Symantec Proves Russian


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Dragonfly energy sector cyberattacks target ICS and SCADA across critical infrastructure, including the power grid and nuclear facilities, using spearphishing, watering-hole sites, supply-chain compromises, malware, and VPN exploits to gain operational access.

 

Key Points

Dragonfly APT campaigns target energy firms and ICS to gain grid access, risking manipulation and service disruption.

✅ Breaches leveraged spearphishing, watering-hole sites, and supply chains.

✅ Targeted ICS, SCADA, VPNs to pivot into operational networks.

✅ Aimed to enable power grid manipulation and potential outages.

 

An October, 2017 report by researchers at Symantec Corp., cited by the U.S. government, has linked recent US power grid cyber attacks to a group of hackers it had code-named "Dragonfly", and said it found evidence critical infrastructure facilities in Turkey and Switzerland also had been breached.

The Symantec researchers said an earlier wave of attacks by the same group starting in 2011 was used to gather intelligence on companies and their operational systems. The hackers then used that information for a more advanced wave of attacks targeting industrial control systems that, if disabled, leave millions without power or water.

U.S. intelligence officials have long been concerned about the security of the country’s electrical grid. The recent attacks, condemned by the U.S. government, striking almost simultaneously at multiple locations, are testing the government’s ability to coordinate an effective response among several private utilities, state and local officials, and industry regulators.

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While the core of a nuclear generator is heavily protected, a sudden shutdown of the turbine can trigger safety systems. These safety devices are designed to disperse excess heat while the nuclear reaction is halted, but the safety systems themselves may be vulnerable to attack.

The operating systems at nuclear plants also tend to be legacy controls built decades ago and don’t have digital control systems that can be exploited by hackers.

“Since at least March 2016, Russian government cyber actors… targeted government entities and multiple U.S. critical infrastructure sectors, including the energy, nuclear, commercial facilities, water, aviation, and critical manufacturing sectors,” according to Thursday’s FBI and Department of Homeland Security report. The report did not say how successful the attacks were or specify the targets, but said that the Russian hackers “targeted small commercial facilities’ networks where they staged malware, conducted spearphishing, and gained remote access into energy sector networks.” At least one target of a string of infrastructure attacks last year was a nuclear power facility in Kansas.

Symantec doesn’t typically point fingers at particular nations in its research on cyberattacks, said Eric Chien, technical director of Symantec’s Security Technology and Response division, though he said his team doesn’t see anything it would disagree with in the new federal report. The government report appears to corroborate Symantec’s research, showing that the hackers had penetrated computers and accessed utility control rooms that would let them directly manipulate power systems, he says.

“There were really no more technical hurdles for them to do something like flip off the power,” he said.

And as for the group behind the attacks, Chien said it appears to be relatively dormant for now, but it has gone quiet in the past only to return with new hacks.

“We expect they’re sort of retooling now, and they likely will be back,”

 


 

In some cases, Dragonfly successfully broke into the core systems that control US and European energy companies, Symantec revealed.

“The energy sector has become an area of increased interest to cyber-attackers over the past two years,” Symantec said in its report.

“Most notably, disruptions to Ukraine’s power system in 2015 and 2016 were attributed to a cyberattack and led to power outages affecting hundreds of thousands of people. In recent months, there have also been media reports of attempted attacks on the electricity grids in some European countries, as well as reports of companies that manage nuclear facilities in the US being compromised by hackers.

“The Dragonfly group appears to be interested in both learning how energy facilities operate and also gaining access to operational systems themselves, to the extent that the group now potentially has the ability to sabotage or gain control of these systems should it decide to do so. Symantec customers are protected against the activities of the Dragonfly group.”

In recent weeks, senior US intelligence officials said that the Kremlin believes it can launch hacking operations against the West with impunity, including a cyber weapon that can disrupt power grids, according to assessments.

The DHS and FBI report further elaborated: “This campaign comprises two distinct categories of victims: staging and intended targets. The initial victims are peripheral organisations such as trusted third-party suppliers with less-secure networks, referred to as ‘staging targets’ throughout this alert.

