SolarÂ’s future looking brighter

Texas Blackout Liability Ruling clarifies appellate court findings in Houston, citing deregulated energy markets, ERCOT immunity, wholesale generators, retail providers, and 2021 winter storm lawsuits over grid failures and wrongful deaths.

Key Points

Houston judges held wholesale generators owe no duty to retail customers, limiting liability for 2021 blackout lawsuits.

✅ Court cites deregulated market and lack of privity to consumers

✅ Ruling shields generators from 2021 winter storm civil suits

✅ Plaintiffs plan appeals; legislature may address liability

Nearly three years after the devastating Texas blackout of 2021, a panel of judges from the First Court of Appeals in Houston has determined that major power companies cannot be held accountable for their failure to deliver electricity during the power grid crisis that unfolded, citing Texas' deregulated energy market as the reason.

This ruling appears likely to shield these companies from lawsuits that were filed against them in the aftermath of the blackout, leaving the families of those affected uncertain about where to seek justice.

In February 2021, a severe cold front swept over Texas, bringing extended periods of ice and snow. The extreme weather conditions increased energy demand while simultaneously reducing supply by causing power generators and the state's natural gas supply chain to freeze. This led to a blackout that left millions of Texans without power and water for nearly a week.

The state officially reported that almost 250 people lost their lives during the winter storm and subsequent blackout, although some analysts argue that this is a significant undercount and warn of blackout risks across the U.S. during severe heat as well.

In the wake of the storm, Texans affected by the energy system's failure began filing lawsuits, and lawmakers proposed a market bailout as political debate intensified. Some of these legal actions were directed against power generators whose plants either ceased to function during the storm or ran out of fuel for electricity generation.

After several years of legal proceedings, a three-judge panel was convened to evaluate the merits of these lawsuits.

This week, Chief Justice Terry Adams issued a unanimous opinion on behalf of the panel, stating, "Texas does not currently recognize a legal duty owed by wholesale power generators to retail customers to provide continuous electricity to the electric grid, and ultimately to the retail customers."

The opinion further clarified that major power generators "are now statutorily precluded by the legislature from having any direct relationship with retail customers of electricity."

This separation of power generation from transmission and retail electric sales in many parts of Texas resulted from energy market deregulation in the early 2000s, with the goal of reducing energy costs, and prompted electricity market reforms aimed at avoiding future blackouts.

Under the previous system, power companies were "vertically integrated," controlling generators, transmission lines, and selling the energy they produced directly to regional customers. However, in deregulated areas of Texas, competition was introduced, creating competing energy-generating companies and retail electric providers that purchase power wholesale and then sell it to residential consumers; meanwhile, electric cooperatives in other parts of the state remained member-owned providers.

Tré Fischer, a partner at the Jackson Walker law firm representing the power companies, explained, "One consequence of that was, because of the unbundling and the separation, you also don't have the same duties and obligations [to consumers]. The structure just doesn't allow for that direct relationship and correspondingly a direct obligation to continually supply the electricity even if there's a natural disaster or catastrophic event."

In the opinion, Justice Adams noted that when designing the Texas energy market, amid renewed interest in ways to improve electricity reliability across the grid, state lawmakers "could have codified the retail customers' asserted duty of continuous electricity on the part of wholesale power generators into law."

The recent ruling applies to five representative cases chosen by the panel out of hundreds filed after the blackout. Due to this decision, it is improbable that any of the lawsuits against power companies will succeed, according to the court's interpretation.

However, plaintiffs' attorneys have indicated their intention to appeal. They may request a review of the panel's opinion by the entire First Court of Appeals or appeal directly to the state supreme court.

The state Supreme Court had previously ruled that the Electric Reliability Council of Texas (ERCOT), the state's power grid operator, enjoys sovereign immunity and cannot be sued over the blackout.

This latest opinion raises the question of who, if anyone, can be held responsible for deaths and losses resulting from the blackout, a question left unaddressed by the court. Fischer commented, "If anything [the judges] were saying that is a question for the Texas legislature."

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Income Graduated Fixed Charge aligns CPUC billing with utility fixed costs, lowers usage rates, supports electrification, and shifts California investor-owned utilities' electric bills by income, with CARE and Climate Credit offsets for low-income households.

Key Points

A CPUC proposal: an income-based monthly fixed fee with lower usage rates to align costs and aid low-income customers.

