Italy passes renewable energy legislation

European Solar Inverter Demand surges as photovoltaics and residential solar expand during the clean energy transition, driven by high natural gas prices; Germany leads, boosting Enphase and SolarEdge sales for rooftop systems and grid-tied installations.

Key Points

Rising European need for solar inverters, fueled by residential PV growth, high energy costs, and clean energy policies.

✅ Germany leads EU rooftop PV installations

✅ Enphase and SolarEdge see revenue growth

✅ High gas prices and policies spur adoption

Solar equipment makers are expected to post higher quarterly profit, benefiting from strong demand in Europe for critical components that convert energy from the sun into electricity, amid record renewable momentum worldwide.

The continent is emerging as a major market for solar firms as it looks to reduce its dependence on the Russian energy supply and accelerate its clean energy transition, with solar already reshaping power prices in Northern Europe across the region, brightening up businesses of companies such as Enphase Energy (ENPH.O) and SolarEdge Technologies (SEDG.O), which make solar inverters.

Wall Street expects Enphase and SolarEdge to post a combined adjusted net income of $323.8 million for the April-June quarter, a 56.7% jump from a year earlier, even as demand growth slows in the United States.

The energy crisis in Europe is not as acute as last year when Western sanctions on Russia severely crimped supplies, but prices of natural gas and electricity continue to be much higher than in the United States, Raymond James analyst Pavel Molchanov said.

As a result, demand for residential solar keeps growing at a strong pace in the region, with Germany being one of the top markets and solar adoption in Poland also accelerating in recent years across the region.

About 159,000 residential solar systems became operational in the first quarter in Germany amid a solar power boost that reflects policy and demand, a 146% rise from a year earlier, according to BSW solar power association.

Adoption of solar is also helping European homeowners have greater control over their energy costs as fossil fuel prices tend to be more volatile, Morningstar analyst Brett Castelli said.

SolarEdge, which has a bigger exposure to Europe than Enphase, said its first-quarter revenue from the continent more than doubled compared with last year.

In comparison, growth in the United States has been tepid due to lukewarm demand in states like Texas and Arizona where cheaper electricity prices make the economics of residential solar less attractive, even though solar is now cheaper than gas in parts of the U.S. market.

Higher interest rates following the U.S. Federal Reserve's recent actions to tame inflation are also weighing on demand, even as power outage risks rise across the United States.

Analysts also expect weakness in California where a new metering reform reduces the money credited to rooftop solar owners for sending excess power into the grid, underscoring how policy shifts can reshape the sector. The sunshine state accounts for nearly a third of the U.S. residential solar market.

Enphase will report its results on Thursday after the bell, while SolarEdge will release its second-quarter numbers on Aug. 1.

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Nova Scotia Cap-and-Trade Program joins Western Climate Initiative to leverage emissions trading IT systems, track allowances, and manage compliance, while setting in-province caps, carbon pricing signals, and third-party verified reporting for industrial and fuel suppliers.

Key Points

A provincial emissions trading system using WCI services to cap GHGs, track allowances, and enforce verified compliance.

✅ Uses WCI IT system to manage allowances and registry

✅ Initial trading limited to in-province participants

✅ Third-party verification and annual reporting deadlines

Nova Scotia is yet to set targets for its new cap and trade regime to reduce greenhouse gases, but the province announced Monday that it has joined the Western Climate Initiative Inc. -- a non-profit corporation formed to provide administrative and technical services to states and provinces with emissions trading programs.

Environment Minister Iain Rankin said joining the initiative would allow the province to use its IT system to manage and track its new cap and trade program.

Rankin said the province can join without trading greenhouse gas emission allowances with other jurisdictions -- California, Quebec, and Ontario are currently linked through the program, with Hydro-Québec's U.S. sales highlighting cross-border dynamics. Nova Scotia currently has no plans to trade outside the province as it works on emissions caps Rankin said will be ready sometime in June.

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Nova Scotia is yet to set targets for its new cap and trade regime to reduce greenhouse gases, but the province announced Monday that it has joined the Western Climate Initiative Inc. -- a non-profit corporation formed to provide administrative and technical services to states and provinces with emissions trading programs.

Environment Minister Iain Rankin said joining the initiative would allow the province to use its IT system to manage and track its new cap and trade program.

