Why daylight saving time is bad for the environment

By Toronto Star


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What if fighting climate change was as easy as not setting your clock forward?

Always sold as a conservation measure, the practice of daylight savings actually jacked electricity use in homes across one central U.S. state by up to four per cent, according to a new American study.

"If you could actually get energy savings and decrease carbon dioxide emissions just by adjusting the clock, that's certainly something we should at least consider," says Matthew Kotchen, a University of California-Santa Barbara economics professor who, together with a graduate student, combed over almost 8 million residential meter readings across Indiana to quantify the change in electricity use over three years.

The state offered a perfect case study: Up until 2006, only a handful of its counties pushed their clocks around at all. The vast majority, mostly rural farm communities where daily routines are still largely dictated by sunrise and not an electric clock, stuck stubbornly to standard time year-round. Then, two years ago, the entire state standardized their clocks and joined the daylight savings movement. That provided both a bulk of data and a control group.

The results? Instead of saving electricity and money by adding an extra hour of sunlight to evenings most of the year, it cost Indiana homes an extra $8.6 million in electricity bills – mostly from chugging air conditioners – each year. And since 95 per cent of that extra energy was generated by coal-fired power plants, that meant much more atmosphere-warming carbon dioxide was spewed into the air.

Expanded nationally, those results would translate to at least two coal-fired electricity plants pumping power just to feed the daylight savings habit.

"In Indiana, I can tell you unambiguously now, there are social and environmental costs associated with daylight savings time because of the pollution emissions and carbon dioxide emissions contributing to climate change," Kotchen says.

The irony is that daylight savings has always been promoted as an energy conservation measure; theoretically, one extra hour of natural light in the evening would erase an hour of electrical light. In 2005, when the American Congress voted to extend daylight savings by four weeks, pushing the start date back three weeks to today, it was advertised as saving Americans the equivalent of 100,000 barrels of oil daily. Ontario decided to follow suit for trade reasons.

"If we're staking our national policy on conservation on daylight savings, we're in big trouble," says Jeff Deyette, an energy analyst with the Union of Concerned Scientists in the United States. "This was one of the few victories of the energy bill of 2005 that otherwise was entirely focused on increasing supply."

The American Congress has promised to review the extension of daylight savings after the U.S. Department of Energy does an audit of its effect. Those findings should be presented by June, says department spokesperson Chris Kielich.

"If daylight saving time doesn't save energy, it's hard to find a cogent reason to continue the experiment," says Ralph Cavanagh, energy program co-director of the Natural Resources Defense Council.

Since first conceived of by Benjamin Franklin more than two centuries ago, the principle behind daylight savings has always been to save on lighting bills. But what the American inventor couldn't envision in 1784 was the rise of the power-sucking central air conditioner. In Indiana, people might not have been flipping on the lights when they returned home after work. But they were cranking their air conditioners, because that extra hour of evening sunlight meant another hour of "solar build-up on your house," says Kotchen.

"Take an hour at dawn versus an hour at sunset. When do you think you're going to run the air conditioner harder?"

Kotchen is now studying the effect of daylight savings on the rest of the country. He figures the air conditioning effect will be even more profound in southern states. And in the north, there is the opposite problem: waking up an hour earlier in the spring and fall means more time roaming around a cold house, rather than dozing under a duvet.

It likely has a similar effect in Ontario, where hot, humid summers are not unlike Indiana's, Kotchen says. On a hot summer day in Ontario, air conditioning can account for a quarter of our total electricity demand.

(A preliminary examination of the extended daylight savings hours last fall showed a very marginal reduction in electricity use – about 0.1 per cent, says Terry Young, spokesperson for the Independent Electricity System Operator, which manages Ontario's electrical system.)

Another way daylight savings might be fuelling our warming climate? Increased carbon dioxide fumes sputtering out of car tailpipes, says Michael Downing, author of Spring Forward: The Annual Madness of Daylight Saving Time. Last March's early spring forward coincided with increased gas prices at the pumps.

But the hikes had no effect on gas sales, a result dubbed by many analysts as the "daylight savings effect," he says.

"When you give people more light after work, they do go to the mall or ball park and they don't walk there. They get in their cars," says Downing, adding that in the 1930s, the petroleum industry lobbied hard to reintroduce daylight savings.

The practice was first introduced, temporarily, in the United States during World War I, and then again during World War II. In 1966, it was reintroduced across most of the United States and Canada, beginning the last Sunday in April and ending six months later in late October. Since then, it has been expanded twice.

