Dominican power companies to break up distributors

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.

Related News

• Electricity Forum News

• Renewable Energy News

Hydro-Québec $185-Billion Clean Energy Plan accelerates hydroelectric upgrades, wind power expansion, solar and battery storage, pumped storage, and 5,000 km transmission lines to decarbonize Quebec, boost grid resilience, and attract bond financing and Indigenous partnerships.

Key Points

Plan to grow renewables, harden the grid, and fund Quebec's decarbonization with major investments.

✅ $110B new generation, $50B grid resilience by 2035

✅ Triple wind, add solar, batteries, and pumped storage

✅ 5,000 km lines, bond financing, Indigenous partnerships

Hydro-Québec is in the preliminary stages of dialogue with various financiers and potential collaborators to strategize the implementation of a $185-billion initiative aimed at transitioning Quebec away from fossil fuel dependency.

As the leading hydroelectric power producer in Canada, Hydro-Québec is set to allocate up to $110 billion by 2035 towards the development of new clean energy facilities, building on its hydropower capacity expansion in recent years, with an additional $50 billion dedicated to enhancing the resilience of its power grid, as revealed in a strategy announced last November. The remainder of the projected expenditure will cover operational costs.

This ambitious initiative has garnered significant interest from the financial sector, with the province's recent electricity for industrial projects also drawing attention, as noted by CEO Michael Sabia during a conference call with journalists where the utility's annual financial outcomes were discussed. Sabia reported receiving various proposals to fund the initiative, though specific partners were not disclosed. He expressed confidence in securing the necessary capital for the project's success.

Sabia highlighted three immediate strategies to increase power output: identifying new sites for hydroelectric projects while upgrading turbines at existing facilities, such as the Carillon Generating Station upgrade now underway for enhanced efficiency, expanding wind energy production threefold, and promoting energy conservation among consumers to optimize current power usage.

Additionally, Hydro-Québec aims to augment its solar and battery energy production and is planning to establish a pumped-storage hydroelectric plant to support peak demand periods. The utility also intends to construct 5,000 kilometers of new transmission lines, address Quebec-to-U.S. transmission constraints where feasible, and is set to double its capital expenditure to $16 billion annually, a significant increase from the investment levels during the James Bay hydropower project construction in the 1970s and 1980s.

To fund part of this expansive plan, Hydro-Québec will continue to access the bond market, having issued $3.7 billion in notes to investors last year despite facing several operational hurdles due to adverse weather conditions.

For the year 2023, Hydro-Québec reported a net income of $3.3 billion, marking a 28% decrease from the previous year's record of $4.56 billion. Factors such as insufficient snow cover, reduced spring runoff, and higher temperatures resulted in lower water levels in reservoirs, leading to a reduction in power exports and a $547-million decrease in external market sales compared to the previous year.

The utility experienced its lowest export volume in a decade but managed to leverage hedging strategies to secure 10.3 cents per kWh for exported power to markets including New Brunswick via recent NB Power agreements that expand interprovincial deliveries, nearly twice the average market rate, through forward contracts that cover up to half of its export volume for about a year in advance.

The success of Sabia's plan will partly depend on the cooperation of First Nations communities, as the proposed infrastructure developments are likely to traverse their ancestral territories. Relationships with some communities are currently tense, exemplified by the Innu of Labrador's $4-billion lawsuit against Hydro-Québec for damages related to land flooding for reservoir construction, and broader regional tensions in Newfoundland and Labrador that persist in the power sector.

Sabia has committed to involving First Nations and Inuit communities as partners in clean energy ventures, offering them ongoing financial benefits rather than one-off settlements, a principle he refers to as "economic reconciliation."

Recently, the Quebec government reached an agreement with the Innu of Pessamit, pledging $45 million to support local community development. This agreement outlines solutions for managing a nearby hydropower reservoir, such as the La Romaine complex in the region, and includes commitments for wind energy development.

Sabia is optimistic about building stronger, more positive relationships with various Indigenous communities, anticipating significant progress in the coming months and viewing this year as a potential milestone in transforming these relationships for the better.

