Purdue: As Ransomware Attacks Increase, New Algorithm May Help Prevent Power Blackouts


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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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UK Anticipates a 16% Decrease in Energy Bills in April

UK Energy Price Cap Cut 2024 signals relief as wholesale gas prices fall; Ofgem price cap drops per Cornwall Insight, aided by LNG supply, mild winter, despite Red Sea tensions and Ukraine conflict impacts.

 

Key Points

A forecast cut to Great Britain's Ofgem price cap as wholesale gas falls, easing typical annual household bills in 2024.

✅ Cap falls from £1,928 to £1,620 in April 2024

✅ Forecast £1,497 in July, then about £1,541 from October

✅ Drivers: lower wholesale gas, LNG supply, mild winter

 

Households in Great Britain are set to experience a significant reduction in energy costs this spring, with bills projected to drop by over £300 annually. This decrease is primarily due to a decline in wholesale gas prices, offering some respite to those grappling with the cost of living crisis.

Cornwall Insight, a well-regarded industry analyst, predicts a 16% reduction in average bills from the previous quarter, potentially reaching the lowest levels since the onset of the Ukraine conflict.

The industry’s price cap, indicative of the average annual bill for a typical household, is expected to decrease from the current £1,928, set earlier this month, to £1,620 in April – a reduction of £308 and £40 less than previously forecasted in December, as ministers consider ending the gas-electricity price link to improve market resilience.

Concerns about escalating tensions in the Red Sea, where Houthi rebels have disrupted global shipping, initially led analysts to fear an increase in wholesale oil prices and subsequent impact on household energy costs.

Contrary to these concerns, oil prices have remained relatively stable, and European gas reserves have been higher than anticipated during a mild winter, with European gas prices returning to pre-Ukraine war levels since November.

Cornwall Insight anticipates that energy prices will continue to be comparatively low through 2024. They predict a further decline to £1,497 for a typical annual bill from July, followed by a slight increase to £1,541 starting in October.

This forecast is a welcome development for Britons who have been dealing with increased expenses across various sectors, from food to utilities, amidst persistently high inflation rates, with energy-driven EU inflation hitting lower-income households hardest across member states.

Energy bills saw a steep rise in 2021, which escalated further due to the Ukraine conflict in 2022, driving up wholesale gas prices. This surge prompted government intervention to subsidize bills, with the UK price cap estimated to cost around £89bn to the public purse, capping costs to a typical household at £2,500.

Cornwall Insight noted that the supply of liquified natural gas to Europe had not been as adversely affected by the Red Sea disruptions as initially feared. Moreover, the UK has been well-supplied with gas from the US, which has become a more significant supplier since the Ukraine war, even as US electricity prices have risen to multi-decade highs. Contributing factors also include lower gas prices in Asia, mild weather, and robust gas availability.

Craig Lowrey, a principal consultant at Cornwall Insight, remarked that concerns about Red Sea events driving up energy prices have not materialized, allowing households to expect a reduction in prices.

On Monday, the next-month wholesale gas price dropped by 4% to 65p a therm.

However, Lowrey cautioned that a complete return to pre-crisis energy bill levels remains unlikely due to ongoing market impacts from shifting away from Russian energy sources and persistent geopolitical tensions, as well as policy changes such as Britain’s Energy Security Bill shaping market reforms.

Richard Neudegg, director of regulation at Uswitch, welcomed the potential further reduction of the price cap in April. However, he pointed out that this offers little solace to households currently struggling with high winter energy costs during the winter. Neudegg urged Ofgem, the energy regulator, to prompt suppliers to reintroduce more competitive and affordable fixed-price deals.

 

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How Ukraine Unplugged from Russia and Joined Europe's Power Grid with Unprecedented Speed

Ukraine-ENTSO-E Grid Synchronization links Ukraine and Moldova to the European grid via secure interconnection, matching frequency for stability, resilience, and energy security, enabling cross-border support, islanding recovery, and coordinated load balancing during wartime disruptions.

