Negative Electricity Prices Amid Renewable Energy Surplus

Alberta Solar Power is accelerating as renewable energy investment, PPAs, and utility-scale projects expand the grid, with independent power producers and foreign capital outperforming AESO forecasts in oil-and-gas-rich markets across Alberta and Calgary.

Key Points

Alberta Solar Power is a fast-growing provincial market, driven by PPAs and private investment, outpacing AESO forecasts.

✅ Utility-scale projects and PPAs expand capacity beyond AESO outlooks

✅ Private and foreign capital drive independent power producers

✅ Costs near $70/MWh challenge >$100/MWh assumptions

Solar power is beating expectations in oil and gas rich Alberta, where the renewable energy source is poised to expand dramatically amid a renewable energy surge in the coming years as international power companies invest in the province.

Fresh capital is being deployed in the Alberta’s electricity generation sector for both renewable and natural gas-fired power projects after years of uncertainty caused by changes and reversals in the province’s power market, said Duane Reid-Carlson, president of power consulting firm EDC Associates, who advises renewable power developers on electric projects in the province.

“From the mix of projects that we see in the queue at the (Alberta Electric System Operator) and the projects that have been announced, Alberta, a powerhouse for both green energy and fossil fuels, has no shortage of thermal and renewable projects,” Reid-Carlson said, adding that he sees “a great mix” of independent power companies and foreign firms looking to build renewable projects in Alberta.

Alberta is a unique power market in Canada because its electricity supply is not dominated by a Crown corporation such as BC Hydro, Hydro One or Hydro Quebec. Instead, a mix of private-sector companies and a few municipally owned utilities generate electricity, transmit and distribute that power to households and industries under long-term contracts.

Last week, Perimeter Solar Inc., backed by Danish solar power investor Obton AS, announced Sept. 30 that it had struck a deal to sell renewable energy to Calgary-based pipeline giant TC Energy Corp. with 74.25 megawatts of electricity from a new 130-MW solar power project immediately south of Calgary. Neither company disclosed the costs of the transaction or the project.

“We are very pleased that of all the potential off-takers in the market for energy, we have signed with a company as reputable as TC Energy,” Obton CEO Anders Marcus said in a release announcing the deal, which it called “the largest negotiated energy supply agreement with a North American energy company.”

Perimeter expects to break ground on the project, which will more than double the amount of solar power being produced in the province, by the end of this year.

A report published Monday by the Energy Information Administration, a unit of the U.S. Department of Energy, estimated that renewable energy powered 3 per cent of Canada’s energy consumption in 2018.

Between the Claresholm project and other planned solar installations, utility companies are poised to install far more solar power than the province is currently planning for, even as Alberta faces challenges with solar expansion today.

University of Calgary adjunct professor Blake Shaffer said it was “ironic” that the Claresholm Solar project was announced the exact same day as the Alberta Electric System Operator released a forecast that under-projected the amount of solar in the province’s electric grid.

The power grid operator (AESO) released its forecast on Sept. 30, which predicted that solar power projects would provide just 1 per cent of Alberta’s electricity supply by 2030 at 231 megawatts.

Shaffer said the AESO, which manages and operates the province’s electricity grid, is assuming that on a levelized basis solar power will need a price over $100 per megawatt hour for new investment. However, he said, based on recent solar contracts for government infrastructure projects, the cost is closer to $70 MW/h.

Most forecasting organizations like the International Energy Agency have had to adjust their forecasts for solar power adoption higher in the past, as growth of the renewable energy source has outperformed expectations.

Calgary-based Greengate Power has also proposed a $500-million, 400-MW solar project near Vulcan, a town roughly one-hour by car southeast of Calgary.

“So now we’re getting close to 700 MW (of solar power),” Shaffer said, which is three times the AESO forecast.

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Hong Kong Typhoon Mangkhut Power Outages strain households with blackouts, electricity disruption, and humid heat, impacting Tin Ping Estate in Sheung Shui and outlying islands; contractor-led restoration faces fines for delays and infrastructure repairs.

Key Points

They are blackout events after Typhoon Mangkhut, bringing heat stress, food spoilage, and delayed power restoration.

