Quebec spurs rush in wind power

California Biofuels vs EV Subsidies examines tradeoffs in decarbonization, greenhouse gas reductions, clean energy deployment, charging infrastructure, energy security, lifecycle emissions, and transportation sector policy to meet climate goals and accelerate sustainable mobility.

Key Points

Policy tradeoffs weighing biofuels and EVs to cut GHGs, boost energy security, and advance clean transportation.

✅ Near-term blending cuts emissions from existing fleets

✅ EVs scale with a cleaner grid and charging buildout

✅ Lifecycle impacts and costs guide optimal subsidy mix

California is at the forefront of the transition to a greener economy, driven by its ambitious goals to reduce greenhouse gas emissions and combat climate change. As part of its strategy, the state is grappling with the question of whether it should subsidize out-of-state biofuels or in-state electric vehicles (EVs) to meet these goals. Both options come with their own sets of benefits and challenges, and the decision carries significant implications for the state’s environmental, economic, and energy landscapes.

The Case for Biofuels

Biofuels have long been promoted as a cleaner alternative to traditional fossil fuels like gasoline and diesel. They are made from organic materials such as agricultural crops, algae, and waste, which means they can potentially reduce carbon emissions in comparison to petroleum-based fuels. In the context of California, biofuels—particularly ethanol and biodiesel—are viewed as a way to decarbonize the transportation sector, which is one of the state’s largest sources of greenhouse gas emissions.

Subsidizing out-of-state biofuels can help California reduce its reliance on imported oil while promoting the development of biofuel industries in other states. This approach may have immediate benefits, as biofuels are widely available and can be blended with conventional fuels to lower carbon emissions right away. It also allows the state to diversify its energy sources, improving energy security by reducing dependency on oil imports.

Moreover, biofuels can be produced in many regions across the United States, including rural areas. By subsidizing out-of-state biofuels, California could foster economic development in these regions, creating jobs and stimulating agricultural innovation. This approach could also support farmers who grow the feedstock for biofuel production, boosting the agricultural economy in the U.S.

However, there are drawbacks. The environmental benefits of biofuels are often debated. Critics argue that the production of biofuels—particularly those made from food crops like corn—can contribute to deforestation, water pollution, and increased food prices. Additionally, biofuels are not a silver bullet in the fight against climate change, as their production and combustion still release greenhouse gases. When considering whether to subsidize biofuels, California must also account for the full lifecycle emissions associated with their production and use.

The Case for Electric Vehicles

In contrast to biofuels, electric vehicles (EVs) offer a more direct pathway to reducing emissions from transportation. EVs are powered by electricity, and when coupled with renewable energy sources like solar or wind power, they can provide a nearly zero-emission solution for personal and commercial transportation. California has already invested heavily in EV infrastructure, including expanding its network of charging stations and exploring how EVs can support grid stability through vehicle-to-grid approaches, and offering incentives for consumers to purchase EVs.

Subsidizing in-state EVs could stimulate job creation and innovation within California's thriving clean-tech industry, with other states such as New Mexico projecting substantial economic gains from transportation electrification, and the state has already become a hub for electric vehicle manufacturers, including Tesla, Rivian, and several battery manufacturers. Supporting the EV industry could further strengthen California’s position as a global leader in green technology, attracting investment and fostering growth in related sectors such as battery manufacturing, renewable energy, and smart grid technology.

Additionally, the environmental benefits of EVs are substantial. As the electric grid becomes cleaner with an increasing share of renewable energy, EVs will become even greener, with lower lifecycle emissions than biofuels. By prioritizing EVs, California could further reduce its carbon footprint while also achieving its long-term climate goals, including reaching carbon neutrality by 2045.

However, there are challenges. EV adoption in California remains a significant undertaking, requiring major investments in infrastructure as they challenge state power grids in the near term, technology, and consumer incentives. The cost of EVs, although decreasing, still remains a barrier for many consumers. Additionally, there are concerns about the environmental impact of lithium mining, which is essential for EV batteries. While renewable energy is expanding, California’s grid is still reliant on fossil fuels to some degree, and in other jurisdictions such as Canada's 2019 electricity mix fossil generation remains significant, meaning that the full emissions benefit of EVs is not realized until the grid is entirely powered by clean energy.

