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Research Findings Point to Upgrade of EMS, SCADA and DMS Capabilities during 2017-2019 among North American Electric Power Utilities to Accommodate Renewables Integration and Demand Response

Emphasis Placed on Extending Applications and Expanding Roles of Distribution Management Systems and Outage Management Systems

Here are some observations based on interviews and surveys with 69 utilities from North America participating in our survey:

Almost one-half of all North America survey respondents (47%) plan to upgrade or retrofit their SCADA installations by 2019. Most respondents with such plans were mid-size and larger cooperatives and public power utilities.

Twenty-six percent of respondents plan to purchase a new or replacement DMS by 2019. Only six (major) utilities reported that they currently have an Advanced DMS, but 24 others will have an ADMS in the near future. Importantly, of the 30 respondents using or planning to use an ADMS, none indicated that their SCADA functionality and network modeling presently include distributed energy resources (DERs). However, most of this sub-group (82%) plans to include DERs in their ADMS functionality in the future.

Real-time network analysis and fault location were the prevalent applications being used as part of current DMS or ADMS installations. Plans are centered on supplementing these (where not yet implemented) and adding network optimization and distributed energy resource management capabilities. (See Fig. 1)

Figure 1. Applications used as a part of DMS/ADMS

Real-time linkages between SCADA and GIS or OMS were found in 44% of the utility sites. Forty-one percent reported having no real-time linkages among these systems.

Almost half of the survey respondents indicated that the operational systems support group is managed by the line of business, while 31% stated that such support is now part of corporate IT. (See Fig. 2)

Figure 2. How is OS Support Managed?

Third party services are being used and relied upon to assist with NERC CIP compliance issues and for the conduct of vulnerability assessments.

DNP3 continues to be the most prevalent operational data communications protocol throughout North American electric power utilities. Plans call for continuing the use of DNP3 for the foreseeable future among most of these utilities. Some planning for IEC 61850 is underway, but remains at a low level among these respondents.

More than a score of additional topics were surveyed in this new study including the impact of NERC CIP compliance on budgets and workloads; cyber security issues; telecommunications strategies and methodologies; distribution network model maintenance; changing organizational responsibilities for control systems; budget outlooks; and applications usage patterns.

Further information on this new series, “The World Market Study of SCADA, Energy Management Systems and Distribution Management Systems in Electric Utilities: 2017-2019” is available from Newton-Evans Research Company, 10176 Baltimore National Pike, Suite 204, Ellicott City, Maryland 21042. Phone: 410-465-7316 Email: or visit us at or to order any of more than 100 related reports. For readers interested in purchasing this new series please call or email the company for special introductory pricing.

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The Year in Summary (2015)

2015 was another busy year for Newton-Evans Research. Some of the studies conducted this past year covered new research topics. While our work was focused on client-commissioned studies, we obtained many insights from operational and engineering perspectives that will assist our research programs in 2016 as we once again conduct our flagship multiclient studies of protection and control, substation modernization, and operational control systems with utilities around the world. For over 30 years Newton-Evans has observed and reported on the fundamental shifts in operational systems and electric power infrastructure technology developments and usage patterns. In 2016, there will be additional changes in usage patterns, plans and outlooks among operational end engineering officials to note, both in North America and internationally.

Continue reading The Year in Summary (2015)

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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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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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Transmission and Distribution Equipment and Systems: Facts and Figures

Newton-Evans Research Company has completed hundreds of studies encompassing most aspects of the U.S. transmission and distribution equipment and related information management, monitoring and control systems markets in the nearly 36 years of its existence.

During the second quarter of 2014, the company will again be publishing more than 85 T&D segment management summaries which provide top-level overviews of most major components of T&D spending. These management summaries provide information on infrastructure topics as well as automation and control systems and engineering services. Definitions, Market size, market shares, recent year shipment estimates and the 2014-2016 outlook is provided in each summary. While some of the information provided in these reports is based on secondary research, much has been developed from meetings and discussions held directly with equipment manufacturers and systems integrators. In some instances, the supporting data is based on larger studies completed by Newton-Evans.

When coupled with the very large “third party services” market and operational communications network investments, T&D-related spending in the United States has grown to more than $25 Billion as of 2013. Importantly, much of these expenditures would occur naturally, without being classified as “smart grid” related. With a mature electrical infrastructure in place for decades, much of the procurement of T&D goods and services today centers on refurbishment and upgrades of existing facilities and field assets, and the smartening up of an older generation of “passive” equipment.

