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Hurricane Ida New Orleans Infrastructure faced a split outcome: levees and pumps protected against storm surge, while the power grid collapsed as transmission lines failed, prompting large-scale restoration efforts across Louisiana and Mississippi.

Key Points

It summarizes Ida's impact: levees and pumps held, but the power grid failed, causing outages and slow restoration.

✅ Levees and pumps mitigated flooding and storm surge impacts.

✅ All transmission lines failed, crippling the power grid.

✅ Crews and drones assess damage; restoration may take weeks.

Infrastructure in the city of New Orleans turned in a mixed performance against the fury of Hurricane Ida, with the levees and pumps warding off catastrophic flooding even as the electrical grid, part of the broader Louisiana power grid, failed spectacularly.

Ida’s high winds, measuring 150 miles (240 kilometers) an hour at landfall, took out all eight transmissions lines that deliver power into New Orleans, ripped power poles in half and crumpled at least one steel transmission tower into a twisted metal heap, knocking out electricity to all of the city. A total of more than 1.2 million homes and businesses in Louisiana and Mississippi lost power. While about 90,000 customers were reconnected by Monday afternoon, many could face days without electricity, and frustration can mount as seen during the Houston outage after major storms.

In contrast, the New Orleans area’s elaborate flood defenses seem to have held up, a vindication of the Army Corps of Engineers’ $14.5 billion project to rebuild levees, flood gates and pumps in the wake of the devastation wrought by Hurricane Katrina in 2005. While there were reports of scattered deaths tied to Ida, the city escaped the kind of flooding that destroyed entire neighborhoods in Katrina’s wake, left parts of the city uninhabitable for months and claimed 1,800 lives. 

“The situation in New Orleans, as bad as it is today with the power, could be so much worse,” Louisiana Governor John Bel Edwards said Monday on the Today Show, praising the levee system’s performance. “All you have to do is go back 16 years to get a glimpse of what that would have been like.”

While the levees’ resiliency is no doubt due to the rebuilding effort that followed Katrina, the starkly different outcomes also stems from the storms’ different characteristics. Katrina slammed the coast with a 30-foot storm surge of ocean water, while preliminary estimates from Ida put its surge far lower. 

Ida’s winds, however, were stronger than Katrina’s, and that’s what ultimately took out so many power lines, a dynamic that also saw Texas utilities struggle during Harvey. Deanna Rodriguez, the chief executive officer of power provider Entergy New Orleans, declined to comment on when service would be restored, saying the company was using helicopters and drones to help assess the damage.

Michael Webber, an energy and engineering professor at the University of Texas at Austin, estimated power restoration will take days and possibly weeks, a pattern seen in Florida restoration timelines after major hurricanes, based on the initial damage reports from the storm. More than 25,000 workers from at least 32 states and Washington are mobilized to assist with power restoration efforts, similar to FPL's massive response after Irma, according to the Edison Electric Institute.

“The question is, how long will it take to rebuild these lines,” Webber said. The utilities will first need to complete their damage assessments before they can get a sense of repair timelines, a step that Gulf Power crews have highlighted in past recoveries, he said. “You can imagine that will take days at least, possibly weeks.”

The loss of electricity will have other affects as well, and even though grid resilience during the pandemic was strong, local systems face immediate constraints. Sewer substations, for example, need electricity to keep wastewater moving, said Ghassan Korban, executive director of the New Orleans Sewerage & Water Board. The storm knocked out power to about 80 of the city’s 84 pumping stations, he said at a Monday press conference. “Without electricity, wastewater backs up and can cause overflows,” he said, adding that residents should conserve water to lessen stress on the system.

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Global Renewable LCOE Trends reveal offshore wind costs down 32%, with 10MW turbines, lower CAPEX and OPEX, and parity for solar PV and onshore wind in Europe, China, and California, per BloombergNEF analysis.

Key Points

Benchmarks showing falling LCOE for offshore wind, onshore wind, and solar PV, driven by larger turbines and lower CAPEX

✅ Offshore wind LCOE $78/MWh; $53-64/MWh in DK/NL excl. transmission

✅ Onshore wind $47/MWh; solar PV $51/MWh, best $26-36/MWh

✅ Cost drivers: 10MW turbines, lower CAPEX/OPEX, weak China demand

World offshore wind costs have fallen 32% from just a year ago and 12% compared with the first half of 2019, according to a BNEF long-term outlook from BloombergNEF.

In its latest Levelized Cost of Electricity (LCOE) Update, BloombergNEF said its current global benchmark LCOE estimate for offshore wind is $78 a megawatt-hour.

