Brazilian utility uses 3M ACCR technology

UK Energy Price Cap aims to protect consumers on gas and electricity bills, tackling Big Six overcharging on default and standard variable tariffs, with Ofgem and MPs pushing urgent reforms to the broken market.

Key Points

A temporary absolute limit on default energy tariffs to shield consumers from overcharging on gas and electricity bills.

✅ Caps standard variable and default tariffs to protect loyalty.

✅ Targets Big Six pricing; oversight by Ofgem and BEIS MPs.

✅ Aims for winter protection while maintaining competition.

MPs are calling for a cap on the price of gas and electricity, with questions over the expected cost of a UK price cap amid fears consumers are being ripped off.

The Business, Energy and Industrial Strategy (BEIS) Select Committee says the Big Six energy companies have been overcharging for years.

MPs on the committee backed plans for a temporary absolute cap, noting debates over EU gas price cap strategies to fix what they called a "broken" energy market.

Labour's Rachel Reeves, who chairs the committee, said: "The energy market is broken. Energy is an essential good and yet millions of customers are ripped off for staying loyal to their energy provider.

"An energy price cap is now necessary and the Government must act urgently to ensure it is in place to protect customers next winter.

"The Big Six energy companies might whine and wail about the introduction of a price cap but they've been overcharging their customers on default and SVTs (standard variable tariffs) for years and their recent feeble efforts to move consumers off these tariffs has only served to highlight the need for this intervention."

The Committee also criticised Ofgem for failing to protect customers, especially the most vulnerable.

Draft legislation for an absolute cap on energy tariffs was published by the Government last year, and later developments like the Energy Security Bill have kept reform on the agenda.

But Business Secretary Greg Clark refused to guarantee that the flagship plans would be in place by next winter, despite warnings about high winter energy costs for households.

Committee members said there was a "clear lack of will" on the part of the Big Six to do what was necessary, including exploring decoupling gas and electricity prices, to deal with pricing problems.

A report from the committee found that customers are paying £1.4bn a year more than they should be under the current system.

Around 12 million households are stuck on poor-value tariffs, according to the report.

National assistance charity Citizens Advice said "loyal and vulnerable" customers had been "ripped off" for too long.

Chief executive Gillian Guy said: "An absolute cap, as recommended by the committee, is crucial to securing protection for the largest number of customers while continuing to provide competition in the market. This should apply to all default tariffs."

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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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UK power grid bottleneck is stalling renewable energy, with connection queues, planning delays, and transmission infrastructure gaps raising costs, slowing decarbonization, and deterring investment as government considers reforms led by a new chief adviser.

Key Points

Delays and capacity gaps that hinder connecting new generation and demand, raising costs and slowing decarbonization.

✅ Connection queues delay projects for years

✅ Planning and NIMBY barriers stall transmission builds

✅ Investment costs on bills risk political pushback

During his three decades at investment bank Morgan Stanley, Franck Petitgas developed a reputation for solving problems that vexed others. Fixing the UK’s creaking power grid could be his most challenging task yet.

Earlier this year, Prime Minister Rishi Sunak appointed Petitgas as his chief business adviser, and the former financier has been pushing to tackle the gridlock that’s left projects waiting endlessly for a connection, an issue he sees as one of the biggest problems for industry.

But there are no easy solutions to tackle the years-long queue to get on the grid or the drawn-out planning process for building clean power generation, with the energy transition stalled by supply delays compounding the problem. And sluggish progress in expanding and improving the electricity network is preventing the construction of new housing developments and offices, as well as slowing the transition to greener power.

That transition has already taken a knock after Sunak last week controversially watered down some of the UK’s climate ambitions, citing in part the cost to consumers. He also acknowledged the issues surrounding the grid and promised the “most transformative plans” in response, drawing on lessons from Europe’s power crisis where applicable. Those are due to be unveiled within weeks. 

Shortly after his appointment, Petitgas offered reassurances to business leaders at a meeting in Downing Street that solutions were being worked on, according to people familiar with the matter. But there’s a lack of confidence across business that enough will be done.

Cost is a big factor in the expansion of the electricity grid, and some argue a state-owned generation model could ease bills over time. Improving the onshore network alone could require investment of between £100 billion and £240 billion ($122-$293 billion) by 2050, according to a government analysis last year. 

With network expansion funded through power bills, that’s a big ask, particularly with Sunak trailing in polls ahead of an election expected next year.

“It’s very difficult for politicians to say more money should be on bills,” said Emma Pinchbeck, chief executive of Energy UK, a trade body. “So you get to a situation where no one wants to pay for the infrastructure investment until it’s really sticky, and that’s where we’ve got to with the grid.”