Rankin said the province can join without trading greenhouse gas emission allowances with other jurisdictions -- California, Quebec, and Ontario are currently linked through the program. Nova Scotia currently has no plans to trade outside the province as it works on emissions caps Rankin said will be ready sometime in June.

"By keeping our system internal it ensures that our greenhouse gas reductions are happening within our province," said Rankin. "But we do have that opportunity (to join) and if there are new entrants or we need more access to credits then that may shift our strategy."

The use of the system will cost Nova Scotia about US$314,000 for 2018-19, with an annual cost in subsequent years of about US$228,000 or more, if the province requests modifications.

"If we were to do something like that internally we would have to build a full database and hire more people, so this was an obvious choice for us," said Rankin.

Nova Scotia has already met the national reduction target of 30 per cent below 2005 levels and says it's on track to have 40 per cent of electricity generation from renewables by 2020, underscoring how cleaning up Canada's electricity supports climate pledges.

Stephen Thomas, energy campaign coordinator for the Ecology Action Centre, called the province's move an "important small step," stressing the importance of using the same administrative rules as the other jurisdictions involved.

But Thomas said Nova Scotia should go further and trade emissions with California, Quebec, and Ontario, and also put a price on carbon by auctioning credits as they do.

Thomas said Nova Scotia's system stands to be volatile because of the smaller number of participants -- about 20 including Nova Scotia Power, Northern Pulp, Lafarge, and large oil and gasoline companies such as ExxonMobil, Imperial and Irving.

"It's very likely to favour Nova Scotia Power as the largest single emitter with the most credits to sell here, and that would change if we had a linked system, at a time when Canada will need more electricity to hit net-zero according to the IEA," Thomas said.

He said it's important to have a linked system and a regional approach in Atlantic Canada, which has more emissions per person and more emissions per GDP than places like Ontario, Quebec and California, and where policies like Newfoundland's rate reduction plan can influence electricity strategy.

"Reducing emissions, because we are so emissions-intensive here, is a little bit cheaper," said Thomas. "So it's possible that Ontario, Quebec and California could pay Nova Scotia to reduce its emissions."

Under its program, Nova Scotia requires industrial facilities generating 50,000 tonnes or more of greenhouse gas emissions per year to report emissions.

Regulations also cover petroleum product suppliers that import or produce 200 litres of fuel or more per year for consumption and natural gas distributors whose products produce at least 10,000 tonnes of greenhouse gas emissions a year.

Companies were to have reported to the Environment Department by May 1 but Rankin said the deadline has been pushed back to June 1, a deadline that was to be followed in subsequent years in any event. Reports must be verified by a third party by Sept. 1 every year.

The Liberal government passed enabling legislation for cap and trade last fall.

As for the upcoming emissions caps, Rankin isn't tipping the province's hand yet, even as B.C.'s 2050 targets face a shortfall in some forecasts.

"Those caps will recognize the investments that have already been made and therefore will be the most cost-effective program that we can put together to meet the federal requirement," he said.

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Middle Tennessee Power Outages disrupt 100,000+ customers as severe thunderstorms, straight-line winds, downed trees, and debris challenge Nashville crews, slow restoration amid COVID-19, and threaten more hail, flash flooding, and damaging gusts.

Key Points

Blackouts across Nashville after severe storms and winds, leaving customers without power and facing restoration delays.

✅ Straight-line winds 60-80 mph toppled trees and power lines

✅ 130,000+ customers impacted; some outages may last 1-2 weeks

✅ Restoration slowed by debris, COVID-19 protocols, and new storms

Some middle Tennessee residents could be without electricity for up to two weeks after strong thunderstorms swept through the area Sunday, knocking out power for more than 100,000 customers, a scale comparable to Los Angeles outages after a station fire.

"Straight line winds as high as 60-80 miles per hour knocked down trees, power lines and power polls, interrupting power to 130,000 of our 400,000+ customers," Nashville Electric said in a statement Monday. The utility said the outage was one of the largest on record, though Carolina power outages recently left a quarter-million without power as well.

"Restoration times will depend on individual circumstances. In some cases, power could be out for a week or two" as challenges related to coronavirus and the need for utilities adapt to climate change complicated crews' responses and more storms were expected, the statement said. "This is unfortunate timing on the heels of a tornado and as we deal with battling COVID-19."

