Utility Pros Worry About Staffing Levels, Consider Outsourcing, BRIDGE Study Finds

Nearly half of utility industry professionals are already doing it or would consider outsourcing operational technology functions, while 45 percent think that a limited supply of experienced staff and retirements are the top challenges for the sector, according to BRIDGE Energy Group’s latest comprehensive survey.

The BRIDGE Index Utility Industry Survey for grid operations received responses from more than 20,000 employees. Seventy percent were in the transmission and distribution (T&D) sectors while 54 percent overall were managers or department heads and 15 percent were executives.

Lack of institutional knowledge seemed a primary concern, with 24 percent putting the limited supply of experience at the top of the challenges list. Twenty-one percent indicated that staff retirements worried them most, and 14 percent pinpointed the lack of project staffing requirements vs. clarity of staff availability.

“The ability to staff real-time systems experts continues to be an impediment to both the delivery of new OT (operations technology) projects and meeting the demands of day-to-day systems operation,” BRIDGE wrote in its summary. “OT resource planning and risk management at a portfolio level is required to effectively prioritize and optimize what is typically a constrained set of key resources.”

The concerns over staffing levels likely fueled a 71-percent leap in plans for outsourcing OT tasks, the survey found. About 48 percent are now outsourcing OT or would consider it, compared to only 28 percent in 2012.

“Once considered taboo, utilities are now considering how to leverage outsourcing as part of the future strategy of utility operations,” BRIDGE noted.

Utility communications networks were picked by 61 percent of respondents as a top project in their near-term plans, slightly above distribution automation and customer service portals at 60 and 56 percent, respectively.

About 60 percent of utilities represented are using advanced technology to detect blue sky outages, with SCADA still the primary source of outage information. Forty-one percent of utilities that have more than half of their meters upgraded are using AMI as the primary source for understanding those outages, according to the survey.

Overall, sourcing for outage information looks like this: 1) SCADA, at 47 percent; 2) the customer, 37 percent; 3) smart meters, 11 percent.

“Data shows that North American utilities seem satisfied with current outage and restoration solutions,” BRIDGE wrote. “Those that aren’t should look to increase overall benefit of smart meters through improved meter to grid integration.”

The survey respondents work for utilities throughout North America. Half of those are investor-owned utilities, while municipal and cooperatives are represented at 25 and 21 percent, respectively.

Consumers Energy Completing AMI Sweep of Michigan This Year

From Mackinaw City to Monroe, Consumers Energy will have installed 1.8 million new meters across Michigan by the end of 2017, the company reported. The completion of the five-year statewide advanced metering infrastructure (AMI) project will allow electric customers to track their energy usage more closely online and identify ways to save energy and money.

“We’ve already installed more than 1.3 million electric meters and 350,000 gas communication modules, allowing our customers to use new programs and services,” said Garrick Rochow, Consumers Energy’s senior vice president of distribution and customer operations. “These upgraded meters provide a clear customer benefit, giving homes and businesses a powerful tool to better manage their energy usage.”

The new meters offer customers the ability to choose their billing date, sign up and receive automated alerts when their energy use is trending higher than usual, and review their energy use by hour, day or month to identify ways to save energy and money on their energy bill.

“By the end of the year, these customers will be able to access their energy use information and sign up to take advantage of money-saving programs,” Rochow said.

Consumers Energy began installing electric meters in 2012 in the Grand Rapids area. In 2015, the energy provider started adding communication modules on natural gas meters of customers who also receive electric service. Those combination customers can access both their hourly energy use and their daily natural gas use through the Smart Energy web portal.

Consumers Energy, Michigan’s largest utility, is the principal unit of CMS Energy, providing natural gas and electricity to 6.7 million of the state’s 10 million residents in all 68 Lower Peninsula counties.

Georgia Power, SRP top Record Results in J.D. Power Business Utility Study

By Rod Walton, Senior Editor

Satisfaction ratings by business customers for their utilities improved to a record high in the latest J.D. Power study released in mid-January.

Overall approval from electric utility business customers rose for the fourth straight year to an average of 755 points, a 51-point increase over last year. The highest year-over-year increases in categories included price satisfaction at more than 60 points and more than 50 points each in communications and customer service.

“Utilities are really beginning to understand the importance of engagement with their business customers, which is reflected in increased communication,” said John Hazen, director in the utility & infrastructure practice at J.D. Power.

Georgia Power ranked first overall and in the large south utility index with 807 points. Winners repeating from last year included Consolidated Edison, east large; Met-Ed, east midsize; Ameren Missouri, midwest large; and Salt River Project (SRP), west large.

SRP, which serves Phoenix and other areas in Arizona, topped the large east electric utilities for the fourth straight year. Georgia Power has ranked first in the south large four of the last five years.

“It’s remarkable how utilities have improved as an industry in understanding the importance of being customer-focused,” Hazen said. “In doing so, they hope to not only improve their financial performance, but also to be viewed more favorably by regulators. Furthermore, business customers are also more supportive of the investment plans utilities have in such projects as updating or developing their infrastructure.”

