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Alberta Capacity Market Overhaul faces scrutiny over electricity costs, reliability targets, investor certainty, and AESO design, as UCP reviews NDP reforms, renewables integration, and deregulated energy-only alternatives impacting generators, ratepayers, and future power price volatility.

Key Points

A shift paying generators for capacity and energy to improve reliability; critics warn of higher electricity costs.

✅ UCP reviewing NDP plan and subsidies amid market uncertainty

✅ AESO cites reliability needs as coal retires, renewables grow

✅ Critics predict overprocurement and premature launch cost spikes

Jason Kenney's government is facing renewed pressure to cancel a massive overhaul of Alberta's power market that one player says will needlessly spike costs by hundreds of millions of dollars, amid an electricity sector in profound change today.

Nick Clark, who owns the Calgary-based electricity retailer Spot Power, has sent the Alberta government an open letter urging it to walk away from the electricity market changes proposed by the former NDP government.

"How can you encourage new industry to open up when one of their raw material costs will increase so dramatically?" Clark said. "The capacity market will add more costs to the consumer and it will be a spiral downwards."

But NDP Leader Rachel Notley, whose government ushered in the changes, said fears over dramatic cost increases are unfounded.

"There are some players within the current electricity regime who have a vested interest in maintaining the current situation," Notley said

Kenney's UCP vowed during the recent election to review the current and proposed electricity market options, as the electricity market heads for a reshuffle, with plans to report on its findings within 90 days.

The party also promised to scrap subsidies for renewable power, while ensuring "a market-based electricity system" that emphasizes competition in Alberta's electricity market for consumers.

The New Democrats had opted to scrap the current deregulated power market — in place since the Klein era — after phasing out coal-fired generation and ushering in new renewable power as part of changes in how Alberta produces and pays for electricity under their climate change strategy.

The Alberta Electric System Operator, which oversees the grid, says the province will need new sources of electricity to replace shuttered coal plants and backstop wind and solar generators, while meeting new consumer demand.

After consulting with power companies and investors, the AESO concluded in late 2016 the electricity market couldn't attract enough investment to build the needed power generation under the current model.

The AESO said at the time investors were concerned their revenues would be uncertain once new plants are running. It recommended what's known as a capacity market, which compensates power generators for having the ability to produce electricity, even when they're not producing it.

In other words, producers would collect revenue for selling electricity into the grid and, separately, for having the capacity to produce power as a backstop, ensuring the lights stay on. Power generators would use this second source of income to help cover plant construction costs.

Clark said the complex system introduces unnecessary costs, which he believes would hurt consumers in the end. He said what's preventing investment in the power market is uncertainty over how the market will be structured in the future.

"What investors need to see in this market is price certainty, regulatory ease, and where the money they're putting into the marketplace is not at risk," he said.

"They can risk their own money, but if in fact the government comes in and changes the policy as it was doing, then money stayed away from the province."

Notley said a capacity market would not increase power bills but would avoid big price swings, with protections like a consumer price cap on power bills also debated, while bringing greener sources of energy into Alberta's grid.

"Moving back to the [deregulated] energy-only market would make a lot of money for a few people, and put consumers, both industrial and residential, at great risk."

Clark disagrees, citing Enmax's recent submissions to the Alberta Utilities Commission, in which the utility argues the proposed design of the capacity market is flawed.

In its submissions to the commission, which is considering the future of Alberta's power market, Enmax says the proposed system would overestimate the amount of generation capacity the province will need in the future. It says the calculation could result in Alberta procuring too much capacity.

The City of Calgary-owned utility says this could drive up costs by anywhere from $147 million to $849 million a year. It says a more conservative calculation of future electricity demand could avoid the extra expense.

An analysis by a Calgary energy consulting firm suggests a different feature of the proposed power market overhaul could also lead to a massive spike in costs.

EDC Associates, hired by the Consumers' Coalition of Alberta, argues the proposal to launch the new system in November 2021 may be premature, because it could bring in additional supplies of electricity before they're needed.