Metropolitan Nashville and Davidson County Mayor John Cooper also noted that the power outages were especially inconvenient, a challenge similar to Hong Kong families without power during Typhoon Mangkhut, as people were largely staying home to slow the spread of coronavirus. He also pointed out that the storms came on the two month anniversary of the Nashville tornado that left at least two dozen people dead.

"Crews are working diligently to restore power and clear any debris in neighborhoods," Cooper said.

He said that no fatalities were reported in the county but sent condolences to Spring Hill, whose police department reported that firefighter Mitchell Earwood died during the storm due to "a tragic weather-related incident" while at his home and off duty. He had served with the fire department for 10 years.

The Metro Nashville Department of Public Works said it received reports of more than 80 downed trees in Davidson County.

Officials also warn that copper theft can be deadly when electrical infrastructure is damaged after storms.

The National Weather Service Nashville said a 72 mph wind gust was measured at Nashville International Airport — the fifth fastest on record.

The weather service warned that strong storms with winds of up to 75 mph, large hail, record-long lightning bolt potential seen in the U.S., and isolated flash flooding could hit middle Tennessee again Monday afternoon and night.

"Treat Severe Thunderstorm Warnings the same way you would Tornado Warnings and review storm safety tips before you JUST TAKE SHELTER," the NWS instructs. "70 mph is 70 mph whether it's spinning around in a circle or blowing in a straight line."

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Lake Erie Connector Investment advances a 1,000 MW HVDC transmission link connecting Ontario to the PJM Interconnection, enhancing grid reliability, clean power trade, and GHG reductions through a public-private partnership led by CIB and ITC.

Key Points

A $1.7B public-private HVDC project linking Ontario and PJM to boost reliability, cut GHGs, and enable clean power trade.

✅ 1,000 MW, 117 km HVDC link between Ontario and PJM

✅ $655M CIB and $1.05B private financing, ITC to own-operate

✅ Cuts system costs, boosts reliability, reduces GHG emissions

The Canada Infrastructure Bank (CIB) and ITC Investment Holdings (ITC) have signed an agreement in principle to invest $1.7 billion in the Lake Erie Connector project.

Under the terms of the agreement, the CIB will invest up to $655 million or up to 40% of the project cost. ITC, a subsidiary of Fortis Inc., and private sector lenders will invest up to $1.05 billion, the balance of the project's capital cost.

The CIB and ITC Investment Holdings signed an agreement in principle to invest $1.7B in the Lake Erie Connector project.

The Lake Erie Connector is a proposed 117 kilometre underwater transmission line connecting Ontario with the PJM Interconnection, the largest electricity market in North America, and aligns with broader regional efforts such as the Maine transmission line to import Quebec hydro to strengthen cross-border interconnections.

The 1,000 megawatt, high-voltage direct current connection will help lower electricity costs for customers in Ontario and improve the reliability and security of Ontario's energy grid, complementing emerging solutions like battery storage across the province. The Lake Erie Connector will reduce greenhouse gas emissions and be a source of low-carbon electricity in the Ontario and U.S. electricity markets.

During construction, the Lake Erie Connector is expected to create 383 jobs per year and drive more than $300 million in economic activity, and complements major clean manufacturing investments like a $1.6 billion battery plant in the Niagara Region that supports the EV supply chain. Over its life, the project will provide 845 permanent jobs and economic benefits by boosting Ontario's GDP by $8.8 billion.

The project will also help Ontario to optimize its current infrastructure, avoid costs associated with existing production curtailments or shutdowns. It can leverage existing generation capacity and transmission lines to support electricity demand, alongside new resources such as the largest battery storage project planned for southwestern Ontario.

ITC continues its discussions with First Nations communities and is working towards meaningful participation in the near term and as the project moves forward to financial close.

The CIB anticipates financial close late in 2021, pending final project transmission agreements, with construction commencing soon after. ITC will own the transmission line and be responsible for all aspects of design, engineering, construction, operations and maintenance.

ITC acquired the Lake Erie Connector project in August 2014 and it has received all necessary regulatory and permitting approvals, including a U.S. Presidential Permit and approval from the Canada Energy Regulator.