“The threat actors used the staging targets’ networks as pivot points and malware repositories when targeting their final intended victims. National Cybersecurity and Communications Integration Center and FBI judge the ultimate objective of the actors is to compromise organisational networks, also referred to as the ‘intended target’.”

According to the US alert, hackers used a variety of attack methods, including spear-phishing emails, watering-hole domains, credential gathering, open source and network reconnaissance, host-based exploitation, and deliberate targeting of ICS infrastructure.

The attackers also targeted VPN software and used password cracking tools.

Once inside, the attackers downloaded tools from a remote server and then carried out a number of actions, including modifying key systems to store plaintext credentials in memory, and built web shells to gain command and control of targeted systems.

“This actors’ campaign has affected multiple organisations in the energy, nuclear, water, aviation, construction and critical manufacturing sectors, with hundreds of victims across the U.S. power grid confirmed,” the DHS said, before outlining a number of steps that IT managers in infrastructure organisations can take to cleanse their systems and defend against Russian hackers. he said.
 

 

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EVs could drive 38% rise in US electricity demand, DOE lab finds

EV-Driven Electricity Demand Growth will reshape utilities through electrification, EV adoption, grid modernization, and ratebasing of charging, as NREL forecasts rising terawatt-hours, CAGR increases, and demand-side flexibility to manage emissions and reliability.

 

Key Points

Growth in power consumption fueled by EV adoption and electrification, increasing utility sales and grid investment.

✅ NREL projects 20%-38% higher U.S. load by 2050

✅ Utilities see CAGR up to 1.6% and 80 TWh/year growth

✅ Demand-side flexibility and EV charging optimize grids

 

Utilities have struggled with flat demand for years, but analysis by the National Renewable Energy Laboratory predicts steady growth across the next three decades — largely driven by the adoption of electric vehicles, including models like the Tesla Model 3 that are reshaping expectations.

The study considers three scenarios, a reference case and medium- and high-adoption electrification predictions. All indicate demand growth, but in the medium and high scenarios for 2050, U.S. electricity consumption increases by 20% and 38%, respectively, compared to business as usual.

Utilities could go from stagnant demand to compound annual growth rates of 1.6%, which would amount to sustained absolute growth of 80 terawatt-hours per year.

"This unprecedented absolute growth in annual electricity consumption can significantly alter supply-side infrastructure development requirements," the report says, and could challenge state power grids in multiple regions.

NREL's Trieu Mai, principal investigator for the study, cautions that more research is needed to fully assess the drivers and impacts of electrification, "as well as the role and value of demand-side flexibility."

"Although we extensively and qualitatively discuss the potential drivers and barriers behind electric technology adoption in the report, much more work is needed to quantitatively understand these factors," Mai said in a statement.

However, utilities have largely bought into the dream.

"Electric vehicles are the biggest opportunity we see right now," Energy Impact Partners CEO Hans Kobler told Utility Dive. And the impact could go beyond just higher kilowattt-hour sales, particularly as electric truck fleets come online.

"When the transportation sector is fully electrified, it will result in around $6 trillion in investment," Kobler said. "Half of that is on the infrastructure side of the utility." And the industry can also benefit through ratebasing charging stations and managing the new demand.

One benefit that NREL's report points to is the possibility of "expanded value streams enabled by electric and/or grid-connected technologies," such as energy storage and mobile chargers that enhance flexibility.

"Many electric utilities are carefully watching the trend toward electrification, as it has the potential to increase sales and revenues that have stagnated or fallen over the past decade," the report said, highlighting potential benefits for all customers as adoption grows. "Beyond power system planning, other motivations to study electrification include its potential to impact energy security, emissions, and innovation in electrical end-use technologies and overall efficient system integration. The impacts of electrification could be far-reaching and have benefits and costs to various stakeholders."

 

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Why power companies should be investing in carbon-free electricity

Noncarbon Electricity Investment Strategy helps utilities hedge policy uncertainty, carbon tax risks, and emissions limits by scaling wind, solar, and CCS, avoiding stranded assets while balancing costs, reliability, and climate policy over decades.

 

Key Points

A strategy for utilities to invest 20-30 percent of capacity in low carbon sources to hedge emissions and carbon risks.

