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Nuclear Power Construction Milestones spotlight EPR builds, Hualong One steam generators, APR-1400 grid integration, and VVER startups, with hot functional testing, hydrostatic checks, and commissioning advancing toward fuel loading and commercial operation.

Key Points

Key reactor project steps, from testing and grid readiness to startup, marking progress toward safe commercial operation.

✅ EPR units advance through cold and hot functional testing

✅ Hualong One installs 365-ton steam generators at Fuqing 5

✅ APR-1400 and VVER projects progress toward grid connection

The world’s nuclear power industry has been busy in the new year, with several construction projects, including U.S. reactor builds, reaching key milestones as 2018 began.

EPR Units Making Progress

Four EPR nuclear units are under construction in three countries: Olkiluoto 3 in Finland began construction in August 2005, Flamanville 3 in France began construction in December 2007, and Taishan 1 and 2 in China began construction in November 2009. Each of the new units is behind schedule and over budget, but recent progress may signal an end to some of the construction difficulties.

EDF reported that cold functional tests were completed at Flamanville 3 on January 6. The main purpose of the testing was to confirm the integrity of primary systems, and verify that components important to reactor safety were properly installed and ready to operate. More than 500 welds were inspected while pressure was held greater than 240 bar (3,480 psi) during the hydrostatic testing, which was conducted under the supervision of the French Nuclear Safety Authority.

With cold testing successfully completed, EDF can now begin preparing for hot functional tests, which verify equipment performance under normal operating temperatures and pressures. Hot testing is expected to begin in July, with fuel loading and reactor startup possible by year end. The company also reported that the total cost for the unit is projected to be €10.5 billion (in 2015 Euros, excluding interim interest).

Olkiluoto 3 began hot functional testing in December. Teollisuuden Voima Oyj—owner and operator of the site—expects the unit to produce its first power by the end of this year, with commercial operation now slated to begin in May 2019.

Although work on Taishan 1 began years after Olkiluoto 3 and Flamanville 3, it is the furthest along of the EPR units. Reports surfaced on January 2 that China General Nuclear (CGN) had completed hot functional testing on Taishan 1, and that the company expects the unit to be the first EPR to startup. CGN said Taishan 1 would begin commercial operation later this year, with Taishan 2 following in 2019.

Hualong One Steam Generators Installed

Another Chinese project reached a notable milestone on January 8. China National Nuclear Corp. announced the third of three steam generators had been installed at the Hualong One demonstration project, which is being constructed as Unit 5 at the Fuqing nuclear power plant.

The Hualong One pressurized water reactor unit, also known as the HPR 1000, is a domestically developed design, part of China’s nuclear program, based on a French predecessor. It has a 1,090 MW capacity. The steam generators reportedly weigh 365 metric tons and stand more than 21 meters tall. The first steam generator was installed at Fuqing 5 on November 10, with the second placed on Christmas Eve.

Barakah Switchyard Energized

In the United Arab Emirates, more progress has been made on the four South Korean–designed APR-1400 units under construction at the Barakah nuclear power plant. On January 4, Emirates Nuclear Energy Corp. (ENEC) announced that the switchyard for Units 3 and 4 had been energized and connected to the power grid, a crucial step in Abu Dhabi toward completion. Unit 2’s main power transformer, excitation transformer, and auxiliary power transformer were also energized in preparation for hot functional testing on that unit.

“These milestones are a result of our extensive collaboration with our Prime Contractor and Joint Venture partner, the Korea Electric Power Corporation (KEPCO),” ENEC CEO Mohamed Al Hammadi said in a press release. “Working together and benefitting from the experience gained when conducting the same work on Unit 1, the teams continue to make significant progress while continuing to implement the highest international standards of safety, security and quality.”

In 2017, ENEC and KEPCO achieved several construction milestones including installation and concrete pouring for the reactor containment building liner dome section on Unit 3, and installation of the reactor containment liner plate rings, reactor vessel, steam generators, and condenser on Unit 4.

