Britain and Norway plan CO2 storage in North Sea

Hydro-Quebec NECEC Transmission Line faces Maine PUC scrutiny over clean energy claims, greenhouse gas emissions, spillage capacity, resource shuffling, and Massachusetts contracts, amid opposition from natural gas generators and environmental groups debating public need.

Key Points

A $1B Maine corridor for Quebec hydropower to Massachusetts, debated over emissions, spillage, and public need.

✅ Maine PUC weighing public need and ratepayer benefits

✅ Emissions impact disputed: resource shuffling vs new supply

✅ Hydro-Quebec spillage claims questioned without data

As Maine regulators are deciding whether to approve construction of a $1 billion electricity corridor across much of western Maine, the Canadian hydroelectric utility poised to make billions of dollars from the project has been absent from the process.

This has left both opponents and supporters of the line arguing about how much available energy the utility has to send through a completed line, and whether that energy will help fulfill the mission of the project: fighting climate change.

And while the utility has avoided making its case before regulators, which requires submitting to cross-examination and discovery, it has engaged in a public relations campaign to try and win support from the region's newspapers.

Government-owned Hydro-Quebec controls dams and reservoirs generating hydroelectricity throughout its namesake province. It recently signed agreements to sell electricity across the proposed line, named the New England Clean Energy Connect, to Massachusetts as part of the state's effort to reduce its dependence on fossil fuels, including natural gas.

At the Maine Public Utilities Commission, attorneys for Central Maine Power Co., which would build and maintain the line, have been sparring with the opposition over the line's potential impact on Maine and its electricity consumers. Leading the opposition is a coalition of natural gas electricity generators that stand to lose business should the line be built, as well as the Natural Resources Council of Maine, an environmental group.

That unusual alliance of environmental and business groups wants Hydro-Quebec to answer questions about its hydroelectric system, which they argue can't deliver the amount of electricity promised to Massachusetts without diverting energy from other regions.

In that scenario, critics say the line would not produce the reduction in greenhouse gas emissions that CMP and Hydro-Quebec have made a central part of their pitch for the project. Instead, other markets currently buying energy from Hydro-Quebec, such as New York, Ontario and New Brunswick, would see hydroelectricity imports decrease and have to rely on other sources of energy, including coal or oil, to make up the difference. If that happened, the total amount of clean energy in the world would remain the same.

Opponents call this possibility "greenwashing." Massachusetts regulators have described these circumstances as "resource shuffling."

But CMP spokesperson John Carroll said that if hydropower was diverted from nearby markets to power Massachusetts, those markets would not turn to fossil fuels. Rather they would seek to develop other forms of renewable energy "leading to further reductions in greenhouse gas emissions in the region."

Hydro-Quebec said it has plenty of capacity to increase its electricity exports to Massachusetts without diverting energy from other places.

However, Hydro-Quebec is not required to participate -- and has not voluntarily participated -- in regulatory hearings where it would be subject to cross examinations and have to testify under oath. Some participants wish it would.

At a January hearing at the Maine Public Utilities Commission, hearing examiner Mitchell Tannenbaum had to warn experts giving testimony to "refrain from commentary regarding whether Hydro-Quebec is here or not" after they complained about its absence when trying to predict potential ramifications of the line.

"I would have hoped they would have been visible and available to answer legitimate questions in all of these states through which their power is going to be flowing," said Dot Kelly, a member of the executive committee at the Maine Chapter of the Sierra Club who has participated in the line's regulatory proceedings as an individual. "If you're going to have a full and fair process, they have to be there."

[What you need to know about the CMP transmission line proposed for Maine]

While Hydro-Quebec has not presented data on its system directly to Maine regulators, it has brought its case to the press. Central to that case is the fact that it's "spilling" water from its reservoirs because it is limited by how much electricity it can export. It said that it could send more water through its turbines and lower reservoir levels, eliminating spillage and creating more energy, if only it had a way to get that energy to market. Hydro-Quebec said the line would make that possible, and, in doing so, help lower emissions and fight climate change.

"We have that excess potential that we need to use. Essentially, it's a good problem to have so long as you can find an export market," Hydro-Quebec spokesperson Serge Abergel told the Bangor Daily News.

Hydro-Quebec made its "spillage" case to the editorial boards of The Boston Globe, The Portland Press Herald and the BDN, winning qualified endorsements from the Globe and Press Herald. (The BDN editorial board has not weighed in on the project).

Opponents have questioned why Hydro-Quebec is willing to present their case to the press but not regulators.

