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California Electricity Prices are surging across PG&E, SCE, and SDG&E territories, driven by fixed grid costs, wildfire mitigation, CARE subsidies, and Net Energy Metering, burdening low-income renters and increasing statewide utility debt, CPUC reports show.

Key Points

High rates driven by fixed grid costs and policies, burdening low-income customers across PG&E, SCE, and SDG&E.

✅ Fixed costs: transmission, distribution, wildfire mitigation

✅ Solar NEM shifts grid costs onto remaining ratepayers

✅ CPUC, CARE, LIHEAP aim to relieve rising utility debt

California's electricity prices are among the highest in the country, new research says, and those costs are falling disproportionately on a customer base that's already struggling to pay their bills.

PG&E customers pay about 80 percent more per kilowatt-hour than the national average, according to a study by the energy institute at UC Berkeley's Haas Business School with the nonprofit think tank Next 10. The study analyzed the rates of the state's three largest investor-owned utilities and found that Southern California Edison charged 45 percent more than the national average, while San Diego Gas & Electric charged double. Even low-income residents enrolled in the California Alternate Rates for Energy program paid more than the average American.

"California's retail prices are out of line with utilities across the country," said UC Berkeley assistant professor and study co-author Meredith Fowlie, citing Hawaii and some New England states among the outliers with even higher rates. "And they're increasing, as regulators face calls for action across the state."

So why are prices so high?
One reason is that California's size and geography inflate the "fixed" costs of operating its electric system, even as the state considers revamping electricity rates to clean the grid in parallel, which include maintenance, generation, transmission, and distribution as well as public programs like CARE and wildfire mitigation, according to the study. Those costs don't change based on how much electricity residents consume, yet between 66 and 77 percent of Californians' electricity bills are used to offset the costs of those programs, the study found.

These are legitimate expenses, Fowlie said. However, because lower-income residents use only moderately less electricity than higher income households, they end up with a disproportionate share of the burden, according to the study. And while the bills of older, wealthier Californians continue to decrease as they adopt cost-efficient alternatives like the state's Net Energy Metering solar program and the resulting solar power cost shift dynamic, costs will keep rising for a shrinking customer base composed mostly of low- and middle-income renters who still use electricity as their main energy source.

"When households adopt solar, they're not paying their fair share," Fowlie said. While solar users generate power that decreases their bills, they still rely on the state's electric grid for much of their power consumption - without paying for its fixed costs like others do.

"As this continues it's going to make electricity even more unaffordable," said F. Noel Perry, founder of Next 10, which funds nonpartisan research on the economy and environment.

PG&E this month raised its electricity rates 3.7 percent, amounting to a $5.01 a month increase for the average residential customer, who now pays $138.85 a month for electricity. It was the second increase this year, as regulators consider major changes to electric bills statewide, said Mark Toney, executive director of The Utility Reform Network, who noted that higher rates are particularly difficult for those who have lost their jobs in the pandemic. The California Public Utilities Commission last year approved a PG&E plan for more incremental increases through Dec. 31, 2022.

PG&E spokesperson Kristi Jourdan said in an email statement that the company was committed to keeping prices as low as possible as the state weighs income-based flat-fee utility bills proposals, and that although some programs are meant to be subsidized through rates, "in other cases, given that some customers have greater access to energy alternatives, the remaining customers - often those with limited means - are left paying unintended subsidies."

The costs quickly became overwhelming for Fretea Sylver, who rents a small house in Castro Valley and lost much of her work as the owner of a small woodwork business early in the pandemic. "They're little tiny changes but they accumulate. You turn around and you're like wait a second, why is my bill $20 more?," Sylver said. "And you have to pay it, no matter what."

Many more are unable to pay. Between February and December of last year, Californians accumulated more than $650 million in late payments from their utility providers, according to an analysis by the CPUC. In 2019, utility debt fell $71,646,869 from the prior year.

Sylver, who was on unemployment for 10 months last year, accumulated over $600 in unpaid PG&E bills. "We sort of went into a bit of debt, having to use credit cards and loans to sustain what we had to pay for. We're trying to catch up," Sylver said. The family received some help from the federal Low-Income Home Energy Assistance Program, which provides up to $1,000 to those who are late on their utility bills.

