming of Remedial Action Schemes (PRAS)
  8. Coordination of Emergency Actions (CEmA)
  9. Coordination of Restorative Actions (CRA)
  10. Intelligent Alarm Processing (IAP)

While ADMS platforms are increasingly used by Tier One utilities, many other utilities continue to rely on their DSCADA system to manage a growing portfolio of ADA functions.

Use of DMS as of Mid-2014 (Participants in Newton-Evans’ Study)

  • Just over 40% of all respondents indicated use of a DMS as of June 2014.
  • IOUs were more likely to indicate having a DMS installation than were respondents from other utility types.
  • All of the surveyed utilities have a DSCADA capability and are likely to be applying SCADA control over basic DA functions such as capacitor bank control and recloser control.

ADMS and DSCADA market participants
The total North American DMS market is made up of ADMS and DSCADA, with some overlapping providers and some different market participants in each category. Among this North America sample of large utilities, GE and ABB/Ventyx led in mentions of current ADMS installations. OSI is also a major supplier of DSCADA and ADMS installations, but their clients tend to be mid-size utilities. All of the mentions for both GE and ABB/Ventyx were made by IOU respondents.

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North American Market for Single Phase Reclosers

During the first quarter of 2015 Newton-Evans Research Company studied the North American market for single phase reclosers. This survey based report addressed questions pertaining to purchasing volume by type (kV rating and insulation type), protection for 1-phase laterals, brands used, types of connections for recloser communications, importance of various recloser features, and other topics.

Newton-Evans found that out of 46 electric utilities who responded to the survey, 72% currently use single phase reclosers on their system and 4% plan to use them in the future. The total number of installed single phase reclosers among the survey sample included about 18,000 units, with the vast majority of those being oil insulated (as opposed to other insulation types like solid dielectric.)

Some key findings from this report suggest the following:
(1) Electric utilities predominantly use fuse protection on single phase taps rather than use a single phase recloser.
(2) While the bulk of survey respondents indicated a greater installed base of oil insulated single phase reclosers, on an average annual basis some utilities indicated they purchase many more solid dielectric reclosers than oil insulated.
(3) Nearly one-half of the respondents said that over 70% of future recloser purchases will be for new units and not for replacements.

Question: Over the next 3 years, please estimate the percentage % of 1-phase reclosers your utility will install on 1-phase laterals vs. feeder main applications.

Only a minority of new purchases of 1-phase reclosers will be installed on single phase laterals, although four utilities plan to use more than one-half of their 15kv purchases to protect single phase laterals. Three utilities plan the same (50%+) for 26kV units, none replied with any indication of any plans to use single phase reclosers of 38kV laterals.

Question: What types of connections are required for recloser communications?
Ethernet ranked as the type of connection required for DA communications, with rs-232, fiber and wireless connections also very important to this group.

Question: How are the 15kV 1-phase laterals on your system protected?
For 15kV laterals, most utilities indicated the vast majority of laterals are protected, but are protected by and large, via the use of fuses. Few 1-phase laterals are protected by reclosers and even fewer by electronic sectionalizers.

Question: What are your preferred protocol for recloser communications?
Clearly, the US utilities are still tightly aligned with DNP 3 as the most critical DA protocol, and the protocol that all manufacturers of DA devices do provide.

For more information about the market for reclosers or other research topics, give us a call: 1 800 222 2856.

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Excerpts from Newton-Evans’ North American Distribution Automation Market Assessment & Outlook: 2015-2017


Below are some excerpts from this recent survey of 75 North American electric transmission & distribution companies.

Where are the controls located for FDIR/FLISR on your distribution system?
As had been observed and reported din earlier Newton-Evans studies of distribution automation, respondents continue to provide a mix of replies to this question. Among the 42% of utility officials indicating some implementation of FDIR/FLISR on their distribution system, many have controls implemented at two or three locations. Among the 31 utilities identified as current FDIR/FLISR user utilities, controls were listed as being located at the control center (58%), in the substation (45%) and in the field (52%).

Location of controls for 31 respondents who have feeder automation and/or FLISR

In the future, where do you anticipate the controls to be located for FDIR/FLISR?
Interestingly, control placement for FDIR/FLISR in the future is anticipated to be primarily in the control center, as cited by 67% of all respondents. Nearly 40% indicated future control location in the field, while 29% cited plans for substation-based controls. Eighteen percent of all respondents indicated no plans (at year-end 2014) for feeder automation.

Importantly, regardless of type or size of responding utility, the majority of participating utilities plan to use the control center based systems to manage field equipment.

Location of controls for 59 respondents who have plans for feeder automation and/or FLISR

Continue reading Excerpts from Newton-Evans’ North American Distribution Automation Market Assessment & Outlook: 2015-2017

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New Utility Insights on Adoption of Advanced Distribution Automation Applications

Findings from the Newton-Evans Research Company study completed in February 2015 indicate that a substantial number of electric utilities are using distribution automation technologies such as FDIR/FLISR and VVC/VVO/CVR, but the number of operating feeders currently configured with these features is still relatively low. These observations are based on a survey of 75 electric T&D utilities in the U.S. and Canada providing electric power service to 32 million customers (approximately 20% of North America’s electricity end users, according to Newton-Evans estimates.)