There are huge competitive and economic implications if the UK falls further behind. With US President Joe Biden spending an estimated $370 billion on climate measures through his Inflation Reduction Act, and China already a world leader in electric vehicles, Britain’s grid inaction is holding it back in the global race to decarbonize, said Jess Ralston, an analyst at the Energy and Climate Intelligence Unit think tank.

“The UK is dithering and delaying, and not making any strategic decisions,” she said. “You can see companies just saying ‘I’m going to the US, or I’m going to China’.” 

In a statement, the government said it’s a “priority to speed up the time taken to connect new power generators and power consumers to the grid.” It added that it’s taking “significant steps to accelerate grid infrastructure,” including support for new Channel interconnectors announced this year.

The government expects demand for electricity to double by 2035 and that will mean more generation that needs to be linked up to the network by cables and pylons. Local grids will also have to expand to accommodate more connection points for electric vehicles and homes, and invest in large-scale energy storage capacity to balance supply.

But so far, the rapid rise in renewable energy investment has not been accompanied by matching spend on the power network, according to BloombergNEF, a pattern seen in Germany’s grid expansion woes as well.

“The pace and scale of what we now have to deliver is significantly different from the last few decades,” said Carl Trowell, president of UK strategic infrastructure at National Grid. “It’s a national endeavor.”

In June, Electricity Networks Commissioner Nick Winser sent the government recommendations for how to accelerate construction of more transmission infrastructure. He said efforts to decarbonize the power sector will be “wasted if we cannot get the power to homes and businesses.”

“We need a seriously stronger sense of urgency,” said Kevin O’Donovan, country manager for Statkraft UK, which is holding off investment in four wind farms and two solar projects due to grid connection delays.

In addition to cost, the other major stumbling block is planning. Politicians in the governing Conservative Party are wary of angering voters with new infrastructure in rural areas that typically vote Tory. Across the country, “Not In My Back Yard” campaigners – NIMBYs — pose a major challenge to projects.

Petitgas, 62, retired from Morgan Stanley last year after nearly 30 years at the bank, where he led its international division from London. The issues over connections and planning have been repeatedly pointed out to Petitgas by investors and trade groups over a series of meetings this year, according to people familiar with the matter, requesting anonymity discussing private talks.

Yet with a general election looming and the issue plagued by political headaches, many are skeptical that Sunak can find the solutions needed.

One business chief said Downing Street considers the issue too tricky and expensive to tackle in the short-term. Others are concerned that while Petitgas has license from Sunak, he doesn’t have influence across the relevant departments to get grids to the top of the agenda.

Wind Farms

Multiple parts of the UK’s climate plans are under pressure. Earlier this month, an auction for contracts to build new wind farms received zero bids from developers, even as wind leads the power mix in many regions, marking yet another green setback. 

The UK is already behind on its target of having 50 gigawatts of offshore wind built by 2030, up from 14 GW today. The challenge is accelerating development without railroading local communities.

Within Sunak’s Conservative Party, some lawmakers are pushing back on new infrastructure in their local areas. A group including Environment Secretary Therese Coffey and former Home Secretary Priti Patel is campaigning against building new pylons across a stretch of eastern England.

According to Adam Bell, director of policy at consultancy Stonehaven, backbench pressure means Sunak is unlikely to take major action on the grid in the near term. He doesn’t see the prime minister accepting Winser’s recommendations, least of all accelerating planning decisions.

“Over the last year, Sunak has favored party management over things that will benefit the country,” Bell said. 

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India Nuclear Generation Shortfall highlights missed five-year plan targets due to uranium fuel scarcity, commissioning delays at Kudankulam, PFBR slippage, and PHWR equipment bottlenecks under IAEA safeguards and domestic supply constraints.

Key Points

A gap between planned and actual nuclear output due to fuel shortages, reactor delays, and first-of-a-kind hurdles.

✅ Fuel scarcity pre-2009-10 constrained unsafeguarded reactors.

✅ Kudankulam delays from protests, litigation, and remobilisation.

✅ FOAK PHWR equipment bottlenecks and PFBR slippage.

A lack of available domestically produced nuclear fuel and delays in constructing and commissioning nuclear power plants, including first-of-a-kind plants and the Prototype Fast Breeder Reactor (PFBR), meant that India failed to meet its nuclear generation targets under the governmental plans over the decade to 2017, even as global project milestones were being recorded elsewhere.

