First Nations communities ready for the grid

Ontario Hydro Crisis highlights soaring electricity rates, costly subsidies, nuclear refurbishments, and stalled renewables in Ontario. Policy missteps, weak planning, and rising natural gas emissions burden ratepayers while energy efficiency and storage remain underused.

Key Points

High power costs and subsidies from policy errors, nuclear refurbishments, stalled efficiency and renewables in Ontario.

✅ $5.6B yearly subsidy masks electricity rates and deficits

✅ Nuclear refurbishments embed rising costs for decades

✅ Efficiency, storage, and DERs stalled amid weak planning

By Mark Winfield

While the troubled Site C and Muskrat Falls hydroelectric dam projects in B.C. and Newfoundland and Labrador have drawn a great deal of national attention over the past few months, Ontario has quietly been having a hydro crisis of its own.

One of the central promises in the 2018 platform of the Ontario Progressive Conservative party was to “clean up the hydro mess,” and then-PC leader Doug Ford vowed to fire Hydro One's leadership as part of that effort. There certainly is a mess, with the costs of subsidies taken from general provincial revenues to artificially lower hydro rates nearing $7 billion annually. That is a level approaching the province’s total pre-COVID-19 annual deficit. After only two years, that will also exceed total expected cost overruns of the Site C and Muskrat Falls projects, currently estimated at $12 billion ($6 billion each).

There is no doubt that Doug Ford’s government inherited a significant mess around the province’s electricity system from the previous Liberal governments of former premiers Dalton McGuinty and Kathleen Wynne. But the Ford government has also demonstrated a remarkable capacity for undoing the things its predecessors had managed to get right while doubling down on their mistakes.

The Liberals did have some significant achievements. Most notably: coal-fired electricity generation, which constituted 25 per cent of the province’s electricity supply in the early 2000s, was phased out in 2014. The phaseout dramatically improved air quality in the province. There was also a significant growth in renewable energy production. From  virtually zero in 2003, the province installed 4,500 MW of wind-powered generation, and 450 MW of solar photovoltaic by 2018, a total capacity more than double that of the Sir Adam Beck Generating Stations at Niagara Falls.

At the same time, public concerns over rising hydro rates flowing from a major reconstruction of the province’s electricity system from 2003 onwards became a central political issue in the province. But rather than reconsider the role of the key drivers of the continuing rate increases – namely the massively expensive and risky refurbishments of the Darlington and Bruce nuclear facilities, the Liberals adopted a financially ruinous Fair Hydro Plan. The central feature of the 2017 plan was a short-term 25 per cent reduction in hydro rates, financed by removing the provincial portion of the HST from hydro bills, and by extending the amortization period for capital projects within the system. The total cost of the plan in terms of lost revenues and financing costs has been estimated in excess of $40 billion over 29 years, with the burden largely falling on future ratepayers and taxpayers.

Decision-making around the electricity system became deeply politicized, and a secret cabinet forecast of soaring prices intensified public debate across Ontario. Legislation adopted by the Wynne government in 2016 eliminated the requirement for the development of system plans to be subject to any form of meaningful regulatory oversight or review. Instead, the system was guided through directives from the provincial cabinet. Major investments like the Darlington and Bruce refurbishments proceeded without meaningful, public, external reviews of their feasibility, costs or alternatives.

The Ford government proceeded to add more layers to these troubles. The province’s relatively comprehensive framework for energy efficiency was effectively dismantled in March, 2019, with little meaningful replacement. That was despite strong evidence that energy efficiency offered the most cost-effective strategy for reducing greenhouse gas emissions and electricity costs.

The Ford government basically retained the Fair Hydro Plan and promised further rate reductions, later tabling legislation to lower electricity rates as well. To its credit, the government did take steps to clarify real costs of the plan. Last year, these were revealed to amount to a de facto $5.6 billion-per-year subsidy coming from general revenues, and rising. That constituted the major portion of the province’s $7.4 billion pre-COVID-19 deficit. The financial hole was deepened further through November’s financial statement, with the addition of a further $1.3 billion subsidy to commercial and industrial consumers. The numbers can only get worse as the costs of the Darlington and Bruce refurbishments become embedded more fully into electricity rates.

