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Infrastructure Security Algorithm prioritizes cyber defense for power grids and critical infrastructure, mitigating ransomware, blackout risks, and cascading failures by guiding utilities, regulators, and cyber insurers on optimal security investment allocation.

Key Points

An algorithm that optimizes security spending to cut ransomware and blackout risks across critical infrastructure.

✅ Guides utilities on optimal security allocation

✅ Uses incentives to correct human risk biases

✅ Prioritizes assets to prevent cascading outages

Millions of people could suddenly lose electricity if a ransomware attack just slightly tweaked energy flow onto the U.S. power grid, as past US utility intrusions have shown.

No single power utility company has enough resources to protect the entire grid, but maybe all 3,000 of the grid's utilities could fill in the most crucial security gaps if there were a map showing where to prioritize their security investments.

Purdue University researchers have developed an algorithm to create that map. Using this tool, regulatory authorities or cyber insurance companies could establish a framework for protecting the U.S. power grid that guides the security investments of power utility companies to parts of the grid at greatest risk of causing a blackout if hacked.

Power grids are a type of critical infrastructure, which is any network - whether physical like water systems or virtual like health care record keeping - considered essential to a country's function and safety. The biggest ransomware attacks in history have happened in the past year, affecting most sectors of critical infrastructure in the U.S. such as grain distribution systems in the food and agriculture sector and the Colonial Pipeline, which carries fuel throughout the East Coast, prompting increased military preparation for grid hacks in the U.S.

With this trend in mind, Purdue researchers evaluated the algorithm in the context of various types of critical infrastructure in addition to the power sector, including electricity-sector IoT devices that interface with grid operations. The goal is that the algorithm would help secure any large and complex infrastructure system against cyberattacks.

"Multiple companies own different parts of infrastructure. When ransomware hits, it affects lots of different pieces of technology owned by different providers, so that's what makes ransomware a problem at the state, national and even global level," said Saurabh Bagchi, a professor in the Elmore Family School of Electrical and Computer Engineering and Center for Education and Research in Information Assurance and Security at Purdue. "When you are investing security money on large-scale infrastructures, bad investment decisions can mean your power grid goes out, or your telecommunications network goes out for a few days."

Protecting infrastructure from hacks by improving security investment decisions

The researchers tested the algorithm in simulations of previously reported hacks to four infrastructure systems: a smart grid, industrial control system, e-commerce platform and web-based telecommunications network. They found that use of this algorithm results in the most optimal allocation of security investments for reducing the impact of a cyberattack.

The team's findings appear in a paper presented at this year's IEEE Symposium on Security and Privacy, the premier conference in the area of computer security. The team comprises Purdue professors Shreyas Sundaram and Timothy Cason and former PhD students Mustafa Abdallah and Daniel Woods.

"No one has an infinite security budget. You must decide how much to invest in each of your assets so that you gain a bump in the security of the overall system," Bagchi said.

The power grid, for example, is so interconnected that the security decisions of one power utility company can greatly impact the operations of other electrical plants. If the computers controlling one area's generators don't have adequate security protection, as seen when Russian hackers accessed control rooms at U.S. utilities, then a hack to those computers would disrupt energy flow to another area's generators, forcing them to shut down.

Since not all of the grid's utilities have the same security budget, it can be hard to ensure that critical points of entry to the grid's controls get the most investment in security protection.

The algorithm that Purdue researchers developed would incentivize each security decision maker to allocate security investments in a way that limits the cumulative damage a ransomware attack could cause. An attack on a single generator, for instance, would have less impact than an attack on the controls for a network of generators, which sophisticated grid-disruption malware can target at scale, rather than for the protection of a single generator.

Building an algorithm that considers the effects of human behavior

Bagchi's research shows how to increase cybersecurity in ways that address the interconnected nature of critical infrastructure but don't require an overhaul of the entire infrastructure system to be implemented.

As director of Purdue's Center for Resilient Infrastructures, Systems, and Processes, Bagchi has worked with the U.S. Department of Defense, Northrop Grumman Corp., Intel Corp., Adobe Inc., Google LLC and IBM Corp. on adopting solutions from his research. Bagchi's work has revealed the advantages of establishing an automatic response to attacks, and analyses like Symantec's Dragonfly report highlight energy-sector risks, leading to key innovations against ransomware threats, such as more effective ways to make decisions about backing up data.