"We need a better answer than 'just trust us,'" Natural Resources Council of Maine attorney Sue Ely said. "What's clear is that CMP and HQ are engaging in a full-court publicity tour peddling false transparency in an attempt to sell their claims of greenhouse gas benefits."

Energy generators aren't typically parties to public utility commission proceedings involving the building of transmission lines, but Maine regulators don't typically evaluate projects that will help customers in another state buy energy generated in a foreign country.

"It's a unique case," said Maine Public Advocate and former Democratic Senate Minority Leader Barry Hobbins, who has neither endorsed nor opposed the project. Hobbins noted the project was not proposed to improve reliability for Maine electricity customers, which is typically the point of new transmission line proposals evaluated by the commission. Instead, the project "is a straight shot to Massachusetts," Hobbins said.

Maine Public Utilities Commission spokesperson Harry Lanphear agreed. "The Commission has never considered this type of project before," he said in an email.

In order to proceed with the project, CMP must convince the Maine Public Utilities Commission that the proposed line would fill a "public need" and benefit Mainers. Among other benefits, CMP said it will help lower electricity costs and create jobs in Maine. A decision is expected in the spring.

Given the uniqueness of the case, even the commission seems unsure about how to apply the vague "public need" standard. On Jan. 14, commission staff asked case participants to weigh in on how it should apply Maine law when evaluating the project, including whether the hydroelectricity that would travel over the line should be considered "renewable" and whether Maine's own carbon reduction goals are relevant to the case.

James Speyer, an energy consultant whose firm was hired by natural gas company and project opponent Calpine to analyze the market impacts of the line, said he has testified before roughly 20 state public utility commissions and has never seen a proceeding like this one.

"I've never been in a case where one of the major beneficiaries of the PUC decision is not in the case, never has filed a report, has never had to provide any data to support its assertions, and never has been subject to cross examination," Speyer said. "Hydro-Quebec is like a black box."

Hydro-Quebec would gladly appear before the Maine Public Utilities Commission, but it has not been invited, said spokesperson Abergel.

"The PUC is doing its own process," Abergel said. "If the PUC were to invite us, we'd gladly intervene. We're very willing to collaborate in that sense."

But that's not how the commission process works. Individuals and organizations can intervene in cases, but the commission does not invite them to the proceedings, commission spokesperson Lanphear said.

CMP spokesperson Carroll dismissed concerns over emissions, noting that Hydro-Quebec is near the end of completing a more than 15-year effort to develop its clean energy resources. "They will have capacity to satisfy the contract with Massachusetts in their reservoirs," Carroll said.

While Maine regulators are evaluating the transmission line, Massachusetts' Department of Public Utilities is deciding whether to approve 20-year contracts between Hydro-Quebec and that state's electric utilities. Those contracts, which Hydro-Quebec has estimated could be worth close to $8 billion, govern how the utility sells electricity over the line.

Dean Murphy, a consultant hired by the Massachusetts Attorney General's office to review the contracts, testified before Massachusetts regulators that the agreements do not require a reduction in global greenhouse gas emissions. Murphy also warned the contracts don't actually require Hydro-Quebec to increase the total amount of energy it sends to New England, as energy could be shuffled from established lines to the proposed CMP line to satisfy the contracts.

Parties in the Massachusetts proceeding are also trying to get more information from Hydro-Quebec. Energy giant NextEra is currently trying to convince Massachusetts regulators to issue a subpoena to force Hydro-Quebec to answer questions about how its exports might change with the construction of the transmission line. Hydro-Quebec and CMP have opposed the motion.

Hydro-Quebec has a reputation for guarding its privacy, according to Hobbins.

"It would have been easier to not have to play Sherlock Holmes and try to guess or try to calculate without having a direct 'yes' or 'no' response from the entity itself," Hobbins said.

Ultimately, the burden of proving that Maine needs the line falls on CMP, which is also responsible for making sure regulators have all the information they need to make a decision on the project, said former Maine Public Utilities Commission Chairman Kurt Adams.

"Central Maine Power should provide the PUC with all the info that it needs," Adams said. "If CMP can't, then one might argue that they haven't met their burden."

'They treat HQ with nothing but distrust'

If completed, the line would bring 9.45 terawatt hours of electricity from Quebec to Massachusetts annually, or about a sixth of the total amount of electricity Massachusetts currently uses every year (and roughly 80 percent of Maine's annual load). CMP's parent company Avangrid would make an estimated $60 million a year from the line, according to financial analysts.

As part of its legally mandated efforts to reduce carbon emissions and fight climate change, Massachusetts would pay the $950 million cost of constructing the line. The state currently relies on natural gas, a fossil fuel, for nearly 70 percent of its electricity, a figure that helps explain natural gas companies' opposition to the project.

