New Jersey needs Salem reactor

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With an aging Ocean County nuclear power plant set to close in 2019, lost electricity must be replaced.

Two seemingly unrelated recent news stories highlight why there's a need for more power plants in New Jersey, and why allowing operators to build a fourth nuclear reactor at the plant along the Delaware River in Salem County makes sense.

Earlier this month, it was announced that the Oyster Creek nuclear power plant in Ocean County will cease operation in 2019. The plant is the oldest operating nuclear power plant in the nation — built in 1969. Its technology is dated and it does not have the cooling towers newer nuclear power plants all have. Rather than build towers, as state environmental regulators are demanding, owner Exelon Corp. now says it will close the plant — which accounts for about 6 percent of New Jersey's electricity production — in 2019 or sooner.

Then there's Jeffrey Kaffee. On December 15, the retired airline pilot from Parsippany, Morris County, became the first American to buy a Chevrolet Volt, the much-hyped electric car from General Motors that can travel 35 miles on nothing but battery power before a gasoline-fueled engine kicks in. Over the next year, it is estimated that 30,000 Volts and Nissan Leafs another electric car new to the market will be sold in the United States. And after 2011, Ford, Toyota and other major automakers are expected to put electric cars on the market.

The closure of Oyster Creek and the sale of the first Chevy Volt are related in this way — New Jersey is facing a newfound need for electricity. When Oyster Creek closes, the supply of electricity in this state will be reduced. When electric cars start being sold in dealerships across the state — and they will, despite the high price — the demand for electricity will go up. The federal government is offering a generous $7,500 tax credit to Americans who buy electric cars, and the savings on gasoline costs will be enormous.

Driving 10,000 miles in a year on electricity will use about 2,500 kilowatt-hours of power. At an average utility rate of 11 cents per kilowatt-hour, that's $275 for a year of fuel. In gasoline terms, that equates to paying 70 cents per gallon to drive. There are going to be plenty of New Jerseyans interested in that.

PSEG announced earlier this year that it wants to build a fourth reactor at its Lower Alloways Creek complex. The three existing reactors there, built with newer technology than is used at Oyster Creek, each produce nearly double the amount of electricity that comes from the Oyster Creek reactor.

Replacing Oyster Creek with another reactor in Salem that employs the newest technology available would more than make up for the loss of the 615 megwatts of power Oyster Creek puts out. It would offer several hundred more megawatts of power that could certainly help account for any surge of demand for electricity brought on by electric cars hitting the roads and being plugged in each night in home garages and driveways.

Power producers are looking at the advent of electric cars as something akin to the spread of air conditioning into homes and businesses in the 1960s and '70s — a development that will hugely increase electricity needs and strain electric grids if new power plants aren't built and infrastructure improvements aren't made.

While the harnessing of renewable energy mainly solar and wind is on the rise in New Jersey, these forms of energy generation still only account for less than 3 percent of New Jersey's electricity supply. And they're not steady sources of power because the sun doesn't shine and the wind doesn't blow every day.

In a state where industry and a glut of cars already contribute to poor air quality in many areas, what New Jersey least needs is a bevy of new coal-fired power plants pumping carbon emissions into the air.

To meet New Jersey's expanding electricity needs, the continued expansion of wind and solar power generation and a new reactor at Salem a decade from now — neither of which would produce any carbon emissions to pollute the air — make sense.

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Bitcoin mining uses so much electricity that 1 city could curtail facility's power during heat waves

Medicine Hat Bitcoin Mining Facility drives massive electricity demand and energy use, leveraging natural gas and nearby wind power; Hut 8 touts economic growth, while critics cite carbon emissions, renewables integration, and climate impact.

 

Key Points

A Hut 8 project in Alberta that mines bitcoin at scale, consuming up to 60 MW and impacting energy and emissions.

✅ Consumes more than 60 MW, rivaling citywide electricity use

✅ Sited by natural gas plant; wind turbines nearby

✅ Economic gains vs. carbon emissions and climate risks

 

On the day of the grand opening of the largest bitcoin mining project in the country, the weather was partly cloudy and 15 C. On a Friday afternoon like this one, the new facility uses as much electricity as all of Medicine Hat, Alta., a city of more than 60,000 people and home to several large industrial plants.

