Ocean Waves Can Be Effectively Harnessed Through New Wave-Pump Technology

Cerro Dominador CSP Plant delivers 110MW concentrated solar power in Chile's Atacama Desert, with 10,600 heliostats, 17.5-hour molten salt storage, and 24/7 dispatchable energy; built by Acciona and Abengoa within a 210MW complex.

Key Points

A 110MW CSP solar-thermal plant in Chile with heliostats and 17.5h molten salt storage, delivering 24/7 dispatchable clean power.

✅ 110MW CSP with 17.5h molten salt for 24/7 dispatch

✅ 10,600 heliostats; part of a 210MW hybrid CSP+PV complex

✅ Built by Acciona and Abengoa; first of its kind in LatAm

A consortium formed by Spanish groups Abengoa and Acciona, as Spain's renewable sector expands with Enel's 90MW wind build activity, has signed a contract to complete the construction of the 110MW Cerro Dominador concentrated solar power (CSP) plant in Chile.

The consortium received notice to proceed to build the solar-thermal plant, which is part of the 210MW Cerro Dominador solar complex.

Under the contract, Acciona, which has 51% stake in the consortium and recently launched a 280 MW Alberta wind farm, will be responsible for building the plant while Abengoa will act as the technological partner.

Expected to be the first of its kind in Latin America upon completion, the plant is owned by Cerro Dominador, which in turn is owned by funds managed by EIG Global Energy Partners.

The project will add to a Abengoa-built 100MW PV plant, comparable to California solar projects in scope, which was commissioned in February 2018, to form a 210MW combined CSP and PV complex.

Spread across an area of 146 hectares, the project will feature 10,600 heliostats and will have capacity to generate clean and dispatachable energy for 24 hours a day using its 17.5 hours of molten salt storage technology, a field complemented by battery storage advances.

Expected to prevent 640,000 tons of CO2 emission, the plant is located in the commune of María Elena, in the Atacama Desert, in the Antofagasta Region.

“In total, the complex will avoid 870,000 tons of carbon dioxide emissions into the atmosphere every year and, in parallel with Enel's 450 MW U.S. wind operations, will deliver clean energy through 15-year energy purchase agreements with distribution companies, signed in 2014.

“The construction of the solarthermal plant of Cerro Dominador will have an important impact on local development, with the creation of more than 1,000 jobs in the area during its construction peak, and that will be priority for the neighbors of the communes of the region,” Acciona said in a statement.

The Cerro Dominador plant represents Acciona’s fifth solar thermal plant being built outside of Spain. The firm has constructed 10 solarthermal plants with total installed capacity of 624MW.

Acciona has been operating in Chile since 1993. The company, through its Infrastructure division, executed various construction projects for highways, hospitals, hydroelectric plants and infrastructures for the mining sector.

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Nunavut electricity rate increase sees QEC raise domestic electricity rates 6.6% over two years, affecting customer rates, base rates, subsidies, and kWh overage charges across communities, with public housing exempt and territory-wide pricing denied.

Key Points

A 6.6% QEC hike over 2018-2019, affecting customer rates, subsidies, and kWh overage; public housing remains exempt.

✅ 3.3% on May 1, 2018; 3.3% on Apr 1, 2019

✅ Subsidy caps: 1,000 kWh Oct-Mar; 700 kWh Apr-Sep

✅ Territory-wide base rate denied; public housing exempt

Ahead of the Nunavut government's approval of the general rate increase for the Qulliq Energy Corporation, many Nunavummiut wondered how the change would impact their electricity bills.

QEC's request for a 6.6-per-cent increase was approved by the government last week. The increase will be spread out over two years, a pattern similar to BC Hydro's two-year rate plan, with the first increase (3.3 per cent) effective May 1, 2018. The remaining 3.3 per cent will be applied on April 1, 2019.

Public housing units, however, are exempt from the government's increase altogether.