India's nuclear generation target under its 11th five-year plan, covering the period 2007-2012, was 163,395 million units (MUs) and the 12th five-year Plan (2012-17) was 241,748 MUs, Minister of state for the Department of Atomic Energy and the Prime Minister's Office Jitendra Singh told parliament on 6 February. Actual nuclear generation in those periods was 109,642 MUs and 183,488 MUs respectively, Singh said in a written answer to questions in the Lok Sabah.

Singh attributed the shortfall in generation to a lack of availability of the necessary quantities of domestically produced fuel during the three years before 2009-2010; delays to the commissioning of two 1000 MWe nuclear power plants at Kudankulam due to local protests and legal challenges; and delays in the completion of two indigenously designed pressurised heavy water reactors and the PFBR.

Kudankulam 1 and 2 are VVER-1000 pressurised water reactors (PWRs) supplied by Russia's Atomstroyexport under a Russian-financed contract. The units were built by Nuclear Power Corporation of India Ltd (NPCIL) and were commissioned and are operated by NPCIL under International Atomic Energy Agency (IAEA) safeguards, with supervision from Russian specialists, while China's nuclear program advanced on a steady development track in the same period. Construction of the units - the first PWRs to enter operation in India - began in 2002.

Singh said local protests resulted in the halt of commissioning work at Kudankulam for nine months from September 2011 to March 2012, when he said project commissioning had been at its peak. As a consequence, additional time was needed to remobilise the workforce and contractors, he said. Litigation by anti-nuclear groups, and compliance with supreme court directives, impacted commissioning in 2013, he said. Unit 1 entered commercial operation in December 2014 and unit 2 in April 2017.

Delays in the manufacture and supply by domestic industry of critical equipment for first-of-a-kind 700 MWe pressurised heavy water reactors -  Kakrapar units 3 and 4, and Rajasthan units 7 and 8 - has led to delays in the completion of those units, the minister said, as well as noting the delay in completion of the PFBR, which is being built at Kalpakkam by Bhavini. In answer to a separate question, Singh said the PFBR is in an "advance stage of integrated commissioning" and is "expected to approach first criticality by the year 2020."

Eight of India's operating nuclear power plants are not under IAEA safeguards and can therefore only use indigenously-sourced uranium. The other 14 units operate under IAEA safeguards and can use imported uranium. The Indian government has taken several measures to secure fuel supplies for reactors in operation and under construction, amid coal supply rationing pressures elsewhere in the power sector, concluding fuel supply contracts with several countries for existing and future reactors under IAEA Safeguards and by "augmentation" of fuel supplies from domestic sources, Singh said.

Kakrapar 3 and 4, with Kakrapar 3 criticality already reported, and Rajasthan 7 and 8 are all currently expected to enter service in 2022, according to World Nuclear Association information.

Joint venture discussions

In February 2016 the government amended the Atomic Energy Act to allow NPCIL to form joint venture companies with other public sector undertakings (PSUs) for involvement in nuclear power generation and possibly other aspects of the fuel cycle, reflecting green industrial strategies shaping future reactor waves globally. In answer to another question, Singh confirmed that NPCIL has entered into joint ventures with NTPC Limited (National Thermal Power Corporation, India's largest power company) and Indian Oil Corporation Limited. Two joint venture companies - Anushakti Vidhyut Nigam Limited and NPCIL-Indian Oil Nuclear Energy Corporation Limited - have been incorporated, and discussions on possible projects to be set up by the joint venture companies are in progress.

An exploratory discussion had also been held with Oil & Natural Gas Corporation, Singh said. Indian Railways - which has in the past been identified as a potential joint venture partner for NPCIL - had "conveyed that they were not contemplating entering into an MoU for setting up of nuclear power plants," Singh said.

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Oil and Gas Profitability Decline reflects shale-driven oversupply, OPEC-Russia dynamics, LNG exports, renewables growth, and weak demand, signaling compressed margins for producers, stressed petrodollar budgets, and shifting energy markets post-Covid.

Key Points

A sustained squeeze on hydrocarbon margins from agile shale supply, weaker OPEC leverage, and expanding renewables.

✅ Shale responsiveness caps prices and erodes industry rents

✅ OPEC-Russia cuts face limited impact versus US supply

✅ Renewables and EVs slow long-term oil and gas demand

The oil-price crash of March 2020 will probably not last long. As in 2014, when the oil price dropped below $50 from $110 in a few weeks, this one will trigger a temporary collapse of the US shale industry. Unless the coronavirus outbreak causes Armageddon, cheap oil will also support policymakers’ efforts to help the global economy.

But there will be at least one important and lasting difference this time round — and it has major market and geopolitical implications.

The oil price crash is a foretaste of where the whole energy sector was going anyway — and that is down.

