The Low-Carbon Resources Initiative (LCRI) is an international collaborative spanning the electric and gas sectors that aims to help advance global, economy-wide deep decarbonization. With 18 anchor sponsors, the LCRI leverages the collaborative research model employed by both companies, bringing industry stakeholders together to conduct clean energy R&D for society’s benefit. Seeded with $10 million from the EPRI collaborative, funding for the initiative is expected to be leveraged many times over its $100 million target through public and private collaboration.

Sponsors of the initiative include:

American Electric Power, Con Edison, Dominion Energy, Duke Energy, Exelon Corporation, Lincoln Electric System, Los Angeles Department of Water & Power, Missouri River Energy Services, Mitsubishi Hitachi Power Systems, Americas, National Fuel, New York Power Authority, Portland General Electric, PPL Corporation, Salt River Project, SoCalGas, Southern California Edison, Southern Company, and the Tennessee Valley Authority

The LCRI is targeting advancements in low-carbon electric generation technologies and low-carbon energy carriers, such as hydrogen, ammonia, synthetic fuels and biofuels. This worldwide collaborative will:

• Identify and accelerate fundamental development of promising technologies,
• Demonstrate and assess the performance of key technologies and processes, and
• Inform key stakeholders and the public about technology options and potential pathways to a low-carbon future.

EPRI President Arshad Mansoor, said, “Achieving ambitious targets will require technologies and processes beyond those widely available today. This global initiative will advance affordable pathways to economy-wide decarbonization.”

“This initiative advances the next-generation clean energy technologies that are critical to achieving net zero emissions within Dominion Energy and across the broader economy. Hydrogen is one of the most promising of these innovations because of its potential to decarbonize many sectors, including power generation, heating, transportation, shipping and manufacturing,” said Mark Webb, Chief Innovation Officer, Dominion Energy.

“This partnership will further efforts to initiate new highly-technical research projects that will address LADWP’s evolving needs and engage in new low-carbon channels for the generation, delivery and end use of electricity in ways that support reliability, sustainability and efficiency,” said Reiko Kerr, Senior Assistant General Manager, Power System Engineering, Planning, and Technical Services, LADWP

Learn more about the LCRI at www.LowCarbonLCRI.com.

Crews safely stored the last of 73 spent nuclear fuel canisters in the Holtec dry storage system. Holtec International is contractor in the decommissioning efforts at San Onofre, which was closed by owner Southern California Edison in 2013 after some safety issues with its steam generators.

The latest milestone brings the spent fuel roads one step closer to relocation at an off-site facility. Currently, however, no such federally licensed facility exists.

“Our commitment remains ensuring spent nuclear fuel is safely stored and that it can be transported to an off-site facility in the future,” said Doug Bauder, SCE vice president and chief nuclear officer. “We are developing a strategic plan to help us explore opportunities for advancing various alternatives to get the spent fuel off-site, as well as make sure that our fuel is ready for pickup when the opportunity presents itself.”

See more stories about Southern California Edison

SCE expects to release the strategic plan early next year, which will consider alternatives for relocating the spent fuel to an off-site facility. The options will include permanent disposal or temporary storage at a site.

All of the spent fuel is now contained in 123 canisters in dry storage. This allows SCE to focus on deconstruction efforts at the San Onofre plant.

The utility issued its deconstruction notice in January and began work to dismantle San Onofre one month later. The first projects completed include asbestos removal from inside the containment domes and shipping the Unit 1 reactor pressure vessel to a disposal facility in Utah.

“For the next stages at San Onofre, we’ve developed a streamlined organization that is focused on providing oversight of our decommissioning contractor and safely managing the spent fuel,” Bauder said. “Much of the work coming up will be inside the containment domes and preparing for the removal of lots of steel and concrete.”

Subscribe to our free, weekly newsletter on all things power generation

San Onofre’s two reactor units which were still active earlier this decade produced a combined 2,250 MW at capacity. Located south of San Clemente on the California coast, it began operations with Unit 1 in the late 1960s, while Unit 2 and 3 were commissioned in the 1980s.