The power corporation also asked for a territory-wide rate, so every community would pay the same base rate (we'll go over specific terms in a minute if you're not familiar with them). But that request was denied, even as Manitoba Hydro scaled back increases next year, and QEC will now take the next two years reassessing each community's base rate.

#google#

So, what does this mean for your home's power bill? Well, there's a few things you need to know, which we'll get to in a second.

But in essence, as long as you don't go over the government-subsidized monthly electricity usage limit, you're paying an extra 3.61 cents per kilowatt hour (kWh).

To be clear, we're talking about non-government domestic rates — basically, private homeowners — and those living in a government-owned unit but pay for their own power.

The basics

First, some quick terminology. The "base rate" term we're going to use (and used above) in this story refers to the community rate. As in, what QEC charges customers in every community. The "customer rate" is the rate customers actually pay, after the government's subsidy.

The first thing you need to know is everyone in Nunavut starts off by paying the same customer rate, unlike jurisdictions using a price cap to limit spikes.

That's because the government subsidizes electricity costs, and that subsidy is different in every community, because the base rate is different.

For example, Iqaluit's new base rate after the 3.3 per cent increase (remember, the 6.6 per cent is being applied over two years) is 56.69 cents per kWh, while Kugaaruk's base rate rose to 112.34 cents per kWh. Those, by the way, are the territory's lowest and highest respective base rates.

However, customers in both Iqaluit and Kugaaruk will each now pay 28.35 cents per kWh because, remember, the government subsidizes the base rates in every community.

Now, remember earlier we mentioned a "government-subsidized monthly electricity usage limit?" That's where customers in various communities start to pay different amounts.

As simply as we can explain it, the government will only cover so much electricity usage in a month, in every household.

Between October and March, the government will subsidize the first 1,000 kilowatt hours, and only 700 kilowatt hours from April to September. QEC says the average Nunavut home will use about 500 kilowatt hours every month over the course of a year.

But if your household goes over that limit, you're at the mercy of your community's base rate for any extra electricity you use. Homes in Kugaaruk in December, for instance, will have to pay that 122.34 cents for every extra kilowatt hour it uses, while homes in Iqaluit only have to pay 56.69 cents per kWh for its extra electricity.

That's where many Nunavummiut have criticized the current rate structure, because smaller communities are paying more for their extra costs than larger communities.

QEC had hoped — as it had asked for — to change the structure so every community pays the same base rate. So regardless of if people go over their electricity usage limits for the government subsidy, everyone would pay the same overage rates.

But the government denied that request.

New rate is actually lower

The one thing we should highlight, however, is the new rate after the increase is actually lower than what customers were paying in 2014.

For the past seven months, customers have been getting power from QEC at a discount, whereas Newfoundland customers began paying for Muskrat Falls during the same period, to different effect.

That's because when QEC sets its rates, it does so based on global oil price forecasts. Since 2014, the price of oil worldwide has slumped, and so QEC was able to purchase it at less than it had anticipated.

When that happens, and QEC makes more than $1 million within a six month period thanks to the lower oil prices, it refunds the excess profits back to customers through a discount on electricity base rates — a mechanism similar to a lump-sum credit used elsewhere — the government subsidy, however, doesn't change so the savings are passed on directly to customers.

Now, the 6.6 per cent increase to electricity rates, is actually being applied to the discounted base rate from the last seven months.

So again, while customers are paying more than they have been for the last seven months, it's lower than what they were paying in 2014.

Lastly, to be clear, all the figures used in this story are only for domestic non-government rates. Commercial rates and changes have not been explored in this story, given the differences in subsidy and rate application.

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Iraq Nuclear Power Plan targets eight reactors and 11 GW to ease blackouts, curb emissions, and support desalination, with financing via partners like Rosatom and Kepco amid OPEC-linked demand growth and chronic grid shortages.

Key Points

A $40B push to build eight reactors adding 11 GW, easing blackouts, cutting emissions, and supporting desalination.

