Officials mull alternative-energy regulations

Inventoried Energy Program pays ISO-NE generators for fuel security to boost winter reliability, with FERC approval, covering fossil, nuclear, hydropower, and batteries, complementing capacity markets to enhance grid resilience during severe cold snaps.

Key Points

ISO-NE program paying generators to hold fuel or energy reserves for emergencies, boosting winter reliability.

✅ FERC-approved stopgap for 2023 and 2024 winter seasons

✅ Pays for on-site fuel or stored energy during cold-trigger events

✅ Open to fossil, nuclear, hydro, batteries; limited gas participation

Electricity ratepayers in New England will pay tens of millions of dollars to fossil fuel and nuclear power plants later this decade under a program that proponents say is needed to keep the lights on during severe winters but which critics call a subsidy with little benefit to consumers or the grid, even as Connecticut is pushing a market overhaul across the region.

Last week the Federal Energy Regulatory Commission said ISO-New England, which runs the six-state power grid, can create what it calls the Inventoried Energy Program or IEP. This basically will pay certain power plants to stockpile of fuel for use in emergencies during two upcoming winters as longer-term solutions are developed.

The federal commission called it a reasonable short-term solution to avoid brownouts which doesn’t favor any given technology.

Not all agree, however, including FERC Commissioner Richard Glick, who wrote a fiery dissent to the other three commissioners.

“The program will hand out tens of millions of dollars to nuclear, coal and hydropower generators without any indication that those payments will cause the slightest change in those generators’ behavior,” Glick wrote. “Handing out money for nothing is a windfall, not a just and reasonable rate.”

The program is the latest reaction by ISO-NE to the winter of 2013-14 when New England almost saw brownouts because of a shortage of natural gas to create electricity during a pair of week-long deep freezes.

ISO-New England says the situation is more critical now because of the possible retirement of the gas-fired Mystic Generating Station in Massachusetts. As with closed nuclear plants such as Vermont Yankee and Pilgrim in Massachusetts, power plant owners say lower electricity prices, partly due to cheap renewables and partly to stagnant demand, means they can’t be profitable just by selling power.

Programs like the IEP are meant to subsidize such plants – “incentivize” is the industry term – even though some argue there is no need to subsidize nuclear in deregulated markets so they’ll stay open if they are needed.

The IEP approved last week will be applied to the winters of 2023 and 2024, after a different subsidy program expires. It sets prices, despite warnings about rushing pricing changes from industry groups, for stocking certain amounts of fuel and payments during any “trigger” event, defined as a day when the average of high and low temperatures at Bradley International Airport in Connecticut is no more than 17 degrees Fahrenheit.

These payments will be made on top of a complex system of grid auctions used to decide how much various plants get paid for generating electricity at which times.

ISO-NE estimates the new program will cost between $102 million and $148 million each winter, depending on weather and market conditions.

It says the payments are open to plants that burn oil, coal, nuclear fuel, wood chips or trash; utility-scale battery storage facilities; and hydropower dams “that store water in a pond or reservoir.” Natural gas plants can participate if they guarantee to have fuel available, but that seems less likely because of winter heating contracts.

A major complaint and groups that filed petitions opposing the project is that ISO-NE presented little supporting evidence of how prices, amount and overall cost were determined. ISO-NE argued that there wasn’t time for such analysis before the Mystic shutdown, and FERC agreed.

“The proposal is a step in the right direction … while ISO-NE finishes developing a long-term market solution,” the commission said in its ruling.

The program is the latest example of complexities facing the nation’s electricity system evolves in the face of solar and wind power, which produce electricity so cheaply that they can render traditional power uneconomic but which can’t always produce power on demand, prompting discussions of Texas grid improvements among policymakers. Another major factor is climate change, which has increased the pressure to support renewable alternatives to plants that burn fossil fuels, as well as stagnant electricity demand caused by increased efficiency.

