Temperatures of 100 degrees Fahrenheit and higher forecast for August 13 across Texas may push electric use in the state to an all-time record, according to the grid operator.
The Electric Reliability Council of Texas (ERCOT) said power demand might reach 65,911 megawatts as temperatures peak between 5:00 p.m. and 6:00 p.m. CDT, surpassing the August 17, 2006 peak of 62,339 MW.
In its annual summer forecast released in May, ERCOT estimated the 2007 peak would be 63,794 MW, up 2.3 percent from the 2006 record.
So far this summer, ERCOT demand has not hit 60,000 MW due to a rainy June and July. The August 10 peak demand was 59,067 MW as isolated showers trimmed afternoon demand around Houston.
The power region has about 70,200 MW of generation. ERCOT can curtail about 1,100 MW of load when supplies are tight, but no formal demand-response program under which pays companies to trim consumption during emergencies.
An ERCOT spokeswoman said the agency was ready for hot weather and anticipated no problems unless generators unexpectedly shut.
The grid operator used blackouts in April 2006 to avoid widespread power disruption when an early heat wave hit while generators had dozens of power plants shut for seasonal maintenance.
Labor National Electricity Market Reform aims to rebalance NEM rules, support a fair-dinkum clean energy target, enable renewable zones, bolster storage and grid reliability, empower households, and unlock CEFC investment via the Finkel review.
Key Points
Labor's plan to overhaul NEM rules for households, clean energy targets, renewable zones, storage, and CEFC investment.
✅ Revises NEM rules to curb big generators' market power
✅ Backs a clean energy target informed by the Finkel review
✅ Expands renewable zones, storage, and CEFC finance
Australia's Labor leader Bill Shorten has called for significant changes to the rules governing the national electricity market, saying they are biased in favour of big energy generators, leaving households worse off even with measures like a WA electricity bill credit in place.
He said the national electricity market (NEM) rules are designed to help the big companies recoup the money they spent on purchasing government assets, a dynamic echoed in debates like a Calgary market overhaul dispute unfolding in Canada, rather than encourage households to generate their own power, and they need to change faster to adapt to consumer needs.
His comments hint at a possible overhaul of the NEM’s governance structure under a future Labor government, because the current rule-making process is too cumbersome and slow, with suggested rules changes taking years to be introduced.
Daniel Andrews defends claims that civil liberties a 'luxury' in fight against terrorism
Labor had promoted a similar idea in the lead-up to the 2016 election, with its call for an electricity modernization review, but now the Finkel review has been released it would be used to guide such a review.
In a speech to the Australian Financial Review’s National Energy Summit in Sydney on Monday, Shorten recommitted Labor to negotiating a “fair-dinkum” clean energy target with the Turnbull government, amid modelling that a strong clean energy target can lower electricity prices, saying “it’s time to put away the weapons of the climate change wars” and work together to find a way forward.
He said the media and business can all share the blame for Australia’s lost decade of energy policy development, with examples abroad showing how leadership steers change, such as in Alberta where Kenney's influence on power policy has been pronounced, but “we need to stop spoiling for a fight and start seeking a solution”.
“The scare campaigns and hyper-partisanship that got Australia into this mess, will not get us out of it,” he will say.
“That’s why, a bit over four months ago, before the chief scientist released his report, I wrote to the prime minister offering an olive branch.
“I said Labor was prepared to move from our preferred position of an emissions intensity scheme and negotiate a fair-dinkum clean energy target.
“That offer was greeted with some cynicism in the media. But let me be crystal clear – I made that offer in good faith, and that offer still stands.”
Shorten said Australia needs to resolve the current “gas crisis” and do more to drive investment in renewable energy that delivers more reliable electricity, a priority underscored by the IEA's warning that falling global energy investment risks shortages, and if Labor wins the next election it will organise Australia into a series of renewable energy zones – as recommended by the chief scientist, Alan Finkel – that identify wind, solar, pumped hydro and geothermal resources, and connect them to the existing network.