The vast amount of electricity needed for bitcoin mining is why the city of Medicine Hat has championed the economic benefits of the project, while environmentalists say they are wary of the significant energy use.

Toronto-based Hut 8 has spent more than $100 million to develop the 4½-hectare site on the northern edge of the city. It has 56 shipping containers, each filled with 180 computer servers that digitally mine for bitcoin around the clock.

The company said it has already mined more than 3,300 bitcoins in Alberta, including at its much smaller site in Drumheller. On average, the Medicine Hat facility mines about 20 bitcoins per day. The value of bitcoin can fluctuate daily, but has sold recently for around $9,000.

The bitcoin mining facility is located right beside the city of Medicine Hat's new natural gas-fired power plant and four wind turbines are a short distance away. The bitcoin plant can consume more than 60 megawatts of power, more than 10 times more electricity used by any other facility in the city, according to the mayor.

That's why, in the event of a summer heat wave, the city has provisions in place to pull the plug on the electricity it provides to Hut 8, mirroring utility pauses on crypto loads seen elsewhere, so there won't be any blackouts for residents, according to the mayor.

Still, some say the bitcoin mining industry wastes far too much energy

"It's a huge magnitude when you talk about the carbon emissions," said Saeed Kaddoura, an analyst with the Pembina Institute, an environmental think-tank. "Moving forward, there needs to be some consideration on what the environmental impact of this is."

Medicine Hat owns its own natural gas and electricity generation and distribution businesses. The city leases the land to Hut 8 and the facility employs 40 full-time workers. Add up the economic benefits and the city of Medicine Hat will receive a significant financial boost from the new project, says Ted Clugston, the city's mayor.

Financial details of the city's deal with Hut 8 are not disclosed.

For more than a century, the city has attracted business by offering low-cost energy, and the mayor said this project is no different.

"They could have gone anywhere in the world and they chose Medicine Hat," said Clugston. "[Hut 8] is not here for renewable energy because it is not reliable. They need gas-fired generation and we have it in spades."

Environmental groups are concerned by the sheer amount of energy consumed by bitcoin mining, with some utilities warning they can't serve new energy-intensive customers right now, especially in places like Medicine Hat where most of the electricity is produced by fossil fuels.

The bitcoin system is designed, so only a limited number of the cryptocurrency can be mined everyday. Over time, as more miners compete for a decreasing number of available bitcoins, facilities will have to use more electricity compared to the amount of the cryptocurrency they collect.

"The way the bitcoin algorithm works is that it's designed to waste as much electricity as possible. And the more popular bitcoin becomes, the more electricity it wastes," said Keith Stewart, a spokesperson for Greenpeace.

Stewart questions whether natural gas should be used to produce a digital product.

"If you live in Alberta, you want to have heat and light, those types of things. I don't think bitcoin is a necessity of life for anyone," he said.

The CEO of Hut 8 completely disagrees, arguing the cryptocurrency is essential.  

"Bitcoin was created during the financial crisis. It has really served a purpose in terms of providing the opportunity for people who don't necessarily trust their government or their central banks," said Andrew Kiguel.

 

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Alberta's Last Coal Plant Closes, Embracing Clean Energy

Alberta Coal Phase-Out signals a clean energy transition, replacing coal with natural gas and renewables, cutting greenhouse gas emissions, leveraging a carbon levy, and supporting workers in Alberta's evolving electricity market.

 

Key Points

Alberta Coal Phase-Out moves power from coal to lower-emission natural gas and renewables to reduce grid emissions.

✅ Last coal plant closed: Genesee Generating Station, Sept 30, 2023

✅ Shift to natural gas and renewables lowers emissions

✅ Carbon levy and incentives accelerated clean power build-out

 

The closure of the Genesee Generating Station on September 30, 2023, marked a significant milestone in Alberta's energy history, as the province moved to retire coal power by 2023 ahead of its 2030 provincial deadline. The Genesee, located near Calgary, was the province's last remaining coal-fired power plant. Its closure represents the culmination of a multi-year effort to transition Alberta's electricity sector away from coal and towards cleaner sources of energy.