A panel of experts recently warned that humanity has 12 years to keep global temperatures from rising above 1.5 degrees Celsius and prevent the worst effects of climate change, which include floods, droughts and extreme heat.

The line could lower New England's annual carbon emissions by as much as 3 million metric tons, an amount roughly equal to Washington D.C.'s annual emissions. Opponents worry that reduction could be mostly offset by increases in other markets.

But while both sides have claimed they are fighting for the environment, much of the debate features giant corporations with headquarters outside of New England fighting over the future of the region's electricity market, echoing customer backlash seen in other utility takeovers.

Hydro-Quebec is owned by the people of Quebec, and CMP is owned by Avangrid, which is in turn owned by Spanish energy giant Iberdrola. Leading the charge against the line are several energy companies in the Fortune 500, including Houston-based Calpine and Florida-based NextEra Energy.

However, only one side of the debate counts environmental groups as part of its coalition, and, curiously enough, that's the side with fossil fuel companies.

Some environmental groups, including the Natural Resources Council of Maine and Environment Maine, have come out against the line, while others, including the Acadia Center and the Conservation Law Foundation, are still deciding whether to support or oppose the project. So far, none have endorsed the line.

"It is discouraging that some of the environmental groups are so opposed, but it seems the best is the enemy of the good," said CMP's Carroll in an email. "They seem to have no sense of urgency; and they treat HQ with nothing but distrust."

Much of the environmentally minded opposition to the project focuses on the impact the line would have on local wildlife and tourism.

Sandi Howard administers the Say NO To NECEC Facebook page and lives in Caratunk, one of the communities along the proposed path of the line. She said opposition to the line might change if it was proven to reduce emissions.

"If it were going to truly reduce global CO2 emissions, I think it would be be a different conversation," Howard said.

Not the first choice

Before Maine, New Hampshire had its own debate over whether it should serve as a conduit between Quebec and Massachusetts. The proposed Northern Pass transmission line would have run the length of the state. It was Massachusetts' first choice to bring Quebec hydropower to its residents.

But New Hampshire's Site Evaluation Committee unanimously voted to reject the Northern Pass project in February 2018 on the grounds that the project's sponsor, Eversource, had failed to prove the project would not interfere with local business and tourism. Though it was the source of the electricity that would have traveled over the line, Hydro-Quebec was not a party to the proceedings.

In its decision, the committee noted the project would not reduce emissions if it was not coupled with a "new source of hydropower" and the power delivered across the line was "diverted from Ontario and New York." The committee added that it was unclear if the power would be new or diverted.

The next month, Massachusetts replaced Northern Pass by selecting CMP's proposed line. As the project came before Maine regulators, questions about Hydro-Quebec and emissions persisted. Two different analyses of CMP's proposed line, including one by the Maine Public Utility Commission's independent consultant, found the line would greatly reduce New England's emissions.

But neither of those studies took into account the line's impact on emissions outside of New England. A study by Calpine's consultant, Energyzt, found New England's emissions reduction could be mostly offset by increased emissions in other areas, including New Brunswick and New York, that would see hydroelectricity imports shrink as energy was redirected to fulfill the contract with Massachusetts.

'They failed in any way to back up those spillage claims'

Hydro-Quebec seemed content to let CMP fight for the project alone before regulators for much of 2018. But at the end of the year, the utility took a more proactive approach, meeting with editorial boards and providing a two-page letter detailing its "spillage" issues to CMP, which entered it into the record at the Maine Public Utilities Commission.

The letter provided figures on the amount of water the utility spilled that could have been converted into sellable energy, if only Hydro-Quebec had a way to get it to market. Instead, by "spilling" the water, the company essentially wasted it.

Instead of sending water through turbines or storing it in reservoirs, hydroelectric operators sometimes discharge water held behind dams down spillways. This can be done for environmental reasons. Other times it is done because the operator has so much water it cannot convert it into electricity or store it, which is usually a seasonal issue: Reservoirs often contain the most water in the spring as temperatures warm and ice melts.

Hydro-Quebec said that, in 2017, it spilled water that could have produced 4.5 terawatt hours of electricity, or slightly more than half the energy needed to fulfill the Massachusetts contracts. In 2018, the letter continued, Hydro-Quebec spilled water that could have been converted into 10.4 terawatts worth of energy. The company said it didn't spill at all due to transmission constraints prior to 2017.

The contracts Hydro-Quebec signed with the Massachusetts utilities are for 9.45 terawatt hours annually for 20 years. In its letter, the utility essentially showed it had only one year of data to show it could cover the terms of the contract with "spilled" energy.