✅ $40B, 20-year payback via partner financing

✅ Talks with Rosatom, Kepco; U.S. and France consulted

✅ Parallel solar buildout to meet 2030 demand

Iraq is working on a plan to build nuclear reactors as the electricity-starved petrostate seeks to end the widespread blackouts that have sparked social unrest.

OPEC’s No. 2 oil producer – already suffering from power shortages and insufficient investment in aging plants – needs to meet an expected 50% jump in demand by the end of the decade. Building atomic plants could help to close the supply gap, though the country will face significant financial and geopolitical challenges in bringing its plan to fruition.

Iraq seeks to build eight reactors capable of producing about 11 gigawatts, said Kamal Hussain Latif, chairman of the Iraqi Radioactive Sources Regulatory Authority. It would seek funding from prospective partners for the $40 billion plan and pay back the costs over 20 years, he said, adding that the authority had discussed cooperation with Russian and South Korean officials, as Iran-Iraq energy cooperation progresses across the sector.

Plunging crude prices last year deprived Iraq of funds to maintain and expand its long-neglected electricity system, though grid rehabilitation deals have been finalized to support upgrades. The resulting outages triggered protests that threatened to topple the government.

“We have several forecasts that show that without nuclear power by 2030, we will be in big trouble,” Latif said in an interview at his office in Baghdad. Not only is there the power shortage and surge in demand to deal with, but Iraq is also trying to cut emissions and produce more water via desalination — “issues that raise the alarm for me.”

Raising financing will be a major task given that Iraq has suffered budgetary crises amid volatile oil prices. Even with crude at about $70 a barrel now, the country is only just balancing its budget, according to data from the International Monetary Fund.

The government will also have to tackle geopolitical concerns around the safety of atomic energy, which have stymied nuclear ambitions elsewhere in the region, even as Europe's nuclear decline underscores broader energy challenges.

Nuclear power, which doesn’t produce carbon dioxide, would help Gulf states’ efforts to cut emissions as governments worldwide, including India's nuclear push to expand capacity, look to become greener. The technology would also allow them to earmark more of their valuable hydrocarbons for export. Saudi Arabia, which is building a test reactor, burns as much as 1 million barrels of crude a day in power plants during its summer months when temperatures soar beyond 50 degrees Celsius (122 Fahrenheit).

The Iraqi cabinet is reviewing an agreement with Russia’s Rosatom Corp. to cooperate in building reactors, Latif said. South Korean officials this year said they wanted to help build the plants and offered the Iraqis a tour of UAE nuclear reactors run by Korea Electric Power Corp. Latif said the nuclear authority has also spoken with French and U.S. officials about the plan.

Kepco, Rosatom
Kepco, as the Korean energy producer is known, is not aware of Iraq’s nuclear plans and hasn’t been in touch with Iraqi officials or been asked to work on any projects there, a company spokesman said Tuesday. Rosatom didn’t immediately comment when asked about an agreement with Iraq.

Even if Iraq builds the planned number of power stations, that still won’t be sufficient to cover future consumption. The country already faces a 10-gigawatt gap between capacity and demand and expects to need an additional 14 gigawatts this decade, Latif said.

With this in mind, Iraq plans to build enough solar plants to generate a similar amount of power to the nuclear program by the end of the decade.
Iraq currently boasts 18.4 gigawatts of electricity, including 1.2 gigawatts imported from Iran into the grid. Capacity additions mean generation will rise to as much as 22 gigawatts by August, but that’s well short of notional demand that stands at almost 28 gigawatts under normal conditions. Peak usage during the hot summer months of July and August exceeds 30 gigawatts, according to the Electricity Ministry. Demand will hit 42 gigawatts by 2030, Latif said.

The nuclear authority has picked 20 potential sites for the reactors and Latif suggested that the first contracts could be signed in the next year.