✅ Income-tiered fixed fees: $0-$42; CARE: $14-$22, by utility territory

✅ Usage rates drop 16%-22% to support electrification and cost-reflective billing

✅ Lowest-income save ~$10-$20; some higher earners pay ~$10+ more monthly

The Public Advocates Office (PAO) for the California Public Utilities Commission (CPUC) has proposed adding a monthly income-based fixed charge on electric utility bills based on income level.  

The rate change is designed to lower bills for the lowest-income residents while aligning billing more directly with utility costs. 

PAO’s recommendation for the Income Graduated Fixed Charge places fees between $22 and $42 per month in the three major investor-owned utilities’ territories, including an SDG&E minimum charge debate under way, for customers not enrolled in the California Alternative Rates for Energy (CARE) program. As seen below, CARE customers would be charged between $14 per month and $22 a month, depending on income level and territory.

For households earning $50,000 or less per year, the fixed charge would be $0, but only if the California Climate Credit is applied to offset the fixed cost.

Meanwhile, usage-based electricity rates are lowered in the PAO proposal, part of major changes to electric bills statewide. Average rates would be reduced between 16% to 22% for the three major investor-owned utilities.

The lowest-income bracket of Californians is expected to save roughly $10 to $20 a month under the proposal, while middle-income customers may see costs rise by about $20 a month, even as lawmakers seek to overturn income-based charges in Sacramento.

“We anticipate the vast majority of low-income customers ($50,000 or less per year) will have their monthly bills decrease by $10 or more, and a small proportion of the highest income earners ($100,000+ per year) will see their monthly bills rise by $10 or more,” said the PAO.

The charges are an effort to help suppress ever-increasing electricity generation and transmission rates, which are among the highest in the country, with soaring electricity prices reported across California. Rates are expected to rise sharply as wildfire mitigation efforts are implemented by the utilities found at fault for their origin.

“We are very concerned. However, we do not see the increases stopping at this point,” Linda Serizawa, deputy director for energy, PAO, told pv magazine. “We think the pace and scale of the [rate] increases is growing faster than we would have anticipated for several years now.”

Consumer advocates and regulators face calls for action on surging electricity bills across the state.

The proposed changes are also meant to more directly couple billing with the fixed charges that utilities incur, as California considers revamping electricity rates to clean the grid. For example, activities like power line maintenance, energy efficiency programs, and wildfire prevention are not expected to vary with usage, so these activities would be funded through a fixed charge.

Michael Campbell of the PAO’s customer programs team, and leader of the proposed program, likened paying for grid enhancements and other social programs with utility rate increases to “paying for food stamps by taxing food.” Instead, a fixed charge would cover these costs.

PAO said the move to lower rates for usage should help encourage electrification as California moves to replace heating and cooling, appliances, and gas combustion cars with electrified counterparts. In addition, lower rates mean the cost burden of running these devices is improved.

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California Gas Plant Extensions keep Ormond Beach, AES Alamitos, and Huntington Beach on standby for grid reliability during heat waves, as regulators balance renewables, battery storage, and power, pending State Water Resources Control Board approval.

Key Points

State plan extending three coastal gas plants to 2026, adding capacity as California expands renewables and storage.

✅ Extends Ormond Beach, AES Alamitos, AES Huntington Beach

✅ Mitigates blackout risk during extreme heat and peak demand

✅ Pending State Water Resources Control Board approval

Temperatures in many California cities are cooling down this week, but a debate is simmering on how to generate enough electricity to power the state through extreme weather events while transitioning away from a reliance on fossil fuels as clean energy progress indicates statewide.

The California Energy Commission voted Wednesday to extend the life of three gas power plants along the state’s southern coast through 2026, even as natural-gas electricity records persist nationwide, postponing a shutoff deadline previously set for the end of this year. The vote would keep the decades-old facilities _ Ormond Beach Generating Station, AES Alamitos and AES Huntington Beach — open so they can run during emergencies.

The state is at a greater risk of blackouts during major events when many Californians simultaneously crank up their air conditioning, such as a blistering heat wave, illustrated by widespread utility shutoffs in recent years.

“We need to move faster in incorporating renewable energy. We need to move faster at incorporating battery storage. We need to build out chargers faster,” commissioner Patricia Monahan said amid an ongoing debate over the classification of nuclear power in California. “We’re working with all the energy institutions to do that, but we are not there yet.”

