Duke Energy said its goal is to ensure energy reliability for its customers as strong economic development successes and population growth power the Carolinas’ energy needs.

The Bad Creek pumped storage facility is located in Salem, S.C. It came online in 1991 and is the largest “battery” on the company’s system, according to a release. The units were upgraded in phases, adding 80 MW of capacity to each new pump turbine. Unit 2 was completed in 2020, Unit 1 was completed in 2021, Unit 3 was completed in 2023 and Unit 4 was completed in April 2024.

“This investment in Bad Creek demonstrates our commitment to improving reliability across the Carolinas. Pumped storage technology gives us operational flexibility, allowing us to store energy and then deploy that energy when customer demand is highest,” said Preston Gillespie, executive vice president and chief generation officer and enterprise operational excellence. “Expanding our energy storage capabilities is just one of the many steps we are taking in the next phase of our energy transition.”

Duke Energy is working to extend the Federal Energy Regulatory Commission operating license of the Bad Creek pumped hydro storage facility, which is set to expire in 2027.

In addition to this upgrade project, Duke Energy is evaluating the potential to add a second powerhouse at Bad Creek that would further help Duke Energy add capacity as well as address increasing system variability, from the growth of solar and customer usage, in a reliable and affordable way. If pursued, the second powerhouse could be in-service as earlier as 2034.

“From population growth to the expansion of manufacturing and other major economic development wins, the Carolinas are booming,” said Mike Callahan, Duke Energy’s South Carolina president. “We must have a diverse energy mix to account for this growth on the coldest winter nights and the warmest summer days. We continue to look at solutions like expanding Bad Creek to make sure the power is there when customers need it, and it is as affordable as possible – providing certainty as they go about their daily lives.”

Expanding operations at Bad Creek also provides significant economic benefits of $7.3 billion to South Carolina, as the state benefits from construction and general infrastructure activity, by 2033.

Duke Energy Carolinas, a subsidiary of Duke Energy, owns 20,700 MW of energy capacity, supplying electricity to 2.9 million residential, commercial and industrial customers across a 24,000-square-mile service area in North Carolina and South Carolina. Duke Energy is headquartered in Charlotte, N.C. The company’s electric utilities serve 8.4 million customers in North Carolina, South Carolina, Florida, Indiana, Ohio and Kentucky, and collectively own 54,800 MW of energy capacity.

Duke Energy is executing an ambitious clean energy transition, keeping reliability, affordability and accessibility at the forefront as the company works toward net-zero methane emissions from its natural gas business by 2030 and net-zero carbon emissions from electricity generation by 2050. The company is investing in major electric grid upgrades and cleaner generation, including expanded energy storage, renewables, natural gas and nuclear.

This contrasts with last year, when U.S. hydropower generation fell to its lowest since 2001.

Northwest and Rockies

More hydropower is generated in the northwest and Rockies than any other region of the U.S. In 2023, 43% of all U.S. hydropower generation occurred in this region. However, last year’s hydropower output was the region’s lowest since at least 2010. Water supply, particularly in Washington and Oregon, was affected by a May heatwave that quickly melted the snowpack and reduced water supply for the rest of the year.

On April 4, the National Oceanic and Atmospheric Administration’s Northwest River Forecast Center (NWRFC) released its latest water supply forecast for the Pacific Northwest, which is part of the larger northwest and Rockies region. The NWRFC forecasts normal to more-than-normal water supply in the southern part of the region, around the Snake River Basin, and normal to less-than-normal water supply in the northern part by the Upper Columbia River Basin.

Because water supply and subsequent hydropower generation can vary widely from year to year, EIA uses these NWRFC forecasts as inputs to the STEO model. EIA expects 106 billion kWh of hydropower this year to be produced in the northwest and Rockies, or 3% more than in 2023.

EIA expects hydropower to account for 29% of the northwest and Rockies region’s electricity generation this year, and the increased output from hydropower resources and non-hydro renewables will reduce generation from natural gas and coal.

Southeast

The largest regional increase in hydropower this year comes from the southeast region, defined as the SERC Reliability Corporation. EIA expects hydropower generation in the southeast to increase by 4 billion kWh this year compared with last year. This region includes Alabama, Tennessee and North Carolina, which combined account for about 10% of total hydropower generating capacity in the U.S.