Opponents, including many environmental groups, say electricity utilities and regulators are too quick to prop up existing systems, as the 145-mile Maine transmission line debate shows, built when electricity was sent one way from a few big plants to many customers. They argue that to combat climate change as well as limit cost, the emphasis must be on developing “non-wire alternatives” such as smart systems for controlling demand, in order to take advantage of the current system in which electricity goes two ways, such as from rooftop solar back into the grid.

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Nuclear Energy Growth accelerates as nations pursue decarbonization, complement renewables, displace coal, and ensure grid reliability with firm, low-carbon baseload, benefiting from standardized builds, lower cost of capital, and learning-curve cost reductions.

Key Points

Expansion of nuclear capacity to cut CO2, complement renewables, replace coal, and stabilize grids at low-carbon cost.

✅ Complements renewables; displaces coal for faster decarbonization

✅ Cuts system costs via standardization and lower cost of capital

✅ Provides firm, low-carbon baseload and grid reliability

By Kirill Komarov, Chairman, World Nuclear Association.

As Europe and the wider world begins to wake up to the need to cut emissions, Dr Kirill Komarov argues that tackling climate change will see the use of nuclear energy grow in the coming years, not as a competitor to renewables but as a competitor to coal.

The nuclear industry keeps making headlines and spurring debates on energy policy, including the green industrial revolution agenda in several countries. With each new build project, the detractors of nuclear power crowd the bandwagon to portray renewables as an easy and cheap alternative to ‘increasingly costly’ nuclear: if solar and wind are virtually free why bother splitting atoms?

Yet, paradoxically as it may seem, if we are serious about policy response to climate change, nuclear energy is seeing an atomic energy resurgence in the coming decade or two.

Growth has already started to pick up with about 3.1 GW new capacity added in the first half of 2018 in Russia and China while, at the very least, 4GW more to be completed by the end of the year – more than doubling the capacity additions in 2017.

In 2019 new connections to the grid would exceed 10GW by a significant margin.

If nuclear is in decline, why then do China, India, Russia and other countries keep building nuclear power plants?

To begin with, the issue of cost, argued by those opposed to nuclear, is in fact largely a bogus one, which does not make a fully rounded like for like comparison.

It is true that the latest generation reactors, especially those under construction in the US and Western Europe, have encountered significant construction delays and cost overruns.

But the main, and often the only, reason for that is the ‘first-of-a-kind’ nature of those projects.

If you build something for the first time, be it nuclear, wind or solar, it is expensive. Experience shows that with series build, standardised construction economies of scale and the learning curve from multiple projects, costs come down by around one-third; and this is exactly what is already happening in some parts of the world.

Furthermore, those first-of-a-kind projects were forced to be financed 100% privately and investors had to bear all political risks. It sent the cost of capital soaring, increasing at one stroke the final electricity price by about one third.

While, according to the International Energy Agency, at 3% cost of capital rate, nuclear is the cheapest source of energy: on average 1% increase adds about US$6-7 per MWh to the final price.

When it comes to solar and wind, the truth, inconvenient for those cherishing the fantasy of a world relying 100% on renewables, is that the ‘plummeting prices’ (which, by the way, haven’t changed much over the last three years, reaching a plateau) do not factor in so-called system and balancing costs associated with the need to smooth the intermittency of renewables.

Put simply, the fact the sun doesn’t shine at night and wind doesn’t blow all the time means wind and solar generation needs to be backed up.

According to a study by the Potsdam Institute for Climate Impact Research, integration of intermittent renewables into the grid is estimated in some cases to be as expensive as power generation itself.

Delivering the highest possible renewable content means customers’ bills will have to cover: renewable generation costs, energy storage solutions, major grid updates and interconnections investment, as well as gas or coal peaking power plants or ‘peakers’, which work only from time to time when needed to back up wind and solar.

The expected cost for kWh for peakers, according to investment bank Lazard is about twice that of conventional power plants due to much lower capacity factors.

Despite exceptionally low fossil fuel prices, peaking natural gas generation had an eye-watering cost of $156-210 per MWh in 2017 while electricity storage, replacing ‘peakers’, would imply an extra cost of $186-413 per MWh.

Burning fossil fuels is cheaper but comes with a great deal of environmental concern and extensive use of coal would make net-zero emissions targets all but unattainable.

