Sunrise Solar negotiates for $30 million contract

Self-healing grid technology automatically reroutes power to reduce outages, speed restoration, and boost reliability during storms like Hurricane Ian in Florida, leveraging smart grid sensors, automation, and grid hardening to support Duke Energy customers.

Key Points

Automated smart grid systems that detect faults and reroute power to minimize outages and accelerate restoration.

✅ Cuts outage duration via automated fault isolation

✅ Reroutes electricity with sensors and distribution automation

✅ Supports storm resilience and faster field crew restoration

As Hurricane Ian made its way across Florida, where restoring power in Florida can take weeks in hard-hit areas, Duke Energy's grid improvements were already on the job helping to combat power outages from the storm.

Smart, self-healing technology, similar to smart grid improvements elsewhere, helped to automatically restore more than 160,000 customer outages and saved nearly 3.3 million hours (nearly 200 million minutes) of total lost outage time.

"Hurricane Ian is a strong reminder of the importance of grid hardening and storm preparedness to help keep the lights on for our customers," said Melissa Seixas, Duke Energy Florida state president. "Self-healing technology is just one of many grid improvements that Duke Energy is making to avoid outages, restore service faster and increase reliability for our customers."

Much like the GPS in your car can identify an accident ahead and reroute you around the incident to keep you on your way, self-healing technology is like a GPS for the grid. The technology can quickly identify power outages and alternate energy pathways to restore service faster for customers when an outage occurs.

Additionally, self-healing technology provides a smart tool to assist crews in the field with power restoration after a major storm like Ian, helping reduce outage impacts and freeing up resources to help restore power in other locations.

Three days after Hurricane Ian exited the state, Duke Energy Florida wrapped up restoration of approximately 1 million customers. This progress enabled the company to deploy more than 550 Duke Energy workers from throughout Florida, as well as contractors from across the country, to help restore power for Lee County Electric Cooperative customers.

Crews worked in Cape Coral and Pine Island, one of the hardest-hit areas in the storm's path, as Canadian power crews have in past storms, and completed power restoration for the majority of customers on Pine Island within approximately one week after arriving to the island.

Prior to Ian in 2022, smart, self-healing technology had helped avoid nearly 250,000 extended customer outages in Florida, similar to Hydro One storm recovery efforts, saving around 285,000 hours (17.1 million minutes) of total lost outage time.

Duke Energy currently serves around 59% of customers in Florida with self-healing capabilities on its main power distribution lines, with a goal of serving around 80% over the next few years.

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Ofgem Renewables Obligations drive supplier payments for renewables fees, feed-in tariffs, and renewable generation, with non-payment risking supply licences amid the price cap and volatile wholesale prices across the UK energy market.

Key Points

Mandatory payments by suppliers funding renewables via feed-in tariffs; non-payment can trigger supply licence revoking.

✅ Covers Renewables Obligation and Feed-in Tariff scheme compliance.

✅ Non-payment can lead to Ofgem action and licence loss.

✅ Affected by price cap and wholesale price volatility.

Seven small British energy suppliers owe a total of 34 million pounds ($43.74 million) in renewables fees, amid a renewables backlog that has stalled projects, and could face losing their supply licences if they cannot pay, energy regulator Ofgem reports.

Under Britain’s energy market rules, suppliers of energy must meet so-called renewables obligations and feed-in tariffs, including households' ability to sell solar power back to energy firms, which are imposed on them by the government to help fund renewable power generation.

Several small energy companies have gone bust over the past two years, a trend echoed by findings from a global utility study on renewable priorities, as they struggled to pay the renewables fees and as their profits were affected by a price cap on the most commonly used tariffs and fluctuating wholesale prices, even as a 10 GW contract brings new renewable capacity onto the UK grid.

Ofgem has called on the companies to make necessary payments by Oct. 31, as moves to offer community-generated power to all UK customers progress.

“If they do not pay Ofgem could start the process of revoking their licences to supply energy,” it said in a statement, as offshore wind power continues to scale nationwide.

The seven suppliers are, amid debates over clean energy impacts, Co-Operative Energy Limited; Flow Energy Limited; MA Energy Limited; Nabuh Energy Limited; Robin Hood Energy Limited; Symbio Energy Limited and Tonik Energy Limited. ($1 = 0.7773 pounds)

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France Electricity Crisis drives record power prices as nuclear outages squeeze supply, forcing energy imports, fuel oil and coal generation, amid gas market shocks, weak wind output, and freezing weather straining the grid.

Key Points

A French power shortfall from nuclear outages, record prices, heavy imports, and oil-fired backup amid cold weather.

