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Voltage Regulators –Guardians for Maintaining High Quality Power Distribution

 

Voltage Regulators –Guardians for High Quality Power Distribution  –   In an electric power distribution system, voltage regulators may be installed at a substation (1p/3p) or along distribution lines/feeders (1p) so that all customers receive steady voltage independent of how much power is drawn from the line. The distribution automation portion of the VR market is primarily for automated control of single-phase units installed along MV distribution lines.  In both distribution feeder and substation applications, VRs are often paired with power capacitors.

Currently the single most important factor behind the growth in use of single-phase VRs is the increase in installations of distributed energy resources (DERs) and the impact that these grid-connected resources are having on grid voltage stability.  Because of the variable or intermittent nature of DERs, there is a need to control voltage fluctuations, hence the push to utilize more VRs by utilities that are actively involved with DERs in their service territories. New construction of C&I sites, residential developments in the suburbs as well as feeder length in large rural areas are also key factors affecting the increase in use of VRs.  Certain regulatory actions in place or planned will continue to influence the need for VRs.  See the chart just below for a look at key drivers for using VRs among IOUs, Public Utilities and electric power cooperatives.

Click on chart to enlarge! Keep in mind that the nation’s electric power delivery/distribution system was designed for one-way (or uni-directional) power flow, and with the development of DERs, we are confronted with a need to accommodate two-way (bi-directional) power flows.  This changes the feeder voltage profile making voltage regulation more challenging, with DERs tending to cause local voltage rise along a distribution feeder.  The expansion of variable renewable generation resources owned by industrial/commercial companies will mean growth in the non-utility/C&I portion of the VR market.  VRs will continue to be used to control voltage levels from these intermittent resources.

 Market Size Summary:

Some suppliers have suggested to Newton-Evans that growth of 10-15% per year is on the horizon.  A lot will depend upon continuing economic recovery and the promulgation of DER-friendly policies and regulations being planned over the coming years.  Currently, there are three principal manufacturers of automated voltage regulators serving the domestic U.S. market.  These are General Electric, Eaton Corporation and Siemens.  Together the “Big Three” control about 75-80% of the combined VR market.  Howard Industries is next, followed by Schneider Electric, Delta Star and Basler Electric with each having a few dozen important utility customers and together comprise the remaining 20-25% of the VR equipment manufacturing market.

Market Drivers:

Currently the single most important market driver for using VRs is the increasingly important role of distributed energy resources (DERs) and the impact that these resources are having on grid voltage stability.  Because of the variable nature of DERs, there is a need to control voltage fluctuations, hence the push to utilize more VRs by utilities that are actively involved with DER in their service territories. New construction of C&I sites and residential developments in the suburbs are also key factors affecting the growth in use of VRs.  Feeder length among suburban, exurban and rural areas and some regulatory actions also impact the need for VRs.  Perhaps offsetting some of the demand from DER sites will be a new generation of smart inverters that may be able to provide voltage stability from DER sites to the grid interconnection point, perhaps nullifying the need for a separate VR on-site.  The publication of IEEE 1547-2018 provides for performance criteria for DERs including such functionality as Volt-Var control which can also be used to help regulate the distribution system.

Operational Driver:

While the use of single-phase VRs can be found among many hundreds of IOUs, public utilities and cooperatives, the use of three phase VRs is less widely used among munis and co-ops.  Many of these utilities have switched to using single-phase units where, in the past, they may have used a three-phase unit.  There are also about 10-15% of utilities that do not use VRs, but rely on on-load tap changers (OLTCs) with substation transformers – most within urban corridors with relatively short distribution feeders.  You may want to return here for more articles on grid modernization over the coming weeks and months.

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Distribution Line Sensing: Approaches to Monitoring Distribution Feeders for Power Quality and Improving Reliability Indices

Newton-Evans Research has developed the following info-graphic illustrating what the company believes to be a T&D market segment wherein growth is currently outpacing some other “smart grid” related developments.  This is the distribution line sensing equipment/device (or DLS) market.  For this article I have combined two related sub-segments of the DLS market – distribution fault indicators and line-mounted monitoring devices. With more than a quarter million primary distribution feeders in operation in the U.S. there is a growing requirement to monitor feeder performance, as is now being done on several thousands of the most critical distribution feeders in operation throughout the U.S. and Canada.  Implementations of DLS systems are being undertaken to shore up grid reliability, provide resilience and help minimize outage frequency and outage duration.