There's a compelling reason why incentivizing good security decisions would work, Bagchi said. He and his team designed the algorithm based on findings from the field of behavioral economics, which studies how people make decisions with money.

"Before our work, not much computer security research had been done on how behaviors and biases affect the best defense mechanisms in a system. That's partly because humans are terrible at evaluating risk and an algorithm doesn't have any human biases," Bagchi said. "But for any system of reasonable complexity, decisions about security investments are almost always made with humans in the loop. For our algorithm, we explicitly consider the fact that different participants in an infrastructure system have different biases."

To develop the algorithm, Bagchi's team started by playing a game. They ran a series of experiments analyzing how groups of students chose to protect fake assets with fake investments. As in past studies in behavioral economics, they found that most study participants guessed poorly which assets were the most valuable and should be protected from security attacks. Most study participants also tended to spread out their investments instead of allocating them to one asset even when they were told which asset is the most vulnerable to an attack.

Using these findings, the researchers designed an algorithm that could work two ways: Either security decision makers pay a tax or fine when they make decisions that are less than optimal for the overall security of the system, or security decision makers receive a payment for investing in the most optimal manner.

"Right now, fines are levied as a reactive measure if there is a security incident. Fines or taxes don't have any relationship to the security investments or data of the different operators in critical infrastructure," Bagchi said.

In the researchers' simulations of real-world infrastructure systems, the algorithm successfully minimized the likelihood of losing assets to an attack that would decrease the overall security of the infrastructure system.

Bagchi's research group is working to make the algorithm more scalable and able to adapt to an attacker who may make multiple attempts to hack into a system. The researchers' work on the algorithm is funded by the National Science Foundation, the Wabash Heartland Innovation Network and the Army Research Lab.

Cybersecurity is an area of focus through Purdue's Next Moves, a set of initiatives that works to address some of the greatest technology challenges facing the U.S. Purdue's cybersecurity experts offer insights and assistance to improve the protection of power plants, electrical grids and other critical infrastructure.

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Nova Scotia Power solar charge proposes an $8/kW monthly system access fee on net metering customers, citing grid costs. UARB review, carbon credits, rate hikes, and solar industry impacts fuel political and consumer backlash.

Key Points

A proposed $8/kW monthly grid access fee on net metered solar customers, delayed to Feb 1, 2023, pending UARB review.

✅ $8/kW monthly system access fee on net metering

✅ Delay to Feb 1, 2023 after industry and political pushback

✅ UARB review; debate over grid costs and carbon credits

Nova Scotia Power has pushed back by a year the start date of a proposed new charge for customers who generate electricity and sell it back to the grid, following days of concern from the solar industry and politicians worried that it will damage the sector.

The company applied to the Nova Scotia Utility and Review Board (UARB) last week for various changes, including a "system access charge" of $8 per kilowatt monthly on net metered installations, and the province cannot order the utility to lower rates under current law. The vast majority of the province's 4,100 net metering customers are residential customers with solar power, according to the application. 

The proposed charge would have come into effect Tuesday if approved, but Nova Scotia Power said in a news release Tuesday it will change the date in its filing from Feb. 1, 2022, to Feb. 1, 2023.

"We understand that the solar industry was taken off guard," utility CEO Peter Gregg said in an interview.

"There could have been an opportunity to have more conversations in advance."

Gregg said the utility will meet with members of the solar industry over the next year to work on finding solutions that support the sector's growth, while addressing what NSP sees as an inequity in the net metering system.

NSP recognized that customers who choose solar invest a significant amount and pay for the electricity they use, but they don't pay for costs associated with accessing the electrical grid when they need energy, such as on cold winter evenings when the sun is not shining.

"I know that's hit a nerve, but it doesn't take away the fact that it is an issue," Gregg said.

He said this is an issue utilities are navigating around North America, where seasonal rate designs have sparked consumer backlash in New Brunswick, and NSP is open to hearing ideas for other models of charges or fees.

The utility's suggested system access charge closely resembles one proposed in California, which has also raised major concerns from the solar industry and been criticized by the likes of Elon Musk, and has parallels to Massachusetts solar demand charges as well.

Although the "solar profile" of Nova Scotia and California is very different, with far more solar customers in that state, and in other provinces such as Saskatchewan, NDP criticism of 8% hikes has intensified affordability debates, Gregg said the fundamental issues are the same.

For those with a typical 10-kilowatt solar system, which generates around $1,800 of electricity a year, the new charge would mean those customers would be required to pay $960 back to NSP. That would roughly double the length of time it takes for those customers to pay off their investment for the panels.