Related News

• Electricity Forum News

• Power Generation News

Germany 2025 Energy Costs forecast electricity and heating price trends amid gas volatility, renewables expansion, grid upgrades, and policy subsidies, highlighting impacts on households, industries, efficiency measures, and the Energiewende transition dynamics.

Key Points

Electricity stabilizes, gas-driven heating stays high; renewables, subsidies, and efficiency measures moderate costs.

✅ Power prices stabilize above pre-crisis levels

✅ Gas volatility keeps heating bills elevated

✅ Subsidies and efficiency upgrades offset some costs

As Germany moves into 2025, the country is facing significant shifts in heating and electricity costs. With a variety of factors influencing energy prices, including geopolitical tensions, government policies, and the ongoing transition to renewable energy sources, consumers and businesses alike are bracing for potential changes in their energy bills. In this article, we will explore how heating and electricity costs are expected to evolve in Germany in the coming year and what that means for households and industries.

Energy Price Trends in Germany

In recent years, energy prices in Germany have experienced notable fluctuations, particularly due to the aftermath of the global energy crisis, which was exacerbated by the Russian invasion of Ukraine. This geopolitical shift disrupted gas supplies, which in turn affected electricity prices and strained local utilities across the country. Although the German government introduced measures to mitigate some of the price increases, many households have still felt the strain of higher energy costs.

For 2024, experts predict that electricity prices will likely stabilize but remain higher than pre-crisis levels. While electricity prices nearly doubled in 2022, they have gradually started to decline, and the market has adjusted to the new realities of energy supply and demand. Despite this, the cost of electricity is expected to stay elevated as Germany continues to phase out coal and nuclear energy while ramping up the use of renewable sources, which often require significant infrastructure investments.

Heating Costs: A Mixed Outlook

Heating costs in Germany are heavily influenced by natural gas prices, which have been volatile since the onset of the energy crisis. Gas prices, although lower than the peak levels seen in 2022, are still considerably higher than in the years before. This means that households relying on gas heating can expect to pay more for warmth in 2024 compared to previous years.

The government has implemented measures to cushion the impact of these increased costs, such as subsidies for vulnerable households and efforts to support energy efficiency upgrades. Despite these efforts, consumers will still feel the pinch, particularly in homes that use older, less efficient heating systems. The transition to more sustainable heating solutions, such as heat pumps, remains a key goal for the German government. However, the upfront cost of such systems can be a barrier for many households.

The Role of Renewable Energy and the Green Transition

Germany has set ambitious goals for its energy transition, known as the "Energiewende," which aims to reduce reliance on fossil fuels and increase the share of renewable energy sources in the national grid. In 2024, Germany is expected to see further increases in renewable energy generation, particularly from wind and solar power. While this transition is essential for reducing carbon emissions and improving long-term energy security, the shift comes with its own challenges already documented in EU electricity market trends reports.

One of the main factors influencing electricity costs in the short term is the intermittency of renewable energy sources. Wind and solar power are not always available when demand peaks, requiring backup power generation from fossil fuels or stored energy. Additionally, the infrastructure needed to accommodate a higher share of renewables, including grid upgrades and energy storage solutions, is costly and will likely contribute to rising electricity prices in the near term.

On a positive note, Germany's growing investment in renewable energy is expected to make the country less reliant on imported fossil fuels, particularly natural gas, which has been a major source of price volatility. Over time, as the share of renewables in the energy mix grows, the energy system should become more stable and less susceptible to geopolitical shocks, which could lead to more predictable and potentially lower energy costs in the long run.

Government Interventions and Subsidies

To help ease the burden on consumers, the German government has continued to implement various measures to support households and businesses. One of the key programs is the reduction in VAT (Value Added Tax) on electricity, which has been extended in some regions. This measure is designed to make electricity more affordable for all households, particularly those on fixed incomes facing EU energy inflation pressures that have hit the poorest hardest.