Two excellent baseline studies completed by the DOE’s PNNL a few years ago have helped with understanding related power distribution grid trends in the U.S. (1)   These reports, along with periodic DOE grid modernization reports to Congress, have provided the impetus for Newton-Evans to continue researching grid modernization, taking into account some of the ground-breaking activities being undertaken by many of the nearly 3000 U.S. and Canadian distribution utilities. Newton-Evans will soon be conducting the third in a series of short-length, repetitive surveys conducted over multiple years.

    • Distribution Fault Indicators  are devices which indicate the passage of fault current. When properly applied, they can reduce operating costs and reduce service interruptions by identifying the section of  feeder that has failed. At the same time, fault indicators can increase safety and reduce equipment damage by reducing the need for sometimes hazardous fault-chasing procedures.  The bulk of installed basic fault indicators are stand-alone devices that provide visual alerts at fault locations along the feeder.
    • Line Mounted and line post mounted MV/DA monitoring devices perform online monitoring of voltage and/or current and/or loads, but do not provide controlling functions. Power sources may include power lines themselves using CT/PT technology, batteries, or even small solar panels. Modern line monitoring devices are typically part of a tri-partite system comprised of the line-mounted sensors, a communications modem and PC-based (or SCADA-based) analytical software. This allows for local or remote monitoring of the device. Some devices are designed with lighted indicators for onsite/local line problem status notification, as are the DFIs so designed.
    • On average, the typical respondent utility in our first DLS study (a commissioned research program) had about a third of a million customers. Overall, the participants in that study accounted for about a 12% sample of the quarter million (3) MV feeders then in operation across North America. A second study was conducted informally during 2020-2021 with a smaller sample of utilities.
    • Almost all of the survey participant utilities in both Newton-Evans’ studies were using some form of basic line sensor/fault current indicator technology on at least some of their operating feeders. Several utilities were using smart sensors by 2019 and a few were using the then-newest generation of advanced multi-attribute line sensors by 2021.
    • The top attributes being measured or monitored among a large group of listed attributes included fault detection, current monitoring, fault magnitude, voltage measurement and time stamping of events. In the more recent (2020-2021) informal follow-on to the 2019 study, these attributes remained as key benefits of smart and intelligent line sensor program adoption.
    • On the topic of data/status communications for smart or advanced line sensors, a significant percentage of respondents (about one-third across two surveys) reported that their line sensor installed base was using built-in communications with about one quarter of installed devices reporting to line-mounted communications modules – using a mesh networking approach.
    • Distribution line sensors by 2021 were most often reporting to SCADA systems (as indicated by about one half of respondents) while about one in five officials cited communications links to the utility’s outage management system (OMS).
    • Line sensor placement by 2021 was being determined by:
          1. evaluating feeder performance and starting with the instrumentation of weaker performing feeders and “critical” customer feeders.
          2. Analyzing customer density and load characteristics on the feeder. Typically, the higher the customer density coupled with the criticality of the feeder, coupled with larger load-carrying feeders were prime candidates for line monitoring installations.
          3. Locating sensors strategically- near switching points, along with feeders routing power to hospitals, police, fire, military installations, government facilities.
    • Importantly, line sense device/system decision-making criteria to both earlier groups of surveyed utilities centered around four attributes: “reliability and long service life”, “ease of installation”, “battery-free operation” and “price.”  It will be interesting to see how these compare this summer with a 24-month interval between studies.
    • In addition to distribution line sensors and line-mounted monitoring devices, there are ancillary market segments that utilize the same, or similar, sensing and communications technology as found in transmission lines, underground lines and T&D capital assets, including substations and field equipment.

Newton-Evans will be re-surveying participants from the earlier distribution line monitoring studies, as well as including additional utilities in a planned mid-2023 update to these earlier research efforts.  Interested parties can contact Newton-Evans for further information regarding participation as sponsors or as survey participants.

__________________

Sources: 

  1. U.S. Department of Energy, Pacific Northwest National Laboratory, Electric Distribution Systems – Volume 3 (July 2016) and Modern Distribution Grid – Three Volume Study (2017)
  2. “Smaller” utilities involved in the Newton-Evans studies included those having at least 30,000 customers. Note that there are also more than 1,500 North American electric power distribution utilities with each having fewer than 30,000 customers.
  3. As estimated by Newton-Evans, based partly on the PNNL studies cited in footnote 1 above and as accounted for in Newton-Evans own files of counts of primary feeders.
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Estimated Value of Selected OT/IT Systems Shipments and License Fees by U.S. Electric Utilities Now Exceeds $3 billion.

