The POWER Podcast

According to a guidebook issued by Sandia National Laboratories, a U.S. Department of Energy (DOE) multi-mission laboratory, microgrids are defined as a group of interconnected loads and distributed energy resources (DERs) that act as a single controllable entity. A microgrid can operate in either grid-connected or island mode, which includes some entirely off-grid applications. A microgrid can span multiple properties, generating and storing power at a dedicated/shared location, or it can be contained on one privately owned site. The latter condition, where all generation, storage, and conduction occur on one site, is commonly referred to as “behind-the-meter.” Microgrids come in a wide variety of sizes. Behind-the-meter installations are growing, especially as entities like hospitals and college campuses are installing their own systems. Where some once served a single residence or building, many now power entire commercial complexes and large housing communities. “Today, there’s a whole new way to do DER management, which is a significant component of microgrids,” Nick Tumilowicz, director of Product Management for Distributed Energy Management with Itron, said as a guest on The POWER Podcast. “There is a way now to do that in a very local, automated, and cost-effective way just by leveraging what utilities have already deployed—hundreds of thousands of meters and the mesh networks that are communicating with those meters.” Tumilowicz said a variety of factors can influence if and/or when a microgrid gets deployed. Sometimes, a company is focused on running cleaner and greener operations. Other times, the grid a company is connected to may have reliability challenges that are affecting business adversely, or the company may just want to be energy independent, so the decision is frequently case specific. “The customer has this motivation to have this backup concept known as resiliency—if the grid’s not there for me, I’ll be there for me,” he said. “Generally speaking, nationally, we’re well above 99.9% grid reliability,” Tumilowicz noted. Yet, even when power outages are rare, a microgrid can still provide value. “It can provide flexible services, such as capacity or resource adequacy, or energy services back to the distribution and the transmission up to the market operator level,” explained Tumilowicz. “So, this is a whole other way to be able to start thinking about how we participate with microgrids when 99-plus percent of the time they’re grid connected, but they’re also there for when the grid is not connected—in that very low probability of time.” However, the return on investment for microgrid systems is highly affected by location. “If you’re in Australia, the equation is different than if you’re in Hawaii, versus if you’re in the northeast U.S.—one of the better-known accelerated paybacks to do this,” said Tumilowicz. For example, in areas where the market operator, such as an independent system operator or regional transmission organization, places a high value on peak power reductions within its system, the economics for microgrid owners can be greatly improved. But regardless of what may have driven the initial decision to create a microgrid, Tumilowicz said being flexible is important. “You might deploy your microgrid to satisfy three use cases and market mechanisms that exist in the beginning of 2024, but you need to be open and receptive—and this is where the innovation comes in—to add use cases over time, because the system is going through a significant energy transition, and you need to be dynamic and accommodating to do that,” he said.

Concrete is the most widely used construction material in the world. One of the key ingredients in concrete is Portland cement. The American Concrete Institute explains that Portland cement is a product obtained by pulverizing material consisting of hydraulic calcium silicates to which some calcium sulfate has usually been provided as an interground addition. When first made and used in the early 19th century in England, it was termed Portland cement because its hydration product resembled a building stone from the Isle of Portland off the British coast. Without going into detail, it suffices to say that a great deal of energy is required to produce Portland cement. The chemical and thermal combustion processes involved in its production are a large source of carbon dioxide (CO2) emissions. According to Chatham House, a UK-based think tank, more than 4 billion tonnes of cement are produced each year, accounting for about 8% of global CO2 emissions. However, fly ash from coal-fired power plants is a suitable substitute for a portion of the Portland cement used in most concrete mixtures. In fact, substituting fly ash for 20% to 25% of the Portland cement used in concrete mixtures has been proven to enhance the strength, impermeability, and durability of the final product. Therefore, using fly ash for this purpose rather than placing it in landfills or impoundments near coal power plants not only reduces waste management at sites, but also reduces CO2 emissions and improves concrete performance. Rob McNally, Chief Growth Officer and executive vice president with Eco Material Technologies, explained as a guest on The POWER Podcast that the ready-mix concrete industry has been reaping the benefits of using fly ash for years. “In terms of economics, fly ash was typically cheaper than Portland cement. It also has beneficial properties that typically makes it stronger long term and reduces permeability, which keeps water out of the concrete mixture and helps concrete to last longer. And, then, it’s also environmentally friendly, because they’re using what is a