EIA expects hydropower to account for 5% of electricity generation in the southeast in 2024. Natural gas and nuclear are the two largest sources of electricity generation in the southeast, and EIA expects both to increase in 2024. In particular, nuclear generation will increase after the Vogtle Unit 4 generator in Georgia starts providing power to the grid during the second quarter of 2024. EIA expects these increases in natural gas, nuclear and hydropower to reduce the use of coal for electricity generation in the region.

California

California’s water supply is susceptible to drought. After a very wet year last year, annual hydropower generation increased by more than 80%, from 17 billion kWh in 2022 to 31 billion kWh in 2023. EIA expects similar hydropower generation in California this year.

The California-Nevada River Forecast Center expects California to have a near-to-above normal water supply. Water reservoirs in California are also mostly above their historical averages for this time of year. In addition, snowstorms between the end of January and end of March increased snowpack across the Sierra Nevada mountain range.

Non-hydro renewables, mainly solar and wind, are the most significant component of change in California’s electricity generation mix. EIA expects California’s non-hydro renewables to increase by 5 billion kWh in 2024.

Rest of the U.S.

EIA expects hydropower to increase in nearly every region, with notable increases in New York and the central region (Southwest Power Pool or SPP). About 6% of U.S. hydropower capacity is located in New York, and EIA expects the state’s hydropower output to increase slightly, to 29 billion kWh.

The SPP region includes many of the states just east of the Rocky Mountains. In 2023, SPP’s hydropower output fell to 11 billion kWh, the least in at least a decade. EIA expects SPP’s hydropower will increase to 14 billion kWh in 2024.

OPG’s hydroelectric stations in Niagara Falls have generated clean, reliable and affordable electricity for Ontario for more than a century, powering the province’s growth and helping establish the low-carbon electricity system we enjoy today.

OPG’s Niagara Operations encompass five hydro generating facilities, including the Sir Adam Beck I and II GS, Sir Adam Beck Pump GS, and DeCew I and II GS. Each year, these plants meet about 9% of Ontario’s energy needs.

Now, this fleet of stations is set to undergo a multi-year refurbishment to keep producing reliable power for Ontario’s electrification and future growth, while supporting OPG’s net-zero goals.

In April, OPG announced it is partnering with General Electric Vernova to complete the first phase of the $1 billion refurbishment project. Starting in 2025 and lasting over 15 years, GE will refurbish up to 25 units at the Sir Adam Beck I and II stations, increasing these plants’ capacity by up to 50 MW.

This work will build on OPG’s long relationship with GE, which manufactured the original generating units still in operation at some of OPG’s sites in Niagara. It will also create more than 200 highly skilled jobs in the Niagara region.

OPG is also developing refurbishment plans for its DeCew I and II stations.

“Upgrading and optimizing OPG’s renewable generation workhorses like the Sir Adam Beck complex is crucial to support the growing demands of electrification and a thriving economy,” said Ken Hartwick, OPG’s president and chief executive officer. “Through this refurbishment, these hydropower stations will build on their remarkable legacy and continue to produce the low-cost, reliable electricity Ontarians need for decades to come.”

The initiative is part of OPG’s commitment to invest in updating and upgrading its hydroelectric fleet. This wider turbine-generator refurbishment program will result in the renewal of 48 OPG hydro stations to extend station life, while also increasing efficiency and, in some cases, generating output.

At Niagara, the refurbishment of older generating units will involve removing some key components, including the turbine runners. These parts will be replaced with newer, more efficient designs that will require less water to generate power.

OPG’s Sir Adam Beck I GS went into service in 1922 and was considered the largest hydro plant in the world at the time. In 1954, its sister station, the 16-unit Sir Adam Beck II GS, went into service and remains Ontario’s largest hydro station by generating capacity.

“Currently, the Dniprovska HPP is not working. Today, we cannot disassemble all the rubble, as both the floor and the walls with the crane beams leaned towards the engine room. It is necessary to dismantle the upper part of the mashzal [turbine hall] in order to get to the lower part.