Unit 1 was decommissioned in 1992

How can homes with solar plus battery systems supply energy to the power grid when it needs it the most? With the help of Sunrun and customers, it is one of the questions Southern California Edison expects to answer by creating one of the country’s largest virtual power plants.

For the next year, up to 300 SCE and Sunrun Brightbox home energy system customers will be part of a network, or virtual power plant, that can be called on to send clean energy back to the grid.

“California is leading the way to 100 percent clean energy for all. We’re excited to work with SCE to bring the benefits of Brightbox rechargeable solar batteries to more Californians through this innovative partnership,” said Lynn Jurich, Sunrun co-founder and CEO.

The program will show how responsive the virtual power plant is in delivering energy to the grid and if it is delivering as expected. Having a dependable and consistent supply of energy is critical to creating a reliable and resilient grid.

When an event is called, the virtual power plant will use energy stored in the batteries for the grid. Some reserve power will remain in the battery for the customers’ use. Customers won’t notice any difference in how their system works and they will receive a $250 incentive at the end of the first year of operation.

Up to 80 calls for energy or energy events will take place throughout the year under six scenarios to better understand how the virtual power plant responds to different types of high-energy demands. While some high-energy demands are predictable, like those that take place almost every day at the same time, others are less so including unexpected weather conditions or emergencies.

“For California to meet its carbon neutrality goal by 2045, we estimate that 40 gigawatts of energy storage will need to be added to the grid, including 10 GW from hundreds of thousands of residential customers in the future,” said Jill Anderson, SCE senior vice president of Customer Service. “The clean energy from these home energy systems will benefit all of our customers.”

“FOR CALIFORNIA TO MEET ITS CARBON NEUTRALITY GOAL BY 2045, WE ESTIMATE THAT 40 GIGAWATTS OF ENERGY STORAGE WILL NEED TO BE ADDED TO THE GRID, INCLUDING 10 GW FROM HUNDREDS OF THOUSANDS OF RESIDENTIAL CUSTOMERS IN THE FUTURE. THE CLEAN ENERGY FROM THESE HOME ENERGY SYSTEMS WILL BENEFIT ALL OF OUR CUSTOMERS.”

Jill Anderson, SCE Senior Vice President

As fossil fuels are replaced with more carbon-free energy sources, like solar, battery storage plays an increasingly important role in maintaining a reliable grid since it can capture energy from the sun for use when it isn’t shining.

SCE’s Pathway 2045 outlines the need to integrate large amounts of utility scale and residential solar energy and energy storage, including 110 GW of solar and 40 GW of storage, into the grid to meet the states carbon neutrality goals.

That’s something more homeowners are interested in taking advantage of as they realize the benefits of clean energy and contributing to a clean energy future.

In April 2015, 116 SCE customers had solar plus energy storage systems. As of this past April, more than 7,900 customers have solar plus energy systems, 1,700 of those installations were in the first few months of the year.

This article was originally posted on ENERGIZED and was republished with permission.

Most states if not all in the U.S., including California early on, have suspended classroom activities in the wake of the coronavirus. Scholarship announcements such as these give hope for the future of STEM industries and for the families. Half of the recipient students will be first-generation college attendees within their respective families.

The 2020 Edison scholars include 30 students who can use the funds to pursue science, technology, engineering or math (STEM) studies.

“We are very proud of these students and their outstanding academic achievements”

Tweet this

“We are very proud of these students and their outstanding academic achievements,” said Pedro Pizarro, president and CEO of Edison International. “The scholarships provide financial support to these deserving scholars and their families so they can focus on their studies. We are counting on them to help us innovate and turn big ideas into real-world solutions and we know they have a bright future ahead.”

Each Edison Scholar will receive a $40,000 scholarship – paid over four years – to further their academic pursuit of STEM fields at a four-year accredited U.S. college or university. Since 2006, more than $11 million in scholarships have been awarded to 670 high school seniors through the Edison Scholars Program.

The 2020 Edison Scholars are:

These announcements by utilities have been happening throughout March. The latest include Tucson Electric Power, Southern California parent Edison International, AVANGRID and Italian utility Enel.