Moreover, the government has been providing financial incentives for households and businesses to invest in energy-efficient technologies, such as insulation and energy-saving heating systems, complementing the earlier 200 billion euro energy shield announced to buffer surging prices. These incentives are intended to reduce overall energy consumption, which could offset some of the rising costs.

The outlook for heating and electricity costs in Germany for 2024 is mixed, even as energy demand hit a historic low amid economic stagnation. While some relief from the extreme price spikes of 2022 may be felt, energy costs will still be higher than they were in previous years. Households relying on gas heating will likely see continued elevated costs, although those who invest in energy-efficient solutions or renewable heating technologies may be able to offset some of the increases. Similarly, electricity prices are expected to stabilize but remain high due to the country’s ongoing transition to renewable energy sources.

While the green transition is crucial for long-term sustainability, consumers must be prepared for potentially higher energy costs in the short term. Government subsidies and incentives will help alleviate some of the financial pressure, but households should consider strategies to reduce energy consumption, such as investing in more efficient heating systems or adopting renewable energy solutions like solar panels.

As Germany navigates these changes, the country’s energy future will undoubtedly be shaped by a delicate balance between environmental goals and the economic realities of transitioning to a greener energy system.

Related News

• Electricity Forum News

• Energy Policy News

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.

Related News

• Electricity Forum News

• Power Generation News

Electricity Investment Surpasses Oil and Gas 2016, driven by renewable energy, power grids, and energy efficiency, as IEA reports lower oil and gas spending, rising solar and wind capacity, and declining coal power plant approvals.

Key Points

A 2016 milestone where electricity topped global energy investment, led by renewables, grids, and efficiency, per the IEA.

✅ IEA: electricity investment hit $718b; oil and gas fell to $650b.

✅ Renewables led with $297b; solar and wind unit costs declined.

✅ Coal plant approvals plunged; networks and storage spending rose.

Investments in electricity surpassed those in oil and gas for the first time ever in 2016 on a spending splurge on renewable energy and power grids as the fall in crude prices led to deep cuts, the International Energy Agency (IEA) said.

Total energy investment fell for the second straight year by 12 per cent to US$1.7 trillion compared with 2015, the IEA said. Oil and gas investments plunged 26 per cent to US$650 billion, down by over a quarter in 2016, and electricity generation slipped 5 per cent.

"This decline (in energy investment) is attributed to two reasons," IEA chief economist Laszlo Varro told journalists.

"The reaction of the oil and gas industry to the prolonged period of low oil prices which was a period of harsh investment cuts; and technological progress which is reducing investment costs in both renewable power and in oil and gas," he said.

Oil and gas investment is expected to rebound modestly by 3 per cent in 2017, driven by a 53 per cent upswing in U.S. shale, and spending in Russia and the Middle East, the IEA said in a report.

"The rapid ramp up of U.S. shale activities has triggered an increase of U.S. shale costs of 16 per cent in 2017 after having almost halved from 2014-16," the report said.

The global electricity sector, however, was the largest recipient of energy investment in 2016 for the first time ever, overtaking oil, gas and coal combined, the report said.

"Robust investments in renewable energy and increased spending in electricity networks, which supports the outlook that low-emissions sources will cover most demand growth, made electricity the biggest area of capital investments," Varro said.

Electricity investment worldwide was US$718 billion, lifted by higher spending in power grids which offset the fall in power generation investments.

"Investment in new renewables-based power capacity, at US$297 billion, remained the largest area of electricity spending, despite falling back by 3 per cent as clean energy investment in developing nations slipped, the report said."

Although renewables investments was 3 per cent lower than five years ago, capacity additions were 50 per cent higher and expected output from this capacity about 35 per cent higher, thanks to the fall in unit costs and technology improvements in solar PV and wind generation, the IEA said.

COAL INVESTMENT IS COMING TO AN END

Investments in coal-fired electricity plants fell sharply. Sanctioning of new coal power plants fell to the lowest level in nearly 15 years, reflecting concerns about local air pollution, and emergence of overcapacity and competition from renewables, with renewables poised to eclipse coal in global power generation, notably in China. Coal investments, however, grew in India.

