Transformer plummets 53 floors

Smart Meter Texas real-time pricing faces rollback as utilities limit on-demand reads, impacting demand response, home area networks, ERCOT wholesale tracking, and thermostat automation, reducing efficiency gains promised through deregulation and smart meter investments.

Key Points

A plan linking smart meters to ERCOT prices, enabling near real-time usage alignment and automated demand response.

✅ Twice-hourly reads miss 15-minute ERCOT price spikes.

✅ Less than 1% of 7.3M meters use HAN real-time features.

✅ Limits hinder automation for HVAC, EV charging, and pool pumps.

Utilities made a promise several years ago when they built Smart Meter Texas that they’d come up with a way for consumers to monitor their electricity use in real time. But now they’re backing out of the deal with the approval of state regulators, leaving in the lurch retail power companies that are building their business model on the promise of real time pricing and denying consumers another option for managing their electricity costs.

Texas utilities collected higher rates to finance the building of a statewide smart meter network that would allow customers to track their electricity use and the quickly changing prices on wholesale power markets almost as they happened. Some retailers are building electricity plans around this promise, providing customers with in-home devices that would eventually track pricing minute-by-minute and allow them to automatically turn down or shut off air conditioners, pool pumps and energy sucking appliances when prices spiked on hot summer afternoons and turn them back on when they prices fell again.

The idea is to help save consumers money by allowing them to shift their electricity consumption to periods when power is cheaper, typically nights and weekends, even as utility revenue in a free-power era remains a debated topic.

“We’re throwing away a large part of (what) ratepayers paid for,” said John Werner, CEO of GridPlus Texas, one of the companies offering consumers a real-time pricing plan that is scheduled to begin testing next month. “They made the smart meters dumb meters.”

When Smart Meter Texas was launched a decade ago by a consortium of the state’s biggest utilities, it was considered an important part of deregulation. The competitive market for electricity held the promise that consumers would eventually have the technology to control their electricity use through a home area network and cut their power bills.

Regulators and legislators also were enticed by the possibility of making the electric system more efficient and relieving pressure on the power grid as consumers responded to high prices and cut consumption when temperatures soared, with ongoing discussions about Texas grid reliability informing policy choices.

One study found that smart meters coupled with smart real time consumption monitors could reduce electricity use between 3 percent and 5 percent, according to Call Me Power, a website sponsored by the European electricity price shopping service Selectra.

But utilities complained that the home area network devices were expensive to install and not used very often, and, with flat electricity demand weighing on growth, they questioned further investment. CenterPoint manager Esther Floyd Kent filed an affidavit with the commission in May that it costs the utility about $30,000 annually to support the network devices, plus maintenance.

Over a six-year period, CenterPoint paid $124,500, or about $20,000 a year, to maintain the system. As of April, there were only 4,067 network devices in CenterPoint’s service area, meaning the utility pays about $30.70 each year to maintain each device.

Centerpoint last year generated $9.6 billion in revenues and earned a $1.8 billion profit, according to its financial filings. CenterPoint officials did not respond to requests for comment.

Other utilities that are part of the Smart Meter consortium also complained to the Public Utility Commission that, up to now, the system hasn’t developed. All told, Texas has 7.3 million meters connected to Smart Meter Texas, but less than 1 percent are using the networking functions to track real-time prices and consumption, according to the testimony of Donny R. Helm, director of technology strategy and architecture for the state’s largest utility Oncor Electric Delivery Co. in Dallas.

The isssue was resolved recently through a settlement agreement that limits on-demand readings to twice an hour that Smart Meter Texas must provide customers. The price of power changes every 15 minutes, so a twice an hour reading may miss some price spikes.

The Public Utility Commission signed off on the deal, and so did several other groups including several retail electricity providers and the Office of Public Utility Counsel which represents residential customers and small businesses.

Michele Gregg, spokeswoman for the Public Utility Counsel, testified in December that the consumer advocate supported the change because widespread use of the networks never materialized. Catherine Webking, an Austin lawyer who represents the Texas Energy Association for Marketers, a group of retail electric providers, said she believes the deal was a reasonable resolution of providing the benefits of Smart Meter Texas while not incurring too much cost.