“New offshore wind projects throughout Europe, including the UK's build-out, now deploy turbines with power ratings up to 10MW, unlocking CAPEX and OPEX savings,” BloombergNEF said.

In Denmark and the Netherlands, it expects the most recent projects financed to achieve $53-64/MWh excluding transmission.

New solar and onshore wind projects have reached parity with average wholesale power prices in California and parts of Europe, while in China levelised costs are below the benchmark average regulated coal price, according to BloombergNEF.

The company's global benchmark levelized cost figures for onshore wind and PV projects financed in the last six months are at $47 and $51 a megawatt-hours, underscoring that renewables are now the cheapest new electricity option in many regions, down 6% and 11% respectively compared with the first half of 2019.

BloombergNEF said for wind this is mainly down to a fall in the price of turbines – 7% lower on average globally compared with the end of 2018.

In China, the world’s largest solar market, the CAPEX of utility-scale PV plants has dropped 11% in the last six months, reaching $0.57m per MW.

“Weak demand for new plants in China has left developers and engineering, procurement and construction firms eager for business, and this has put pressure on CAPEX,” BloombergNEF said.

It added that estimates of the cheapest PV projects financed recently – in India, Chile and Australia – will be able to achieve an LCOE of $27-36/MWh, assuming competitive returns for their equity investors.

Best-in-class onshore wind farms in Brazil, India, Mexico and Texas can reach levelized costs as low as $26-31/MWh already, the research said.

Programs such as the World Bank wind program are helping developing countries accelerate wind deployment as costs continue to drop.

BloombergNEF associate in the energy economics team Tifenn Brandily said: “This is a three- stage process. In phase one, new solar and wind get cheaper than new gas and coal plants on a cost-of- energy basis.

“In phase two, renewables reach parity with power prices. In phase three, they become even cheaper than running existing thermal plants.

“Our analysis shows that phase one has now been reached for two-thirds of the global population.

“Phase two started with California, China and parts of Europe. We expect phase three to be reached on a global scale by 2030.

“As this all plays out, thermal power plants will increasingly be relegated to a balancing role, looking for opportunities to generate when the sun doesn’t shine or the wind doesn’t blow.”

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Entergy COVID-19 Emergency Relief Fund provides financial assistance to ALICE households, low-income seniors, and disabled customers via United Way grants for rent, mortgage, utilities, food, and bill payment support during COVID-19, alongside a disconnect moratorium.

Key Points

A shareholder-funded program offering essential grants and bill support to Entergy customers affected by COVID-19.

✅ Shareholders commit $700,000; grants distributed via United Way partners.

✅ Focus on ALICE families, low-income seniors, and disabled customers.

✅ Disconnects suspended; bill tools and LIHEAP advocacy underway.

In an effort to help working families experiencing financial hardships as a result of the coronavirus pandemic, the Entergy Charitable Foundation has established the COVID-19 Emergency Relief Fund, recognizing the need for electricity across communities.

"The health and safety of our customers, employees and communities is Entergy's top priority," said Leo Denault, chairman and CEO of Entergy Corporation. "For more than 100 years, Entergy has never wavered in our commitment to supporting our customers and the communities we serve. This pandemic is no different. During this challenging time, we are helping lessen the impact of this crisis on the most vulnerable in our communities. I strongly encourage our business partners to join us in this effort."

As devastating and disruptive as this crisis is for everyone, we know from past experience that those most heavily impacted are ALICE households (low-wage working families) and low-income elderly and disabled customers, who often face energy insecurity during such events - roughly 40%-50% of Entergy's customer base.

"We know from experience that working families and low-income elderly and disabled customers are hardest hit during times of crisis," said Patty Riddlebarger, vice president of Entergy's corporate social responsibility. "We are working quickly to make funds available to community partners that serve vulnerable households to lessen the economic impact of the COVID-19 crisis and ensure that families have the resources they need to get by during this time of uncertainty."

To support our most vulnerable customers, Entergy shareholders are committing $700,000 to the COVID-19 Emergency Relief Fund to help qualifying customers with basic needs such as food and nutrition, rent and mortgage assistance, and other critical needs, alongside measures like Texas utilities waiving fees that ease household costs, until financial situations become more stable. Grants from the fund will be provided to United Way organizations and other nonprofit partners across Entergy's service area that are providing services to impacted households.

Company shareholders will also match employee contributions to the COVID-19 relief efforts of local United Way organizations up to $100,000 to maximize impact.