waste product as opposed to more Portland cement—and Portland cement is highly CO2 intensive. For every tonne of Portland cement produced, it’s almost a tonne of CO2 that’s introduced into the atmosphere. So, they have seen those benefits for years with the use of fresh fly ash,” McNally said. However, as climate change concerns have grown, many power companies have come under pressure to retire coal-fired power plants. As plants are retired, fresh fly ash has become less and less available. “The availability of fresh fly ash is declining,” said McNally. “In some places—many places actually—around the country, replacement rates that used to be 20% of Portland cement was replaced by fly ash are now down in single digits. But that’s a reflection of fly ash availability.” Eco Material Technologies, which claims to be the leading producer of sustainable cementitious materials in the U.S., has a solution, however. It has developed a fly ash harvesting process and has nine fly ash harvesting plants in operation or under development to harvest millions of tons of landfilled ash from coal power plants. Locations include sites in Arizona, Georgia, North Dakota, Oregon, and Texas. “There are billions—with a b—of tons of impounded fly ash around the country, so we have many, many years of supply,” McNally said. Still, Eco Material is not resting its business solely on fly ash harvesting, or marketing fresh fly ash, which it has also done for years. “The other piece where we will fill the gap that fresh fly ash leaves behind is with the green cement products. Because with those, we’re able to use natural pozzolans, like volcanic ash, and process those and replace 50% plus of Portland cement in concrete mixes. So, we think there’s an answer for the decline in fly ash and that’s where the next leg of our business is taking.”

There is growing demand for cybersecurity professionals all around the world. According to the “2023 Official Cybersecurity Jobs Report,” sponsored by eSentire and released by Cybersecurity Ventures, there will be 3.5 million unfilled jobs in the cybersecurity industry through 2025. Furthermore, having these positions open can be costly. The researchers said damages resulting from cybercrime are expected to reach $10.5 trillion by 2025. In response to the escalating demand for adept cybersecurity professionals in the U.S., the Department of Energy (DOE) has tried to foster a well-equipped energy cybersecurity workforce through a hands-on operational technology cybersecurity competition with real-world challenges. On Nov. 4, the DOE hosted the ninth edition of its CyberForce Competition. The all-day event, led by DOE’s Argonne National Laboratory (ANL), drew 95 teams—with nearly 550 students total—from universities and colleges across the nation. This year the focus was on distributed energy resources including solar panels and wind turbines. “The CyberForce Competition comes out of the Department of Energy’s Office of Cybersecurity, Energy Security, and Emergency Response, which is CESER for short,” Amanda Theel, group leader for workforce development at ANL, said as a guest on The POWER Podcast. “Their main goal for this is really to help develop the pipeline of qualified cybersecurity applicants for the energy sector. And I say that meaning, we really dive heavily on the competition and looking at the operational technology side, along with the information technology side.” Theel said each team gets about six or seven virtual machines (VMs) that they have to harden and defend to the best of their ability. Besides monitoring and protecting the VMs, which include normal business systems such as email and file servers, the teams also have to defend grid operations and other energy resources. “We have a Red Team that’s constantly trying to either come into the system from your regular attack-defend penetration. We also have a portion of our Red Team that we like to call our ‘assumed breach,’ so we assume that adversary is already in the system,” Theel explained. “The Blue Team, which is what we call our college students, their job is to work to try to get those Red Team members out.” She said they also have what they call “our whack-a-mole,” which are vulnerabilities built into the system for the Blue Team members to identify and patch. Besides the college students, ANL brings in volunteers—high school students, parents, grandparents, people from the lab, and people from the general public—to test websites and try to pay pretend bills by logging in and out of the simulated systems. Theel said this helps students understand that while security is important, they must also ensure that owners, operators, and end-users can still get in and use the systems as intended. “So, you have to kind of play the balance of that,” she said. Other distractions are also incorporated into the competition, such as routine meetings and requests from supervisors, for example, to review a forensics file and check the last time a person in question logged into the system. The intention is to overload the teams with tasks so evaluators can see if the most critical items are prioritized and remedied. For the second year in a row, a team from the University of Central Florida (UCF) won first place in the competition (Figure 1). They received a score of 8,538 out of 10,000. Theel said the scores do vary quite significantly from the top-performing teams to lower-ranked groups. “What we’ve found is obviously teams that have returned year after year already have that—I’ll use the word expectation—of already knowing what to expect in the competition,” explained Theel. “Once they come to year two, we’ve definitely seen massive improvements with teams.”