 

Key Points

Rapid alignment of Ukraine and Moldova into the European grid to enable secure interconnection and system stability.

✅ Matches 50 Hz frequency across interconnected systems

✅ Enables cross-border support and electricity trading

✅ Improves resilience, stability, and energy security

 

On February 24 Ukraine’s electric grid operator disconnected the country’s power system from the larger Russian-operated network to which it had always been linked. The long-planned disconnection was meant to be a 72-hour trial proving that Ukraine could operate on its own and to protect electricity supply before winter as contingencies were tested. The test was a requirement for eventually linking with the European grid, which Ukraine had been working toward since 2017. But four hours after the exercise started, Russia invaded.

Ukraine’s connection to Europe—which was not supposed to occur until 2023—became urgent, and engineers aimed to safely achieve it in just a matter of weeks. On March 16 they reached the key milestone of synchronizing the two systems. It was “a year’s work in two weeks,” according to a statement by Kadri Simson, the European Union commissioner for energy. That is unusual in this field. “For [power grid operators] to move this quickly and with such agility is unprecedented,” says Paul Deane, an energy policy researcher at the University College Cork in Ireland. “No power system has ever synchronized this quickly before.”

Ukraine initiated the process of joining Europe’s grid in 2005 and began working toward that goal in earnest in 2017, as did Moldova. It was part of an ongoing effort to align with Europe, as seen in the Baltic states’ disconnection from the Russian grid, and decrease reliance on Russia, which had repeatedly threatened Ukraine’s sovereignty. “Ukraine simply wanted to decouple from Russian dominance in every sense of the word, and the grid is part of that,” says Suriya Jayanti, an Eastern European policy expert and former U.S. diplomat who served as energy chief at the U.S. embassy in Kyiv from 2018 to 2020.

After the late February trial period, Ukrenergo, the Ukrainian grid operator, had intended to temporarily rejoin the system that powers Russia and Belarus. But the Russian invasion made that untenable. “That left Ukraine in isolation mode, which would be incredibly dangerous from a power supply perspective,” Jayanti says. “It means that there’s nowhere for Ukraine to import electricity from. It’s an orphan.” That was a particularly precarious situation given Russian attacks on key energy infrastructure such as the Zaporizhzhia nuclear power plant and ongoing strikes on Ukraine’s power grid that posed continuing risks. (According to Jayanti, Ukraine’s grid was ultimately able to run alone for as long as it did because power demand dropped by about a third as Ukrainians fled the country.)

Three days after the invasion, Ukrenergo sent a letter to the European Network of Transmission System Operators for Electricity (ENTSO-E) requesting authorization to connect to the European grid early. Moldelectrica, the Moldovan operator, made the same request the following day. While European operators wanted to support Ukraine, they had to protect their own grids, amid renewed focus on protecting the U.S. power grid from Russian hacking, so the emergency connection process had to be done carefully. “Utilities and system operators are notoriously risk-averse because the job is to keep the lights on, to keep everyone safe,” says Laura Mehigan, an energy researcher at University College Cork.

An electric grid is a network of power-generating sources and transmission infrastructure that produces electricity and carries it from places such as power plants, wind farms and solar arrays to houses, hospitals and public transit systems. “You can’t just experiment with a power system and hope that it works,” Deane says. Getting power where it is it needed when it is needed is an intricate process, and there is little room for error, as incidents involving Russian hackers targeting U.S. utilities have highlighted for operators worldwide.

Crucial to this mission is grid interconnection. Linked systems can share electricity across vast areas, often using HVDC technology, so that a surplus of energy generated in one location can meet demand in another. “More interconnection means we can move power around more quickly, more efficiently, more cost effectively and take advantage of low-carbon or zero-carbon power sources,” says James Glynn, a senior research scholar at the Center on Global Energy Policy at Columbia University. But connecting these massive networks with many moving parts is no small order.