The consultant's report, also filed with the Alberta Utilities Commission, estimates the early launch date could require customers to pay 40 per cent more for electricity amid rising electricity prices in the province — potentially an extra $1.4 billion — in 2021/22.

"The target implementation date is politically driven by the previous government," said Duane Reid-Carlson, president of EDC Associates.

Reid-Carlson recommends delaying the launch date by several years and making another tweak: reducing the proposed target for system reliability, which would scale back the amount of power generation needed to backstop renewable sources.

"You could get a result in the capacity market that would give a similar cost to consumers that the [deregulated] energy-only market design would have done otherwise," he said.

"You could have a better risk profile associated with the capacity market that would serve consumers better through lower cost, lower price volatility, and it would serve generators better by giving them better access to capital at lower costs."

The UCP government did not respond to a request for comment.

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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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California Renewable Energy Curtailment highlights grid congestion, midday solar peaks, limited battery storage, and market constraints, with WEIM participation and demand response programs proposed to balance supply-demand and reduce wasted solar and wind generation.

Key Points

It is the deliberate reduction of solar and wind output when grid limits or low demand prevent full integration.

✅ Grid congestion restricts transmission capacity

✅ Midday solar peaks exceed demand, causing surplus

✅ Storage, WEIM, and demand response mitigate curtailment

California has long been a leader in renewable energy adoption, achieving a near-100% renewable milestone in recent years, particularly in solar and wind power. However, as the state continues to expand its renewable energy capacity, it faces a growing challenge: the curtailment of excess solar and wind energy. Curtailment refers to the deliberate reduction of power output from renewable sources when the supply exceeds demand or when the grid cannot accommodate the additional electricity.

Increasing Curtailment Trends

Recent data from the U.S. Energy Information Administration (EIA) highlights a concerning upward trend in curtailments in California. In 2024, the state curtailed a total of 3,102 gigawatt-hours (GWh) of electricity generated from solar and wind sources, surpassing the 2023 total of 2,660 GWh. This represents a 32.4% increase from the previous year. Specifically, 2,892 GWh were from solar, and 210 GWh were from wind, marking increases of 31.2% and 51.1%, respectively, compared to the first nine months of 2023.

Causes of Increased Curtailment

Several factors contribute to the rising levels of curtailment:

1. Grid Congestion: California's transmission infrastructure has struggled to keep pace with the rapid growth of renewable energy sources. This congestion limits the ability to transport electricity from generation sites to demand centers, leading to curtailment.
   
   

2. Midday Solar Peaks: Amid California's solar boom, solar energy production typically peaks during the midday when electricity demand is lower. This mismatch between supply and demand results in excess energy that cannot be utilized, necessitating curtailment.
   
   

3. Limited Energy Storage: While battery storage technologies are advancing, California's current storage capacity is insufficient to absorb and store excess renewable energy for later use. This limitation exacerbates curtailment issues.
   
   

4. Regulatory and Market Constraints: Existing market structures and regulatory frameworks may not fully accommodate the rapid influx of renewable energy, leading to inefficiencies and increased curtailment.

Economic and Environmental Implications

Curtailment has significant economic and environmental consequences. For renewable energy producers, curtailed energy represents lost revenue and undermines the economic viability of new projects. Environmentally, curtailment means that clean, renewable energy is wasted, and the grid may rely more heavily on fossil fuels to meet demand, counteracting the benefits of renewable energy adoption.

Mitigation Strategies

To address the rising curtailment levels, California is exploring several strategies aligned with broader decarbonization goals across the U.S.:

• Grid Modernization: Investing in and upgrading transmission infrastructure to alleviate congestion and improve the integration of renewable energy sources.
  
  

• Energy Storage Expansion: Increasing the deployment of battery storage systems to store excess energy during peak production times and release it during periods of high demand.
  
  

• Market Reforms: Participating in the Western Energy Imbalance Market (WEIM), a real-time energy market that allows for the balancing of supply and demand across a broader region, helping to reduce curtailment.
  
  

• Demand Response Programs: Implementing programs that encourage consumers to adjust their energy usage patterns, such as shifting electricity use to times when renewable energy is abundant.