The 2022-2024 edition of the Newton-Evans’ U.S. market overview series covering developments in 12 control and monitoring systems and related IT/OT applications topics is now available for ordering on the company’s website.

The series covers the following topics with individual 2-to-4-page report summaries.  The summaries are based on our studies with utilities and industry discussions held over the past three years.  The market segments covered in this year’s series include energy management systems (EMS), supervisory control and data acquisition (SCADA), geographic information systems (GIS), customer information systems (CIS), outage management systems (OMS), meter data management systems (MDMS), mobile workforce management systems (MWM), advanced distribution management systems and advanced distribution automation (ADMS/ADA), energy market management systems (EMMS), Cyber Security, generation management and distributed control systems (GMS/DCS) and distributed energy resources management systems (DERMS).

The total value of shipments/sales of these 12 systems and application software categories delivered primarily to U.S.-based electric utilities and C&I customers, is now estimated to be more than $3 billion annually.  Some major systems providers are active in a majority of these market segments, with industry segment specialists also key participants.

The C&I segment accounts for about $120-$150 million in procurements of these systems, as developed primarily for electric utilities.1   However, EMMS offerings are primarily oriented to ISO/RTO community, and DERMS solutions are regularly purchased by renewables aggregators, as are specialized SCADA offerings for wind and solar applications.

Some of the segments are oligopolistic, in that only a handful of suppliers are actively serving that particular market.  EMS and EMMS are two such examples.  Other segments are characterized by fragmented market shares held by many suppliers, as evidenced in cyber security, OMS and MDMS market segments.

Individual reports are priced at $195.00 and the entire 12-report series is available for $1,450.00.  Each market overview report includes a segment description, estimated market size, market shares for key participants and a market outlook through 2024.

  1. C&I firms spend additional billions of dollars on vertical industry-developed OT and IT systems such as factory-based SCADA and related automation systems and software.  Distributed control systems with appropriate industry-specific applications and functions is another prime example.  Today’s cyber security investments are also targeted in part to vertical market requirements, as are mobile workforce management systems.  CIS/CRM systems are also widely deployed in several segments within the C&I marketplace.
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Transmission & Distribution World – New Article by Chuck Newton

Grid Modernization from an Energy Policy Perspective in 2019

by Chuck Newton

This article has just been published in the November 21, 2019 online edition of Transmission & Distribution World.  The article is part one of a two-part series on current policy trends, first  presented by Chuck Newton at the Little Rock, Arkansas EMMOS Users Conference in September 2019.  The link to the T&D World article is here:  https://www.tdworld.com/smart-grid/grid-modernization-energy-policy-perspective-2019 .

I hope you find the article informative and helpful in navigating the fairly complex regulatory and policy-making organizations that affect and drive the U.S. electric power industry – affecting utilities, equipment manufacturers, systems and services providers, the engineering consulting community and the many millions of residential, commercial and industrial electric power users.

Kind Regards,

Chuck

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Global Study Finds Continuing Moderate Growth in Protective Relay Market with Commitment to Improving Protection Coordination and Grid Security Practices

In 2016, Newton-Evans Research Company completed a six-month research study and survey of protective relay usage patterns in the world community of electric power utilities. Findings from 114 large and mid-size utilities in 28 countries pointed to some newer trends in adoption and use of protection and control technology.

Among the key findings reported in the 2016 four-volume study were these:

  • There was a receptive market for incorporating advanced technological capabilities.
  • The role of synchrophasors and teleprotection continued to expand; providing better situational awareness and visualization for control system operators.
  • Most new and retrofit relay units being purchased were digital relays, but in some of the protection applications studied, such as motor protection and
  • large generator applications, and in installations where electrical interference is strong, electro-mechanical and older solid state relays continued to have a niche market position.

Continue reading Global Study Finds Continuing Moderate Growth in Protective Relay Market with Commitment to Improving Protection Coordination and Grid Security Practices

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U.S. Investor-Owned Electric Power Utility Automation Market Report

A recently published compilation of survey findings by Newton-Evans Research 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.