The plan, put together by the state’s Department of Water Resources, still needs final approval from the State Water Resources Control Board, which may vote on the issue next week. Democratic Gov. Gavin Newsom signed legislation last year creating an energy reserve the state could use as a last resort if there is likely to be an energy shortage, a challenge mirrored by Ontario electricity shortfall concerns elsewhere. The law allowed the Department of Water Resources to fund or secure power sources in those instances, after PG&E shutdown reasons drew attention to grid vulnerabilities.

The commission acknowledged it was a difficult decision. Environmentalists say the state needs to transition to more short- and long-term solutions that will help it move away from fossil fuels and to rely more on renewable energy sources like solar and wind, similar to Ontario's clean power push in recent years. They’re also concerned about the health impacts associated with pollution from gas plants.

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Solar ITC Impact on U.S. Wind frames how a 30% solar investment tax credit could undercut wind PTC economics, shift corporate procurement, and, without transmission and storage, slow onshore builds despite offshore wind momentum.

Key Points

It is how a solar ITC extension may curb U.S. wind growth absent PTC parity, transmission, storage, and offshore backing.

✅ ITC at 30% risks shifting corporate procurement to solar.

✅ Post-PTC wind faces grid, transmission, and curtailment headwinds.

✅ Offshore wind, storage pairing, TOU demand could offset.

The booming U.S. wind industry, amid a wind power surge, faces an uncertain future in the 2020s. Few factors are more important than the fate of the solar ITC.

An extension of the solar investment tax credit (ITC) at its 30 percent value would be “devastating” to the future U.S. wind market, according to a new Wood Mackenzie report.

The U.S. is on track to add a record 14.6 gigawatts of new wind capacity in 2020, despite Covid-19 impacts, and nearly 39 gigawatts during a three-year installation boom from 2019 to 2021, according to Wood Mackenzie’s 2019 North America Wind Power Outlook.

But the market’s trajectory begins to look highly uncertain from the early 2020s onward, and solar is one of the main reasons why.

Since the dawn of the modern American renewables market, the wind and solar sectors have largely been allies on the national stage, benefiting from many of the same favorable government plans and sharing big-picture goals. Until recently, wind and solar companies rarely found themselves in direct competition.

But the picture is changing as solar catches up to wind on cost and the grid penetration of renewables surges. What was once a vague alliance between the two fastest growing renewables technologies could morph into a serious rivalry.

While many project developers are now active in both sectors, including NextEra Energy Resources, Invenergy and EDF, the country’s thriving base of wind manufacturers could face tougher days ahead.

The ITC's inherent advantage

At this point, wind remains solar’s bigger sibling in many ways.

The U.S. has nearly 100 gigawatts of installed wind capacity today, compared to around 67 gigawatts of solar. With their substantially higher capacity factors, wind farms generated four times more power for the U.S. grid last year than utility-scale solar plants, for a combined wind-solar share of 8.2 percent, according to government figures, even as renewables are projected to reach one-fourth of U.S. electricity generation. (Distributed PV systems further add to solar’s contribution.)

But it's long been clear that wind would lose its edge at some point. The annual solar market now regularly tops wind. The cost of solar energy is falling more rapidly, and appears to have more runway for further reduction. Solar’s inherent generation pattern is more valuable in many markets, delivering power during peak-demand hours, while the wind often blows strongest at night.

And then there’s the matter of the solar ITC.

In 2015, both wind and solar secured historic multi-year extensions to their main federal subsidies. The extensions gave both industries the longest period of policy clarity they’ve ever enjoyed, setting in motion a tidal wave of installations set to crest over the next few years.

Even back in 2015, however, it was clear that solar got the better deal in Washington, D.C.

While the wind production tax credit (PTC) began phasing down for new projects almost immediately, solar developers were given until the end of 2019 to qualify projects for the full ITC.

And critically, while the wind PTC drops to nothing after its sunset, commercially owned solar projects will remain eligible for a 10 percent ITC forever, based on the existing legislation. Over time, that amounts to a huge advantage for solar.

In another twist, the solar industry is now openly fighting for an extension of the 30 percent ITC, while the wind industry seemingly remains cooler on the prospect of pushing for a similar prolongation — having said the current PTC extension would be the last.

Plenty of tailwinds, too

Wood Mackenzie's report catalogues multiple factors that could work for or against the wind market in the "uncharted" post-PTC years, many of them, including the Covid-19 crisis, beyond the industry’s direct control.

If things go well, annual installations could bounce back to near-record levels by 2027 after a mid-decade contraction, the report says. But if they go badly, installations could remain depressed at 4 gigawatts or below from 2022 through most of the coming decade, and that includes an anticipated uplift from the offshore market.