Percentage of all feeders that have Fault Detection Isolation Restoration (FDIR) or Fault Location Isolation Service Restoration (FLISR) Capabilities
On a summary basis, nearly one-third of the responding utilities (32%) cited their operation of one or more primary distribution feeders configured with FDIR/FLISR capabilities. However, the overall installed base of feeders with FDIR/FLISR capabilities was quite small, standing at about five percent of the total number of feeders operated by these utilities. According to the survey sample, six percent of 13-15kV feeders and seven percent of 22-26kV feeders are configured to provide FDIR/FLISR functionality.


Percentage of feeders that support integrated Volt/VAR control (VVC), Volt Var Optimization (VVO), or Conservation Voltage Reduction (CVR)
Just over half of all respondents reported having at least some feeders supporting Integrated Volt/Var Control, Volt/Var Optimization (VVC/VVO) or Conservation Voltage Reduction (CVR). The 75 respondents indicated an installed base of 34,122 feeders across 4 voltage levels: 4kV (5,094 feeders), 13kV/15kV (22,831 feeders), 22kV/26kV (4,214 feeders), and 33kV/38kV (1,983 feeders). Overall, respondents indicated that 32% of all feeders currently support VVC, VVO or CVR, but out of 4,214 feeders at the 22/24kV level about 59% support these capabilities.


Percentage of utilities integrating VVC, VVO or CVR by year end 2017
Overall, 68% of the utilities replying to this question indicated that at least some feeders will support integrated IVV control/VVO and/or CVR by year-end 2017.

Decision factors for implementing VVC/VVO
Respondents indicated that “cost savings effected by reducing the need for infrastructure enhancements” was the single most-cited driver for volt-Var optimization (VVO) implementation, as reported by 38% of respondents. Additional cost savings brought about by “reducing the need for additional generation” was second in importance, at 33%. About 1 in 5 respondents also cited “regulatory compliance” as a significant driver for implementing VVO.

Other reasons mentioned for implementing include peak shaving to reduce demand costs, reducing losses, and maintaining power factor. A few utilities mentioned that VVO is either not a requirement for them or that they do not want to implement additional technology simply to raise revenue.

To see a table of contents and pricing information for the “North American Distribution Automation Market Assessment and Outlook: 2015-2017” visit our reports page

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Utility Plans Call for Continuation of Substantial Investment in North American Distribution Grid Automation Programs

Findings Corroborate Earlier Newton-Evans Studies Regarding “Mixed” Placement of Controls of Field Devices

The Newton-Evans Research Company today released key findings from its newly published study of electric utility plans for distribution automation. Entitled “North American Distribution Automation Market Assessment and Outlook: 2015-2017” the 89-page report includes coverage of more than 35 DA-related issues.

Progress Being Made with Distribution Automation Programs:
North American utilities are making good progress in developing and implementing new DA applications and telecommunications network upgrades. The overall DA market among North American utilities is approaching one billion dollars and will continue to grow each year for the foreseeable future.

DA Controls Placement:
The placement of DA controls for field devices remains mixed. While some see controls being distributed to field locations, others are placing controls on substation automation platforms, while an even larger group is using control center systems-based approaches (centered on SCADA-DMS systems).

The outlook for controls placement in the future shows that utilities are bringing more controls for fault detection, isolation and service restoration (FDIR/FLISR) and for volt/var control (VVC) into the control center as shown in these charts.

FLISRcontrols VVCcontrols

Automatic Fault Sensing:
Devices providing information such as hot line status and fault indications are becoming a mainstay in many utility DA programs. IOUs and Canadian utilities were more likely to be using automatic fault sensing devices than were their counterparts at electric cooperatives or public power utilities. Usage patterns and plans for AFS devices were strongest among the respondent subgroup of very large utilities (those serving more than 500,000 customers). Of the subgroup using AFS devices, about one-third actively utilize the status of such devices in their DA schemes.

Integration of Communications and Controls for Distributed Generation into DA System Architecture:
By year-end 2014, only about 16% of utilities indicated some use of DA-related communications/controls while another 14% plan to integrate these for DG purposes by year-end 2017. In a related question, well over one third of the respondents indicated that they have a trial deployment to manage distributed energy resources within the DA system either underway or planned.

More than 30 additional topics are covered in the 2015-2017 Newton-Evans DA report. Seventy five major and mid-size utilities were surveyed and interviewed to gather the information for the report. This group provides a substantial sample, accounting for 20% of served customers and 19% of primary feeders across North America.

A supplemental North American DA market outlook synopsis for the years 2015 through 2020 will be released in March. The outlook supplement will provide DA market outlook information based on type, size and regional location of utilities.

Additional information on the North American Distribution Automation Market Assessment and Outlook: 2015-2017 report is available from Newton-Evans Research Company, 10176 Baltimore National Pike, Suite 204, Ellicott City, Maryland 21042. Phone 1-410-465-7316 or write to

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Use of FDIR, Integrated Volt/Var Control, and Sensors on Distribution Feeders

The following information was excerpted from a Newton-Evans survey conducted in September 2010. A total of 47 utility officials from the U.S., Canada, Europe and Asia-Pacific regions responded to the survey participation request. For the majority of U.S.-based respondents, there was a good mix of utility representation by size and by type of utility.