✅ 16 floors in Tin Ping Estate lost power after meter room blast.

✅ Contractor faces HK$100,000 daily fines for late restoration.

✅ Kat O and Ap Chau families remain off-grid in humid heat.

Nearly 600 Hong Kong families are still sweltering under the summer heat and facing dark nights without electricity after Typhoon Mangkhut cut off power supply to areas, echoing mass power outages seen elsewhere.

At Sheung Shui’s Tin Ping Estate in the New Territories, 384 families were still without power, a situation similar to the LA-area blackout that left many without service. They were told on Tuesday that a contractor would rectify the situation by Friday, or be fined HK$100,000 for each day of delay.

In remote areas such as outlying islets Kat O and Ap Chau, there were some 200 families still without electricity, similar to Tennessee storm outages affecting rural communities.

The power outage at Tin Ping Estate affected 16 floors – from the 11th to 26th – in Tin Cheung House after a blast from the meter room on the 15th floor was heard at about 5pm on Sunday, and authorities urged residents to follow storm electrical safety tips during repairs.

“I was sitting on the sofa when I heard a loud bang,” said Lee Sau-king, 61, whose flat was next to the meter room. “I was so scared that my hands kept trembling.”

While the block’s common areas and lifts were not affected, flats on the 16 floors encountered blackouts.

As her fridge was out of power, Lee had to throw away all the food she had stocked up for the typhoon. With the freezer not functioning, her stored dried seafood became soaked and she had to dry them outside the window when the storm passed.

Daily maximum temperatures rose back to 30 degrees Celsius after the typhoon, and nights became unbearably humid, as utilities worldwide pursue utility climate adaptation to maintain reliability. “It’s too hot here. I can’t sleep at all,” Lee said.

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Renewable Energy Economic Recovery drives GDP gains, job growth, and climate targets by accelerating clean energy investment, green hydrogen, and grid modernization, delivering high ROI and a resilient, low-carbon transition through stimulus and policy alignment.

Key Points

A strategy to boost GDP and jobs by accelerating clean power and green hydrogen while meeting climate goals.

✅ Adds $98tn to global GDP by 2050; $3-$8 return per $1 invested

✅ Quadruples clean energy jobs to 42m; improves health and welfare

✅ Cuts CO2 70% by 2050; enables net-zero via green hydrogen

Renewable energy could power an economic recovery from Covid-19 through a green recovery that spurs global GDP gains of almost $100tn (£80tn) between now and 2050, according to a report.

The International Renewable Energy Agency’s new IRENA report found that accelerating investment in renewable energy could generate huge economic benefits while helping to tackle the global climate emergency.

The agency’s director general, Francesco La Camera, said the global crisis ignited by the coronavirus outbreak exposed “the deep vulnerabilities of the current system” and urged governments to invest in renewable energy to kickstart economic growth and help meet climate targets.

The agency’s landmark report found that accelerating investment in renewable energy would help tackle the climate crisis and would in effect pay for itself.

Investing in renewable energy would deliver global GDP gains of $98tn above a business-as-usual scenario by 2050, as clean energy investment significantly outpaces fossil fuels, by returning between $3 and $8 on every dollar invested.

It would also quadruple the number of jobs in the sector to 42m over the next 30 years, and measurably improve global health and welfare scores, according to the report.

“Governments are facing a difficult task of bringing the health emergency under control while introducing major stimulus and recovery measures, as a US power coalition demands action,” La Camera said. “By accelerating renewables and making the energy transition an integral part of the wider recovery, governments can achieve multiple economic and social objectives in the pursuit of a resilient future that leaves nobody behind.”

The report also found that renewable energy could curb the rise in global temperatures by helping to reduce the energy industry’s carbon dioxide emissions by 70% by 2050 by replacing fossil fuels, with measures like a fossil fuel lockdown hastening the shift.

Renewables could play a greater role in cutting carbon emissions from heavy industry and transport to reach virtually zero emissions by 2050, particularly by investing in green hydrogen.

The clean-burning fuel, which can replace the fossil fuel gas in steel and cement making, could be made by using vast amounts of clean electricity to split water into hydrogen and oxygen elements.