So, contrary to some claims, nuclear does not compete with renewables. Moreover, a recent study by the MIT Energy Initiative showed, most convincingly, that renewables and load following advanced nuclear are complementary.

Nuclear competes with coal. Phasing out coal is crucial to fighting climate change. Putting off decisions to build new nuclear capacities while increasing the share of intermittent renewables makes coal indispensable and extends its life.

Scientists at the Brattle group, a consultancy, argue that “since CO2 emissions persist for many years in the atmosphere, near-term emission reductions are more helpful for climate protection than later ones”.

The longer we hesitate with new nuclear build the more difficult it becomes to save the Earth.

Nuclear power accounta for about one-tenth of global electricity production, but as much as one-third of generation from low-carbon sources. 1GWe of installed nuclear capacity prevents emissions of 4-7 million metric tons of CO2 emissions per year, depending on the region.

The International Energy Agency (IEA) estimates that in order to limit the average global temperature increase to 2°C and still meet global power demand, we need to connect to the grid at least 20GW of new nuclear energy each year.

The World Nuclear Association (WNA) sets the target even higher with the total of 1,000 GWe by 2050, or about 10 GWe per year before 2020; 25 GWe per year from 2021 to 2025; and on average 33 GWe from 2026 to 2050.

Regulatory and political challenges in the West have made life for nuclear businesses in the US and in Europe's nuclear sector very difficult, driving many of them to the edge of insolvency; but in the rest of the world nuclear energy is thriving.

Nuclear vendors and utilities post healthy profits and invest heavily in next-gen nuclear innovation and expansion. The BRICS countries are leading the way, taking over the initiative in the global climate agenda. From their perspective, it’s the opposite of decline.

Dr Kirill Komarov is first deputy CEO of Russian state nuclear energy operator Rosatom and chairman of the World Nuclear Association.

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Zaporizhzhia Nuclear Plant Mines reported by IAEA at the Russian-occupied site: anti-personnel devices in a buffer zone, restricted areas; access limits to reactor rooftops and turbine halls heighten nuclear safety and security concerns in Ukraine.

Key Points

IAEA reports anti-personnel mines at Russian-held Zaporizhzhia, raising nuclear safety risks in buffer zones.

✅ IAEA observes mines in buffer zone at occupied site

✅ Restricted areas; no roof or turbine hall access granted

✅ Safety systems unaffected, but staff under pressure

The United Nations atomic watchdog said it saw anti-personnel mines at the site of Ukraine's Zaporizhzhia nuclear power plant which is occupied by Russian forces.

Europe's largest nuclear facility fell to Russian forces shortly after the invasion of Ukraine in February last year, as Moscow later sought to build power lines to reactivate it amid ongoing control of the area. Kyiv and Moscow have since accused each other of planning an incident at the site.

On July 23 International Atomic Energy Agency (IAEA) experts "saw some mines located in a buffer zone between the site's internal and external perimeter barriers," agency chief Rafael Grossi said in a statement on Monday.

The statement did not say how many mines the team had seen.

The devices were in "restricted areas" that operating plant personnel cannot access, Mr Grossi said, adding the IAEA's initial assessment was that any detonation "should not affect the site's nuclear safety and security systems".

Laying explosives at the site was "inconsistent with the IAEA safety standards and nuclear security guidance" and, amid controversial proposals on Ukraine's nuclear plants that have circulated internationally, created additional psychological pressure on staff, he added.

Ukrainians in Nikopol are out of water and within Russia's firing line. But Zaporizhzhia nuclear power plant could pose the biggest threat, even as Ukraine has resumed electricity exports to regional grids.

Last week the IAEA said its experts had carried out inspections at the plant, without "observing" the presence of any mines, although they had not been given access to the rooftops of the reactor buildings, while a possible agreement to curb attacks on plants was being discussed.

The IAEA had still not been given access to the roofs of the reactor buildings and their turbine halls, its latest statement said, even as a proposal to control Ukraine's nuclear plants drew scrutiny.

