Can U.S. compete with Canadian offshore wind?

Thailand Covid-19 Electricity Bill Relief offers energy subsidies, tariff cuts, and free power for small meters, helping work-from-home users as authorities waive charges and discount kWh rates via EGAT, MEA, PEA for three months.

Key Points

Program waiving or cutting household electricity bills for 22 million homes in March-May, easing work-from-home costs.

? Free power for meters <= 5 amps; up to 10M homes

? Up to 800 kWh: pay February rate; above, 50% discount

? >3,000 kWh: 30% discount; program valid March-May

The Thailand cabinet has formally approved energy authorities' decision to either waive or cut electricity charges, similar to B.C. electricity relief measures, for 22 million households where people are working at home because of the coronavirus disease.

Energy Minister Sontirat Sontijirawong said after the cabinet meeting on Tuesday that the ministers acknowledged the step taken by from the Energy Regulatory Commission, the Electricity Generating Authority of Thailand, the Metropolitan Electricity Authority and the Provincial Electricity Authority and noted parallels with Ontario's COVID-19 hydro plan rolled out to support ratepayers.

The measure would be valid for three months, from March to May, and cover 22 million households. It would cost the state 23.68 billion baht in lost revenue, he said, a pattern also seen with Ontario rate reductions affecting provincial revenues.

"The measure reduces the electricity charges burden on households. It is the cost of living of the people who are working from home to support the government's control of Covid-19," Mr Sontirat said.

The business sector also wants similar assistance, echoing sentiments from Ontario manufacturers during recent price reduction efforts. He said their requests were being considered.

Free electricity is extended to households with a power meter of no more than 5 amps. Up to 10 million households are expected to benefit, although issues like electricity payment challenges in India highlight different market contexts.

For households with a power meter over 5 amps, if their consumption does not exceed 800 units (kilowat hours), they will pay as much as they did in their February bill. The amount over 800 units will be subject to a 50 per cent discount, while elsewhere B.C. commercial consumption has fallen sharply.

Large houses that consume more than 3,000 units will get a 30 per cent discount, at a time when BC Hydro demand is down 10%.

Related News

• Electricity Forum News

• T&D Business News

California Nuclear Renewable Bill AB 2898 seeks to add nuclear to the Renewables Portfolio Standard, impacting Diablo Canyon, PG&E compliance, carbon-free targets, and potential license extensions while addressing climate goals and natural gas reliance.

Key Points

A bill to add nuclear to California's RPS, influencing Diablo Canyon, PG&E planning, and carbon-free climate targets.

✅ Reclassifies nuclear as renewable in California's RPS.

✅ Could influence Diablo Canyon license extension and ownership.

✅ Targets carbon-free goals while limiting natural gas reliance.

Although he admits it's a long shot, a member of the California Legislature from the district that includes the Diablo Canyon nuclear plant has introduced a bill that would add nuclear power to the state's list of renewable energy sources.

"I think that nuclear power is an important component of generating large-scale electricity that's good for the environment," said Jordan Cunningham, R-San Luis Obispo. "Without nuclear as part of the renewable portfolio, we're going to have tremendous difficulty meeting the state's climate goals without a significant cost increase on electricity ratepayers."

Established in 2002, California's Renewables Portfolio Standard spells out the power sources eligible to count toward the state's goals to wean itself of fossil fuels. The list includes solar, wind, biomass, geothermal, small hydroelectric facilities and even tidal currents. The standard has been updated, currently calling for 60 percent of California's electricity to come from renewables by 2030 and 100 percent from carbon-free sources by 2045, even as some analyses argue net-zero emissions may be difficult to achieve without nuclear power.

Nuclear power is not part of the portfolio standard and Diablo Canyon — the only remaining nuclear plant in California — is scheduled to stop producing electricity by 2025, even as some Southern California plant closures face postponement to maintain grid reliability.