✅ Hedges future carbon tax and emissions limits

✅ Targets 20-30 percent of new generation from clean sources

✅ Reduces stranded asset risk and builds renewables capacity

 

When utility executives make decisions about building new power plants, a lot rides on their choices. Depending on their size and type, new generating facilities cost hundreds of millions or even billions of dollars. They typically will run for 40 or more years — 10 U.S. presidential terms. Much can change during that time.

Today one of the biggest dilemmas that regulators and electricity industry planners face is predicting how strict future limits on greenhouse gas emissions will be. Future policies will affect the profitability of today’s investments. For example, if the United States adopts a carbon tax 10 years from now, it could make power plants that burn fossil fuels less profitable, or even insolvent.

These investment choices also affect consumers. In South Carolina, utilities were allowed to charge their customers higher rates to cover construction costs for two new nuclear reactors, which have now been abandoned because of construction delays and weak electricity demand. Looking forward, if utilities are reliant on coal plants instead of solar and wind, it will be much harder and more expensive for them to meet future emissions targets, even as New Zealand's electrification push accelerates abroad. They will pass the costs of complying with these targets on to customers in the form of higher electricity prices.

With so much uncertainty about future policy, how much should we be investing in noncarbon electricity generation in the next decade? In a recent study, we proposed optimal near-term electricity investment strategies to hedge against risks and manage inherent uncertainties about the future.

We found that for a broad range of assumptions, 20 to 30 percent of new generation in the coming decade should be from noncarbon sources such as wind and solar energy across markets. For most U.S. electricity providers, this strategy would mean increasing their investments in noncarbon power sources, regardless of the current administration’s position on climate change.

Many noncarbon electricity sources — including wind, solar, nuclear power and coal or natural gas with carbon capture and storage — are more expensive than conventional coal and natural gas plants. Even wind power, which is often mentioned as competitive, is actually more costly when accounting for costs such as backup generation and energy storage to ensure that power is available when wind output is low.

Over the past decade, federal tax incentives and state policies designed to promote clean electricity sources spurred many utilities to invest in noncarbon sources. Now the Trump administration is shifting federal policy back toward promoting fossil fuels. But it can still make economic sense for power companies to invest in more expensive noncarbon technologies if we consider the potential impact of future policies.

How much should companies invest to hedge against the possibility of future greenhouse gas limits? On one hand, if they invest too much in noncarbon generation and the federal government adopts only weak climate policies throughout the investment period, utilities will overspend on expensive energy sources.

On the other hand, if they invest too little in noncarbon generation and future administrations adopt stringent emissions targets, utilities will have to replace high-carbon energy sources with cleaner substitutes, which could be extremely costly.

 

Economic modeling with uncertainty

We conducted a quantitative analysis to determine how to balance these two concerns and find an optimal investment strategy given uncertainty about future emissions limits. This is a core choice that power companies have to make when they decide what kinds of plants to build.

First we developed a computational model that represents the sectors of the U.S. economy, including electric power. Then we embedded it within a computer program that evaluates decisions in the electric power sector under policy uncertainty.

The model explores different electric power investment decisions under a wide range of future emissions limits with different probabilities of being implemented. For each decision/policy combination, it computes and compares economy-wide costs over two investment periods extending from 2015 to 2030.

We looked at costs across the economy because emissions policies impose costs on consumers and producers as well as power companies. For example, they may lead to higher electricity, fuel or product prices. By seeking to minimize economy-wide costs, our model identifies the investment decision that produces the greatest overall benefits to society.

 

More investments in clean generation make economic sense

We found that for a broad range of assumptions, the optimal investment strategy for the coming decade is for 20 to 30 percent of new generation to be from noncarbon sources. Our model identified this as the best level because it best positions the United States to meet a wide range of possible future policies at a low cost to the economy.

From 2005-2015, we calculated that about 19 percent of the new generation that came online was from noncarbon sources. Our findings indicate that power companies should put a larger share of their money into noncarbon investments in the coming decade.

While increasing noncarbon investments from a 19 percent share to a 20 to 30 percent share of new generation may seem like a modest change, it actually requires a considerable increase in noncarbon investment dollars. This is especially true since power companies will need to replace dozens of aging coal-fired power plants that are expected to be retired.