This is the CIB's first investment commitment in a transmission project and another example of the CIB's momentum to quickly implement its $10B Growth Plan, amid broader investments in green energy solutions in British Columbia that support clean growth.

Endorsements

This project will allow Ontario to export its clean, non-emitting power to one of the largest power markets in the world and, as a result, benefit Canadians economically while also significantly contributing to greenhouse gas emissions reductions in the PJM market. The project allows Ontario to better manage peak capacity and meet future reliability needs in a more sustainable way. This is a true win-win for both Canada and the U.S., both economically and environmentally.
Ehren Cory, CEO, Canada Infrastructure Bank

The Lake Erie Connector has tremendous potential to generate customer savings, help achieve shared carbon reduction goals, and increase electricity system reliability and flexibility. We look forward to working with the CIB, provincial and federal governments to support a more affordable, customer-focused system for Ontarians. 
Jon Jipping, EVP & COO, ITC Investment Holdings Inc., a subsidiary of Canadian-based Fortis Inc. 

We are encouraged by this recent announcement by the Canada Infrastructure Bank. Mississaugas of the Credit First Nation has an interest in projects within our historic treaty lands that have environmental benefits and that offer economic participation for our community.
Chief Stacey Laforme, Mississaugas of the Credit First Nation

While our evaluation of the project continues, we recognize this project can contribute to the economic resilience of our Shareholder, the Mississaugas of the Credit First Nation. Subject to the successful conclusion of our collaborative efforts with ITC, we look forward to our involvement in building the necessary infrastructure that enable Ontario's economic engine.
Leonard Rickard, CEO, Mississaugas of the Credit Business Corporation

The Lake Erie Connector demonstrates the advantages of public-private partnerships to develop critical infrastructure that delivers greater value to Ontarians. Connecting Ontario's electricity grid to the PJM electricity market will bring significant, tangible benefits to our province. This new connection will create high-quality jobs, improve system flexibility, and allow Ontario to export more excess electricity to promote cost-savings for Ontario's electricity consumers.
Greg Rickford, Minister of Energy, Northern Development and Mines, Minister of Indigenous Affairs

With the US pledging to achieve a carbon-free electrical grid by 2035, Canada has an opportunity to export clean power, helping to reduce emissions, maximizing clean power use and making electricity more affordable for Canadians. The Lake Erie Connector is a perfect example of that. The Canada Infrastructure Bank's investment will give Ontario direct access to North America's largest electricity market - 13 states and D.C. This is part of our infrastructure plan to create jobs across the country, tackle climate change, and increase Canada's competitiveness in the clean economy, alongside innovation programs like the Hydrogen Innovation Fund that foster clean technology.

Quick Facts

• The Lake Erie Connector is a 1,000 megawatt, 117 kilometre long underwater transmission line connecting Ontario and Pennsylvania.
• The PJM Interconnection is a regional transmission organization coordinating the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
• The project will help to reduce electricity system costs for customers in Ontario, and aligns with ongoing consultations on industrial electricity pricing and programs, while helping to support future capacity needs.
• The CIB is mandated to invest CAD $35 billion and attract private sector investment into new revenue-generating infrastructure projects that are in the public interest and support Canadian economic growth.
• The investment commitment is subject to final due diligence and approval by the CIB's Board.

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India Nuclear Generation Shortfall highlights missed five-year plan targets due to uranium fuel scarcity, commissioning delays at Kudankulam, PFBR slippage, and PHWR equipment bottlenecks under IAEA safeguards and domestic supply constraints.

Key Points

A gap between planned and actual nuclear output due to fuel shortages, reactor delays, and first-of-a-kind hurdles.

✅ Fuel scarcity pre-2009-10 constrained unsafeguarded reactors.

✅ Kudankulam delays from protests, litigation, and remobilisation.

✅ FOAK PHWR equipment bottlenecks and PFBR slippage.

A lack of available domestically produced nuclear fuel and delays in constructing and commissioning nuclear power plants, including first-of-a-kind plants and the Prototype Fast Breeder Reactor (PFBR), meant that India failed to meet its nuclear generation targets under the governmental plans over the decade to 2017, even as global project milestones were being recorded elsewhere.