Other winners include Louisville Gas & Electric, midwest midsize; Gulf Power, south midsize; and Seattle City Light among the west midsize electric utilities. SRP was second highest in overall rating at 797 points, while Gulf Power scored 793 points.

The study, now in its 18th year, measures satisfaction among business customers of 87 targeted U.S. electric utilities, each of which serves more than 40,000 business customers. In aggregate, these utilities provide electricity to more than 11 million customers.

J.D. Power’s study revealed that in the past six months business customers have experienced an average of 1.9 brief power interruptions (five minutes or less) and 1.2 outages of longer than five minutes. Those figures were virtually unchanged from last year’s report, but the average duration of the longest outages increased nearly two minutes to 13.7 minutes.

Another key finding was that more than half of business customers have signed up for outage alerts and 66 percent are receiving monthly outage alerts.

Corporate citizen efforts play a growing role in how customers view their utilities. For example, 70 percent of business customers say their electric utility provider supports economic development of the local community; 30 percent have seen utility employees volunteering or working in their community; and 43 percent are aware of their utility provider’s efforts to improve its effect on the environment.

Midwest Transmission Project Energized by Transource

The 180-mile Midwest Transmission Project was energized late last year. The new transmission line was built in Missouri by Transource Mission LLC. Transource Missouri LLC is a subsidiary of Transource Energy, a competitive electric transmission joint venture formed in 2012 by American Electric Power (AEP) and Great Plains Energy Inc.

The 345-kV Midwest Transmission Project connects Kansas City Power & Light Co.’s (KCP&L) Sibley Substation located near Sibley, Missouri, with a new transmission substation (Mullin Creek Substation) located south of Maryville, Missouri. It then extends to an Omaha Public Power District (OPPD) substation located near Nebraska City, Nebraska. Transource Missouri built and owns approximately 135 miles of the project in Missouri and the new Mullin Creek Substation. Transource Missouri’s portion of the project cost was approximately $250 million.

OPPD built and owns approximately 45 miles of the project in Nebraska.

“This project clearly demonstrates that the combined transmission experience and expertise of AEP and Great Plains Energy allows Transource to develop transmission solutions that successfully balance system requirements, project constructability and costs,” Antonio Smyth, Transouce Energy president, said in a statement. The project will “reduce grid congestion, increase system reliability” and enable large-scale renewable energy.

Transource Missouri built an additional, separate 31-mile, 345-kV transmission project to enhance reliability and relieve grid congestion in northwest Missouri from KCP&L’s Iatan Substation to the Nashua Substation near Smithville. That project was energized in April 2015.

The Midwest Transmission Project is one of several “Priority” projects determined by the Southwest Power Pool’s board of directors and members committee in April of 2010.

PECO Completes $32M Substation

PECO recently completed construction of a new $32 million electric distribution substation to support increased demand and future growth in Marcus Hook, Delaware County, Pennsylvania.

The project, which began in August 2015, incorporated the latest innovations in smart substation technology to provide customers with enhanced electric service reliability.

This includes the installation of fiber-optic current transformers and diagnostic systems that process real-time analysis of transformers, circuit breakers and battery systems. In addition, thermal imaging is used to identify potential issues before they occur by recording temperature variations within a piece of equipment while in operation.

“This project is another significant investment designed to enhance our electric system to meet the needs of our customers,” said Dave Weaver, vice president of technical services. “In addition, we will be able to leverage new, innovative solutions and advanced analytics to anticipate maintenance issues to avoid customer outages.”

The Philadelphia-based utility reported that it invests more than $500 million annually to enhance its system infrastructure through preventive maintenance and equipment. Through PECO’s System 2020 plan, the company is investing an additional $275 million over five years to install advanced equipment and reinforce the local electric system, making it more weather resistant and less vulnerable to storm damage.

PECO provides electric power and natural gas to about 2 million customers in Pennsylvania. It is owned by Exelon.

Siemens, OMNETRIC, CPS and UTSA Partner on Military Microgrid

OMNETRIC Group and Siemens deployed the final part of the U.S. Department of Energy’s (DOE’s) National Renewable Energy Laboratory’s (NREL) Project INTEGRATE (Integrated Network Testbed for Energy Grid Research and Technology Experimentation)-an initiative aimed at resolving the current constraints utilities face when integrating distributed general assets, including renewable energy sources, into the grid.

Working with OMNETRIC Group and Siemens, CPS Energy installed a microgrid solution at the Joint Base San Antonio’s Fort Sam Houston military post consisting of a 20-kW solar PV array, 48-kWh battery, a weather station and a microgrid controller.

Demonstration tests at CPS Energy showed improved control of the new microgrid under live conditions, which enables renewable resources to be integrated more predictably. The demonstration will help advance the integration of renewables and development of microgrid systems on a larger scale.

“We are eager to utilize technology to modernize the electric grid for the benefit of our customers. The seamless integration of distribution assets is another step toward our ability to offer the next generation of reliability, resiliency and product choice to our customers,” said James Boston III, manager of market intelligence at CPS Energy.