Looking Ahead

As California continues to expand its renewable energy capacity, addressing curtailment will be crucial to ensuring the effectiveness and sustainability of its energy transition. By investing in grid infrastructure, energy storage, and market reforms, the state can reduce curtailment levels and make better use of its renewable energy resources, while managing challenges like wildfire smoke impacts on solar output. These efforts will not only enhance the economic viability of renewable energy projects but also contribute to California's 100% clean energy targets by maximizing the use of clean energy and reducing reliance on fossil fuels.

While California's renewable energy sector faces challenges related to curtailment, proactive measures and strategic investments can mitigate these issues, as scientists continue to improve solar and wind power through innovation, paving the way for a more sustainable and efficient energy future.

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ERCOT Ancillary Services Clawback and VOLL Pricing summarize PUCT and IMM actions on load shed, real-time pricing adders, clawbacks, and settlement corrections after the 2021 winter storm in the Texas power grid market.

Key Points

Policies addressing clawbacks for unprovided AS and correcting VOLL-based price adders after load shed ended in ERCOT.

✅ PUCT ordered clawbacks for ancillary services not delivered.

✅ IMM urged price correction after firm load shed ceased.

✅ ERCOT's VOLL adder raised costs by $16B during 32 hours.

Potomac Economics, the Independent Market Monitor (IMM) for the Electric Reliability Council of Texas (ERCOT), filed a report with the Public Utility Commission of Texas (PUCT) that certain payments were made by ERCOT for Ancillary Services (AS) that were not provided, even as ERCOT later issued a winter reliability RFP to procure capacity during subsequent seasons.

According to the IMM (emphasis added):

There were a number of instances during the operating days outlined above in which AS was not provided in real time because of forced outages or derations. For market participants that are not able to meet their AS responsibility, typically the ERCOT operator marks the short amount in the software. This causes the AS responsibility to be effectively removed and the day-ahead AS payment to be clawed back in settlement. However, the ERCOT operators did not complete this task during the winter event, echoing issues like the Ontario IESO phantom demand that cost customers millions, and therefore the "failure to provide" settlements were not invoked in real time.

Removing the operator intervention step and automating the "failure to provide" settlement was contemplated in NPRR947: Clarification to Ancillary Service Supply Responsibility Definition and Improvements to Determining and Charging for Ancillary Service Failed Quantities; however, the NPRR was withdrawn in August 2020 amid ongoing market reform discussions because of the system cost, some complexities related to AS trades, and the implementation of real-time co-optimization.

Invoking the "failure to provide" settlement for all AS that market participants failed to provide during the operating days outlined above will produce market outcomes and settlements consistent with underlying market principles. In this case, the principle is that market participants should not be paid for services that they do not provide, even as a separate ruling found power plants exempt from providing electricity in emergencies under Texas law, underscoring the distinction between obligations and settlements. Whether ERCOT marked the short amount in real-time or not should not affect the settlement of these ancillary services.

On March 3, 2021, the PUCT ordered (a related press release is here) that:

ERCOT shall claw back all payments for ancillary service that were made to an entity that did not provide its required ancillary service during real time on ERCOT operating days starting February 14, 2021 and ending on February 19,2021.

On March 4, 2021, the IMM filed another report and recommended that:

the [PUCT] direct ERCOT to correct the real-time prices from 0:00 February 18,2021, to 09:00 February 19, 2021, to remove the inappropriate pricing intervention that occurred during that time period.

The IMM approvingly noted the PUCT's February 15, 2021 order, which mandated that real-time energy prices reflect firm load shed by setting prices at the value of lost load (VOLL).1

According to the IMM (emphasis added):

This is essential in an energy-only market, like ERCOT's, where the Texas power grid faces recurring crisis risks, because it provides efficient economic signals to increase the electric generation needed to restore the load and service it reliably over the long term.

Conversely, it is equally important that prices not reflect VOLL when the system is not in shortage and load is being served, and experiences in capacity markets show auction payouts can fall sharply under different conditions. The Commission recognized this principle in its Order, expressly stating it is only ERCOT's out-of-market shedding firm load that is required to be reflected in prices. Unfortunately, ERCOT exceeded the mandate of the Commission by continuing to set process at VOLL long after it ceased the firm load shed.