"Reservoir levels have been increasing in the last 15 years. Having reached their maximum levels, spillage maneuvers became necessary in 2017 and 2018," said Hydro-Quebec spokesperson Lynn St. Laurent.

By providing the letter through CMP, Hydro-Quebec did not have to subject its spillage figures to cross examination.

Dr. Shaleen Jain, a civil and environmental engineering professor at the University of Maine, said that, while spilled water could be converted into power generation in some circumstances, spills happen for many different reasons. Knowing whether spillage can be translated into energy requires a great deal of analysis.

"Not all of it can be repurposed or used for hydropower," Jain said.

In December, one of the Maine Public Utility Commission's independent consultants, Gabrielle Roumy, told the commission that there's "no way" to "predict how much water would be spilled each and every year." Roumy, who previously worked for Hydro-Quebec, added that even after seeing the utility's spillage figures, he believed it would need to divert energy from other markets to fulfill its commitment to Massachusetts.

"I think at this point we're still comfortable with our assumptions that, you know, energy would generally be redirected from other markets to NECEC if it were built," Roumy said.

In January, Tanya Bodell, the founder and executive director of consultant Energyzt, testified before the commission on behalf of Calpine that it was impossible to know why Hydro-Quebec was spilling without more data.

"There's a lot of details you'd have to look at in order to properly assess what the reason for the spillage is," Bodell said. "And you have to go into an hourly level because the flows vary across the year, within the month, the week, the days. ...And, frankly, it would have been nice if Hydro-Quebec was here and brought their model and allowed us to see how this could help them to sell more."

Even though CMP and Hydro-Quebec's path to securing approval of the project does not go through the Legislature, and despite a Maine court ruling that energized Hydro-Quebec's export bid, lawmakers have taken notice of Hydro-Quebec's absence. Rep. Seth Berry, D-Bowdoinham, the House chairman of the Joint Committee On Energy Utilities and Technology and a frequent critic of CMP, said he would like to see Hydro-Quebec "show up and subject their proposal to examination and full analysis and public examination by the regulators and the people of Maine."

"They're trying to sell an incredibly lucrative proposal, and they failed in any way to back up those spillage claims with defensible numbers and defensible analysis," Berry said.

Berry was part of a bipartisan group of Maine lawmakers that wrote a letter to Massachusetts regulators last year expressing concerns about the project, which included doubts about whether the line would actually reduce global gas emissions. On Monday, he announced legislation that would direct the state to create an independent entity to buy out CMP from its foreign investors.

'No benefit to remaining quiet'

Hydro-Quebec would like to provide answers, but "there is always a commercially sensitive information concern when we do these things," said spokesperson Abergel.

"There might be stuff we can do, having an independent study that looks at all of this. I'm not worried about the conclusion," Abergel said. "I'm worried about how long it takes."

Instead of asking Hydro-Quebec questions directly, participants in both Maine and Massachusetts regulatory proceedings have had to direct questions for Hydro-Quebec to CMP. That arrangement may be part of Hydro-Quebec's strategy to control its information, said former Maine Public Utilities Commissioner David Littell.

"From a tactical point of view, it may be more beneficial for the evidence to be put through Avangrid and CMP, which actually doesn't have that back-up info, so can't provide it," Littell said.

Getting information about the line from CMP, and its parent company Avangrid, has at times been difficult, opponents say.

In August 2018, the commission's staff warned CMP in a legal filing that it was concerned "about what appears to be a lack of completeness and timeliness by CMP/Avangrid in responding to data requests in this proceeding."

The trouble in getting information from Hydro-Quebec and CMP only creates more questions for Hydro-Quebec, said Jeremy Payne, executive director of the Maine Renewable Energy Association, which opposes the line in favor of Maine-based renewables.

"There's a few questions that should have relatively simple answers. But not answering a couple of those questions creates more questions," Payne said. "Why didn't you intervene in the docket? Why are you not a party to the case? Why won't you respond to these concerns? Why wouldn't you open yourself up to discovery?"

"I don't understand why they won't put it to bed," Payne said. "If you've got the proof to back it up, then there's no benefit to remaining quiet."

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Nation Rise Wind Farm Ruling overturns Ontario cancellation, as Superior Court finds the minister's decision unreasonable; EDP Renewables restarts 100-megawatt project near Cornwall, citing jobs, clean energy, and procedural fairness over bat habitat concerns.

Key Points

Ontario court quashes cancellation, letting EDP Renewables finish 100 MW Nation Rise project and resume clean energy.