After falling into Russian hands, Europe's biggest power plant was targeted by gunfire and has been severed from the grid several times, raising nuclear risk warnings from the IAEA and others.

The six reactor units, which before the war produced around a fifth of Ukraine's electricity, have been shut down for months, prompting interest in wind power development as a harder-to-disrupt source.

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B.C. LNG Electrification embeds clean hydro and wind power into low-emission liquefied natural gas, cutting carbon intensity, enabling coal displacement in Asia, and opening grid-scale demand for independent power producers and ITMO-based climate accounting.

Key Points

Powering LNG with clean electricity cuts carbon intensity, displaces coal, and grows demand for B.C.'s clean power.

✅ Electric-drive LNG cuts emissions intensity by up to 80%.

✅ Creates major grid load, boosting B.C. independent power producers.

✅ Enables ITMO crediting when coal displacement is verified.

B.C. has abundant clean power – if only there was a way to ship those electrons across the sea to help coal-dependent countries reduce their emissions, and even regionally, Alberta–B.C. grid link benefits could help move surplus power domestically.

Natural gas that is liquefied using clean hydro and wind power and then exported would be, in a sense, a way of embedding B.C.’s low emission electricity in another form of energy, and, alongside the Canada–Germany clean energy pact, part of a broader export strategy.

Given the increased demand that could come from an LNG industry – especially one that moves towards greater electrification and, as the IEA net-zero electricity report notes, broader system demand – poses some potentially big opportunities for B.C.’s clean energy independent power sector, as those attending the Clean Energy Association of BC's annual at the Generate conference heard recently.

At a session on LNG electrification, delegates were told that LNG produced in B.C. with electricity could have some significant environmental benefits.

Given how much power an LNG plant that uses electric drive consumes, an electrified LNG industry could also pose some significant opportunities for independent power producers – a sector that had the wind taken out of its sails with the sanctioning of the Site C dam project.

Only one LNG plant being built in B.C. – Woodfibre LNG – will use electric drive to produce LNG, although the companies behind Kitimat LNG have changed their original design plans, and now plan to use electric drive drive as well.

Even small LNG plants that use electric drive require a lot of power.

“We’re talking about a lot of power, since it’s one of the biggest consumers you can connect to a grid,” said Sven Demmig, head of project development for Siemens.

Most LNG plants still burn natural gas to drive the liquefaction process – a choice that intersects with climate policy and electricity grids in Canada. They typically generate 0.35 tonnes of CO2e per tonne of LNG produced.

Because it will use electric drive, LNG produced by Woodfibre LNG will have an emissions intensity that is 80% less than LNG produced in the Gulf of Mexico, said Woodfibre president David Keane.

In B.C., the benchmark for GHG intensities for LNG plants has been set at 0.16 tonnes of CO2e per tonne of LNG. Above that, LNG producers would need to pay higher carbon taxes than those that are below the benchmark.

The LNG Canada plant has an intensity of 0.15 tonnes og CO2e per tonne of LNG. Woodfibre LNG will have an emissions intensity of just 0.059, thanks to electric drive.

“So we will be significantly less than any operating facility in the world,” Keane said.

Keane said Sinopec has recently estimated that it expects China’s demand for natural gas to grow by 82% by 2030.

“So China will, in fact, get its gas supply,” Keane said. “The question is: where will that supply come from?

“For every tonne of LNG that’s being produced today in the United States -- and tonne of LNG that we’re not producing in Canada -- we’re seeing about 10 million tonnes of carbon leakage every single year.”

The first Canadian company to produce LNG that ended up in China is FortisBC. Small independent operators have been buying LNG from FortisBC’s Tilbury Island plant and shipping to China in ISO containers on container ships.

David Bennett, director of communications for FortisBC, said those shipments are traced to industries in China that are, indeed, using LNG instead of coal power now.

“We know where those shipping containers are going,” he said. “They’re actually going to displace coal in factories in China.”

Verifying what the LNG is used for is important, if Canadian producers want to claim any kind of climate credit. LNG shipped to Japan or South Korea to displace nuclear power, for example, would actually result in a net increase in GHGs. But used to displace coal, the emissions reductions can be significant, since natural gas produces about half the CO2 that coal does.