In addition to establishing the COVID-19 Emergency Relief Fund, Entergy is taking additional steps to support and protect our customers during this crisis, similar to PG&E's pandemic response measures, including:

With support from our regulators, we are temporarily suspending customer disconnects, as seen in New Jersey and New York policies, as we continue to monitor the situation.

We are working with our network of community advocates, as the industry coordination with federal partners continues, to request a funding increase of the Low Income Home Energy Assistance Program to help alleviate financial hardships caused by COVID-19 on vulnerable households.

We are developing bill payment solutions and tools to help customers pay their accumulated balances once the disconnect moratorium is lifted.

Already in place to support vulnerable customers is Entergy's The Power to Care program, which provides emergency bill payment assistance to seniors and disabled individuals. To mark the 20th anniversary of Entergy's low-income customer initiative, the limit of shareholders' dollar for dollar match of customer donations was increased from $500,000 to $1 million per year. Shareholders continue to match employee donations dollar for dollar with no limit.

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Ontario Nuclear Power Costs highlight LCOE, capex, refurbishment outlays, and waste management, compared with renewables, grid reliability, and emissions targets, informing Australia and Peter Dutton on feasibility, timelines, and electricity prices.

Key Points

They include high capex and LCOE from refurbishments and waste, offset by reliable, low-emission baseload.

✅ Refurbishment and maintenance drive lifecycle and LCOE variability.

✅ High capex and long timelines affect consumer electricity prices.

✅ Low emissions, but waste and safety compliance add costs.

Australian opposition leader Peter Dutton recently lauded Canada’s use of nuclear power as a model for Australia’s energy future. His praise comes as part of a broader push to incorporate nuclear energy into Australia’s energy strategy, which he argues could help address the country's energy needs and climate goals. However, the question arises: Is Ontario’s experience with nuclear power as cost-effective as Dutton suggests?

Dutton’s endorsement of Canada’s nuclear power strategy highlights a belief that nuclear energy could provide a stable, low-emission alternative to fossil fuels. He has pointed to Ontario’s substantial reliance on nuclear power, and the province’s exploration of new large-scale nuclear projects, as an example of how such an energy mix might benefit Australia. The province’s energy grid, which integrates a significant amount of nuclear power, is often cited as evidence that nuclear energy can be a viable component of a diversified energy portfolio.

The appeal of nuclear power lies in its ability to generate large amounts of electricity with minimal greenhouse gas emissions. This characteristic aligns with Australia’s climate goals, which emphasize reducing carbon emissions to combat climate change. Dutton’s advocacy for nuclear energy is based on the premise that it can offer a reliable and low-emission option compared to the fluctuating availability of renewable sources like wind and solar.

However, while Dutton’s enthusiasm for the Canadian model reflects its perceived successes, including recent concerns about Ontario’s grid getting dirtier amid supply changes, a closer look at Ontario’s nuclear energy costs raises questions about the financial feasibility of adopting a similar strategy in Australia. Despite the benefits of low emissions, the economic aspects of nuclear power remain complex and multifaceted.

In Ontario, the cost of nuclear power has been a topic of considerable debate. While the province benefits from a stable supply of electricity due to its nuclear plants, studies warn of a growing electricity supply gap in coming years. Ontario’s experience reveals that nuclear power involves significant capital expenditures, including the costs of building reactors, maintaining infrastructure, and ensuring safety standards. These expenses can be substantial and often translate into higher electricity prices for consumers.

The cost of maintaining existing nuclear reactors in Ontario has been a particular concern. Many of these reactors are aging and require costly upgrades and maintenance to continue operating safely and efficiently. These expenses can add to the overall cost of nuclear power, impacting the affordability of electricity for consumers.

Moreover, the development of new nuclear projects, as seen with Bruce C project exploration in Ontario, involves lengthy and expensive construction processes. Building new reactors can take over a decade and requires significant investment. The high initial costs associated with these projects can be a barrier to their economic viability, especially when compared to the rapidly decreasing costs of renewable energy technologies.

In contrast, the cost of renewable energy has been falling steadily, even as debates over nuclear power’s trajectory in Europe continue, making it a more attractive option for many jurisdictions. Solar and wind power, while variable and dependent on weather conditions, have seen dramatic reductions in installation and operational costs. These lower costs can make renewables more competitive compared to nuclear energy, particularly when considering the long-term financial implications.

Dutton’s praise for Ontario’s nuclear power model also overlooks some of the environmental and logistical challenges associated with nuclear energy. While nuclear power generates low emissions during operation, it produces radioactive waste that requires long-term storage solutions. The management of nuclear waste poses significant environmental and safety concerns, as well as additional costs for safe storage and disposal.