While energy conservation has always been the window dressing, the true motivation was repeatedly economic, says Downing, who spent two years reading all the U.S. congressional and senate hearings on DST dating back to 1919.

"The most persistent lobby on behalf of daylight savings has long been retailers and merchants. If you give people more light when they leave work, they will stop and shop on their way home," says Downing, a writing professor at Tufts University.

"There is a reason we continue to get daylight savings under the rubric of energy conservation because as a policy, it costs individual consumers nothing and asks them to conserve nothing. So it's wildly popular," he says.

"Unfortunately, it's entirely ineffective."

Previous studies on daylight savings have had similar findings. But most have been based on simulation models, not concrete data. An exception was a study on the extension of daylight savings in two Australian territories for the 2000 Summer Olympic Games, which showed more electricity used.

But even that didn't dissuade the Australian government from introducing daylight savings to the western part of the country more than a year ago, says David Prerau, author of Seize the Daylight: The Curious and Contentious Story of Daylight Saving Time.

"Most people feel they are gaining an extra hour to do things in," says Prerau, adding other benefits include decreased traffic accidents, a more active population and a boost to the economy. "There's a lot of benefits that generally outweigh the negatives. Energy is just one of the impact areas."

A broader study would be needed to convince even Ontario's chief conservation officer, Peter Love, to include ending the practice in his campaigns to cut back Ontario's electricity usage. "Ontario, quite frankly, is not doing this for energy efficiency reasons," Love says. "We did it to be in sync with our major trading partner to the south," he says. "It's not something I'd want to do alone."

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U.S. Department of Energy Announces $110M for Carbon Capture, Utilization, and Storage

DOE CCUS Funding advances carbon capture, utilization, and storage with FEED studies, regional deployment, and CarbonSAFE site characterization, leveraging 45Q tax credits to scale commercial CO2 reduction across fossil energy sectors.

 

Key Points

DOE CCUS Funding are federal FOAs for commercial carbon capture, storage, and utilization via FEED and CarbonSAFE.

✅ $110M across FEED, Regional, and CarbonSAFE FOAs

✅ Supports Class VI permits, NEPA, and site characterization

✅ Enables 45Q credits and enhanced oil recovery utilization

 

The U.S. Department of Energy’s (DOE’s) Office of Fossil Energy (FE) has announced approximately $110 million in federal funding for cost-shared research and development (R&D) projects under three funding opportunity announcements (FOAs), alongside broader carbon-free electricity investments across the power sector.

Approximately $75M is for awards selected under two FOAs announced earlier this fiscal year; $35M is for a new FOA.

These FOAs further the Administration’s commitment to strengthening coal while protecting the environment. Carbon capture, utilization, and storage (CCUS) is increasingly becoming widely accepted as a viable option for fossil-based energy sources—such as coal- or gas-fired power plants under new EPA power plant rules and other industrial sources—to lower their carbon dioxide (CO2) emissions.

DOE’s program has successfully deployed various large-scale CCUS pilot and demonstration projects, and it is imperative to build upon these learnings to test, mature, and prove CCUS technologies at the commercial scale. A recent study by Science of the Total Environment found that DOE is the most productive organization in the world in the carbon capture and storage field.

“This Administration is committed to providing cost-effective technologies to advance CCUS around the world,” said Secretary Perry. “CCUS technologies are vital to ensuring the United States can continue to safely use our vast fossil energy resources, and we are proud to be a global leader in this field.”

“CCUS technologies have transformative potential,” said Assistant Secretary for Fossil Energy Steven Winberg. “Not only will these technologies allow us to utilize our fossil fuel resources in an environmentally friendly manner, but the captured CO2 can also be utilized in enhanced oil recovery and emerging CO2-to-electricity concepts, which would help us maximize our energy production.”

Under the first FOA award, Front-End Engineering Design (FEED) Studies for Carbon Capture Systems on Coal and Natural Gas Power Plants, DOE has selected nine projects to receive $55.4 million in federal funding for cost-shared R&D. The selected projects will support FEED studies for commercial-scale carbon capture systems. Find project descriptions HERE. 

Under the second FOA award, Regional Initiative to Accelerate CCUS Deployment, DOE selected four projects to receive up to $20 million in federal funding for cost-shared R&D. The projects also advance existing research and development by addressing key technical challenges; facilitating data collection, sharing, and analysis; evaluating regional infrastructure, including CO2 storage hubs and pipelines; and promoting regional technology transfer. Additionally, this new regional initiative includes newly proposed regions or advanced efforts undertaken by the previous Regional Carbon Sequestration Partnerships (RCSP) Initiative. Find project descriptions HERE. 