Andrew Steer, chief executive of the World Resources Institute, said: “As the world looks to recover from the current health and economic crises, we face a choice: we can pursue a modern, clean, healthy energy system, or we can go back to the old, polluting ways of doing business. We must choose the former.”

The call for a green economic recovery from the coronavirus crisis comes after a warning from Dr Fatih Birol, head of the International Energy Agency, that government policies must be put in place to avoid an investment hiatus in the energy transition, even as the solar and wind industry faces Covid-19 disruptions.

“We should not allow today’s crisis to compromise the clean energy transition, even as wind power growth persists despite Covid-19,” he said. “We have an important window of opportunity.”

Ignacio Galán, the chairman and CEO of the Spanish renewables giant Iberdrola, which owns Scottish Power, said the company would continue to invest billions in renewable energy as well as electricity networks and batteries to help integrate clean energy in the electricity.

“A green recovery is essential as we emerge from the Covid-19 crisis. The world will benefit economically, environmentally and socially by focusing on clean energy,” he said. “Aligning economic stimulus and policy packages with climate goals is crucial for a long-term viable and healthy economy.”

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India Power Sector Crisis: a tangled market of underused plants, coal shortages, cross-subsidies, high transmission losses, and weak PPAs, requiring deregulation, power exchanges, and cost-reflective tariffs to fix insolvency and outages.

Key Points

India power market failure from subsidies, coal shortages, and losses, needing deregulation and reflective pricing.

✅ Deregulate to enable spot trading on power exchanges

✅ End cross-subsidies; charge cost-reflective tariffs

✅ Secure coal supply; cut T&D losses and theft

India's electricity industry is in a financial and political tangle.

Power producers sit on thousands of megawatts of underutilized plant, while consumers face frequent power cuts, both planned and unplanned.

Financially troubled generators struggle to escape insolvency proceedings. The state-owned banks that have mostly financed power utilities fear that debts of troubled utilities totaling 1.74 trillion rupees will soon go bad.

Aggressive bidding for supply contracts and slower-than-expected demand growth, including a recent demand slump in electricity use, is the root cause. The problems are compounded by difficulties in securing coal and other fuels, high transmission losses, electricity theft and cash-starved distribution companies.

But India's 36 state and union territory governments are contributing mightily to this financial and economic mess. They persist with populist cross-subsidies -- reducing charges for farmers and households at the cost of nonagricultural businesses, especially energy-intensive manufacturing sectors such as steel.

The states refuse to let go of their control over how electricity is produced, distributed and consumed. And they are adamant that true markets, with freedom for large industrial users to buy power at market-determined rates from whichever utility they want at power exchanges -- will not become a reality in India.

State politicians are driven mainly by the electoral need to appease farmers, India's most important vote bank, who have grown used to decades of nearly-free power.

New Delhi is therefore relying on short-term fixes instead of attempting to overhaul a defunct system. Users must pay the real cost of their electricity, as determined by a properly integrated national market free of state-level interference if India's power mess is to be really addressed.

As of Aug. 31, the country's total installed production capacity was 344,689 MW, underscoring its status as the third-largest electricity producer globally by output. Out of that, thermal power comprising coal, gas and diesel accounted for 64%, hydropower 13% and renewables accounted for 20%. Commercial and industrial users accounted for 55% of consumption followed by households on 25% and the remaining 20% by agriculture.

Coal-fired power generation, which contributes roughly 90% of thermal output and the bulk of the financially distressed generators, is the most troubled segment as it faces a secular decline in tariffs due to increasing competition from highly subsidized renewables (which also benefit from falling solar panel costs), coal shortages and weak demand.

The Central Electricity Act (CEA) 2003 opened the gates of the country's power sector for private players, who now account for 45% of generating capacity.

But easy credit, combined with an overconfident estimation of the risks involved, emboldened too many investors to pile in, without securing power purchase agreements (PPAs) with distribution companies.

As a result, power capacity grew at an annual compound rate of 11% compared to demand at 6% in the last decade leading to oversupply.

This does not mean that the electricity market is saturated. Merely that there are not enough paying customers. Distributors have plenty of consumers who will not or cannot pay, even though they have connections. There is huge unmet demand for power. There are 32 million Indian homes -- roughly 13% of the total -- mostly rural and poor with no access to electricity.