India's nuclear generation target under its 11th five-year plan, covering the period 2007-2012, was 163,395 million units (MUs) and the 12th five-year Plan (2012-17) was 241,748 MUs, Minister of state for the Department of Atomic Energy and the Prime Minister's Office Jitendra Singh told parliament on 6 February. Actual nuclear generation in those periods was 109,642 MUs and 183,488 MUs respectively, Singh said in a written answer to questions in the Lok Sabah.

Singh attributed the shortfall in generation to a lack of availability of the necessary quantities of domestically produced fuel during the three years before 2009-2010; delays to the commissioning of two 1000 MWe nuclear power plants at Kudankulam due to local protests and legal challenges; and delays in the completion of two indigenously designed pressurised heavy water reactors and the PFBR.

Kudankulam 1 and 2 are VVER-1000 pressurised water reactors (PWRs) supplied by Russia's Atomstroyexport under a Russian-financed contract. The units were built by Nuclear Power Corporation of India Ltd (NPCIL) and were commissioned and are operated by NPCIL under International Atomic Energy Agency (IAEA) safeguards, with supervision from Russian specialists, while China's nuclear program advanced on a steady development track in the same period. Construction of the units - the first PWRs to enter operation in India - began in 2002.

Singh said local protests resulted in the halt of commissioning work at Kudankulam for nine months from September 2011 to March 2012, when he said project commissioning had been at its peak. As a consequence, additional time was needed to remobilise the workforce and contractors, he said. Litigation by anti-nuclear groups, and compliance with supreme court directives, impacted commissioning in 2013, he said. Unit 1 entered commercial operation in December 2014 and unit 2 in April 2017.

Delays in the manufacture and supply by domestic industry of critical equipment for first-of-a-kind 700 MWe pressurised heavy water reactors -  Kakrapar units 3 and 4, and Rajasthan units 7 and 8 - has led to delays in the completion of those units, the minister said, as well as noting the delay in completion of the PFBR, which is being built at Kalpakkam by Bhavini. In answer to a separate question, Singh said the PFBR is in an "advance stage of integrated commissioning" and is "expected to approach first criticality by the year 2020."

Eight of India's operating nuclear power plants are not under IAEA safeguards and can therefore only use indigenously-sourced uranium. The other 14 units operate under IAEA safeguards and can use imported uranium. The Indian government has taken several measures to secure fuel supplies for reactors in operation and under construction, amid coal supply rationing pressures elsewhere in the power sector, concluding fuel supply contracts with several countries for existing and future reactors under IAEA Safeguards and by "augmentation" of fuel supplies from domestic sources, Singh said.

Kakrapar 3 and 4, with Kakrapar 3 criticality already reported, and Rajasthan 7 and 8 are all currently expected to enter service in 2022, according to World Nuclear Association information.

Joint venture discussions

In February 2016 the government amended the Atomic Energy Act to allow NPCIL to form joint venture companies with other public sector undertakings (PSUs) for involvement in nuclear power generation and possibly other aspects of the fuel cycle, reflecting green industrial strategies shaping future reactor waves globally. In answer to another question, Singh confirmed that NPCIL has entered into joint ventures with NTPC Limited (National Thermal Power Corporation, India's largest power company) and Indian Oil Corporation Limited. Two joint venture companies - Anushakti Vidhyut Nigam Limited and NPCIL-Indian Oil Nuclear Energy Corporation Limited - have been incorporated, and discussions on possible projects to be set up by the joint venture companies are in progress.

An exploratory discussion had also been held with Oil & Natural Gas Corporation, Singh said. Indian Railways - which has in the past been identified as a potential joint venture partner for NPCIL - had "conveyed that they were not contemplating entering into an MoU for setting up of nuclear power plants," Singh said.

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California Community Choice Aggregators are reshaping electricity markets with renewable energy, solar and wind sourcing, competitive rates, and customer choice, challenging PG&E, SDG&E, and Southern California Edison while advancing California's clean power goals.

Key Points

Local governments that buy power, often cleaner and cheaper, while utilities handle delivery and billing.

✅ Offer higher renewable mix than utilities at competitive rates

✅ Utilities retain transmission and billing responsibilities

✅ Rapid expansion threatens IOU market share across California

Nearly 2 million electricity customers in California may not know it, but they’re part of a revolution. That many residents and businesses are getting their power not from traditional utilities, but via new government-affiliated entities known as community choice aggregators. The CCAs promise to deliver electricity more from renewable sources, such as solar and wind, even as California exports its energy policies across Western states, and for a lower price than the big utilities charge.