But Griddy, an electricity provider that offers customers the opportunity to pay wholesale power prices, which also issued a plea to customers during a price surge, said the state hasn’t given the smart-meter networks a chance and could miss out on its potential. Griddy was counting on the continued adoption of real time pricing as the next step for customers wanting to control their electricity costs.

Right now, Griddy sends out price alerts from the grid operator Electric Reliability Council of Texas so businesses like hotels can run washers and dryers when electricity prices are cheapest. But the company was counting on a smart-meter program that would allow customers to track wholesale prices and manage consumption themselves, making Griddy’s offerings attractive to more people.

Wholesale prices are generally cheaper than retail prices, but they can fluctuate widely, especially when the Texas power grid faces another crisis during extreme weather. Last year, wholesale prices averaged less than 3 cents per kilowatt hour, much lower than than retail rates that now are running above 11 cents, but they can spike at times of high demand to as much as $9 a kilowatt hour.

What customers want is to be able to use energy when it’s cheapest, said Greg Craig, Griddy’s CEO, and they want to do it automatically. They want to be able to program their thermostat so that if the price rises they can shut off their air conditioning and if the price falls, they can charge their electric-powered vehicle.

Griddy customers may still save money even without real time data, he said. But they won’t be able to see their usage in real time or see how much they’re spending.

“The big utilities have big investments in the existing way and going to real time and more transparency isn’t really in their best interest,” said Craig.

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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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SaskPower Summer Power Demand Record hits 3,520 MW as heat waves drive electricity consumption; grid capacity, renewables expansion, and energy efficiency tips highlight efforts to curb greenhouse gas emissions while meeting Saskatchewan's growing load.

Key Points

The latest summer peak load in Saskatchewan: 3,520 MW, driven by heat, with plans to expand capacity and lower emissions.

✅ New peak surpasses last August by 50 MW to 3,520 MW.

✅ Capacity target: 7,000 MW by 2030 with more renewables.

✅ Tips: AC settings, close blinds, delay heat-producing chores.

As the mercury continues to climb in Saskatchewan, where Alberta's summer electricity record offers a regional comparison, SaskPower says the province has set a new summer power demand record.

The Crown says the new record is 3,520 megawatts. It’s an increase of 50 megawatts over the previous record, or enough electricity for 50,000 homes.

“We’ve seen both summer and winter records set every year for a good while now. And if last summer is any indication, we could very well see another record before temperatures cool off heading into the fall,” said SaskPower Vice President of Transmission and Industrial Services Kory Hayko in a written release. “It’s not impossible we’ll break this record again in the coming days. It’s SaskPower’s responsibility to ensure that Saskatchewan people and businesses have the power they need to thrive. That’s what drives our investment of $1 billion every year, as outlined in our annual report, to modernize and grow the province’s electrical system.”

The previous summer consumption record of 3,740 megawatts was set last August, and similar extremes in the Yukon electricity demand highlight broader demand pressures this year. The winter demand record remains higher at 3,792 megawatts, set on Dec. 29, 2017.

SaskPower says it plans to expand its generation capacity from 4,500 megawatts now to 7,000 megawatts in 2030, with a focus on decreasing greenhouse gas emissions and doubling renewable electricity by 2030 as part of its strategy.

To reduce power bills, the Crown suggests turning down or programming air conditioning when residents aren’t home, inspecting the air conditioner to make sure it is operating efficiently, keeping blinds closed to keep out direct sunlight, delaying chores that produce heat and making sure electronics are turned off when people leave the room.

The new record beats the previous summer peak of 3,470 MW, set last August after also being broken twice in July. The winter demand record is still higher at 3,792 MW, which was set on December 29, 2017. To meet growing power demand, and amid projections that Manitoba's electrical demand could double in the next 20 years, SaskPower is expanding its generation capacity from approximately 4,500 MW now to 7,000 MW by 2030 while also reducing greenhouse gas emissions by 40 per cent from 2005 levels. To accomplish this, we will be significantly increasing the amount of renewables on our system.

Cooling and heating represents approximately a quarter of residential power bills. To reduce consumption and power bills during heat waves, SaskPower’s customers can:

Turn down or program the air conditioning when no one is home (for every degree that air conditioning is lowered for an eight-hour period, customers can save up to two per cent on their power costs);

Consider having their air conditioning unit inspected to make sure it is operating efficiently;

Keep the heat out by closing blinds and drapes, especially those with direct sunlight;

Delay chores that produce heat and moisture, like dishwashing and laundering, until the cooler parts of the day or evening; and

As with any time of the year, make sure lights, televisions and other electronics are turned off when no one's in the room. For example, a modern gaming console can use as much power as a refrigerator.

