Brief power outage affects 5,500

Alberta Electricity Market Reform reshapes policy under the UCP, weighing a capacity market versus energy-only design, AESO reliability rules, renewables targets, coal phase-out, carbon pricing, consumer rates, and investment certainty before AUC decisions.

Key Points

Alberta Electricity Market Reform is the UCP plan to reassess capacity vs energy-only, renewables, and carbon pricing.

✅ Reviews capacity market timeline and AESO procurement

✅ Alters subsidies for renewables; slows wind and solar growth

✅ Adjusts industrial carbon levy; audits Balancing Pool losses

Hearings kicked off this week into the future of the province’s electricity market design, amid an electricity market reshuffle pledged by the province, but a high-stakes decision about the industry’s fate — affecting billions of dollars in investment and consumer costs — won’t be made inside the meeting room of the Alberta Utilities Commission.

Instead, it will take place in the office of Jason Kenney, as the incoming premier prepares to pivot away from the seismic reforms to Alberta’s electricity sector introduced by the Notley government.

The United Conservative Party has promised to adopt market-based policies, reflecting changes to how Alberta produces and pays for power, that will reset how the sector operates, from its approach to renewable energy and carbon pricing to re-evaluating the planned transition to an electricity “capacity market.”

“Every ball in electricity is up in the air right now,” Vittoria Bellissimo, of the Industrial Power Consumers Association of Alberta, said Tuesday during a break in the commission hearings.

Industry players are uncertain how quickly the UCP will change direction on power policies, but there’s little doubt Kenney’s government will take a strikingly different approach to the sector that keeps the lights on in Alberta.

“There’s some things they are going to change that are going to impact the electricity industry significantly,” said Duane Reid-Carlson, chief executive of consultancy EDC Associates.

“But I don’t think it’s going to be upheaval. I think the new government will proceed with caution because electricity is the foundation of our economy.”

Alberta’s electricity market has been turned on its head in recent years due to the recession, power prices dropping to near two-decade lows and several transformative policies initiated by the NDP.

The Notley government’s climate plan included an accelerated phase-out of all coal-fired generation and set targets for more renewable energy.

The most significant, but least-understood, move has been the planned shift to an electricity capacity market in 2021.

Under the strategy, generators will no longer solely be paid for the power produced and sold into the market; they will also receive payments for having electricity capacity available to the grid on demand.

The change was recommended by the Alberta Electric System Operator (AESO) as a way to reduce price volatility and provide more reliability than the current energy-only market, which some argue needs more competition to deliver better outcomes.

The independent system operator and industry officials have spent more than two years planning the transition since the switch was announced in late 2016. Proposed rules for the new system, outlining market changes, are now being discussed at the Alberta Utilities Commission hearings.

However, there is no ironclad guarantee the system remake will go ahead following the UCP’s election victory last week — amid calls to scrap the overhaul from a Calgary retailer — it plans to study the issue further — while other substantive electricity changes are already in store.

The UCP has promised to end “costly subsidies” to renewable energy developments and abandon the NDP’s pledge to have such energy sources make up 30 per cent of all power generation by 2030.

It will remove the planned phase-out of coal-fired electricity generation, although federal regulations for a 2030 prohibition remain in place.

It will also ask the auditor general to conduct a special audit of the massive losses sustained by the province’s Balancing Pool due to power purchase arrangements being handed back to the agency three years ago.

While Kenney has pledged to cancel the provincewide carbon tax, a levy on large industrial greenhouse gas emitters (such has power plants) will still be charged, although at a reduced rate of $20 a tonne.

The biggest unknown remains the power market’s structure, which underpins how the entire system operates.

The UCP has promised to consult on the shift to the capacity market and report back to Albertans within 90 days.

The complex issue may sound like an eye-glazer, but it will have a profound effect on industry investment, as well as how much consumers pay on their monthly electricity bills.

A number of industry players worry the capacity market will lead AESO to procure more power than is necessary, foisting unnecessary costs onto all Albertans.

“I still have concerns for what the impact on consumers is going to be,” said energy market consultant Sheldon Fulton. “I’d love to see the capacity market go away.”

An analysis by EDC Associates found the transition to a capacity market will procure additional electricity before it’s needed, requiring consumers to pay up to 40 per cent more — an extra $1.4 billion — for power in 2021-22 than under the existing market structure.

“I don’t think there’s any prejudged outcome,” said Blake Shaffer, former head trader at TransAlta Corp. and a fellow-in-residence at the C.D. Howe Institute.

“But it really matters about getting this right.”