“On Saturday, March 23, we held a meeting with the head of Zaporizhzhya OVA, so that emergency services specialists with equipment for dismantling the ceiling could join the liquidation of the consequences.

“Together with the relevant services, we will try to restore the bridge crossing as soon as possible.

“The situation at the Dnipro HPP dam itself is under control. There is no threat of a breakthrough. The extent of damage requires a thorough examination. However, it is already known for certain that the restoration of the station will require a lot of money and a long time.”

Per Ukrhydroenergo, on the morning of March 22, from 04:10 to 07:00, Russian rockets attacked the Dnipro hydroelectric plant in the city of Zaporizhia. Emergency services and emergency services quickly arrived at the station. The fire at the facility was contained around 8:00.

As a result of several missile strikes at the Dniprovskaya HPP, electrical equipment and hydraulic units were damaged, and a significant number of construction structures were damaged. The station is not working.

There are no victims among DniproHES employees.

Ukrhydroenergo said it was implementing all possible measures to pass water downstream of the Dnipro plant.

Hydropower plays a key role in regulating peak loads. Ukraine has lost more than 1,000 MW of regulating capacity in terms of the operation of the energy system. Compensating mechanisms will be found for energy supply to consumers. However, for the energy system today, in the situation of constant terrorist attacks on energy facilities, these are serious losses, Ukrhydroenergo said.

Discussions are under way with international partners and financial institutions to attract assistance in the restoration of Dnipro HPP.

“Ukrhydroenergo draws the attention of the international community to the need for quick decisions and decisive actions. The destruction of the Kakhovskaya HPP and the terrorist attack on the Dnipro HPP require the Russian side to be held accountable for targeted attacks on Ukrainian infrastructure,” according to a release.

Just last week, Hydro Review reported that Dnipro was one of three Ukrhydroenergo hydroelectric projects to be rehabilitated under a memorandum of understanding with the European Investment Bank.

This is the key message of a new report, Hydropower Investment Landscape, developed by the National Renewable Energy Laboratory with support from Deloitte.

Globally, hydropower is the third largest source of electricity after coal and natural gas. As the world continues to transition away from fossil fuels, low-carbon sources of firm power will be increasingly critical to maintain the electric grid’s reliability. Hydropower already serves as a force multiplier for other renewable energy sources, and the value of this reliability and flexibility will continue to increase.

With the Bipartisan Infrastructure Law and Inflation Reduction Act offering financial support for clean energy projects, new hydropower and pumped storage projects could offer increasingly attractive investment opportunities.

The new report provides a comprehensive analysis of the risks and opportunities for investing in small- to medium-sized hydropower and pumped storage projects. Key findings from the study, which was funded by the U.S. Department of Energy’s (DOE’s) Water Power Technologies Office (WPTO), include:

Medium-sized projects offer significant opportunities for low-impact hydropower development. The medium-sized project pipeline includes projects that would constitute a total capacity of more than 1 GW and involves capacity additions, non-powered dam retrofits, hydropower generation in conduits, pumped storage, new stream-reach development and hybrid projects that combine multiple renewable technologies.

New technology innovations and the variety of sites at which hydropower could be developed present potential opportunities for future investment. Top areas of interest include modular conduit hydropower, non-powered dam resources, hybrid plant confirmation and closed-loop pumped storage innovation.

In the past decade, developers have begun designing and deploying small modular conduit systems, which can be manufactured offsite and assembled onsite. This approach can decrease construction costs, reduce project timelines and increase flexibility to expand the size of a hydropower system in the future. One example highlighted in the report of a company pursuing modular conduit hydropower is Emrgy, which raised several million dollars in private investment.

Because about 97% of U.S. dams do not have power-generating infrastructure, non-powered dams represent an attractive development opportunity with a potential capacity of 2 GW or more within the medium-sized range.

Using hydropower in a hybrid configuration with other renewables and battery storage can unlock new revenue streams by providing power during peak demand or ancillary services, such as the ability to adjust quickly to ensure grid reliability.

Closed-loop pumped storage systems feature two reservoirs that are not connected to a naturally flowing water feature like a river. These projects, which can offer siting flexibility, account for the majority of pumped storage projects in the pipeline. These projects would be the first closed-loop facilities in the U.S.