Spending for high voltage equipment itself accounts for more than $5 billion (excluding power transformers). HV substation upgrades, together with circuit breakers and switchgear, make up the bulk of HV-related spending. Gas insulated HV switchgear will likely grow in importance in the U.S. just as it has in countries around the world. Transmission monitoring and control is now being upgraded with the development and deployment of two relatively new technologies, synchrophasors and dynamic line rating systems. HV substation and transmission line/tower construction spending tends to vary each year and ranges from about $2.5 billion to more than $5 billion in recent years.


Shipments of medium voltage (MV) equipment are now approaching $4.5 billion in value. Major MV equipment categories include air-insulated metal-clad switchgear, reclosers and sectionalizers, load interrupters and surge arrestors. When coupled with spending for distribution automation, and a host of related services and control systems, MV-related spending exceeds $10 billion.

Looking at transformers, which can range from extra-large power transformers to medium power units, to a variety of pad-mount and pole-top distribution units, the value of product shipments for this entire category approaches $5 billion to about $6 billion in a “typical” year.

The emerging field of advanced distribution automation includes the monitoring and control systems supporting field instrumentation devices such as pole-top RTUs, faulted circuit indicators and controllers for capacitor banks and reclosers and voltage regulators. Supporting platforms required for processing data acquired from these devices include newer applications hosted locally, at substations or at the control center-based distribution management systems, which often includes modern “distribution SCADA” systems for mid-size utilities.

Operational control systems have been a mainstay of the electric power delivery industry since the early 1970s. Today, modern energy management systems are in operation in virtually every North American transmission utility. Distribution-focused SCADA systems are now installed and operating at nearly 1,900 U.S. utilities. Separate DMS hosting platforms supporting advanced DA activities are becoming prevalent in many of the largest utilities. When coupled with spending for geographic information systems, outage management systems, meter data management systems, mobile workforce management systems, market management systems, cyber-security applications software and supporting services, the annual external spending for supporting operational IT systems of the U.S. electric utility community is now approaching $2.5 billion.

Combining the very large market for systems protection in the form of protective relays, the market for smart/intelligent electronic devices (various types of substation meters, power quality monitors and event recorders) and the market for integration and processing of all of this data, the recent year aggregated market for HV and MV substation automation and modernization has hovered between $1.5 billion and $2 billion.

Realizing that the investor-owned community of electric utilities accounts for around 70% of all customers, industry revenues and spending on T&D, keep in mind that the 1,800 public power utilities and the more than 900 electrical cooperatives represent an attractive, growing (and often leading edge) user base for newer technologies, especially for MV equipment, systems and services.

In addition to the electric utility community, the 710,000 industrial companies and nearly 18 million commercial firms account for about 15% of all T&D equipment and services purchased in this huge $22-$25 billion marketplace.

Unlike many countries around the world, and unlike many other components of the American economy, U.S.-based factories produce more than 90% of all T&D equipment purchased by U.S. utilities. A few years ago this was not the case for large power transformers, but with the opening of several manufacturing facilities in the southern U.S., this has changed for the better, and has resulted in shortened lead times for power transformers. North American-based business operations also develop and provide the vast majority of services, systems and applications software needed for utility operations and implement virtually all control and monitoring systems used here.

In multiple recent studies conducted by Newton-Evans, the nation’s electrical equipment manufacturers have reported that they have the capabilities to produce whatever may be required to advance the development of a more resilient, more reliable power grid. Smaller firms continue to lead in research and development of advanced energy technologies, and the follow-on benefits of the 2009-2012 ARRA programs under the guidance of the U.S. Department of Energy continue to positively impact the development of a 21st century electric grid.

It will take sustained investment over the next 20-30 years, along with ongoing research and development, to realize a fully reliant, resilient and sustainable power grid here and elsewhere. The development of demand response techniques, inclusion of distributed energy resources, deployment of micro—grids, large scale energy storage, cost-effective underground distribution networks where sensible, and the integration of renewables are each poised to play an important role in the future development of a modern American grid. We don’t need to tear down and start over, but we do need to modernize and upgrade the grid components in an iterative and intelligent manner. We need to improve and safeguard what remains as one of the world’s great technical achievements of the past century, the North American electric power grid.