Construction began on the four units (Figure 1) in July 2012, May 2013, September 2014, and September 2015, respectively. Unit 1 is currently undergoing commissioning and testing activities while awaiting regulatory review and receipt of the unit’s operating license from the Federal Authority for Nuclear Regulation, before achieving 100% power in a later phase. According to ENEC, Unit 2 is 90% complete, Unit 3 is 79% complete, and Unit 4 is 60% complete.

VVER Units Power Up

On December 29, Russia’s latest reactor to commence operation—Rostov 4 near the city of Volgodonsk—reached criticality, as other projects like Leningrad II-1 advance across the fleet, and was operated at its minimum controlled reactor power (MCRP). Criticality is a term used in the nuclear industry to indicate that each fission event in the reactor is releasing a sufficient number of neutrons to sustain an ongoing series of reactions, which means the neutron population is constant and the chain reaction is stable.

“The transfer to the MCRP allows [specialists] to carry out all necessary physical experiments in the critical condition of [the] reactor unit (RU) to prove its design criteria,” Aleksey Deriy, vice president of Russian projects for ASE Engineering Co., said in a press release. “Upon the results of the experiments the specialists will decide on the RU powerup.”

Rostov 4 is a VVER-1000 reactor with a capacity of 1,000 MW. The site is home to three other VVER units: Unit 1 began commercial operation in 2001, Unit 2 in 2010, and Unit 3 in 2015.

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US Electricity Demand Stagnation reflects decoupling from GDP as TVA's IRP revises outlook, with energy efficiency, distributed generation, renewables, and cheap natural gas undercutting coal, reshaping utility business models and accelerating grid modernization.

Key Points

US electricity demand stagnation is flat load growth driven by efficiency, DG, and decoupling from GDP.

✅ Flat sales pressure IOU profits and legacy baseload investments.

✅ Efficiency and rooftop solar reduce load growth and capacity needs.

✅ Utilities must pivot to services, DER orchestration, and grid software.

The US electricity sector is in a period of unprecedented change and turmoil, with emerging utility trends reshaping strategies across the industry today. Renewable energy prices are falling like crazy. Natural gas production continues its extraordinary surge. Coal, the golden child of the current administration, is headed down the tubes.

In all that bedlam, it’s easy to lose sight of an equally important (if less sexy) trend: Demand for electricity is stagnant.

Thanks to a combination of greater energy efficiency, outsourcing of heavy industry, and customers generating their own power on site, demand for utility power has been flat for 10 years, with COVID-19 electricity demand underscoring recent variability and long-run stagnation, and most forecasts expect it to stay that way. The die was cast around 1998, when GDP growth and electricity demand growth became “decoupled”:

This historic shift has wreaked havoc in the utility industry in ways large and small, visible and obscure. Some of that havoc is high-profile and headline-making, as in the recent requests from utilities (and attempts by the Trump administration) to bail out large coal and nuclear plants amid coal and nuclear industry disruptions affecting power markets and reliability.

Some of it, however, is unfolding in more obscure quarters. A great example recently popped up in Tennessee, where one utility is finding its 20-year forecasts rendered archaic almost as soon as they are released.

Falling demand has TVA moving up its planning process

Every five years, the Tennessee Valley Authority (TVA) — the federally owned regional planning agency that, among other things, supplies electricity to Tennessee and parts of surrounding states — develops an Integrated Resource Plan (IRP) meant to assess what it requires to meet customer needs for the next 20 years.

The last IRP, completed in 2015, anticipated that there would be no need for major new investment in baseload (coal, nuclear, and hydro) power plants; it foresaw that energy efficiency and distributed (customer-owned) energy generation would hold down demand.

Even so, TVA underestimated. Just three years later, the Times Free Press reports, “TVA now expects to sell 13 percent less power in 2027 than it did two decades earlier — the first sustained reversal in the growth of electricity usage in the 85-year history of TVA.”

TVA will sell less electricity in 10 years than it did 10 years ago. That is bonkers.

This startling shift in prospects has prompted the company to accelerate its schedule. It will now develop its next IRP a year early, in 2019.