It may not look that way at first. Saudi Arabia will soon realise, as it did in 2015, that its lethal decision to pump more oil is not only killing US shale but its public finances as well. Riyadh will soon knock on Moscow’s door again. Once American shale supplies collapse, Russia will resume co-operation with Saudi Arabia.

With the world economy recovering from the Covid-19 crisis by then, and with electricity demand during COVID-19 shifting, moderate supply cuts by both countries will accelerate oil market recovery. In time, US shale producers will return too.

Yet this inevitable bounceback should not distract from two fundamental factors that were already remaking oil and gas markets. First, the shale revolution has fundamentally eroded industry profitability. Second, the renewables’ revolution will continue to depress growth in demand.

The combined result has put the profitability of the entire global hydrocarbon industry under pressure. That means fewer petrodollars to support oil-producing countries’ national budgets, including Canada's oil sector exposures. It also means less profitable oil companies, which traditionally make up a large segment of stock markets, an important component of so many western pension funds.

Start with the first factor to see why this is so. Historically, the geological advantages that made oil from countries such as Saudi Arabia so cheap to produce were unique. Because oil and gas were produced at costs far below the market price, the excess profits, or “rent”, enjoyed by the industry were very large.

Furthermore, collusion among low-cost producers has been a winning strategy. The loss of market share through output cuts was more than compensated by immediately higher prices. It was the raison d’être of Opec.

The US shale revolution changed all this, exposing the limits of U.S. energy dominance narratives. A large oil-producing region emerged with a remarkable ability to respond quickly to price changes and shrink its costs over time. Cutting back cheap Opec oil now only increases US supplies, with little effect on world prices.

That is why Russia refused to cut production this month. Even if its cuts did boost world prices — doubtful given the coronavirus outbreak’s huge shock to demand — that would slow the shrinkage of US shale that Moscow wants.

Shale has affected the natural gas industry even more. Exports of US liquefied natural gas now put an effective ceiling on global prices, and debates over a clean electricity push have intensified when gas prices spike.

On top of all this, there is also the renewables’ revolution, though a green revolution has not been guaranteed in the near term. Around the world, wind and solar have become ever-cheaper options to generate electricity. Storage costs have also dropped and network management improved. Even in the US, renewables are displacing coal and gas. Electrification of vehicle fleets will damp demand further, as U.S. electricity, gas, and EVs face evolving pressures.

Eliminating fossil fuel consumption completely would require sustained and costly government intervention, and reliability challenges such as coal and nuclear disruptions add to the complexity. That is far from certain. Meanwhile, though, market forces are depressing the sector’s usual profitability.

The end of oil and gas is not immediately around the corner. Still, the end of hydrocarbons as a lucrative industry is a distinct possibility. We are seeing that in dramatic form in the current oil price crash. But this collapse is merely a message from the future.

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New England Grid Reform Initiative aligns governors with ISO New England to reshape market design, boost grid reliability, accelerate renewable energy and offshore wind, explore carbon pricing and forward clean energy markets, and bolster accountability.

Key Points

Five states aim to reform ISO New England markets, prioritize renewables and reliability, and test carbon pricing.

✅ Governors seek market design aligned with clean energy mandates

✅ ISO-NE accountability and stakeholder engagement prioritized

✅ Explore carbon pricing and forward clean energy market options

Weeks after initiating a broad overhaul of utility regulation within its borders, Connecticut has recruited four New England states, as Maine debates a 145-mile transmission line project to rework the regional grid that is overseen by ISO New England, the independent system operator charged with ensuring a reliable supply of electricity from power plants.

In a written statement Thursday morning, Gov. Ned Lamont said the current structure “has actively hindered” states’ efforts to phase out polluting power plants in favor of renewable sources like wind turbines and solar panels, while increasing costs “to fix market design failures” in his words. Lamont’s energy policy chief Katie Dykes has emerged as a vocal critic of ISO New England’s structure and priorities, in her role as commissioner of the Connecticut Department of Energy and Environmental Protection.

“When Connecticut opted to deregulate our electricity market, we wanted the benefits of competition — to achieve lower-cost energy, compatible with meeting our clean-energy goals,” Dykes said in a telephone interview Thursday afternoon. “We have a partner [in] ISO New England, to manage this grid and design a market that is not thwarting our clean-energy goals, but achieving them; and not ignoring consumers’ concerns. ... That’s really what we are looking to do — reclaim the benefits of competition and regional cooperation.”

Lamont and his counterparts in Massachusetts, Rhode Island, Vermont and Maine plan to release a “vision document” in their words on Friday through the New England States Committee on Electricity, after New Hampshire rejected a Quebec-Massachusetts transmission proposal that sought to import Canadian hydropower.