The study identified improvements to make California's power grid more equitable, such as income-based fixed electricity charges for the grid's cost that are based on income. Republican state senators this week called on the state to use federal relief money to forgive the billions Californians owe in utility debt, even as some lawmakers move to overturn income-based utility charges amid ongoing debate. Californians are currently protected by a statewide moratorium on disconnection for nonpayment of electricity bills through June 30. The CPUC this month began taking public input on the issue of how to grant some relief to those who have fallen behind on their utility bills.

This article is part of the California Divide, a collaboration among newsrooms examining income inequality and economic survival in California.

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California Community Choice Aggregators are reshaping electricity markets with renewable energy, solar and wind sourcing, competitive rates, and customer choice, challenging PG&E, SDG&E, and Southern California Edison while advancing California's clean power goals.

Key Points

Local governments that buy power, often cleaner and cheaper, while utilities handle delivery and billing.

✅ Offer higher renewable mix than utilities at competitive rates

✅ Utilities retain transmission and billing responsibilities

✅ Rapid expansion threatens IOU market share across California

Nearly 2 million electricity customers in California may not know it, but they’re part of a revolution. That many residents and businesses are getting their power not from traditional utilities, but via new government-affiliated entities known as community choice aggregators. The CCAs promise to deliver electricity more from renewable sources, such as solar and wind, even as California exports its energy policies across Western states, and for a lower price than the big utilities charge.

The customers may not be fully aware they’re served by a CCA because they’re still billed by their local utility. But with more than 1.8 million accounts now served by the new system and more being added every month, the changes in the state’s energy system already are massive.

Faced for the first time with real competition, the state’s big three utilities have suddenly become havens of innovation. They’re offering customers flexible options on the portion of their power coming from renewable energy, amid a broader review to revamp electricity rates aimed at cleaning the grid, and they’re on pace to increase the share of power they get from solar and wind power to the point where they are 10 years ahead of their deadline in meeting a state mandate.

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But that may not stem the flight of customers. Some estimates project that by late this year, more than 3 million customers will be served by 20 CCAs, and that over a longer period, Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric could lose 80% of their customers to the new providers.

Two big customer bases are currently in play: In Los Angeles and Ventura counties, a recently launched CCA called the Clean Power Alliance is hoping by the end of 2019 to serve nearly 1 million customers. Unincorporated portions of both counties and 29 municipalities have agreed in principle to join up.

Meanwhile, the city of San Diego is weighing two options to meet its goal of 100% clean power by 2035, as exit fees are being revised by the utilities commission: a plan to be submitted by SDG&E, or the creation of a CCA. A vote by the City Council is expected by the end of this year. A city CCA would cover 1.4 million San Diegans, accounting for half SDG&E’s customer demand, according to Cody Hooven, the city’s chief sustainability officer.

Don’t expect the big companies to give up their customers without a fight. Indeed, battle lines already are being drawn at the state Public Utilities Commission, where a recent CPUC ruling sided with a community energy program over SDG&E, and local communities.

“SDG&E is in an all-out campaign to prevent choice from happening, so that they maintain their monopoly,” says Nicole Capretz, who wrote San Diego’s climate action plan as a city employee and now serves as executive director of the Climate Action Campaign, which supports creation of the CCA.

California is one of seven states that have legalized the CCA concept, even as regulators weigh whether the state needs more power plants to ensure reliability. (The others are New York, New Jersey, Massachusetts, Ohio, Illinois and Rhode Island.) But the scale of its experiment is likely to be the largest in the country, because of the state’s size and the ambition of its clean-power goal, which is for 50% of its electricity to be generated from renewable sources by 2030.

California created its system via legislative action in 2002. Assembly Bill 117 enabled municipalities and regional governments to establish CCAs anywhere that municipal power agencies weren’t already operating. Electric customers in the CCA zones were automatically signed up, though they could opt out and stay with their existing power provider. The big utilities would retain responsibility for transmission and distribution lines.

The first CCA, Marin Clean Energy, began operating in 2010 and now serves 470,000 customers in Marin and three nearby counties.

