UN panel to rule on ChinaÂ’s wind projects

By Reuters


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Lobbyist pressure will not weigh on a UN panel's decision whether to award carbon finance worth about 100 million euros (US$144 million) to Chinese wind power projects, said the chair of the panel.

"If you add it all up there are quite a number of projects, all from China," Lex de Jonge told the Reuters Global Climate and Alternative Energy Summit, on a ruling due soon.

The issue has caused long-running tension between the panel and project developers and brokers about the speed of approvals in the $6.5 billion global carbon offset market.

Under the UN-led Kyoto Protocol's clean development mechanism, rich countries can buy rights to pollute by funding cuts in greenhouse gas emissions in developing nations.

The UN executive board in the past three months has decided to review if many new Chinese wind projects qualify, after noting a drop in financial support from Beijing.

The Kyoto scheme is supposed to fund additional cuts in emissions and if projects are self sufficient it may be that they are no longer cutting emissions below normal trends.

"We see a downward trend in (windpower price premium) tariffs in certain areas in China. Changing the tariff may have an impact on a final decision on whether a project is additional," he said at the summit held at the Reuters office in London.

The panel is reviewing 17 projects with a total capacity of more than 900 megawatts, enough to power about 1 million homes. The projects would produce through 2012 some 8 million tonnes of carbon offsets called certified emissions reductions (CERs), worth 107 million euros at today's prices.

Clean Development Mechanism (CDM) projects must prove either that the scheme allowed a project to overcome some barrier such as financial uncertainty, or that the project was not as financially attractive as an alternative such as coal power.

Market participants say the rules should be simpler — pointing out that in China electricity generation is dominated by high-carbon coal.

"The need to encourage the deployment of wind energy in countries like China, where energy needs are growing rampantly, is enormous," said the lobby group the International Emissions Trading Association in a letter to de Jonge last month.

China has recently firmed its support for the wind power sector in some regions with a premium tariff levied, complicating the issue of whether Chinese official support is indeed falling.

"I didn't count and I don't care," said de Jonge when asked how much the projects under review were worth. "That might sound strange but this is about safeguarding integrity of the CDM."

"With so much money involved, people have interests and if they don't see their interests followed they start complaining. I don't feel pressured about this. To me it's normal."

De Jonge said that some past "bashing" of the board had been justified, for example with regard to a lack of transparency, but added that waiting times were falling following new guidance.

Most criticism of the CDM now came from the United States, he said. "(American) NGOs and academics are critical toward the CDM... based on arguments that are no longer valid."

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Powering Towards Net Zero: The UK Grid's Transformation Challenge

UK Electricity Grid Investment underpins net zero, reinforcing transmission and distribution networks to integrate wind, solar, EV charging, and heat pumps, while Ofgem balances investor returns, debt risks, price controls, resilience, and consumer bills.

 

Key Points

Capital to reinforce grids for net zero, integrating wind, solar, EVs and heat pumps while balancing returns and bills.

✅ 170bn-210bn GBP by 2050 to reinforce cables, pylons, capacity.

✅ Ofgem to add investability metric while protecting consumers.

✅ Integrates wind, solar, EVs, heat pumps; manages grid resilience.

 

Prime Minister Sunak's recent upgrade to his home's electricity grid, designed to power his heated swimming pool, serves as a microcosm of a much larger challenge facing the UK: transforming the nation's entire electricity network for net zero emissions, amid Europe's electrification push across the continent.

This transition requires a monumental £170bn-£210bn investment by 2050, earmarked for reinforcing and expanding onshore cables and pylons that deliver electricity from power stations to homes and businesses. This overhaul is crucial to accommodate the planned switch from fossil fuels to clean energy sources - wind and solar farms - powering homes with electric cars, as EV demand on the grid rises, and heat pumps.

The UK government's Climate Change Committee warns of potentially doubled electricity demand by 2050, the target date for net zero, even though managing EV charging can ease local peaks. This translates to a significant financial burden for companies like National Grid, SSE, and Scottish Power who own the main transmission networks and some regional distribution networks.