Pacific Gas & Electric, the operators of Diablo Canyon, announced in 2016 an agreement with a collection of environmental and labor groups to shut down the plant, often framed as part of a just transition for workers and communities. PG&E said Diablo will become uneconomical to run due to changes in California's power grid — such as growth of renewable energy sources, increased energy efficiency measures and the migration of customers from traditional utilities to community choice energy programs.

But Cunningham thinks the passage of Assembly Bill 2898, which he introduced last week, — as innovators like Bill Gates' mini-reactor venture tout new designs — could give the plant literally a new lease on life.

"If PG&E were able to count the power produced (at Diablo) toward its renewable goals, it might — I'm not saying it will or would, but it might — cause them to reconsider applying to extend the operating license at Diablo," Cunningham said.

Passing the bill, supporters say, could also make Diablo Canyon attractive to an outside investor to purchase and then apply to the Nuclear Regulatory Commission for a license extension.

But nuclear power has long generated opposition in California and AB 2898 will face long odds in Sacramento, and similar efforts elsewhere have drawn opposition from power producers as well. The Legislature is dominated by Democrats, who have expressed more interest in further developing wind and solar energy projects than offering a lifeline to nuclear.

And if the bill managed to generate momentum, anti-nuclear groups will certainly be quick to mobilize, reflecting a national energy debate over Three Mile Island and whether to save struggling plants.

When told of Cunningham's bill, David Weisman, outreach coordinator for the Alliance for Nuclear Responsibility, said flatly, "Diablo Canyon has become a burdensome, costly nuclear white elephant."

Critics say nuclear power by definition cannot be considered renewable because it leaves behind waste in the form of spent nuclear fuel that then has to be stored, while supporters point to next-gen nuclear designs that aim to improve safety and costs. The federal government has not found a site to deposit the waste that has built up over decades from commercial nuclear power plants.

Even though Diablo Canyon is the only nuclear plant left in the Golden State, it accounts for 9 percent of California's power mix. Cunningham says if the plant closes, the state's reliance on natural gas — a fossil fuel — will increase, pointing to what happened when the San Onofre Nuclear Generating Station closed.

In 2011, the final full year operations for San Onofre, nuclear accounted for 18.2 percent of in-state generation and natural gas made up 45.4 percent. The following year, nuclear dropped to 9.3 percent and gas shot up to 61.1 percent of in-state generation.

"If we're going to get serious about being a national leader as California has been on dealing with climate change, I think nuclear is part of the answer," Cunningham said.

But judging from the response to an email from the Union-Tribune, PG&E isn't exactly embracing Cunningham's bill.

"We remain focused on safely and reliably operating Diablo Canyon Power Plant until the end of its current operating licenses and planning for a successful decommissioning," said Suzanne Hosn, a PG&E senior manager at Diablo Canyon. "The Assemblyman's proposal does not change any of PG&E's plans for the plant."

Cunningham concedes AB 2898 is "a Hail Mary pass" but said "it's an important conversation that needs to be had."

The second-term assemblyman introduced a similar measure late last year that sought to have the Legislature bring the question before voters as an amendment to the state constitution. But the legislation, which would require a two-thirds majority vote in the Assembly and the Senate, is still waiting for a committee assignment.

AB 2898, on the other hand, requires a simple majority to move through the Legislature. Cunningham said he hopes the bill will receive a committee assignment by the end of next month.
 

Related News

• Electricity Forum News

• Power Generation News

Iran Electricity Grid Synchronization enables regional interconnection, cross-border transmission, and Caspian-Europe energy corridors, linking Iraq, Azerbaijan, Russia, and Qatar to West Asia and European markets with reliable, flexible power exchange.

Key Points

Iran's initiative to link West Asian and European power grids for trade, transit, reliability, and regional influence.