Investors surveyed for this study generally expressed the greatest level of interest in supporting capacity additions at existing facilities. With a connection to the grid already established, these facilities offer critical opportunities to increase clean energy production.

Overall, innovations in hydropower are driving the industry toward smaller, more modular and flexible solutions that can be more easily scaled and replicated.

Of course, there are challenges associated with hydropower projects, which are generally well known in the industry. Risks like financing for early-stage development, long permitting and licensing timelines, supply chain constraints, and more are important considerations but can also be addressed. The report includes several suggestions for addressing challenges in the industry to help increase investment. They are:

• Provide financing, funding and support for early-stage development
• Support improved market-based incentive signals for hydropower and pumped storage
• Support transparent and efficient permitting and licensing processes
• Support new, innovative research on reducing deployment time and costs
• Clarify new legislation and regulations and conduct outreach with developers and industry
• Increase awareness of new opportunities in hydropower and pumped storage

Published on Hydro Review.

This funding — made possible by the Bipartisan Infrastructure Law — will support community-driven energy projects in rural and remote regions, such as building microgrids for health centers or constructing a new hydroelectric facility on Tribal lands. The announcement underscores the Biden-Harris Administration’s commitment to building an inclusive and equitable clean energy future that creates safer, more resilient communities, enhances Tribal energy sovereignty, strengthens energy security, and delivers new economic opportunities, according to a release.

“President Biden firmly believes that every community should benefit from the nation’s historic transition to a clean energy future, especially those in rural and remote areas,” said U.S. Secretary of Energy Jennifer M. Granholm. “DOE is helping revitalize communities across America — ensuring thriving businesses, reliable access to clean energy, and exciting new economic opportunities, now and for generations to come.”

In line with President Biden’s Justice40 Initiative to advance energy and environmental justice, all 17 projects are located in or adjacent to disadvantaged communities that are disproportionally overburdened by pollution and historically underserved. The projects are part of DOE’s Energy Improvements in Rural or Remote Areas (ERA) program, which is managed by the Office of Clean Energy Demonstrations (OCED). The ERA program leverages DOE’s expertise in resilient energy solutions while recognizing the unique environmental, cultural and economic landscapes of rural and remote communities. At least 12 projects will support Tribal communities.

Each ERA selectee is required to develop and implement a comprehensive Community Benefits Plan (CBP) — which will be informed by early and meaningful community engagements in each region. As part of the department’s commitment to transparency, OCED will hold a series of national and regional virtual briefings to provide information on the selected projects, OCED’s approach to clean energy demonstrations, and opportunities for community engagement.

Before funding is issued, DOE and the selectees will undergo a negotiation process, and DOE may cancel negotiations and rescind the selection for any reason during that time. Lead applicants also may change during the award negotiations process. If awarded, OCED will evaluate these projects through a phased approach to project management that includes “go/no-go” decision points between each phase.    

Below are details on the four hydroelectric projects chosen:

Chignik Hydroelectric Dam and Water Source Project in Chignik Bay, Alaska, will receive a federal cost share of $7,270,000. The lead applicant is The Lake and Peninsula Borough. This project involves constructing a new run-of-the-river hydroelectric facility, replacing a 70+ year-old wooden dam that is at risk of failure. It aims to improve energy and water security as the current dam leaks frequently, also jeopardizing the community’s only stable source of clean water. The proposed 2.1 MWh hydroelectric facility aims to replace 100% of the community’s diesel consumption. It also plans to provide excess power for heating, electric vehicle charging, and expansion of local economic activities like tourism and fish processing. The Chignik Bay Tribal Council will own the facility and plans to sell power to local utilities for 80% of the avoided cost of fuel, reducing total electricity rates by an estimated 7%.

Old Harbor Hydroelectric Project in Old Harbor, Alaska, will receive a federal cost share of $10,000,000. The lead applicant is the Alutiiq Tribe of Old Harbor. This project plans to construct a run-of-river hydroelectric facility with a diversion structure, pipeline, powerhouse and electric transmission line. It is anticipated that the project will be capable of generating about 3,470 MWh of energy annually and offset diesel fuel use at the local power plant by 95%. Old Harbor is a remote Alutiiq Tribal village on Kodiak Island, about 50 air miles from the nearest social services in the City of Kodiak. There are nearly 200 residents and 83% are Native Alaskans who rely on a subsistence diet. According to the Denali Commission, 88% of residents live below the federal poverty line, with a median household income of $13,181, and experience disproportionally higher cost energy bills.