The customers may not be fully aware they’re served by a CCA because they’re still billed by their local utility. But with more than 1.8 million accounts now served by the new system and more being added every month, the changes in the state’s energy system already are massive.

Faced for the first time with real competition, the state’s big three utilities have suddenly become havens of innovation. They’re offering customers flexible options on the portion of their power coming from renewable energy, amid a broader review to revamp electricity rates aimed at cleaning the grid, and they’re on pace to increase the share of power they get from solar and wind power to the point where they are 10 years ahead of their deadline in meeting a state mandate.

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But that may not stem the flight of customers. Some estimates project that by late this year, more than 3 million customers will be served by 20 CCAs, and that over a longer period, Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric could lose 80% of their customers to the new providers.

Two big customer bases are currently in play: In Los Angeles and Ventura counties, a recently launched CCA called the Clean Power Alliance is hoping by the end of 2019 to serve nearly 1 million customers. Unincorporated portions of both counties and 29 municipalities have agreed in principle to join up.

Meanwhile, the city of San Diego is weighing two options to meet its goal of 100% clean power by 2035, as exit fees are being revised by the utilities commission: a plan to be submitted by SDG&E, or the creation of a CCA. A vote by the City Council is expected by the end of this year. A city CCA would cover 1.4 million San Diegans, accounting for half SDG&E’s customer demand, according to Cody Hooven, the city’s chief sustainability officer.

Don’t expect the big companies to give up their customers without a fight. Indeed, battle lines already are being drawn at the state Public Utilities Commission, where a recent CPUC ruling sided with a community energy program over SDG&E, and local communities.

“SDG&E is in an all-out campaign to prevent choice from happening, so that they maintain their monopoly,” says Nicole Capretz, who wrote San Diego’s climate action plan as a city employee and now serves as executive director of the Climate Action Campaign, which supports creation of the CCA.

California is one of seven states that have legalized the CCA concept, even as regulators weigh whether the state needs more power plants to ensure reliability. (The others are New York, New Jersey, Massachusetts, Ohio, Illinois and Rhode Island.) But the scale of its experiment is likely to be the largest in the country, because of the state’s size and the ambition of its clean-power goal, which is for 50% of its electricity to be generated from renewable sources by 2030.

California created its system via legislative action in 2002. Assembly Bill 117 enabled municipalities and regional governments to establish CCAs anywhere that municipal power agencies weren’t already operating. Electric customers in the CCA zones were automatically signed up, though they could opt out and stay with their existing power provider. The big utilities would retain responsibility for transmission and distribution lines.

The first CCA, Marin Clean Energy, began operating in 2010 and now serves 470,000 customers in Marin and three nearby counties.

The new entities were destined to come into conflict with the state’s three big investor-owned utilities. Their market share already has fallen to about 70%, from 78% as recently as 2010, and it seems destined to keep falling. In part that’s because the CCAs have so far held their promise: They’ve been delivering relatively clean power and charging less.

The high point of the utilities’ hostility to CCAs was the Proposition 16 campaign in 2009. The ballot measure was dubbed the “Taxpayers Right to Vote Act,” but was transparently an effort to smother CCAs in the cradle. PG&E drafted the measure, got it on the ballot, and contributed all of the $46.5 million spent in the unsuccessful campaign to pass it.

As recently as last year, PG&E and SDG&E were lobbying in the legislature for a bill that would place a moratorium on CCAs. The effort failed, and hasn’t been revived this year.

Rhetoric similar to that used by PG&E against Marin’s venture has surfaced in San Diego, where a local group dubbed “Clear the Air” is fighting the CCA concept by suggesting that it could be financially risky for local taxpayers and questioning whether it will be successful in providing cleaner electricity. Whether Clear the Air is truly independent of SDG&E’s parent, Sempra Energy, is questionable, as at least two of its co-chairs are veteran lobbyists for the company.

SDG&E spokeswoman Helen Gao says the utility supports “customers’ right to choose an energy provider that best meets their needs” and expects to maintain a “cooperative relationship” with any provider chosen by the city.

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