✅ Synchronizes grids with Iraq, Azerbaijan, Russia, and potential Qatar link

✅ Enables east-to-Europe electricity transit via Caspian energy corridors

✅ Backed by gas-fueled and combined-cycle generation capacity

Following a plan for becoming West Asia’s electricity hub, Iran has been taking serious steps for joining its electricity network with neighbors in the past few years.

The Iranian Energy Ministry has been negotiating with the neighboring countries including Iraq for the connection of their power networks with Iran, discussing Iran-Iraq energy cooperation as well as ties with Russia, Afghanistan, Azerbaijan, and Qatar to make them enable to import or transmit their electricity to new destination markets through Iran.

The synchronization of power grids with the neighboring countries, not only enhances Iran’s electricity exchanges with them, but it will also increase the political stance of the country in the region.

So far, Iran’s electricity network has been synchronized with Iraq, where Iran is supplying 40% of Iraq's power today, and back in September, the Energy Minister Reza Ardakanian announced that the electricity networks of Russia and Azerbaijan are the next in line for becoming linked with the Iranian grid in the coming months.

“Within the next few months, the study project of synchronization of the electricity networks of Iran, Azerbaijan, and Russia will be completed and then the executive operations will begin,” the minister said.

Meanwhile, Ardakanian and Qatari Minister of State for Energy Affairs Saad Sherida Al-Kaabi held an online meeting in late September to discuss joining the two countries' electricity networks via sea.

During the online meeting, Al-Kaabi said: "Electricity transfer between the two countries is possible and this proposal should be worked on.”

Now, taking a new step toward becoming the region’s power hub, Iran has suggested becoming a bridge between East and Europe for transmitting electricity.

In a virtual conference dubbed 1st Caspian Europe Forum hosted by Berlin on Thursday, the Iranian energy minister has expressed the country’s readiness for joining its electricity network with Europe.

"We are ready to connect Iran's electricity network, as the largest power generation power in West Asia, with the European countries and to provide the ground for the exchange of electricity with Europe," Ardakanian said addressing the online event.

Iran's energy infrastructure in the oil, gas, and electricity sectors can be used as good platforms for the transfer of energy from east to Europe, he noted.

In the event, which was aimed to study issues related to the development of economic cooperation, especially energy, between the countries of the Caspian Sea region, the official added that Iran, with its huge energy resources and having skilled manpower and advanced facilities in the field of energy, can pave the ground for the prosperity of international transport and energy corridors.

"In order to help promote communication between our landlocked neighbors with international markets, as Uzbekistan aims to export power to Afghanistan across the region, we have created a huge transit infrastructure in our country and have demonstrated in practice our commitment to regional development and peace and stability," Ardakanian said.

He pointed out that having a major percentage of proven oil and gas resources in the world, regional states need to strengthen relations in a bid to regulate production and export policies of these huge resources and potentially play a role in determining the price and supply of these resources worldwide.

“EU countries can join our regional cooperation in the framework of bilateral or multilateral mechanisms such as ECO,” he said.

Given the growing regional and global energy needs and the insufficient investment in the field, with parts of Central Asia facing severe electricity shortages today, as well as Europe's increasing needs, this area can become a sustainable area of cooperation, he noted.

Ardakanian also said that by investing in energy production in Iran, Europe can meet part of its future energy needs on a sustainable basis.

In Iraq, plans for nuclear power plants are being pursued to tackle chronic electricity shortages, reflecting parallel efforts to diversify generation.

Iran currently has electricity exchange with Armenia, Azerbaijan, Iraq, where grid rehabilitation deals have been finalized, Turkmenistan, and Afghanistan.

The country’s total electricity exports vary depending on the hot and cold seasons of the year, since during the hot season which is the peak consumption period, the country’s electricity exports decreases, however electrical communication with neighboring countries continues.

Enjoying abundant gas resources, which is the main fuel for the majority of the country’s power plants, Iran has the capacity to produce about 85,500 megawatts [85.5 gigawatts (GW)] of electricity.