For decades, coal was the backbone of Alberta's electricity grid. Coal-fired plants were reliable and relatively inexpensive to operate. However, coal also has a significant environmental impact. The burning of coal releases greenhouse gases, including carbon dioxide, a major contributor to climate change. Coal plants also produce air pollutants such as sulfur dioxide and nitrogen oxide, which can cause respiratory problems and acid rain, and in some regions electricity is projected to get dirtier as gas use expands.

In recognition of these environmental concerns, the Alberta government began to develop plans to phase out coal-fired power generation in the early 2000s. The government implemented a number of policies to encourage the shift from coal to cleaner energy such as natural gas and renewable energy. These policies included providing financial incentives for the construction of new natural gas plants and renewable energy facilities, as well as imposing a carbon levy on coal-fired generation.

The phase-out of coal was also driven by economic factors. The cost of natural gas has declined significantly in recent years, making it a more competitive fuel source for electricity generation as producers switch to gas under evolving market conditions. Additionally, the Alberta government faced increasing pressure from the federal government to reduce greenhouse gas emissions.

The transition away from coal has not been without its challenges. Coal mining and coal-fired power generation have long been important parts of Alberta's economy. The closure of coal plants has resulted in job losses in the affected communities. The government has implemented programs to help workers transition to new jobs in the clean energy sector.

Despite these challenges, the closure of the Genesee Generating Station is a positive development for Alberta's environment and climate. Coal-fired power generation is one of the largest sources of greenhouse gas emissions in Alberta, and recent wind generation outpacing coal underscores the sector's transformation. The closure of the Genesee is expected to result in a significant reduction in emissions, helping Alberta to meet its climate change targets.

The transition away from coal also presents opportunities for Alberta. The province has vast natural gas resources, which can be used to generate electricity with lower emissions than coal. Alberta is also well-positioned to develop renewable energy sources, such as wind power and solar power. These renewable energy sources can help to further reduce emissions and create new jobs in the clean energy sector.

The closure of the Genesee Generating Station is a significant milestone in Alberta's energy history. It represents the end of an era for coal-fired power generation in the province, a shift mirrored by the UK's last coal station going offline earlier this year. However, it also marks the beginning of a new era for Alberta's energy sector. By transitioning to cleaner sources of energy, Alberta can reduce its environmental impact and create a more sustainable energy future.

 

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Electricity complaints filed by Texans reach three-year high, report says

Texas Electricity Complaints surged to a three-year high, highlighting Public Utility Commission data on billing disputes, meter problems, and service issues in the competitive retail electricity market and consumer protection process.

 

Key Points

Consumer filings to Texas PUC about billing, service, and meters, with 2018 reaching a three-year high.

✅ 5,371 complaints/inquiries in FY2018; 43.8% involved billing disputes.

✅ Service issues 15.8% and meters 12.6%; PUC publishes complaint stats.

✅ Advocates urge monitoring to keep deregulated retail market healthy.

 

The number of electricity service-related complaints and inquiries filed with the state’s Public Utility Commission reached a three-year high this past fiscal year, an advocacy group said Tuesday.

According to the Texas Coalition for Affordable Power, a nonprofit that advocates for low electricity prices, Texans filed 5,371 complaints or inquiries with the commission between September 2017 and August of this year. That’s up from the 4,175 complaints or inquiries filed during the same period in 2017 and the 4,835 filed in 2016. The complaints and inquiries included concerns with billing, meters and service.

“This stark uptick in complaints is disappointing — especially after several years of generally improving numbers,” Jay Doegey, the coalition's executive director, said in a written statement. “In percentage terms, the year-to-year rise in complaints is the greatest in a decade. Clearly, many Texans remain frustrated with aspects of their electric service.”

The utility commission did not immediately respond to a request for comment.

While complaints and inquiries increased in 2018, the number of complaints and inquiries has generally decreased since 2009, when Texans filed 15,956 with the commission. That could be because there have been lower residential electricity prices and because Texans have become more familiar with the state’s competitive retail electricity system over the last decade, the coalition's report said.

And complaints from 2018 are well below 2003 levels, when the number of complaints and inquiries soared to more than 17,000, a year after Texas deregulated most of its electricity market structure at the time.