“These zones would be based on both existing generation and storage in the area – and the potential for future development,” he said.
Australia's politics only barrier to clean energy system, report finds
“Identifying these zones – from eastern Queensland, north-east New South Wales, west Victoria, the Eyre Peninsula in South Australia and the entire state of Tasmania – will also plant a flag for investors – signalling future sites for job-creating projects.”
Shorten also said Labor will free upthe Clean Energy Finance Corporation to invest in more generation and more storage.
“Under Labor, the return benchmark for the CEFC was set at the weighted average of the Australian government bond rate.
“Under this government, it was initially increased to the weighted average plus 4% to 5% and is now set at the average plus 3% to 4%.
“Setting the return benchmark too high defeats the driving purpose of the CEFC and it holds back the crucial investment Australia needs – right now – in new generation and storage.
“This is why a Labor government would restore the original benchmark return of the Clean Energy Finance Corporation, to invest in more generation, more storage and more jobs.”
Alberta Electricity Price Surge reflects soaring wholesale rates, natural gas spikes, carbon tax pressures, and grid decarbonization challenges amid cold-weather demand, constrained supply, and Europe-style energy crisis impacts across the province.
Key Points
An exceptional jump in Alberta's power costs driven by gas price spikes, high demand, policy costs, and tight supply.
✅ Wholesale prices averaged $123/MWh in December
✅ Gas costs surged; supply constraints and outages
✅ Carbon tax and decarbonization policies raised costs
Albertans just endured the highest electricity prices in 21 years. Wholesale prices averaged $123 per megawatt-hour in December, more than triple the level from the previous year and highest for December since 2000.
The situation in Alberta mirrors the energy crisis striking Europe where electricity prices are also surging, largely due to a shocking five-fold increase in natural gas prices in 2021 compared to the prior year.
The situation should give pause to Albertans when they consider aggressive plans to “decarbonize” the electric grid, including proposals for a fully renewable grid by 2030 from some policymakers.
The explanation for skyrocketing energy prices is simple: increased demand (because of Calgary's frigid February demand and a slowly-reviving post-pandemic economy) coupled with constrained supply.
In the nitty gritty details, there are always particular transitory causes, such as disputes with Russian gas companies (in the case of Europe) or plant outages (in the case of Alberta).
But beyond these fleeting factors, there are more permanent systemic constraints on natural gas (and even more so, coal-fired) power plants.
I refer of course to the climate change policies of the Trudeau government at the federal level and some of the more aggressive provincial governments, which have notable implications for electricity grids across Canada.
The most obvious example is the carbon tax, the repeal of which Premier Jason Kenney made a staple of his government.
Putting aside the constitutional issues (on which the Supreme Court ruled in March of last year that the federal government could impose a carbon tax on Alberta), the obvious economic impact will be to make carbon-sourced electricity more expensive.
This isn’t a bug or undesired side-effect, it’s the explicit purpose of a carbon tax.
Right now, the federal carbon tax is $40 per tonne, is scheduled to increase to $50 in April, and will ultimately max out at a whopping $170 per tonne in 2030.
Again, the conscious rationale of the tax, aligned with goals for cleaning up Canada's electricity, is to make coal, oil and natural gas more expensive to induce consumers and businesses to use alternative energy sources.
As Albertans experience sticker shock this winter, they should ask themselves — do we want the government intentionally making electricity and heating oil more expensive?
Of course, the proponent of a carbon tax (and other measures designed to shift Canadians away from carbon-based fuels) would respond that it’s a necessary measure in the fight against climate change, and that Canada will need more electricity to hit net-zero according to the IEA.
Yet the reality is that Canada is a bit player on the world stage when it comes to carbon dioxide, responsible for only 1.5% of global emissions (as of 2018).
As reported at this “climate tracker” website, if we look at the actual policies put in place by governments around the world, they’re collectively on track for the Earth to warm 2.7 degrees Celsius by 2100, far above the official target codified in the Paris Agreement.