The new entities were destined to come into conflict with the state’s three big investor-owned utilities. Their market share already has fallen to about 70%, from 78% as recently as 2010, and it seems destined to keep falling. In part that’s because the CCAs have so far held their promise: They’ve been delivering relatively clean power and charging less.

The high point of the utilities’ hostility to CCAs was the Proposition 16 campaign in 2009. The ballot measure was dubbed the “Taxpayers Right to Vote Act,” but was transparently an effort to smother CCAs in the cradle. PG&E drafted the measure, got it on the ballot, and contributed all of the $46.5 million spent in the unsuccessful campaign to pass it.

As recently as last year, PG&E and SDG&E were lobbying in the legislature for a bill that would place a moratorium on CCAs. The effort failed, and hasn’t been revived this year.

Rhetoric similar to that used by PG&E against Marin’s venture has surfaced in San Diego, where a local group dubbed “Clear the Air” is fighting the CCA concept by suggesting that it could be financially risky for local taxpayers and questioning whether it will be successful in providing cleaner electricity. Whether Clear the Air is truly independent of SDG&E’s parent, Sempra Energy, is questionable, as at least two of its co-chairs are veteran lobbyists for the company.

SDG&E spokeswoman Helen Gao says the utility supports “customers’ right to choose an energy provider that best meets their needs” and expects to maintain a “cooperative relationship” with any provider chosen by the city.

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US Control of Ukraine Nuclear Plants sparks debate over ZNPP, Zaporizhzhia, sovereignty, safety, ownership, and international cooperation, as Washington touts utility expertise, investment, and modernization to protect critical energy infrastructure amid conflict.

Key Points

US management proposal for Ukraine's nuclear assets, notably ZNPP, balancing sovereignty, safety, and investment.

✅ Ukraine retains ownership; any transfer requires parliament approval.

✅ ZNPP safety risks persist amid occupation near active conflict.

✅ International reactions split: sovereignty vs. cooperation and investment.

In a recent phone call with Ukrainian President Volodymyr Zelenskyy, U.S. President Donald Trump proposed that the United States take control of Ukraine's nuclear power plants, including the Zaporizhzhia Nuclear Power Plant (ZNPP), which has been under Russian occupation since early in the war and where Russia is reportedly building power lines to reactivate the plant amid ongoing tensions. Trump suggested that American ownership of these plants could be the best protection for their infrastructure, a proposal that has sparked controversy in policy circles, and that the U.S. could assist in running them with its electricity and utility expertise.

Ukrainian Response

President Zelenskyy promptly addressed Trump's proposal, stating that while the conversation focused on the ZNPP, the issue of ownership was not discussed. He emphasized that all of Ukraine's nuclear power plants belong to the Ukrainian people and that any transfer of ownership would require parliamentary approval . Zelenskyy clarified that while the U.S. could invest in and help modernize the ZNPP, ownership would remain with Ukraine.

Security Concerns

The ZNPP, Europe's largest nuclear facility, has been non-operational since its occupation by Russian forces in 2022. The plant's location near active conflict zones raises significant safety risks that the IAEA has warned of in connection with attacks on Ukraine's power grids, and its future remains uncertain. Ukrainian officials have expressed concerns about potential Russian provocations, such as explosions, especially after UN inspectors reported mines at the Zaporizhzhia plant near key facilities, if and when Ukraine attempts to regain control of the plant.

International Reactions

The proposal has elicited mixed reactions both within Ukraine and internationally. Some Ukrainian officials view it as an opportunistic move by the U.S. to gain control over critical infrastructure, while others see it as a potential avenue for modernization and investment, alongside expanding wind power that is harder to destroy in wartime. The international community remains divided on the issue, with some supporting Ukraine's sovereignty over its nuclear assets and others advocating for a possible agreement on power plant attacks to ensure the plant's safety and future operation.

President Trump's proposal to have the U.S. take control of Ukraine's nuclear power plants has sparked significant controversy. While the U.S. offers expertise and investment, Ukraine maintains that ownership of its nuclear assets is a matter of national sovereignty, even as it has resumed electricity exports to bolster its economy. The situation underscores the complex interplay between security, sovereignty, and international cooperation in conflict zones.