Balancing investor needs for returns and ensuring affordable energy bills for consumers presents a delicate tightrope act for regulators like Ofgem. The National Audit Office criticized Ofgem in 2020 for allowing network owners excessive returns, prompting concerns about potential bill hikes, especially after lessons from 2021 reshaped market dynamics.

Think-tank Common Wealth reported that distribution networks paid out a staggering £3.6bn to their owners between 2017 and 2021, raising questions about the balance between profitability and affordability, amid UK EV affordability concerns among consumers.

However, Ofgem acknowledges the need for substantial investment to finance network upgrades, repairs, and the clean energy transition. To this end, they are considering incorporating an "investability" metric, recognizing how big battery rule changes can erode confidence elsewhere, in the next price controls for transmission networks, ensuring these entities remain attractive for equity fundraising without overburdening consumers.

This proposal, while welcomed by the industry, has drawn criticism from consumer advocacy groups like Citizens Advice, who fear it could contribute to unfairly high bills. With energy bills already hitting record highs, public trust in the net-zero transition hinges on ensuring affordability.

High debt levels and potential credit rating downgrades further complicate the picture, potentially impacting companies' ability to raise investment funds. Ofgem is exploring measures to address this, such as stricter debt structure reporting requirements for regional distribution companies.

Lawrence Slade, CEO of the Energy Networks Association, emphasizes the critical role of investment in achieving net zero. He highlights the need for "bold" policies and regulations that balance ambitious goals with investor confidence and ensure efficient resource allocation, drawing on B.C.'s power supply challenges as a cautionary example.

The challenge lies in striking a delicate balance between attracting investment, ensuring network resilience, and maintaining affordable energy bills. As Andy Manning from Citizens Advice warns, "Without public confidence, net zero won't be delivered."

The UK's journey to net zero hinges on navigating this complex landscape. By carefully calibrating regulations, fostering investor confidence, and prioritizing affordability, the country can ensure its electricity grid is not just robust enough to power heated swimming pools, but also a thriving green economy for all.

 

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BC Hydro Rates to Rise by 3.75% Over Two Years

British Columbia electricity rate increase will raise BC Hydro bills 3.75% over 2025-2026 to fund infrastructure, Site C, and clean energy, balancing affordability, reliability, and energy security while keeping prices below the North American average.

 

Key Points

BC will raise BC Hydro rates 3.75% in 2025-2026, about $3.75/month, to fund grid upgrades, Site C, and clean energy.

✅ 3.75% over 2025-2026; about $3.75/month on $100 average bill

✅ Funds Site C, grid maintenance, and clean energy capacity

✅ Keeps BC Hydro rates below North American averages

 

British Columbia's electricity rates will experience a 3.75% increase over the next two years, following an earlier 3% rate increase approval that set the stage, as confirmed by the provincial government on March 17, 2025. The announcement was made by Minister of Energy and Climate Solutions, Adrian Dix, who emphasized the decision's necessity for maintaining BC Hydro’s infrastructure while balancing affordability for residents.

For most households, the increase will amount to an additional $3.75 per month, based on an average BC Hydro bill of $100, though some coverage framed an earlier phase as a BC Hydro $2/month proposal that later evolved. While this may seem modest, the increase reflects a broader strategy to stabilize the utility's rates amidst economic challenges and ensure long-term energy security for the province.

Reasons Behind the Rate Hike

The rate increase comes during a period of rising costs in both global markets and local economies. According to Dix, the economic uncertainty stemming from trade dynamics and inflation has forced the government to act. Despite these pressures, and after a prior B.C. rate freeze to moderate impacts, the increase remains below cumulative inflation over the last several years, a move designed to shield consumers from the full force of these economic changes.

Dix also noted that, when adjusted for inflation, electricity rates in British Columbia in 2025 are effectively at the same price they were four decades ago. This stability, he argued, underscores the provincial government’s commitment to keeping rates as low as possible for residents, even as operating costs rise.

“We must take urgent action to protect British Columbians from the uncertainty posed by rising costs while building a strong, resilient electricity system for the long-term benefit of B.C.’s energy independence,” Dix said. He also highlighted the government's approach to minimizing the financial burden on consumers by keeping electricity costs well below the North American average.