Think for a moment about why a big utility like TVA (serving 9 million customers in seven states, with more than $11 billion in revenue) sets out to plan 20 years ahead. It is investing in extremely large and capital-intensive infrastructure like power plants and transmission lines, which cost billions of dollars and last for decades. These are not decisions to make lightly; the utility wants to be sure that they will still be needed, and will still pay off, for many years to come.

Now think for a moment about what it means for the electricity sector to be changing so fast that TVA’s projections are out of date three years after its last IRP, so much so that it needs to plunge back into the multimillion-dollar, year-long process of developing a new plan.

TVA wanted a plan for 20 years; the plan lasted three.

The utility business model is headed for a reckoning

TVA, as a government-owned, fully regulated utility, has only the goals of “low cost, informed risk, environmental responsibility, reliability, diversity of power and flexibility to meet changing market conditions,” as its planning manager told the Times Free Press. (Yes, that’s already a lot of goals!)

But investor-owned utilities (IOUs), which administer electricity for well over half of Americans, face another imperative: to make money for investors. They can’t make money selling electricity; monopoly regulations forbid it, raising questions about utility revenue models as marginal energy costs fall. Instead, they make money by earning a rate of return on investments in electrical power plants and infrastructure.

The problem is, with demand stagnant, there’s not much need for new hardware. And a drop in investment means a drop in profit. Unable to continue the steady growth that their investors have always counted on, IOUs are treading water, watching as revenues dry up

Utilities have been frantically adjusting to this new normal. The generation utilities that sell into wholesale electricity markets (also under pressure from falling power prices; thanks to natural gas and renewables, wholesale power prices are down 70 percent from 2007) have reacted by cutting costs and merging. The regulated utilities that administer local distribution grids have responded by increasing investments in those grids, including efforts to improve electricity reliability and resilience at lower cost.

But these are temporary, limited responses, not enough to stay in business in the face of long-term decline in demand. Ultimately, deeper reforms will be necessary.

As I have explained at length, the US utility sector was built around the presumption of perpetual growth. Utilities were envisioned as entities that would build the electricity infrastructure to safely and affordably meet ever-rising demand, which was seen as a fixed, external factor, outside utility control.

But demand is no longer rising. What the US needs now are utilities that can manage and accelerate that decline in demand, increasing efficiency as they shift to cleaner generation. The new electricity paradigm is to match flexible, diverse, low-carbon supply with (increasingly controllable) demand, through sophisticated real-time sensing and software.

That’s simply a different model than current utilities are designed for. To adapt, the utility business model must change. Utilities need newly defined responsibilities and new ways to make money, through services rather than new hardware. That kind of reform will require regulators, politicians, and risky experiments. Very few states — New York, California, Massachusetts, a few others — have consciously set off down that path.

Flat or declining demand is going to force the issue

Even if natural gas and renewables weren’t roiling the sector, the end of demand growth would eventually force utility reform.

To be clear: For both economic and environmental reasons, it is good that US power demand has decoupled from GDP growth. As long as we’re getting the energy services we need, we want overall demand to decline. It saves money, reduces pollution, and avoids the need for expensive infrastructure.

But the way we’ve set up utilities, they must fight that trend. Every time they are forced to invest in energy efficiency or make some allowance for distributed generation (and they must always be forced), demand for their product declines, and with it their justification to make new investments.

Only when the utility model fundamentally changes — when utilities begin to see themselves primarily as architects and managers of high-efficiency, low-emissions, multidirectional electricity systems rather than just investors in infrastructure growth — can utilities turn in earnest to the kind planning they need to be doing.

In a climate-aligned world, utilities would view the decoupling of power demand from GDP growth as cause for celebration, a sign of success. They would throw themselves into accelerating the trend.

Instead, utilities find themselves constantly surprised, caught flat-footed again and again by a trend they desperately want to believe is temporary. Unless we can collectively reorient utilities to pursue rather than fear current trends in electricity, they are headed for a grim reckoning.

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US Electricity Sales Decline amid population growth and GDP gains, as DOE links reduced per capita consumption to energy efficiency, warmer winters, appliances, and bulbs, while hotter summers and rising AC demand may offset savings.