Moreover, consumption by those big commercial and industrial users which do not enjoy privileged rates is curbed by high prices, driven up by the cost of subsidizing others, extra charges on exchange-traded power and transmission and distribution losses (including theft) of 20-30%.

With renewables increasingly becoming cheaper, financially stressed distributors are avoiding long-term power purchase agreements, preferring spot markets. Meanwhile, coal shortages force generators to buy expensive imported coal supplies or cut output. The operating load for most private generators, which suffer particularly acute coal shortages in compared to state-owned utilities, has fallen from 84% in 2009-2010 to 55% now.

Smoothing coal supplies should be the top priority. Often coal is denied to power generators without long-term purchase contracts. Such discrimination in coal allocation prevails -- because the seller (state-run Coal India and its numerous subsidiaries) is an inefficient monopolist which cannot produce enough and rations coal supplies, favoring state-run generators over private.

To help power producers, New Delhi plans measures including auctioning power sales contracts with assured access to coal. However, even though coal and electricity shortages eased recently, such short-term fixes won't solve the problem. With electricity prices in secular decline, distributors are not seeking long-term supply contracts -- rather they are often looking for excuses to get out of existing agreements.

India needs a fundamental two-step reform. First, the market must be deregulated to allow most bulk suppliers and users to move to power trading exchanges, which currently account for just 10% of the market.

This would lead to genuine price discovery in a spot market and, in time, lead to the trading of electricity futures contracts. That would help in consumers and producers hedge their respective costs and revenues and safeguard their economic positions without any need for government intervention.

The second step to a healthy electricity industry is for consumers to pay the real cost of power. Cross-subsidization must end. That would promote optimal electricity use, innovation and environmental protection. Farmers enjoying nearly-free power create ecological problems by investing in water-guzzling crops such as rice and sugar cane.

Most industrial consumers, who do not have power supply privileges, have their businesses distorted and delayed by high prices. Lowering their costs would encourage power-intensive manufacturing to expand, and in the process, boost electricity demand and improve capacity utilization.

Of course, cutting theft is central to making consumers pay their way. Government officials must stop turning a blind eye to theft, especially when such transmission and distribution losses average 20%.

Politicians who want to continue subsidizing farmers or assist the poor can do so by paying cash out directly to their bank accounts, instead of wrongly relying on the power sector.

Such market-oriented reforms have long been blocked by state-level politicians, who now enjoy the influence born of operating subsidies and interfering in the sector. New Delhi must address this opposition. Narendra Modi, as a self-styled reforming prime minister, should have the courage to bite this bullet and convince state governments (starting with those ruled by his Bharatiya Janata Party) to reform. To encourage cooperation, he could offer states securing real improvements an increased share of centrally collected taxes.

Ritesh Kumar Singh is to be the chief economist of the new policy research and advocacy company Indonomics Consulting. He is former assistant director of the Finance Commission of India.

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Hydro One Avista merger faces regulatory scrutiny in Washington, Oregon, and Idaho, as political risk outweighs defensive utilities fundamentals like stable cash flow, rate base growth, EPS outlook, and a near 5% dividend yield.

Key Points

A planned Hydro One-Avista acquisition awaiting key state approvals amid elevated political and regulatory risk.

✅ Hold rating, $24 price target, 28.1% implied return

✅ EPS forecast: $1.27 in 2018; $1.38 in 2019

✅ Defensive utility: stable cash flow, 4-6% rate base growth

A seemingly positive development for Hydro One is overshadowed by ongoing political and regulatory risk, as seen after the CEO and board ouster, Industrial Alliance Securities analyst Jeremy Rosenfield says.

On October 4, staff from the Washington Utilities and Transportation Commission filed updated testimony in support of the merger of Hydro One and natural gas distributor Avista, which had previously received U.S. antitrust clearance from federal authorities.

The merger, which was announced in July of 2017 has received the green light from federal and key states, with Washington, Oregon and Idaho being exceptions, though the companies would later seek reconsideration from U.S. regulators in the process.