✅ Judges call minister's decision unreasonable, unfair

✅ EDP Renewables to restart construction near Cornwall

✅ 100 MW, 29 turbines; costs awarded, appeal considered

Construction of a wind farm in eastern Ontario, as wind power makes gains nationwide, will move ahead after a court quashed a provincial government decision to cancel the project.

In a ruling released Wednesday, a panel of Ontario Superior Court judges said the province's decision to scrap the Nation Rise Wind Farm in December 2019 did not meet the proper requirements.

At the time, Environment Minister Jeff Yurek revoked the approvals of the project near Cornwall, Ont., citing the risk to three bat species.

That decision came despite a ruling from the province's Environmental Review Tribunal that determined the risk the project posed to the bat population was negligible.

The judges said the minister's decision was "unreasonable" and "procedurally unfair."

"The decision does not meet requirements of transparency, justification, and intelligibility, as the Minister has failed to adequately explain his decision," the judges wrote in their decision.

The company behind the project, EDP Renewables, said the 29-turbine wind farm was almost complete when its approval was revoked in December, even as Alberta saw TransAlta scrap a wind farm in a separate development.

The company said Thursday it plans to restart construction on the 100-megawatt wind farm.

"EDPR is eager to recommence construction of the Nation Rise Wind Farm, which will bring much-needed jobs and investment to the community," the company said in a statement. "This delay has resulted in unnecessary expenditures to-date, at a time when governments and businesses should be focused on reducing costs and restarting the economy."

A spokesman for Yurek said the government is disappointed with the outcome of the case but did not comment on a possible appeal.

"At this time, we are reviewing the decision and are carefully considering our next steps," Andrew Buttigieg said in a statement.

NDP climate change critic Peter Tabuns said the court decision is an embarrassment for the minister and the government. He urged the government not to pursue an appeal.

Yurek "was found to have ignored the evidence and the facts," he said. "They didn't just lose, their case collapsed. They had nothing to stand on. Taking this to appeal would be a complete and total waste of money."

Green party Leader Mike Schreiner said the ruling proves the government was acting based on ideology over evidence when it revoked the project's approval.

"As we shift towards a post-COVID recovery, we need the Ford government to give up the irrational crusade against affordable and reliable clean energy," Schreiner said in a statement.

Last year, the NDP revealed the province had spent $231 million to cancel more than 750 renewable energy contracts, a move Ford said he was proud of, shortly after winning the 2018 election.

The Progressive Conservatives have blamed the previous Liberal government, as leadership candidates debate how to fix power, for signing the bad energy deals while the province had an oversupply of electricity.

The Ford government, amid a new stance on wind power, has also said that by cancelling the contracts it would ultimately save ratepayers $790 million -- a figure industry officials have disputed.

At the time of the wind farm cancellation, the government also said it would introduce legislation that would protect consumers from any costs incurred, though a developer warned cancellations could exceed $100M at the time.

It has since acknowledged it will have to pay some companies to cancel the deals and set aside $231 million to reach agreements with those firms, and more recently has moved to reintroduce renewable projects in some cases.

On Wednesday, the judges awarded Nation Rise $126,500 in costs, which the government will have to pay.

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Hydro One COVID-19 Rate Relief responds to time-of-use pricing, peak rates, and Ontario Energy Board rules as residents stay home, offering a Pandemic Relief Fund, flexible payments, and support for electricity bills amid off-peak adjustments.

Key Points

Hydro One's COVID-19 rate relief includes payment flexibility and hardship aid to ease time-of-use bill burdens.

✅ Advocates flexibility on time-of-use and peak rate impacts

✅ Pandemic Relief Fund offers aid and payment options

✅ OEB sets prices; utilities relay concerns and support

Hydro One says it is listening to requests by self-isolating residents for reduced kilowatt hour peak rates during the day when most people are home riding out the COVID-19 pandemic.

Peak rates of 20.8 cents per kw/h are twice as high from 7 a.m. to 7 p.m. – except weekends – than off-peak rates of 10.1 cents per kw/h and set by the Ontario Energy Board and not electricity providers such as Hydro One and Elexicon (formerly Veridian).

Frustrated electrical customers have signed their John Henry’s more than 50,000 times to a change.org petition demanding Hydro One temporarily slash rates for those already struggling with work closures and loss of income amid concerns about a potential recovery rate that could raise bills.

Alex Stewart, media relations spokesman for Hydro One, said the corporation is working toward a solution.

“While we are regulated to adhere to time-of-use pricing by the Ontario Energy Board, we’ve heard the concerns about time-of-use pricing and the idea of a fixed COVID-19 hydro rate as many of our customers will stay home to stop the spread of COVID-19,” Stewart told The Intelligencer.