One of the primary challenges of interconnecting grids is synchronizing them, which is what Ukrenergo, Moldelectrica and ENTSO-E accomplished last week. Synchronization is essential for sharing electricity. The task involves aligning the frequencies of every energy-generation facility in the connecting systems. Frequency is like the heartbeat of the electric grid. Across Europe, energy-generating turbines spin 50 times per second in near-perfect unison, and when disputes disrupt that balance, slow clocks across Europe can result, reminding operators of the stakes. For Ukraine and Moldova to join in, their systems had to be adjusted to match that rhythm. “We can’t stop the power system for an hour and then try to synchronize,” Deane says. “This has to be done while the system is operating.” It is like jumping onto a moving train or a spinning ride at the playground: the train or ride is not stopping, so you had better time the jump perfectly.

 

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Hydro-Quebec won't ask for rate hike next year

Hydro-Quebec Rate Freeze maintains current electricity rates, aligned with Bill 34, inflation indexing, and energy board oversight, delivering rebates to residential, commercial, and industrial customers and projecting nearly $1 billion in savings across Quebec.

 

Key Points

A Bill 34 policy holding power rates, adding 2020 rebates, and indexing 2021-2024 rates to inflation for Quebec customers.

✅ 2020-21 rates frozen; savings near $1B over five years.

✅ $500M rebate: residential, commercial, industrial shares.

✅ 2021-2024 rates index to inflation; five-year reviews after 2025.

 

Hydro-Quebec Distribution will not file a rate adjustment application with the province’s energy board this year, amid a class-action lawsuit alleging customers were overcharged.

In a statement released on Friday the Crown Corporation said it wants current electricity rates to be maintained for another year, as pandemic-driven demand pressures persist, starting April 1. That is consistent with the recently tabled Bill 34, and echoes Ontario legislation to lower electricity rates in its aims, which guarantees lower electricity rates for Quebecers.

The bill also provides a $500 million rebate in 2020, similar to a $535 million refund previously issued, half of which will go to residential customers while $190 million will go to commercial customers and another $60 million to industrial ones.

Hydro-Quebec said the 2020-21 rate freeze will generate savings of nearly $1 billion for its clients over the next five years, even as Manitoba Hydro scales back increases in a different market.

Bill 34, which was tabled in June, also proposes to set rates based on inflation for the years 2021 to 2024, contrasting with Ontario rate increases over the same period. After 2025 Hydro-Quebec would have to ask the energy board to set new rates every five years, as opposed to the current annual system, while BC Hydro is raising rates by comparison.

 

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'Transformative change': Wind-generated electricity starting to outpace coal in Alberta

Alberta wind power surpasses coal as AESO reports record renewable energy feeding the grid, with natural gas conversions, solar growth, energy storage, and decarbonization momentum lowering carbon intensity across Alberta's electricity system.

 

Key Points

AESO data shows wind surpassing coal in Alberta, driven by coal retirements, gas conversions, and growing renewables.

✅ AESO reports wind output above coal several times this week

✅ Coal units retire or convert to natural gas, boosting renewables

✅ Carbon intensity falls; storage and solar improve grid reliability

 

Marking a significant shift in Alberta energy history, wind generation trends provided more power to the province's energy grid than coal several times this week.

According to data from the Alberta Energy System Operator (AESO) released this week, wind generation units contributed more energy to the grid than coal at times for several days. On Friday afternoon, wind farms contributed more than 1,700 megawatts of power to the grid, compared to around 1,260 megawatts from coal stations.

"The grid is going through a period of transformative change when we look at the generation fleet, specifically as it relates to the coal assets in the province," Mike Deising, AESO spokesperson, told CTV News in an interview.

The shift in electricity generation comes as more coal plants come offline in Alberta, or transition to cleaner energy through natural gas generation, including the last of TransAlta's units at the Keephills Plant west of Edmonton.

Only three coal generation stations remain online in the province, at the Genesee plant southwest of Edmonton, as the coal phase-out timeline advances. Less available coal power, means renewable energy like wind and solar make up a greater portion of the grid.