Southern Nuclear, Southern Company’s nuclear power plant operations business, announced in late September that it had received “first-of-a-kind approval” from the Nuclear Regulatory Commission (NRC) to use advanced fuel—accident tolerant fuel (ATF)—exceeding 5% enrichment of uranium-235 (U-235) in Plant Vogtle Unit 2. The fuel is expected to be loaded in 2025 and will have enrichments up to 6 weight % U-235. The company said this milestone “underscores the industry’s effort to optimize fuel, enabling increased fuel efficiency and long-term affordability for nuclear power plants.” “5 weight % was deeply ingrained in all of our regulatory basis, licensing basis for shipment containers, licensing basis for the operation of the plants—it was somewhat of a line drawn in the sand,” Johnathan Chavers, Southern Nuclear’s director of Nuclear Fuels and Analysis, explained as a guest on The POWER Podcast. “Testing of the increased enrichment component has been a licensing and regulatory exercise to see how we would move forward with existing licensing infrastructure to install weight percents above that legacy 5 weight %,” Chavers told POWER. Chavers said ATF became a focal point for the industry in March 2011 following the magnitude 9.0 Tohoku-Oki earthquake and resulting tsunami, which caused a crisis at the Fukushima nuclear power plant. “In 2012, Congress used the term ‘accident tolerant fuel’ for the first time in an Appropriations Act, and that’s where it all began,” Chavers explained. “It was really for the labs and the DOE [Department of Energy] to incentivize enhanced safety for our fuel in response to the Fukushima incident.” In 2015, the DOE issued a report to Congress outlining details of its accident tolerant fuel program. The report, titled “Development of Light Water Reactor Fuels with Enhanced Accident Tolerance,” set a target for inserting a lead fuel assembly into a commercial light water reactor by the end of fiscal year 2022. Notably, Southern Company achieved the goal four years early. “We were the first in the world to install fueled accident tolerant fuel assemblies of different technologies that were developed by GE at our Hatch unit in 2018,” Chavers noted. The following year, Southern Nuclear installed four Framatome-developed GAIA lead fuel assemblies containing enhanced accident-tolerant features applied to full-length fuel rods in Unit 2 at Plant Vogtle. “This is the third set that we’re actually installing that is a Westinghouse-developed accident tolerant fuel, which also includes enrichments that exceed the historical limits of 5 weight %,” Chavers explained. While enhanced safety is perhaps the most significant benefit provided by ATF, advanced nuclear fuel is also important in lowering the cost of electricity. “Our ultimate goal is to enable 24-month [refueling] cycles for all U.S. nuclear power plants, to improve the quality of life for our workers, to lower the cost of electricity,” said Chavers. “Fundamentally, [nuclear power] is a clean green power source—carbon-free. The more we can keep it running—that’s something we’re trying to go after,” noted Chavers. “We see a lot of positives in this program in that not only are we improving safety, lowering the cost, but we’re also increasing the amount of megawatts electric we can get out of the nuclear assets.”

During President Biden’s first year in office, his administration published a document titled “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050.” The document says all viable routes to net-zero involve five key transformations. They are: • Decarbonize electricity. • Electrify end uses and switch to other clean fuels. • Cut energy waste. • Reduce methane and other non-CO2 emissions. • Scale up CO2 removal. Which of the key transformations will play the biggest role in reaching the U.S.’s net-zero goal is still up for debate. “The first step—decarbonize electricity—is critical and may be one of the most important steps in achieving net-zero emissions,” Brendan O’Brien, business development manager, and strategy and sales leader with Burns & McDonnell, said as a guest on The POWER Podcast. “That transition is going to include a lot of things that we’re probably familiar with today, like clean energy driven by solar and wind, but also it’ll look to the future for decarbonized technologies and decarbonized solution.” O’Brien noted that the U.S. is targeting 100% clean energy by 2035, and he suggested the transition is already well underway. “It’s been occurring and even accelerating in recent years,” he said. “It’s been driven by plummeting costs in key technologies, like solar, onshore wind, offshore wind, and batteries, which you’re seeing more and more as deployed technology of the utilities in the United States. All that’s being bolstered by policies and regulation that has been enacted by various governments. And then also—the final—the big push is really coming from the consumer. More and more consumers are demanding clean energy and clean power, and the power generation market in the United States has been reacting to it.” Complexity is added to the equation with the second key transformation, that is, electrifying end uses. O’Brien said the transportation sector’s shift from internal combustion engines to electric vehicles will require a 65% increase in power generation. That’s on top of other load growth from manufacturers reshoring operations, as well as the need to replace retiring power generation units, specifically coal plants. “I think there’s going to be quite a fun challenge of figuring out what the energy mix is going to look like over the next 10 to 25 years to meet these targets,” said Megan Reusser, hydrogen technology manager with Burns & McDonnell, who also participated on the podcast. “What we really need to be looking at is the whole picture,” she said, noting that there are many sectors trying to electrify including industrial applications, agriculture, and forestry, among others. “Transportation is one piece, but when we start putting all the pieces together, it’s going to be large amounts of generation required,” said Reusser. Meanwhile, cutting energy waste is a no-brainer. Likewise, reducing methane and other non-CO2 emissions follows a similar thought pattern. Lastly, scaling up CO2 capture is important. “We cover a wide range of these different technologies. So, we’re looking at carbon capture and sequestration, whether that is amine technology or membrane technologies—doing a lot of work in the direct air capture, or DAC, markets. So, looking to essentially remove CO2 from the atmosphere that’s already there, and then sequester that with various technologies,” Reusser explained. In the end, it’s likely an integrated approach will be necessary to reach the U.S.’s net-zero target successfully. “There’s not just going to be a single solution that’s going to get us there. If you dive a little bit more into the U.S. strategy that we were talking about today, it really lays out the groundwork of how to get there. And as you dive into that, you’ll see that it doesn’t just focus on one single industry or one single technology, it’s really across the value chain on how we can accomplish this by working together,” concluded Reusser.