The government also quietly dispensed with the last public vestige of an energy planning framework, relieving itself of the requirement to produce a Long-Term Energy Plan every three years. The next plan would normally have been due next month, in February.

Even the gains from the 2014 phaseout of coal-fired electricity are at risk. Major increases are projected in emissions of greenhouse gases, smog-causing nitrogen oxides and particulate matter from natural gas-fired power plants as the plants are run to cover electricity needs during the Bruce and Darlington refurbishments over the next decade. These developments could erode as much as 40 per cent of the improvements in air quality and greenhouse gas emission gained through the coal phaseout.

The province’s activities around renewable energy, energy storage and distributed energy resources are at a standstill, with exception of a few experimental “sandbox” projects, while other jurisdictions face profound electricity-sector change and adapt. Globally, these technologies are seen as the leading edge of energy-system development and decarbonization. Ontario seems to have chosen to make itself an energy innovation wasteland instead.

The overall result is a system with little or no space for innovation that is embedding ever-higher costs while trying to disguise those costs at enormous expense to the provincial treasury and still failing to provide effective relief to low-income electricity consumers.

The decline in electricity demand associated with the COVID-19 pandemic, along with the introduction of a temporary recovery rate for electricity, gives the province an opportunity to step back and consider its next steps with the electricity system. A phaseout of the Fair Hydro Plan electricity-rate reduction and its replacement with a more cost-effective strategy of targeted relief aimed at those most heavily burdened by rising hydro rates, particularly rural and low-income consumers, as reconnection efforts for nonpayment have underscored the hardship faced by many households, would be a good place to start.

Next, the province needs to conduct a comprehensive, public review of electricity options available to it, including additional renewables – the costs of which have fallen dramatically over the past decade – distributed energy resources, hydro imports from Quebec and energy efficiency before proceeding with further nuclear refurbishments.

In the longer term, a transparent, evidence-based process for electricity system planning needs to be established – one that is subject to substantive public and regulatory oversight and review. Finally, the province needs to establish a new organization to be called Energy Efficiency Ontario to revive its efforts around energy efficiency, developing a comprehensive energy-efficiency strategy for the province, covering electricity and natural gas use, and addressing the needs of marginalized communities.

Without these kinds of steps, the province seems destined to continue to lurch from contradictory decision after contradictory decision as the economic and environmental costs of the system’s existing trajectory continue to rise.

Mark Winfield is a professor of environmental studies at York University and co-chair of the university’s Sustainable Energy Initiative.

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Community Solar for Low-Income Homes expands energy equity by delivering renewable energy access, predictable bill savings, and tax credit benefits to renters and energy-insecure households, accelerating distributed generation and storage adoption nationwide.

Key Points

A program model enabling renters and LMI households to subscribe to off-site solar and save on utility bills.

✅ Earn bill credits from shared solar generation.

✅ Expands access for renters and LMI subscribers.

✅ Often paired with storage and IRA tax credit adders.

On a square-foot basis, the issue of inequality is made worse by higher costs for energy usage in the nation. Efforts like community solar programs such as Maryland community solar are underway to boost low-income participation in the cost benefits of renewable energy.

The Energy Information Administration (EIA) shows that households that are considered energy insecure, or those that have the inability to adequately meet basic household energy costs, are paying more for electricity than their wealthier counterparts. 

On average in the United States in 2020, households were billed about $1.04 per square foot for all energy sources. For homes that did not report energy insecurity, that average was $0.98 per square foot, while homes with energy insecurity issues paid an average of $1.24 per square foot for energy. This means that U.S. residents that need the most support on their energy bills are stuck with costs 27% higher than their neighbors on square-foot-basis.

EIA said energy-insecure households have reduced or forgone basic necessities to pay energy bills, kept their houses at unsafe temperatures because of energy cost concerns, or been unable to repair heating or cooling equipment because of cost.

In 2020, households with income less than $10,000 a year were billed an average of $1.31 per square foot for energy, while households making $100,000 or more were billed an average of $0.96 per square foot, said EIA. Renters paid considerably more ($1.28 per square foot) than owners ($0.98 per square foot). There were also considerable differences between regions, with New England solar growth sparking grid upgrade debates, ethnic groups and races, and insulation levels, as seen below.