 

EVOLUTION OF THE GRID
"Our grid is changing, and it's evolving," Deising said, adding that more units have converted to natural gas and companies are making significant investments into solar and wind energy.

For energy analyst Kevin Birn with IHS Markit, that trend is only going to continue.

"What we've seen for the last 24 to 36 months is a dramatic acceleration in ambition, policy, and projects globally around cleaner forms of energy or lower carbon forms of energy," Birn said.

Birn, who is also chief analyst of Canadian Oil Markets, added that not only has the public appetite for cleaner energy helped fuel the shift, but technological advancements have made renewables like wind and solar more cost-efficient.

"Alberta was traditionally heavily coal-reliant," he said. "(Now) western Canada has quite a diverse energy base."


LESS CARBON-INTENSIVE
According to Birn, the shift in energy production marks a significant reduction in carbon emissions as Alberta progresses toward its last coal plant closure milestone.

Ten years ago, IHS Markit estimates that Alberta's grid contributed about 900 kilograms of carbon dioxide equivalent per megawatt-hour of energy generation.

"That (figure is) really representing the dominance and role of coal in that grid," Birn said.

Current estimates show that figure is closer to 600 kilograms of CO2 equivalent.

"That means the power you and I are using is less carbon-intensive," Birn said, adding that figure will continue to fall over the next couple of years.


RENEWABLES HERE TO STAY
While many debate whether Alberta's energy is getting clean enough fast enough, Birn believes change is coming.

"It's been a half-decade of incredible price volatility in the oil market which had really dominated this sector and region," the analyst said.

"When I think of the future, I see the power sector building on large-scale renewables, which means decarbonization, and that provides an opportunity for those tech companies looking for clean energy places to land facilities."

Coal and natural gas are considered baseline assets by the AESO, where generation capacity does not shift dramatically, though some utilities report declining coal returns in other markets.

"Wind is a variable resource. It will generate when the wind is blowing, and it obviously won't when the wind is not," Deising said. "Wind and solar can ramp quickly, but they can drop off quite quickly, and we have to be prepared.

"We factor that into our daily planning and assessments," he added. "We follow those trends and know where the renewables are going to show up on the system, how many renewables are going to show up."

Deising says one wind plant in Alberta currently has an energy storage capacity to preserve renewably generated electricity during summer demand records and peak hours as needed. As the technology becomes more affordable, he expects more plants to follow suit.

"As a system operator, our job is to make sure as (the grid) is evolving we can continue to provide reliable power to Albertans at every moment every day," Deising said. "We just have to watch the system more carefully." 

 

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U.S. Electricity Sales Projections Continue to Fall

US Electricity Demand Outlook examines EIA forecasts, GDP decoupling, energy efficiency, electrification, electric vehicles, grid load growth, and weather variability to frame long term demand trends and utility planning scenarios.

 

Key Points

An analysis of EIA projections showing demand decoupling from GDP, with EV adoption and efficiency shaping future grid load.

✅ EIA lowers load growth; demand decouples from GDP.

✅ Efficiency and sector shifts depress kWh sales.

✅ EV adoption could revive load and capacity needs.

 

Electricity producers and distributors are in an unusual business. The product they provide is available to all customers instantaneously, literally at the flip of a switch. But the large amount of equipment, both hardware and software to do this takes years to design, site and install.

From a long range planning perspective, just as important as a good engineering design is an accurate sales projections. For the US electric utility industry the most authoritative electricity demand projec-tions come from the Department of Energy’s Energy Information Administration (EIA). EIA's compre-hensive reports combine econometric analysis with judgment calls on social and economic trends like the adoption rate of new technologies that could affect future electricity demand, things like LED light-ing and battery powered cars, and the rise of renewables overtaking coal in generation.

Before the Great Recession almost a decade ago, the EIA projected annual growth in US electricity production at roughly 1.5 percent per year. After the Great Recession began, the EIA lowered its projections of US electricity consumption growth to below 1 percent. Actual growth has been closer to zero. While the EIA did not antici-pate the last recession or its aftermath, we cannot fault them on that.

