China set for additional 1,650MW of wind power

Sidi Mansour Wind Farm Tunisia will deliver 30 MW as an IPP, backed by UPC Renewables and CFM, under a STEG PPA, supporting 2030 renewable energy targets, grid connection, job creation, and CO2 emissions reduction.

Key Points

A 30 MW wind IPP by UPC and CFM in Sidi Mansour, supplying STEG and advancing Tunisia's 2030 renewable target.

✅ 30 MW capacity under STEG PPA, first wind IPP in Tunisia

✅ Co-developed by UPC Renewables and Climate Fund Managers

✅ Cuts CO2 by up to 56,645 t and creates about 100 jobs

UPC Renewables (UPC) and the Climate Fund Managers (CFM) have partnered to develop a 30 megawatt wind farm in Sidi Mansour, Tunisia, which, amid regional wind expansion efforts, will help the country meet its 30% renewable energy target by 2030.

Tunisia announced the launch of its solar energy plan in 2016, with projects like the 10 MW Tunisian solar park aiming to increase the role of renewables in its electricity generation mix ten-fold to 30%,

This Sidi Mansour Project will help Tunisia meet its goals, reducing its reliance on imported fossil fuels and, mirroring 90 MW Spanish wind build milestones, demonstrating to the world that it is serious about further development of renewable energy investment.

“Chams Enfidha”, the first solar energy station in Tunisia with a capacity of 1 megawatt and located in the Enfidha region. (Ministry of Energy, Mines and Energy Transition Facebook page)

This project will also be among the country’s first Independent Power Producers (IPP). CFM is acting as sponsor, financial adviser and co-developer on the project, in a landscape shaped by IRENA-ADFD funding in developing countries, while UPC will lead the development with its local team. The team will be in charge of permitting, grid connection, land securitisation, assessment of wind resources, contract procurement and engineering.

UPC was selected under the “Authorisation Scheme” tender for the project in 2016, similar to utility-scale developments like a 450 MW U.S. wind farm, and promptly signed a power purchase agreement with Société Tunisienne Electricité et du Gaz (STEG).

Brian Caffyn, chairman of UPC Group, said: “We can start the construction of the Sidi Mansour wind farm in 2020, helping stimulate the Tunisian economy, create local jobs and a social plan for local communities while respecting international environmental protection guidelines.”

Sebastian Surie, CFM’s regional head of Africa, added: “CFM is thrilled to partner with a leading wind developer in the Sidi Mansour Wind Project to assist Tunisia in meeting its renewable energy goals. As potentially the first Wind IPP in Tunisia, this Project will be a testament to how CI1’s full life-cycle financing solution can unlock investment in renewable energy in new markets, as seen in an Irish offshore wind project globally.”

The project will not only provide electricity, but also reduce CO2 emissions by up to 56,645 tonnes and create some 100 new jobs.

Wind turbine in El Haouaria, Tunisia, highlighting advances such as a huge offshore wind turbine that can power 18,000 homes. (Reuters)

Tunisia’s first power station, “Chams Enfidha,” inaugurated at the beginning of July, has a capacity of one megawatt, with an estimated cost of 3.3 million dinars ($1.18 million). The state invested 2.3 million dinars into the project ($820,000), with the remaining 1 million dinars ($360,000) provided by a private investor.

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Philippsburg Demolition Delay: EnBW postpones controlled cooling-tower blasts amid the coronavirus pandemic, affecting decommissioning timelines in Baden-Wurttemberg and grid expansion for a transformer station to route renewable power and secure supply in southern Germany.

Key Points

EnBW's COVID-19 delay of Philippsburg cooling-tower blasts, affecting decommissioning and grid plans.

✅ Controlled detonation shifted to mid-May at earliest

✅ Demolition links to transformer station for north-south grid

✅ Supports security of supply in southern Germany

German energy company EnBW said the coronavirus outbreak has impacted plans to dismantle its Philippsburg nuclear power plant in Baden-Wurttemberg, southwest Germany, amid plans to phase out coal and nuclear nationally.

The controlled detonation of Phillipsburg's cooling towers will now take place in mid-May at the earliest, subject to coordination as Germany debates whether to reconsider its nuclear phaseout in light of supply needs.