The energy transition toward renewables like solar has offered price stability, amid record solar and storage growth nationwide, but thus far energy-insecure communities have relatively been left behind. A recent Berkeley Lab report, Residential Solar-Adopter Income and Demographic Trends, indicates that even though the rate of solar adoption among low-income residents is increasing (from 5% in 2010 to 11% in 2021), that segment of energy consumers remains under-represented among solar adopters, relative to its share of the population.

Community solar efforts

As such, the United States is targeting communities most impacted by energy costs that have not benefitted from the transition, highlighting “Energy Communities” that are eligible for an additional 10% tax credit through funds made possible by the Inflation Reduction Act.

Additionally, a push for community solar development is taking place nationwide to extend access to affordable solar energy to renters and other residents that aren’t able to leverage finances to invest in predictable, low-cost residential solar systems. The Biden Administration set a goal this year to sign up 5 million community solar households, achieving $1 billion in bill savings by 2025. The community solar model only represents about 8% of the total distributed solar capacity in the nation. This target would entail a jump from 3 GW installed capacity to 20 GW by the target year. The Department of Energy estimates community solar subscribers save an average of 20% on their bills.

California this year passed AB 2316, the Community Renewable Energy Act takes aim at four acute problems in the state’s power market: reliability amid rising outage risks, rates, climate and equity. The law creates a community renewable energy program, including community solar-plus-storage, supported by cheaper batteries, to overcome access barriers for nearly half of Californians who rent or have low incomes. Community solar typically involves customers subscribing to an off-site solar facility, receiving a utility bill credit for the power it generates.

“Community renewable energy is a proven powerful tool to help close California’s clean energy gap, bringing much needed relief to millions struggling with high housing costs and utility debt,” said Alexis Sutterman, energy equity program manager at the California Environmental Justice Alliance.

The program has energy equity baked into its structure, working to make sure Californians of all income levels participate in the benefits of the energy transition. Not only does it open solar access to renters, the law ensures that at least 51% of subscribers are low-income customers, which is expected to make projects eligible for a 10% tax credit adder under the IRA.

“The money’s on the table now,” said Jeff Cramer, president and chief executive of the Coalition for Community Solar Access. “While there are groups pushing for solar access for all, and states with strong legislation, there are other pockets of interest in surprising places in the United States. For example, Louisiana has no policy for community solar or support for low-income residents going solar but the city of New Orleans has its own utility commission with a community solar program. In Nebraska, forward-looking co-operatives have created community solar projects.

Community solar markets are active in 22 states, with more expected to come online in the future as states pursue 100% clean energy targets across the country. However, the market is expected to require strong community outreach efforts to foster trust and gain subscribers.

“There is a distrust of community solar initially in LMI communities as many have been burned before by retail energy false promises,” said Eric LaMora, executive director, community solar, Nautilus Solar on a panel at the Solar Energy Industries Association Finance, Tax, and Buyers seminar. “People are suspicious but there really are no hooks with community solar.”

LMI residents are leery to provide tax records or much documents at all in order to sign up for community solar, LaMora said. “We were surprised to see less of a default rate with LMI residents. We attribute this to the fact that they see significant savings on their electric bill, making it easier to pay each month,” he said.

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Alberta Electricity Price Surge reflects soaring wholesale rates, natural gas spikes, carbon tax pressures, and grid decarbonization challenges amid cold-weather demand, constrained supply, and Europe-style energy crisis impacts across the province.

Key Points

An exceptional jump in Alberta's power costs driven by gas price spikes, high demand, policy costs, and tight supply.

✅ Wholesale prices averaged $123/MWh in December

✅ Gas costs surged; supply constraints and outages

✅ Carbon tax and decarbonization policies raised costs

Albertans just endured the highest electricity prices in 21 years. Wholesale prices averaged $123 per megawatt-hour in December, more than triple the level from the previous year and highest for December since 2000.

The situation in Alberta mirrors the energy crisis striking Europe where electricity prices are also surging, largely due to a shocking five-fold increase in natural gas prices in 2021 compared to the prior year.

The situation should give pause to Albertans when they consider aggressive plans to “decarbonize” the electric grid, including proposals for a fully renewable grid by 2030 from some policymakers.