But Jake Dyer, a policy analyst at the coalition, said his group is closely watching the uptick in complaints this year as the Texas power grid faces recurring strains.

“We are invested in making sure the competition works,” Dyer said. “When you see an uptick like this, you should watch very closely to make sure the market remains healthy and to make sure there is not something else going on.”

However, Dyer said that it is too early to know what that something else that is going on might be.

According to the report, concerns about billing made up most of the complaints and inquiries filed this year at 43.8 percent. That’s up from 42.5 percent in fiscal year 2017. Concerns about the provision of electrical service and about electrical meters also ranked high, constituting 15.8 percent and 12.6 percent of the complaints and inquiries, respectively.

The Public Utility Commission publishes customer complaint statistics on its website. The Texas Coalition for Affordable Power takes into account both complaints and inquiries filed with the commission for its report in order “to gauge general consumer sentiment and to maintain a uniform methodology across the study period.”

Texans can file an official complaint with the the commission's Customer Protection Division. Under the complaint process, the complaint is sent to the electric company, which has 21 days to respond.

Some providers outside the competitive market, such as electric cooperatives, drew praise for performance during the 2021 winter storm.

Following the 2021 winter storm, Texas lawmakers proposed an electricity market bailout to stabilize costs and reliability.

 

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EV Fires Raise Health Concerns for Firefighters

EV Firefighter Cancer Risks: lithium-ion battery fires, toxic metals like nickel and chromium, hazardous smoke plumes, and prolonged exposure threaten first responders; SCBA use, decontamination, and evidence-based protocols help reduce occupational health impacts.

 

Key Points

Health hazards from EV battery fires exposing responders to toxic metals and smoke, elevating long-term cancer risk.

✅ Nickel and chromium in EV smoke linked to lung and sinus cancers

✅ Use SCBA, on-scene decon, and post-incident cleaning to cut exposure

✅ Adopt EV fire SOPs: cooling, monitoring, isolation, air monitoring

 

As electric vehicles (EVs) become more popular, the EV fire risks to firefighters are becoming an increasing concern. These fires, fueled by the high-capacity lithium-ion batteries in EVs, produce dangerous chemical exposures that could have serious long-term health implications for first responders.

Claudine Buzzo, a firefighter and cancer survivor, knows firsthand the dangers that come with the profession. She’s faced personal health battles, including rare pancreatic cancer and breast cancer, both of which she attributes to the hazards of firefighting. Now, as EV adoption increases and some research links adoption to fewer asthma-related ER visits in local communities, Buzzo and her colleagues are concerned about how EV fires might add to their already heavy exposure to harmful chemicals.

The fire risks associated with EVs are different from those of traditional gasoline-powered vehicles. Dr. Alberto Caban-Martinez, who is leading a study at the Sylvester Comprehensive Cancer Center, explains that the high concentrations of metals released in the smoke from an EV fire are linked to various cancers. For instance, nickel, a key component in EV batteries, is associated with lung, nasal, and laryngeal cancers, while chromium, another metal found in some EV batteries, is linked to lung and sinus cancers.

Research from the Firefighter Cancer Initiative indicates that the plume of smoke from an EV fire contains significantly higher concentrations of these metals than fires from traditional vehicles. This raises the risk of long-term health problems for firefighters who respond to such incidents.

While the Electric Vehicle Association acknowledges the risks associated with various types of vehicle fires, they maintain that the lithium-ion batteries in EVs may not present a significantly higher risk than other common fire hazards, even as broader assessments suggest EVs are not a silver bullet for climate goals. Nonetheless, the growing body of research is causing concern among health experts, urging for further studies into how these new types of fires could affect firefighter health and how upstream electricity generation, where 18% of electricity in 2019 came from fossil fuels in Canada, factors into overall risk perceptions.

Fire departments and health researchers are working to understand the full scope of these risks and are emphasizing the importance of protective gear, such as self-contained breathing apparatuses, to minimize exposure during EV fire responses, while also considering questions like grid impacts during charging operations and EV sustainability improvements in different regions.