Key Points

US electricity sales fell 3% since 2010 despite population and GDP growth, driven by efficiency gains and warmer winters.

✅ DOE links drops to efficiency and warmer winters

✅ Per capita residential use fell about 7% since 2010

✅ Rising AC demand may offset winter heating savings

Since 2010, the United States has grown by 17 million people, and the gross domestic product (GDP) has increased by $3.6 trillion. Yet in that same time span, electricity sales in the United States actually declined by 3%, according to data released by the U.S. Department of Energy (DOE), even as electricity prices rose at a 41-year pace nationwide.

The U.S. decline in electricity sales is remarkable given that the U.S. population increased by 5.8% in that same time span. This means that per capita electricity use fell even more than that; indeed, the Department of Energy pegs residential electricity sales per capita as having declined by 7%, even as inflation-adjusted residential bills rose 5% in 2022 nationwide.

There are likely multiple reasons for this decline in electricity sales. Department of Energy analysts suggest that, at least in part, it is due to increased adoption of energy-efficient appliances and bulbs, like compact fluorescents. Indeed, the DOE notes that there is a correlation between consumer spending on “energy efficiency” and a reduction in per capita electricity sales, while utilities invest more in delivery infrastructure to modernize the grid.

Yet the DOE also notes that states with a greater increase in warm weather days had a corresponding decrease in electricity sales, as milder weather can reduce power demand across years. In southern states, the effect was most dramatic: for instance, from 2010 to 2016, Florida had a 56% decrease in cold weather days that would require heating and as a result, saw a 9% decrease in per capita electricity sales.

The moral is that warm winters save on electricity. But if global temperatures continue to rise, and summers become hotter, too, this decrease in winter heating spending may be offset by the increased need to run air conditioning in the summer, and given how electricity and natural gas prices interact, overall energy costs could shift. Indeed, it takes far more energy to cool a room than it does to heat it, for reasons related to the basic laws of thermodynamics. 

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Vancouver October 2024 Windstorm brought extreme weather to British Columbia, causing power outages, storm damage, and downed lines as BC Hydro crews led emergency response and restoration, highlighting climate change resilience and community preparedness.

Key Points

A severe storm with 100 km/h gusts that caused outages and damage in Vancouver, prompting wide power restoration.

✅ 100 km/h gusts toppled trees and downed power lines

✅ Over 200,000 BC Hydro customers lost electricity

✅ Crews and communities coordinated emergency response

In October 2024, a powerful windstorm swept through the Vancouver area, resulting in widespread power outages and disruption across the region. The storm, characterized by fierce winds and heavy rainfall, reflected conditions seen when strong winds in the Miami Valley knocked out power earlier this year, and was part of a larger weather pattern that affected much of British Columbia. Residents braced for the impacts, with local authorities and utility companies preparing for the worst.

The Storm's Impact

The windstorm hit Vancouver with wind gusts exceeding 100 km/h, toppling trees, and downing power lines. As the storm progressed, reports of damaged properties and fallen trees began to flood in. Many neighborhoods experienced significant power outages, mirroring widespread outages in Quebec earlier in the season, with thousands of residents left without electricity for extended periods. The areas hardest hit included the West End, Kitsilano, and parts of the North Shore, where the impact of the storm was particularly severe.

Utility companies, including BC Hydro operations, mobilized their crews quickly in response to the storm's aftermath. Emergency response teams worked tirelessly to restore power, often facing challenging conditions. The restoration efforts were complicated by the sheer number of outages reported—over 200,000 customers were affected at the height of the storm. Crews encountered not only downed lines but also hazardous conditions as they navigated through debris-laden streets.

Community Response and Resilience

In the wake of the storm, the community showcased remarkable resilience. Local residents rallied together to assist one another, sharing resources and providing support to those most affected. Many community centers opened their doors as emergency shelters, offering warmth and safety to those without power, a step also taken when a London power outage disrupted mornings for thousands across the city.

Authorities also emphasized the importance of preparedness in such situations. They urged residents to have emergency kits ready, including food, water, and essential supplies, noting that nearby areas like North Seattle can face sudden outages with little warning. Local officials highlighted the value of staying informed through weather updates and alerts, allowing residents to make informed decisions during extreme weather events.