Infrastructure and Maintenance Costs

The primary justification for the rate increase is to allow BC Hydro to continue its critical infrastructure development, including the Site C hydroelectric project, which is expected to become operational in the coming years. The increased costs of maintaining and upgrading the province's electricity grid also contribute to the need for higher rates.

The Site C project, a massive hydroelectric dam under construction on the Peace River, is expected to provide a substantial increase in clean, renewable energy capacity. However, such large-scale projects require significant investment and maintenance, both of which have contributed to the increased operating costs for BC Hydro.

A Strategic Move for Rate Stability

The provincial government has been clear that the rate increase will allow for a continuation of infrastructure development while keeping the rates manageable for consumers. The 3.75% increase will be spread across two years, with the first hike scheduled for April 1, 2025, reflecting the typical April rate changes BC Hydro implements, and the second for April 1, 2026.

Dix confirmed that the rate hike would still keep electricity costs among the lowest in North America, noting that British Columbians pay about half of what residents in Alberta pay for electricity. This is part of a broader effort by the provincial government to provide stable energy pricing while bolstering the transition to clean energy solutions, such as the Site C project and other renewable energy initiatives.

Addressing Public Concerns

Although the government has framed the increase as a necessary measure to ensure the province's long-term energy independence and reliability, the rate hikes are likely to face scrutiny from residents, particularly those already struggling with the rising cost of living, even as provinces like Ontario face their own Ontario hydro rate increase pressures this fall.

Public reactions to utility rate increases are often contentious, as residents feel the pressure of rising prices across various sectors, from housing to healthcare. However, the government has promised that the new rates will remain manageable, especially considering the relatively low rate increases compared to inflation and other regions where Manitoba Hydro scaled back a planned increase to temper impacts.

Furthermore, the increase comes as part of a broader strategy that aims to keep the overall impact on consumers as low as possible. Minister Dix emphasized that these rate increases were intended to ensure the continued reliability of BC Hydro’s services, without overwhelming ratepayers.

Long-Term Goals

Looking ahead, the province's strategy centers on not only maintaining affordable electricity rates but also reinforcing the importance of renewable energy, while some jurisdictions consider a 2.5% annual increase plan over multiple years to stabilize their grids. As climate change becomes an increasingly pressing issue, BC’s investments in clean energy projects like Site C aim to provide sustainable power for generations to come.

The government’s long-term vision involves building a resilient, energy-independent province that can weather future economic and environmental challenges. In this context, the rate increases are framed not just as a response to immediate inflationary pressures but as a necessary step in preparing BC’s energy infrastructure for the future.

The 3.75% rate increase set for 2025 and 2026 represents a balancing act between managing the financial health of BC Hydro and protecting consumers from higher costs. While the increase will have a modest effect on household bills, the long-term goal is to build a more robust and sustainable electricity system for British Columbia’s future. Through investments in clean energy and strategic infrastructure development, the province aims to keep electricity rates competitive while positioning itself as a leader in energy independence and climate action.

 

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US January power generation jumps 9.3% on year: EIA

US January power generation climbed to 373.2 TWh, EIA data shows, with coal edging natural gas, record wind output, record nuclear generation, rising hydro, and stable utility-scale solar amid higher Henry Hub prices.

 

Key Points

US January power generation hit 373.2 TWh; coal led gas, wind and nuclear set records, with solar edging higher.

✅ Coal 31.8% share; gas 29.4%; coal output 118.7 TWh, gas 109.6 TWh.

✅ Wind hit record 26.8 TWh; nuclear record 74.6 TWh.

✅ Total generation 373.2 TWh, highest January since 2014.

 

The US generated 373.2 TWh of power in January, up 7.9% from 345.9 TWh in December and 9.3% higher than the same month in 2017, Energy Information Administration data shows.

The monthly total was the highest amount in January since 377.3 TWh was generated in January 2014.

Coal generation totaled 118.7 TWh in January, up 11.4% from 106.58 TWh in December and up 2.8% from the year-ago month, consistent with projections of a coal-fired generation increase for the first time since 2014. It was also the highest amount generated in January since 132.4 TWh in 2015.