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U.S. Electric Transmission & Distribution Equipment Market Overview

In 2014 Newton-Evans plans to update its U.S. T&D Equipment Market Overview report series to reflect market observations from 2013 and estimates for 2014-2016. This series of 2-3 page “top line” summaries will present the 2013 market shares for major participants in dollars and % of U.S. total. Each report will also present U.S. market segmentation in $MUSD, and a forecast out to 2016. Vendor and IEEE equipment definitions are provided.

Make sure to email and sign up for our newsletter and report availability notifications for this series.

Here is a complete list of reports that will be available for $150 each:

Continue reading U.S. Electric Transmission & Distribution Equipment Market Overview

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Smart Meter Deployments By Usage Segment

Even in mid-2013, American utilities continued to rely on more than 80+ million “dumb” electricity metering devices for data acquisition on electricity consumption. Most of the installed analog metering devices were manufactured in the United States. Smart metering technology is also largely developed and manufactured in the U.S.; at the very least, it is tested in the U.S., and its final assembly is completed here. There are several more suppliers of automated meters than there were of electromechanical meters. Here is Newton-Evans outlook for smart meter deployments in each of three key usage segments.

Smart Meter Deployments Timeline

Smart Meter deployments chart

For more information about U.S. electric utility equipment manufacturing capabilities see our recent report, “American Manufacturing and Systems Integration Capabilities for Power Grid Modernization” on our reports page.

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New Report from Newton-Evans Emphasizes U.S. Know-How and Capacity to Forge a Modern Electric Power Grid

Study entitled “American Manufacturing and Systems Integration Capabilities for Power Grid Modernization” Provides Specific Guidance from Manufacturers and Systems Integration Firms concerning Readiness to Serve

September 25, 2013. Ellicott City, Maryland. Newton-Evans Research believes that American manufacturers can accommodate more rapid growth in U.S. grid modernization efforts than currently exists. Based on repeated surveys of several of the key manufacturing companies active in grid modernization product development and firms involved with grid management and control systems integration activities, there is sufficient manufacturing and integration capacity to meet expected demand levels for almost all core components of the smart grid investment grant program identified by the U.S. Department of Energy as well as additional grid modernization components studied by Newton-Evans Research Company. The latter group includes the intelligent electronic devices required for various automation projects from transmission and distribution level applications down to smart infrastructure equipment.

Regarding the nation’s ability to increase systems integration workloads and capabilities, there is sufficient integration expertise available to expand usage levels of the following: (1) dynamic transmission line rating systems; (2) synchrophasor-related monitoring systems used in the nation’s high-voltage transmission networks; (3) operational control systems deployed for power generation management, transmission and distribution network operations and outage management; (4) information technology with which to intelligently manage deployments of grid modernization components, including telecommunications and analytical tools.

Newton-Evans’ ongoing discussions and formal studies with suppliers, appropriate consultants and utilities have enabled the research firm to develop an independent update and prepare a fresh outlook for each of the DOE-identified smart grid components and a number of additional grid modernization components studied on a repetitive basis by Newton-Evans. Nationwide grid modernization efforts could be largely completed by 2040, including widespread deployment of a variety of scalable energy storage devices sited along the electric power delivery network and at customer premises, according to these observations and insights.

The core technologies identified as smart grid investment grant (SGIG) program components by DOE and discussed anew in this report are as follows: Energy storage, dynamic line rating (DLR), operational control and monitoring systems including SCADA and energy management, distribution management system, Advanced Distribution Automation (ADA) and outage management systems, synchrophasors, advanced metering infrastructure, smart meters, home-area networks and smart electricity loads

In addition, Newton-Evans has included observations from its own related studies of other essential components of grid modernization. These additional grid modernization components include substation modernization programs, protection and control activities, cyber security developments, time synchronization and a variety of grid infrastructure equipment.

Newton-Evans also conducted its fifth tracking study of capital investment in grid modernization during the summer of 2013. This new report includes key excerpts from findings reported in the company’s report Global CAPEX and O&M Expenditure Outlook for Electric Power T&D Investments: 2013-2014.

The 41 page report is priced at $975.00 and is available on our reports page.