The Role of Climate Change

The October windstorm serves as a stark reminder of the increasing frequency and intensity of extreme weather events, a trend often linked to climate change. Experts have noted that rising global temperatures are contributing to more severe weather patterns, including stronger storms and increased Toronto flooding events. As cities like Vancouver face the reality of climate change, discussions about infrastructure resilience and adaptation strategies have gained urgency.

City planners and environmental advocates are pushing for initiatives that enhance the city's ability to withstand extreme weather. This includes improving stormwater management systems, increasing green spaces to absorb rainfall, and investing in renewable energy sources. By addressing these challenges proactively, Vancouver aims to mitigate the impacts of future storms and protect its residents.

Moving Forward

As recovery efforts continue, the focus now shifts to restoring normalcy and preparing for future weather events. Residents are encouraged to report any ongoing outages or hazards to local authorities and to stay updated through reliable news sources. BC Hydro and other utility companies are committed to transparency, providing regular updates on power restoration efforts, even as outages can persist for days as seen in Toronto after a spring storm.

The October 2024 windstorm will be remembered not only for its immediate impacts but also as a catalyst for discussions on resilience and community preparedness. As Vancouver looks ahead, the lessons learned from this storm will shape strategies for better handling extreme weather, ensuring that the city is equipped to face the challenges posed by a changing climate.

In conclusion, while the windstorm caused significant disruption and hardship for many, it also highlighted the strength of community spirit and the importance of proactive planning in the face of climate challenges. Vancouver's response and recovery will be crucial in building a more resilient future for all its residents.

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Philippines Renewable Energy Mini-Grids address rising electricity demand, rolling blackouts, off-grid electrification, and decentralized power in an archipelago, leveraging solar, wind, and hybrid systems to close the generation capacity gap and expand household access.

Key Points

Decentralized solar, wind, and hybrid systems powering off-grid areas to relieve shortages and expand access.

✅ Targets 2.3M unelectrified homes with reliable clean power

✅ Mitigates rolling blackouts via modular mini-grid deployments

✅ Supports energy access, resilience, and grid decentralization

The reason why IRENA made its study in the Philippines is because of the country’s demand for electricity is on a steady rise while the generating capacity lags behind. To provide households the electricity, the government is constrained to implement rolling blackouts in some regions. By 2030, the demand for electricity is projected to reach 30 million kilowatts as compared to 17 million kilowatts which is its current generating capacity.

One of the country’s biggest conglomerations, San Miguel Corporation is accountable for almost 20% of power output. It has power plants that has a 900,000-kW generation capacity. Another corporation in the energy sector, Aboitiz Power, has augmented its facilities as well to keep up with the demand. As a matter fact, even foreign players such as Tokyo Electric Power and Marubeni, as a result of the gradual privatization of the power industry which started in 2001, have built power plants in the country, a challenge mirrored in other regions where electricity for all demands greater investment, yet the power supply remains short.

And so, the IRENA came up with the study entitled “Accelerating the Deployment of Renewable Energy Mini-Grids for Off-Grid Electrification – A Study on the Philippines” to provide a clearer picture of what the current state of the crisis is and lay out possible solutions. It showed that as of 2016, a record year for renewables worldwide, the Philippines has approximately 2.3 million households without electricity. With only 89.6 percent of household electrification, that leaves about 2.36 million homes either with limited power of four to six hours each day or totally without electricity.

By the end of 2017, the Philippine government will have provided 90% of Philippine households with electricity. It is worth mentioning that in 2014, the National Capital Region together with two other regions had received 90 percent electrification. However, some areas are still unable to access power that’s within or above the national average. IRENA’s study has become a source of valuable information and analysis to the Philippines’ power systems and identified ways on how to surmount the challenges involving power systems decentralization, with renewable energy funding supporting those mini-grids which are either powered in parts or in full by renewable energy resources. This, however, does not discount the fact that providing electricity in every household still is an on-going struggle. Considering that the Philippines is an archipelago, providing enough, dependable, and clean modern energy to the entire country, including the remote and isolated islands is difficult. The onset of renewable energy is a viable and cost-effective option to support the implementation of mini-grids, as shown by Ireland's green electricity targets rising rapidly.