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Alberta Energy-Only Electricity Market faces capacity market debate, AESO price cap review, and coal-to-gas shifts by TransAlta and Capital Power, balancing reliability with volatility as investment signals evolve across Alberta's grid.

Key Points

An energy market paying generators only for electricity sold, with AESO oversight and a price cap guiding new capacity.

✅ AESO reviewing $999 per MW-h wholesale price cap.

✅ UCP retained energy-only; capacity market plan cancelled.

✅ TransAlta and Capital Power shift to coal-to-gas.

The Kenney government’s decision to cancel the redesign of Alberta’s electricity system to a capacity market won’t side-track two of the province’s largest power generators from converting coal-fired facilities to burn natural gas as part of Alberta’s shift from coal to cleaner energy overall.

But other changes could be coming to the province’s existing energy-only electricity market — including the alteration of the $999 per megawatt-hour (MW-h) wholesale price cap in Alberta.

The heads of TransAlta Corp. and Capital Power Corp. are proceeding with strategies to convert existing coal-fired power generating facilities to use natural gas in the coming years.

Calgary-based TransAlta first announced in 2017 that it would make the switch, as the NDP government was in the midst of overhauling the electricity sector and wind generation began to outpace coal in the province.

At the time, the Notley government planned to phase out coal-fired power by 2030, even as Alberta moved to retire coal by 2023 in practice, and shift Alberta into an electricity capacity market in 2021.

Such a move, made on the recommendation of the Alberta Electric System Operator (AESO), was intended to reduce price volatility and ensure system reliability.

Under the energy-only market, generators receive payments for electricity produced and sold into the grid. In a capacity market, generators are also paid for having power available on demand, regardless of how often they sell energy into the provincial grid.

The UCP government decided last month to ditch plans for a capacity market after consulting with the sector, saying it would be better for consumers.

On a conference call, TransAlta CEO Dawn Farrell said the company will convert coal-fired generating plants to burn gas, although it may alter the mix between simple conversions and switching to so-called “hybrid” plants.

(A hybrid conversion is a larger and more-expensive switch, as it includes installing a new gas turbine and heat-recovery steam generator, but it creates a highly efficient combined cycle unit.)

“Our view is fundamentally that carbon will be priced over the next 20 years no matter what,” she said Friday.

“We cannot get off coal fast enough in this company, and gas right now in Alberta is extremely inexpensive…

“So our coal-to-gas strategy is completely predicated on our belief that it’s not smart to be in carbon-intensive fuels for the future.”

Elsewhere in Canada, the Stop the Shock campaign has advocated for reviving coal power, underscoring ongoing policy debates.

The company said it’s planning the coal-to-gas conversion and re-powering of some or all of the units at its Keephills and Sundance facilities to gas-fired generation sometime between 2020 and 2023.

Similarly, Capital Power CEO Brian Vaasjo said the Edmonton-based company is moving ahead with a project that will allow it to burn both coal and natural gas at its Genesee generating station, even as Ontario’s energy minister sought to explore a halt to natural gas generation elsewhere.

In June, the company announced it would spend an estimated $50 million between 2019 and 2021 to allow it to use gas at the facility.

“What we’re doing is going to be dual fuel, so we will be able to operate 100 per cent natural gas or 100 per cent coal and everything in between,” Vaasjo said in an interview.

“You can expect to see we will be burning coal in the winter when natural gas prices are high, and we will be burning natural gas in summer when gas prices are real low.”

The transition comes as the government’s decision to stick with the energy-only market has been welcomed by players in the industry, and as Alberta's electricity future increasingly leans on wind resources.

A study by electricity consultancy EDC Associates found the capacity market would result in consumers paying an extra $1.4 billion in direct costs in 2021-22, as it required more generation to come online earlier than expected.

These additional costs would have accumulated to $10 billion by 2030, said EDC chief executive Duane-Reid Carlson.

For Capital Power, the decision to stick with the current system makes the province more investable in the future. Vaasjo said there was great uncertainty about the transition to a capacity market, and the possibility of rules shifting further.

Officials with Enmax Corp. said the city-owned utility would not have invested in future generation under the proposed capacity market.