In general, society will bear greater costs if power companies underinvest in noncarbon technologies than if they overinvest. If utilities build too much noncarbon generation but end up not needing it to meet emissions limits, they can and will still use it fully. Sunshine and wind are free, so generators can produce electricity from these sources with low operating costs.

In contrast, if the United States adopts strict emissions limits within a decade or two, they could prevent carbon-intensive generation built today from being used. Those plants would become “stranded assets” — investments that are obsolete far earlier than expected, and are a drain on the economy.

Investing early in noncarbon technologies has another benefit: It helps develop the capacity and infrastructure needed to quickly expand noncarbon generation. This would allow energy companies to comply with future emissions policies at lower costs.

 

Seeing beyond one president

The Trump administration is working to roll back Obama-era climate policies such as the Clean Power Plan, and to implement policies that favor fossil generation. But these initiatives should alter the optimal strategy that we have proposed for power companies only if corporate leaders expect Trump’s policies to persist over the 40 years or more that these new generating plants can be expected to run.

Energy executives would need to be extremely confident that, despite investor pressure from shareholders, the United States will adopt only weak climate policies, or none at all, into future decades in order to see cutting investments in noncarbon generation as an optimal near-term strategy. Instead, they may well expect that the United States will eventually rejoin worldwide efforts to slow the pace of climate change and adopt strict emissions limits.

In that case, they should allocate their investments so that at least 20 to 30 percent of new generation over the next decade comes from noncarbon sources. Sustaining and increasing noncarbon investments in the coming decade is not just good for the environment — it’s also a smart business strategy that is good for the economy.

 

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Yale Report on Western Grid Integration: Just Say Yes

Western Grid Integration aligns CAISO with a regional transmission operator under FERC oversight, boosting renewables, reliability, and cost savings while respecting state energy policy, emissions goals, and utility regulation across the West.

 

Key Points

Western Grid Integration lets CAISO operate under FERC to cut costs, boost reliability, and accelerate renewables.

✅ Lowers wholesale costs via wider dispatch and resource sharing

✅ Improves reliability with regional balancing and reserves

✅ Preserves state policy authority under FERC oversight

 

A strong and timely endorsement for western grid integration forcefully rebuts claims that moving from a balkanized system with 38 separate entities to a regional operation could introduce environmental problems, raise costs, or, as critics warn, export California’s energy policies to other western states, or open state energy and climate policies to challenge by federal regulators. In fact, Yale University’s Environmental Protection Clinic identifies numerous economic and environmental benefits from allowing the California Independent System Operator to become a regional grid operator.

The groundbreaking report comprehensively examines the policy and legal merits of allowing the California Independent System Operator (CAISO) to become a regional grid operator, open to any western utility or generator that wants to join, as similar market structure overhauls proceed in New England.

The Yale report identifies the increasing constraints that today’s fragmented western grid imposes on system-wide electricity costs and reliability, addresses the potential benefits of integration, and evaluates  potential legal risks for the states involved. California receives particular attention because its legislature is considering the first step in the grid integration process, which involves authorizing the CAISO to create a fully independent board, even as it examines revamping electricity rates to clean the grid (other western states are unlikely to approve joining an entity whose governance is determined solely by California’s governor and legislature, as is the case now).

 

Elements of the report

The analysis examined all of California’s key energy and climate policies, from its cap on carbon emissions to its renewable energy goals and its pollution standards for power plants, and concludes that none would face additional legal risks under a fully integrated western grid. The operator of such a grid would be regulated by an independent federal agency (the Federal Energy Regulatory Commission)—but so is the CAISO itself, now and since its inception, by virtue of its extended involvement in interstate electricity commerce throughout the West. 

And if empowered to serve the entire region, the CAISO would not interfere with the longstanding rights of California and other states to regulate their utilities’ investments or set energy and climate policies. The study points out that grid operators don’t set energy policies for the states they serve; they help those states minimize costs, enhance reliability in the wake of California blackouts across the state, and avoid unnecessary pollution.