Continue reading U.S. Investor-Owned Electric Power Utility Automation Market Report

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Utility Plans Call for Continuation of Moderate-to-Substantial Investment in North American Distribution Grid Automation Projects

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: 2018-2020” the 74-page report includes coverage of more than 30 DA-related issues.

Progress Being Made with Distribution Automation Programs
North American utilities are making progress, by and large, in developing and implementing new DA applications and installing telecommunications network upgrades to accommodate DA device transmissions. The overall DA market among North American utilities is approaching $1.5 billion and is expected to continue to grow in the near-term and mid-term.
Continue reading Utility Plans Call for Continuation of Moderate-to-Substantial Investment in North American Distribution Grid Automation Projects

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Distribution Automation Market Study Shows Increase of Distributed Generation Communications/Controls Among North American Electric Utilities

More interim findings from a Newton-Evans study currently underway, “North American Distribution Automation Market Assessment & Outlook 2018-2020,” suggest a trend of gradual integration of communications and control for the management of distributed generation (DG) and distributed energy resources (DERs) among North American electric Utilities. The growth of DG and DERs raises a number of challenges for electric utilities and asset owners who might need to integrate these new resources into their existing distribution automation systems. Here are a few mid-study observations from the survey responses that have been received so far:
Continue reading Distribution Automation Market Study Shows Increase of Distributed Generation Communications/Controls Among North American Electric Utilities

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New Distribution Automation Tracking Study Finds Utilities Implementing DA Control Logic Either In The SCADA Control Center Or In Field Devices

Initial findings from a current Newton-Evans tracking study indicate that more North American electric utilities developing Distribution Automation applications are implementing control logic for FLISR (fault location, isolation, and service restoration) and Volt-VAR in the SCADA control center. This study follows up on a 2014 survey-based study of DA that gathered responses from 75 electric utilities in the U.S. and Canada. Here are some highlights from the first 30 survey participants so far.
Continue reading New Distribution Automation Tracking Study Finds Utilities Implementing DA Control Logic Either In The SCADA Control Center Or In Field Devices

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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
Continue reading 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

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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

header1-field

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
DA1June1

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
DA2June1

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.

DAsharedApps

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?”

DAcontrols

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.

TDMktplaceMay2014

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 info@newton-evans.com 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.

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Smart Grid and Time Synchronization

Precision timing and time synchronization are topics vital to the future of smart grid operations, especially in electric power substations. In the recently published Newton-Evans, “Assessment and Overview of the World Market for Time Synchronization in Electric Power Substations,” we asked 17 vendors what time references their substation IEDs support. Fourteen out of 17 said that their products support IRIG-B, and 13 indicated NTP (Network Timing Protocol). Precision Timing Protocol (PTP) and Pulse Rates are offered and supported by 9 of these manufacturers while PTP with Power Profile is supported by 7. Just over one-third (35%) reported using direct GPS signals, while nearly one-quarter (23.5%) of the group reported “other” time references were used or offered with their substation equipment.

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The participating manufacturers represent the majority of substation-based intelligent electronic devices (other than protective relays) used in conjunction with substation modernization programs. A number of these respondents also manufacture synchrophasor products including phasor measurement units and phasor data concentrators. Among the other product classes represented are: metering products; communications switches; fault and event recorders; protective relays; automation processing platforms; equipment monitors, and a range of IEC 61850 and DNP 3 supported equipment and devices.

Utility and Consultant Survey Observations
There was strong support for this time synchronization study received from 57 utilities in 24 countries. In addition to the utilities, six leading international engineering consulting firms provided key members of their substation consulting teams to participate in the study. The survey included 14 questions related to substation timing issues and current approaches to synchronize and distribute timing information.

Current Market for Precision Time Clocks
The multi-industry use of precision clocks (masters and slaves) is estimated to be in the range of $200-250 Million as of 2012, with moderate to good growth anticipated by clock manufacturers as well as by utility users. The mid-to-long term market outlook indicates growing interest in adoption of precision timing protocol (PTP) IEEE 1588.

Global sales of time synchronization devices for use in electric power substation (and all other electric power) applications are estimated to be in the range of $35-50 Million for 2012.

This 64 page report, “Assessment and Overview of the World Market for Time Synchronization in Electric Power Substations: A Utility and Industry Survey-Based Report on Precision Timing Requirements” is now available for $975.00 on our reports page. Samples from the report are available.