Elsewhere in North America, provincial efforts such as Quebec's and industry partners like Cascades are investing in energy efficiency projects to complement emissions-reduction goals.

Under the new FOA, Carbon Storage Assurance Facility Enterprise (CarbonSAFE): Site Characterization and CO2 Capture Assessment, DOE is announcing up to $35 million in federal funding for cost-shared R&D projects that will accelerate wide-scale deployment of CCUS through assessing and verifying safe and cost-effective anthropogenic CO2 commercial-scale storage sites, and carbon capture and/or purification technologies. These types of projects have the potential to take advantage of the 45Q tax credit, bolstered by historic U.S. climate legislation, which provides a tax credit for each ton of CO2 sequestered or utilized. The credit was recently increased to $35/metric ton for enhanced oil recovery and $50/metric ton for geologic storage.

Projects selected under this new FOA shall perform the following key activities: complete a detailed site characterization of a commercial-scale CO2 storage site (50 million metric tons of captured CO2 within a 30 year period); apply and obtain an underground injection control class VI permit to construct an injection well; complete a CO2capture assessment; and perform all work required to obtain a National Environmental Policy Act determination for the site.

 

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Two new electricity interconnectors planned for UK

Ofgem UK Electricity Interconnectors will channel subsea cables, linking Europe, enabling energy import/export, integrating offshore wind via multiple-purpose interconnectors, boosting grid stability, capacity, and investment under National Grid analysis to 2030 targets.

 

Key Points

Subsea links between the UK and Europe that trade power, integrate offshore wind, and reinforce grid capacity.

✅ Two new subsea interconnector bids open in 2025

✅ Pilot for multiple-purpose links to offshore wind clusters

✅ National Grid to assess optimal routes, capacity, and locations

 

Ofgem has opened bids to build two electricity interconnectors between the UK and continental Europe as part of the broader UK grid transformation now underway.

The energy regulator said this would “bring forward billions of pounds of investment” in the subsea cables, such as the Lake Erie Connector, which can import cheaper energy when needed and export surplus power from the UK when it is available.

Developers will be invited to submit bids to build the interconnectors next year. Ofgem will additionally run a pilot scheme for ‘multiple-purpose interconnectors’, which are used to link clusters of offshore wind farms and related innovations like an offshore vessel chargepoint to an interconnector.

This forms part of the UK Government drive to more than double capacity by 2030, and to manage rising electric-vehicle demand, as discussed in EV grid impacts, in support of its target of quadrupling offshore wind capacity by the same date.

Interconnectors provide some 7 per cent of UK electricity demand. The UK so far has seven electricity interconnectors linked to Ireland, France, Belgium, the Netherlands and Norway, while projects like the Ireland-France connection illustrate broader European grid integration.

Balfour Beatty won a £90m contract for onshore civil engineering works on the Viking Link Norway interconnector, which is due to come into operation in 2023, while London Gateway's all-electric berth highlights related port electrification.

It said that interconnector developers have in the past been allowed to propose their preferred design, connection location and sea route to the connecting country. Ofgem has now said it may decide to consider only those projects that meet its requirements based on an analysis of location and capacity needs by National Grid.

Ofgem has not specified that the new interconnectors must link to any specific place or country, but may do so later, as priorities like the Cyprus electricity highway illustrate emerging directions.

 

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Electricity prices rise more than double EU average in first half of 2021

Estonia energy prices 2021 show sharp electricity hikes versus the EU average, mixed natural gas trends, kWh tariffs on Nord Pool spiking, and VAT, taxes, and support measures shaping household bills.

 

Key Points

EU-high electricity growth, early gas dip, then Nord Pool spikes; taxes, VAT, and subsidies shaped energy bills.

✅ Electricity up 7% on year; EU average 2.8% in H1 2021.

✅ Gas fell 1% in H1; later spiked with global market.

✅ VAT, taxes, excise and aid impacted household costs.

 

Estonia saw one of the highest rates in growth of electricity prices in the first half of 2021, compared with the same period in key trends in 2020 across Europe. These figures were posted before the more recent, record level of electricity and natural gas prices; the latter actually dropped slightly in Estonia in the first half of the year.

While electricity prices rose 7 percent on year in the first half of 2021 in Estonia, the average for the EU as a whole, where energy prices drove inflation across the bloc, stood at 2.8 percent over the same period, BNS reports.