A Balancing Act

The debate between subsidizing out-of-state biofuels and in-state electric vehicles is ultimately a question of how best to allocate California’s resources to meet its climate and economic goals. Biofuels may offer a quicker fix for reducing emissions from existing vehicles, but their long-term benefits are more limited compared to the transformative potential of electric vehicles, even as some analysts warn of policy pitfalls that could complicate the transition.

However, biofuels still have a role to play in decarbonizing hard-to-abate sectors like aviation and heavy-duty transportation, where electrification may not be as feasible in the near future. Thus, a mixed strategy that includes both subsidies for EVs and biofuels may be the most effective approach.

Ultimately, California’s decision will likely depend on a combination of factors, including technological advancements, 2021 electricity lessons, and the pace of renewable energy deployment, and the state’s ability to balance short-term needs with long-term environmental goals. The road ahead is not easy, but California's leadership in clean energy will be crucial in shaping the nation’s response to climate change.

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2019 Global CO2 Emissions stayed flat, IEA reports, as renewable energy growth, wind and solar deployment, nuclear output, and coal-to-gas switching in advanced economies offset increases elsewhere, supporting climate goals and clean energy transitions.

Key Points

33 gigatonnes, unchanged YoY, as advanced economies cut power emissions via renewables, gas, and nuclear.

✅ IEA reports emissions flat at 33 Gt despite 2.9% GDP growth

✅ Advanced economies cut power-sector CO2 via wind, solar, gas

✅ Nuclear restarts and mild weather aided reductions

Despite widespread expectations of another increase, global energy-related CO2 emissions stopped growing in 2019, according to International Energy Agency (IEA) data released today. After two years of growth, global emissions were unchanged at 33 gigatonnes in 2019, a notable marker in the global energy transition narrative even as the world economy expanded by 2.9%.

This was primarily due to declining emissions from electricity generation in advanced economies, thanks to the expanding role of renewable sources (mainly wind and solar across many markets), fuel switching from coal to natural gas, and higher nuclear power generation, the Paris-based organisation says in the report.

"We now need to work hard to make sure that 2019 is remembered as a definitive peak in global emissions, not just another pause in growth," said Fatih Birol, the IEA's executive director. "We have the energy technologies to do this, and we have to make use of them all."

Higher nuclear power generation in advanced economies, particularly in Japan and South Korea, avoided over 50 Mt of CO2 emissions. Other factors included milder weather in several countries, and slower economic growth in some emerging markets. In China, emissions rose but were tempered by slower economic growth and higher output from low-carbon sources of electricity. Renewables continued to expand in China, and 2019 was also the first full year of operation for seven large-scale nuclear reactors in the country.

A significant decrease in emissions in advanced economies in 2019 offset continued growth elsewhere. The USA recorded the largest emissions decline on a country basis, with a fall of 140 million tonnes, or 2.9%. US emissions are now down by almost 1 gigatonne from their peak in 2000. Emissions in the European Union fell by 160 million tonnes, or 5%, in 2019 driven by reductions in the power sector as electricity producers move away from coal in the generation mix. Japan’s emissions fell by 45 million tonnes, or around 4%, the fastest pace of decline since 2009, as output from recently restarted nuclear reactors increased.

Emissions in the rest of the world grew by close to 400 million tonnes in 2019, with almost 80% of the increase coming from countries in Asia where coal-fired power generation continued to rise, and in Australia emissions rose 2% due to electricity and transport. Coal-fired power generation in advanced economies declined by nearly 15%, reflecting a sharp fall in coal-fired electricity across multiple markets, as a result of growth in renewables, coal-to-gas switching, a rise in nuclear power and weaker electricity demand.

The IEA will publish a World Energy Outlook Special Report in June that will map out how to cut global energy-related carbon emissions by one-third by 2030 and put the world on track for longer-term climate goals, a pathway that, in Canada, will require more electricity to hit net-zero. It will also hold an IEA Clean Energy Transitions Summit in Paris on 9 July, bringing together key government ministers, CEOs, investors and other major stakeholders.