✅ EDF halted reactors; 10% capacity offline, 30% by January

✅ Imports surge; fuel oil and coal units dispatched

✅ Prices spike as gas reverses flow and wind output drops

Electricity prices surged to a fresh record as France scrambled to keep its lights on, sucking up supplies from the rest of Europe.

France, usually an exporter of power, is boosting electricity imports and even burning fuel oil, and has at times limited nuclear output due to high river temperatures during heatwaves. The crunch comes after Electricite de France SA said it would halt four reactors accounting for 10% of the nation’s nuclear capacity, straining power grids already facing cold weather. Six oil-fired units were turned on in France on Tuesday morning, according to a filing with Entsoe.

“It’s illustrating how severe it is when they’re actually starting to burn fuel oil and importing from all these countries,” said Fabian Ronningen, an analyst at Rystad Energy. The unexpected plant maintenance “is reflected in the market prices,” he said

Europe is facing an energy crisis, with utilities relying on coal and oil. Almost 30% of France’s nuclear capacity will be offline at the beginning of January, leaving the energy market at the mercy of the weather. To make matters worse, Germany is closing almost half of its nuclear capacity before the end of the year, as Europe loses nuclear power just when it really needs energy.

German power for delivery next year surged 10% to 278.50 euros a megawatt-hour, while the French contract for January added 9.5% to a record 700.60 euros. Prices also gained, under Europe’s marginal pricing system, as gas jumped after shipments from Russia via a key pipeline reversed direction, flowing eastward toward Poland instead.

Neighboring countries are boosting their exports to France this week to cover for lost nuclear output, with imports from Germany rising to highest level in at least four years. In the U.K., four coal power units were operating on Tuesday with as much as 1.5 gigawatts of hourly output being sent across the channel. 

The power crisis is so severe that the French government has asked EDF to restart some nuclear reactors earlier than planned amid outage risks for nuclear-powered France. Ecology Minister Barbara Pompili said last weekend that, in addition to the early reactor restarts and past river-temperature limits, the country had contracts with some companies in which they agreed to cut production during peak demand hours in exchange for payments from the government.

Higher energy prices threaten to derail Europe’s economic recovery just as the coronavirus omicron variety is spreading. Trafigura Group’s Nyrstar will pause production at its zinc smelter in France in the first week of January because of rising electricity prices. Norwegian fertilizer producer Yara International, which curbed output earlier this year, said it would continue to monitor the situation closely and curtail production where necessary.

Freezing weather this week is also sending short-term power prices surging as renewables can’t keep up, even though wind and solar overtook gas in the EU last year. German wind output plunged to a five-week low on Tuesday.

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Ontario Darlington SMR Expansion advances four GE Hitachi BWRX-300 reactors with OPG, adding 1,200 MW of baseload nuclear power to support electrification, grid reliability, and clean energy growth across Ontario and Saskatchewan.

Key Points

Plan to build four BWRX-300 SMRs at Darlington, delivering 1,200 MW of clean, reliable baseload power under OPG.

✅ Four GE Hitachi BWRX-300 units, 1,200 MW total

✅ Shared infrastructure cuts costs and timelines

✅ Supports electrification, grid reliability, net zero

The day after Ontario announced it would be building an additional 4,800 megawatts of nuclear reactors at Bruce Nuclear Generating Station, the province announced it would be dramatically expanding its planned rollout of small modular reactors at its Darlington Nuclear Generating Station, and confirmed plans to refurbish Pickering B as part of its broader strategy.

Ontario Power Generation OPG was always going to be the first to build the GE-Hitachi BWRX-300 small modular reactor SMR, with the U.S.’s Tennessee Valley Authority among others like SaskPower and several European nations following suit. But the OPG was originally going to build just one. On July 7, OPG and the Province of Ontario announced they would be bumping that up to four units of the BWRX-300.

The Ontario government is working with Ontario Power Generation (OPG) to commence planning and licensing for three additional small modular reactors (SMRs), for a total of four SMRs at the Darlington nuclear site. Once deployed, these four units would produce a total 1,200 megawatts (MW) of electricity, equivalent to powering 1.2 million homes, helping to meet increasing demand from electrification and fuel the province’s strong economic growth, the Ontario Ministry of Energy said in a release.

“Our government’s open for business approach has led to unprecedented investments across the province — from electric vehicles and battery manufacturing to critical minerals to green steel,” said Todd Smith, Minister of Energy. “Expanding Ontario’s world-leading SMR program will ensure we have the reliable, affordable and clean electricity we need to power the next major international investment, the new homes we are building and industries as they grow and electrify.”