Tucson Electric Power and sister utility UniSource Energy Services announced they will donate a combined $1 million to bill payment assistance and other coronavirus relief efforts in the communities they serve throughout Arizona.

 “We know many of our customers have been hit hard by this pandemic, and we want to do everything we can to help,” said David G. Hutchens, CEO of TEP, UniSource and their parent company, UNS Energy. “In addition to maintaining reliable energy service, we want to help local nonprofit groups support our communities during this period of unprecedented and urgent need.”

The companies will contribute $500,000 to the COVID-19 Community Support Fund established by the Community Foundation of Southern Arizona (CFSA) to support charities experiencing increased service demands from vulnerable populations during this public health crisis. Of that amount, $350,000 will be directed to Tucson-area agencies and $150,000 will benefit communities served by UniSource.

California-based Edison International also pledged $1 million earlier this month to local nonprofits. Other of the state’s utilities Southern California gas and Pacific Gas & Electric also have made significant donations, the latter giving close to one million protective masks for first responders.

Edison International’s pledge is to organizations providing critical services, food and necessities to vulnerable communities dealing with COVID-19. Those include California Community Foundation’s COVID-19 LA County Response Fund, Community Action Partnerships in the region and Foodbank Santa Barbara County, among others.

 “Edison International appreciates the health care workers, first responders, local communities and others who are on the front lines working to contain this pandemic,” said Pedro Pizarro, president and CEO of Edison International, Southern California Edison’s parent company. “As an essential service provider and a member of the community, we remain committed to the health, safety and well-being of customers and employees, and will support those who need it the most during these unprecedented times.”

Connecticut-based AVANGRID Inc. and the Avangrid Foundation together announced a $2 million commitment to support national and local organizations on the front lines of dealing with the impacts from the coronavirus. The U.S. has close to 70,000 confirmed cases of COVID-19 with more than 700 people dead, according to reports.

The AVANGRID family of companies includes Avangrid Renewables and eight electric and natural gas companies in New York, Maine, Connecticut and Massachusetts.

 “As a provider of critical electric and gas services, AVANGRID understands the need for rapid response and is no stranger to working on the frontline of a crisis. We’re proud to offer a steady and helping hand to those who support the most vulnerable among us, particularly during these challenging times,” said Jim Torgerson, the Foundation president and AVANGRID CEO. “We are determined to help address the pandemic’s economic, social and health ramifications. Our communities are in need, and we will stand by them.”

Malaysian utility TNB pledged the equivalent of $2.3 million to that nation’s ministry of health. The company also called on other organizations to do the same.

 “The growing number of people infected by the COVID-19 virus in Malaysia is exerting pressure on the resources of government hospitals that have been designated to deal with the virus, said Dato’ Seri Dr. Chen Chaw Min, Secretary General of the Ministry of Health.

The worst hit of all nations is Italy, with 75,000 afflicted and 7,500 killed. In Rome, Enel announced it had drawn up an insurance policy to cover all of the group’s more than 68,000 employees globally in the event they are hospitalized with the COVID-19 virus.

The insurance tool, which was specifically designed for the needs of the Enel Group, represents the first ever of its kind in the world aimed at guaranteeing support at global level for the ongoing pandemic, according to the company.

Through the policy, Enel will guarantee a cash allowance for all Group employees who are hospitalized after contracting the virus or undergoing intensive care. The policy will guarantee additional benefits beyond those offered by all other insurance tools and forms of health care already available to Group employees.

This tool, developed in collaboration with the leading company in the insurance and risk management services sector Aon SpA, was activated immediately in all countries where Enel has employees.

Enel operates in 33 countries with 2.2 million kilometers of grid network and a managed capacity of more than 88 GW.

Scores of utilities have committed contributions to nonprofits, bill payment assistance, postponing service disconnections and more to fighting the novel virus which had killed more than 21,000 people worldwide since December.

(Rod Walton is content director for Power Engineering and POWERGEN International. He can be reached at 918-831-9177 and rod.walton@clarionevents.com).

History may paint a rosier picture, but in 1969, only 47 percent of the public supported the moon landing. They weren’t necessarily on board, but for the teams of scholars, researchers, scientists and engineers working around the clock, failure was not an option.