David Brushett, chair of Solar Nova Scotia, said he relayed concerns from solar installers and others in the industry to Gregg on Monday. 

Brushett said the year delay is a positive first step, but he is still calling on the province to take a strong stance against the application, which has led to customers cancelling their panel installations and companies considering layoffs.

"There's still an urgency to this situation that hasn't been addressed, and we need to kind of protect the industry," he said Tuesday.

NSP's original application proposed exempting net metering customers who enrolled before Feb. 1, 2022, from the charge for 25 years after they sign up. But any benefit would be lost if those customers sold their home, and the exemption wouldn't extend to the new buyers, said Brushett.

Carbon offsets missing from equation: industry
Brushett said NSP "completely ignored" the fact that it's getting free carbon offset credits from homeowners who use solar energy under the provincial cap and trade program.

If the net metering system continues as is, NSP has said non-solar customers would pay about $55 million between now and 2030. That number assumes about 2,000 people sign up for net metering each year over the next nine years.

When asked whether those carbon emission credits were factored into the calculations for the proposed charge, Gregg said, "I don't believe in the current structure it is, but it's something that certainly we'd be open to hearing about."

Brushett said his group is finalizing a legal response to NSP's proposal and has already filed an official complaint against the company with the UARB.

Base charge on actual electrical output: customer
At least one shareholder in NSP parent company Emera is considering selling his shares in response to the application.

Joe Hood, a shareholder from Middle Sackville, said the proposed charge won't apply to his existing 11.16-kilowatt solar system, but if it did, it would cost him $1,071 a year.

"I am offended that a company I would invest in would do this to the solar industry in Nova Scotia," he said.

According to his meter, Hood said he pushed 9,600 kilowatt hours of solar electricity to the grid last year— some only for a brief period, and all of which was used by his home by the end of the year.

Under the proposed charge, someone with one solar panel who goes away on vacation in the summer would push all their electricity to the grid, and be charged far less than someone with 10 panels who has used all their own power and hasn't pushed anything.

"Nova Scotia Power's argument is that it's an issue with the grid. Well, then it should be based on what touches the grid," Hood said.

Far from actually making the system fair for everyone, Hood said this charge places solar only in the hands of the super-rich or NSP, with projects like its community solar gardens in Amherst, N.S.

Green Party suggests legislation update
Nova Scotia's Green Party also said Tuesday that Gregg's arguments of fairness are misleading, echoing earlier premier opposition to a 14% hike on rates.

The party is calling for an update to the Electricity Act that would "prevent penalizing any activity that helps Nova Scotia reach its emissions target," aligning with calls to make the electricity system more accountable to residents.

In its application, NSP has also asked to increase electricity rates for residential customers by at least 10 per cent over the next three years, amid debate that culminated in a 14% rate hike approval by regulators. 

The company wants to maintain its nine per cent rate of return.

NSP expects to earn $153 million this year, $192 million in 2023, and $213 million in 2024 from its rate of return. 

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France Nuclear Heatwave Restrictions signal reduced nuclear power along the Rhone River as EDF imposes output limits due to high water temperatures, grid needs, with minimal price impact amid strong solar and exports.

Key Points

Temporary EDF output limits at Rhone River reactors due to hot water, protecting ecosystems and grid reliability.

✅ EDF expects halved output at Bugey and Saint Alban.

✅ Cuts align with water temperature and discharge rules.

✅ Weekend midday curtailments offset by solar supply.

The high temperature warning has come early this year but will affect fewer nuclear power plants. High temperatures could halve nuclear power production, with river temperature limits at plants along France's Rhone River this week. 

Output restrictions are expected at two nuclear plants in eastern France due to high temperature forecasts, nuclear operator EDF said. It comes several days ahead of a similar warning that was made last year but will affect fewer plants, and follows a period when power demand has held firm during lockdowns across Europe.

The hot weather is likely to halve the available power supply from the 3.6 GW Bugey plant from 13 July and the 2.6 GW Saint Alban plant from 16 July, the operator said.

However, production will be at least 1.8 GW at Bugey and 1.3 GW at Saint Alban to meet grid requirements, and may change according to grid needs, the operator said.

Kpler analyst Emeric de Vigan said the restrictions were likely to have little effect on output in practice. Cuts are likely only at the weekend or midday when solar output was at its peak so the impact on power prices would be slim.