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China Energy Crisis drives electricity shortages, power cuts, and blackouts as coal prices surge, carbon-neutrality rules tighten, and manufacturing hubs ration energy, disrupting supply chains and industrial output ahead of winter demand peaks.

Key Points

A power shortfall from costly coal, price caps, and emissions targets, causing blackouts and industrial rationing.

✅ Coal prices soar while electricity tariffs are capped

✅ Factories in northeast hubs face rationing and downtime

✅ Supply chains risk delays ahead of winter demand

China is struggling with a severe shortage of electricity which has left millions of homes and businesses hit by power cuts.

Blackouts are not that unusual in the country but this year a number of factors have contributed to a perfect storm for electricity suppliers, including surging electricity demand globally.

The problem is particularly serious in China's north eastern industrial hubs as winter approaches - and is something that could have implications for the rest of the world.

Why has China been hit by power shortages?
The country has in the past struggled to balance electricity supplies with demand, which has often left many of China's provinces at risk of power outages.

During times of peak power consumption in the summer and winter the problem becomes particularly acute.

But this year a number of factors have come together to make the issue especially serious.

As the world starts to reopen after the pandemic, demand for Chinese goods is surging and the factories making them need a lot more power, highlighting China's electricity appetite in recent months.

Rules imposed by Beijing as it attempts to make the country carbon neutral by 2060 have seen coal production slow, even as the country still relies on coal for more than half of its power and as low-emissions generation is set to cover most global demand growth.

And as electricity demand has risen, the price of coal has been pushed up.

But with the government strictly controlling electricity prices, coal-fired power plants are unwilling to operate at a loss, with many drastically reducing their output instead.

Who is being affected by the blackouts?
Homes and businesses have been affected by power cuts as electricity has been rationed in several provinces and regions.

A coal-burning power plant can be seen behind a factory in China"s Inner Mongolia Autonomous Region

The state-run Global Times newspaper said there had been outages in four provinces - Guangdong in the south and Heilongjiang, Jilin and Liaoning in the north east. There are also reports of power cuts in other parts of the country.

Companies in major manufacturing areas have been called on to reduce energy usage during periods of peak demand or limit the number of days that they operate.

Energy-intensive industries such as steel-making, aluminium smelting, cement manufacturing and fertiliser production are among the businesses hardest hit by the outages.

What has the impact been on China's economy?
Official figures have shown that in September 2021, Chinese factory activity shrunk to the lowest it had been since February 2020, when power demand dropped as coronavirus lockdowns crippled the economy.

Concerns over the power cuts have contributed to global investment banks cutting their forecasts for the country's economic growth.

Goldman Sachs has estimated that as much as 44% of the country's industrial activity has been affected by power shortages. It now expects the world's second largest economy to expand by 7.8% this year, down from its previous prediction of 8.2%.

Globally, the outages could affect supply chains, including solar supply chains as the end-of-the-year shopping season approaches.

Since economies have reopened, retailers around the world have already been facing widespread disruption amid a surge in demand for imports.

China's economic planner, the National Development and Reform Commission (NDRC), has outlined a number of measures to resolve the problem, with energy supplies in the northeast of the country as its main priority this winter.

The measures include working closely with generating firms to increase output, ensuring full supplies of coal and promoting the rationing of electricity.

The China Electricity Council, which represents generating firms, has also said that coal-fired power companies were now "expanding their procurement channels at any cost" in order to guarantee winter heat and electricity supplies.

However, finding new sources of coal imports may not be straightforward.

Russia is already focused on its customers in Europe, Indonesian output has been hit by heavy rains and nearby Mongolia is facing a shortage of road haulage capacity,

Are energy shortages around the world connected?
Power cuts in China, UK petrol stations running out of fuel, energy bills jumping in Europe, near-blackouts in Japan and soaring crude oil, natural gas and coal prices on wholesale markets - it would be tempting to assume the world is suddenly in the grip of a global energy drought.