Renewable propane, produced from renewable diesel and sustainable aviation fuels, has the same features as conventional propane with reduced carbon emissions. The scalability of renewable propane production is increasing, with predictions of reaching 200 million gallons by 2024. The podcast also covers the advantages of renewable propane over hydrogen as a fuel, its interchangeability with conventional propane, and growing demand. Additionally, the podcast discusses the use of propane for EV charging solutions, reducing carbon intensity, achieving zero net energy and zero net carbon buildings, and advancements in the OEM industry for propane-powered equipment.

It’s pretty easy to understand how the weather affects certain forms of power generation and infrastructure. Sunlight is obviously needed to generate solar power, wind is required to produce wind energy, and extreme storms of all kinds can wreak havoc on transmission and distribution lines, and other energy-related assets. Therefore, having accurate and constantly updated weather information is vital to power companies. “First and foremost, utilities need to understand as best as possible the forecast of the environmental resources that are supplying these generation sources. It’s ultra-critical, because even small, slight changes in wind speed or solar radiation can have pretty substantial impacts as far as the capacity factor that a renewable generator is operating at,” Nic Wilson, director of product management for weather and climate risk with DTN, said as a guest on The POWER Podcast. Wilson highlighted some of the weather-related applications that utilities are integrating into their operations. “One of the focal points for DTN is working with utility emergency preparedness teams in order to help them better understand and forecast at-risk weather environmental hazards that are going to impact their overhead distribution operations, and understanding and communicating appropriately the outage impact risks,” he said. “Another application is asset inspection,” said Wilson. “After a storm goes through, how does the utility prioritize where it’s going to do inspection along its lines for potential damage?” One way could be using DTN’s tools. Wilson suggested, for example, a company responsible for the operations and maintenance of wind farms could use DTN data to identify turbines that may have experienced blade damage during a weather event. With that insight, the company could proactively inspect for compromises to the fiberglass blades before the damage turned catastrophic. Load forecasting is another important use case for DTN’s data. Many things must be considered to develop load forecasts including historical trends and current events. Wilson suggested temperature, precipitation, cloud cover, time of day, time of year, and more will affect not only the renewable energy production, but also demand for electricity. With accurate forecasts, power companies can plan appropriately to take advantage of any given situation. If they anticipate a surplus, units could be taken offline for scheduled maintenance, but if the supply is expected to be tight, they can issue orders to increase plant readiness. “Then, there’s some emerging applications, such as capital planning, where utilities are trying to climate-adjust the age, and understand the performance and condition monitoring of their assets in order to prioritize resiliency investments,” Wilson said. DTN’s products are constantly being refined too. Wilson said artificial intelligence and machine learning are behind many of the improvements. “We are consistently doing what we call retraining. So, as new data becomes available from the utility, whether that’s outage management system data, or condition monitoring information, or satellite- or LIDAR [light detection and ranging]-derived vegetation datasets, we’re incorporating that into our models and updating them as frequently as possible in order to ensure that our predictions are as representative of the current environment as possible,” he said. Wilson said DTN is making some forays into climate modeling and trying to understand how different environmental factors of interest to utilities are going to evolve in not only the next three to six months on a seasonal basis, but also out to 30 years in the future. This is important information for power companies because they are often making investments with a 50-year time horizon in mind.