Evan Bahry, executive director of the Independent Power Producers Society of Alberta, said the fact the UCP’s review was confined to just 90 days is helpful, as it avoids throwing the entire industry into a prolonged period of uncertainty.

As for the greening of Alberta’s power grid, amid growing attention to clean grids and storage, the demise of the NDP’s Renewable Electricity Program will likely slow down the rapid pace of wind and solar development. But it’s unlikely to stop the growth trend as costs continue to fall for such developments.

“Renewables over the last number of years have evolved to the point that they make sense on a subsidy-free basis,” said Dan Balaban, CEO of Greengate Power Corp., which has developed 480 MW of wind power in Alberta and Ontario.

“There is a path to clean electricity ahead.”

Chris Varcoe is a Calgary Herald columnist.

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European Power Demand During Second Lockdowns remains resilient as winter heating offsets commercial losses; electricity consumption tracks seasonal norms, with weather sensitivity, industrial activity, natural gas shielding, and coal decline shaping dynamics under COVID-19 restrictions.

Key Points

It is expected to remain near seasonal norms, driven by heating, industry activity, and weather sensitive consumption.

✅ Winter heating offsets retail and hospitality closures

✅ Demand sensitivity rises with colder weather in France

✅ Gas generation shielded; coal likely to curtail first

European power demand is likely to hold up in the second round of national lockdown restrictions, with fluctuations most likely driven by changes in the weather.

Traders and analysts expect normal consumption this time around as home heating during the chilly season replaces commercial demand.

Last week electricity consumption in France, Germany and the U.K. was close to business-as-usual levels for the time of year, according to BloombergNEF data. By contrast, power demand had dropped 16% in the first seven days of the springtime lockdown, as reflected by the U.K.’s 10% daily decline reported then.

How power demand performs has significance outside the sector. It’s often seen as a proxy for economic growth and during lockdowns earlier this year, electricity use slumped along with GDP, and stunted hydro and nuclear output could further hobble recovery. For Western Europe, annual demand is expected to be 5% lower than the previous year, a bigger decline than after the global financial crisis in 2008, according to S&P Global Platts.

The Covid-19 limits are lighter than those from earlier in the year “with an explicit drive to preserve economic activity, particularly at the more energy-intensive industrial end of the spectrum,” said Glenn Rickson, head of European power analysis at S&P Global Platts.

Higher levels of working from home will offset some of the losses from shop and hospitality closures, “but also increase the temperature sensitivity of overall gas and power demand, as heat-driven demand records have shown in recent summers,” he said.

The latest wave of national lockdowns began in France, Germany, Spain, Italy and Britain, with Spain having seen April demand plummet earlier in the year, as coronavirus cases surged and officials struggled to keep the spread of the virus under control.

Much of the manufacturing industry remains working for now despite additional restrictions to contain the coronavirus. With the peak of the second wave yet to be reached, “it seems almost inevitable that the fourth quarter will prove economically challenging,” analysts at Alfa Energy said.

There will initially be significantly less of an impact on demand compared with this spring when global daily demand dipped about 15% and electricity consumption in Europe was down 30%, Johan Sigvardsson, power price analyst at Swedish utility Bixia AB said.

The prevalence of electric heating systems in France means that power demand is particularly sensitive to cold weather. A cold spell would significantly boost demand and drive record electricity prices in tight markets.

Similar to the last round of shutdowns, it’s use of coal that will probably be hit first if power demand sags, as transition-focused responses gather pace, leaving natural gas mostly shielded from fluctuations in the market.

“We expect that another drop in power demand would again impact coal-fired generation and shield gas power to some extent,” said Carlos Torres Diaz, an analyst at Rystad Energy.

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Los Angeles Power Station Fire prompts LADWP to shut a Northridge/Reseda substation, causing a San Fernando Valley outage amid a heatwave; high-voltage equipment and mineral oil burned as 94,000 customers lost power, elevator rescues reported.

Key Points

An LADWP substation fire in Northridge/Reseda caused a major outage; 94,000 customers affected as crews restore power.

✅ Fire started around 6:52 p.m.; fully extinguished by 9 p.m.

✅ High-voltage gear and mineral oil burned; no injuries reported.

✅ Outages hit Porter Ranch, Reseda, West Hills, Granada Hills.

About 94,000 customers were without electricity Saturday night after the Los Angeles Department of Water and Power shut down a power station in the northeast San Fernando Valley that caught fire, the agency said.

The fire at the station in the Northridge/Reseda area of Los Angeles started about 6:52 p.m. and involved equipment that carries high-voltage electricity and distributes it at lower voltages to customers in the surrounding area, the department said, even as other utilities sometimes deploy wildfire safety shut-offs to reduce risk during dangerous conditions.