For the first time since 2005, Ontario’s electricity demand is rising. While the government has implemented its plan to meet rising electricity demand this decade, the experts at Ontario’s Independent Electricity System Operator have recommended the province advance new nuclear generation and pursue life-extension at Pickering NGS to provide reliable, baseload power to meet increasing electricity needs in the 2030s and beyond.

Subject to Ontario Government and Canadian Nuclear Safety Commission (CNSC) regulatory approvals on construction, the additional SMRs could come online between 2034 and 2036. That is the same timeframe that SaskPower is looking at for its first, and possibly second, units.

The initial unit is expected to go online in 2028 following Ontario’s first SMR groundbreaking at Darlington.

The Darlington site, which already hosts four reactors, was originally considered for an expansion of “large nuclear,” which is why OPG was already well on its way for site approvals of additional nuclear power generation. The plan changed to one, singular, SMR. Now that has been updated to four.

The announcement has significant impact on Saskatchewan, and its plans to build four of its own SMRs. The timing would allow Ontario Power Generation to apply learnings from the construction of the first unit to deliver cost savings on subsequent units. This is also the strategy SaskPower is following – allow Ontario to build the first, then learn from that experience.

Building multiple units will also allow common infrastructure such as cooling water intake, transmission connection and control room to be utilized by all four units instead of just one, reducing costs even further, the Ministry said.

“A fleet of SMRs at the Darlington New Nuclear Site is key to meeting growing electricity demands and net zero goals,” said Ken Hartwick, OPG President and CEO. “OPG has proven its large nuclear project expertise through the on-time, on budget Darlington Refurbishment project. By taking a similar approach to building a fleet of SMRs, we will deliver cost and schedule savings, and power 1.2 million homes from this site by the mid-2030s.”

The Darlington SMR project is situated on the traditional and treaty territories of the seven Williams Treaties First Nations and is also located within the traditional territory of the Huron Wendat peoples. OPG is actively engaging and consulting with potentially impacted Indigenous communities, including exploring economic opportunities in the Darlington SMR project such as commercial participation and employment.

The Ministry noted, “Ontario’s robust nuclear supply chain is uniquely positioned to support SMR development and deployment in Ontario, Canada and globally. Building additional SMRs at Darlington would provide more opportunities for Ontario companies and broader economic benefits as suppliers of nuclear equipment, components, and services to make further investments to expand their operation to serve the growing SMR market both domestically and abroad.”

Supporting new SMR development and investing in nuclear power is part of the Ontario government’s larger plan, aligned with a Canadian interprovincial nuclear initiative that brings provinces together, to prepare for electricity demand in the 2030s and 2040s that will build on Ontario’s clean electricity advantage and ensure the province has the power to maintain it’s position as leader in job creation and a magnet for the industries of the future, the Ministry said.

In February, World Nuclear News (WNN) reported that Poland was considering up to 79 small modular reactors of the same design as OPG and SaskPower. And on June 5, it reported, “Canada’s Ontario Power Generation will provide operator services to Poland’s Orlen Synthos Green Energy under a letter of intent signed between the partners, extending their existing cooperation on the deployment of small modular reactors.”

WNN added, “The letter of intent is aimed at concluding future agreements under which OPG and its subsidiaries could provide operator services for SMR reactors to OSGE in connection with the deployment of SMRs in Poland and other European countries. The partnership would include a number of SMR-related activities including: development and deployment; operations and maintenance; operator training; commissioning; and regulatory support.”

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Idaho Power Valmy Settlement outlines early closure of the North Valmy coal-fired plant in Nevada, accelerated depreciation recovery, a 1.17% base-rate increase, and impacts for customers, NV Energy co-ownership, and Idaho Public Utilities Commission review.

Key Points

A proposed agreement to close North Valmy early, recover costs via a 1.17% rate hike, and seek PUC approval.

✅ Unit 1 closes 2019; Unit 2 closes 2025 in Nevada.

✅ 1.17% base-rate hike; about $1.20 per 1,000 kWh monthly bill.

✅ Idaho PUC comment deadline May 25; NV Energy co-owner.

State regulators have set a May 25 deadline for public comment on a proposed settlement related to the early closure of a coal-fired plant co-owned by Idaho Power, even as some utilities plan to keep a U.S. coal plant running indefinitely in other jurisdictions.

The settlement calls for shuttering Unit 1 of the North Valmy Power Plant in Nevada in 2019, with Unit 2 closing in 2025, amid regional coal unit retirements debates. The units had been slated for closure in 2031 and 2035, respectively.