The U.S. Department of Energy (DOE) defines environmental justice as: “The fair treatment and meaningful involvement of all people, regardless of race, color, national origin, or income, with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies.” It says “fair treatment” means that no population bears a disproportionate share of negative environmental consequences resulting from industrial, municipal, and commercial operations or from the execution of federal, state, and local laws; regulations; and policies. “Meaningful involvement,” meanwhile, “requires effective access to decision makers for all, and the ability in all communities to make informed decisions and take positive actions to produce environmental justice for themselves,” according to the DOE. Environmental justice (EJ) has become a very important consideration when it comes to siting and/or expanding energy projects, including power plants. While many people associated with the power industry tend to focus on the benefits provided to communities when a project is developed, such as well-paying jobs and an increase in the tax base, people in the affected community may have a different view. They may be more focused on the negative effects, which could include an increase in harmful emissions, water usage, and heavy-haul traffic. “Communities are weighing the pros and cons of having industry there—having a job creator—and that, of course, generating additional economic activity. On the flip side, there are actual or perceived environmental or health issues,” Erich Almonte, a senior associate with King and Spalding, said as a guest on The POWER Podcast. King and Spalding is a full-service law firm with more than 1,300 lawyers and 23 offices globally, including a large team focused on energy-related matters. “It’s important to note that there really isn’t any ‘Environmental Justice Law.’ What we have instead are a use of current statutes and regulations that were perhaps designed for something else to try to achieve environmental justice ends,” Almonte said. The impact EJ could have on a project is quite substantial. “A company could meet all of its environmental permitting requirements, but still have a permit denied, if there were disparate impacts that weren’t mitigated properly, under Title VI of the Civil Rights Act,” Almonte explained. “This came out in a guidance document in April 2022, and since, it’s featured a couple of times in subsequent guidance documents that the administration has put out,” he added. While Almonte said he wasn’t aware of a permit being denied in that fashion to date, it’s a major consideration for companies when planning projects. Another potential show-stopper could be trigger through Section 303 of the Clean Air Act. This section provides “emergency powers” to the Environmental Protection Agency (EPA). “When there’s an environmental threat that poses an imminent and substantial endangerment to the public, or to the environmental welfare, then EPA can essentially stop that activity or file a lawsuit against it,” Almonte explained. “This is true even if the activity that’s causing the supposed endangerment is allowed by the permit.” According to Almonte, the EPA has only used this authority 14 times in the past five decades, but four of those occurrences have been in the past two years. This suggests it could become a regular tool used by the administration to achieve its EJ goals.

While power outages are not uncommon in the U.S., widespread blackouts that last more than a couple of hours are pretty rare. However, this summer marks the 20th anniversary of one of the most significant blackouts in North American history. The incident didn’t just affect the U.S., but also major parts of Canada. The blackout occurred on Aug. 14, 2003. The History Channel reports it began at 4:10 p.m. EDT, when 21 power plants shut down in just three minutes. Fifty million people were affected, including residents of New York City, Cleveland, and Detroit, as well as Toronto and Ottawa, Canada, among others. Although power companies were able to resume some service in as little as two hours, power remained off in other places for more than a day. The outage stopped trains and elevators, and disrupted everything from cellular telephone service to operations at hospitals and traffic at airports. “It was close to quitting time in the afternoon, and given the warm weather in the middle of the summer and thunderstorm season, our system was holding up well. I was looking forward to actually leaving on time for a change,” Paul Toscarelli, senior director of Electric Transmission and Distribution (T&D) Operations for the Palisades Division with Public Service Electric and Gas (PSE&G), New Jersey’s largest utility, said as a guest on The POWER Podcast. Toscarelli was an engineer assigned to one of PSE&G’s regional distribution divisions at the time and was in the distribution dispatch office when the incident occurred. He recalled the event quite vividly. “We were coming up around the second anniversary of 9/11, as I recollect, and just about everyone’s gut feel—instinctive feel—was this was another kind of terrorist attack,” Toscarelli said. “Looking back at it, it was very strange to recollect how relieved we were to find out it was just a widespread system outage of epic proportions.” Of the 750,000 PSE&G customers that lost power that day, nearly three-quarters were back online within five hours and virtually all had service by noon the next day. PSE&G said diversification and design protections helped to contain the outage, and the company was safely able to reenergize the system circuit by circuit. “The industry learned a lot about the electric system vulnerabilities,” said Toscarelli. Based on studies of the incident, the North American Electric Reliability Corporation (NERC) enhanced its standards in an effort to prevent future blackouts. Since the 2003 blackout, PSE&G has spent billions of dollars to further enhance the reliability and resiliency of its T&D systems with the aim of mitigating future outages. In fact, the company’s planned capital expenditures this year are the largest in the utility’s history—more than $3.5 billion. Among the projects PSE&G expects to complete in 2023 is a Newark Switch Rebuild Project. The Newark Switching Station is the heart of the company’s Newark T&D network. The $350 million project will modernize aging infrastructure that was put into service in 1957. Another example is the $550 million Roseland-Pleasant Valley Project, which was completed in May and was one of PSE&G’s largest transmission projects to date. The 51-mile undertaking replaced transmission facilities that were, on average, about 90 years old. “Infrastructure continually ages. It’s our job as the stewards of our system to monitor the usage of our equipment, inspect it, maintain it, and replace it where it’s deemed necessary, in a timely manner, and continuously repeat that process,” said Toscarelli. “We have an asset management model that involves risk assessment and risk scoring, and it lets us stay in the forefront of this.”