Currently, combined cycle power plants account for the biggest share in the country’s total power generation capacity as Iran is turning thermal plants to combined cycle to save energy, followed by gas power plants.

Related News

• Electricity Forum News

• Power Generation News

ISEM Price Volatility reflects Ireland-Northern Ireland grid balancing pressures, driven by dispatchable power shortages, day-ahead market dynamics, renewable shortfalls, and interconnector constraints, affecting intraday trading, operational reserves, and cross-border electricity flows.

Key Points

ISEM price volatility is Irish power price swings from grid balancing stress and limited dispatchable capacity.

✅ One-off spike linked to plant outage and low renewables

✅ Day-ahead market settling; intraday trading integration pending

✅ Interconnectors and reserves vital to manage adequacy

Irish grid-balancing prices soared to €3,774 ($4,284) per megawatt-hour last month amid growing concerns over dispatchable power capacity across Europe.

The price spike, triggered by an alert regarding generation losses, came only four months after Ireland and Northern Ireland launched an Integrated Single Electricity Market (ISEM) designed to make trading more competitive and improve power distribution across the island.

Evie Doherty, senior consultant for Ireland at Cornwall Insight, a U.K.-based energy consultancy, said significant price volatility was to be expected while ISEM is still settling down, aligning with broader 2019 grid edge trends seen across markets.

When the U.K. introduced a single market for Great Britain, called British Electricity Trading and Transmission Arrangements, in 2005, it took at least six months for volatility to subside, Doherty said.

In the case of ISEM, “it will take more time to ascertain the exact drivers behind the high prices,” she said. “We are being told that the day-ahead market is functioning as expected, but it will take time to really be able to draw conclusions on efficiency.”

Ireland and Northern Ireland have been operating with a single market “very successfully” since 2007, said Doherty. Although each jurisdiction has its own regulatory authority, they make joint decisions regarding the single market.

ISEM, launched in October 2018, was designed to help include Ireland and Northern Ireland day-ahead electricity prices in a market pricing system called the European Union Pan-European Hybrid Electricity Market Integration Algorithm.

In time, ISEM should also allow the Irish grids to participate in European intraday markets, and recent examples like Ukraine's grid connection underline the pace of integration efforts across Europe. At present, they are only able to do so with Great Britain. “The idea was to...integrate energy use and create more efficient flows between jurisdictions,” Doherty said.

EirGrid, the Irish transmission system operator, has reported that flows on its interconnector with Northern Ireland are more efficient than before, she said.

The price spike happened when the System Operator for Northern Ireland issued an alert for an unplanned plant outage at a time of low renewable output and constraints on the north-south tie-line with Ireland, according to a Cornwall Insight analysis.

Not an isolated event

Although it appears to have been a one-off event, there are increasing worries that a shortage of dispatchable power could lead to similar situations elsewhere across Europe, as seen in Nordic grid constraints recently.

Last month, newspaper Frankfurter Allgemeine Zeitung (FAZ) reported that German industrial concerns had been forced to curtail more than a gigawatt of power consumption to maintain operational reserves on the grid in December, after renewable production fell short of expectations and harsh weather impacts strained systems elsewhere.

Paul-Frederik Bach, a Danish energy consultant, has collected data showing that this was not an isolated incident. The FAZ report said German aluminum smelters had been forced to cut back on energy use 78 times in 2018, he noted.

Energy availability was also a concern last year in Belgium, where six out of seven nuclear reactors had been closed for maintenance. The closures forced Belgium to import 23 percent of its electricity from neighboring countries, Bach reported.

In a separate note, Bach revealed that 11 European countries that were net importers of energy had boosted their imports by 26 percent between 2017 and 2018. It is important to note that electricity imports do not necessarily imply a shortage of power, he stated.

However, it is also true that many European grid operators are girding themselves for a future in which dispatchable power is scarcer than today.