Today, we’re seeing a lot of parallels when it comes to decarbonization — the new “moon shot” of the 21^st century. And the “moon”? The promise by electric utilities of delivering net-zero carbon emissions or carbon-free energy in a rapidly decentralizing marketplace.

There’s no set path to decarbonization and no single rocket ship that will get us there. Although it’s a common goal, the players — utilities, governments, corporations and other entities — are at different starting points, with different drivers, timelines, and levels of complexity. Some have staked out aggressive goals, e.g., 100-percent renewable energy or a zero-carbon footprint, while others are aiming for more intermediary steps, such as working towards cleaner coal or relying on natural gas as a transition fuel toward a cleaner energy future.

What is known is that decarbonization will require a colossal effort. Utilities know where they want to go, and they know that a moon shot is necessary to get there — but the exact trajectory remains unclear.

How to Build a Rocket Ship

The march towards renewables isn’t slowing anytime soon, spurred on by an accelerating pace of change, increasing-price parity for new technologies, and new advances in electrification, decentralization and digitization. As a result, we’re seeing sweeping changes in how electricity is produced. Coal continues to decline, dropping 18 percent in 2019, while natural gas has surged ahead to become the No. 1 source of generation in the U.S.

Today, market players have more options than ever before, including large-scale solar and wind, battery storage and associated technologies, the replacement of coal with natural gas, and the advent of hydrogen power and next-generational nuclear energy. Utilities, governments and corporations are evaluating these technologies as they build their “rocket ships.”

These measures will get us 70 to 80 percent of the way there, but to make it to the moon, we need new regulatory and market processes and evaluation of new technologies that are not yet fully developed to meet 2050 goals.

There are a lot of potential solutions, and new ones are being added all the time. But utilities will have to take an individualized approach based on their current situation. For example: Do they own generation? Will they need to retire or make new investments? If they do not own generation, are they going to invest in 100-percent renewable generation? Or are they going to buy credits? How do state and national regulatory components need to change to support my changing business? Where are the other market players?

Rapidly changing technology is also forcing utilities to address new issues. For example: In the past, power flowed in one direction and optimization happened based on that scenario. Today, distributed generation has spawned bi-directional power flows, introducing a slew of new challenges when it comes to protecting and operating the grid. In addition, utilities must include assets they often don’t own or control into their grid control and optimization strategy, while still providing safe, reliable power to their customers.

Add to this list, increasing penetration of distributed energy resources (DER), growing concerns over grid resilience and reliability, aging infrastructure, increasing load demands due to growing electrification, distribution modernization, increasingly connected (and vulnerable) IT and communication networks, third-party market participation, and security.

How to Achieve Liftoff

Data management will be critical. The ongoing digitization of the grid combined with the influx of new market players and new digital assets is driving immense amounts of data being collected by smart sensors and remote devices. Good data management comes down to obtaining secure, reliable, timely, coordinated information from both utility and non-utility assets, and aligning that data to tell meaningful stories. Considering the level of distributed assets — with third parties owning, controlling and selling assets into the marketplace — utilities are facing a different market model that will require unprecedented levels of information sharing.

Move decision-making to the grid edge. All too often, there is latency in data transmission caused by data traveling from a device to the centralized system for a decision to be made, then returning that decision to the device. To remedy this, grid operators must havethe ability to make decisions very rapidly, near the grid edge close to where operations occur, while still relying on a centralized control system to provide oversight. Sharing information at the grid edge will require a whole new level of communication and security infrastructure to protect critical data and assets.

Improve visibility into distribution and transmission systems. Utilities must understand what impact both utility and non-utility-owned assets are having to the distribution and transmission grids. A collection of assets on the distribution side can cause instability on the transmission side, and vice versa. Optimization can no longer occur on one system. Utilities must understand how DER impact the grid, and access to the right data will be critical for forecasting and alignment of load and generation at increasingly complex levels of granularity.