Thayer Creek Hydroelectric Project in Angoon, Alaska, will receive a federal cost share of $26,920,000. The lead applicant is Kootznoowoo Inc. (KI). This project encompasses an 850-kW, run-of-river hydroelectric project that has the potential to supply three times the community’s electricity needs, providing additional power for heating, fish processing, electric vehicle charging and tourism. KI is the Alaska Native Village Corporation for the community of Angoon, the ancient home of the Tlingit Xóotsnoowe’di people, with a population of 357. In 1980, as part of the Alaska National Interest Lands Conservation Act (P.L. 96-487), KI and Angoon gave up rights to their ancestral land to establish the Admiralty Island National Monument. As compensation, KI was granted the right to develop Thayer Creek Hydroelectric. However, the initial agreement did not include funding, and the Tlingit people are still entirely reliant on imported diesel, which leads to energy costs that are 4.5 times the national average. This project aims to provide an avenue to address historical oversight and support access to reliable and affordable energy for the Tlingit people.

Yakama Tribal Solar Canal & Hydro Project on the Yakama Indian Reservation, Wash., will receive federal cost share of $32,000,000. The lead applicant is The Confederated Tribes and Bands of the Yakama Nation. This project aims to convert inefficient, open-water irrigation canals into a solar and micro-hydropower irrigation system. This system could conserve up to 20% more water and help energy-burdened residents save up to 15% on their utility bills. Additionally, the project team plans to build solar panels on land the Tribe knows does not risk disturbing cultural resources. It is anticipated that deploying solar technologies will increase the Yakama Nation’s renewable power supply, while improving its energy resilience and reliability. Improvements in irrigation efficiency could also benefit grazing and irrigated agriculture, the area’s key economic drivers.

The Hydroelectric Efficiency Improvement Incentive payments are administered by the Grid Deployment Office and funded by the Bipartisan Infrastructure Law.

“Hydropower is the nation’s prototype of renewable power playing an important role in deploying affordable and reliable electricity across the country,” said U.S. Secretary of Energy Jennifer M. Granholm. “Thanks to the President’s Investing in America agenda we are maintaining and expanding our hydropower fleets, helping reduce costs of operation and ensuring American workers continue to drive the nation’s clean energy transition.”

This incentive program received robust industry interest, DOE said, with applications requesting a total of $192 million in federal support. Using all available funding directed to the incentive, the selected improvements are anticipated to generate $468 million in combined federal and private investment. With an average selectee facility age of 75 years, these upgrades will contribute to the continued operation and longevity of hydroelectric assets. 

Hydropower accounts for 27% of renewable electricity generation in the U.S., as well as 93% of all utility-scale energy storage capacity. In addition, the U.S. hydroelectric fleet and their associated reservoirs play an important role with respect to water supply, flood control and recreation. More efficient use of water for electric generation can only enhance the fleets’ ability to more effectively manage the nation’s waters.

Investments under the Hydroelectric Efficiency Improvement Incentives will support the continued operation of the U.S. hydropower fleet and ensure a more reliable and resilient electric grid system. The owners or operators of hydroelectric facilities, including pumped storage hydropower, receiving the efficiency incentives announced will make capital improvements that improve their facility’s efficiency by an average of 14% with a statutory minimum of 3% improvement per facility. Investments include upgrades to facility turbines and generators, as well as improvements to water conveyance structures, to increase efficiency. 

The 46 selected projects are in California, Colorado, Connecticut, Georgia, Idaho, Maine, Massachusetts, New Hampshire, New York, North Carolina, Oklahoma, Oregon, Pennsylvania, Rhode Island, Tennessee, Vermont, Virginia, Washington and West Virginia.