“We continue to advocate for greater choice during this difficult time and are working with everyone in the electricity sector to ensure our customers are heard.”

Stewart said the electricity provider is reaching out to customers to help them during a difficult self-isolating and social distancing period in other ways to bring financial relief.

For example, new hardship measures are now in play by Hydro One to give customers some relief from ballooning electricity bills.

“This is a difficult time for everyone. Hydro One has launched a new Pandemic Relief Fund to support customers affected by the novel coronavirus COVID-19. As part of our commitment to customers, we will offer financial assistance, as well as increased payment flexibility, to customers experiencing hardship,” Stewart said.

“Hydro One is also extending its Winter Relief program to halt disconnections and reconnections to customers experiencing hardship during the coldest months of the year. This is about doing the right thing and offering flexibility to our customers so they have peace of mind and can concentrate on what matters most – keeping their loved ones safe.”

Stewart said customers having difficult times can visit the company’s website for more details at www.HydroOne.com/ReliefFund.

Elexicon Energy, meanwhile, said earlier the former Veridian company is passing along concerns to the OEB but otherwise can’t lower the rates unless directed to do so, as occurred when the province set off-peak pricing temporarily.

Chris Mace, Elexicon corporate communications spokesperson, said, “We don’t have the authority to do that.

“The Ontario Energy Board sets the energy prices. This is in the Ministry of Energy’s hands. We at Elexicon, along with other local distribution companies (LDC), have shared this feedback with the ministry and OEB to come up with some sort of solution or alternative. But this is out of our hands. We can’t shift anything.”

He suggested residents can shift the use of higher-drawing electrical appliances to early morning before 7 or in the evening after 7 p.m. when ultra-low overnight rates may apply.

Families may want to be “mindful whether it be cooking or laundry and so on and holding off on doing those until off-peak hours take effect. We are hearing customers and we have passed along those concerns to the ministry and the OEB.”

Hydro One power tips

Certain electrical uses in the home consumer more power than others, as reflected in Ontario’s electricity cost allocation approach:

62 per cent goes to space heating
19 per cent goes to water heaters
13 per cent goes to appliances
2 per cent goes to space cooling

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Texas Electricity Market Bailout proposes securitization bonds and ERCOT-backed fees after Winter Storm Uri, spreading costs via ratepayer charges on power bills to stabilize generators, co-ops, and retailers and avert bankruptcies and investor flight.

Key Points

State plan to securitize storm debts via ERCOT fees, adding bill charges to stabilize Texas power firms.

✅ Securitization bonds finance unpaid ancillary services and energy costs

✅ ERCOT fee spreads Winter Storm Uri debts across ratepayers statewide

✅ Aims to prevent bankruptcies, preserve grid reliability, reassure investors

An approximately $2.5 billion plan to bail out Texas’ distressed electricity market from the financial crisis caused by Winter Storm Uri in February has been approved by the Texas House.

The legislation would impose a fee — likely for the next decade or longer — on electricity companies, which would then get passed on to residential and business customers in their power bills, even as some utilities waived certain fees earlier in the crisis.

House lawmakers sent House Bill 4492 to the Senate on Thursday after a 129-15 vote. A similar bill is advancing in the Senate.

Some of the state’s electricity providers and generators are financially underwater in the aftermath of the February power outages, which left millions without power and killed more than 100 people. Electricity companies had to buy whatever power was available at the maximum rate allowed by Texas regulations — $9,000 per megawatt hour — during the week of the storm (the average price for power in 2020 was $22 per megawatt hour). Natural gas fuel prices also spiked more than 700% during the storm.

Several companies are nearing default on their bills to the Electric Reliability Council of Texas, which manages the Texas power grid that covers most of the state and facilitates financial transactions in it.

Rural electric cooperatives were especially hard hit; Brazos Electric Power Cooperative, which supplies electricity to 1.5 million customers, filed for bankruptcy citing a $1.8 billion debt to ERCOT.

State Rep. Chris Paddie, R-Marshall, the bill’s author, said a second bailout bill will be necessary during the current legislative session for severely distressed electric cooperatives.

“This is a financial crisis, and it’s a big one,” James Schaefer, a senior managing director at Guggenheim Partners, an investment bank, told lawmakers at a House State Affairs Committee hearing in early April. He warned that more bankruptcies would cause higher costs to customers and hurt the state’s image in the eyes of investors.

“You’ve got to free the system,” Schaefer said. “It’s horrible that a bunch of folks have to pay, but it’s a system-wide failure. If you let a bunch of folks crash, it’s not a good look for your state.”