The explanation for skyrocketing energy prices is simple: increased demand (because of Calgary's frigid February demand and a slowly-reviving post-pandemic economy) coupled with constrained supply.

In the nitty gritty details, there are always particular transitory causes, such as disputes with Russian gas companies (in the case of Europe) or plant outages (in the case of Alberta).

But beyond these fleeting factors, there are more permanent systemic constraints on natural gas (and even more so, coal-fired) power plants.

I refer of course to the climate change policies of the Trudeau government at the federal level and some of the more aggressive provincial governments, which have notable implications for electricity grids across Canada.

The most obvious example is the carbon tax, the repeal of which Premier Jason Kenney made a staple of his government.

Putting aside the constitutional issues (on which the Supreme Court ruled in March of last year that the federal government could impose a carbon tax on Alberta), the obvious economic impact will be to make carbon-sourced electricity more expensive.

This isn’t a bug or undesired side-effect, it’s the explicit purpose of a carbon tax.

Right now, the federal carbon tax is $40 per tonne, is scheduled to increase to $50 in April, and will ultimately max out at a whopping $170 per tonne in 2030.

Again, the conscious rationale of the tax, aligned with goals for cleaning up Canada's electricity, is to make coal, oil and natural gas more expensive to induce consumers and businesses to use alternative energy sources.

As Albertans experience sticker shock this winter, they should ask themselves — do we want the government intentionally making electricity and heating oil more expensive?

Of course, the proponent of a carbon tax (and other measures designed to shift Canadians away from carbon-based fuels) would respond that it’s a necessary measure in the fight against climate change, and that Canada will need more electricity to hit net-zero according to the IEA.

Yet the reality is that Canada is a bit player on the world stage when it comes to carbon dioxide, responsible for only 1.5% of global emissions (as of 2018).

As reported at this “climate tracker” website, if we look at the actual policies put in place by governments around the world, they’re collectively on track for the Earth to warm 2.7 degrees Celsius by 2100, far above the official target codified in the Paris Agreement.

Canadians can’t do much to alter the global temperature, but federal and provincial governments can make energy more expensive if policymakers so choose, and large-scale electrification could be costly—the Canadian Gas Association warns of $1.4 trillion— if pursued rapidly.

As renewable technologies become more reliable and affordable, business and consumers will naturally adopt them; it didn’t take a “manure tax” to force people to use cars rather than horses.

As official policy continues to make electricity more expensive, Albertans should ask if this approach is really worth it, or whether options like bridging the Alberta-B.C. electricity gap could better balance costs.

Robert P. Murphy is a senior fellow at the Fraser Institute.

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NRC Special Inspection at River Bend reviews failures of portable emergency diesel generators, nuclear safety measures, and Entergy Operations actions after Fukushima; off-site power loss readiness, remote COVID-19 oversight, and corrective action plans are assessed.

Key Points

An NRC review of generator test failures at River Bend, assessing nuclear safety, root causes, and corrective actions.

✅ Evaluates failures of portable emergency diesel generators

✅ Reviews causal analyses and adequacy of corrective actions

✅ Remote COVID-19 oversight; public report expected within 45 days

The Nuclear Regulatory Commission has begun a special inspection at the River Bend nuclear power plant, part of broader oversight that includes the Turkey Point renewal application, to review circumstances related to the failure of five portable emergency diesel generators during testing. The plant, operated by Entergy Operations, is located in St. Francisville, La., as nations like France outage risks continue to highlight broader reliability concerns.

The generators are used to supply power to plant systems in the event of a prolonged loss of off-site electrical power coupled with a failure of the permanently installed emergency generators, a concern underscored by incidents such as the SC nuclear plant leak that shut down production for weeks. These portable generators were acquired as part of the facility's safety enhancements mandated by the NRC following the 2011 accident at the Fukushima Dai-ichi facility in Japan, and amid constraints like France limiting output from warm rivers, the emphasis on resilience remains.

The three-member NRC team will develop a chronology of the test failures and evaluate the licensee's causal analyses and the adequacy of corrective actions, informed by lessons from cases like Davis-Besse closure stakes that underscore risk management.