He said the situation would need monitoring in the coming weeks, however, noting it was unusually early in the summer for nuclear-powered France to see such restrictions imposed.

Water temperatures at the Bugey plant already eclipsed the initial threshold for restrictions on 9 July, as European power hits records during the heatwave. They are currently forecast to peak next week and then drop again, Refinitiv data showed.

"France is currently net exporting large amounts of power – and, despite a nuclear power dispute with Germany, single nuclear units' supply restrictions will not have the same effect as last year," Refinitiv analyst Nathalie Gerl said.

The Garonne River in southern France has the highest potential for critical levels of warming, but its Golfech plant is currently offline for maintenance until mid-August, as Europe faces nuclear losses, the data showed.

"(The restrictions were) to be expected and it will probably occur more often," Greenpeace campaigner Roger Spautz said.

"The authorities must stick to existing regulations for water discharges. Otherwise, the ecosystems will be even more affected," he added.

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Germany's Coal Reliance reflects an energy crisis, soaring natural gas prices, and a nuclear phase-out, as Destatis data show higher coal-fired electricity despite growing wind and solar generation, impacting grid stability and emissions.

Key Points

Germany's coal reliance is more coal power due to gas spikes and a nuclear phase-out, despite wind and solar growth.

✅ Coal share near one-third of electricity, per Destatis

✅ Gas-fired output falls as prices soar after Russia's invasion

✅ Wind and solar rise; grid stability and recession risks persist

Germany is relying on highly-polluting coal for almost a third of its electricity, as the impact of government policies, reflecting an energy balancing act for the power sector, and the war in Ukraine leads producers in Europe’s largest economy to use less gas and nuclear energy.

In the first six months of the year, Germany generated 82.6 kWh of electricity from coal, up 17 per cent from the same period last year, according to data from Destatis, the national statistics office, published on Wednesday. The leap means almost one-third of German electricity generation now comes from coal-fired plants, up from 27 per cent last year. Production from natural gas, which has tripled in price to €235 per megawatt hour since Russia’s invasion in late February, fell 18 per cent to only 11.7 per cent of total generation.

Destatis said that the shift from gas to coal was sharper in the second quarter. Coal-fired electricity increased by an annual rate of 23 per cent in the three months to June, while electricity generation from natural gas fell 19 per cent.

The figures highlight the challenge facing European governments in meeting clean energy goals after the Kremlin announced this week that the Nordstream 1 pipeline that takes Russian gas to Germany would remain closed until Europe removed sanctions on the country’s oil.

Germany has been trying to reduce its reliance on coal, which releases almost twice as many emissions as gas and more than 60 times those of nuclear energy, according to estimates from the Intergovernmental Panel on Climate Change, though grid expansion challenges have slowed renewable build-out in recent years.

Chancellor Olaf Scholz said the opposition CDU bore “complete responsibility” for the exit from coal and nuclear power that formed part of his predecessor Angela Merkel’s Energiewende policies, amid a continuing nuclear option debate in climate policy, which in turn raised reliance on Russian gas. At the beginning of this year, more than 50 per cent of Germany’s gas imports came from Russia, a figure that fell slightly over the opening half of 2022.

But CDU leader Friedrich Merz accused the government of “madness” over its decision to idle the country’s three remaining nuclear power stations from the end of this year, though officials have argued that nuclear would do little to solve the gas issue in the short term.

Electricity generation from nuclear energy has already halved after three of the six nuclear power plants that were still in operation at the end of 2021 were closed during the first half of this year. Berlin said on Monday it would keep on standby two of its remaining three nuclear power stations, a move to extend nuclear power during the energy crisis, which were all due to close at the end of the year.

The German government has warned of the risk of electricity shortages this winter. “We cannot be sure that, in the event of grid bottlenecks in neighbouring countries, there will be enough power plants available to help stabilise our electricity grid in the short term,” said German economy minister Robert Habeck on Monday.

However Scholz said that, after raising gas storage levels to 86 per cent of capacity, Germany would “probably get through this winter, despite all the tension”.

One bright spot from the data was the increase in use of renewable energy, highlighting a recent renewables milestone in Germany. The proportion of electricity generated from wind power generation rose by 18 per cent to 25 per cent of all electricity generation, while solar energy production increased 20 per cent.

Ángel Talavera, head of Europe economics at the consultancy Oxford Economics, said that the success in moving away from gas towards other energy sources “means that the risks of hard energy rationing over the winter are less severe now, even with little to no Russian gas flows”.