As part of the solution, OMNETRIC Group has verified and implemented a new interoperability reference architecture called the open field message bus (OpenFMB) framework. This solution, integrated with Siemens microgrid management software (MGMS), allows CPS Energy to overcome the lack of standardization and interoperability between equipment to better manage load behavior on the power grid.

The project partners also include the University of Texas at San Antonio (UTSA), which has integrated the university’s solar PV and load forecasting technology with the microgrid management system. Using its own sky imager technology, UTSA can study cloud movement in real-time (speed and direction of travel). This information, updated every 15 minutes, is fed into the Siemens and OMNETRIC Group solution for it to predict power generation in near real-time from the microgrid.

“Siemens is excited to have our leading microgrid management software play such an integral role in this important milestone with our partners CPS Energy, UTSA and NREL,” said Mike Carlson, president of Siemens Digital Grid. “Our software is not only providing the detailed insight and decision making ability necessary to effectively manage a microgrid, but has demonstrated extensive security capabilities and islanding coordination, which are critical in helping power producers embrace agility and successfully integrate renewables across the country.”

IEA: Brazil, Mexico and Others Need to Adapt Transmission to Renewable Potential

By Rod Walton, Senior Editor

Denmark, Mexico, China, Brazil and South Africa are expected to dramatically increase their share of variable renewable energy (VRE) while Indonesia hardly taps into its VRE potential, according to a new report by International Energy Agency.

All those countries adding VRE potential must adapt their transmission systems to better fit their renewable energy resources whether its hydro, wind or solar. Some, such as Brazil, find their primary VRE resources far away from the load centers, while Indonesia is challenged by the archipelagic layout of its grid, with islands forming isolated subsystems, according to the IEA.

Much of the report, titled “Next Generation Wind and Solar Power: From Cost to Value,” focused on VRE generation potential, but part of each case study noted the transmission system and how it matches the needs.

In Brazil, for instance, “Long transmission lines are needed to connect the country’s hydropower resources to the coastal load centers. New hydroelectric projects-such as along the Rio Madeira, Rio Tapagos and Rio Xingu rivers-lie more than 2,300 kilometers (km), or 1,439 miles, away from the coastal cities of Sàƒ£o Paulo and Rio de Janeiro and require significant transmission grid updates,” the report reads.

Brazil’s transmission system has grown by 52,000 km in the past 15 years, according to the IEA, but the country is due to build another 55,000 km in less than a decade.

Mexico plans to construct nearly 25,000 km of transmission lines from 2016 to 2030, according to reports. The country has 13 transmission lines that interconnect with neighboring nations, including 11 with the U.S., although five of those U.S. interconnections are not available for cross-border trade and only in emergency situations, the IEA report noted.

“The transmission grid (in Mexico) is well developed in the central region where the principal load centers are situated, but it is less extensive in the northern regions,” the report concludes. “Cross-border interconnection capacity is relatively weak. Given the lack of major storage facilities and the planned decommissioning of peaking plants, a flexible operation of the combined-cycle fleet will be critical to ensuring sufficient levels of flexibility in the Mexican system.”

All in all, the share of electrical generation provided by VRE is growing and upgrades will be needed, the IEA said. “Such steps will be a priority for Brazil, China, Mexico and South Africa in coming years,” the report reads.

Finland, Sweden Moving Forward with new Transmission Connection

Transmission system operators Fingrid and Svenska kraftnàƒ¤t have decided to move forward on the third alternating current (AC) connection between Finland and Sweden. Fingrid’s Board of Directors decided on the issue late in 2016 after Svenska kraftnàƒ¤t’s Board had already taken a similar decision. The project, which aims for commissioning by 2025, advances to more detailed planning, looking for a transmission line route that is suitable from the environmental perspective.

Electricity transmission between Finland and Sweden is among the most congested in Europe, reports say. The electricity imports from Sweden have increased, and in the past few years, sufficient cross-border transmission capacity has been available to the electricity market for only around half of the time. In the arising bottleneck situations, the electricity price between Sweden and Finland has diverged.

During 2016, Fingrid and Svenska kraftnàƒ¤t carried out a study on the development needs of cross-border capacity. The study found that bottleneck situations will be probable and a new transmission connection is needed. The most significant benefit of a new connection is the levelling of electricity price differences between the countries. The third AC connection is also important for system security of the entire Finnish power system, adequacy of electricity and enhanced reserve market.

Fingrid intends to apply for the Project of Common Interest status and later also financial support for the project from the European Union . Next, the project will proceed to more detailed planning, after which follows the environmental impact assessment.

The transmission line connection to be constructed will increase the transmission capacity from Sweden to Finland by 800 MW, which corresponds to around 30 percent of the current capacity. The transmission line is planned from Messaure in Sweden via Keminmaa to Pyhàƒ¤nselkàƒ¤ in Finland, spanning a distance of around 370 km. The estimated costs of the project are just under 200 million euros ($209 million).

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at

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