Hungary (€10 per 100 Kwh) and Bulgaria (€10.20 per 100 Kwh) saw the lowest electricity prices EU-wide, while at €31.9 per KWH, Germany's power prices posted the most expensive rate, while Denmark, Belgium and Ireland also had high prices, in excess of €25 per Kwh.

Slovenia saw the highest electricity price rise, at 15 percent, and even the United States' electricity prices saw their steepest rise in decades during the same era, while Estonia was in third place, joint with Romania at 7 percent as noted, and behind Poland (8 percent).

Lithuania, on the other hand, experienced the third highest electricity price fall over the first half of 2021, compared with the same period in 2020, at 6 percent, behind only Cyprus (7 percent) and the Netherlands (10 percent, largely due to a tax cut).

Urmas Reinsalu: VAT on electricity, gas and heating needs to be lowered
The EU average price of electricity was €21.9 percent per Kwh, with taxes and excise accounting for 39 percent of this, even as prices in Spain surged across the day-ahead market.

Estonia has also seen severe electricity price rises in the second half of the year so far, with records set and then promptly broken several times earlier in October, while an Irish electricity provider raised prices amid similar pressures, and a support package for low income households rolled out for the winter season (October to March next year). The price on the Nord Pool market as of €95.01 per Kwh; a day earlier it had stood at €66.21 per Kwh, while on October 19 the price was €140.68 per Kwh.

Gas prices
Natural gas prices to household, meanwhile, dropped in Estonia over the same period, at a sharper rate (1 percent) than the EU average (0.5 percent), according to Eurostat.

Gas prices across the EU were lowest in Lithuania (€2.8 per 100 Kwh) and highest in the Netherlands (€9.6 per KWH), while the highest growth was seen in Denmark (19 percent), in the first half of 2021.

Natural gas prices dropped in 20 member states, however, with the largest drop again coming in Lithuania (23 percent).

The average price of natural gas EU-side in the first half of 2021 was €6.4, and taxes and excise duties accounted on average for 36 percent of the total.

The second half of the year has seen steep gas price rises in Estonia, largely the result of increases on the world market, though European gas benchmarks later fell to pre-Ukraine war levels.

 

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UK Anticipates a 16% Decrease in Energy Bills in April

UK Energy Price Cap Cut 2024 signals relief as wholesale gas prices fall; Ofgem price cap drops per Cornwall Insight, aided by LNG supply, mild winter, despite Red Sea tensions and Ukraine conflict impacts.

 

Key Points

A forecast cut to Great Britain's Ofgem price cap as wholesale gas falls, easing typical annual household bills in 2024.

✅ Cap falls from £1,928 to £1,620 in April 2024

✅ Forecast £1,497 in July, then about £1,541 from October

✅ Drivers: lower wholesale gas, LNG supply, mild winter

 

Households in Great Britain are set to experience a significant reduction in energy costs this spring, with bills projected to drop by over £300 annually. This decrease is primarily due to a decline in wholesale gas prices, offering some respite to those grappling with the cost of living crisis.

Cornwall Insight, a well-regarded industry analyst, predicts a 16% reduction in average bills from the previous quarter, potentially reaching the lowest levels since the onset of the Ukraine conflict.

The industry’s price cap, indicative of the average annual bill for a typical household, is expected to decrease from the current £1,928, set earlier this month, to £1,620 in April – a reduction of £308 and £40 less than previously forecasted in December, as ministers consider ending the gas-electricity price link to improve market resilience.

Concerns about escalating tensions in the Red Sea, where Houthi rebels have disrupted global shipping, initially led analysts to fear an increase in wholesale oil prices and subsequent impact on household energy costs.

Contrary to these concerns, oil prices have remained relatively stable, and European gas reserves have been higher than anticipated during a mild winter, with European gas prices returning to pre-Ukraine war levels since November.

Cornwall Insight anticipates that energy prices will continue to be comparatively low through 2024. They predict a further decline to £1,497 for a typical annual bill from July, followed by a slight increase to £1,541 starting in October.

This forecast is a welcome development for Britons who have been dealing with increased expenses across various sectors, from food to utilities, amidst persistently high inflation rates, with energy-driven EU inflation hitting lower-income households hardest across member states.

Energy bills saw a steep rise in 2021, which escalated further due to the Ukraine conflict in 2022, driving up wholesale gas prices. This surge prompted government intervention to subsidize bills, with the UK price cap estimated to cost around £89bn to the public purse, capping costs to a typical household at £2,500.