Canadians can’t do much to alter the global temperature, but federal and provincial governments can make energy more expensive if policymakers so choose, and large-scale electrification could be costly—the Canadian Gas Association warns of $1.4 trillion— if pursued rapidly.
As renewable technologies become more reliable and affordable, business and consumers will naturally adopt them; it didn’t take a “manure tax” to force people to use cars rather than horses.
As official policy continues to make electricity more expensive, Albertans should ask if this approach is really worth it, or whether options like bridging the Alberta-B.C. electricity gap could better balance costs.
Robert P. Murphy is a senior fellow at the Fraser Institute.
ITER Nuclear Fusion advances tokamak magnetic confinement, heating deuterium-tritium plasma with superconducting magnets, targeting net energy gain, tritium breeding, and steam-turbine power, while complementing laser inertial confinement milestones for grid-scale electricity and 2025 startup goals.
Key Points
ITER Nuclear Fusion is a tokamak project confining D-T plasma with magnets to achieve net energy gain and clean power.
✅ Tokamak magnetic confinement with high-temp superconducting coils
✅ Deuterium-tritium fuel cycle with on-site tritium breeding
✅ Targets net energy gain and grid-scale, low-carbon electricity
It sounds like the stuff of dreams: a virtually limitless source of energy that doesn’t produce greenhouse gases or radioactive waste. That’s the promise of nuclear fusion, often described as the holy grail of clean energy by proponents, which for decades has been nothing more than a fantasy due to insurmountable technical challenges. But things are heating up in what has turned into a race to create what amounts to an artificial sun here on Earth, one that can provide power for our kettles, cars and light bulbs.
Today’s nuclear power plants create electricity through nuclear fission, in which atoms are split, with next-gen nuclear power exploring smaller, cheaper, safer designs that remain distinct from fusion. Nuclear fusion however, involves combining atomic nuclei to release energy. It’s the same reaction that’s taking place at the Sun’s core. But overcoming the natural repulsion between atomic nuclei and maintaining the right conditions for fusion to occur isn’t straightforward. And doing so in a way that produces more energy than the reaction consumes has been beyond the grasp of the finest minds in physics for decades.
But perhaps not for much longer. Some major technical challenges have been overcome in the past few years and governments around the world have been pouring money into fusion power research as part of a broader green industrial revolution under way in several regions. There are also over 20 private ventures in the UK, US, Europe, China and Australia vying to be the first to make fusion energy production a reality.
“People are saying, ‘If it really is the ultimate solution, let’s find out whether it works or not,’” says Dr Tim Luce, head of science and operation at the International Thermonuclear Experimental Reactor (ITER), being built in southeast France. ITER is the biggest throw of the fusion dice yet.
Its $22bn (£15.9bn) build cost is being met by the governments of two-thirds of the world’s population, including the EU, the US, China and Russia, at a time when Europe is losing nuclear power and needs energy, and when it’s fired up in 2025 it’ll be the world’s largest fusion reactor. If it works, ITER will transform fusion power from being the stuff of dreams into a viable energy source.
Constructing a nuclear fusion reactor ITER will be a tokamak reactor – thought to be the best hope for fusion power. Inside a tokamak, a gas, often a hydrogen isotope called deuterium, is subjected to intense heat and pressure, forcing electrons out of the atoms. This creates a plasma – a superheated, ionised gas – that has to be contained by intense magnetic fields.
The containment is vital, as no material on Earth could withstand the intense heat (100,000,000°C and above) that the plasma has to reach so that fusion can begin. It’s close to 10 times the heat at the Sun’s core, and temperatures like that are needed in a tokamak because the gravitational pressure within the Sun can’t be recreated.
When atomic nuclei do start to fuse, vast amounts of energy are released. While the experimental reactors currently in operation release that energy as heat, in a fusion reactor power plant, the heat would be used to produce steam that would drive turbines to generate electricity, even as some envision nuclear beyond electricity for industrial heat and fuels.