Additionally, the potential risks associated with nuclear power, including the possibility of accidents, contribute to the complexity of its adoption. The safety and environmental regulations surrounding nuclear energy are stringent and require continuous oversight, adding to the overall cost of maintaining nuclear facilities.

As Australia contemplates integrating nuclear power into its energy mix, it is crucial to weigh these financial and environmental considerations. While the Canadian model provides valuable insights, the unique context of Australia’s energy landscape, including its existing infrastructure, energy needs, and the costs of scrapping coal-fired electricity in comparable jurisdictions, must be taken into account.

In summary, while Peter Dutton’s endorsement of Canada’s nuclear power model reflects a belief in its potential benefits for Australia’s energy strategy, the cost-effectiveness of Ontario’s nuclear power experience is more nuanced than it may appear. The high capital and maintenance costs associated with nuclear energy, combined with the challenges of managing radioactive waste and ensuring safety, present significant considerations. As Australia evaluates its energy future, a comprehensive analysis of both the benefits and drawbacks of nuclear power will be essential to making informed decisions about its role in the country’s energy strategy.

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SaskPower Summer Power Demand Record hits 3,520 MW as heat waves drive electricity consumption; grid capacity, renewables expansion, and energy efficiency tips highlight efforts to curb greenhouse gas emissions while meeting Saskatchewan's growing load.

Key Points

The latest summer peak load in Saskatchewan: 3,520 MW, driven by heat, with plans to expand capacity and lower emissions.

✅ New peak surpasses last August by 50 MW to 3,520 MW.

✅ Capacity target: 7,000 MW by 2030 with more renewables.

✅ Tips: AC settings, close blinds, delay heat-producing chores.

As the mercury continues to climb in Saskatchewan, where Alberta's summer electricity record offers a regional comparison, SaskPower says the province has set a new summer power demand record.

The Crown says the new record is 3,520 megawatts. It’s an increase of 50 megawatts over the previous record, or enough electricity for 50,000 homes.

“We’ve seen both summer and winter records set every year for a good while now. And if last summer is any indication, we could very well see another record before temperatures cool off heading into the fall,” said SaskPower Vice President of Transmission and Industrial Services Kory Hayko in a written release. “It’s not impossible we’ll break this record again in the coming days. It’s SaskPower’s responsibility to ensure that Saskatchewan people and businesses have the power they need to thrive. That’s what drives our investment of $1 billion every year, as outlined in our annual report, to modernize and grow the province’s electrical system.”

The previous summer consumption record of 3,740 megawatts was set last August, and similar extremes in the Yukon electricity demand highlight broader demand pressures this year. The winter demand record remains higher at 3,792 megawatts, set on Dec. 29, 2017.

SaskPower says it plans to expand its generation capacity from 4,500 megawatts now to 7,000 megawatts in 2030, with a focus on decreasing greenhouse gas emissions and doubling renewable electricity by 2030 as part of its strategy.

To reduce power bills, the Crown suggests turning down or programming air conditioning when residents aren’t home, inspecting the air conditioner to make sure it is operating efficiently, keeping blinds closed to keep out direct sunlight, delaying chores that produce heat and making sure electronics are turned off when people leave the room.

The new record beats the previous summer peak of 3,470 MW, set last August after also being broken twice in July. The winter demand record is still higher at 3,792 MW, which was set on December 29, 2017. To meet growing power demand, and amid projections that Manitoba's electrical demand could double in the next 20 years, SaskPower is expanding its generation capacity from approximately 4,500 MW now to 7,000 MW by 2030 while also reducing greenhouse gas emissions by 40 per cent from 2005 levels. To accomplish this, we will be significantly increasing the amount of renewables on our system.

Cooling and heating represents approximately a quarter of residential power bills. To reduce consumption and power bills during heat waves, SaskPower’s customers can:

Turn down or program the air conditioning when no one is home (for every degree that air conditioning is lowered for an eight-hour period, customers can save up to two per cent on their power costs);

Consider having their air conditioning unit inspected to make sure it is operating efficiently;

Keep the heat out by closing blinds and drapes, especially those with direct sunlight;

Delay chores that produce heat and moisture, like dishwashing and laundering, until the cooler parts of the day or evening; and

As with any time of the year, make sure lights, televisions and other electronics are turned off when no one's in the room. For example, a modern gaming console can use as much power as a refrigerator.

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Australian Electric Vehicle Sales tripled in 2019 amid expanding charging infrastructure and more models, but market share remains low, constrained by limited government policy, weak incentives, and absent emissions standards despite growing ultra-fast chargers.

Key Points

EV units sold in Australia; in 2019 they tripled to 6,718, but market share was just 0.6%.