Birol will discuss the results published today tomorrow at an IEA Speaker Series event at its headquarters with energy and climate ministers from Poland, which hosted COP24 in Katowice; Spain, which hosted COP25 in Madrid; and the UK, which will host COP26 in Glasgow this year, as greenhouse gas concentrations continue to break records worldwide.

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Puerto Rico Tesla Solar Power enables resilient microgrids using batteries, renewable energy, and energy storage to rebuild the hurricane-damaged grid, reduce fossil fuels, cut costs, and accelerate recovery with scalable solar-plus-storage solutions.

Key Points

A solar-plus-storage plan using Tesla microgrids and batteries to restore Puerto Rico's cleaner, resilient power.

✅ Microgrids cut diesel reliance and harden critical facilities.

✅ Batteries stabilize the grid and shave peak demand costs.

✅ Scalable solar enables faster, modular disaster recovery.

Puerto Rico’s governor Ricardo Rossello has said that he will speak to Elon Musk after the Tesla inventor said his innovative solar and battery systems could be used to restore electricity on the island.

Mr Musk was mentioned in a tweet, referencing an article discussing ways to restore Puerto Rico’s power grid, which was knocked out by Hurricane Maria on September 20.

Restoring the ageing and already-weakened network has proved slow: as of Friday 90 per cent of the island remained without power. The island’s electricity company was declared bankrupt in July.

Mr Musk was asked: “Could @ElonMusk go in and rebuild #PuertoRico’s electricity system with independent solar & battery systems?”

The South African entrepreneur replied: “The Tesla team has done this for many smaller islands around the world, but there is no scalability limit, so it can be done for Puerto Rico too.

“Such a decision would be in the hands of the PR govt, PUC, any commercial stakeholders and, most importantly, the people of PR.”

His suggestion was seized upon by Mr Rossello, who then tweeted: “@ElonMusk Let's talk. Do you want to show the world the power and scalability of your #TeslaTechnologies?

“PR could be that flagship project.”

Mr Musk replied that he was happy to talk.

Restoring power to the battered island is a priority for the government, and improving grid resilience remains critical, with hospitals still running on generators and the 3.5 million people struggling with a lack of refrigeration or air conditioning.

Radios broadcast messages advising people how to keep their insulin cool, and doctors are concerned about people not being able to access dialysis.

And, with its power grid wiped out, the Caribbean island could totally rethink the way it meets its energy needs, drawing on examples like a resilient school microgrid built locally. 

“This is an opportunity to completely transform the way electricity is generated in Puerto Rico and the federal government should support this,” said Judith Enck, the former administrator for the region with the environmental protection agency.

“They need a clean energy renewables plan and not spending hurricane money propping up the old fossil fuel infrastructure.”

Forty-seven per cent of Puerto Rico’s power needs were met by burning oil last year - a very expensive and outdated method of electricity generation. For the US as a whole, petroleum accounted for just 0.3 per cent of all electricity generated in 2016 even as the grid isn’t yet running on 100% renewable energy nationwide.

The majority of the rest of Puerto Rico’s energy came courtesy of coal and natural gas, with renewables, which later faced pandemic-related setbacks, accounting for only two per cent of electricity generation.

“In that time of extreme petroleum prices, the utility was borrowing money and buying oil in order to keep those plants operating,” said Luis Martinez, a lawyer at natural resources defense council and former special aide to the president of Puerto Rico’s environmental quality board.

“That precipitated the bankruptcy that followed. It was in pretty poor shape before the storm. Once the storm got there, it finished the job.”

But Mr Martinez told the website Earther that it might be difficult to secure the financing for rebuilding Puerto Rico with renewables from FEMA (Federal Emergency Management Agency) funds.

“A lot of distribution lines were on wood poles,” he said.

“Concrete would make them more resistant to winds, but that would potentially not be authorized under the use of FEMA funds.