However, EnBW said the exact demolition date depends on many factors - including the further development in the coronavirus pandemic and ongoing climate policy debates about energy choices.

Philippsburg 2, a 1402MWe pressurised water reactor unit permanently shut down on 31 December 2019, as part of Germany's broader effort to shut down its remaining reactors over time.

At the end of 2019, the Ministry of the Environment gave basic approval for decommissioning and dismantling of unit 2 of the Philippsburg nuclear power plant, inluding explosive demolition of the colling towers. Since then EnBW has worked intensively on getting all the necessary formal steps on the way and performing technical and logistical preparatory work, even as discussions about a potential nuclear resurgence continue nationwide.

“The demolition of the cooling towers is directly related to future security of supply in southern Germany. We therefore feel obliged to drive this project forward," said Jörg Michels head of the EnBW nuclear power division.

The timely removal of the cooling towers is important as the area currently occupied by nuclear plant components is needed for a transformer station for long-distance power lines, an issue underscored during the energy crisis when Germany temporarily extended nuclear power to bolster supply. These will transport electricity from renewable sources in the north to industrial centres in the south.

As of early 2020, there six nuclear reactors in operation in Germany, even as the country turned its back on nuclear in subsequent years. According to research institute Fraunhofer ISE, nuclear power provided about 14% of Germany's net electricity in 2019, less than half of the figure for 2000.

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California Net Zero Grid Investment will fuel electrification, renewable energy buildout, EV adoption, and grid modernization, boosting utilities, solar, and storage, while policy, IRA incentives, and transmission upgrades drive reliability and long-term rate base growth.

Key Points

Funding to electrify sectors and modernize the grid, scaling renewables, EVs, and storage to meet 2045 net zero goals.

✅ $370B over 22 years to meet 2045 net zero target

✅ Utilities lead gains via grid modernization and rate base growth

✅ EVs, solar, storage scale; IRA credits offset costs

$370 billion: That’s the investment Edison International CEO Pedro Pizarro says is needed for California’s power grid to meet the state’s “net zero” goal for CO2 emissions by 2045.

Getting there will require replacing fossil fuels with electricity in transportation, HVAC systems for buildings and industrial processes. Combined with population growth and data demand potentially augmented by artificial intelligence, that adds up to an 82 percent increase in electricity demand over 22 years, or 3 percent annually, and a potential looming shortage if buildout lags.

California’s plans also call for phasing out fossil fuel generation in the state, despite ongoing dependence on fossil power during peaks. And presumably, its last nuclear plant—PG&E Corp’s (PCG) Diablo Canyon—will be eventually be shuttered as well. So getting there also means trebling the state’s renewable energy generation and doubling usage of rooftop solar.

Assuming this investment is made, it’s relatively easy to put together a list of beneficiaries. Electric vehicles hit 20 percent market share in the state in Q2, even as pandemic-era demand shifts complicate load forecasting. And while competition from manufacturers has increased, leading manufacturers like Tesla TSLA -3% Inc (TSLA) can look forward to rising sales for some time—though that’s more than priced in for Elon Musk’s company at 65 times expected next 12 months earnings.

In the past year, California regulators have dialed back net metering through pricing changes affecting compensation, a subsidy previously paying rooftop solar owners premium prices for power sold back to the grid. That’s hit share prices of SunPower Corp (SPWR) and Sunrun Inc (RUN) quite hard, by further undermining business plans yet to demonstrate consistent profitability.

Nonetheless, these companies too can expect robust sales growth, as global prices for solar components drop and Inflation Reduction Act tax credits at least somewhat offset higher interest rates. And the combination of IRA tax credits and U.S. tariff walls will continue to boost sales at solar manufacturers like JinkoSolar Holding (JKS).

The surest, biggest beneficiaries of California’s drive to Net Zero are the utilities, reflecting broader utility trends in grid modernization, with investment increasing earnings and dividends. And as the state’s largest pure electric company, Edison has the clearest path.

Edison is currently requesting California regulators OK recovery over a 30-year period of $2.4 billion in losses related to 2017 wildfires. Assuming a amicable decision by early next year, management can then turn its attention to upgrading the grid. That investment is expected to generate long-term rate base growth of 8 percent at year, fueling 5 to 7 percent annual earnings growth through 2028 with commensurate dividend increases.