Due to the COVID-19 pandemic, they will complete most of their work remotely, while other regions address constraints such as high river temperatures limiting output for nuclear stations. An inspection report documenting the team's findings, released as global nuclear project milestones continue across the sector, will be publicly available within 45 days of the end of the inspection.
 

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Texas After-Labor Day School Start could ease ERCOT's power grid strain by shifting peak demand, lowering air-conditioning loads in schools, improving grid reliability, reducing electricity costs, and curbing emissions during extreme heat the summer months.

Key Points

A proposed calendar shift to start school after Labor Day to lower ERCOT peak demand, costs, and grid risk.

✅ Cuts school HVAC loads during peak summer heat

✅ Lowers costly peaker plant use and electricity rates

✅ Requires calendar changes, testing and activities shifts

As Texas faces increasing demands on its power grid, a new proposal is gaining traction: starting the school year after Labor Day. This idea, reported by the Dallas News, suggests that delaying the start of the academic year could help alleviate some of the pressure on the state’s electricity grid during the peak summer months, potentially leading to both grid stability and financial savings. Here’s an in-depth look at how this proposed change could impact Texas’s energy landscape and education system.

The Context of Power Grid Strain

Texas's power grid, operated by the Electric Reliability Council of Texas (ERCOT), has faced significant challenges in recent years. Extreme weather events, record-breaking temperatures, and high energy demand have strained the grid, and some analyses argue that climate change, not demand is the biggest challenge today, leading to concerns about reliability and stability. The summer months are particularly taxing, as the demand for air conditioning surges, often pushing the grid to its limits.

In this context, the idea of adjusting the school calendar to start after Labor Day has been proposed as a potential strategy to help manage electricity demand. By delaying the start of school, proponents argue that it could reduce the load on the power grid during peak usage periods, thereby easing some of the stress on energy resources.

Potential Benefits for the Power Grid

The concept of delaying the school year is rooted in the potential benefits for the power grid. During the hottest months of summer, the demand for electricity often spikes as families use air conditioning to stay cool, and utilities warn to prepare for blackouts as summer takes hold. School buildings, typically large and energy-intensive facilities, contribute significantly to this demand when they are in operation.

Starting school later could help reduce this peak demand, as schools would be closed during the hottest months when the grid is under the most pressure. This reduction in demand could help prevent grid overloads and reduce the risk of power outages, at a time when longer, more frequent outages are afflicting the U.S. power grid, ultimately contributing to a more stable and reliable electricity supply.

Additionally, a decrease in peak demand could help lower electricity costs. Power plants, particularly those that are less efficient and more expensive to operate, are often brought online during periods of high demand. By reducing the peak load, the state could potentially minimize the need for these costly power sources, leading to lower overall energy costs.

Financial and Environmental Considerations

The financial implications of starting school after Labor Day extend beyond just the power grid. By reducing energy consumption during peak periods, the state could see significant savings on electricity costs. This, in turn, could lead to lower utility bills for schools, businesses, and residents alike, a meaningful relief as millions risk electricity shut-offs during summer heat.

Moreover, reducing the demand for electricity from fossil fuel sources can have positive environmental impacts. Lower peak demand may reduce the reliance on less environmentally friendly energy sources, and aligns with calls to invest in a smarter electricity infrastructure nationwide, thereby decreasing greenhouse gas emissions and contributing to overall environmental sustainability.

Challenges and Trade-offs

While the proposal offers potential benefits, it also comes with challenges and trade-offs. Adjusting the school calendar would require significant changes to the academic schedule, potentially affecting extracurricular activities, summer programs, and family plans, and comparisons to California's reliability challenges underscore the complexity. Additionally, there could be resistance from various stakeholders, including parents, educators, and students, who are accustomed to the current school calendar.

There are also logistical considerations to address, such as how a delayed start might impact standardized testing schedules and the academic calendar for higher education institutions. These factors would need to be carefully evaluated to ensure that the proposed changes do not adversely affect educational outcomes or create unintended consequences.

Looking Ahead

The idea of starting Texas schools after Labor Day represents an innovative approach to addressing the challenges facing the state’s power grid. By potentially reducing peak demand and lowering energy costs, and alongside efforts to connect Texas's grid to the rest of the nation, this proposal could contribute to greater grid stability and financial savings. However, careful consideration and planning will be essential to navigate the complexities of altering the school calendar and to ensure that the benefits outweigh the challenges.