Tokamaks aren’t the only fusion reactors being tried. Another type of reactor uses lasers to heat and compress a hydrogen fuel to initiate fusion. In August 2021, one such device at the National Ignition Facility, at the Lawrence Livermore National Laboratory in California, generated 1.35 megajoules of energy. This record-breaking figure brings fusion power a step closer to net energy gain, but most hopes are still pinned on tokamak reactors rather than lasers.
In June 2021, China’s Experimental Advanced Superconducting Tokamak (EAST) reactor maintained a plasma for 101 seconds at 120,000,000°C. Before that, the record was 20 seconds. Ultimately, a fusion reactor would need to sustain the plasma indefinitely – or at least for eight-hour ‘pulses’ during periods of peak electricity demand.
A real game-changer for tokamaks has been the magnets used to produce the magnetic field. “We know how to make magnets that generate a very high magnetic field from copper or other kinds of metal, but you would pay a fortune for the electricity. It wouldn’t be a net energy gain from the plant,” says Luce.
One route for nuclear fusion is to use atoms of deuterium and tritium, both isotopes of hydrogen. They fuse under incredible heat and pressure, and the resulting products release energy as heat
The solution is to use high-temperature, superconducting magnets made from superconducting wire, or ‘tape’, that has no electrical resistance. These magnets can create intense magnetic fields and don’t lose energy as heat.
“High temperature superconductivity has been known about for 35 years. But the manufacturing capability to make tape in the lengths that would be required to make a reasonable fusion coil has just recently been developed,” says Luce. One of ITER’s magnets, the central solenoid, will produce a field of 13 tesla – 280,000 times Earth’s magnetic field.
The inner walls of ITER’s vacuum vessel, where the fusion will occur, will be lined with beryllium, a metal that won’t contaminate the plasma much if they touch. At the bottom is the divertor that will keep the temperature inside the reactor under control.
“The heat load on the divertor can be as large as in a rocket nozzle,” says Luce. “Rocket nozzles work because you can get into orbit within minutes and in space it’s really cold.” In a fusion reactor, a divertor would need to withstand this heat indefinitely and at ITER they’ll be testing one made out of tungsten.
Meanwhile, in the US, the National Spherical Torus Experiment – Upgrade (NSTX-U) fusion reactor will be fired up in the autumn of 2022, while efforts in advanced fission such as a mini-reactor design are also progressing. One of its priorities will be to see whether lining the reactor with lithium helps to keep the plasma stable.
Choosing a fuel Instead of just using deuterium as the fusion fuel, ITER will use deuterium mixed with tritium, another hydrogen isotope. The deuterium-tritium blend offers the best chance of getting significantly more power out than is put in. Proponents of fusion power say one reason the technology is safe is that the fuel needs to be constantly fed into the reactor to keep fusion happening, making a runaway reaction impossible.
Deuterium can be extracted from seawater, so there’s a virtually limitless supply of it. But only 20kg of tritium are thought to exist worldwide, so fusion power plants will have to produce it (ITER will develop technology to ‘breed’ tritium). While some radioactive waste will be produced in a fusion plant, it’ll have a lifetime of around 100 years, rather than the thousands of years from fission.
At the time of writing in September, researchers at the Joint European Torus (JET) fusion reactor in Oxfordshire were due to start their deuterium-tritium fusion reactions. “JET will help ITER prepare a choice of machine parameters to optimise the fusion power,” says Dr Joelle Mailloux, one of the scientific programme leaders at JET. These parameters will include finding the best combination of deuterium and tritium, and establishing how the current is increased in the magnets before fusion starts.
The groundwork laid down at JET should accelerate ITER’s efforts to accomplish net energy gain. ITER will produce ‘first plasma’ in December 2025 and be cranked up to full power over the following decade. Its plasma temperature will reach 150,000,000°C and its target is to produce 500 megawatts of fusion power for every 50 megawatts of input heating power.