"We’re looking into if some of those requirements can be waived so rebuilding can be more resilient.”

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U.S. coal-fired generation 2021 rose as higher natural gas prices, stable coal costs, and a recovering power sector shifted the generation mix; capacity factors rebounded despite low coal stocks and ongoing plant retirements.

Key Points

Coal output rose 22% on high gas prices and higher capacity factors; a 5% decline is expected in 2022.

✅ Natural gas delivered cost averaged $4.93/MMBtu, more than double 2020

✅ Coal capacity factor rose to ~51% from 40% in 2020

✅ 2022 coal generation forecast to fall about 5%

We expect 22% more U.S. coal-fired generation in 2021 than in 2020, according to our latest Short-Term Energy Outlook (STEO). The U.S. electric power sector has been generating more electricity from coal-fired power plants this year as a result of significantly higher natural gas prices and relatively stable coal prices, even as non-fossil sources reached 40% of total generation. This year, 2021, will yield the first year-over-year increase in coal generation in the United States since 2014, highlighted by a January power generation jump earlier in the year.

Coal and natural gas have been the two largest sources of electricity generation in the United States. In many areas of the country, these two fuels compete to supply electricity based on their relative costs and sensitivity to policies and gas prices as well. U.S. natural gas prices have been more volatile than coal prices, so the cost of natural gas often determines the relative share of generation provided by natural gas and coal.

Because natural gas-fired power plants convert fuel to electricity more efficiently than coal-fired plants, record natural gas generation has at times underscored that advantage, and natural gas-fired generation can have an economic advantage even if natural gas prices are slightly higher than coal prices. Between 2015 and 2020, the cost of natural gas delivered to electric generators remained relatively low and stable. This year, however, natural gas prices have been much higher than in recent years. The year-to-date delivered cost of natural gas to U.S. power plants has averaged $4.93 per million British thermal units (Btu), more than double last year’s price.

The overall decline in electricity demand in 2020 and record-low natural gas prices led coal plants to significantly reduce the percentage of time that they generated power. In 2020, the utilization rate (known as the capacity factor) of U.S. coal-fired generators averaged 40%. Before 2010, coal capacity factors routinely averaged 70% or more. This year’s higher natural gas prices have increased the average coal capacity factor to about 51%, which is almost the 2018 average, a year when wind and solar reached 10% nationally.

Although rising natural gas prices have resulted in more U.S. coal-fired generation than last year, this increase in coal generation will most likely not continue as solar and wind expand in the generation mix. The electric power sector has retired about 30% of its generating capacity at coal plants since 2010, and no new coal-fired capacity has come online in the United States since 2013. In addition, coal stocks at U.S. power plants are relatively low, and production at operating coal mines has not been increasing as rapidly as the recent increase in coal demand. For 2022, we forecast that U.S. coal-fired generation will decline about 5% in response to continuing retirements of generating capacity at coal power plants and slightly lower natural gas prices.

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Alberta Electricity Market Reforms aim to boost grid reliability and efficiency through a day-ahead market, transmission policy changes, clearer pricing signals, AESO oversight, and smarter siting near existing infrastructure to lower consumer costs.

Key Points

Policies add a day-ahead market and transmission fees to modernize the grid and improve reliability.

✅ Day-ahead market for clearer pricing and scheduling

✅ Up-front, non-refundable transmission payments by generators

✅ AESO to draft new rules by end of 2025

The Alberta government is implementing significant electricity policy changes to its electricity market to enhance system reliability and efficiency. These reforms aim to modernize the grid, accommodate growing energy demands, and align with best practices observed in other jurisdictions.

Proposed Market Reforms

The government has outlined several key initiatives:

• Day-Ahead Market Implementation: Introducing a day-ahead market is intended to provide clearer pricing signals and improve the scheduling of electricity generation. This approach allows market participants to plan and commit to energy production in advance, enhancing grid stability.

• Transmission Policy Revisions: The government proposes reforms to transmission policies, including the introduction of up-front and non-refundable transmission payments from new power generators. These payments would vary based on the proximity of new generators to existing transmission lines with available capacity. As part of a broader market overhaul, this strategy encourages the development of power plants in areas where existing infrastructure can be utilized, potentially reducing costs for consumers and businesses.