However, it is not quite as simple as that - there are some distinctly different issues around the world.

For example, in the UK petrol stations have run dry as motorists rushed to fill up their vehicles over concerns that a shortage of tanker drivers would mean fuel would soon become scarce.

Meanwhile, mainland Europe's rising energy bills and record electricity prices are due to a number of local factors, including low stockpiles of natural gas, weak output from the region's windmills and solar farms and maintenance work that has put generating operations out of action.
 

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Ontario Global Adjustment and ICI balance hydro rates, renewable cost shift, and peak demand. Class A and Class B customers face demand response decisions amid pandemic occupancy uncertainty and volatile GA charges through 2022.

Key Points

A pricing model where GA costs and ICI peak allocation shape Class A/B bills, driven by renewables cost shifts.

✅ Renewable cost shift trims GA; larger Class A savings expected.

✅ Class A peak strategy returns; occupancy uncertainty persists.

✅ Class B faces volatile GA; limited levers beyond efficiency.

Ontario’s large commercial electricity customers can approach the looming annual decision about their billing structure for the 12 months beginning July 1 with the assurance of long-term relief on a portion of their costs, amid changes coming for electricity consumers that could affect planning. That’s to be weighed against uncertainties around energy demand and whether a locked-in cost allocation formula that looked favourable in pre-pandemic times will remain so until June 30, 2022.

“The biggest unknown is we just don’t know when the people are coming back,” Jon Douglas, director of sustainability with Menkes Property Management Services, reflected during a webinar sponsored by the Building Owners and Managers Association (BOMA) of Greater Toronto last week. “The occupancy in our office buildings this fall, and going into the new year, could really impact the outcome of the decision.”

After a year of operational upheaval and more modifications to provincial electricity pricing policies, BOMA Toronto’s regularly scheduled workshop ahead of the June 15 deadline for eligible customers to opt into the Industrial Conservation Initiative (ICI) program had a lot of ground to cover. Notably, beginning in January, all commercial customers have seen a reduction in the global adjustment (GA) component of their monthly hydro bills after the Ontario government shifted costs associated with contracted non-hydroelectric renewable supply to reduce the burden on industrial ratepayers from electricity rates to the general provincial account — a move that trims approximately $258 million per month from the total GA charged to industrial and commercial customers. However, they won’t garner the full benefit of that until 2022 since they’re currently repaying about $333 million in GA costs that were deferred in April, May and June of 2020.

Renewable cost shift pares the global adjustment
For now, Ontario government officials estimate the renewable cost shift equates to a 12 per cent discount relative to 2020 prices, even as typical bills may rise about 2% as fixed pricing ends in some cases. Once last year’s GA deferral is repaid at the end of 2021, they project the average Class A customer participating in the ICI program should realize a 16 per cent saving on the total hydro bill, while Class B customers paying the GA on a volumetric per kilowatt-hour (kWh) basis will see a slightly more moderate 15 per cent decrease.

“This is the biggest change to electricity pricing that’s happened since the introduction of ICI,” Tim Christie, director of electricity policy, economics and system planning for Ontario’s Ministry of Energy, Northern Development and Mines, told online workshop attendees. “The government is funding the out-of-market costs of renewables. It does tail off into the 2030s as those contracts (for wind, solar and biomass generation) expire, but over the next eight-ish years, it’s pretty steady at around just over $3 billion per year.”

Extrapolating from 2020 costs, he pegged average electricity costs at roughly 9.1 cents/kWh for Class A commercial customers and 13.2 cents/kWh for Class B, a point of concern for Ontario manufacturers facing high rates as well. However, energy management specialists suggest actual 2021 numbers haven’t proved that out.

“In commercial buildings, we’re averaging 10 to 12 cents for Class A in 2021, and we’re seeing more than that for about 14, 15 cents for Class B,” reported Scott Rouse, managing partner with the consulting firm, Energy@Work.

GA costs for Class B customers dropped nearly 30 per cent in the first four months of 2021 compared to the last four months of 2020, when they averaged 11.8 cents/kWh. Thus far, though, there have been significant month-to-month fluctuations, with a low of 5.04 cents/kWh in February and a high of 10.9 cents/kWh in April contributing to the four-month average of 8.3 cents/kWh.