Advocate for regulation modernization. Regulators will be a key inflection point and new utility business models will be required to help ensure an orderly transition to this new marketplace.How much ability will utilities have to shape the rules of engagement? At this point in time, utilities may be

responding to the market rather than leading it, but with data coming from all these different sources, data integrity and security become significant issues. To mitigate this, utilities will need to integrate with third-party participants. Utilities will also benefit from collective advocacy for regulatory changes and structures at both the state and federal level that support their evolving business models.

How to Thrive, Not Just Survive on the Moon

Once we achieve our moon shot, what can utilities do to ensure that they can thrive in this new energy ecosystem? What do they need to be aware of?

For one, business models and customer requirements will change. Loads will decrease as customers deploy their own generation sources, even as utilities deploy solutions to address customer’s evolving needs. To stay competitive, utilities will need to implement systems and processes that help reduce operational costs, such as asset management, monitoring and maintenance; predictive analytics; and automation, AI and machine learning.

Utilities will also need to develop trusted partnerships with regulators and advocate for regulation modernization to support new utility business models. Left as-is, the current rate structure will increase rates as utilities deploy the technologies that are required to address a distributed grid.

However, as customers continue to deploy self-generation, relegating the utility grid to a standby or backup role, the number of full rate-paying customers will decrease, risking the possibility that the only customers left bearing the financial burden will be those who can least afford to generate electricity themselves. To mitigate this issue, the market needs new regulatory models and rate structures that address the need to balance the costs of going from the grid we have– to the grid we need.

Once the future grid is in place, utilities may see changes in the amount of infrastructure required to produce and distribute energy; less infrastructure may be needed to meet demand. For example, with more DER on the horizon, utilities may need fewer transmission facilities. The market may not need larger substations — or more substations — if it generates energy at the distribution level where it’s consumed. Utilities may end up with extraneous assets that simply aren’t needed.

The relationship between utilities, customers, vendors and regulators will change and become more collaborative, and new third-party players will continue to enter the market and deliver the technologies needed to get to the moon. To address this, utilities will need to step up to serve as an “ecosystem orchestrator” for markets and grid operations and become an active participant in customer offerings.

When it comes to decarbonization, utilities have significant industry-changing goals. Although the end game may be the same, no one trajectory will get utilities to where they need to be. There will be best practices to adopt, as well as items to avoid. To build the best rocket ship, utilities must realize a new path, one where they can share lessons learned and act in cooperation while also dealing with the realities of complexity and competition.

About the authors: Leslie Ponder is the technology portfolio director for global distributed energy at Black & Veatch and is responsible for evaluating and delivering technology solutions within distribution, asset management, and distributed generation. Ponder has more than 30 years of experience, including 10 years with Duke Energy, where she led systems strategy and planning for communications, grid analytics, and grid control and security systems. She previously led R&D initiatives and partnered with the Department of Energy and National Laboratories to further the advancement of advanced distribution management systems and the adoption of distributed energy resources.

Kevin Cornish is a senior managing director with Black & Veatch Management Consulting. Cornish has more than 35 years of utility operations, enabling technology and management consulting experience, including 13 years with Pacific Gas & Electric Company. Experienced in managing complex utility technology programs, he is responsible for supporting grid modernization-enabling technology solutions within the electric, natural gas and water industry domains particularly in the areas on advanced metering infrastructure, operating center solutions, IT/OT convergence and business process redesign.

 For energy companies, missteps in asset management can have extensive and costly consequences. Asset management is the lifeblood of their operations, through which they streamline production processes, control costs and ensure resources are being used responsibly. As the energy sector transforms to meet the challenges posed by an evolving landscape, asset managers should implement advanced technological approaches in order to sustain their plant’s value. 

 Software representation of assets and processes helps energy companies understand, predict, and optimize performance in order to achieve improved business outcomes. Energy companies should value assets from the earliest developmental stage through mature operation — but project assets require different services at different times, rendering human prediction an inefficient financial risk. 

 In years past, many plants used manual processes to manage their operations and output.  Spreadsheets with simplified calculations and other discrepancy-prone tools were sometimes used to estimate a project’s capacity. From the uploading of information to the running and distribution of reports, the management of these processes was susceptible to human error, leading to inaccuracies and increased potential for lost market revenues. Production planning solutions can shrink this margin of error while increasing process efficiencies and optimizing performance.