The Hydroelectric Efficiency Improvement Incentives are one of three incentive offerings funded by the Bipartisan Infrastructure Law to maintain and enhance existing hydroelectric facilities and ensure generators continue to provide clean, renewable electricity, while improving dam safety and reducing environmental impacts. Other program offerings include Hydroelectric Production Incentives provided to qualified hydroelectric facilities for electricity generated and sold and Maintaining and Enhancing Hydroelectricity Incentives provided to existing hydroelectric facilities for capital improvements directly related to grid resiliency, dam safety and environmental improvements.

“Hydroelectric power generated by the Columbia River System is the foundation of the electric grid in the Northwest,” Matheson told the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security. “It is the key to electric reliability, economic prosperity and public safety. Put simply, hydropower is the reason why the lights stay on in the Pacific Northwest. Breaching or chipping away at the lower Snake River dams pulls a critical, dispatchable, carbon-free renewable resource out of the mix at a time when electric demand continues to grow.”

The U.S. Army Corps of Engineers operates four run-of-river dams and locks on the lower Snake River in Washington that together provide 1,000 average MW of capacity and up to 3,033 MW of capacity at their peak. The dams, constructed between 1955 and 1961, are Ice Harbor, Lower Monumental, Little Goose and Lower Granite. Construction and operation of the dams altered the physical, chemical, hydrological and biological processes in the river, and all species of salmon that use the Snake River are listed as threatened or endangered under the Endangered Species Act. With salmon being “central to culture and wellbeing in tribal nations throughout the Pacific Northwest,” there have been discussions about breaching the dams.

Matheson testified before the panel about a legal settlement reached by the Biden administration, environmental groups, and tribal and state governments over the federal government’s operation of the lower Snake River dams. Those dams supply hydropower to 55 coops in eight western states served by the Bonneville Power Administration.

In a 2021 lawsuit, plaintiffs charged that the dams are threatening the survival of endangered salmon. The settlement supports breaching the dams and replacing them with other types of renewable energy.

Although it would take an act of Congress to breach the dams, the settlement agreement undermines their operation, Matheson said. “While the dams are not physically breached by the agreement, the mandated spill and flow requirements chip away at the economic viability of the dams with the goal of making them uneconomical to operate,” he said.

It won’t just be electric power providers who will be hurt, Matheson added. “It will adversely impact agricultural producers, the transportation sector and economically disadvantaged rural communities.”

For decades, the hydropower provided by the Columbia River System has fueled economic growth in the region, Matheson said. “The region’s hydropower is a major attraction for economic investment in the Northwest. Companies locate their operations in the Northwest to take advantage of the reliable, affordable and carbon-free hydropower. Small family-owned businesses, electric vehicle manufacturers, agricultural producers and tech giants have all based operations in the Northwest because of hydropower.”

Although power generation within the BPA system includes wind, solar and biomass, those sources are dwarfed by hydropower, which makes up nearly 80% of capacity, Matheson said.

The settlement envisions replacing lower Snake River dam hydropower with other renewables. Matheson noted that “hydropower is not interchangeable with wind or solar. Hydropower is a dispatchable resource, meaning it can be adjusted to meet demand and is ever-ready as a source of baseload power. Wind and solar, on the other hand, are unpredictable.”

He also denounced the exclusion of co-ops and other electric utilities in the settlement talks. “No one from the electric consumer sector was included in the final closed-door negotiations that led to this settlement,” Matheson said. “The people that keep the lights on were purposefully kept in the dark…This settlement process sets a dangerous precedent of exclusion.”

Originally published in Hydro Review.

Why? “What got us to where we are is not going to get us where we need to be,” said Brian Roth, vice president O&M with PROENERGY. The company is a third-party solutions provider for the energy industry.

How does this connect to remote power plant operations? Divergent thinking, which is a process used to create ideas by exploring many possible solutions, is needed to help address challenges the industry is facing now and will be facing in the future. And yet convergent thinking, which focuses on reaching a single well-defined solution to a problem, often causes us to shut down potential solutions. Roth encouraged a focus on separating convergent thinking from divergent thinking within organizations. Thinking about a challenge without taking into account constraints encourages divergent thinking.

With this encouragement setting the stage, Roth discussed the difference between remote dispatch, which is a subset of remote operations that focuses on start/stop energy monitoring, remote operations (physically controlling a unit) and remote monitoring (and diagnostics) or RM&D. The latter involves looking at data trending, setting more narrow bands to get alarms earlier than the control system and enabling plant personnel to take action.