ERCOT recalled the last of the firm load shed instructions at 23:55 on February 17, 2021. Therefore, in order to comply with the Commission Order, the pricing intervention that raised prices to VOLL should have ended immediately at that time. However, ERCOT continued to hold prices at VOLL by inflating the Real-Time On-Line Reliability Deployment Price Adder for an additional 32 hours through the morning of February 19. This decision resulted in $16 billion in additional costs to ERCOT's market, prompting legislative bailout proposals in Austin, of which roughly $1.5 billion was uplifted to load-serving entities to provide make-whole payments to generators for energy that was not needed or produced.

However, at its March 5, 2021, open meeting (related discussion begins around minute 20), although the PUCT acknowledged the "good points" raised by the IMM, the PUCT was not willing to retrospectively adjust its real-time pricing for this period out of concerns that some related transactions (ICE futures and others) may have already settled and for unintended consequences of such retroactive adjustments.  

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Earth Hour BC highlights BC Hydro data on electricity use, energy savings, and participation in the Lower Mainland and Vancouver Island amid climate change and hydroelectric power dynamics.

Key Points

BC observance tracking BC Hydro electricity use and conservation during Earth Hour, amid hydroelectric power dominance.

✅ BC Hydro reports rising electricity use during Earth Hour 2018

✅ Savings fell from 2% in 2008 to near zero province-wide

✅ Hydroelectric grid yields low GHG emissions in BC

For the first time since it began tracking electricity use in the province during Earth Hour, BC Hydro said customers used more power during the 60-minute period when lights are expected to dim, mirroring all-time high electricity demand seen recently.

The World Wildlife Fund launched Earth Hour in Sydney, Australia in 2007. Residents and businesses there turned off lights and non-essential power as a symbol to mark the importance of combating climate change.

The event was adopted in B.C. the next year and, as part of that, BC Hydro began tracking the megawatt hours saved.

#google#

In 2008, residents and businesses achieved a two per cent savings in electricity use. But since then, BC Hydro says the savings have plummeted.

The event was adopted in B.C. the next year and, as part of that, BC Hydro began tracking the megawatt hours saved.

In 2008, residents and businesses achieved a two per cent savings in electricity use. But since then, BC Hydro says the savings have plummeted, as record-breaking demand in 2021 and beyond changed consumption patterns.

Lights on

For Earth Hour this year, which took place 8:30-9:30 p.m. on March 24, BC Hydro says electricity use in the Lower Mainland increased by 0.5 per cent, even as it activated a winter payment plan to help customers manage bills. On Vancouver Island it increased 0.6 per cent.

In the province's southern Interior and northern Interior, power use remained the same during the event.

On Friday, the utility released a report called: "lights out". Why Earth Hour is dimming in BC. which explores the decline of energy savings related to Earth Hour in the province.

The WWF says the way in which hydro companies track electricity savings during Earth Hour is not an accurate measure of participation, and tracking of emerging loads like crypto mining electricity use remains opaque, and noted that more countries than ever are turning off lights for the event.

For 2018, the WWF shifted the focus of Earth Hour to the loss of wildlife across the globe.

BC Hydro says in its report that the symbolism of Earth Hour is still important to British Columbians, but almost all power generation in B.C. is hydroelectric, though recent drought conditions have required operational adjustments, and only accounts for one per cent of greenhouse gas emissions.

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Great Northern Transmission Line delivers 250 MW of carbon-free hydropower from Manitoba Hydro, strengthening Midwest grid reliability, enabling wind storage balancing, and advancing Minnesota Power's EnergyForward strategy for cleaner, renewable energy across the region.

Key Points

A 500 kV cross-border line delivering 250 MW of carbon-free hydropower, strengthening reliability and enabling renewables.