Government's Objectives

Minister of Affordability and Utilities, Nathan Neudorf, emphasized that these changes are necessary to meet growing energy demands and modernize Alberta’s electricity system. The government's goal is to create a more reliable and efficient electrical system that benefits both consumers and the broader economy.

Industry Reactions

The proposed reforms have elicited mixed reactions from industry stakeholders amid profound sector change across Alberta:

• Renewable Energy Sector Concerns: The Canadian Renewable Energy Association (CanREA) has expressed concerns about the potential for punitive market and transmission changes, and some retailers have similarly urged caution. They advocate for policies that support the integration of renewable energy sources and ensure fair treatment within the market.

• Regulatory Oversight: The Alberta Electric System Operator (AESO) is tasked with preparing restructured energy market rules by the end of 2025. This timeline reflects the government's commitment to a thorough and consultative approach to market reform.

Implications for Consumers

The Alberta government's proposed market changes aim to enhance the reliability and efficiency of the electricity system by considering measures such as a Rate of Last Resort to provide additional stability. By encouraging the development of power plants in areas with existing infrastructure, the reforms seek to reduce costs for consumers and businesses. However, the success of these initiatives will depend on careful implementation and ongoing engagement with all stakeholders to balance the diverse interests involved.

Alberta's proposed electricity market reforms represent a significant step toward modernizing the province's energy infrastructure. By introducing a day-ahead market and revising transmission policies, the government aims to create a more reliable and efficient electrical system and promote market competition more effectively. While these changes have generated diverse reactions, they underscore the government's commitment to addressing the evolving energy needs of Alberta's residents and businesses.

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Texas Electric Cooperatives outperformed during Winter Storm Uri, with higher customer satisfaction, equitable rolling blackouts, and stronger grid reliability compared to deregulated markets, according to ERCOT-area survey data of regulated utilities and commercial providers.

Key Points

Member-owned utilities in Texas delivering power, noted for reliability and fair outages during Winter Storm Uri.

✅ Member-owned, regulated utilities serving local communities

✅ Rated higher for blackout management and communication

✅ Operate outside deregulated markets; align incentives with users

Winter Storm Uri began to hit parts of Texas on February 13, 2021 and its onslaught left close to 4.5 million Texas homes and businesses without power, and many faced power and water disruptions at its peak. By some accounts, the preliminary number of deaths attributed to the storm is nearly 200, and the economic toll for the Lone Star State is estimated to be as high as $295 billion. 

The more than two-thirds of Texans who lost power during this devastating storm were notably more negative than positive in their evaluation of the performance of their local electric utility, mirrored by a rise in electricity complaints statewide, with one exception. That exception are the members of the more than 60 electric cooperatives operating within the Texas Interconnection electrical grid, which, in sharp contrast to the customers of the commercial utilities that provide power to the majority of Texans, gave their local utility a positive evaluation related to its performance during the storm.

In order to study Winter Storm Uri’s impact on Texas, the Hobby School of Public Affairs at the University of Houston conducted an online survey during the first half of March of residents 18 and older who live in the 213 counties (91.5% of the state population) served by the Texas power grid, which is managed by the Electric Reliability Council of Texas (ERCOT). 

Three-quarters of the survey population (75%) live in areas with a deregulated utility market, where a specified transmission and delivery utility by region is responsible for delivering the electricity (purchased from one of a myriad of private companies by the consumer) to homes and businesses. The four main utility providers are Oncor, CenterPoint CNP -2.2%, American Electric Power (AEP) North, and American Electric Power (AEP) Central. 