However, economists still expect a recession in the eurozone’s largest economy, amid a deteriorating German economy outlook over the near term, as a large part of the impact comes via higher prices and because industries and households still rely on gas for heating.

Separate official data also published on Wednesday showed that German industrial production slid 0.3 per cent between June and July. Production at Germany’s most energy intensive industries fell almost 7 per cent in the five months after Russia’s invasion of Ukraine.

“The demand destruction caused by the surge in prices will still send the German economy into recession over the winter,” said Talavera.

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Nuclear decarbonization leverages low-carbon electricity, process heat, and hydrogen from advanced reactors and SMRs to electrify industry, buildings, and transport, supporting net-zero strategies and grid flexibility alongside renewables with dispatchable baseload capacity.

Key Points

Nuclear decarbonization uses reactors to supply low-carbon power, heat, and hydrogen, cutting emissions across industry.

✅ Advanced reactors and SMRs enable high-temperature process heat

✅ Nuclear-powered electrolysis and HTSE produce low-carbon hydrogen

✅ District heating from reactors reduces pollution and coal use

By Dr Henri Paillere, Head of the Planning and Economics Studies Section of the IAEA

Decarbonising the power sector will not be sufficient to achieving net-zero emissions, with assessments indicating nuclear may be essential across sectors. We also need to decarbonise the non-power sectors - transport, buildings and industry - which represent 60% of emissions from the energy sector today. The way to do that is: electrification with low-carbon electricity as much as possible; using low-carbon heat sources; and using low-carbon fuels, including hydrogen, produced from clean electricity.
The International Energy Agency (IEA) says that: 'Almost half of the emissions reductions needed to reach net zero by 2050 will need to come from technologies that have not reached the market today.' So there is a need to innovate and push the research, development and deployment of technologies. That includes nuclear beyond electricity.

Today, most of the scenario projections see nuclear's role ONLY in the power sector, despite ongoing debates over whether nuclear power is in decline globally, but increased electrification will require more low-carbon electricity, so potentially more nuclear. Nuclear energy is also a source of low-carbon heat, and could also be used to produce low-carbon fuels such as hydrogen. This is a virtually untapped potential.

There is an opportunity for the nuclear energy sector - from advanced reactors, next-gen nuclear small modular reactors, and non-power applications - but it requires a level playing field, not only in terms of financing today's technologies, but also in terms of promoting innovation and supporting research up to market deployment. And of course technology readiness and economics will be key to their success.

On process heat and district heating, I would draw attention to the fact there have been decades of experience in nuclear district heating. Not well spread, but experience nonetheless, in Russia, Hungary and Switzerland. Last year, we had two new projects. One floating nuclear power plant in Russia (Akademik Lomonosov), which provides not only electricity but district heating to the region of Pevek where it is connected. And in China, the Haiyang nuclear power plant (AP1000 technology) has started delivering commercial district heating. In China, there is an additional motivation to reducing emissions, namely to cut air pollution because in northern China a lot of the heating in winter is provided by coal-fired boilers. By going nuclear with district heating they are therefore cutting down on this pollution and helping with reducing carbon emissions as well. And Poland is looking at high-temperature reactors to replace its fleet of coal-fired boilers and so that's a technology that could also be a game-changer on the industry side.

There have also been decades of research into the production of hydrogen using nuclear energy, but no real deployment. Now, from a climate point of view, there is a clear drive to find substitute fuels for the hydrocarbon fuels that we use today, and multiple new nuclear stations are seen by industry leaders as necessary to meet net-zero targets. In the near term, we will be able to produce hydrogen with electrolysis using low-carbon electricity, from renewables and nuclear. But the cheapest source of low-carbon power is from the long-term operation of existing nuclear power plants which, combined with their high capacity factors, can give the cheapest low-carbon hydrogen of all.

In the mid to long term, there is research on-going with processes that are more efficient than low-temperature electrolysis, which is high temperature steam electrolysis or thermal splitting of water. These may offer higher efficiencies and effectiveness but they also require advanced reactors that are still under development. Demonstration projects are being considered in several countries and we at the IAEA are developing a publication that looks into the business opportunities for nuclear production of hydrogen from existing reactors. In some countries, there is a need to boost the economics of the existing fleet, especially in the electricity systems where you have low or even negative market prices for electricity. So, we are looking at other products that have higher values to improve the competitiveness of existing nuclear power plants.