It won’t be Iraq’s first attempt to go nuclear. Four decades ago, an Israeli air strike destroyed a reactor under construction south of Baghdad. The Israelis alleged the facility, called Osirak, was aimed at producing nuclear weapons for use against them. Iraq suffered more than a decade of violence and upheaval after the 2003 U.S. invasion, which was also motivated by allegations that Iraq wanted to develop weapons.

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Hydro One Power Restoration showcases outage recovery after a severe windstorm, with crews repairing downed power lines, broken poles and crossarms, partnering with utilities and contractors to boost grid resilience and promote emergency kit preparedness.

Key Points

A coordinated response by Hydro One and partners to repair storm damage, restore outages, strengthen grid resilience.

✅ Crews repaired downed lines, broken poles, and crossarms

✅ Partners and contractors aided rapid outage restoration

✅ Investments improve grid resilience and emergency readiness

Hydro One crews have restored power to more than 277,000 customers following back-to-back storms, with impacts felt in communities like Sudbury where local crews worked to reconnect service, including a damaging windstorm on that caused 57 broken poles, 27 broken crossarms, as well as downed power lines and fallen trees on lines. Hydro One crews restored power to more than 140,000 customers within 24 hours of Friday's windstorm, even as Toronto outages persisted for some customers elsewhere.

'We understand power outages bring life to a halt, which is why we are continuously improving our storm response, as employee COVID-19 support demonstrated, while making smart investments in a resilient, reliable and sustainable electricity system to energize life for families, businesses and communities for years to come,' said David Lebeter, Chief Operating Officer, Hydro One. 'We thank our customers for their patience as our crews worked tirelessly, alongside our utility partners and contractors, including Ontario crews in Florida, to restore power as quickly and as safely as possible.'

Hydro One thanks all of its utility partners and contractors who assisted with restoration efforts following the windstorm (alongside similar Quebec outages that highlighted the broader impact), including Durham High Voltage, EPCOR, ERTH Power, K-Line Construction Ltd., Lakeland Power Distribution Ltd., North Bay Hydro, Sproule Powerline Construction Ltd. and Valard Construction.

Hydro One encourages customers to restock their emergency kits following these storms, which utilities such as BC Hydro have also characterized as atypical, and to be aware of support programs like our pandemic relief fund that can help during difficult periods, to ensure they're prepared for an emergency or extended power outage.

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Lawa Hydropower Station approved on the Jinsha River, a Yangtze tributary, delivers 2,000 MW via four units; 784 ft dam, 12 sq mi reservoir, Sichuan-Tibet site, US$4.59b investment, Huadian stake, renewable energy generation.

Key Points

A 2,000 MW dam project on the Jinsha River with four units, a 784 ft barrier, and 8.36 billion kWh annual output.

✅ Sichuan-Tibet junction on the Jinsha River

✅ 2,000 MW capacity; four turbine-generator units

✅ 8.36 bn kWh/yr; US$4.59b total; Huadian 48% stake

China has approved construction of the 2,000-MW Lawa hydropower station, a Yangtze tributary hydropower project on the Jinsha River, multiple news agencies are reporting.

Lawa, at the junction of Sichuan province and the Tibet autonomous region, will feature a 784-foot-high dam and the reservoir will submerge about 12 square miles of land. The Jinsha River is a tributary of the Yangtze River, and the project aligns with green hydrogen development in China.

The National Development and Reform Commission of the People’s Republic of China, which also guides China's nuclear energy development as part of national planning, is reported to have said that four turbine-generator units will be installed, and the project is expected to produce about 8.36 billion kWh of electricity annually.

Total investment in the project is to be US$4.59 billion, and Huadian Group Co. Ltd. will have a 48% stake in the project, reflecting overseas power infrastructure activity, with minority stakes held by provincial firms, according to China Daily.

In other recent news in China, Andritz received an order in December 2018 to supply four 350-MW reversible pump-turbines and motor-generators, alongside progress in compressed air generation technologies, for the 1,400-MW ZhenAn pumped storage plant in Shaanxi province.