 Competitive Power Ventures (CPV) implemented GE production planning software to reliably estimate a plant’s capacity while improving process efficiencies. This software can accurately predict the plant’s output based on the ambient conditions using local weather forecasts and then auto-correct calculations should those conditions or source of the information change. This has helped us accurately predict day-ahead plant capacity, minimize the margin of error and capitalize on the market, all while reducing the risk of underselling energy.  Production planning automatically issues the reports that are consistently issued in a reliable manner to the proper distribution to those who rely on this information.  

 The incremental value of such technology is statistically evident, as companies have visibility to more capacity and improved productivity. Our productivity, for example, is valued today at approximately $200,000 per year for a 700-MW plant. 

 By implementing innovative production planning software, power plant operators can improve plant dispatch, generate more revenue with increased output all while reducing emissions. 

Another important tool energy companies can use to improve their asset management capabilities is the remote monitoring of plant equipment. Companies are accustomed to monitoring the focal part of the plant, like the combustion turbines, but rarely have systems in place to examine every piece of equipment; it’s unrealistic to expect operators and engineers to expend time doing so 24 hours per day, seven days per week on every piece of equipment. But through artificial intelligence and advanced pattern recognition, remote monitoring can identify potential issues in equipment health that most likely would go undetected until it’s too late, resulting in downtime and lost revenues. 

 Remote monitoring collects real-time data. Over time, patterns in this data establish the baseline standards for normal equipment operations. If the monitoring system detects irregularities in the pattern, it notifies plant operators and management team and suggests potential solutions before system failures occur. These insights and recommendations become more comprehensive with time. Proactive identification of issues, instead of reactionary measures, will better protect assets and improve reliability for both the short-term and long-term life of a plant. Companies receive warning emails as well as periodic PDF reports of this data, and follow up with phone calls to communicate new or ongoing differences in the equipment pattern. Remote monitoring is a cost-effective service — especially when trying to minimize factors that cause a plant to go offline, the cost of such technology justifies its value. By outsourcing remote monitoring, companies can avoid incurring the costs of building brick-and-mortar facilities or the development of a similar technology. 

 As the technological landscape updates and expands, the energy industry must match the demands of today’s market. Energy companies, however, needn’t sacrifice profitability while utilizing the most efficient modes of production. By applying new innovations in asset management, such as advanced production planning software and enhanced remote monitoring capabilities, companies will bolster profits and modernize the grid simultaneously for years to come.

About the author: Nick Rahn is the Senior Vice President of Asset Management for Competitive Power Ventures. CPV’s asset management oversees 9,300 MW of fossil including the gas-fired Woodbridge Energy Center in New Jersey (pictured at top) and renewable power generation projects in eight U.S. states.

Healthcare experts say if coronavirus, known as COVID-19, a respiratory disease originating in China, spreads widely in the United States one of the biggest challenges will be staffing hospitals.

Without a vaccine, many doctors and nurses on the front lines of caring for patients will be infected. Even healthcare workers who aren’t infected may have family members who are, so they’ll end up missing shifts to stay home and care for sick relatives.

Staffing will be no less of a challenge for utilities if COVID-19 circulates widely. Many utilities have experience to draw on, though. In 2009, the swine-flu pandemic, which was caused by the H1N1 virus, affected approximately 16 percent of the world’s population. By definition, a pandemic causes a significant amount of deaths, involves person-to-person transmission and occurs worldwide. Utilities have historically done a great job of preparing for all types of events, and, while pandemic plans have existed for some time, COVID-19 is a driver to review plans, communicate internally and respond accordingly.

Back to the future

Some of the resource management preparations from 11 years ago included making plans for non-essential employees to work from home if possible. For essential personal like line crews and dispatching, that’s a different story.  Dispatch organizations considered cordoning off operations, sequestering essential personnel and providing space to work, eat and sleep for days or even a week at a time. Prior to starting a shift, each employee would go through quarantine and testing to make sure he or she wasn’t infected. If a worker tested negative, the managers would allow the person to enter the work area. This process repeated until the pandemic had passed. If COVID-19 were to cause widespread infections, the normal workforce that many utilities rely upon may not be willing or able to come to work.