If approved by the Senate and Gov. Greg Abbott, a newly-created Texas Electric Securitization Corp. would use the money raised from the fees for bonds to help pay the companies’ debts, including costs for ancillary services, a financial product that helps ensure power is continuously generated and improve electricity reliability across the grid.

Paddie told his colleagues Wednesday that he could not yet estimate how long the new fee would be imposed, but during committee hearings lawmakers estimated it’s likely to be at least a decade. Several other bills to spread out the costs of the winter storm and consider market reforms are also moving through the Legislature.

ERCOT’s independent market monitor recommended in March that energy sold during that period be repriced at a lower rate, which would have allowed ERCOT to claw back about $4.2 billion in payments to power generators, but the Public Utility Commission declined to do so, even as a court ruling on plant obligations in emergencies drew scrutiny among market participants.

Instead, lawmakers are pushing for bailouts that several energy experts have said is needed, both to ensure distressed companies don’t pass enormous costs on to their customers and to prevent electricity investors and companies from leaving the state if it’s viewed as too risky to continue doing business.

Becky Klein, an energy consultant in Austin and former chair of the Public Utility Commission who played a key role in de-regulating Texas’ electricity market two decades ago, said during a retail electricity panel hosted by Integrate that legislation is necessary to provide “some kind of backstop during a crazy market crisis like this to show the financial market that we’re willing to provide some relief.”

Still, some lawmakers are concerned with how they will win public support, including potential voter-approved funding measures, for bills to bail out the state’s electricity market.

“I have to go back to Laredo and say, ‘I know you didn’t have electricity for several days, but now I’m going to make you pay a little more for the next 20 years,’” state Rep. Richard Peña Raymond, D-Laredo, said during an early April discussion on the plan in the House State Affairs Committee. He said he voted for the bill because it’s in the best interest of the state.

Paddie, during the same committee hearing, acknowledged that “none of us want to increase fees or taxes.” However, he said, “We have to deal with the reality set before us.”

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German Energy Price Brakes harness price signals in a market-based policy, cutting gas consumption, preserving industrial output, and supporting CO2 reduction, showcasing Germany's resilience and adaptation while protecting households and businesses across Europe.

Key Points

Fixed-amount subsidies preserving price signals to curb gas use, shield consumers, and sustain industrial output.

✅ Maintains incentives via market-based price signals

✅ Cuts gas consumption without distorting EU markets

✅ Protects households and industry while curbing CO2

German industry and society are once again proving much more resilient and adaptable than certain people feared. Horror scenarios of a dangerous energy rationing or a massive slump in our economy have often been bandied about. But we are nowhere near that. With a challenging year just behind us, this is good news — not only for Germany, but also for Europe, where France-Germany energy cooperation has strengthened solidarity.

Companies and households reacted swiftly to the sharp increases in energy prices, in line with momentum in the global energy transition seen across markets. They installed more efficient heating or production facilities, switched to alternatives and imported intermediate products. The results are encouraging: German households and businesses have reduced gas consumption significantly, despite recent cold weather. From the start of the war in Ukraine to mid-December industrial gas consumption in Germany was (temperature-adjusted) around 20 per cent lower than the average level for the preceding three years. Even if some firms have cut back production, especially in energy-intensive sectors, industrial output as a whole has only fallen by about 1 per cent since the start of 2022. Added to this, in a survey released by the Ifo institute in November, over a third of German companies saw the potential to reduce gas consumption further without endangering output.

Instead of imposing excessive laws and regulations, we have relied on price signals and the prudence of market participants to create the right incentives and reduce gas consumption, as falling costs like record-low solar power prices continue to reinforce those signals across sectors.

We will follow this approach in coming months, when energy savings will remain important, even as the EU electricity outlook anticipates sharply higher demand by 2050. Our latest relief measures will not distort price signals. To this end, the Bundestag approved gas and electricity price brakes in its final session in 2022. They are designed to function without any intervention in markets or prices. This system will pay out a fixed amount relative to previous years’ consumption and the current difference to a reference price — regardless of current consumption.

Energy price brakes are the main component of Germany’s “protective shield”, which makes up to €200bn available for measures in 2022 to 2024. Seen in relation to the German economy’s size, its past heavy reliance on Russian energy imports and the fact that the measures will expire in 2024, these are balanced and expedient mechanisms. In contrast to instruments used in other countries, our new arrangements will not affect the price formation process driven by supply and demand, or on incentives to save gas. Companies and households will continue to save the full market price when they reduce consumption by a unit of gas or electricity. In this way, the price brakes also avoid the creation of additional demand for gas at the expense of consumers in other European countries, even as Europe’s Big Oil turning electric signals broader structural shifts in energy markets. No one need fear that competition will be distorted or that gas will be bought up. Indeed, a recent IMF working paper on cushioning the impact of high energy prices on households explicitly praises the German energy price brakes.