The future means not only looking at electricity, but also at industry and transport, and so integrated energy systems. Electricity will be the main workhorse of our global decarbonisation effort, but through heat and hydrogen. How you model this is the object of a lot of research work being done by different institutes and we at the IAEA are developing some modelling capabilities with the objective of optimising low-carbon emissions and overall costs.

This is just a picture of what the future might look like: a low-carbon power system with nuclear lightwater reactors (large reactors, small modular reactors and fast reactors) drawing on the green industrial revolution reactor waves in planning; solar, wind, anything that produces low-carbon electricity that can be used to electrify industry, transport, and the heating and cooling of buildings. But we know there is a need for high-temperature process steam that electricity cannot bring but which can be delivered directly by high-temperature reactors. And there are a number of ways of producing low-carbon hydrogen. The beauty of hydrogen is that it can be stored and it could possibly be injected into gas networks that could be run in the future on 100% hydrogen, and this could be converted back into electricity.

So, for decarbonising power, there are many options - nuclear, hydro, variable renewables, with renewables poised to surpass coal in global generation, and fossil with carbon capture and storage - and it's up to countries and industries to invest in the ones they prefer. We find that nuclear can actually reduce the overall cost of systems due to its dispatchability and the fact that variable renewables have a cost because of their intermittency. There is a need for appropriate market designs and the role of governments to encourage investments in nuclear.

Decarbonising other sectors will be as important as decarbonising electricity, from ways to produce low-carbon heat and low-carbon hydrogen. It's not so obvious who will be the clear winners, but I would say that since nuclear can produce all three low-carbon vectors - electricity, heat and hydrogen - it should have the advantage.
We at the IAEA will be organising a webinar next month with the IEA looking at long-term nuclear projections in a net-zero world, building on IAEA analysis on COVID-19 and low-carbon electricity insights. That will be our contribution from the point of view of nuclear to the IEA's special report on roadmaps to net zero that it will publish in May.

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Consumers Energy Virtual Energy Coaching connects Michigan small businesses with remote efficiency experts to cut utility costs, optimize energy usage, and access rebates and incentives, delivering safe COVID-19-era support and long-term savings through tailored assessments.

Key Points

A remote coaching service helping small businesses improve energy efficiency, access rebates, and cut utility costs.

✅ Three-call virtual coaching with usage review and savings plan

✅ Connects to rebates, incentives, and financing options

✅ Eligibility: <=1,200,000 kWh, <=15,000 MCF annually

Franklin Energy, a leading provider in energy efficiency and grid optimization solutions, announced today that they will implement Consumers Energy's Small Business Virtual Energy Coaching Service in response to the COVID-19 pandemic and broader industry coordination with federal partners across the power sector.

This Michigan-wide offering to natural gas, electric and combination small business customers provides a complimentary virtual energy-coaching service to help small businesses find ways to reduce electricity bills and benefit from lower utility costs, both now during COVID-19 and into the future, informed by similar Ontario electricity bill support efforts in other regions. To be eligible for the program, small businesses must have electric usage at or below 1,200,000 kWh annually and gas usage at or below 15,000 MCF annually.

"By developing lasting customer relationships and delivering consistent solutions through conversation, the Energy Coaching Program offers the next level of support for small business customers," said Hollie Whitmire, Franklin Energy program manager. "Energy coaching is suitable for all small businesses, but it's ideal for businesses that are new to energy efficiency or for those that have had low engagement with energy efficiency offerings and emerging new utility rate designs in years past."

Through a series of three calls, eligible small businesses can speak with an energy coach to help them connect to the right program offering available through Consumers Energy's energy efficiency programs for businesses, including demand response models like the Ontario Peak Perks program that support load management. From answering questions to reviewing energy usage, conducting assessments, identifying savings opportunities, and more, the energy coach is available to help small businesses put money back into their pocket now, when it matters most.

"Consumers Energy is committed to helping Michigan's small business community prosper, now more than ever, with examples such as Entergy's COVID-19 relief fund underscoring industry support," said Lauren Youngdahl Snyder, Consumers Energy's vice president of customer experience. "We are excited to work with Franklin Energy to develop an innovative solution for our small business customers. The Virtual Energy Coaching Service lets us engage our customers in a safe and effective manner, as seen with utilities waiving fees in Texas during the crisis, and has the potential to last even past the COVID-19 pandemic."

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