To plan for this and address gaps, utilities could begin verifying everyone’s roles and responsibilities, including storm roles. By updating records, utility managers will find it easier and efficient to know who to bring in should a person with the primary responsibility fall ill.

For organizations with automated crew management platforms, incident commanders could use their technology to review employees’ roles and set up staffing scenarios based on which resources are available to work. These crew management platforms are typically refreshed instantly with employee qualifications and status, which could help in a COVID-19 scenario.

Technology can help utility managers gauge resource availability and see at what point they might need external assistance. That said, a widely spreading virus could cause a utility to lose many of its contractors because they become ill, can’t enter an area that’s quarantined or stay home to care for sick relatives. This could also impact external resources from other utilities. That would cause utilities to rely primarily, or solely, on native crews. For utilities building and managing crews and resources manually, this planning is still possible, but likely crunching this data would require days or even weeks instead of hours or even minutes.

The goal, in part, is to ask ourselves as an industry how to put our best foot forward when maintaining or restoring service during a wider outbreak. For example, during the H1N1 preparations, utilities considered how line crews might have to interact with consumers. If a crew was, for example, installing a pad-mounted transformer, some utilities decided to communicate to customers in advance that their crews wouldn’t be able to speak with customers while in the field in order to avoid the risk of exposure. Managers instructed crew foremen to add an additional barrier to the perimeter of their work area, keeping the public and others a safe distance away to avoid the transmission of the virus.

Along with managing people and crews during a pandemic, the Department of Homeland Security suggests that utilities consider scenarios involving equipment, material and government regulations. For instance, many utilities stockpile several months’ worth of material in an anticipation of storm season. If, however, a COVID-19 outbreak disrupts the supply chain, how will utilities obtain what they need for employees? According to DHS, “reliance on ‘just-in-time’ delivery could shut down your supply chain, . . . consider stockpiling fuels (i.e., coal, gas, and oil), replacement parts and personal protective equipment (e.g., masks, gloves, hand sanitizer) on site or make contingency plans.”

Since utilities already generally stockpile material, the bigger question in planning for a pandemic is how stockpiled material at, say, a central warehouse gets distributed to service centers when needed. If COVID-19 were widespread, utilities may not have enough workers to transport supplies to a service yard. Or a quarantine might prevent a utility delivering material to an affected area. If a significant number of workers fell ill to COVID-19, utilities may see regulators make exceptions to reliability indices because of a limited number of native and contract crews in the field maintaining service. If one utility, in particular, is hard hit with absences, managers may want to request such an exception.

During the planning for the H1N1 virus, utility industry recommendations also included selecting a subset of a utility’s senior management team to spearhead planning and response. That team was to oversee task groups who, in turn, would:

• Identify critical processes and operations to keep running versus putting on hold non-critical activities (e.g., meter reading);
• Implement a communications strategy and relay specific information about the spread of H1N1 to employees to stop false reports and mitigate panic and, if necessary, counsel employees and families;
• Establish health screening for people returning to work after infection or caring for an infected relative;
• Review technology plans to identify and solve any business limitations that might arise from moving operations to a remote site or being blocked from entering a site due to quarantine.

Many utilities already have these processes as part of standard emergency response planning. But a pandemic introduces challenges unlike a major storm or cyberattack because a utility’s workforce is directly in the virus’ crosshairs. At the beginning of February, the U.S. Centers for Disease Control and Prevention (CDC) notified the public that people should prepare for COVID-19 because the virus was likely to gain a foothold in America. By drawing on past plans and making contingencies for new scenarios, utility managers can maintain the critical electric service that healthcare workers need to stop COVID-19 from gaining anything more than a foothold.

Author: Jim Nowak retired as manager of emergency restoration planning for AEP in 2014. He capped his 37-year career with AEP by directing the utility’s distribution emergency restoration plans for all seven of the company’s operating units, spanning 11 states. He was one of the original co-chairs for Edison Electric Institute’s (EEI) Mutual Assistance Committee and National Mutual Assistance Resource Team and a member of EEI’s National Response Event (NRE) governance and exercise sub-committees. He currently serves as senior director of Operations, Product and Services for ARCOS LLC.