Cornwall Insight noted that the supply of liquified natural gas to Europe had not been as adversely affected by the Red Sea disruptions as initially feared. Moreover, the UK has been well-supplied with gas from the US, which has become a more significant supplier since the Ukraine war, even as US electricity prices have risen to multi-decade highs. Contributing factors also include lower gas prices in Asia, mild weather, and robust gas availability.

Craig Lowrey, a principal consultant at Cornwall Insight, remarked that concerns about Red Sea events driving up energy prices have not materialized, allowing households to expect a reduction in prices.

On Monday, the next-month wholesale gas price dropped by 4% to 65p a therm.

However, Lowrey cautioned that a complete return to pre-crisis energy bill levels remains unlikely due to ongoing market impacts from shifting away from Russian energy sources and persistent geopolitical tensions, as well as policy changes such as Britain’s Energy Security Bill shaping market reforms.

Richard Neudegg, director of regulation at Uswitch, welcomed the potential further reduction of the price cap in April. However, he pointed out that this offers little solace to households currently struggling with high winter energy costs during the winter. Neudegg urged Ofgem, the energy regulator, to prompt suppliers to reintroduce more competitive and affordable fixed-price deals.

 

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For Hydro-Québec, selling to the United States means reinventing itself

Hydro-Quebec hydropower exports deliver low-carbon electricity to New England, sparking debate on greenhouse gas accounting, grid attributes, and REC-style certificates as Quebec modernizes monitoring to verify emissions, integrate renewables, and meet ambitious climate targets.

 

Key Points

Low-carbon electricity to New England, with improved emissions tracking and verifiable grid attributes.

✅ Deep, narrow reservoirs cut lifecycle GHGs in cold boreal waters

✅ Attribute certificates trace source, type, and carbon intensity

✅ Contracts require facility-level tagging for compliance

 

For 40 years, through the most vicious interprovincial battles, even as proposals for bridging the Alberta-B.C. gap aimed to improve grid resilience, Canadians could agree on one way Quebec is undeniably superior to the rest of the country.

It’s hydropower, and specifically the mammoth dam system in Northern Quebec that has been paying dividends since it was first built in the 70s. “Quebec continues to boast North America’s lowest electricity prices,” was last year’s business-as-usual update in one trade publication, even as Newfoundland's rate strategy seeks relief for consumers.

With climate crisis looming, that long-ago decision earns even more envy and reflects Canada's electricity progress across the grid today. Not only do they pay less, but Quebeckers also emit the least carbon per capita of any province.

It may surprise most Canadians, then, to hear how most of New England has reacted to the idea of being able to buy permanently into Quebec’s power grid.

​​​​​​Hydro-Québec’s efforts to strike major export deals have been rebuffed in the U.S., by environmentalists more than anyone. They question everything about Quebec hydropower, including asking “is it really low-carbon?”

These doubts may sound nonsensical to regular Quebeckers. But airing them has, in fact, pushed Hydro-Québec to learn more about itself and adopt new technology.

We know far more about hydropower than we knew 40 years ago, including whether it’s really zero-emission (it’s not), how to make it as close to zero-emission as possible, and how to account for it as precisely as new clean energies like solar and wind, underscoring how cleaning up Canada's electricity is vital to meeting climate pledges.

The export deals haven’t gone through yet, but they’ve already helped drag Hydro-Québec—roughly the fourth-biggest hydropower system on the planet—into the climate era.

Fighting to export
One of the first signs of trouble for Quebec hydro was in New Hampshire, almost 10 years ago. People there began pasting protest signs on their barns and buildings. One citizens’ group accused Hydro of planning a “monstrous extension cord” across the state.

Similar accusations have since come from Maine, Massachusetts and New York.

The criticism isn’t coming from state governments, which mostly want a more permanent relationship with Hydro-Québec. They already rely on Quebec power, but in a piecemeal way, topping up their own power grid when needed (with the exception of Vermont, which has a small permanent contract for Quebec hydropower).

Last year, Quebec provided about 15 percent of New England’s total power, plus another substantial amount to New York, which is officially not considered to be part of New England, and has its own energy market separate from the New England grid.

Now, northeastern states need an energy lynch pin, rather than a top-up, with existing power plants nearing the end of their lifespans. In Massachusetts, for example, one major nuclear plant shut down this year and another will be retired in 2021. State authorities want a hydro-based energy plan that would send $10 billion to Hydro-Québec over 20 years.