“If ITER is successful, it’ll eliminate most, if not all, doubts about the science and liberate money for technology development,” says Luce. That technology development will be demonstration fusion power plants that actually produce electricity, where advanced reactors can build on decades of expertise. “ITER is opening the door and saying, yeah, this works – the science is there.”
BC Hydro 2021 Peak Load Records highlight record-breaking electricity demand, peak load spikes, heat dome impacts, extreme cold, and shifting work-from-home patterns managed by a flexible hydroelectric system and climate-driven load trends.
Key Points
Record-breaking electricity demand peaks from extreme heat and cold that reshaped daily load patterns across BC in 2021.
✅ Heat dome and deep freeze drove sustained peak electricity demand
✅ Peak load built gradually, reflecting work-from-home behavior
✅ Flexible hydroelectric system adapts quickly to demand spikes
From June’s heat dome to December’s extreme cold, 2021 was a record-setting year, according to BC Hydro, and similar spikes were noted as Calgary's electricity use surged in frigid weather.
On Friday, the energy company released a new report on electricity demand, and how extreme temperatures over extended periods of time, along with growing scrutiny of crypto mining electricity use, led to record peak loads.
“We use peak loads to describe the electricity demand in the province during the highest load hour of each day,” Kyle Donaldson, BC Hydro spokesperson, said in a media release.
“With the heat dome in the summer and the sustained cold temperatures in December, we saw more record-breaking hours on more days last year than any other single year.”
According to BC Hydro, during summer, the Crown corporation recorded 19 of its top 25 all-time summer daily peak records — including breaking its all-time summer peak hourly demand record.
In December, which saw extremely cold temperatures and heavy snowfall, BC Hydro said its system experienced the highest and longest sustained load levels ever, as it activated its winter payment plan to assist customers.
Overall, BC Hydro says it has experienced 11 of its top 25 all-time daily peak records this winter, adding that Dec. 27 broke its all-time high peak hourly demand record.
“BC Hydro’s hydroelectric system is directly impacted by variations in weather, including drought conditions that require adaptation, and in 2021 more electricity demand records were broken than any other year prior, largely because of the back-to-back extreme temperatures lasting for days and weeks on end,” reads the report.
The energy company expects this trend to continue, noting that it has broken the peak record five times in the past five years, and other jurisdictions such as Quebec consumption record have also shattered consumption records.
It also noted that peak demand patterns have also changed since the first year of the COVID-19 pandemic, with trends seen during Earth Hour usage offering context.
“When the previous peak hourly load record was broken in January 2020, load displayed sharper increases and decreases throughout the day, suggesting more typical weather and behaviour,” said the report.
“In contrast, the 2021 peak load built up more gradually throughout the day, suggesting more British Columbians were likely working from home, or home for the holidays – waking up later and home earlier in the evening – as well as colder weather than average.”
BC Hydro also said “current climate models suggest a warming trend continuing in years to come which could increase demand year-round,” but noted that its flexible hydroelectric system can meet changes in demand quickly.
Ontario EV Battery Storage ROI leverages V2B, V2G, two-way charging, demand response, and second-life batteries to monetize peak pricing, cut GHG emissions, and unlock up to $38,000 in lifetime value for commuters and buildings.
Key Points
The economic return from V2B/V2G two-way charging and second-life storage using EV batteries within Ontario's grid.
✅ Monetize peak pricing via workplace V2B discharging
✅ Earn up to $8,400 per EV over vehicle life
✅ Reduce gas generation and GHGs with demand response
The payback that usually comes to mind when people buy an electric vehicle is to drive an emissions-free, low-maintenance, better-performing mode of transportation.
On top of that, you can now add $38,000.
That, according to a new report from Ontario electric vehicle education and advocacy nonprofit, Plug‘n Drive, is the potential lifetime return for an electric car driven as a commuter vehicle while also being used as an electricity storage option amid an energy storage crunch in Ontario’s electricity system.