Approximately what percentage of your feeders (existing & new) will include FDIR, Integrated Volt/VAR Control, or Medium Voltage/Low Voltage Sensors?

Importantly, utility responses indicate that the percentages of feeders to include any of the three applications will continue to increase over the 2010-2011 and 2011-2012 periods.

Integrated volt and VAR control was the most likely application to have been implemented to date. However, the budget percentages allocated for FDIR are expected to more than double over the 2010-2012 periods (from 7% to 15%). The already substantial portion allocated for IVVC will likely grow from 19% to 28%.

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Distribution Automation: Communications for Feeder Automation

The following information was excerpted from a Newton-Evans survey conducted in September 2010. A total of 47 utility officials from the U.S., Canada, Europe and Asia-Pacific regions responded to the survey participation request. For the majority of U.S.-based respondents, there was a good mix of utility representation by size and by type of utility.

Do you plan to migrate (or have you already migrated) the existing feeder automation communications network to a newer wireless technology that allows for functionality like higher bandwidth, IP enabled radios and WiMAX?
Fifty-six percent of respondents had no plans to undertake any migration to newer wireless technology approaches. Sixteen percent of survey respondents had already migrated their existing feeder automation communications network to a newer wireless technology, while 30% were planning to do so.

If you are adding wireless technologies for feeder automation communications, which wireless technology are you planning to migrate to?
Three specific technologies were listed on the survey form (WiMAX, LTE and 4G) along with “other.” Forty-one percent cited WiMAX, 18% mentioned 4G and 6% listed LTE. More than three quarters of the group listed other wireless technologies as shown below.

Other Mentions

  • NetCom 900MHz packet radio
  • IP radio system
  • 700mHz Arcadian
  • CDMA 450 Mhz
  • Owned licensed spectrum
  • not sure; investigating
  • RFP stage
  • Low bandwidth/IP enabled IDEN
  • Higher speed 900 mHz supporting IP
  • Under investigation; not decided yet
  • unlicensed spread spectrum
  • Wimax, 802.11 technology, 900 mHz spread spectrum
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Distribution Automation Apps That Will Share Network Space

In 2007, a Newton-Evans survey of electric utilities in North America showed that 65% of the sample planned to have capacitor bank control on the same telecommunications infrastructure as distribution automation. Thirty-eight percent said that Volt/Var optimization, demand management or voltage reduction applications will share the same telecoms as DA, and 13% indicated load balancing will also use the same infrastructure. One quarter of the respondents to this survey cited “other” applications such as AMI, fault location, and station alarms.  We are revisiting this question and obtaining status and plans related to many more DA topics and issues during the fourth quarter of 2014.


In designing a Distribution Automation system, controls and/or logic can be control center based, substation based, or field based. The 2007 Newton-Evans survey asked electric utilities, “Which type of controls are you planning for feeder automation?”


Since completion of the 2007 study, Newton-Evans has conducted several proprietary studies on DA topics, both from a field equipment perspective as well as from a DMS perspective.  Our current study is now being readied for North American-wide utility participation in a comprehensive survey format.    During mid-2014, Newton-Evans also published its series of nine comprehensive DA market segment overviews on key market components including DA/DMS systems, control devices for reclosers and capacitors, voltage regulators, fault current indicators, pole-top RTUs, line mount monitoring devices, DA communications options and DA engineering and consulting services.

For more information on Newton-Evans DA research (including the new study of the North American market for DA, planned for late January 2015 availability) see our reports page and the article below.

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Newton-Evans Research Company plans to revisit the topic of Distribution Automation

DA Brochure Image

Newton-Evans Research Company plans to revisit the topic of Distribution Automation (DA) by researching the market for DA field devices, communications methods, engineering service and Distribution Management Systems (DMS) applications software used in the control center, the substation, and on lines and poles. We will invite hundreds of North American electric transmission & distribution utilities to participate in a survey of Distribution Automation hardware, software and communications infrastructure.

The results of this survey will be combined with Newton-Evans’ discussions with DA vendors and manufacturers and published in a report titled “Distribution Automation 2015-2020: North American Utility Perspectives, Market Outlook and Analysis.” This report – available in January of 2015 – will be a comprehensive market overview of the automation aspects of electric distribution networks and supporting infrastructure. The scope of this research project will also include estimates of growth in the communications infrastructure needed to support this increased deployment of DA hardware and software.

Research Methodology
The study will include several weeks of survey-based research with major and mid-size utilities, requesting their insights regarding DA plans through 2020. This study will also include secondary research to learn about documented plans for DA among North American utilities.

The final report, “Distribution Automation 2015-2020: North American Utility Perspectives, Market Outlook and Analysis” will measure current market sizes, provide estimates and outlooks of demand for distribution automation equipment through 2020, and showcase a selection of major product vendors and service providers in the DA marketplace.

(Download a .pdf brochure here)

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