The department shut off power to the station as a precautionary move, and it is restoring power now that the fire has been put out, similar to restoration after intentional shut-offs in other parts of California. Initially, 140,000 customers were without power. That number had been cut to 94,000 by 11 p.m.

The power outage comes as much of California baked in heat that broke records, and rolling blackout warnings were issued as the grid strained. A record that stood 131 years in Los Angeles was snapped when the temperature spiked at 98 degrees downtown.

People reported losing power in Porter Ranch, Winnetka, West Hills, Canoga Park, Woodland Hills, Granada Hills, North Hills, Reseda and Chatsworth, KABC TV reported, highlighting electricity inequality across communities.

Shortly after the blaze broke out, firefighters found a huge container of mineral oil that is used to cool electrical equipment on fire, Los Angeles Fire Department spokesman Brian Humphrey told the Los Angeles Times. The incident underscores infrastructure risks that in some regions have required a complete grid rebuild after severe storms.

Firefighters had the blaze under control by 8:30 p.m. and were able to put it out by 9 p.m., Humphrey said. "These were fierce flames, with smoke towering more than 300 feet into the sky," he told the newspaper.

No one was injured.

Firefighters rescued people who were stranded in elevators, Humphrey said.

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Jersey Electricity Standby Charge proposes a grid-backup fee for commercial self-generators of renewable energy, with a review delaying implementation; potential tariff impacts include 10-15 percent price rises, cost recovery, and network reliability.

Key Points

A grid-backup fee for Jersey self-generating businesses to share network costs fairly and curb electricity price rises.

✅ Applies to commercial self-generation using renewables or not

✅ Excludes full exporters and pre-charge installations

✅ Aims to recover grid costs and avoid 10-15% price rises

Electricity prices could rise by ten to 15 per cent if a standby charge for some commercial customers is not implemented, the chief executive of Jersey Electricity has warned.

Jersey Electricity has proposed extending a monthly fee to commercial customers who generate their own power through renewable means but still wish to be connected to Jersey’s grid as a back-up, echoing Ontario energy storage efforts to shore up reliability.

The States recently unanimously backed a proposal lodged by Deputy Carolyn Labey to delay administering the levy until a review could be carried out, as seen in the UK grid's net-zero transformation debates influencing policy. The charge, was due to be implemented next month but will now not be introduced until May, or later if the review has not concluded.

But Chris Ambler, JE chief executive, warned that failing to implement the standby charge could lead to additional costs for customers.

Some of JE’s commercial customers have already been charged a standby fee after generating their own power through non-renewable means.

The charge does not apply to businesses which export all of their electricity back into the system as part of a buy-back scheme or those which install self-generation facilities before the charge is implemented.

Deputy Labey argued that the Island had done ‘absolutely nothing’ to support the use of renewable energies and instead were discouraging locally generated power by allowing JE to set a standby charge.

She added that she was pleased that the Council of Ministers had already starting reviewing the charges but the debate needed to go ahead to ensure the work continued after the May election.

During a States debate last month, she said: ‘It is increasingly concerning that we, as an island in the 21st century, are happy for our electricity to be provided to us by an unregulated, publicly listed for-profit company with a monopoly on energy.

‘I also think that introducing a charge on renewables at a time when the world is experiencing a revolution in renewable energies, including offshore vessel charging solutions, which are becoming increasingly economic, is something that needs to be investigated.

‘Jersey should be looking to diversify our electricity production and supply, to help protect us from price and currency fluctuations and to ensure that we, as an island, receive the best deal possible for Islanders.’

Mr Ambler said that any price increase would be dependent on the future take-up and use of renewable-energy technology in Jersey.

He said: ‘The cost impact would not be significant in the short term but in the long term it could be significant. I think that we are obliged to let our customers know that.

‘It is very difficult to assess but if we are not able to levy a fair charge, then, as electricity shortages in Canada have shown, we could see prices rise by ten to 15 per cent over time.’

Mr Ambler added that his company was in favour of the use of renewable energy, with a third of the company’s electricity being generated by hydroelectric sources, but that the costs of implementing it needed to be fairly distributed, given how big battery rule changes can affect project viability elsewhere in the market.

And he said that, while it was difficult to quantify how much could be lost if the standby charge was not implemented, it could cost the company over £10 million.

‘In 2014, we only increased our prices by one per cent,’ he said. ‘We are reviewing our prices at the moment but if we did put an increase in place it would be modest and it would not be linked to the standby charge.’