“EVs contain large batteries that store electric energy,” says the report. “Besides driving the car, [those] batteries have two other potentially useful applications: mobile storage via vehicle-to-grid while they are installed in the vehicle, and second-life storage after the vehicle batteries are retired.”
Pricing and demand differentials
The study, prepared by the research firm Strategic Policy Economics, modeled a two-stage scenario calculating the total benefits from both mobile and second-life storage when taking advantage of differences in daytime and nighttime electricity pricing and demand.
If done systematically and at scale, the combined benefits to EV owners, building operators and the electricity system in Ontario could reach $129 million per year by 2035, according to the report. Along with the financial gains, the province would also cut GHG emissions by up to 67.2 kilotons annually.
The math might sound complicated, but the concepts are simple. All it requires is for drivers to charge their batteries with low-cost electricity overnight at home, then plug them into two-way EV charging stations at work and discharge their stored electricity for use by the building by day when buying power from the grid is more expensive.
“Workplace buildings could avoid high daytime prices by purchasing electricity from EVs parked onsite and enjoy savings as a result,” says the report.
Based on average commuting distances, EVs in this scenario could make half their storage capacity available for discharge. Drivers would be paid out of the building’s savings, effectively selling electricity back to the grid and earning up to $8,400 over the life of their vehicle.
According to the report, Ontario could have as many as 18,555 vehicles participating in mobile storage by 2030. At this level, the daily electricity demand would be reduced by 565 MWh. This, in turn, would reduce demand for natural gas-fired electricity generation, a fossil-fuel electricity source, avoiding the expense of gas purchases while reducing GHG emissions.
The second-life storage opportunity begins when the vehicle lifespan ends. “EV batteries will still have over 80% of their storage capacity after being driven for 13 years and providing mobile storage,” the report states. “Those-second life batteries could provide a low-cost energy storage solution for the electricity grid and enhance grid stability over time.”
Some of the savings could be shared with EV owners in the form of a rebate worth up to 20 per cent of the batteries’ initial cost.
Call to action
The report concludes with a call to action for EV advocates to press policy makers and other stakeholders to take actions on building codes, the federal Clean Fuel Standard and other business models in order to maximize the benefits of using EV batteries for the electricity system in this way, even as growing adoption could challenge power grids in some regions.
“EVs are often approached as an environmental solution to climate change,” says Cara Clairman, Plug’n Drive president and CEO. “While this is true, there are significant economic opportunities that are often overlooked.”
California Net Zero Grid Investment will fuel electrification, renewable energy buildout, EV adoption, and grid modernization, boosting utilities, solar, and storage, while policy, IRA incentives, and transmission upgrades drive reliability and long-term rate base growth.
Key Points
Funding to electrify sectors and modernize the grid, scaling renewables, EVs, and storage to meet 2045 net zero goals.
✅ $370B over 22 years to meet 2045 net zero target
✅ Utilities lead gains via grid modernization and rate base growth
✅ EVs, solar, storage scale; IRA credits offset costs
$370 billion: That’s the investment Edison International CEO Pedro Pizarro says is needed for California’s power grid to meet the state’s “net zero” goal for CO2 emissions by 2045.
Getting there will require replacing fossil fuels with electricity in transportation, HVAC systems for buildings and industrial processes. Combined with population growth and data demand potentially augmented by artificial intelligence, that adds up to an 82 percent increase in electricity demand over 22 years, or 3 percent annually, and a potential looming shortage if buildout lags.
California’s plans also call for phasing out fossil fuel generation in the state, despite ongoing dependence on fossil power during peaks. And presumably, its last nuclear plant—PG&E Corp’s (PCG) Diablo Canyon—will be eventually be shuttered as well. So getting there also means trebling the state’s renewable energy generation and doubling usage of rooftop solar.
Assuming this investment is made, it’s relatively easy to put together a list of beneficiaries. Electric vehicles hit 20 percent market share in the state in Q2, even as pandemic-era demand shifts complicate load forecasting. And while competition from manufacturers has increased, leading manufacturers like Tesla TSLA -3% Inc (TSLA) can look forward to rising sales for some time—though that’s more than priced in for Elon Musk’s company at 65 times expected next 12 months earnings.