If approved by the Idaho Public Utilities Commission, the settlement would increase base rates by approximately $13.3 million, or 1.17 percent, in order to allow the company to recover its investment in the plant on an accelerated basis.

That equates to an additional $1.20 on the monthly bill of the typical residential customer using 1,000 kilowatt-hours of energy per month.

Idaho Power, which co-owns the plant with NV Energy, maintains that closing Valmy early rather than continuing to operate it until it is fully depreciated in 2035, will ultimately save customers $103 million in today's dollars.

The company said a significant decrease in market prices for electricity has made it uneconomic to operate the plant except during extremely cold or hot weather, when the demand for energy peaks, a trend underscored by transactions involving the San Juan Generating Station deal elsewhere. The company also said plant balances have increased by approximately $70 million since its last general rate case in 2011, due to routine maintenance and repairs, as well as investments required to meet environmental regulations.

The proposed settlement reflects a number of changes to Idaho Power's original proposal regarding Valmy, and comes in the wake of discussions with interested parties in February and April, against the backdrop of a broader energy debate over plant closures and reliability.

In its initial application, filed in October, Idaho Power proposed closing both units in 2025. The original proposal would have increased base rates by $28.5 million, or about 2.5 percent, in order to allow the company to recover its costs associated with the plant's accelerated depreciation, decommissioning and anticipated investments, with cautionary examples such as the Kemper power plant costs illustrating potential risks.

Concurrently, Idaho Power asked for commission approval to adjust depreciation rates for its other plants and equipment based on the result of a study it conducts every five years, as outlined in Case IPC-E-16-23. The adjustment would have led to a $6.7 million increase to base rates.

The two requests filed in October would have increased customer costs by a total of $35.2 million or 3.1 percent, leading to a $3.08 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

The proposed settlement submitted to the Commission on May 4 calls for $13,285,285 to be recovered from all customer classes through base rates until 2028, all related to the Valmy shutdown. That is an increase of 1.17 percent and would result in a $1.20 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

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Duke Energy Net Metering Proposal updates rooftop solar compensation with time-of-use rates, lower grid credits, and a minimum charge, aligning payments with electricity demand in North Carolina pending regulators' approval.

Key Points

A plan to swap flat credits for time-of-use rates and a minimum charge for rooftop solar customers in North Carolina.

✅ Time-of-use credits vary by grid demand

✅ $10 minimum use charge plus $14 basic fee

✅ Aims to align solar payouts with actual electricity value

Duke Energy has proposed new rules for how owners of rooftop solar panels are paid for electricity they send to the electric grid. It could mean more complexity and lower payments, but the utility says rates would be fairer.

State legislators have called for changes in the payment rules — known as "net metering" policies that allow households to sell power back to energy firms.

Right now, solar panel owners who produce more electricity than they need get credits on their bills, equal to whatever they pay for electricity. Under the proposed changes, the credit would be lower and would vary according to electricity demand, said Duke spokesperson Randy Wheeless.

"So in a cold winter morning, like now, you would get more, but maybe in a mild spring day, you would get less," Wheeless said Tuesday. "So, it better reflects what the price of electricity is."

Besides setting rates by time of use, solar owners also would have to pay a minimum of $10 a month for electricity, even if they don't use any from the grid. That's on top of Duke's $14 basic charge. Duke said it needs the extra revenue to pay for grid infrastructure to serve solar customers.

The proposal is the result of an agreement between Duke and solar industry groups — the North Carolina Sustainable Energy Association; the Southern Environmental Law Center, which represented Vote Solar and the Southern Alliance for Clean Energy; solar panel maker Sunrun Inc.; and the Solar Energy Industries Association.

The deal is similar to one approved by regulators in South Carolina last year, while in Nova Scotia a solar charge was delayed after controversy.

Daniel Brookshire of the North Carolina Sustainable Energy Association said he hopes the agreement will help the solar industry.

"We reached an agreement here that we think will provide certainty over the next decade, at least, for those interested in pursuing solar for their homes, and for our members who are solar installers," Brookshire said.

But other environmental and consumer groups oppose the changes, amid debates over who pays for grid upgrades elsewhere. Jim Warren with NC WARN said the rules would slow the expansion of rooftop solar in North Carolina.

"It would make it even harder for ordinary people to go solar," Warren said. "This would make it more complicated and more expensive, even for wealthier homeowners."

State regulators still must approve the proposal, even as courts weigh aspects of the electricity monopoly in related solar cases. If state regulators approve it, rates for new net metering customers would take effect Jan. 1, 2023.

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