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Texas PUC Electricity Market Reforms aim to boost grid reliability, support ERCOT resilience, pay standby generators, require capacity procurement, and mitigate blackout risk, though analysts warn higher consumer bills and winter reserve margin deficits.

Key Points

PUC proposals to bolster ERCOT reliability via standby capacity, capacity procurement, and measures to reduce blackout risk.

✅ Pays generators for standby capacity during grid stress

✅ Requires capacity procurement to meet forecast demand

✅ Could raise consumer bills despite reliability gains

The Public Utility Commission of Texas is discussing major reforms to the state’s electricity market with the purpose to avoid a repeat of the power failures and blackouts during the February 2021 winter storm, which led to the death of more than 100 people and left over 11 million residents without electricity for days.

The regulator is discussing at a meeting on Thursday around a dozen proposals to make the grid more stable and reliable in case of emergencies. Proposals include paying power generators that are on standby when the grid needs backup, and requiring companies to pre-emptively buy capacity to meet future demand.

It is not clear yet how many and which of the proposals for electricity market reforms PUC will endorse today, while Texans vote on funding to modernize electricity generation later this year.

Analysts and consumer protection bodies warn that the measures will raise the energy bills for consumers, as some electricity market bailout ideas shift costs to ratepayers as well.

“Customers will be paying for more, but will they be getting more reliability?” Michael Jewell, an attorney with Jewell & Associates PLLC who represents clients at PUC proceedings, told Bloomberg.

“This is going to take us further down a path that’s going to increase cost to consumers, we better be darn sure these are the right choices,” Tim Morstad, Associate State Director, AARP Texas, told FOX 4 NEWS.

Last month, a report by the North American Electric Reliability Corp warned that the Texas power grid remained vulnerable to blackouts in case of a repeat of this year’s February Freeze.

Beyond Texas, electricity blackout risks have been identified across the U.S., underscoring the stakes for grid planning.

According to the 2021-2022 Winter Reliability Assessment report, Texas risks a 37-percent reserve margin deficit in case of a harsh winter, with ERCOT moving to procure capacity to address winter concerns, NERC said.

A reserve margin is the reserve of power generation capacity comparative to demand. The expected reserve margin for Texas for this winter, according to NERC, is 41.9 percent. Yet if another cold spell hits the state, it would affect this spare capacity, pushing the margin deeply into negative territory.

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Denmark Renewable Energy Outlook assesses Eurostat ranking, district heating and trash incineration, EV adoption, wind turbine testing expansions, and electrification to cut CO2, aligning policies with EU 2050 climate goals and green electricity usage.

Key Points

A brief analysis of Denmark's green power use, electrification, EVs, and policies needed to meet EU 2050 CO2 goals.

✅ Eurostat rank low due to trash incineration in district heating.

✅ EV adoption stalled after tax reinstatement, slowing electrification.

✅ Wind test centers expanded; electrification could cut 95% CO2.

Denmark’s low ranking in the latest figures from Eurostat regarding climate-friendly electricity, which places the country in 32nd place out of 40 countries, is partly a result of the country’s reliance on the incineration of trash to warm our homes via long-established district heating systems.

Additionally, there are not enough electric vehicles – a recent increase in sales was halted in 2016 when the government started to phase back registration taxes scrapped in 2008, and Europe’s EV slump underscores how fragile momentum can be.

Not enough green electricity being used

Denmark is good at producing green electricity, reports Politiken, but it does not use enough, and amid electricity price volatility in Europe this is bad news if it wants to fulfil the EU’s 2050 goal to eliminate CO2 emissions.

A recent report by Eurelectric and McKinsey demonstrates that if heating, transport and industry were electrified, reflecting a broader European push for electrification across the energy system, 95 percent of the country’s CO2 emissions could be eliminated by that date.

Wind turbine testing centre expansion approved

Parliament has approved the expansion of two wind turbine centres in northwest Jutland, supporting integration as e-mobility drives electricity demand in the coming years. The centres in Østerild and Høvsøre will have the capacity to test nine and seven turbines, measuring 330 and 200 metres in size (up from 250 and 165) respectively. The Østerild expansion should be completed in 2019, while Høvsøre ​​will have to wait a little longer.

Third on the Environmental Performance Index

Denmark finished third on the latest Environmental Performance Index, finishing only behind Switzerland and France. Its best category ranking was third for Environmental Health, and comparative energy efficiency benchmarking can help contextualize progress. Elsewhere, it ranked 11th for Ecosystem Vitality, 18th for Biodiversity and Habitat, 94th for Forests, 87th for Fisheries, 25th for Climate and Energy and 37th for Air Pollution, 14th for Water Resources and 7th for Agriculture.

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