For the second straight month, more power was generated from coal than natural gas, as 109.6 TWh came from gas, up 3.3% from 106.14 TWh in December and up 19.9% on the year.

However, the 118.7 TWh generated from coal was down 9.6% from the five-year average for the month, due to the higher usage of gas and renewables and a rising share of non-fossil generation in the overall mix.

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Coal made up 31.8% of the total US power generation in January, up from 30.8% in December but down from 33.8% in January 2017.

Gas` generation share was at 29.4% in the latest month, with momentum from record gas-fired electricity earlier in the period, down from 30.7% in December but up from 26.8% in the year-ago month.

In January, the NYMEX Henry Hub gas futures price averaged $3.16/MMBtu, up 13.9% from $2.78/MMBtu averaged in December but down 4% from $3.29/MMBtu averaged in the year-ago month.

 

WIND, NUCLEAR GENERATION AT RECORD HIGHS

Wind generation was at a record-high 26.8 TWh in January, up 29.3% from 22.8 TWh in December and the highest amount on record, according to EIA data going back to January 2001. Wind generated 7.2% of the nation`s power in January, as an EIA summer outlook anticipates larger wind and solar contributions, up from 6.6% in December and 6.1% in the year-ago month.

Utility-scale solar generated 3.3 TWh in January, up 1.3% from 3.1 TWh in December and up 51.6% on the year. In January, utility-scale solar generation made up 0.9% of US power generation, during a period when solar and wind supplied 10% of US electricity in early 2018, flat from December but up from 0.6% in January 2017.

Nuclear generation was also at a record-high 74.6 TWh in January, up 1.3% month on month and the highest monthly total since the EIA started tracking it in January 2001, eclipsing the previous record of 74.3 TWh set in July 2008. Nuclear generation made up 20% of the US power in January, down from 21.3% in December and 21.4% in the year-ago month.

Hydro power totaled 25.4 TWh in January, making up 6.8% of US power generation during the month, up from 6.5% in December but down from 8.2% in January 2017.

 

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Two huge wind farms boost investment in America’s heartland

MidAmerican Energy Wind XI expands Iowa wind power with the Beaver Creek and Prairie farms, 169 turbines and 338 MW, delivering renewable energy, grid reliability, rural jobs, and long-term tax revenue through major investment.

 

Key Points

MidAmerican Energy Wind XI is a $3.6B Iowa wind buildout adding 2,000 MW to enhance reliability, jobs, and tax revenue.

✅ 169 turbines at Beaver Creek and Prairie deliver 338 MW.

✅ Wind supplies 36.6 percent of Iowa electricity generation.

✅ Projects forecast $62.4M in property taxes over 20 years.

 

Power company MidAmerican Energy recently announced the beginning of operations at two huge wind farms in the US state of Iowa.

The two projects, called Beaver Creek and Prairie, total 169 turbines and have a combined capacity of 338 megawatts (MW), enough to meet the annual electricity needs of 140,000 homes in the state.

“We’re committed to providing reliable service and outstanding value to our customers, and wind energy accomplishes both,” said Mike Fehr, vice president of resource development at MidAmerican. “Wind energy is good for our customers, and it’s an abundant, renewable resource that also energizes the economy.”

The wind farms form part of MidAmerican Energy’s major Wind XI project, which will see an extra 2,000MW of wind power built, and $3.6 billion invested amid notable wind farm acquisitions shaping the market by the end of 2019. The company estimates it is the largest economic development project in Iowa’s history.

Iowa is something of a hidden powerhouse in American wind energy. The technology provides an astonishing 36.6 percent of the state’s entire electricity generation and plays a growing role in the U.S. electricity mix according to the American Wind Energy Association (AWEA). It also has the second largest amount of installed capacity in the nation at 6917MW; Texas is first with over 21,000MW.

Along with capital investment, wind power brings significant job opportunities and tax revenues for the state. An estimated 9,000 jobs are supported by the industry, something a U.S. wind jobs forecast stated could grow to over 15,000 within a couple of years.

MidAmerican Energy is also keen to stress the economic benefits of its new giant projects, claiming that they will bring in $62.4 million of property tax revenue over their 20-year lifetime.