New England has some of North America’s most ambitious climate goals, with every state in the region pledging to cut emissions by at least 80 percent over the next 30 years.

What’s the downside? Ask the citizens’ groups and nonprofits that have written countless op-eds, organized petitions and staged protests. They argue that hydropower isn’t as clean as cutting-edge clean energy such as solar and wind power, and that Hydro-Québec isn’t trying hard enough to integrate itself into the most innovative carbon-counting energy system. Right as these other energy sources finally become viable, they say, it’s a step backwards to commit to hydro.

As Hydro-Québec will point out, many of these critics are legitimate nonprofits, but others may have questionable connections. The Portland Press Herald in Maine reported in September 2018 that a supposedly grassroot citizens’ group called “Stand Up For Maine” was actually funded by the New England Power Generators Association, which is based in Boston and represents such power plant owners as Calpine Corp., Vistra Energy and NextEra Energy.

But in the end, that may not matter. Arguably the biggest motivator to strike these deals comes not from New England’s needs, but from within Quebec. The province has spent more than $10 billion in the last 15 years to expand its dam and reservoir system, and in order to stay financially healthy, it needs to double its revenue in the next 10 years—a plan that relies largely on exports.

With so much at stake, it has spent the last decade trying to prove it can be an energy of the future.

“Learning as you go”
American critics, justified or not, have been forcing advances at Hydro for a long time.

When the famously huge northern Quebec hydro dams were built at James Bay—construction began in the early 1970s—the logic was purely economic. The term “climate change” didn’t exist. The province didn’t even have an environment department.

The only reason Quebec scientists started trying to measure carbon emissions from hydro reservoirs was “basically because of the U.S.,” said Alain Tremblay, a senior environmental advisor at Hydro Quebec.


Alain Tremblay, senior environmental advisor at Hydro-Québec. Photograph courtesy of Hydro-Québec
In the early 1990s, Hydro began to export power to the U.S., and “because we were a good company in terms of cost and efficiency, some Americans didn't like that,” he said—mainly competitors, though he couldn’t say specifically who. “They said our reservoirs were emitting a lot of greenhouse gases.”

The detractors had no research to back up that claim, but Hydro-Québec had none to refute it, either, said Tremblay. “At that time we didn’t have any information, but from back-of-the envelope calculations, it was impossible to have the emissions the Americans were expecting we have.”

So research began, first to design methods to take the measurements, and then to carry them out. Hydro began a five-year project with a Quebec university.

It took about 10 years to develop a solid methodology, Tremblay said, with “a lot of error and learning-as-you-go.” There have been major strides since then.

“Twenty years ago we were taking a sample of water, bringing it back to the lab and analyzing that with what we call a gas chromatograph,” said Tremblay. “Now, we have an automated system that can measure directly in the water,” reading concentrations of CO2 and methane every three hours and sending its data to a processing centre.

The tools Hydro-Québec uses are built in California. Researchers around the world now follow the same standard methods.

At this point, it’s common knowledge that hydropower does emit greenhouse gases. Experts know these emissions are much higher than previously thought.

Workers on the Eastmain-1 project environmental monitoring program. Photography courtesy of Alain Tremblay.
​But Hydro-Québec now has the evidence, also, to rebut the original accusations from the early 1990s and many similar ones today.

“All our research from Université Laval [found] that it’s about a thousand years before trees decompose in cold Canadian waters,” said Tremblay.

Hydro reservoirs emit greenhouse gases because vegetation and sometimes other biological materials, like soil runoff, decay under the surface.

But that decay depends partly on the warmth of the water. In tropical regions, including the southern U.S., hydro dams can have very high emissions. But in boreal zones like northern Quebec (or Manitoba, Labrador and most other Canadian locations with massive hydro dams), the cold, well-oxygenated water vastly slows the process.

Hydro emissions have “a huge range,” said Laura Scherer, an industrial ecology professor at Leiden University in the Netherlands who led a study of almost 1,500 hydro dams around the world.

“It can be as low as other renewable energy sources, but it can also be as high as fossil fuel energy,” in rare cases, she said.

While her study found that climate was important, the single biggest factor was “sizing and design” of each dam, and specifically its shape, she said. Ideally, hydro dams should be deep and narrow to minimize surface area, perhaps using a natural valley.

Hydro-Québec’s first generation of dams, the ones around James Bay, were built the opposite way—they’re wide and shallow, infamously flooding giant tracts of land.