“There is no short-term need (today) for new generation, so we’re just looking at the market and saying, ‘OK, as it evolves, we will see what happens,’” said Enmax vice-president Tim Boston.

Sticking with the energy-only market doesn’t mean Alberta will keep the existing rules.

In a July 25 letter, Alberta Energy Minister Sonya Savage directed AESO chair Will Bridge to examine if changes to the existing market are needed and report back by July 2020.

AESO, which manages the power grid, has been asked to investigate whether the current price cap of $999 per megawatt-hour (MW-h) should be changed.

The price ceiling hasn’t been altered since the energy-only market was implemented by the Klein government about two decades ago.

While allowing prices to go higher would increase volatility, reflecting lessons from Europe’s power crisis about scarcity pricing, during periods of rising demand and limited supply, it would send a signal to generators when investment in new generation is required, said Kent Fellows, a research associate at the University of Calgary’s School of Public Policy.

“Keeping the price (cap) too low could end up costing us more in the long run,” he said.

In a 2016 report, AESO said the province examined raising the price cap to $5,000 per MW-h, but “determined that it was unlikely to be successful in attracting investment due to increased price volatility.”

However, the amount of future generation that will be required in Alberta has been scaled back by the province.

In the United States, the Electricity Reliability Council of Texas (ERCOT) allows wholesale power prices in the state to climb to a cap of $9,000 per megawatt hours as demand rises — as it did Tuesday in the midst of a heat wave, according to Bloomberg.

Jim Wachowich, legal counsel for the Consumers’ Coalition of Alberta, said while few players are exposed to spot electricity prices, he has yet to be convinced raising the cap would be good for Albertans.

“Someone has to show me the evidence, and I suspect that’s what the minister has asked the AESO to do,” he said.

Generators say they believe some tinkering is needed to the energy-only market to ensure new generation is built when it’s required.

“The No. 1 change that the government has to … think about is in pricing,” added Farrell.

“If you don’t have enough of a price signal in an energy-only market to attract new capital, you won’t get new capital — and you’ll run up against the wall.”

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UAE Nuclear Power Plant launches the Barakah facility, delivering clean electricity to the Middle East under IAEA safeguards amid Gulf tensions, proliferation risks, and debates over renewables, natural gas, grid resilience, and energy security.

Key Points

The UAE Nuclear Power Plant, Barakah, is a civilian facility expected to supply 25% of electricity under IAEA oversight.

✅ Barakah reactors target 25% of national electricity.

✅ Operates under IAEA oversight, no enrichment per US 123 deal.

✅ Raises regional security, proliferation, and environmental concerns.

The United Arab Emirates became the first Arab country to open a nuclear power plant on Saturday, following a crucial step in Abu Dhabi earlier in the project, raising concerns about the long-term consequences of introducing more nuclear programs to the Middle East.

Two other countries in the region — Israel and Iran — already have nuclear capabilities. Israel has an unacknowledged nuclear weapons arsenal and Iran has a controversial uranium enrichment program that it insists is solely for peaceful purposes.

The U.A.E., a tiny nation that has become a regional heavyweight and international business center, said it built the plant to decrease its reliance on the oil that has powered and enriched the country and its Gulf neighbors for decades. It said that once its four units were all running, the South Korean-designed plant would provide a quarter of the country’s electricity, with Unit 1 reaching 100% power as a milestone toward commercial operations.

Seeking to quiet fears that it was trying to build muscle to use against its regional rivals, it has insisted that it intends to use its nuclear program only for energy purposes.

But with Iran in a standoff with Western powers over its nuclear program, Israel in the neighborhood and tensions high among Gulf countries, some analysts view the new plant — and any that may follow — as a security and environmental headache. Other Arab countries, including Saudi Arabia and Iraq, are also starting or planning nuclear energy programs.

The Middle East is already riven with enmities that pit Saudi Arabia and the U.A.E. against Iran, Qatar and Iran’s regional proxies. One of those proxies, the Yemen-based Houthi rebel group, claimed an attack on the Barakah plant when it was under construction in 2017.

And Iran is widely believed to be behind a series of attacks on Saudi oil facilities and oil tankers passing through the Gulf over the last year.