An extension of the solar ITC without additional wind support would “severely compound” the wind market’s struggle to rebound in the 2020s, the report says. The already-evident shift in corporate renewables procurement from wind to solar could intensify dramatically.

The other big challenge for wind in the 2020s is the lack of progress on transmission infrastructure that would connect potentially massive low-cost wind farms in interior states with bigger population centers. A hoped-for national infrastructure package that might address the issue has not materialized.

Even so, many in the wind business remain cautiously optimistic about the post-PTC years, with a wind jobs forecast bolstering sentiment, and developers continue to build out longer-term project pipelines.

Turbine technology continues to improve. And an extension of the solar ITC is far from assured.

Other factors that could work in wind’s favor in the years ahead include:

The nascent offshore sector, which despite lingering regulatory uncertainty at the federal level looks set to blossom into a multi-gigawatt annual market by the mid-2020s, in line with an offshore wind forecast that highlights substantial growth potential. Lobbying efforts for an offshore wind ITC extension are gearing up, offering a potential area for cooperation between wind and solar.

The potential linkage of policy support for energy storage to wind projects, building on the current linkage with solar.

Growing electric vehicle sales and a shift toward time-of-use retail electricity billing, which could boost power demand during off-peak hours when wind generation is strong.

The land-use advantages wind farms have over solar in some agricultural regions.

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Spring Storm Grid Risks highlight tornado outbreaks, flooding, power outages, and transmission disruptions, with NOAA flood outlooks, coal and barge delays, vulnerable nuclear sites, and distribution line damage demanding resilience, reliability, and emergency preparedness.

Key Points

Spring Storm Grid Risks show how tornadoes and floods disrupt power systems, fuel transport, and plants guide resilience.

✅ Tornado outbreaks and derechos damage distribution and transmission

✅ Flooding drives outages via treefall, substation and plant inundation

✅ Fuel logistics disrupted: rail coal, river barges, road access

The storm and tornado outbreak that recently barreled through the US Midwest, South and Mid-Atlantic was a devastating reminder of how much danger spring can deliver, despite it being the “milder” season compared to summer and winter.  

Danger season is approaching, and the country is starting to see the impacts. 

The event killed at least 32 people across seven states. The National Weather Service is still tallying up the number of confirmed tornadoes, which has already passed 100. Communities coping with tragedy are assessing the damage, which so far includes at least 72 destroyed homes in one Tennessee county alone, and dozens more homes elsewhere. 

On Saturday, April 1–the day after the storm struck–there were 1.1 million US utility customers without power, even as EIA reported a January power generation surge earlier in the year. On Monday morning, April 3, there were still more than 80,000 customers in the dark, according to PowerOutage.us. The storm system brought disruptions to both distribution grids–those networks of local power lines you generally see running overhead to buildings–as well as the larger transmission grid in the Midwest, which is far less common than distribution-level issues. 

While we don’t yet have a lot of granular details about this latest storm’s grid impacts, recent shifts in demand like New York City's pandemic power patterns show how operating conditions evolve, and it’s worth going through what else the country might be in for this spring, as well as in future springs. Moreover, there are steps policymakers can take to prepare for these spring weather phenomena and bolster the reliability and resilience of the US power system. 

Heightened flood risk 
The National Oceanic Atmospheric Administration (NOAA) said in a recent outlook that about 44 percent of the United States is at risk of floods this spring, equating to about 146 million people. This includes most of the eastern half of the country, the federal agency said. 

The agency also sees “major” flood risk potential in some parts of the Upper Mississippi River Basin, and relatively higher risk in the Sierra Nevada region, due in part to a historic snowpack in California.  

Multiple components of the power system can be affected by spring floods. 

Power lines – Floods can saturate soil and make trees more likely to uproot and fall onto power lines. This has been contributing to power outages during California’s recent heavy storms–called atmospheric rivers–that started over the winter. In other regions, soil moisture has even been used as a predictor of where power outages will occur due to hurricanes, so that utility companies are better prepared to send line repair crews to the right areas. Hurricanes are primarily a summer and fall phenomenon, and summer also brings grid stress from air conditioning demand in many states, so for now, during spring, they are less of a concern.  

Fuel transport – Spring floods can hinder the transportation of fuels like coal. While it is a heavily polluting fossil fuel that is set to continue declining as a fuel source for US electricity generation, with the EIA summer outlook for wind and solar pointing to further shifts, coal still accounted for roughly 20 percent of the country’s generation in 2022.   