That’s a strong value proposition Edison stock, with trades at just 14 times expected next 12 months earnings. The yield of roughly 4.4 percent at current prices was increased 5.4 percent this year and is headed for a similar boost in December.

When California deregulated electricity in 1996, it required utilities with rare exceptions to divest their power generation. As a result, Edison’s growth opportunity is 100 percent upgrading its transmission and distribution grid. And its projects can typically be proposed, sited, permitted and built in less than a year, limiting risk of cost overruns to ensure regulatory approval and strong investment returns.

Edison’s investment plan is also pretty much immune to an unlikely backtracking on Net Zero goals by the state. And the company has a cost argument as well: Dr Pizarro cites U.S. Department of Energy and Department of Transportation data to project inflation-adjusted savings of 40 percent in California’s total customer energy bills from full electrification.

There’s even a reason to believe 40 percent savings will prove conservative. Mainly, gasoline currently accounts for a bit more than half energy expenditures. And after a more than 10-year global oil and gas investment drought, supplies are likely get tighter and prices possibly much higher in coming years.

Of course, those savings will only show up after significant investment is made. At this point, no major utility system in the world runs on 100 percent renewable energy, and California’s blackout politics underscore how reliability concerns shape deployment. And the magnitude of storage technology needed to overcome intermittency in solar and wind generation is not currently available let alone affordable, though both cost and efficiency are advancing.

Taking EVs from 20 to 100 percent of California’s new vehicle sales calls for a similar leap in efficiency and cost, even with generous federal and state subsidy. And while technology to fully electrify buildings and homes is there, economically retrofitting statewide is almost certainly going to be a slog.

At the end of the day, political will is likely to be as important as future technological advance for how much of Pizarro’s $370 billion actually gets spent. And the same will be true across the U.S., with state governments and regulators still by and large calling the shots for how electricity gets generated, transmitted and distributed—as well as who pays for it and how much, even as California’s exported policies influence Western markets.

Ironically, the one state where investors don’t need to worry about renewable energy’s prospects is one of the currently reddest politically. That’s Florida, where NextEra Energy NEE +2.8% (NEE) and other utilities can dramatically cut costs to customers and boost reliability by deploying solar and energy storage.

You won’t hear management asserting it can run the Sunshine State on 100 percent renewable energy, as utilities and regulators do in some of the bluer parts of the country. But by demonstrating the cost and reliability argument for solar deployment, NextEra is also making the case why its stock is America’s highest percentage bet on renewables’ growth—particularly at a time when all things energy are unfortunately becoming increasingly, intensely political.

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Oil and Gas Profitability Decline reflects shale-driven oversupply, OPEC-Russia dynamics, LNG exports, renewables growth, and weak demand, signaling compressed margins for producers, stressed petrodollar budgets, and shifting energy markets post-Covid.

Key Points

A sustained squeeze on hydrocarbon margins from agile shale supply, weaker OPEC leverage, and expanding renewables.

✅ Shale responsiveness caps prices and erodes industry rents

✅ OPEC-Russia cuts face limited impact versus US supply

✅ Renewables and EVs slow long-term oil and gas demand

The oil-price crash of March 2020 will probably not last long. As in 2014, when the oil price dropped below $50 from $110 in a few weeks, this one will trigger a temporary collapse of the US shale industry. Unless the coronavirus outbreak causes Armageddon, cheap oil will also support policymakers’ efforts to help the global economy.

But there will be at least one important and lasting difference this time round — and it has major market and geopolitical implications.

The oil price crash is a foretaste of where the whole energy sector was going anyway — and that is down.

It may not look that way at first. Saudi Arabia will soon realise, as it did in 2015, that its lethal decision to pump more oil is not only killing US shale but its public finances as well. Riyadh will soon knock on Moscow’s door again. Once American shale supplies collapse, Russia will resume co-operation with Saudi Arabia.

With the world economy recovering from the Covid-19 crisis by then, and with electricity demand during COVID-19 shifting, moderate supply cuts by both countries will accelerate oil market recovery. In time, US shale producers will return too.

Yet this inevitable bounceback should not distract from two fundamental factors that were already remaking oil and gas markets. First, the shale revolution has fundamentally eroded industry profitability. Second, the renewables’ revolution will continue to depress growth in demand.