✅ Sales rose from 2,216 (2018) to 6,718 (2019); ~80% were BEVs.

✅ Public charging sites reached 2,307; fast chargers up 40% year-on-year.

✅ Policy gaps and absent standards limit model supply and EV uptake.

Sales of electric vehicles in Australia tripled in 2019 despite a lack of government support, according to the industry’s peak body.

The country’s network of EV charging stations was also growing, the Electric Vehicle Council’s annual report found, including a rise in the number of faster charging stations that let drivers recharge a car in about 15 minutes.

But the report, released on Wednesday, found the market share for electric vehicles was still only 0.6% of new vehicle sales – well behind the 2.5% to 5% in other developed countries.

The chief executive of the council, Behyad Jafari, said the rise in sales was down to more models becoming available. There are now 28 electric models on sale, with eight priced below $65,000.

Six more were due to arrive before the end of 2021, including two priced below $50,000, the council’s report said.

“We have repeatedly heard from car companies that they were planning to bring vehicles here, but Australia doesn’t have that policy support.”

The Morrison government promised a national electric vehicle strategy would be finalised by the middle of this year, but the policy has been delayed. The prime minister, Scott Morrison, last year accused Labor of wanting to “end the weekend” and force people out of four-wheel drives after the opposition set a target of 50% of new car sales being electric by 2030.

Jafari cited the Kia e-Niro – an award-winning electric SUV that was being prepared for an Australian launch, but is now reportedly on hold because the manufacturer favoured shipping to countries with emissions standards.

The council’s members include BMW, Nissan, Hyundai and Harley Davidson, as well as energy, technology and charging infrastructure companies.

Sales of electric vehicles – which include plug-in hybrids – went from 2,216 in 2018 to 6,718 in 2019, the report said. Jafari said about 80% of those sales were all-electric vehicles.

There have been 3,226 electric vehicles sold in 2020, the report said, despite an overall drop of 20% in vehicle sales due to the Covid-19 pandemic, while U.S. EV sales have surged into 2024.

Jafari said: “Our report is showing that Australian consumers want these cars.

“There is no controversy that the future of the industry is electric, but at the moment the industry is looking at different markets. We want policies that show [Australia] is going on this journey.”

Government agency data has forecast that half the new cars sold will be electric by 2035, underscoring that the age of electric cars is arriving even if there is no policy to support their uptake.

Manufacturers currently selling electric cars in Australia are Nissan, Hyundai, Mitsubishi, Tesla, Volvo, Porsche, Audi, BMW, Mercedes, Jaguar and Renault, the report said.

Jafari said most G20 countries had emissions standards in place for vehicles sold and incentives in place to support electric vehicles, such as rebates or exemptions from charges. This hadn’t happened in Australia, he said.

The report said: “Globally, carmakers are rolling out more electric vehicle models as the electric car market expands, but so far production cannot keep up with demand. This means that without policy signals, Australians will continue to be denied access to the full global range of electric vehicles.”

On Tuesday, one Australian charging provider, Evie Networks, opened an ultra-fast station at a rest stop at Campbell Town in Tasmania – between Launceston and Hobart.

The company said the station would connect EV owners in the state’s north and south and the two 350kW chargers could recharge a vehicle in 15 minutes, highlighting whether grids have the power to charge EVs at scale. Two more sites were planned for Tasmania, the company said.

A Tasmanian government grant to support electric vehicle charging had helped finance the site. Evie was also supported with a $15m grant from the federal government’s Australian Renewable Energy Agency.

According to the council report, Australia now has 2,307 public charging stations, including 357 fast chargers – a rise of 40% in the past year.

A survey of 2,900 people in New South Wales, the ACT, Victoria and South Australia, carried out by NRMA, RACV and RAA on behalf of the council, found the main barriers to buying an electric vehicle were concerns over access to charging points, higher prices and uncertainty over driving range.

Consumers favoured electric vehicles because of their environmental footprint, lower maintenance costs and vehicle performance.

The report said the average battery range of electric vehicles available in Australia was 400km, but almost 80% of people thought the average was less.

According to the survey, 56% of Australians would consider an electric car when they next bought a vehicle, and in the UK, EV inquiries soared during a fuel supply crisis.

“We are far behind, but it is surmountable,” Jafari said.

The council report also rated state and territories on the policies that supported its industry and found the ACT was leading, followed by NSW and Queensland.

A review of commercial electric vehicle use found public electric bus trials were planned or under way in Queensland, NSW, WA, Victoria and ACT. There are now more than 400,000 electric buses in use around the globe.

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