Tom Kiernan, AWEA’s CEO, revealed last year that, as the most-used source of renewable electricity in the U.S., wind energy is providing more than five states in the American Midwest with over 20 percent of electricity generation, “a testament to American leadership and innovation”.

“For these states, and across America, wind is welcome because it means jobs, investment, and a better tomorrow for rural communities”, he added.

 

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Sask. sets new record for power demand

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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Pickering NGS life extensions steer Ontario towards zero carbon horizon

OPG Pickering Nuclear Refurbishment extends four CANDU reactors to bolster Ontario clean energy, grid reliability, and decarbonization goals, leveraging Darlington lessons, mature supply chains, and AtkinsRealis OEM expertise for cost effective life extension.

 

Key Points

Modernizing four Pickering CANDU units to extend life, add clean power, and enhance Ontario grid reliability.

✅ Extends four 515 MW CANDU reactors by 30 years

✅ Supports clean, reliable baseload and decarbonization

✅ Leverages Darlington playbook and AtkinsRealis OEM supply chain

 

In a pivotal shift last month, Ontario Power Generation (OPG) revised its strategy for the Pickering Nuclear Power Station, scrapping plans to decommission its six remaining reactors. Instead, OPG has opted to modernize four reactors (Pickering B Units 5-8) starting in 2027, while Units 1 and 4 are slated for closure by the end of the current year.

This revision ensures the continued operation of the four 515 MW Canada Deuterium Uranium (CANDU) reactors—originally constructed in the 1970s and 1980s—extending their service life by at least 30 more years amid an extension request deadline for Pickering.

Todd Smith, Ontario's Energy Minister, underscored the significance of nuclear power in maintaining Ontario's status as a region with one of the cleanest and most reliable electricity grids globally. He emphasized the integral role of nuclear facilities, particularly the Pickering station, in the provincial energy strategy during the announcement supporting continued operations, which was made in the presence of union workers at the plant.

The Pickering station has demonstrated remarkable efficiency and reliability, notably achieving its second-highest output in 2023 and setting a record in 2022 for continuous operation. Extending the lifespan of nuclear plants like Pickering is deemed the most cost-effective method for sustaining low-carbon electricity, according to research conducted by the International Energy Agency (IEA) and the OECD Nuclear Energy Agency (NEA) across 243 plants in 24 countries.

The refurbishment project is poised to significantly boost Ontario's economy, projected to add CAN$19.4 billion to the GDP over 11 years and generate approximately 11,000 jobs annually. The Independent Electricity System Operator (IESO) has indicated that to meet the province's future electrification and decarbonization goals, as it faces a growing electricity supply gap, Ontario will need to double its nuclear capacity by 2050, requiring an addition of 17.8 GW of nuclear power.

Subo Sinnathamby, OPG's Senior Vice President of Nuclear Refurbishment, emphasized the necessity of nuclear energy in reducing reliance on natural gas. Sinnathamby, who is leading the refurbishment efforts at OPG's Darlington nuclear power station, where SMR plans are also underway, highlighted the positive impact of the Darlington and Bruce Power projects on the nuclear power supply chain and workforce.

The procurement strategy employed for Darlington, which involved placing orders early to ensure readiness among suppliers, is set to be replicated for the Pickering refurbishment. This approach aims to facilitate a seamless transition of skilled workers and resources from Darlington to Pickering refurbishment, leveraging a matured supply chain and experienced vendors.

AtkinsRealis, the original equipment manufacturer (OEM) for CANDU reactors, has a track record of successfully refurbishing CANDU plants worldwide. The CANDU reactor design, known for its refurbishment capabilities, allows for individual replacement of pressure tubes and access to fuel channels without decommissioning the reactor. Gary Rose, Executive Vice-President of Nuclear at AtkinsRealis, highlighted the economic benefits and environmental benefits of refurbishing reactors, stating it as a viable and swift solution to maximize fossil-free energy.

Looking forward, AtkinsRealis is exploring the potential for multiple refurbishments of CANDU reactors, which could extend their operational life beyond 100 years, addressing local energy needs and economic factors in the decision-making process. This innovative approach underscores the role of nuclear refurbishment in meeting global energy demands sustainably and economically.

 

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