The combined result has put the profitability of the entire global hydrocarbon industry under pressure. That means fewer petrodollars to support oil-producing countries’ national budgets, including Canada's oil sector exposures. It also means less profitable oil companies, which traditionally make up a large segment of stock markets, an important component of so many western pension funds.

Start with the first factor to see why this is so. Historically, the geological advantages that made oil from countries such as Saudi Arabia so cheap to produce were unique. Because oil and gas were produced at costs far below the market price, the excess profits, or “rent”, enjoyed by the industry were very large.

Furthermore, collusion among low-cost producers has been a winning strategy. The loss of market share through output cuts was more than compensated by immediately higher prices. It was the raison d’être of Opec.

The US shale revolution changed all this, exposing the limits of U.S. energy dominance narratives. A large oil-producing region emerged with a remarkable ability to respond quickly to price changes and shrink its costs over time. Cutting back cheap Opec oil now only increases US supplies, with little effect on world prices.

That is why Russia refused to cut production this month. Even if its cuts did boost world prices — doubtful given the coronavirus outbreak’s huge shock to demand — that would slow the shrinkage of US shale that Moscow wants.

Shale has affected the natural gas industry even more. Exports of US liquefied natural gas now put an effective ceiling on global prices, and debates over a clean electricity push have intensified when gas prices spike.

On top of all this, there is also the renewables’ revolution, though a green revolution has not been guaranteed in the near term. Around the world, wind and solar have become ever-cheaper options to generate electricity. Storage costs have also dropped and network management improved. Even in the US, renewables are displacing coal and gas. Electrification of vehicle fleets will damp demand further, as U.S. electricity, gas, and EVs face evolving pressures.

Eliminating fossil fuel consumption completely would require sustained and costly government intervention, and reliability challenges such as coal and nuclear disruptions add to the complexity. That is far from certain. Meanwhile, though, market forces are depressing the sector’s usual profitability.

The end of oil and gas is not immediately around the corner. Still, the end of hydrocarbons as a lucrative industry is a distinct possibility. We are seeing that in dramatic form in the current oil price crash. But this collapse is merely a message from the future.

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Alberta Electricity Rebate Extension provides $50 monthly credits, utility bill relief, and an natural gas rebate, supporting homes, farms, and small businesses with energy costs through December 2022, capped at 250 MWh per year.

Key Points

A provincial program extending $50 credits and energy relief, with a natural gas rebate for eligible consumers in 2022.

✅ Up to $300 in bill credits; auto-applied to eligible accounts

✅ Applies to whole bill; limit 250 MWh/year consumption

✅ Natural gas rebate triggers above $6.50/GJ Oct-Mar 2023

Alberta's electricity rebate program has been extended by three months amid an electricity price spike in Alberta, and will now be in effect until the end of December, the government said.

The program was originally to provide more than 1.9 million homes, farms and small businesses with $50 monthly credits on their electricity bills, complementing a consumer price cap on power bills, for July, August and September. It will now also cover the final three months of 2022.

Those eligible for the rebate could receive up to $300 in credits until the end of December, a relief for Alberta ratepayers facing deferral costs.

The program, designed to provide relief to Albertans hit hard by high utility bills and soaring energy prices, will cost the Alberta government $600 million.

Albertans who have consumed electricity within the past calendar year, up to a maximum of 250 megawatt hours per year, are eligible for the rebates, which will be automatically applied to consumer bills, as seen in Ontario electricity bill support initiatives.

The rebates will apply to the entire bill, similar to a lump-sum credit in Newfoundland and Labrador, not just the energy portion, the government said. The rebates will be automatic and no application will be needed.

Starting October, the government will enact a natural gas rebate program until March 2023 that will kick in when prices exceed $6.50 per gigajoule, and Alberta's consumer price cap on electricity will remain in place.

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Advanced Nuclear Technology drives decarbonization through innovation, SMRs, and a stable grid, bolstering U.S. leadership, energy security, and clean power exports under supportive regulation and policy to meet climate goals cost-effectively.

Key Points

Advanced nuclear technology uses SMRs to deliver low-carbon, reliable power and strengthen energy security.