But Rosenfield says even though decisions from Oregon and Idaho are expected by December, there are still too many unknowns about Hydro One to recommend investors jump into the stock.

Hydro One stock defensive but risky

“We continue to view Hydro One as a fundamentally defensive investment, underpinned by (1) stable earnings and cash flows from its regulated utility businesses (2) healthy organic rate base and earning growth (4-6%/year through 2022) and (3) an attractive dividend (~5% yield, 70-80% target payout),” the analyst says. “In the meantime, and ahead of key regulatory approvals in the AVA transaction, we continue to see heightened political/regulatory risk as an overhand on the stock, outweighing Hydro One’s fundamentals in the near term.”

In a research update to clients today, Rosenfield maintained his “Hold” rating and one year price target of $24.00 on Hydro One, implying a return of 28.1 per cent at the time of publication.

Rosenfield thinks Hydro One will generate EPS of $1.27 per share in fiscal 2018, even though its Q2 profit plunged 23% as electricity revenue fell. He expects that number will improve to EPS of $1.38 a share the following year.

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Ontario Electricity Capacity Gap threatens reliability as IESO forecasts shortfalls from the Pickering shutdown and rapid electrification, requiring new low-emission nuclear generation to meet net-zero targets, maintain baseload, and stabilize the grid.

Key Points

Expected 2030 shortfalls from Pickering closure and electrification, requiring new low-emission nuclear to meet net-zero.

✅ IESO projects a 3.6-9.5 GW capacity gap by 2030

✅ Pickering shutdown removes baseload, stressing reliability

✅ New low-emission nuclear needed to meet net-zero targets

Ontario faces an electricity supply shortage and reliability risks in the next four to eight years and will not meet net-zero objectives without building new low-emission, nuclear generation starting as soon as possible, according to a report released yesterday by the Power Workers' Union (PWU). The capacity needed to fill the expected supply gap will be equivalent to doubling the province's planned nuclear fleet in eight years.

The planned closure of the Pickering nuclear power plant in 2025 and the increase in demand from electrification of the economy are the drivers behind a capacity gap in 2030 of at least 3.6 GW which could widen to as much as 9.5 GW, Electrification Pathways for Ontario to Reduce Emissions, finds. Ontario's Independent Electricity System Operator (IESO) has since 2013 been forecasting a significant gap in the province's electricity supply due the closure of Pickering, but has been underestimating the impact of electrification, the report says.

In addition, the electrification of buildings, transport and industry sectors that will be needed to achieve goals of net-zero emissions by 2050 that being set by the federal government and civil society will see the province's electricity demand increase by at least 130% over current planning forecasts, and potentially by over 190%. Leveraging electricity, natural gas and hydrogen synergies can reduce supply needs, but 55 GW of new electricity capacity, including new large-scale nuclear plants, will still be needed by 2050 - four times Ontario's current nuclear and hydro assets - the report finds.

These findings underscore the urgent need for a paradigm shift in Ontario's electricity planning and procurement process, the authors say, adding that immediate action is needed both to mitigate the system reliability risks and enable the significant societal benefits needed to pursue net-zero objectives. Planning for procurement to replace Pickering's capacity, or to pursue life extension options, must begin as soon as possible.

"Policymakers around the world realise climate change can't be tackled without nuclear. Ontario's nuclear fleet has delivered emissions reductions for over 50 years," PWU President Jeff Parnell said. "In fact, without building new nuclear units, Ontario will miss its emission reduction targets and carbon emissions from electricity generation will rise dramatically, as explored in why Ontario's power could get dirtier today."

"This report clearly shows that Ontario cannot sustain the low-carbon status of its hydro and nuclear-based electricity system, decarbonise its economy and meet its carbon reduction targets without new nuclear or continued operation at Pickering in the near term. Most disturbing is the fact that we are already well behind and needed to start planning for this capacity yesterday," he said.

The six operating Candu reactors at Ontario Power Generation's Pickering plant have been kept in operation to provide baseload electricity during the refurbishment of units at the Darlington and Bruce plants. Currently, the company plans to shut down Pickering units 1 and 4 in 2024 and units 5 to 8 in 2025, even as Ontario moves to refurbish Pickering B to extend life.

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