✅ 500 kV, 224-mile line from Manitoba to Minnesota

✅ Delivers 250 MW hydropower via ALLETE-Minnesota Power

✅ Enables wind storage and grid balancing with Manitoba Hydro

Minnesota Power, a utility division of ALLETE Inc. (NYSE:ALE), has energized its Great Northern Transmission Line, bringing online an innovative delivery and storage system for renewable energy that spans two states and one Canadian province, similar to the Maritime Link project in Atlantic Canada.

The 500 kV line is now delivering 250 megawatts of carbon-free hydropower from Manitoba, Canada, to Minnesota Power customers.

Minnesota Power completed the Great Northern Transmission Line (GNTL) in February 2020, ahead of schedule and under budget. The 224-mile line runs from the Canadian border in Roseau County to a substation near Grand Rapids, Minnesota. It consists of 800 tower structures which were fabricated in the United States and used 10,000 tons of North American steel. About 2,200 miles of wire were required to install the line's conductors. The GNTL also is contributing significant property tax revenue to local communities along the route.

"This is such an incredible achievement for Minnesota Power, ALLETE, and our region, and is the culmination of a decade-long vision brought to life by our talented and dedicated employees," said ALLETE President and CEO Bethany Owen. "The GNTL will help Minnesota Power to provide our customers with 50 percent renewable energy less than a year from now. As part of our EnergyForward strategy, it also strengthens the grid across the Midwest and in Canada, enhancing reliability for all of our customers."

With the GNTL energized and connected to Manitoba Hydro's recently completed Manitoba-Minnesota Transmission Project at the border, the companies now have a unique "wind storage" mechanism that quickly balances energy supply and demand in Minnesota and Manitoba, and enables a larger role for renewables in the North American energy grid.

The GNTL and its delivery of carbon-free hydropower are important components of Minnesota Power's EnergyForward strategy to transition away from coal and add renewable power sources while maintaining reliable and affordable service for customers, echoing interties like the Maritime Link that facilitate regional power flows. It also is part of a broader ALLETE strategy to advance and invest in critical regional transmission and distribution infrastructure, such as the TransWest Express transmission project, to ensure grid integrity and enable cleaner energy to reduce carbon emissions.

"The seed for this renewable energy initiative was planted in 2008 when Minnesota Power proposed purchasing 250 megawatts of hydropower from Manitoba Hydro. Beyond the transmission line, it also included a creative asset swap to move wind power from North Dakota to Minnesota, innovative power purchase agreements, and a remarkable advocacy process to find an acceptable route for the GNTL," said ALLETE Executive Chairman Al Hodnik. "It marries wind and water in a unique connection that will help transform the energy landscape of North America and reduce carbon emissions related to the existential threat of climate change."

Minnesota Power and Manitoba Hydro, a provincial Crown Corporation, coordinated on the project from the beginning, navigating National Energy Board reviews along the way. It is based on the companies' shared values of integrity, environmental stewardship and community engagement.

"The completion of Minnesota Power's Great Northern Transmission Line and our Manitoba-Minnesota Transmission Project is a testament to the creativity, perseverance, cooperation and skills of hundreds of people over so many years on both sides of the border," said Jay Grewal, president and CEO of Manitoba Hydro. "Perhaps even more importantly, it is a testament to the wonderful, longstanding relationship between our two companies and two countries. It shows just how much we can accomplish when we all work together toward a common goal."

Minnesota Power engaged federal, state and local agencies; the sovereign Red Lake Nation and other tribes, reflecting First Nations involvement in major transmission planning; and landowners along the proposed routes beginning in 2012. Through 75 voluntary meetings and other outreach forums, a preferred route was selected with strong support from stakeholders that was approved by the Minnesota Public Utilities Commission in April 2016.

A four-year state and federal regulatory process culminated in late 2016 when the federal Department of Energy approved a Presidential Permit for the GNTL, similar to the New England Clean Power Link process, needed because of the international border crossing. Construction of the line began in early 2017.

"A robust stakeholder process is essential to the success of any project, but especially when building a project of this scope," Owen said. "We appreciated the early engagement and support from stakeholders, local communities and tribes, agencies and regulators through the many approval milestones to the completion of the GNTL."

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