After the event, though, the EIA also trimmed its estimates of economic growth. For the 2015-2030 period it now predicts 2.1 percent economic and 0.3 percent electricity growth, down from previously projections of 2.7 percent and 1.3 percent respectively. (See Figures 1 and 2.)



 

Table 1. EIA electric generation projections by year of forecast (kWh billions)

 


 

Table 2. EIA forecast of GDP by year of forecast (billion 2009 $)

Back in 2007, the EIA figured that every one percent increase in economic activity required a 0.48 percent in-crease in electric generation to support it. By 2017, the EIA calculated that a 1 percent growth in economic activity now only required a 0.14 percent increase in electric output. What accounts for such a downgrade or disconnect between electricity usage and economic growth? And what factors might turn the numbers 
around?

First, the US economy lost energy intensive heavy industry like smelting, steel mills and refineries; patterns in China's electricity sector highlight how industrial shifts can reshape power demand. A more service oriented economy (think health care) relies more heavily on the movement of data or information and uses far less power than a manufacturing-oriented economy.

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Second, internet shopping has hurt so-called "brick and mortar" retailers. Despite the departure of heavy industry, in years past a burgeoning US commercial sector increased its demand and usage of electricity to offset the industrial decline. But not anymore. Energy efficiency measures as well as per-haps greater concern about global warming and greenhouse gas emissions and have cut into electricity sales. “Do more with less” has the right ring to it.

But there may be other components to the ongoing decline in electricity usage. Academic studies show that electricity usage seems to increase with income along an S curve, and flattens out after a certain income level. That is, if you earn $1 billion per year you do not (or cannot) use ten times a much electricity as someone earning only $100 million.

But people at typical, middle income levels increase or decrease electricity usage when incomes rise or fall. The squeeze on middle income families was discussed often in the late presidential campaign. In recent decades an increasing percentage of income has gone to a small percentage of the population at the top of the income scale. This trend probably accounts for some weakness in residential sales. This suggests that government policy addressing income inequality would also boost electricity sales.

Population growth affects demand for electricity as well as the economy as a whole. The EIA has made few changes in its projections, showing 0.7 percent per year population growth in 2015- 2030 in both the 2007 and 2017 forecasts. Recent studies, however, have shown a drop in the birth rate to record lows. More troubling, from a national health perspective is that the average age of death may have stopped rising. Those two factors point to lower population growth, especially if the government also restricts immi-gration. Thus, the US may be approaching a period of rather modest population growth.

All of the above factors point to minimal sales growth for electricity producers in the US--perhaps even lower than the seemingly conservative EIA estimates. But the cloud on the horizon has a silver lining in the shape of an electric car. Both the United Kingdom and France have set dates to end of production of automobiles with internal combustion engines. Several European car makers have declared that 20 percent of their output will be electric vehicles by the early 2020s. If we adopt automobiles powered by electricity and not gasoline or diesel, electricity sales would increase by one third. For the power indus-try, electric vehicles represent the next big thing.

We don’t pretend to know how electric car sales will progress. But assume vehicle turnover rates re-main at the current 7 percent per year and electric cars account for 5 percent of sales in the first five years (as op-posed to 1 percent now), 20 percent in the next five years and 50 percent in the third five year period. Wildly optimistic assumptions? Maybe. By 2030, electric cars would constitute 28 percent of the vehicle fleet. They would add about 10 percent to kilowatt hour sales by that date, assuming that battery efficiencies do not improved by then. Those added sales would require increased electric generation output, with low-emissions sources expected to cover almost all the growth globally. They would also raise long term growth rates for 2015-2030 from the present 0.3 percent to 1.0 percent. The slow upturn in demand should give the electric companies time to gear up so to speak.

In the meantime, weather will continue to play a big role in electricity consumption. Record heat-induced demand peaks are being set here in the US even as surging global demand puts power systems under strain worldwide.