The problem for LNG producers here is B.C.’s emissions reduction targets as they stand today. Even LNG produced with electricity will produce some GHGs. The fact that LNG that could dramatically reduce GHGs in other countries, if it displaces coal power, does not count in B.C.’s carbon accounting.

Under the Paris Agreement, countries agree to set their own reduction targets, and, for Canada, cleaning up Canada’s electricity remains critical to meeting climate pledges, but don’t typically get to claim any reductions that might result outside their own country.

Canada is exploring the use of Internationally Transferred Mitigation Outcomes (ITMO) under the Under the Paris Agreement to allow Canada to claim some of the GHG reductions that result in other countries, like China, through the export of Canadian LNG.

“For example, if I were producing 4 million tonnes of greenhouse gas emissions in B.C. and I was selling 100% of my LNG to China, and I can verify that they’re replacing coal…they would have a reduction of about 60 or million tonnes of greenhouse gas emissions,” Keane said.

“So if they’re buying 4 million tonnes of emissions from us, under these ITMOs, then they have net reduction of 56 million tonnes, we’d have a net increase of zero.”

But even if China and Canada agreed to such a trading arrangement, the United Nations still hasn’t decided just how the rules around ITMOs will work.

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Venezuela Power Outage cripples the national grid after a massive blackout; alleged cyber attacks at Guri Dam and Caracas, damaged transmission lines, CORPOELEC restoration, looting, water shortages, and sanctions pressure compound recovery.

Key Points

A March 2019 blackout crippling Venezuela's grid amid alleged cyber attacks, equipment failures, and slow restoration.

✅ Power restored partially after 96 hours across all states

✅ Alleged cyber attacks at Guri Dam and Caracas systems

✅ CORPOELEC urges reduced load during grid stabilization

Venezuelan authorities continue working to bring back online the electric grid following a massive outage that started on Thursday, March 7.

According to on-the-ground testimonies and official sources, power finally began to reach Venezuela’s western states, including Merida and Zulia, on Monday night, around 96 hours after the blackout started. Electricity has now been restored at least in some areas of every state, with authorities urging citizens, as seen in Ukraine's efforts to keep lights on during crisis, to avoid using heavy usage devices while efforts to restore the whole grid continue.

President Nicolas Maduro gave a televised address on Tuesday evening, offering more details about the alleged attack against the country’s electrical infrastructure. According to Maduro, both the computerized system in the Guri Dam, on Thursday afternoon, and the central electrical “brain” in Caracas, on Saturday morning, suffered cyber attacks, while recovery was delayed by physical attacks against transmission lines and electrical substations, a pattern seen in power outages in western Ukraine as well.

“The recovery has been a miracle by CORPOELEC (electricity) workers” he said, vowing that a “battle” had been won.

Maduro claimed that the attacks were directed from Chicago and Houston and that more evidence would be presented soon. The Venezuelan president had announced on Monday that two arrests were made in connection to alleged acts of sabotage against the communications system in the Guri Dam.

Venezuela’s electrical grid has suffered from poor maintenance and sabotage in recent years, with infrastructure strained by under-investment and Washington’s economic sanctions further compounding difficulties, with parallels to electricity inequality in California highlighting broader systemic challenges, though causes differ.

The extended power outage saw episodes of lootings take place, especially in the Zulia capital of Maracaibo. Food warehouses, supermarkets and a shopping mall were targeted according to reports and footage on social media.

Isolated episodes of protests and lootings were also reported in other cities, including some sectors of Caracas. A video spread on social media appeared to show a violent confrontation in the eastern city of Maturin in which a National Guardsman was shot dead.

While electricity has been gradually restored, public transportation and other services have yet to be reactivated, a contrast with U.S. grid resilience during COVID-19 where power systems remained stable, with the government suspending work and school activities until Wednesday.