“The UAE’s investment in these four nuclear reactors risks further destabilizing the volatile Gulf region, damaging the environment and raising the possibility of nuclear proliferation,” Paul Dorfman, a researcher at University College London’s Energy Institute, wrote in an op-ed in March.

Noting that the U.A.E. had other energy options, including “some of the best solar energy resources in the world,” he added that “the nature of Emirate interest in nuclear may lie hidden in plain sight — nuclear weapon proliferation.”
But the U.A.E. has said it considered natural gas and renewable energy sources before dismissing them in favor of nuclear energy because they would not produce enough for its needs.

Offering evidence that its intentions are peaceful, it points to its collaborations with the International Atomic Energy Agency, which has reviewed the Barakah project, and the United States, with which it signed a nuclear energy cooperation agreement in 2009 that allows it to receive nuclear materials and technical assistance from the United States while barring it from uranium enrichment and other possible bomb-development activities.

That has not persuaded Qatar, which last year lodged a complaint with the international nuclear watchdog group over the Barakah plant, calling it “a serious threat to the stability of the region and its environment.”

The U.A.E.’s oil exports account for about a quarter of its total gross domestic product. Despite its gusher of oil, it has imported increasing amounts of natural gas in recent years in part to power its energy-intensive desalination plants.

“We proudly witness the start of Barakah nuclear power plant operations, in alignment with the highest international safety standards,” Mohammed bin Zayed, the U.A.E.’s de facto ruler, tweeted on Saturday.

The new nuclear facility, which is in the Gharbiya region on the coast, close to Qatar and Saudi Arabia, is the first of several prospective Middle East nuclear plants, even as Europe reduces nuclear capacity elsewhere. Egypt plans to build a power plant with four nuclear reactors.

Saudi Arabia is also building a civilian nuclear reactor while pursuing a nuclear cooperation deal with the United States, and globally, China's nuclear program remains on a steady development track, though the Trump administration has said it would sign such an agreement only if it includes safeguards against weapons development.

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AI Load Forecasting for Utilities leverages machine learning, smart meters, and predictive analytics to balance energy demand during COVID-19 disruptions, optimize grid reliability, support demand response, and stabilize rates for residential and commercial customers.

Key Points

AI predicts utility demand with ML and smart meters to improve reliability and reduce costs.

✅ Adapts to rapid demand shifts with accurate short term forecasts

✅ Optimizes demand response and distributed energy resources

✅ Reduces outages risk while lowering procurement and operating costs

The spread of the novel coronavirus that causes COVID-19 has prompted state and local governments around the U.S. to institute shelter-in-place orders and business closures. As millions suddenly find themselves confined to their homes, the shift has strained not only internet service providers, streaming platforms, and online retailers, but the utilities supplying power to the nation’s electrical grid, which face longer, more frequent outages as well.

U.S. electricity use on March 27, 2020 was 3% lower than it was on March 27, 2019, a loss of about three years of sales growth. Peter Fox-Penner, director of the Boston University Institute for Sustainable Energy, asserted in a recent op-ed that utility revenues will suffer because providers are halting shutoffs and deferring rate increases. Moreover, according to research firm Wood Mackenzie, the rise in household electricity demand won’t offset reduced business electricity demand, mainly because residential demand makes up just 40% of the total demand across North America.

Some utilities are employing AI and machine learning for the energy transition to address the windfalls and fluctuations in energy usage resulting from COVID-19. Precise load forecasting could ensure that operations aren’t interrupted in the coming months, thereby preventing blackouts and brownouts. And they might also bolster the efficiency of utilities’ internal processes, leading to reduced prices and improved service long after the pandemic ends.

Innowatts
Innowatts, a startup developing an automated toolkit for energy monitoring and management, counts several major U.S. utility companies among its customers, including Portland General Electric, Gexa Energy, Avangrid, Arizona Public Service Electric, WGL, and Mega Energy. Its eUtility platform ingests data from over 34 million smart energy meters across 21 million customers in more than 13 regional energy markets, while its machine learning algorithms analyze the data to forecast short- and long-term loads, variances, weather sensitivity, and more.