As Texas continues to explore solutions for managing its power grid and energy resources, the proposal to shift the school year schedule provides an intriguing possibility. It reflects a broader trend of seeking creative and multifaceted approaches to balancing energy demand, environmental sustainability, and public needs.

In conclusion, starting schools after Labor Day could offer tangible benefits for Texas’s power grid and financial well-being. As discussions on this proposal advance, it will be important to weigh all factors and engage stakeholders to ensure a successful and equitable implementation.

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UK Coal-Free Electricity Record highlights rapid growth in renewables as National Grid phases out coal; wind, solar, and offshore projects surge, green tariffs expand, and energy comparison helps consumers switch to cheaper, cleaner deals.

Key Points

Britain's longest coal-free run, enabled by renewables, lower demand, and grid shifts for cheaper, greener tariffs.

✅ Record set after two months without coal-fired generation

✅ Renewables outpace fossil fuels; wind and solar dominate

✅ Green tariffs expand; prices at three-year lows

On Wednesday 10 June, Britain hit a significant landmark: the UK went for two full months without burning coal to generate power – that's the longest period since the 1880s, following earlier milestones such as a full week without coal power in the recent past.

According to the National Grid, Britain has now run its electricity network without burning coal since midnight on the 9 April. This coal-free period has beaten the country’s previous record of 18 days, six hours and 10 minutes, which was set in June 2019, even though low-carbon generation stalled in 2019 according to analyses.

With such a shift in Britain’s drive for renewables and lower electricity demand following the coronavirus lockdown, as Britain recorded its cleanest electricity during lockdown to date, now may be the perfect time to do an online energy comparison and switch to a cheaper, greener deal.

Only a decade ago, around 40 per cent of Britain’s electricity came from coal generation, but since then the country has gradually shifted towards renewable energy, with the coal share at record lows in the system today. When Britain was forced into lockdown in response to the coronavirus pandemic, electricity demand dropped sharply, and the National Grid took the four remaining coal-fired plants off the network.

Over the past 10 years, Britain has invested heavily in renewable energy. Back in 2010, only 3 per cent of the country's electricity came from wind and solar, and many people remained sceptical. However, now, the UK has the biggest offshore wind industry in the world. Plus, last year, construction of the world’s single largest wind farm was completed off the coast of Yorkshire.

At the same time, Drax – Britain’s biggest power plant – has started to switch from burning coal to burning compressed wooden pellets instead, reflecting the UK's progress as it keeps breaking its coal-free energy record again across the grid. By this time next year, the plant hopes to have phased out coal entirely.

So far this year, renewables have generated more power than all fossil fuels put together, the BBC reports, and the energy dashboard shows the current mix in real time. Renewables have been responsible for 37 per cent of electricity supplied to the network, with wind and solar surpassing nuclear for the first time, while fossil fuels have accounted for 35 per cent. During the same period, nuclear accounted for 18 per cent and imports made up the remaining 10 per cent.

What does this mean for consumers?

As the country’s electricity supply moves more towards renewables, customers have more choice than ever before. Most of the ‘Big Six’ energy companies now have tariffs that offer 100 per cent green electricity. On top of this, specialist green energy suppliers such as Bulb, Octopus and Green Energy UK make it easier than ever to find a green energy tariff.

The good news is that our energy comparison research suggests that green energy doesn’t have to cost you more than a traditional fixed-price energy contract would. In fact, some of the cheapest energy suppliers are actually green companies.

At present, energy bills are at three-year lows, which means that now is the perfect time to switch supplier. As prices remain low and renewables begin to dominate the marketplace, more switchers will be drawn to green energy deals than ever before.

However, if you’re interested in choosing a green energy supplier, make sure that you look at the company's fuel mix. This way, you’ll be able to see whether they are guaranteeing the usage of green energy, or whether they’re just offsetting your usage. All suppliers must report how their energy is generated to Ofgem, so you’ll easily be able to compare providers.

You may find that you pay more for a supplier that generates its own energy from renewables, or pay less if the supplier simply matches your usage by buying green energy. You can decide which option is right for you after comparing the prices.

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