Current developments confirm the effectiveness of a market-based approach — and show that we should also rely on price signals when it comes to reducing CO₂ emissions, as suggested by IEA CO2 trends in recent years. Last year, households and companies had only a few weeks to adapt, yet we have already seen a strong response. The effect of CO₂ prices can be even stronger, as adaptation is possible over a much longer time and they additionally affect expectations and long-term decisions. Regulatory interventions and subsidy schemes, even if well targeted, cannot compete with market co-ordination and incentives that support individual decision-making and promote innovation.

Europe and Germany can weather this crisis without a collapse in industrial production. We also have an opportunity to deal efficiently with the move to climate neutrality, aligned with Germany’s hydrogen strategy for imported low-carbon fuels. In both cases, we should have confidence in price signals as well as in the power of people and business to innovate and adapt.

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Ontario Electricity Grid Decarbonization outlines the IESO's net-zero pathway: $400B investment, nuclear expansion, renewables, hydrogen, storage, and demand management to double capacity by 2050 while initiating a 2027 natural gas moratorium.

Key Points

A 2050 plan to double capacity, retire gas, and invest $400B in nuclear, renewables, and storage for a net-zero grid.

✅ $400B over 25 years to meet net-zero electricity by 2050

✅ Capacity doubles to 88,000 MW; demand grows ~2% annually

✅ 2027 gas moratorium; build nuclear, renewables, storage

Ontario will need to spend $400 billion over the next 25 years in order to decarbonize the electricity grid and embrace clean power according to a new report by the province’s electricity system manager that’s now being considered by the Ford government.

The Independent System Electricity Operator (IESO) was tasked with laying out a path to reducing Ontario’s reliance on natural gas for electricity generation and what it would take to decarbonize the entire electricity grid by 2050.

Meeting the goal, the IESO concluded, will require an “aggressive” approach of doubling the electricity capacity in Ontario over the next two-and-a-half decades — from 42,000 MW to 88,000 MW — by investing in nuclear, hydrogen and wind and solar power while implementing conservation policies and managing demand.

“The process of fully eliminating emissions from the grid itself will be a significant and complex undertaking,” IESO president Lesley Gallinger said in a news release.

The road to decarbonization, the IESO said, begins with a moratorium on natural gas power generation starting in 2027 as long as the province has “sufficient, non-emitting supply” to meet the growing demands on the grid.

The approach, however, comes with significant risks.

The IESO said hydroelectric and nuclear facilities can take 10 to 15 years to build and if costs aren’t controlled the plan could drive up the price of clean electricity, turning homeowners and businesses away from electrification.

“Rapidly rising electricity costs could discourage electrification, stifle economic growth or hurt consumers with low incomes,” the report states.

The IESO said the province will need to take several “no regret” actions, including selecting sites and planning to construct new large-scale nuclear plants as well as hydroelectric and energy storage projects and expanding energy-efficiency programs beyond 2024.

READ MORE: Ontario faces calls to dramatically increase energy efficiency rebate programs

Ontario’s minister of energy didn’t immediately commit to implementing the recommendations, citing the need to consult with stakeholders first.

“I look forward to launching a consultation in the new year on next steps from today’s report, including the potential development of major nuclear, hydroelectric and transmissions projects,” Todd Smith said in a statement.

Currently, electricity demand is increasing by roughly two per cent per year, raising concerns Ontario could be short of electricity in the coming years as the manufacturing and transportation sectors electrify and as more sectors consider decarbonization.

At the same time, the province’s energy supply is facing “downward pressure” with the Pickering nuclear power plant slated to wind down operations and the Darlington nuclear generating station under active refurbishment.

To meet the energy need, the Ford government said it intended to extend the life of the Pickering plant until 2026.

READ MORE: Ontario planning to keep Pickering nuclear power station open until 2026

But to prepare for the increase, the Ontario government was told the province would also need to build new natural gas facilities to bridge Ontario’s electricity supply gap in the near term — a recommendation the Ford government agreed to.

The IESO said a request for proposals has been opened and the province is looking for host communities, with the expectation that existing facilities would be upgraded before projects on undeveloped land would be considered.

The IESO said the contract for any new facilities would expire in 2040, and all natural gas facilities would be retired in the 2040s.

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