And as to whether an integrated grid would help renewable energy or fossil fuels, the report finds that renewable resources would be the inevitable winners, thanks to their lower operating costs, although the most important winners would be western utility customers, through lower bills, expanded retail choice options, and improved reliability.

 

Call to action

The Yale report concludes with what amounts to a call to action for California’s legislators:

“In sum, enhanced Western grid integration in general, and the emergence of a regional system operator in particular, would not expose California’s clean energy policies to additional legal risks. Shifting to a regional grid operator would enable more efficient, affordable and reliable integration of renewable resources without increasing the legal risk to California’s clean energy policies.”

The authors of the analysis, from the Yale Law School and the Yale School of Forestry and Environmental Studies, are Juliana Brint, Josh Constanti, Franz Hochstrasser. and Lucy Kessler. They dedicated months to the project, consulted with a diverse group of reviewers, and made the trek from New Haven to Folsom, CA, to visit the California Independent System Operator and interview key staff members.

 

 

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Opinion: Would we use Site C's electricity?

Site C Dam Electricity Demand underscores B.C.'s decarbonization path, enabling electrification of EVs, heat pumps, and industry, aligning with BC Hydro forecasts and 2030/2050 GHG targets to supply dependable, renewable baseload power.

 

Key Points

Projected clean power tied to Site C, driven by B.C. electrification to meet 2030 and 2050 greenhouse gas targets.

✅ Aligns with 25-30% by 2030 and 55-70% by 2050 GHG cuts

✅ Supports EVs, heat pumps, and industrial electrification

✅ Provides dependable baseload alongside efficiency gains

 

There are valid reasons not to build the Site C dam. There are also valid reasons to build it. One of the latter is the rapid increase in clean electricity needed to reduce B.C.’s greenhouse gas emissions from burning natural gas, gasoline, diesel and other harmful fossil fuel products.

Although former Premier Christy Clark casually avoided near-term emissions targets, Prime Minister Justin Trudeau has set Canadian targets for both 2030 and 2050, and cleaning up Canada's electricity is critical to meeting them. Studies by my research group at Simon Fraser University and other independent analysts show that B.C.’s cost-effective contribution to these national targets requires us to reduce our emissions 25 to 30 per cent by 2030 and 55 to 70 per cent by 2050 — an energy evolution involving, among other things, a much greater use of electricity in buildings, vehicles and industry.

Recent submissions to the Site C hearing have offered widely different estimates of B.C.’s electricity demand in the decade after the project’s completion in 2025, some arguing the dam’s output will be completely surplus to domestic need for years and perhaps decades, even though improved B.C.-Alberta grid links could help balance regional demand. Some of this variation in demand forecasts is understandable. Industrial demand is especially difficult to predict, dependent as it is on global economic conditions and shifting trade relations. And there are legitimate uncertainties about B.C. Hydro’s ability to reduce electricity demand by promoting efficient products and behaviour through its Power Smart program. But some of the forecasts appear to be deliberate exaggerations, designed to support fixed positions for or against Site C.

Our university-based research team models the energy system changes required to meet national and provincial emissions targets, and we have been comparing estimates of the electricity demand implications. These estimates are produced by academics, as well as by key institutions like B.C. Hydro, the National Energy Board, and the governments of Canada and B.C.

Most electricity forecasts for B.C., including the most recent by B.C. Hydro, do not assume that B.C. reduces its greenhouse gas emissions by 25 to 30 per cent by 2030 and 55 to 70 per cent by 2050. When we adjust Hydro’s forecast for just the low end of these targets, we find that in its latest, August 30, submission to the Site C hearing, which followed the premier’s over-budget go-ahead on the project, Hydro has underestimated the demand for its electricity by about three terawatt-hours in 2025, four in 2030 and 10 in 2035. Hydro’s forecast indicates that it will need the five terawatt-hours from Site C. Our research shows that even if Hydro’s demand forecast is too high, appropriate climate policy nationally and in B.C. will absorb all the electricity the dam can produce soon after its completion.