 

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Canada Clean Electricity Exports leverage hydroelectric power, energy storage, and transmission interconnections to meet rising IEA-forecast demand, support electrification, decarbonize grids, and attract green finance with stable policy and advanced technology.

Key Points

Canada's cross-border power sales from hydro and renewables, enabled by storage, transmission, and supportive policy.

✅ Hydro leads generation; expand transmission interties to the US

✅ Deploy storage to balance wind and solar variability

✅ Streamline regulation and green finance to scale exports

As global electricity demand continues to surge, Canada finds itself uniquely positioned to capitalize on this expanding market by choosing an electric, connected and clean pathway that scales with demand. With its vast natural resources, advanced technology, and stable political environment, Canada can play a crucial role in meeting the world’s energy needs while also advancing its own economic interests.

The International Energy Agency (IEA) has projected that global electricity demand will grow significantly over the next decade, driven by factors such as population growth, urbanization, and the increasing electrification of various sectors, including transportation and industry. This presents a golden opportunity for Canada to bolster its energy security as it boasts an abundance of renewable energy sources, particularly hydroelectric power. Currently, hydroelectricity accounts for about 60% of Canada’s total electricity generation, making it one of the largest producers of this clean energy source in the world.

The growing emphasis on renewable energy aligns perfectly with Canada’s strengths, with the Prairie Provinces emerging as leaders in new wind and solar capacity across the country. As countries worldwide strive to reduce their carbon footprints and transition to greener energy solutions, Canada’s clean energy resources can be harnessed not only to meet domestic needs but also to export electricity to neighboring countries and beyond. The U.S., for instance, is already a significant market for Canadian electricity, with interconnections facilitating the flow of power across borders. Expanding these connections and investing in infrastructure could further increase Canada’s electricity exports.

Moreover, advancements in energy storage technology present another avenue for Canada to enhance its role in the global electricity market. With the rise of intermittent energy sources like wind and solar, the ability to store excess electricity generated during peak production times becomes essential. Canada’s expertise in technology and innovation positions it well to develop and deploy energy storage solutions that can stabilize the grid through grid modernization projects and ensure a reliable supply of electricity.

Additionally, Canada’s commitment to reducing greenhouse gas emissions and combating climate change aligns with the global shift towards sustainable energy. By investing in renewable energy projects and supporting research and development, Canada can not only meet its climate targets, including zero-emissions electricity by 2035, but also attract international investment. Green financing initiatives are becoming increasingly popular, and Canada can leverage its reputation as a leader in environmental stewardship to tap into this growing market.

However, to fully realize these opportunities, Canada must address some key challenges. Regulatory hurdles, infrastructure limitations, and the need for a coordinated national energy strategy are critical issues that must be navigated. Streamlining regulations and fostering collaboration between federal and provincial governments will be essential in creating a conducive environment for investment in renewable energy projects.

Furthermore, public acceptance and community engagement are vital components of developing new energy projects, especially where solar power adoption lags and outreach is needed. Ensuring that local communities benefit from these initiatives—whether through job creation, economic investment, or shared revenues—will help garner support and facilitate smoother project implementation.

In addition to domestic efforts, Canada should also position itself as a global leader in energy diplomacy. By collaborating with other nations to share best practices, technologies, and resources, Canada can strengthen its influence in international energy discussions. Engaging in multilateral initiatives aimed at addressing energy poverty and promoting sustainable development will not only enhance Canada’s standing on the world stage but also open doors for Canadian companies to expand their reach.

In conclusion, as the global demand for electricity rises, Canada stands at a crossroads, with a tremendous opportunity to lead in the clean energy sector. By leveraging its natural resources, investing in technology, and fostering international partnerships, Canada can not only meet its energy needs but also pursue zero-emission electricity by 2035 while positioning itself as a key player in the global electricity market. The path forward will require strategic planning, investment, and collaboration, but the potential rewards are significant—both for Canada and the planet.

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