Can we discern a pattern in weather conditions 15 years out? Maybe we can, but that is one topic we don’t expect a government agency to tackle in public right now. Meantime, weather will affect sales more than anything else and we cannot predict the weather. Or can we?

 

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UK electricity and gas networks making ‘unjustified’ profits

UK Energy Network Profits are under scrutiny as Ofgem price controls, Citizens Advice claims, and National Grid margins spark debate over monopolies, allowed returns, consumer bills, rebates, and future investment under tougher regulation.

 

Key Points

UK Energy Network Profits are returns set by Ofgem for regulated grid operators, shaping consumer bills and investment

✅ Ofgem sets allowed returns for monopoly networks via price controls

✅ Dispute over interest rates, bond yields, and risk premiums

✅ Reforms proposed: shorter controls, tougher investor incentives

 

Companies that run Britain’s electricity and gas networks, including National Grid, are making “eye-watering” profits at the expense of households, according to a well-known consumer group.

Citizens Advice believes £7.5bn in “unjustified” profits should be returned to consumers who pay for network costs via their electricity and gas bills, with parallels seen in a deferred BC Hydro costs report abroad, although its figures have been contested by the energy industry and regulator.

Ownership of electricity and gas networks came under the spotlight in the run-up to June’s general election, after the Labour party said in its manifesto it would bring both national and regional grid infrastructure to back into public ownership, amid wider debates about grid privatization concerns elsewhere, over time.

Electricity sector privatisation began in 1990 and the gas industry was privatised in 1986. Energy network companies — which own and operate the cables and wires that help deliver electricity and gas to homes and businesses — are in effect monopolies that are regulated by Ofgem. Ofgem evaluates what their costs, including the cost of capital to finance investments, might be over an eight-year “price control” period, similar to determinations like the OEB decision on Hydro One rates in Ontario, Canada. Citizens Advice claims many of the regulator’s calculations for the most recent price control went “considerably in networks’ financial favour”.

It believes assumptions Ofgem made about factors such as the future path of interest rates and returns on government bonds were too generous, with international contrasts like power theft challenges in India illustrating different risk contexts, as was the regulator’s assessment of the risk associated with operating a network company. 

These “generous” assumptions will lead to network companies making average profit margins of 19 per cent and an average return of 10 per cent for their investors at the expense of consumers, Citizens Advice claims in a report published on Wednesday, which recommends a shorter price control period to allow for more accurate forecasting.

“Decisions made by Ofgem have allowed gas and electricity network companies to make sky-high profits that we’ve found are not justified by their performance,” said Gillian Guy, chief executive of Citizens Advice. Ofgem defended its regulatory regime, saying it helped to cut costs, improve reliability and customer satisfaction. 

“Ofgem has already cut costs to consumers by 6 per cent in the current price control and secured a rebate of over £4.5bn from network companies and is engaging with the industry to deliver further savings, with some regions seeing Ontario electricity rate reductions for businesses as well,” said Dermot Nolan, chief executive of the energy regulator.

Mr Nolan insisted the next price controls would be “tougher for investors”. The current price controls for the gas and electricity transmission networks, plus gas distribution, run until 2021 and until 2023 for local electricity distribution networks.

“While we don’t agree with its modelling and the figures it has produced, the Citizens Advice report raises some important issues about network regulation which will be addressed in the next control,” Mr Nolan said.

The Energy Networks Association, a trade body, refuted the claims of Citizens Advice, insisting that costs had fallen by 17 per cent in real terms since privatisation. The current regulatory framework was established after a public consultation, it said, adding that today’s report repeated several old claims that had previously been rejected by the Competition and Markets Authority.

“Our energy networks are among the most reliable and lowest cost in the world and their performance has never been better. In the next six years energy network companies are forecasted to deliver £45bn of investment in the UK economy,” a spokesman for the networks association added. National Grid said that since 2013 it had generated savings of £460m for bill payers.

 

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