“In 2020, system-wide GA very often averaged more than $1 billion per month,” Rouse said. “This February it dropped to $500 million, which was really quite surprising. So it is a very volatile cost.”

Although welcome, the renewable cost shift does alter the payback on energy-saving investments, particularly for demand response mechanisms like energy storage. When combined with pandemic-related uncertainty and a series of policy and program reversals alongside calls to clean up Ontario’s hydro policy in recent years, the industry’s appetite for some more capital-intensive technologies appears to be flagging.

“Volatility puts a pause on some of the innovation,” said Terry Flynn, general manager with BentallGreenOak and chair of BOMA Toronto’s energy committee. “It could be a leading edge, but it might be a bleeding edge that won’t bear any fruit because the way the commodity costs are structured will change.”

“There’s kind of a wait-and-see approach on some of these bigger investments,” Douglas concurred.

Industrial Conservation Initiative underpins commercial class divide
Turning to the ICI, Class A customers — defined as those with average monthly energy demand of at least 1 megawatt (MW) — encountered some unexpected changes to the program rules during 2020. Meanwhile, Class B customers — encompassing the vast share of commercial properties smaller than about 350,000 square feet — confront the persistent reality of electricity cost allocation that offloads the burden from larger players onto them.

Through the ICI, participating Class A customers pay a share of the global adjustment that’s prorated to their energy use during the five hours of the period from May 1 to April 30 when the highest overall system demand is recorded. This gives Class A customers the opportunity to lock in a favourable factor for calculating their share of monthly system-wide global adjustment costs if they can successful project and curtail energy loads during those five hours of peak demand. On the flipside, Class B customers pay the remainder of those system-wide costs, on a straightforward per-kWh basis, once Class A payments have been reconciled.

“Class B has sometimes been regarded as the forgotten middle child of the customer classes in Ontario where all the shifted costs in the system kind of pile up,” acknowledged Mark Olsheski, vice president, energy and environment, with Sussex Strategy Group. “Likewise, there can be big unpredictable and uncontrollable swings in the global adjustment rate from month to month and, outside of pure energy efficiency, there really is precious little opportunity or empowerment for a Class B customer to take actions to lower their bills.”

Nevertheless, COVID-19 presents a few extra hiccups for Class A customers this year. Conventionally, late May is when they receive notification of the cost allocation factor that would be used to determine their GA for the upcoming July 1 to June 30 period. This year, though, all current ICI participants will retain the factor they secured by responding to the five hours of peak demand during the 12 months from May 1, 2019 to April 30, 2020 after the Ontario government placed a temporary halt on the peak demand response aspect of the program last summer. Regardless, eligible ICI participants must formally opt into the program by June 15 or they will be billed as Class B customers.

Peak chasing resumes for summer 2021
Since peak demand hours conventionally occur from June to September, Class A customers will once again be studying forecasts intently and preparing to respond via Peak Perks as the heat wave season sets in. That should help alleviate some of the system stresses that arose last summer — prompting policy-makers to reject lobbying for a continued pause on peak demand response.

“The policy rationale was to allow consumers to focus on their operations when recovering from COVID as opposed to reducing peaks. The other issue was that we did not expect the peaks to be high last summer given COVID shutdowns,” Christie recounted. “But due to some hot weather, more people at home and also the lack of ICI response, we saw peaks we haven’t seen in many, many years come up last summer. So the peak hiatus has ended and this summer we’ll be back to responding to ICI as per normal.”

Among Class A customers, owners/managers of office and retail facilities generally have the most to lose from a billing formula tied to the energy demand of more densely occupied buildings in the summer of 2019. However, they could be much more competitively positioned for 2022-23 if their buildings remain below full occupancy and energy demand stays lower than usual this summer.

“Where we can improve is the IESO (Independent Electricity System Operator) and the LDCs (local distribution companies) need to help customers get their real-time data, especially in light of the phantom demand issue, interpret their bills and their Class A versus B scenarios much more easily and comprehensively,” urged Lee Hodgkinson, vice president, technical services, sustainability and ESG, with Dream Unlimited. “ I look for APIs (application programming interface) and direct data flow from the LDCs to the building owners so that we can access that data really easily.”

Given Class A’s historic advantages, few eligible ICI participants are expected to migrate out to Class B. From a sustainability perspective, there’s perhaps more cause to question how the ICI’s 1-MW threshold encourages strategies to move in the other direction.