 

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ERCOT Issues RFP to Procure Capacity to Alleviate Winter Concerns

ERCOT Winter Capacity RFP seeks up to 3,000 MW through generation and demand response to bolster Texas grid reliability during peak load, leveraging Reliability Must-Run, incentive factors, and EEA risk mitigation for the 2023-24 season.

 

Key Points

An ERCOT initiative to procure 3,000 MW of generation and demand response to reduce EEA risk and improve reliability.

✅ Targets 3,000 MW from generation and demand response

✅ Uses RMR-style contracts with flexible incentive factors

✅ Aims to lower EEA probability below 10% this winter

 

The Electric Reliability Council of Texas (ERCOT) issued a request for proposals to stakeholders to procure up to 3,000 MW of generation or demand response capacity to meet load and reserve requirements during the winter 2023-24 peak load season (Dec. 1, 2023, through Feb. 29, 2024), amid ongoing Texas power grid challenges across the region.

ERCOT cited “several factors, including significant peak load growth since last winter, recent and proposed retirements of dispatchable Generation Resources, and recent extreme winter weather events, including Winter Storm Elliott in December 2022, Winter Storm Uri in February 2021, and the 2018 and 2011 winter storms, each of which resulted in abnormally high demand during winter weather.” It now seeks additional capacity under its “authority to prevent an anticipated Emergency Condition,” reflecting nationwide blackout risks identified by grid experts.

In its notice regarding the RFP, ERCOT identified a number of mothballed and recently decommissioned generation resources that may be eligible to offer capacity under the RFP. It further stated that offers must comport with the format of its “Reliability Must-Run” agreement but could include a proposed “Incentive Factor” that reflects the revenues the unit owners determine would be necessary to bring the unit back to operation. It added that the Incentive Factor is not necessarily limited to 10%. Providers of eligible demand response can submit offers based on similar principles that are not necessarily constrained by cost. The notice identifies potential acceptable sources of demand response, describes certain parameters for the kinds of demand response that are permitted to respond to the RFP, and outlines the time periods during which ERCOT must be able to deploy the demand response resources to improve electricity reliability across the system.

To meet the Dec. 1, 2023, service start date, ERCOT developed an aggressive timeline to solicit and evaluate proposals through the RFP. Responses to the RFP are due Nov. 6, 2023. ERCOT’s schedule provides that it will notify market participants that obtain awards on Nov. 23, 2023. Expect contracts to be executed by Nov. 30, 2023.

Unlike Regional Transmission Organizations in the Northeastern United States, ERCOT does not have a capacity market. Instead, ERCOT relies on a high price cap of $5,000 per MWh for its energy market (decreased from the $9,000 per MWh cap in effect during Winter Storm Uri) and an Operating Reserve Demand Curve adder that pays additional funds to generators supplying power and ancillary services, an area recently scrutinized for improper payments when supply conditions are tight. In the wake of Winter Storm Uri, some calls were made to have ERCOT adopt a capacity market for reliability reasons, and a number of legal battles continue to play out in the wake of Winter Storm Uri. (See recent McGuireWoods legal alert “Winter Storm Uri Power Dispute Reaches the Supreme Court of Texas.”) Though a capacity market was not adopted, the Texas Legislature approved a $7.2 billion loan program, widely described as an electricity market bailout for generators, to build up to 10,000 MW of dispatchable generation. The legislature also approved a version of the Public Utility Commission of Texas’ proposal to establish a “Performance Credit Mechanism,” but with a cost cap of $1 billion.

The loss of life and economic impacts of Winter Storm Uri in 2021, along with the energy crunches and calls for conservation this past summer, are driving changes to ERCOT’s “energy-only” market, including electricity market reforms under consideration. Texas policymakers are providing multiple financial incentives to promote investment in dispatchable on-demand generation, and voters will consider funding to modernize generation measures this year to make the Texas grid more reliable and able to deal with power demand from a growing economy and increased demand for electricity driven by weather. In the meantime, ERCOT’s plan to procure 3,000 MW through this RFP process is a stopgap measure intended to bolster reliability for the upcoming winter season and lower the probability of load shed in the event of severe winter weather.

 

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Cyprus can’t delay joining the electricity highway

Cyprus Electricity Interconnectors link the island to the EU grid via EuroAsia and EuroAfrica projects, enabling renewable energy trade, subsea transmission, market liberalization, and stronger energy security and diplomacy across the region.