About 70 percent of US coal is transported at least part of the way by trains. The rail infrastructure to transport coal from the Powder River Basin in Montana and Wyoming–the country’s primary coal source–was proven to be vulnerable to extreme floods in the spring of 2011, and even more extreme floods in the spring of 2019. The 2019 floods’ disruptions of coal shipments to power plants via rail persisted for months and into the summertime, also affecting river shipments of coal by barge. In June 2019, hundreds of barges were stalled in the Mississippi River, through which millions of tons of the fossil fuel are normally transported. 

Power plants – Power plants themselves can also be at risk of flooding, since most of them are sited near a source of water that is used to create steam to spin the plants’ turbines, and conversely, low water levels can constrain hydropower as seen in Western Canada hydropower drought during recent reservoir shortfalls. Most US fossil fuel generating capacity from sources like methane gas, which recently set natural gas power records across the grid, and coal utilizes steam to generate electricity. 

However, much of the attention paid to the flood risk of power plant sites has centered on nuclear plants, a key source of low-carbon electricity discussed in IAEA low-carbon electricity lessons that also require a water source for the creation of steam, as well as for keeping the plant cool in an emergency. To name a notable flood example here in the United States–both visually and substantively–in 2011, the Fort Calhoun nuclear plant in Nebraska was completely surrounded by water due to late-spring flooding along the Missouri River. This sparked a lot of concerns because it was just a few months after the March 2011 meltdown of the Fukushima Daiichi nuclear plant in Japan. The public was thankfully not harmed by the Nebraska incident, but this was unfortunately not an isolated incident in terms of flood risks posed to the US nuclear power fleet. 

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China 2060 Carbon-Neutral Energy Transition projects tripled electricity, rapid electrification, wind and solar dominance, scalable hydrogen, CCUS, and higher carbon pricing to meet net-zero goals while decarbonizing heavy industry and transport.

Key Points

Shell's outlook for China to reach net zero by 2060 via electrification, renewables, hydrogen, CCUS, and carbon pricing.

✅ Power supply to 60% of energy; generation triples by 2060.

✅ Wind and solar reach 80% of electricity; coal declines sharply.

✅ Hydrogen scales to 17 EJ; CCUS and carbon pricing expand.

China may triple electricity generation to supply 60 percent of the country's total energy under Beijing's carbon-neutral goal by 2060, up from the current 23 per cent, according to Royal Dutch Shell.

Shell is one of the largest global investors in China's energy sector, with business covering gas production, petrochemicals and a retail fuel network. A leading supplier of liquefied natural gas, it has recently expanded into low-carbon business such as hydrogen power and electric vehicle charging.

In a rare assessment of the country's energy sector by an international oil major, Shell said China needed to take quick action this decade to stay on track to reach the carbon-neutrality goal.

China has mapped out plans to reach peak emissions by 2030, and aims to reduce coal power production over the coming years, but has not yet revealed any detailed carbon roadmap for 2060.

This includes investing in a reliable and renewable power system, including compressed air generation, and demonstrating technologies that transform heavy industry using hydrogen, biofuel and carbon capture and utilization.

"With early and systematic action, China can deliver better environmental and social outcomes for its citizens while being a force for good in the global fight against climate change," Mallika Ishwaran, chief economist of Shell International, told a webinar hosted by the company's China business.

Shell expects China's electricity generation to rise three-fold to more than 60 exajoules (EJ) in 2060 from 20 EJ in 2020, even amid power supply challenges reported recently.

Solar and wind power are expected to surpass coal as the largest sources of electricity by 2034 in China, reflecting projections that renewables will eclipse coal globally by mid-decade, versus the current 10 percent, rising to 80 percent by 2060, Shell said.

Hydrogen is expected to scale up to 17 EJ, or equivalent to 580 million tonnes of coal by 2060, up from almost negligible currently, adding over 85 percent of the hydrogen will be produced through electrolysis, supported by PEM hydrogen R&D across the sector, powered by renewable and nuclear electricity, Shell said.

Hydrogen will meet 16 percent of total energy use in 2060 with heavy industry and long-distance transport as top hydrogen users, the firm added.

The firm also expects China's carbon price to rise to 1,300 yuan (CDN$256.36) per tonne in 2060 from 300 yuan in 2030.

Nuclear, on a steady development track, and biomass will have niche but important roles for power generation in the years to come, Shell said.

Electricity generated from biomass, combined with carbon, capture, utilization and storage (CCUS), provide a source of negative emissions for the rest of the energy system from 2053, it added.

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