Category: Grid Modernization

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Substation Automation and Integration Services – Guiding the Way to the Digital Substation

Substation Automation Integration Specialists are firms (or business units of large electrical equipment manufacturers) that can assist with or develop and provide a full or partially automated electric power substation on a turnkey basis, leading to “digital substations.” These companies help utilities and C&I firms toward digital substations.  Such firms include dedicated businesses (see examples below) or can be business units of larger companies engaged in the electric power automation business as EMS/SCADA suppliers, RTU/PLC/PAC/gateway manufacturers or protection and control specialists.  As well, T&D engineering firms, from the nation’s TOP 10 in size and reach, to dozens of smaller but capable regional service businesses are involved in helping utilities and C&I firms integrate and automate (or digitize) the nation’s nearly 70,000 utility T&D substations and another several thousand substations that are managed and operated directly by C&I firms, including large renewables installations.

 

Four “tiers” of substation integration providers are included in our assessment:

  • Specialist substation automation integration service revenues in 2022.es
  • SCADA industry participants with substation devices (RTUs, FEPs, Relays, IEDs, platforms) offering substation integration expertise
  • National T&D Engineering Services firms with substation integration expertise
  • Regional T&D Engineering Service firms

Together, these automation and integration services providers accounted for nearly $400 million of substation automation and integrations services-related revenue in 2022 (Newton-Evans estimate).  Click on chart to expand view.

Turnkey costs for substation integration services range from an estimated $45-55,000 for a small distribution substation having few feeders to upwards of $250,000 for a large transmission substation. Some metro-area MV substations with 20 or more feeders can cost upwards of $300,000 to automate and provide device integration services.

The automation equipment/device costs are in the range of $50,000-250,000 for a distribution substation and can range up to $500,000 for smart equipment and integration services in EHV transmission substations.

These totals shown in the chart below for automation and integration services are but a portion of the total expenditures allocated to electric power substations.  New substation construction (greenfield) and up-rating activities (brownfield) account for a few billion dollars, while substation equipment and communications costs also account for several billion additional dollars.

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Wind Turbine Controls Usage Patterns Study Underway

During April and early May, Newton-Evans Research is conducting studies on the American wind power market.  Of specific interest is the  wind turbine controls segment of the fast-growing renewables business.

We are researching the types and brands of control devices and control systems that are in use among the more than 72,000 wind turbines installed in the United States as of January 2023.¹

Importantly, most controls within the wind turbine itself are provided by the OEM – the wind turbine manufacturer.  In the U.S., that likely means one of six manufacturers that account for 90% of all utility-scale wind turbine installations as of January 2023.  Three of the six (GE, Vestas, Siemens Gamesa) accounted for a whopping 82% of wind turbine installations.  Three others (Mitsubishi, Nordex and Suzlon) account for nearly 6,000 operational wind turbines operating throughout the country.  In addition to the major OEMs, there are more than 10 other manufacturers having at least 50 or more operational U.S. wind turbine installations.  See Figure 1. (Click on the figure to expand the view).

When it comes to wind turbine controls, multi-site wind farm operators and owners have more say in determining control devices and control systems selections as needed, especially for controls that reside external to the wind turbine.   Larger wind farms configured with wind turbines from multiple manufacturers also tend to have more interest in procuring PLCs, SCADA systems and plant-wide and multi-plant control and monitoring systems.  Wind farm operators and owners also tend to make more of the turbine control selections when it comes to retrofitting wind turbines.

There are more than a dozen wind controls specialist firms actively marketing and installing pitch and yaw controls, and/or condition monitoring systems in the United States.  Many wind turbine control specialists active in the U.S. are headquartered in European countries having extensive wind power installations and decades of wind power experience, led by firms based in Denmark, with others in Spain, Germany, Austria and Italy.  Some companies provide their own fine-tuned PLCs and wind-specific SCADA systems (you can read our 2021 article on renewables SCADA here): https://www.newton-evans.com/scada-systems-for-the-renewables-energy-industry-and-adms-for-utilities/.

We are still seeking a few additional participants to two short surveys.  One survey is geared to wind farm operators/owners, and can be answered by experienced wind turbine technicians.  The second survey addresses the OEM and wind turbine controls supplier community.  If you qualify to participate, please contact Chuck Newton (cnewton@newton-evans.com) and a link to the appropriate survey will be forwarded. 

Note:  1. Wind turbine installation data is provided by the U.S. Geological Service:  https://eerscmap.usgs.gov/uswtdb/

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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.

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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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U.S. Substation Automation and Integration Market Expenditures Valued at $2.5 Billion in 2021

When the estimated sales of 14 product/service topics covered in the newly released 2022-2024 edition of U.S. Substation Automation Market Overview Series are totaled, the estimated value of these product/services purchased by American utilities and industrial substation sites reached $2.493 Billion in 2021. Equipment types reported in the series include RTUs, PLCs, protective relays, multifunction meters and recorders (digital fault recorders, sequence of events recorders, power quality recorders) reclosers, inter-utility revenue meters, automation platforms, time synchronization clocks, voltage regulators, communications equipment and integration services.