 

Key Points

Subsea links connecting Cyprus to Greece, Israel and Egypt for EU grid integration, renewable trade and energy security.

✅ Connects EU, Israel, Egypt via EuroAsia and EuroAfrica

✅ Enables renewables integration and market liberalization

✅ Strengthens energy security, investment, and diplomacy

 

Electricity interconnectors bridging Cyprus with the broader geographical region, mirroring projects like the Ireland-France grid link already underway in Europe, are crucial for its diplomacy while improving its game to become a clean energy hub.

In an interview with Phileleftheros daily, Andreas Poullikkas, chairman of the Cyprus Energy Regulatory Authority (CERA), said electricity cables such as the EuroAsia Interconnector and the EuroAfrica Interconnector, could turn the island into an energy hub, creating investment opportunities.

“Cyprus, with proper planning, can make the most of its energy potential, turning Cyprus into an electricity producer-state and hub by establishing electrical interconnections, such as the EuroAsia Interconnector and the EuroAfrica Interconnector,” said Poullikkas.

He said these electricity interconnectors, “will enable the island to become a hub for electricity transmission between the European Union, Israel and Egypt, with developments such as the Israel Electric Corporation settlement highlighting regional dynamics, while increasing our energy security”.

Poullikkas argued it will have beneficial consequences in shaping healthy conditions for liberalising the country’s electricity market and economy, facilitating the production of electricity with Renewable Energy Sources and supporting broader efforts like the UK grid transformation toward net zero.

“Electricity interconnections are an excellent opportunity for greater business flexibility in Cyprus, ushering new investment opportunities, as seen with the Lake Erie Connector investment across North America, either in electricity generation or other sectors. Especially at a time when any investment or financial opportunity is welcomed.”

He said Cyprus’ energy resources are a combination of hydrocarbon deposits and renewable energy sources, such as solar.

This combination offers the country a comparative advantage in the energy sector.

Cyprus can take advantage of the development of alternative supply routes of the EU, as more links such as new UK interconnectors come online.

Poullikkas argued that as energy networks are developing rapidly throughout the bloc, serving the ever-increasing needs for electricity, and aligning with the global energy interconnection vision highlighted in recent assessments, the need to connect Cyprus with its wider geographical area is a matter of urgency.

He argues the development of important energy infrastructure, especially electricity interconnections, is an important catalyst in the implementation of Cyprus goals, while recognising how rule changes like Australia's big battery market shift can affect storage strategies.

“It should also be a national political priority, as this will help strengthen diplomatic relations,” added Poullikkas.

Implementing the electricity interconnectors between Israel, Cyprus and Greece through Crete and Attica (EuroAsia Interconnector) has been delayed by two years.

He said the delay was brought about after Greece decided to separate the Crete-Attica section of the interconnection and treat as a national project.

Poullikkas stressed the Greek authorities are committed to ensuring the connection of Cyprus with the electricity market of the EU.

“All the required permits have been obtained from the competent authorities in Cyprus and upon the completion of the procedures with the preferred manufacturers, construction of the Cyprus-Crete electrical interconnection will begin before the end of this year. Based on current data, the entire interconnection is expected to be implemented in 2023”.

“The EuroAfrica Interconnector is in the pre-works stage, all project implementation studies have already been completed and submitted to the competent authorities, including cost and benefit studies”.

EuroAsia Interconnector is a leading EU project of common interest (PCI), also labelled as an “electricity highway” by the European Commission.

It connects the national grids of Israel, Cyprus and Greece, creating a reliable energy bridge between the continents of Asia and Europe allowing bi-directional transmission of electricity.

The cost of the entire subsea cable system, at 1,208km, the longest in the world and the deepest at 3,000m below sea level, is estimated at €2.5 bln.

Construction costs for the first phase of the Egypt-Cyprus interconnection (EuroAfrica) with a Stage 1 transmission capacity of 1,000MW is estimated at €1bln.

The Cyprus-Greece (Crete) interconnection, as well as the Egypt-Cyprus electricity interconnector, will both be commissioned by December 2023.

 

 

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