B.C. Hydro does not forecast electricity demand to 2050. But, studies by us and others show that B.C. electricity demand will be almost double today’s levels if we are to reduce emissions by 55 to 70 per cent, even amid a documented risk of missing the 2050 target, in just over three decades while our population, economy, buildings and equipment grow significantly. Most mid- and small-sized vehicles will be electric. Most buildings will be well insulated and heated by electric resistance or electric heat-pumps, either individually or via district heating systems. And many low temperature industrial applications will be electric.

Aggressive efforts to promote energy efficiency will make an important contribution, such that energy demand will not grow nearly as fast as the economy. But it is delusional to think that humans will stop using energy. Even climate policy scenarios in which we assume unprecedented success with energy efficiency show dramatic increases in the consumption of electricity, this being the most favoured zero-emission form of energy as a replacement for planet-destroying gasoline and natural gas.

The completion of the Site C dam is a complicated and challenging societal choice, and delay-related cost risks highlighted by the premier underscore the stakes. There is unbiased evidence and argument supporting either completion or cancellation. But let’s stick to the unbiased evidence. In the case of our 2030 and 2050 greenhouse gas reduction targets, such evidence shows that we must substantially increase our generation of dependable electricity. If the Site C dam is built, and if we are true to our climate goals, all its electricity will be used in B.C. soon after completion.

Mark Jaccard is a professor of sustainable energy in the School of Resource and Environmental Management at Simon Fraser University.

 

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Tesla’s Powerwall as the beating heart of your home

GMP Tesla Powerwall Program replaces utility meters with smart battery storage, enabling virtual power plant services, demand response, and resilient homes, integrating solar readiness, EV charging support, and smart grid controls across Vermont households.

 

Key Points

Green Mountain Power uses Tesla Powerwalls as smart meters, creating a VPP for demand response and home backup.

✅ $30 monthly for 10 years or $3,000 upfront for two units

✅ Utility controls batteries for peak shaving and demand response

✅ Enables backup power, solar readiness, and EV charging support

 

There are more than 100 million single-family homes in the United States of America. If each of these homes were to have two 13.5 kWh Tesla Powerwalls, that would total 2.7 Terawatt-hours worth of electricity stored. Prior research has suggested that this volume of energy storage could get us halfway to the 5.4 TWh of storage needed to let the nation get 80% of its electricity from solar and wind, as states like California increasingly turn to grid batteries to support the transition.

Vermont utility Green Mountain Power (GMP) seeks to remove standard electric utility metering hardware and replace it with the equipment inside of a Tesla Powerwall, as part of a broader digital grid evolution underway. Mary Powell, President and CEO of Green Mountain Power, says, “We have a vision of a battery system in every single home” and they’ve got a patent pending software solution to make it happen.

The Resilient Home program will install two standard Tesla Powerwalls each in 250 homes in GMP’s service area. The homeowner will pay either $30 a month for ten years ($3,600), or $3,000 up front. At the end of the ten year period, payments end, but the unit can stay in the home for an additional five years – or as long as it has a usable life.

A single Powerwall costs approximately $6,800, making this a major discount.

GMP notes that the home must have reliable internet access to allow GMP and Tesla to communicate with the Powerwall. GMP will control the functions of the Powerwall, effectively operating a virtual power plant across participating homes, expanding the scope of programs like those that saved the state’s ratepayers more than $500,000 during peak demand events last year. The utility specifically notes that customers agree to share stored energy with GMP on several peak demand days each year.

The hardware can be designed to interact with current backup generators during power outages, or emerging fuel cell solutions that maintain battery charge longer during extended outages, however, the units will not charge from the generator. As noted the utility will be making use of the hardware during normal operating times, however, during a power outage the private home owner will be able to use the electricity to back up both their house and top off their car.

The utility told pv magazine USA that the Powerwalls are standard from the factory, with GMP’s patent pending software solution being the special sauce (has a hint of recent UL certifications). GMP said the program will also get home owners “adoption ready” for solar power, including microgrid energy storage markets, and other smart devices.

Sonnen’s ecoLinx is already directly interacting with a home’s electrical panel (literally throwing wifi enabled circuit breakers). Now with Tesla Powerwalls being used to replace utility meters, we see one further layer of integration that will lead to design changes that will drive residential solar toward $1/W. Electric utilities are also experimenting with controlling module level electronics and smart solar inverters in 100% residential penetration situations. And of course, considering that California is requiring solar – and probably storage in the future – in all new homes, we should expect to see further experimentation in this model. Off grid solar inverter manufacturers already include electric panels with their offerings.