The total of spending on substation automation-related equipment and smart devices, along with substation integration services is on the rebound from COVID-era induced spending cutbacks. Newton-Evans Research expects investments in substation modernization to continue to grow over the next 24-36 months at a moderate rate of growth. As new substations come onto the grid to support renewable energy sites, these will be highly automated.

While automation budgets will remain a substantial portion of all substation-related budgets, additional investment is necessary to shore up grid resiliency and cyber and physical security defenses at the substation level and so these expenditures will share in the overall investment plans. The need for substation physical expansions and upratings will also continue to cause substations investments to rise.

Newton-Evans Research also finds that there are three distinct tiers of substation integration service providers. These include substation automation specialist firms, SCADA industry participants having substation devices and which also provide integration services and T&D engineering service firms having substation integration expertise.

Individual substation market overview reports are priced at $195.00 and the entire 14-report series is available for $1,150.00. Each market overview report includes a segment description, estimated market size, market shares for key participants and the U.S. market outlook through 2024.

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Outlook for Grid Modernization from IT and OT Perspectives: Recovering the Momentum Lost During COVID

Over the past two years, the pandemic has affected our lives, our businesses and the nation’s plans for infrastructure modernization, including the electric power grid. We had earlier (2020) forecasted rather robust growth in spending on IT, OT and smart grid initiatives in a grid modernization report prepared for a client organization.

During the first year of the pandemic, Newton-Evans conducted a small sample study (25 large and mid-size utilities) of the impact of COVID on electric power transmission and distribution capital investment projects.

Observations from that 2020 study indicated capital investment plans for some utilities had been scaled back by as much as 50% for 2020 and 2021. Other respondents reported that capital projects had been deferred for 12, 24 or even 36 months. A few utilities held fast to their pre-pandemic investment plans as long as they could do so.

In Figure 1, note our belief that total 2021 expenditures for the combination of IT, OT and smart grid projects likely reached about $14.2 Billion. In 2020, Newton-Evans had estimated that 2021 would likely see about $16.1 Billion in these combined expenditures, but by that year, the pandemic had firmly taken hold, restricting the availability of utility workforce personnel. COVID also impacted the manufacturing of some electrical equipment and provision of consulting and engineering services related to IT, OT and grid modernization projects.


Figure 1.
NOTE: Total IT + OT + SG Expenditures = $14.25 Billion
($5.55 Billion for IT + $5.30 Billion for OT + $3.4 Billion for “pure” Smart Grid)
$14.25 B = about 4.75% of electric utility operating revenue or 3.6% of total electricity sales.
IT spending alone likely less than 2% of operating revenue.

Now, the question arises – What is included in “pure” smart grid investment? Here, we include smart grid devices and equipment that acquire and transmit data and other signals to monitor and/or control utility field operations outside of the substation fence. For the most part, these are 21st century developments or generational improvements over earlier “legacy” devices. Pole top RTUs, distribution line fault indicators and feeder monitors, multiple types of controllers (for capacitor banks, automatic circuit reclosers, voltage regulators, line mounted monitoring devices et al) and automated switches and protective devices).

The related advanced communications infrastructure including built-out portions of the utility wide-area networks, local area networks and supporting infrastructure for automatic metering equipment are also placed in the “pure” smart grid bucket. IT system components related to smart grid are typified by meter data management systems, the customer services links to outage management systems, and geographic information systems to name a few. Operations side systems and applications would include advanced distribution management systems which collect and aggregate the thousands of field data points now configured with intelligent electronic field devices mentioned earlier that assist in more effective operation of the distribution grid.

By the third quarter of 2021, some recovery in capital spending for transmission and distribution was underway, based on recent discussions with a variety of industry sources. Even now, in the first quarter of 2022, we are still in a cautionary progression, given the lingering concerns over, and the effects of the OMICRON variant on the utility labor force and on delays in equipment availability in some situations. By 2023, I anticipate combined investment in IT, OT and grid modernization projects as shown in Figure 3 below will increase to more than $16.6 Billion. When compared with a pre-pandemic outlook calling for about $19.2 Billion in such investment in the coming year this leaves a shortfall of $2.6 Billion.

Importantly, when utilities have been compared with other industries related to IT spending, at first glance the industry appears to invest relatively less of its revenues in IT and OT. However, we have found that even in this pandemic area, with total U.S. electric power revenues approaching $400 Billion, the investment in combined IT and OT, plus related portions of grid modernization technology projects (exclusive of the cost of grid modernization equipment), the level of capital spending for grid modernization is closer to the 3.6% – 4.0% investment level. IT spending alone hovers around 1.5%-1.9% of operating revenues. Adding in the industry’s investment in OT and in key technology aspects of smart grid projects, the relative investment in overall information technology in total climbs to a much more reasonable level. See Figure 2.


Figure 2.
Two key assumptions about this outlook:
1. COVID will be endemic, not pandemic, by 3Q 2022.
2. Infrastructure Investment and Jobs Act actually begins funding significant portions of the $72.3 Billion allocated for energy and electric power infrastructure renewal by mid-year 2022.