Beyond these table-stakes predictions, Innowatts helps evaluate the effects of different rate configurations by mapping utilities’ rate structures against disaggregated cost models. It also produces cost curves for each customer that reveal the margin impacts on the wider business, and it validates the yield of products and cost of customer acquisition with models that learn the relationships between marketing efforts and customer behaviors (like real-time load).

Innowwatts told VentureBeat that it observed “dramatic” shifts in energy usage between the first and fourth weeks of March. In the Northeast, “non-essential” retailers like salons, clothing shops, and dry cleaners were using only 35% as much energy toward the end of the month (after shelter-in-place orders were enacted) versus the beginning of the month, while restaurants (excepting pizza chains) were using only 28%. In Texas, conversely, storage facilities were using 142% as much energy in the fourth week compared with the first.

Innowatts says that throughout these usage surges and declines, its clients took advantage of AI-based load forecasting to learn from short-term shocks and make timely adjustments. Within three days of shelter-in-place orders, the company said, its forecasting models were able to learn new consumption patterns and produce accurate forecasts, accounting for real-time changes.

Innowatts CEO Sid Sachdeva believes that if utility companies had not leveraged machine learning models, demand forecasts in mid-March would have seen variances of 10-20%, significantly impacting operations.

“During these turbulent times, AI-based load forecasting gives energy providers the ability to … develop informed, data-driven strategies for future success,” Sachdeva told VentureBeat. “With utilities and energy retailers seeing a once-in-a-lifetime 30%-plus drop in commercial energy consumption, accurate forecasting has never been more important. Without AI tools, utilities would see their forecasts swing wildly, leading to inaccuracies of 20% or more, placing an enormous strain on their operations and ultimately driving up costs for businesses and consumers.”

Autogrid
Autogrid works with over 50 customers in 10 countries — including Energy Australia, Florida Power & Light, and Southern California Edison — to deliver AI-informed power usage insights. Its platform makes 10 million predictions every 10 minutes and optimizes over 50 megawatts of power, which is enough to supply the average suburb.

Flex, the company’s flagship product, predicts and controls tens of thousands of energy resources from millions of customers by ingesting, storing, and managing petabytes of data from trillions of endpoints. Using a combination of data science, machine learning, and network optimization algorithms, Flex models both physics and customer behavior, automatically anticipating and adjusting for supply and demand patterns through virtual power plants that coordinate distributed assets.

Autogrid also offers a fully managed solution for integrating and utilizing end-customer installations of grid batteries and microgrids. Like Flex, it automatically aggregates, forecasts, and optimizes capacity from assets at sub-stations and transformers, reacting to distribution management needs while providing capacity to avoid capital investments in system upgrades.

Autogrid CEO Dr. Amit Narayan told VentureBeat that the COVID-19 crisis has heavily shifted daily power distribution in California, where it’s having a “significant” downward impact on hourly prices in the energy market. He says that Autogrid has also heard from customers about transformer failures in some regions due to overloaded circuits, which he expects will become a problem in heavily residential and saturated load areas during the summer months (as utilities prepare for blackouts across the U.S. when air conditioning usage goes up).

“In California, [as you’ll recall], more than a million residents faced wildfire prevention-related outages in PG&E territory in 2019,” Narayan said, referring to the controversial planned outages orchestrated by Pacific Gas & Electric last summer. “The demand continues to be high in 2020 in spite of the COVID-19 crisis, as residents prepare to keep the lights on and brace for a similar situation this summer. If a 2019 repeat happens again, it will be even more devastating, given the health crisis and difficulty in buying groceries.”

AI making a difference
AI and machine learning isn’t a silver bullet for the power grid — even with predictive tools at their disposal, utilities are beholden to a tumultuous demand curve and to mounting climate risks across the grid. But providers say they see evidence the tools are already helping to prevent the worst of the pandemic’s effects — chiefly by enabling them to better adjust to shifted daily and weekly power load profiles.

“The societal impact [of the pandemic] will continue to be felt — people may continue working remotely instead of going into the office, they may alter their commute times to avoid rush hour crowds, or may look to alternative modes of transportation,” Schneider Electric chief innovation officer Emmanuel Lagarrigue told VentureBeat. “All of this will impact the daily load curve, and that is where AI and automation can help us with maintenance, performance, and diagnostics within our homes, buildings, and in the grid.”

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