If we add in the electric car, and have vehicle-to-grid abilities, we start to see a very strong amount of electricity generation and energy storage, helping to keep the lights on during grid stress, potentially happening in more than 100 million residential power plants. Resilient homes indeed.

 

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Ontario looks to build on electricity deal with Quebec

Ontario-Quebec Electricity Deal explores hydro imports, terawatt hours, electricity costs, greenhouse gas cuts, and baseload impacts, amid debates on Pickering nuclear operations and competitive procurement in Ontario's long-term energy planning.

 

Key Points

A proposed hydro import deal from Quebec, balancing costs, emissions, and reliability for Ontario electricity customers.

✅ Draft 20-year, 8 TWh offer reported by La Presse disputed

✅ Ontario seeks lower costs and GHG cuts versus alternatives

✅ Not a baseload replacement; Pickering closure not planned

 

Ontario is negotiating a possible energy swap agreement to buy electricity from Quebec, but the government is disputing a published report that it is preparing to sign a deal for enough electricity to power a city the size of Ottawa.

La Presse reported Tuesday that it obtained a copy of a draft, 20-year deal that says Ontario would buy eight terawatt hours a year from Quebec – about 6 per cent of Ontario’s consumption – whether the electricity is consumed or not.

Ontario Energy Minister Glenn Thibeault’s office said the province is in discussions to build on an agreement signed last year for Ontario to import up to two terawatt hours of electricity a year from Quebec.

 

But his office released a letter dated late last month to his Quebec counterpart, in which Mr. Thibeault said the offer extended in June was unacceptable because it would increase the average residential electricity bill by $30 a year.

“I am hopeful that your continued support and efforts will help to further discussions between our jurisdictions that could lead to an agreement that is in the best interest of both Ontario and Quebec,” Mr. Thibeault wrote July 27 to Pierre Arcand.

Ontario would prepare a “term sheet” for the next stage of discussions ahead of the two ministers meeting at the Energy and Mines Ministers Conference later this month in New Brunswick, Mr. Thibeault wrote.

Any future agreements with Quebec will have to provide a reduction in Ontario electricity rates compared with other alternatives and demonstrate measurable reductions in greenhouse gas emissions, he wrote.

Progressive Conservative Leader Patrick Brown said Ontario doesn’t need eight terawatt hours of additional power and suggested it means the Liberal government is considering closing power facilities such as the Pickering nuclear plant early.

A senior Energy Ministry official said that is not on the table. The government has said it intends to keep operating two units at Pickering until 2022, and the other four units until 2024.

Even if the Quebec offer had been accepted, the energy official said, that power wouldn’t have replaced any of Ontario’s baseload power because it couldn’t have been counted on 24 hours a day, 365 days a year.

The Society of Energy Professionals said Mr. Thibeault was right to reject the deal, but called on him to release the Long-Term Energy Plan – which was supposed to be out this spring – before continuing negotiations.

Some commentators have argued for broader reforms to address Ontario's hydro system challenges, urging policymakers to review all options as negotiations proceed.

The Ontario Energy Association said the reported deal would run counter to the government’s stated energy objectives amid concerns over electricity prices in the province.

“Ontarians will not get the benefit of competition to ensure it is the best of all possible options for the province, and companies who have invested in Ontario and have employees here will not get the opportunity to provide alternatives,” president and chief executive Vince Brescia said in a statement. “Competitive processes should be used for any new significant system capacity in Ontario.”

The Association of Power Producers of Ontario said it is concerned the government is even considering deals that would “threaten to undercut a competitive marketplace and long-term planning.”

“Ontario already has a surplus of energy, so it’s very difficult to see how this deal or any other sole-source deal with Quebec could benefit the province and its ratepayers,” association president and CEO David Butters said in a statement.

The Ontario Waterpower Association also said such a deal with Quebec would “present a significant challenge to continued investment in waterpower in Ontario.”

 

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