The impact of COVID on electric power industry investment during 2020 and 2021 and into 2022 has taken its toll. The question facing the industry and the nation is whether or not this estimated $16.5 Billion shortfall in grid modernization investment (as postponed or deferred from initial estimates) can be made up during the remaining years of this decade? My belief is that the investment gap will be narrowing over the next 36 months, as shown in Figure 3 below, and the pre- and post-pandemic trendlines will indeed converge in the latter years of the 2020’s. Closing the investment gap will especially be likely – and may occur earlier than anticipated with help from DOE funding. Much will depend on federal funds flows from the recently enacted Infrastructure Investment and Jobs Act – legislation that will enable additional billions of dollars to be provided for grid modernization programs and related energy projects. At least several billion dollars of the $72 billion or so earmarked for electric power modernization will be applied to IT, OT and “pure” smart grid projects, although the majority of the total budget is earmarked for transmission grid expansion, overall grid hardening and integration of renewable energy sources.

I believe that this forthcoming federal investment in the nation’s electric power grid – coupled with the investments of the nation’s utilities, must include funding for research and development of advanced technical solutions for ever higher levels of cybersecurity and grid resilience.

As of February 2022, the nation’s electric utilities are re-starting or initiating a number of grid modernization projects and programs, deferred in part over the past 24 months.  This activity will help boost IT, OT and smart grid device/equipment expenditures this year and into 2023. Figure 4 illustrates the near-term growth estimate we have made for the IT, OT and smart grid field components of capital investment as the effects of the COVID pandemic begin to wane in the first quarter of 2022.

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Sizing the Market for Electric Power Grid Modernization In an Era of Pandemic

According to the U.S. Department of Energy’s Energy Information Administration, annual spending on electricity distribution systems by major U.S. utilities continued to increase year-over-year through 2019, with major utilities spending some $57.4 billion on electric distribution in that last pre-pandemic year. More than half of utility distribution spending in 2019 went toward capital investment ($31.4 billion) as utilities worked to replace, upgrade, and extend existing infrastructure. Another $14.6 billion was invested in operations and maintenance (O&M), and $11.5 billion was appropriated for customer expenses, which included advertising, billing, and customer service.

In 2019, much of the $31.4 billion distribution system capital investment (40%) was spent on power lines, both underground (23% of investment) and overhead (17% of investment). Distribution lines are added or expanded to accommodate new neighborhood development or higher electricity flows as sales increase.1
Keep in mind that when spending by municipal electric utilities and electric cooperatives are added to the EIA totals, the amounts reported by EIA actually would increase by about 25-30%, at least in our estimation.  The bulk of this additional non-IOU spending was for distribution expenditures.

We have increased these amounts for 2020 and 2021, if only to account for inflationary pressures on prices of electrical equipment and systems. Thus, our view is that, in 2021, about $60 Billion was spent in total, on electric power distribution activities in the United States. Of this amount, $33 Billion was estimated for capital investment, and about $20 Billion of the total went for distribution equipment and systems.


Fig. 1

Newton-Evans’ recent year studies of U.S. combined utility and industrial/commercial spending for dozens of specific T&D products, equipment types and systems suggest about $22 Billion was invested in about 70 specific T&D equipment types in 2021.2 Note that this estimate includes spending for both transmission and distribution. In fact, the total expenditures for T&D procurements likely exceeded 100 billion dollars. See Figure 2.


Fig. 2

This $22 Billion shown in the above chart excludes additional billions of dollars invested in power lines, underground cables, electric power poles, meters and ancillary equipment as well as customer-related spending, certain substation construction and O&M services.

One recent Newton-Evans’ study of capital investment changes brought on by the COVID pandemic, resulted in an expected drop in CAPEX from 2019 to 2020, followed by stabilization and a moderate increase in spending for some areas in 2021. Some respondents cited this as a “deferral” of investments rather than a cancellation of investments at the time of the study.3 Nonetheless, total capital investment by U.S. electric utilities during the 2020 and 2021 years likely centered around the $130 Billion mark.4

If the nation (and the entire world) can move on from the ongoing pandemic era, to an endemic period, grid modernization investment may recover some of the momentum lost or deferred from the past 24 months. As well, the significance of the passage of the Infrastructure Investment and Jobs Act in November, 2021, cannot be overstated. More than $60 Billion dollars of funding under this new act has been allocated to the energy sector, most of that amount earmarked for modernization of the electric grid.

Sources:
1. U.S. Department of Energy, Energy Information Administration
2. Newton-Evans’ Market Overview Series on various T&D Topics
3. Newton-Evans Research Study of Capital Investment among U.S. Utilities in Midst of Pandemic Conditions (1-2 Quarters, 2020)
4. Newton-Evans Calculations of 1.28 x EEI/EIA estimate of $107 B. Newton-Evans’ estimate very similar to estimate prepared by Statista, which itself was sourced in part from S&P Global Market data.

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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