The initial documents made no mention of New Hampshire, which likewise obtains electricity through the wholesale markets managed by ISO New England and has seen clashes over the Northern Pass hydropower project in recent years; and whose Seabrook Station is one two nuclear power plants in New England alongside Dominion Energy’s Millstone Power Station in Waterford. Gov. Chris Sununu’s office did not respond immediately to a query on why New Hampshire is not participating.

Connecticut and the four other states outlined a few broad goals that they will hone over the coming months. Those include creating a better market structure and planning process supporting the conversion to renewables; improving grid reliability, with measures such as an emergency fuel stock program considered; and increasing the accountability of ISO New England to the states and by extension their ratepayer households and businesses.

ISO New England spokesperson Matt Kakley indicated the Holyoke, Mass.-based nonprofit will “engage with the states and our stakeholders” on the governors’ proposal, in an email response to a query. He did not elaborate on any immediate opportunities or challenges inherent in the governors’ proposal.

“Maintaining reliable, competitively-priced electricity through the clean energy transition will require broad collaboration,” Kakley stated. “The common vision of the New England governors will play an important role in the discussions currently underway on the future of the grid.”

Renewable revolution
ISO New England launched operations in 1999, running auctions through which power plant operators bid to supply electricity, including against long-term projections for future needs that can only be met through the construction or installation of new generation capacity.

ISO New England falls under the jurisdiction of the Federal Energy Regulatory Commission rather than the states whose electricity supplies it is tasked with ensuring. That has led to pointed criticism from Dykes and Connecticut legislators that ISO New England is out of touch with the state’s push to switch to renewable sources of electricity.

Entering October, ISO New England published an updated outlook that revealed 60 percent of proposed power generators in the region’s future “queue” are wind farms, primarily offshore installations like the proposed Park City Wind project of Avangrid and Revolution Wind from Eversource. But Dykes recently criticized as unnecessary an NTE Energy plant approved already by ISO New England for eastern Connecticut, which will be fueled by natural gas if all other regulatory approvals are granted.

The six New England states participate in the Regional Greenhouse Gas Initiative that caps carbon emissions by individual power plants, while allowing them to purchase unused allowances from each other with that revenue funneled to the states to support renewable energy and conservation programs. FERC is now considering the concept of carbon pricing, which would levy a tax on power plants based on their emissions, and it also faces pressure to act on aggregated DERs from lawmakers.

ISO New England is investigating the concepts of net carbon pricing and a “forward clean energy market” that would borrow elements of the existing forward capacity market, but designed to meet individual state objectives for the percentage of renewable power they want generated while ensuring adequate electricity is in place when weather does not cooperate.

The Connecticut Public Utilities Regulatory Authority is collecting on its own initiative industry input on modernization proposals, as New York regulators open a formal review of retail energy markets for comparison, that would add up to hundreds of millions of dollars, including utility-scale batteries to store power generated by offshore wind farms and solar arrays; and “smart” meters in homes and businesses to help electricity customers better manage their power use.

The New England Power Pool serves as a central forum for plant operators, commercial users and others like the Connecticut Office of Consumer Counsel, amid Massachusetts solar demand charge debates that affect distributed generation policy, with NEPOOL’s chair stating Thursday morning the group was still reviewing the governors’ announcement.

“NEPOOL has been engaged this year in meetings ... exploring the transition to a future grid in New England and potential pathways forward to support that transition,” stated Nancy Chafetz, chair of NEPOOL, in an email.

Connecticut’s issues with ISO New England boiled over this summer on the heels of a power-purchase agreement between Millstone owner Dominion and transmission grid operators Eversource and United Illuminating, which contributed to a sharp increase in customer bills.

A few weeks ago, Lamont signed into law a “Take Back the Grid” act that allows the Connecticut Public Utilities Regulatory Authority to factor in Eversource’s and Avangrid subsidiary United Illuminating’s past performance in maintaining electric reliability, in addition to any future needs for revenue based on needed upgrades. The law included an element for Connecticut to initiate a study of ISO New England’s role.

Eversource and Avangrid have voiced support for the switch to “performance-based” regulation in Connecticut. Eversource spokesperson Mitch Gross on Thursday cited the company’s view that any changes to the operation of New England’s wholesale power markets should occur within the existing ISO New England structure.

“We also recommend any examination of potential alternatives includes a thorough evaluation that ensures unfair costs would not be imposed on customers,” Gross stated in an email.

In a statement forwarded by Avangrid spokesperson Ed Crowder, the United Illuminating parent indicated it intends to have “a voice in this process” with the goal of continued grid reliability amid increased adoption of clean energy sources.

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