The other 25% of the survey population live in areas with regulated markets, where a single company is responsible for both delivering the electricity to homes and businesses and serves as the only source from which electricity is purchased. Municipal-owned and operated utilities (e.g., Austin Energy, Bryan Texas Utilities, Burnet Electric Department, Denton Municipal Electric, New Braunfels Utilities, San Antonio’s CPS Energy CMS -2.1%) serve 73% of the regulated market. Electric cooperatives (e.g., Bluebonnet Electric Cooperative, Central Texas Electric Cooperative, Guadalupe Valley Cooperative, Lamb County Electric Cooperative, Pedernales Electricity Cooperative, Wood County Electric Cooperative) serve one-fifth of this market (21%), with private companies accounting for 6% of the regulated market.

The overall distribution of the survey population by electric utility providers is: Oncor (38%), CenterPoint (21%), municipal-owned utilities (18%), AEP Central & AEP North combined (12%), electric cooperatives (6%), other providers in the deregulated market (4%) and other providers in the regulated market (1%). 

There were no noteworthy differences among the 31% of Texans who did not lose power during the winter storm in regard to their evaluations of their local electricity provider or their belief that the power cuts in their locale were carried out in an equitable manner.  

However, among the 69% of Texans who lost power, those served by electric cooperatives in the regulated market and those served by private electric utilities in the deregulated market differed notably regarding their evaluation of the performance of their local electric utility, both in regard to their management of the rolling blackouts, amid debates over market reforms to avoid blackouts, and to their overall performance during the winter storm. Those Texans who lost power and are served by electric cooperatives in a regulated market had a significantly more positive evaluation of the performance of their local electric utility than did those Texans who lost power and are served by a private company in a deregulated electricity market. 

For example, only 24% of Texans served by electric cooperatives had a negative evaluation of their local electric utility’s overall performance during the winter storm, compared to 55%, 56% and 61% of those served by AEP, Oncor and CenterPoint respectively. A slightly smaller proportion of Texans served by electric cooperatives (22%) had a negative evaluation of their local electric utility’s performance managing the rolling blackouts during the winter storm, compared to 58%, 61% and 71% of Texans served by Oncor, AEP and CenterPoint, respectively.

Texans served by electric cooperatives in regulated markets were more likely to agree that the power cuts in their local area were carried out in an equitable manner compared to Texans served by commercial electricity utilities in deregulated markets. More than half (52%) of those served by an electric cooperative agreed that power cuts during the winter storm in their area were carried out in an equitable manner, compared to only 26%, 23% and 23% of those served by Oncor, AEP and CenterPoint respectively

The survey data did not allow us to provide a conclusive explanation as to why the performance during the winter storm by electric cooperatives (and to a much lesser extent municipal utilities) in the regulated markets was viewed more favorably by their customers than was the performance of the private companies in the deregulated markets viewed by their customers. Yet here are three, far from exhaustive, possible explanations.

First, electric cooperatives might have performed better (based on objective empirical metrics) during the winter storm, perhaps because they are more committed to their customers, who are effectively their bosses. .  

Second, members of electric cooperatives may believe their electric utility prioritizes their interests more than do customers of commercial electric utilities and therefore, even if equal empirical performance were the case, are more likely to rate their electric utility in a positive manner than are customers of commercial utilities.  

Third, regulated electric utilities where a single entity is responsible for the commercialization, transmission and distribution of electricity might be better able to respond to the type of challenges presented by the February 2021 winter storm than are deregulated electric utilities where one entity is responsible for commercialization and another is responsible for transmission and distribution, aligning with calls to improve electricity reliability across Texas.

Other explanations for these findings may exist, which in addition to the three posited above, await future empirical verification via new and more comprehensive studies designed specifically to study electric cooperatives, large commercial utilities, and the incentives that these entities face under the regulatory system governing production, commercialization and distribution of electricity, including rulings that some plants are exempt from providing electricity in emergencies under state law. 

Still, opinion about electricity providers during Winter Storm Uri is clear: Texans served by regulated electricity markets, especially by electric cooperatives, were much more satisfied with their providers’ performance than were those in deregulated markets. Throughout its history, Texas has staunchly supported the free market. Could Winter Storm Uri change this propensity, or will attempts to regulate electricity lessen as the memories of the storm’s havoc fades? With a hotter summer predicted to be on the horizon in 2021 and growing awareness of severe heat blackout risks, we may soon get an answer.   

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