✅ Accelerates decarbonization with firm, low-carbon baseload power

✅ Enhances grid reliability via SMRs and advanced fuel cycles

✅ Supports U.S. leadership through exports, R&D, and modern regulation

The most cost-effective way--indeed the only reasonable way-- to reduce greenhouse gas emissions and foster our national economic and security interests is through innovation, especially next-gen nuclear power innovation. That's from Rep. Greg Walden, R-Oregon, ranking Republican member of the House Energy and Commerce Committee, speaking to a Subcommittee on Energy hearing titled, "Building a 100 Percent Clean Economy: Advanced Nuclear Technology's Role in a Decarbonized Future."

Here are the balance of his remarks.

Encouraging the deployment of atomic energy technology, strengthening our nuclear industrial base, implementing policies that helps reassert U.S. nuclear leadership globally... all provide a promising path to meet both our environmental and energy security priorities. In fact, it's the only way to meet these priorities.

So today can help us focus on what is possible and what is necessary to build on recent policies we've enacted to ensure we have the right regulatory landscape, the right policies to strengthen our domestic civil industry, and the advanced nuclear reactors on the horizon.

U.S. global leadership here is sorely needed. Exporting clean power and clean power technologies will do more to drive down global Co2 emissions on the path to net-zero emissions worldwide than arbitrary caps that countries fail to meet.

In May last year, the International Energy Agency released an informative report on the role of nuclear power in clean energy systems; it did not find current trends encouraging.

The report noted that nuclear and hydropower "form the backbone of low-carbon electricity generation," responsible for three-quarters of global low-carbon generation and the reduction of over 60 gigatons of carbon dioxide emissions over the past 50 years.

Yet IEA found in advanced economies, nuclear power is in decline, with closing plants and little new investment, "just when the world requires more low-carbon electricity."

There are various reasons for this, some relating to cost overruns and delays, others to policies that fail to value the "low-carbon and energy security attributes" of nuclear. In any case, the report found this failure to encourage nuclear will undermine global efforts to develop cleaner electricity systems.

Germany demonstrates the problem. As it chose to shut down its nuclear industry, it has doubled down on expanding renewables like solar and wind. Ironically, to make this work, it also doubled down on coal. This nuclear phase out has cost Germany $12 billion a year, 70% of which is from increased mortality risk from stronger air pollutants (this according to the National Bureau of Economic Research). If other less technologically advanced nations even could match the rate of renewables growth reached by Germany, they would only hit about a fifth of what is necessary to reach climate goals--and with more expensive energy. So, would they then be forced to bring online even more coal-fired sources than Germany?

On the other hand, as outlined by the authors of the pro-nuclear book "A Bright Future," France and Sweden have both demonstrated in the 1970s and 1980s, how to do it. They showed that the build out of nuclear can be done at five times the rate of Germany's experience with renewables, with increased electricity production and relatively lower prices.

I think the answer is obvious about the importance of nuclear. The question will be "can the United States take the lead going forward?"

We can help to do this in Congress if we fully acknowledge what U.S. leadership on nuclear will mean--both for cleaner power and industrial systems beyond electricity, here and abroad--and for the ever-important national security attributes of a strong U.S. industry.

Witnesses have noted in recent hearings that recognizing how U.S. energy and climate policy effects energy and energy technology relationships world-wide is critical to addressing emissions where they are growing the fastest and for strengthening our national security relationships.

Resurrecting technological leadership in nuclear technology around the world will meet our broader national and energy security reasons--much as unleashing U.S. LNG from our shale revolution restored our ability to counter Russia in energy markets, while also driving cleaner technology. Our nuclear energy exports boost our national security priorities.

We on Energy and Commerce have been working, in a bipartisan manner over the past few Congresses to enhance U.S. nuclear policies. There is most certainly more to do. And I think today's hearing will help us explore what can be done, both administratively and legislatively, to pave the way for advanced nuclear energy.

Let me welcome the panel today. Which, I'm pleased to see, represents several important perspectives, including industry, regulatory, safety, and international expertise, to two innovative companies--Terrapower and my home state of Oregon's NuScale. All of these witnesses can speak to what we need to do to build, operate and lead with these new technologies.

We should work to get our nation's nuclear policy in order, learning from global frameworks like the green industrial revolution abroad. Today represents a good step in that effort.

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