“You could jack up demand in some buildings and get them into Class A basically by firing up the chillers on the weekend and then pouring cooling outside to get rid of it,” Douglas noted. “That has nothing to do with climate change strategy or sustainability, but it’s a cost- saving strategy, and, sometimes, when you look at the math, it’s hundreds of thousands of dollars you can save.”

Brian Hewson, vice president, consumer protection and industry performance with the Ontario Energy Board (OEB), confirmed the OEB is currently scrutinizing the discrepancy that leaves Class B as the only consumer group with no flexibility to curtail energy load during higher-priced periods, and will be providing advice to the Ministry of Energy. In the interim, that status does, at least, simplify tactics.

“Just reduce your kWh and it doesn’t matter what time of day because you’re paying that fixed rate for 24 hours a day. So if you can curb your demand at night, you get a big bang for your dollar,” Rouse advised.

“We do talk about rates a lot, but if you’re not using it, you’re not paying for it,” Flynn agreed. “A lot of our focus is still on really to try to reduce the number of kilowatts that we use. That seems to be the best thing to do.”

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UK Electricity Interconnectors secure capacity market subsidies, supporting winter reliability with seabed cables to France and Belgium via the Channel Tunnel, lowering consumer costs, squeezing coal, and challenging new gas plants through cross-border energy trading.

Key Points

High-voltage cables linking Britain to Europe, securing backup capacity, cutting costs and boosting winter reliability.

✅ Won capacity market contracts at record-low prices

✅ Cables to France and Belgium via Channel Tunnel, seabed routes

✅ Squeezes coal, challenges new gas; renewables may join market

New electricity cables across the Channel to France and Belgium will be a key part of keeping Britain’s lights on during winter amid record electricity prices across Europe in the early 2020s, after their owners won backup power subsidies in a government auction this week.

For the first time, interconnector operators successfully bid for a slice of hundreds of millions’ worth of contracts in the capacity market. That will help cut costs for consumers, given how electricity is priced in Europe today, and squeeze out old coal power plants.

Three new interconnectors are currently being built to Europe, almost doubling existing capacity, with one along the Channel Tunnel and two on the seabed: one between Kent and Zeebrugge and one from Hampshire to Normandy. 

The interconnectors were success stories in this week’s capacity auction, which saw power firms bid to provide backup electricity in the winter of 2021/22. Prices for the four-year contracts hit a record low of £8.40 per kilowatt per year, which analysts described as a shock and well below expectations.

One industry source said the figure was “miles away” from what is needed to encourage companies to build big new gas power stations, which some argue are necessary to fill the gap when the UK’s ageing nuclear reactors close as Europe loses nuclear power across the region over the next decade.

While bad news for those firms, the low price is good for consumers. The subsidies will add about £525m to energy bills, or £5.68 for the average household, compared with £11 for the year before, according to analysts Cornwall Insight.

Existing gas power stations scooped up most of the contracts, but new gas ones lost out, as did several coal plants. Battery storage plants, a standout success in the last auction, fared comparatively poorly after changes to the rules.

Experts at Bernstein bank said the the misses by coal meant that around half the UK’s remaining coal power capacity could close from October 2019, when existing capacity market contracts run out. Chaitanya Kumar, policy adviser at thinktank Green Alliance, said: “Coal’s exit from the UK’s energy system just moved a step closer as coal contracts fell by half compared with last year.”

Tom Edwards, an analyst at Cornwall Insight, said that more interconnectors were likely to bid into future rounds of the capacity market, such as the cable being laid between Norway and the UK. Relying on foreign power supplies was fine, he said, provided Brexit did not make energy trading more difficult and the interconnectors delivered at times of need, where events like Irish grid price spikes illustrate the stress points.

However, one industry source, who wants to see new gas plants built in the UK, said the results showed that the system was not working, amid UK peak power prices that have climbed in recent trading. “That self-sufficiency doesn’t seem to be a priority at a time when we’re breaking away from Europe is a bit weird,” they said.

But the prospects for new gas plants in future rounds of the capacity market look bleak. They will very likely face a new source of competition next year, if energy regulator Ofgem approves a proposal to allow renewables to compete too.

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