In the past year, California regulators have dialed back net metering through pricing changes affecting compensation, a subsidy previously paying rooftop solar owners premium prices for power sold back to the grid. That’s hit share prices of SunPower Corp (SPWR) and Sunrun Inc (RUN) quite hard, by further undermining business plans yet to demonstrate consistent profitability.
Nonetheless, these companies too can expect robust sales growth, as global prices for solar components drop and Inflation Reduction Act tax credits at least somewhat offset higher interest rates. And the combination of IRA tax credits and U.S. tariff walls will continue to boost sales at solar manufacturers like JinkoSolar Holding (JKS).
The surest, biggest beneficiaries of California’s drive to Net Zero are the utilities, reflecting broader utility trends in grid modernization, with investment increasing earnings and dividends. And as the state’s largest pure electric company, Edison has the clearest path.
Edison is currently requesting California regulators OK recovery over a 30-year period of $2.4 billion in losses related to 2017 wildfires. Assuming a amicable decision by early next year, management can then turn its attention to upgrading the grid. That investment is expected to generate long-term rate base growth of 8 percent at year, fueling 5 to 7 percent annual earnings growth through 2028 with commensurate dividend increases.
That’s a strong value proposition Edison stock, with trades at just 14 times expected next 12 months earnings. The yield of roughly 4.4 percent at current prices was increased 5.4 percent this year and is headed for a similar boost in December.
When California deregulated electricity in 1996, it required utilities with rare exceptions to divest their power generation. As a result, Edison’s growth opportunity is 100 percent upgrading its transmission and distribution grid. And its projects can typically be proposed, sited, permitted and built in less than a year, limiting risk of cost overruns to ensure regulatory approval and strong investment returns.
Edison’s investment plan is also pretty much immune to an unlikely backtracking on Net Zero goals by the state. And the company has a cost argument as well: Dr Pizarro cites U.S. Department of Energy and Department of Transportation data to project inflation-adjusted savings of 40 percent in California’s total customer energy bills from full electrification.
There’s even a reason to believe 40 percent savings will prove conservative. Mainly, gasoline currently accounts for a bit more than half energy expenditures. And after a more than 10-year global oil and gas investment drought, supplies are likely get tighter and prices possibly much higher in coming years.
Of course, those savings will only show up after significant investment is made. At this point, no major utility system in the world runs on 100 percent renewable energy, and California’s blackout politics underscore how reliability concerns shape deployment. And the magnitude of storage technology needed to overcome intermittency in solar and wind generation is not currently available let alone affordable, though both cost and efficiency are advancing.
Taking EVs from 20 to 100 percent of California’s new vehicle sales calls for a similar leap in efficiency and cost, even with generous federal and state subsidy. And while technology to fully electrify buildings and homes is there, economically retrofitting statewide is almost certainly going to be a slog.
At the end of the day, political will is likely to be as important as future technological advance for how much of Pizarro’s $370 billion actually gets spent. And the same will be true across the U.S., with state governments and regulators still by and large calling the shots for how electricity gets generated, transmitted and distributed—as well as who pays for it and how much, even as California’s exported policies influence Western markets.
Ironically, the one state where investors don’t need to worry about renewable energy’s prospects is one of the currently reddest politically. That’s Florida, where NextEra Energy NEE +2.8% (NEE) and other utilities can dramatically cut costs to customers and boost reliability by deploying solar and energy storage.
You won’t hear management asserting it can run the Sunshine State on 100 percent renewable energy, as utilities and regulators do in some of the bluer parts of the country. But by demonstrating the cost and reliability argument for solar deployment, NextEra is also making the case why its stock is America’s highest percentage bet on renewables’ growth—particularly at a time when all things energy are unfortunately becoming increasingly, intensely political.