"Coal investment is coming to an end. At the very least, it is coming to a pause," Varro said.

The IEA report said energy efficiency investments continued to expand in 2016, reaching US$231 billion, with most of it going to the building sector globally.

Electric vehicles sales rose 38 per cent in 2016 to 750,000 vehicles at $6 billion, and represented 10 per cent of all transport efficiency spending. Some US$6 billion was spent globally on electronic vehicle charging stations, the IEA said.

Spending on electricity networks and storage continued the steady rise of the past five years, as surging electricity demand puts power systems under strain, reaching an all-time high of US$277 billion in 2016, with 30 per cent of the expansion driven by China’s spending in its distribution system, the report said.

China led the world in energy investments with 21 per cent of global total share, the report said, driven by low-carbon electricity supply and networks projects.

Although oil and gas investments fell in the United States in 2016, its total energy investments rose 16 per cent, even as Americans use less electricity in recent years, on the back of spending in renewables projects, the IEA report said.

Related News

• Electricity Forum News

• Power Generation News

Ottawa Electricity Consumption Drop reflects COVID-19 impacts, with Hydro Ottawa and IESO reporting 10-12% lower demand, delayed morning peaks, and shifted weekend peak to 4 p.m., alongside provincial time-of-use rate relief.

Key Points

A 10-12% decline in Ottawa's electricity demand during COVID-19, with later morning peaks and weekend peak at 4 p.m.

✅ Weekday demand down 11%; weekends down 10% vs April 2019.

✅ Morning peak delayed about 4 hours; 6 a.m. usage down 17%.

✅ Weekend peak moved from 7 p.m. to 4 p.m.; rate relief ongoing.

Ottawa residents may be spending more time at home, with residential electricity use up even as the city’s overall energy use has dropped during the COVID-19 pandemic.

Hydro Ottawa says there was a 10-to-11 per cent drop in electricity consumption in April, with the biggest decline in electricity usage happening early in the morning, a pattern echoed by BC Hydro findings in its province.

Statistics provided to CTV News Ottawa show average hourly energy consumption in the City of Ottawa dropped 11 per cent during weekdays, mirroring Manitoba Hydro trends reported during the pandemic, and a 10 per cent decline in electricity consumption on weekends.

The drop in energy consumption came as many businesses in Ottawa closed their doors due to the COVID-19 measures and physical distancing guidelines.

“Based on our internal analysis, when comparing April 2020 to April 2019, Hydro Ottawa observed a lower, flatter rise in energy use in the morning, with peak demand delayed by approximately four hours.” Hydro Ottawa said in a statement to CTV News Ottawa.

“Morning routines appear to have the largest difference in energy consumption, most likely as a result of a collective slower pace to start the day as people are staying home.”

Hydro Ottawa says overall, there was an 11 per cent average hourly reduction in energy use on weekdays in April 2020, compared to April 2019. The biggest difference was the 6 a.m. hour, with a 17 per cent decrease.

On weekends, the average electricity usage dropped 10 per cent in April, compared to April 2019. The biggest difference was between 7 a.m. and 8 a.m., with a 13 per cent drop in hydro usage.

Hydro Ottawa says weekday peak continues to be at 4 p.m., while on weekends the peak has shifted from 7 p.m. before the pandemic to 4 p.m. now, though Hydro One has not cut peak rates for self-isolating customers.

The Independent Electricity System Operator says across Ontario, there has been a 10 to 12 per cent drop in energy consumption during the pandemic, a trend reflected in province-wide demand data that is the equivalent to half the demand of Toronto.

The Ontario Government has provided emergency electricity rate relief during the COVID-19 pandemic. Residential and small business consumers on time-of-use pricing, and later ultra-low overnight options, will continue to pay one price no matter what time of day the electricity is consumed until the end of May.

Related News

• Electricity Forum News

• Utility Operations News