In 2021, Idaho National Laboratory (INL) Director John Wagner set a lofty goal for the lab to achieve net-zero carbon emissions within 10 years. An uninformed observer might think that would be an easy task for an organization as focused on energy as INL, but it’s important to recognize that the lab is spread over nearly 900 square miles—about three-quarters the size of the state of Rhode Island. To shuttle the lab’s nearly 5,400 employees everywhere they need to go across that vast territory, INL has a fleet of about 85 motor coaches with an operating schedule that runs 24 hours a day, seven days a week. With all the transportation and 357 buildings to heat and cool throughout the year, achieving net-zero is a significant challenge. Jhansi Kandasamy, INL’s net-zero program director, explained that more than half of the lab’s carbon emissions come from purchased electricity. That means INL has to work with Idaho Power to cut much of its emissions. “Probably 60 to 80% is already pretty clean—carbon-free—because they have hydro as a majority electricity generation,” Kandasamy said as a guest on The POWER Podcast, but that still leaves a fairly large gap to fill. “With my background in nuclear and nuclear being dependable, secure, 24/7, we’ve worked with Idaho Power to say, ‘We’d like to include nuclear as the generation,’ ” Kandasamy said. “If we accomplish that—if we get nuclear—that addresses the 54% of carbon emissions that we get from purchasing electricity. Without doing anything else, we would have reduced our carbon emissions by 70%.” The Carbon Free Power Project, spearheaded by Utah Associated Municipal Power Systems (UAMPS), with NuScale Power’s VOYGR small modular reactor technology at its heart, seems like a logical fit for Idaho Power’s needs. The six-module plant will be built on INL property. Kandasamy said INL helped get some potential project partners, including folks from UAMPS, NuScale, Idaho Power, Idaho Falls Power, and the Department of Energy (DOE), in a room to talk about the project and what needed to be done to ensure it is operational within the next decade. “It’s a collaboration effort instead of competition. It’s all collaboration—getting all the people that are the experts in the room and kind of working through it. And it’s been great in that they’re all coming up with these different ideas,” she said. In addition to motor coaches, INL also has more than 600 other vehicles in its transportation fleet. Kandasamy suggested there are plans to electrify much of INL’s fleet, as well as adding some hydrogen-fueled vehicles and using carbon-free fuels, such as R99 (renewable diesel), in others, which will all help to cut carbon emissions. Still, getting the vehicles poses a challenge. INL is required to source its vehicles through the DOE, and the DOE’s supply of electric and hydrogen-fueled models is lacking. “The Executive Order says by 2027 we need to have all of our light-duty vehicles transition to electric. That’s not far away. We have 240 vehicles—light-duty vehicles—that we need to transition. We’ve gotten 24,” Kandasamy said. Yet, employees may be the real key to success. Kandasamy said the staff at INL has really gotten behind the initiative. “The big push is really the cultural shift across the entire laboratory. So, the communication becomes a really huge part of saying, ‘Here’s what we’re doing for each scope. Here’s how each of the employees contributes to getting us to net-zero,’ ” she said. “We’ve been putting in all these communications about how we’re transitioning. The other part is for the employees to tell their story on how they are achieving net-zero,” said Kandasamy. “That has been huge. Now, it’s like, everybody wants to have their story. So, they start talking about how they are transforming in their personal life, as well as how they’re commuting to work, and so on, with net-zero stories.”