In Caracas, attention has now turned to water. Shortages started to be felt after the water pumping system in the nearby Tuy valley was shut down amid the electricity blackout, underscoring that electricity is civilization in conflict zones, as interdependent systems cascade. Authorities announced on Tuesday afternoon that the system was due to resume supplying water to the capital metropolitan region.

Some communities protested the lack of water on Monday and long queues formed at water distribution points, with local authorities looking to send water tanks to supply communities and guarantee the normal functioning of hospitals.

The Venezuelan government has yet to release any information concerning casualties in hospitals, with NGO Doctors for Health reporting 24 dead as of Monday night following alleged contact with multiple hospitals. Higher figures, including claims of 80 newborns dead in Maracaibo, have been denied by local sources.

Self-proclaimed “Interim President” Juan Guaido has blamed the electricity crisis on government mismanagement and corruption, dismissing the government’s cyber attack thesis on the grounds that the system is analog, and attributing the national outage to a lack of qualified personnel needed to reactivate the grid. However, these claims have been called into question by people with knowledge of the system.

Guaido called for street protests on Tuesday afternoon which saw small groups momentarily take to streets in Caracas and other cities, or banging pots and pans from windows.

The opposition-controlled National Assembly, which has been in contempt of court since 2016, approved a decree on Monday declaring a state of “national alarm,” blaming the government for the current crisis and issuing instructions for public officials and security forces.

Likewise on Tuesday, Venezuelan Attorney General Tarek William Saab announced that an investigation was being opened against Guaido regarding his alleged responsibility for the recent power outage. Saab explained that this investigation would add to the previous one, opened on January 29, as well as determine responsibilities in instigating violence.

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Offshore Wind Cost Competitiveness is rising as larger turbines boost megawatt output, cut LCOE, and trim maintenance and installation time, enabling projects in New England to rival natural gas pricing while scaling reliably.

Key Points

It describes how larger offshore turbines lower LCOE and O&M, making U.S. projects price competitive with natural gas.

✅ Larger turbines boost MW output and reduce LCOE.

✅ Lower O&M and faster installation cut lifecycle costs.

✅ Competes with gas in New England bids, per BNEF.

Massive offshore wind turbines keep getting bigger, as projects like the biggest UK offshore wind farm come online, and that’s helping make the power cheaper — to the point where developers say new projects in U.S. waters can compete with natural gas.

The price “is going to be a real eye-opener,” said Bryan Martin, chairman of Deepwater Wind LLC, which won an auction in May to build a 400-megawatt wind farm southeast of Rhode Island.

Deepwater built the only U.S. offshore wind farm, a 30-megawatt project that was completed south of Block Island in 2016. The company’s bid was selected by Rhode Island the same day that Massachusetts picked Vineyard Wind to build an 800-megawatt wind farm in the same area, while international investors such as Japanese utilities in UK projects signal growing confidence.

#google#

Bigger turbines that make more electricity have cut the cost per megawatt by about half, a trend aided by higher-than-expected wind potential in many markets, said Tom Harries, a wind analyst at Bloomberg New Energy Finance. That also reduces maintenance expenses and installation time. All of this is helping offshore wind vie with conventional power plants.

“You could not build a thermal gas plant in New England for the price of the wind bids in Massachusetts and Rhode Island,” Martin said Friday at the U.S. Offshore Wind Conference in Boston. “It’s very cost-effective for consumers.”

The Massachusetts project could be about $100 to $120 a megawatt hour, according to a February estimate from Harries, though recent UK price spikes during low wind highlight volatility. The actual prices there and in Rhode Island weren’t disclosed.

For comparison, a new U.S. combine-cycle gas turbine ranges from $40 to $60 a megawatt-hour, and a new coal plant is $67 to $113, according to BNEF data.

A new power plant in land-constrained New England would probably be higher than that, and during winter peaks the region has seen record oil-fired generation in New England that underscores reliability concerns. More importantly, gas plants get a significant portion of their revenue from being able to guarantee that power is always available, something wind farms can’t do, said William Nelson, a New York-based analyst with BNEF. Looking only at the price at which offshore turbines can deliver electricity is a “narrow mindset,” he said.

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