He was frank when sharing the value of remote operations centers (ROC), including pros and cons. The pros list is substantive: better coordination and resource allocation, safety enhancements, and improved reliability and sustainability. But the cons must also be acknowledged, with Roth highlighting two in particular: technology differences make it more challenging, and the importance of communication without the ability to meet face-to-face can’t be overlooked. In addition, it is easy to overload ROC operators with information.

Roth pointed out that tools don’t solve problems. With RM&D, the aspiration is to detect small anomalies and then do something with that information before there’s a problem. RM&D can empower a utility to reach peak efficiency using predictive technology. RM&D systems can deliver prescriptive alerts to operator, which Roth called alarms with recommendations.

Now, coming back to the concept of divergent thinking: Early in the session, Roth asked attendees: “Can a single operator run 100 units?” The knee-jerk answer to that question might be no, and in that case you would be thinking convergently, not divergently. Putting aside current technology and personnel constraints, your answer should change. Roth said at this time, the company has an ROC where a single operator runs 32 units, so taking today’s constraints out of the equation could perhaps see the aspirational goal of 100 units reached.

To start identifying recommendations for accomplishing this vital task, the Accelerating the Energy Workforce Development Workshop was held Monday at POWERGEN International 2024. Outcomes from the workshop, facilitated by the nonprofit U.S. Women in Nuclear organization, will help in the creation of a report offering recommendations on developing a diverse, equitable, and inclusive workforce as energy industries gear up for rapid expansion.

What is exactly the size and scope of this challenge? Representatives of Idaho National Laboratory, who moderated the workshop, set the stage for what the industry faces.

It is well-known that diverse perspectives allow companies to craft more effective solutions. Despite this, and even though half of the global energy workforce is in clean energy, only 26% of the energy workforce is female and 24% minorities. One major challenge identified when it comes to staffing for nuclear energy is a small applicant pool, with many of those applicants not having the technical skills needed. In addition, the need for jobs in nuclear energy is quite diverse, encompassing regulatory, construction, manufacturing/supply chain, wholesale trade, professional and business services, and more.

The goal of this small and very interactive roundtable discussion was to help attendees identify ways to develop a diverse pipeline and ensure gender equity and a growth plan for the industry.

Four expert panelists addressed the situation from three key angles: readiness, recruitment, and retention.

Concerning readiness, Kimberly Cook-Nelson, executive vice president of nuclear operations and chief nuclear officer with Entergy, said her company employs a variety of initiatives, starting with working as early as the elementary school level in the communities it serves, to reach the potential future energy workforce. As stated above, employees needed for the industry include accountants, human resources, electricians, and more as well as engineers. At the university level, Entergy’s efforts include providing $7 million in grants and scholarships to historically black colleges and universities and working on a radiation protection program at a Mississippi university that has translated to 19 employees for the company.

On the topic of recruitment, Erin Hultman, vice president of member and corporate services and chief financial officer with the Nuclear Energy Institute, said it is important to understand the size and scale of the challenge. Among NEI members alone, which represent just over half of all nuclear production in the U.S., it is anticipated nuclear production will more than double over the next 10 to 15 years, based on plans (not aspirations). In addition, about 300 small modular reactors may be installed, with “everything that goes along with that,” Hultman said.

Finally, regarding retention, Nicole Hughes, director, North America Nuclear at Thomas Thor, pointed out that while developing a career path for employees is nice, one caveat is it’s not an approach that works for everyone. Kara Temple, MBA, member of the board of directors at Allied Power, shared her own experience with regard to retention in the industry. She recalled working at a company where she took the initiative to set up three rotation opportunities for herself with office directors, only to have her boss deny her request to cross-train, three times. Temple said it’s important to create a holistic experience so employees can try different things, even potentially offering them the opportunity to move to different locations within the company so they can find their best fit.

Hughes left attendees with a memorable impression of the challenges, and how changing the way they’re viewed can yield results: “The rainbow-colored unicorn you’re looking for might not be available. Maybe a zebra might be a better fit for you,” she said.