Alain Tremblay, senior environmental advisor at Hydro-Québec testing emission levels. Photography courtesy of Alain Tremblay
Newly built ones take that new information into account, said Tremblay. Its most recent project is the Romaine River complex, which will eventually include four reservoirs near Quebec’s northeastern border with Labrador. Construction began in 2016.

The site was picked partly for its topography, said Tremblay.

“It’s a valley-type reservoir, so large volume, small surface area, and because of that there’s a pretty limited amount of vegetation that’s going to be flooded,” he said.

There’s a dramatic emissions difference with the project built just before that, commissioned in 2006. Called Eastmain, it’s built near James Bay.

“The preliminary results indicate with the same amount of energy generated [by Romaine] as with Eastmain, you’re going to have about 10 times less emissions,” said Tremblay.

Tracing energy to its source
These signs of progress likely won’t satisfy the critics, who have publicly argued back and forth with Hydro about exactly how emissions should be tallied up.

But Hydro-Québec also faces a different kind of growing gap when it comes to accounting publicly for its product. In the New England energy market, a sophisticated system “tags” all the energy in order to delineate exactly how much comes from which source—nuclear, wind, solar, and others—and allows buyers to single out clean power, or at least the bragging rights to say they bought only clean power.

Really, of course, it’s all the same mix of energy—you can’t pick what you consume. But creating certificates prevents energy producers from, in worst-case scenarios, being able to launder regular power through their clean-power facilities. Wind farms, for example, can’t oversell what their own turbines have produced.

What started out as a fraud prevention tool has “evolved to make it possible to also track carbon emissions,” said Deborah Donovan, Massachusetts director at the Acadia Center, a climate-focused nonprofit.

But Hydro-Québec isn’t doing enough to integrate itself into this system, she says.

It’s “the tool that all of our regulators in New England rely on when we are confirming to ourselves that we’ve met our clean energy and our carbon goals. And…New York has a tool just like that,” said Donovan. “There isn’t a tracking system in Canada that’s comparable, though provinces like Nova Scotia are tapping the Western Climate Initiative for technical support.”

Hydro Quebec Chénier-Vignan transmission line crossing the Outaouais river. Photography courtesy of Hydro-Québec
Developing this system is more a question of Canadian climate policy than technology.

Energy companies have long had the same basic tracking device—a meter, said Tanya Bodell, a consultant and expert in New England’s energy market. But in New England, on top of measuring “every time there’s a physical flow of electricity” from a given source, said Bodell, a meter “generates an attribute or a GIS certificate,” which certifies exactly where it’s from. The certificate can show the owner, the location, type of power and its average emissions.

Since 2006, Hydro-Québec has had the ability to attach the same certificates to its exports, and it sometimes does.

“It could be wind farm generation, even large hydro these days—we can do it,” said Louis Guilbault, who works in regulatory affairs at Hydro-Québec. For Quebec-produced wind energy, for example, “I can trade those to whoever’s willing to buy it,” he said.

But, despite having the ability, he also has the choice not to attach a detailed code—which Hydro doesn’t do for most of its hydropower—and to have it counted instead under the generic term of “system mix.”

Once that hydropower hits the New England market, the administrators there have their own way of packaging it. The market perhaps “tries to determine emissions, GHG content,” Guilbault said. “They have their own rules; they do their own calculations.”

This is the crux of what bothers people like Donovan and Bodell. Hydro-Québec is fully meeting its contractual obligations, since it’s not required to attach a code to every export. But the critics wish it would, whether by future obligation or on its own volition.

Quebec wants it both ways, Donovan argued; it wants the benefits of selling low-emission energy without joining the New England system of checks and balances.

“We could just buy undifferentiated power and be done with it, but we want carbon-free power,” Donovan said. “We’re buying it because of its carbon content—that’s the reason.”

Still, the requirements are slowly increasing. Under Hydro-Québec’s future contract with Massachusetts (which still has several regulatory steps to go through before it’s approved) it’s asked to sell the power’s attributes, not just the power itself. That means that, at least on paper, Massachusetts wants to be able to trace the energy back to a single location in Quebec.

“It’s part of the contract we just signed with them,” said Guilbault. “We’re going to deliver those attributes. I’m going to select a specific hydro facility, put the number in...and transfer that to the buyers.”

Hydro-Québec says it’s voluntarily increasing its accounting in other ways. “Even though this is not strictly required,” said spokeswoman Lynn St. Laurent, Hydro is tracking its entire output with a continent-wide registry, the North American Renewables Registry.