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Ontario Pickering Nuclear Closure will shift supply to natural gas, raising emissions as the electricity grid manages nuclear refurbishment, IESO planning, clean power imports, and new wind, solar, and storage to support electrification.

Key Points

Ontario will close Pickering and rely on natural gas, increasing emissions while other nuclear units are refurbished.

✅ 14% of Ontario electricity supplied by Pickering now

✅ Natural gas use rises; grid emissions projected up 375%

✅ IESO warns gas phaseout by 2030 risks blackouts, costs

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall with natural gas-generated power in a move that will, as an analysis of Ontario's grid shows, hike the province’s greenhouse gas emissions substantially in the coming years.

In a report released this week, a nuclear advocacy group urged Ontario to refurbish the aging facility east of Toronto, which is set to be shuttered in phases in 2024 and 2025, prompting debate over a clean energy plan after Pickering as the closure nears. The closure of Pickering, which provides 14 per cent of the province’s annual electricity supply, comes at the same time as Ontario’s other two nuclear stations are undergoing refurbishment and operating at reduced capacity.

Canadians for Nuclear Energy, which is largely funded by power workers' unions, argued closing the 50-year-old facility will result in job losses, emissions increases, heightened reliance on imported natural gas and an electricity supply gap across Ontario.

But Palmer Lockridge, spokesperson for the provincial energy minister, said further extending Pickering’s lifespan isn’t on the table.

“As previously announced in 2020, our government is supporting Ontario Power Generation’s plan to safely extend the life of the Pickering Nuclear Generating Station through the end of 2025,” said Lockridge in an emailed response to questions.

“Going forward, we are ensuring a reliable, affordable and clean electricity system for decades to come. That’s why we put a plan in place that ensures we are prepared for the emerging energy needs following the closure of Pickering, and as a result of our government’s success in growing and electrifying the province’s economy.”

The Progressive Conservative government under Premier Doug Ford has invested heavily in electrification, sinking billions into electric vehicle and battery manufacturing and industries like steel-making to retool plants to run on electricity rather than coal, and exploring new large-scale nuclear plants to bolster baseload supply.

Natural gas now provides about seven per cent of the province’s energy, a piece of the pie that will rise significantly as nuclear energy dwindles. Emissions from Ontario’s electricity grid, which is currently one of the world’s cleanest with 94 per cent zero-emission power generation, are projected to rise a whopping 375 per cent as the province turns increasingly to natural gas generation. Those increases will effectively undo a third of the hard-won emissions reductions the province achieved by phasing out coal-fired power generation.

The Independent Electricity System Operator (IESO), which manages Ontario’s grid, studied whether the province could phase out natural gas generation by 2030 and concluded that “would result in blackouts and hinder electrification” and increase average residential electricity costs by $100 per month.

The Ontario Clean Air Alliance, however, obtained draft documents from the electricity operator that showed it had studied, but not released publicly, other scenarios that involved phasing out natural gas without energy shortfalls, price hikes or increases in emissions.

The Ontario government will not reconsider plans to close the Pickering nuclear station and instead stop-gap the consequent electricity shortfall facing Ontario with natural gas-generated power in a move that will hike the province’s greenhouse gas emissions.

One model suggested increasing carbon taxes and imports of clean energy from other provinces could keep blackouts, costs and emissions at bay, while another involved increasing energy efficiency, wind generation and storage.

“By banning gas-fired electricity exports to the U.S., importing all the Quebec water power we can with the existing transmission lines and investing in energy efficiency and wind and solar and storage — do all those things and you can phase out gas-fired power and lower our bills,” said Jack Gibbons, chair of the Ontario Clean Air Alliance.

The IESO has argued in response that the study of those scenarios was not complete and did not include many of the challenges associated with phasing out natural gas plants.

Ontario Energy Minister Todd Smith asked the IESO to develop “an achievable pathway to zero-emissions in the electricity sector and evaluate a moratorium on new-build natural gas generation stations,” said his spokesperson. That report, an early look at halting gas power, is expected in November.

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