EirGrid, for example, expects dispatchable generation and interconnection capacity to drop from 10.6 gigawatts in 2018 to 9 gigawatts in 2027.

The Swedish transmission system operator Svenska Kraftnät, meanwhile, is forecasting winter peak power deficits could rise from 400 megawatts currently to 2.5 gigawatts in 2020-21.

Research conducted by the European Network of Transmission System Operators for Electricity, suggests power adequacy will fall across most of Europe up to 2025, although perhaps not to a critical degree.

The continent’s ability to deal with the problem will be helped by having more efficient trading systems, Bach told GTM. That means developments such as ISEM could be a step in the right direction, despite initial price volatility.

In the long run, however, Europe will need to make sure market improvements are accompanied by investments in HVDC technology and interconnectors and reserve capacity. “Somewhere there must be a production of electricity, even when there is no wind,” said Bach. 

Related News

• Electricity Forum News

• Power Generation News

Grid Modernization drives utilities to integrate DER, AMI, and battery storage while balancing reliability, safety, and affordability; regulators pursue cost-benefit analyses, new rate design, and policy actions to guide investment and protect customer-owned resources.

Key Points

Upgrading the grid to manage DER with digital tools, while maintaining reliability, safety, and customer affordability.

✅ Cost-benefit analyses guide prudent grid investments

✅ AMI and storage deployments enable DER visibility and control

✅ Rate design reforms support customer-owned resources

Utilities’ pursuit of a modern grid, including the digital grid concept, to maintain the reliability and safety pillars of electricity delivery has raised a lot of questions about the third pillar — affordability.

Utilities are seeing rising penetrations of emerging technologies, highlighted in recent grid edge trends reports, like distributed solar, behind-the-meter battery storage, and electric vehicles. These new distributed energy resources (DER) do not eliminate utilities' need to keep distribution systems safe and reliable.

But the need for modern tools to manage DER imposes costs on utilities, prompting calls to invest in smarter infrastructure even as some regulators, lawmakers and policymakers are concerned those costs could drive up electricity rates.

The result is an increasing number of legislative and regulatory grid modernization actions aimed at identifying what is necessary to serve the coming power sector transformation and address climate change risks across the grid.

The rise of grid modernization

Grid modernization, which is supported by both conservatives and distributed energy resources advocates, got a lot of attention last year. According to the 2017 review of grid modernization policy by the North Carolina Clean Energy Technology Center (NCCETC), 288 grid modernization policy actions were proposed, pending or enacted in 39 states.

These numbers from NCCETC's first annual review of policy activity set a benchmark against which future years' activity can be measured.

The most common type of state actions, by far, were those that focused on the deployment of advanced metering infrastructure (AMI) and battery energy storage. Those are two of the 2017 trends identified in NCCETC’s 50 States of Grid Modernization report. But deployment of those technologies, while foundational to an updated grid, only begins to prepare distribution systems for the coming power sector transformation.

Bigger advances, including the newest energy system management tools, are being held back by 2017’s other policy actions requiring more deliberation and fact-finding, even as grid vulnerability report cards underscore the risks that modernization seeks to mitigate.

Utilities’ proposals to more fully prepare their grids to deliver 21st century technologies are being met with questions about completeness and cost.

Utilities are being asked to address these questions in comprehensive, public utility commission-led cost-benefit analyses and studies. This is also one of NCCETC’s top 2017 policy action trends for grid modernization. The outcome to date appears to be an increased, but still incomplete, understanding of what is needed to build a 21st century grid.

Among the top objectives of those driving the policy actions are resolving questions about private sector participation in grid modernizaton buildouts and developing new rate designs to protect and support customer-owned distributed energy resources. Actions on those topics are also on NCCETC’s list of 2017 policy trends.

Altogether, the trend list is dominated by actions that do not lead to completion of grid modernization but to more work on it.

Related News

• Electricity Forum News

• Grid Technologies News

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.

Related News

• Electricity Forum News

• Energy Policy News