That registry is separate from New England’s, so as far as Bodell is concerned, the measure doesn’t really help. But she and others also expect the entire tracking system to grow and mature, perhaps integrating into one. If it had been created today, in fact, rather than in the 1990s, maybe it would use blockchain technology rather than a varied set of administrators, she said.

Counting emissions through tracking still has a long way to go, as well, said Donovan, and it will increasingly matter in Canada's race to net-zero as standards tighten. For example, natural gas is assigned an emissions number that’s meant to reflect the emissions when it’s consumed. But “we do not take into account what the upstream carbon emissions are through the pipeline leakage, methane releases during fracking, any of that,” she said.

Now that the search for exactitude has begun, Hydro-Québec won’t be exempt, whether or not Quebeckers share that curiosity. “We don’t know what Hydro-Québec is doing on the other side of the border,” said Donovan.

 

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Powering Towards Net Zero: The UK Grid's Transformation Challenge

UK Electricity Grid Investment underpins net zero, reinforcing transmission and distribution networks to integrate wind, solar, EV charging, and heat pumps, while Ofgem balances investor returns, debt risks, price controls, resilience, and consumer bills.

 

Key Points

Capital to reinforce grids for net zero, integrating wind, solar, EVs and heat pumps while balancing returns and bills.

✅ 170bn-210bn GBP by 2050 to reinforce cables, pylons, capacity.

✅ Ofgem to add investability metric while protecting consumers.

✅ Integrates wind, solar, EVs, heat pumps; manages grid resilience.

 

Prime Minister Sunak's recent upgrade to his home's electricity grid, designed to power his heated swimming pool, serves as a microcosm of a much larger challenge facing the UK: transforming the nation's entire electricity network for net zero emissions, amid Europe's electrification push across the continent.

This transition requires a monumental £170bn-£210bn investment by 2050, earmarked for reinforcing and expanding onshore cables and pylons that deliver electricity from power stations to homes and businesses. This overhaul is crucial to accommodate the planned switch from fossil fuels to clean energy sources - wind and solar farms - powering homes with electric cars, as EV demand on the grid rises, and heat pumps.

The UK government's Climate Change Committee warns of potentially doubled electricity demand by 2050, the target date for net zero, even though managing EV charging can ease local peaks. This translates to a significant financial burden for companies like National Grid, SSE, and Scottish Power who own the main transmission networks and some regional distribution networks.

Balancing investor needs for returns and ensuring affordable energy bills for consumers presents a delicate tightrope act for regulators like Ofgem. The National Audit Office criticized Ofgem in 2020 for allowing network owners excessive returns, prompting concerns about potential bill hikes, especially after lessons from 2021 reshaped market dynamics.

Think-tank Common Wealth reported that distribution networks paid out a staggering £3.6bn to their owners between 2017 and 2021, raising questions about the balance between profitability and affordability, amid UK EV affordability concerns among consumers.

However, Ofgem acknowledges the need for substantial investment to finance network upgrades, repairs, and the clean energy transition. To this end, they are considering incorporating an "investability" metric, recognizing how big battery rule changes can erode confidence elsewhere, in the next price controls for transmission networks, ensuring these entities remain attractive for equity fundraising without overburdening consumers.

This proposal, while welcomed by the industry, has drawn criticism from consumer advocacy groups like Citizens Advice, who fear it could contribute to unfairly high bills. With energy bills already hitting record highs, public trust in the net-zero transition hinges on ensuring affordability.

High debt levels and potential credit rating downgrades further complicate the picture, potentially impacting companies' ability to raise investment funds. Ofgem is exploring measures to address this, such as stricter debt structure reporting requirements for regional distribution companies.

Lawrence Slade, CEO of the Energy Networks Association, emphasizes the critical role of investment in achieving net zero. He highlights the need for "bold" policies and regulations that balance ambitious goals with investor confidence and ensure efficient resource allocation, drawing on B.C.'s power supply challenges as a cautionary example.

The challenge lies in striking a delicate balance between attracting investment, ensuring network resilience, and maintaining affordable energy bills. As Andy Manning from Citizens Advice warns, "Without public confidence, net zero won't be delivered."

The UK's journey to net zero hinges on navigating this complex landscape. By carefully calibrating regulations, fostering investor confidence, and prioritizing affordability, the country can ensure its electricity grid is not just robust enough to power heated swimming pools, but also a thriving green economy for all.

 

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