Originally published on power-grid.com

The Chicago-based company was at DISTRIBUTECH International in San Antonio recently, unveiling its new “Reliability Experience” at the feeder, lateral and grid edge locations. Andrew Jones, senior vice president of global sales for S&C, answered a few questions from Clarion Energy Content Director Rod Walton.

1. Tell us about the new S&C reliability experience that was unveiled at DistribuTECH?

“S&C Electric Company’s 2020 Augmented Reality Reliability Experience was designed to reinforce the importance of improved grid reliability at feeder, lateral, and grid edge locations. The demo projected attendees into three scenarios utilities commonly face, at various locations on the grid, to show the value of innovative grid solutions. Reliability improvements at any location on the grid will benefit both a utility and end customers, but a comprehensive approach, looking at all three locations, provides the best combination of increased reliability scores, lowered O&M costs, and improved customer satisfaction.”

2. Give us a quick history lesson on S&C, and what’s changed the most about the company during that time?

“S&C was founded in Chicago in 1911, and we have a history of over 100 years of innovation. Starting with the liquid power fuse all the way to our most recent product launch, the VacuFuseâ„¢ Self-Resetting Interrupter, S&C has always championed innovation. Throughout our history we have introduced unique technology that minimizes the impact of, and can even prevent, power outages. Over the last 100 years, lots has changed. We moved to a bigger manufacturing site in the city of Chicago, we developed new products, and we hired new people, but at the core, S&C remains the same: committed to improving the performance of the grid and providing utilities and other power customers with safe and reliable grid solutions.”

3. What are the biggest T&D and smart-grid trends you see coming for 2020?

“In 2020, the biggest trend we will see continue to grow is a push for improved reliability. But, this trend of reliability is supported by a variety of other trends: No. 1, we will see utilities place an increased focus on their distributions systems. These utilities will be looking at reliability solutions that help mitigate outages in the last mile of line.

“No. 2, we will also see utilities place an increased focus on their customer’s experience. Much of the work being done in the reliability space is to provide a better power experience for power users, regardless of where they are on the grid. Solutions to lessen momentary outages falls in this category as well.

“In 2020 we will also see more utilities taking steps to harden their grid, one of which will be the undergrounding of power lines. This solution is very effective for areas with severe weather concerns and will help restore power to service areas quicker following a disaster.

4. Regulations seem to be slackening under this US presidential administration, but they could go the other direction if a new leader is elected. How do utilities and their suppliers deal with this volatility in government expectations?

“The challenge in the US is the multiple regulators that are at the state level. National policy does have some impact, but the biggest impact on regulation does come from the state level. The major challenge the industry is facing is that there are multiple regulators throughout the US are trying to cover the needs of Investor Owned Utilities (IOUs) and Customer Owned Utilities such as Co-ops and Municipals. This diversity of regulations makes it difficult for utilities and their suppliers because there is no real certainty. There is also a shift throughout the country towards Performance Based Regulation (PBR).”

Coal ash stored at the former Allen Fossil Plant in Tennessee will be moved to an approved offsite landfill, according to the release. The TVA shut down the 741-MW power facility in March 2018.

The authority has identified six permitted landfills which could potentially accept coal ash from Allen. The U.S. Environmental Protection Agency regulates coal ash as a nonhazardous solid waste.

The TVA has not selected a specific site and will issue a request for proposals from the landfills. Each applicant would be required to offer environmental plans, project designs and a history of regulatory compliance.

The federal utility has released an environmental impact statement (EIS) on the Allen coal-ash scenario. The preferred alternative is removal of all coal ash.

Allen Fossil Plant generated electricity for 59 years beginning in 1959. Memphis Light, Gas and Water initially started the plant, while TVA operated from 1964 on and acquired it outright 20 years later.

The three coal-fired units were placed with the Allen Combined Cycle gas-fired plant that also includes a 1-MW solar farm.