Reduced moisture in the Amazon delivered clear skies and increased irradiance across the tropics of South America. Solar assets in the region saw 110-120% of average monthly irradiance through September.

A strong and slow-moving storm early in the month lessened irradiance in southern Brazil, but the rest of mid-latitude South America saw mostly normal irradiance, according to data collected by Solcast, a DNV company, via the Solcast API. The Altiplano Plateau saw the highest irradiance for the whole continent. This is in line with historical averages, as the area records some of the highest irradiance levels in the world.

In September the tropics saw higher irradiance than usual. This was due to clearer skies caused by the current drought in the Amazon. The northeastern part of the Amazon has been dry since mid-July, resulting in reduced moisture in the rainforest and less evapotranspiration. This is a major source of moisture fuelling cloud formation over rainforest regions.

The region saw regular cumuliform clouds typical of tropical regions, but not the large storms and rainfall events that are typical of the start of the wet season in September. The rivers in the Amazon are reported to be at their lowest level in over a century as there has been a lack of rainfall and ensuing dry conditions in recent months. This has been exacerbated by warm conditions, as South America recorded the warmest September extending from heatwaves.

The Brazilian southern states of Rio Grande de Sul and Santa Catarina saw reduced irradiance. It recorded 10-20% below September averages and is due to an unusually strong extra-tropical cyclone. The storm moved onshore from the Atlantic in early September, and it’s slow-moving nature meant the irradiance impacts were more focussed and intense. Most of the remainder of mid-latitude South America saw much more moderate irradiance at or slightly below the long-term average.

Solcast produces these figures by tracking clouds and aerosols at 1-2km resolution globally, using satellite data and proprietary AI/ML algorithms. This data is used to drive irradiance models, enabling Solcast to calculate irradiance at high resolution, with a typical bias of less than 2%, and also cloud-tracking forecasts. This data is used by more than 300 companies managing over 150 GW of solar assets globally.

China Mono Grade, the OPIS benchmark assessment for polysilicon prices in the country, fell 4.22% to CNY79.5 ($11.07)/kg week-on-week for the first time in more than three months on the back of weakening demand across the solar supply chain, which has finally impacted the upstream polysilicon sector.

Domestic polysilicon prices were assessed in the range of CNY75-83/kg. While major polysilicon makers hold their price quotes at the higher end of the range, tier-2 producers have cut prices to their lower end, pulling overall market prices down.

Weakening polysilicon demand – driven by lower solar installation rates in the fourth quarter of 2023 – contributes to the move downward, with trade volumes light in the week to Tuesday. Wafer makers have cut their operating rates as module inventories build and solar installations face delays in the fourth quarter. Expecting polysilicon prices to fall further, wafer makers adopting a wait-and-see approach when purchasing the material.

High inventories in both the polysilicon and wafer segments also weigh on prices. According to a solar market veteran, China’s wafer inventories are estimated at 20 GW and polysilicon inventories at around 50,000 MT.

China polysilicon prices are expected to bottom out in the fourth quarter as more polysilicon capacity comes online and building inventories contribute to a supply glut.

OPIS, a Dow Jones company, provides energy prices, news, data, and analysis on gasoline, diesel, jet fuel, LPG/NGL, coal, metals, and chemicals, as well as renewable fuels and environmental commodities. It acquired pricing data assets from Singapore Solar Exchange in 2022 and now publishes the OPIS APAC Solar Weekly Report.

From pv magazine 10/23

Solar installations in India have been steadily rising since March 2023. As per official numbers, India installed 9 GW (AC) of solar capacity from January to August 2023, which is around 12 GW of DC capacity, according to estimates. These installation numbers reflect many projects that were originally supposed to be built in 2021 and 2022 but were hindered by high equipment prices.

A government-approved relaxation of restrictions imposed by the approved list of models and manufacturers (ALMM) – which indicates which products can be included in government-backed projects – has accelerated Indian PV installations, helped also by falling module prices.

The start of 2023 looked a bit gloomy for India, compared with the usual pattern of a strong first quarter each calendar year. Module price and availability prevented many projects from being completed. In May, after the SNEC solar trade show in China, the market turned around. Module prices, excluding import duties, quickly dropped below $0.18 per watt (W) and continued to fall, reaching less than $0.15/W in the July to September period. Installers took the chance to complete pending projects, driving the current installation boom, which is likely to continue through the first three months of next year.

Rising imports

Local developers have grabbed the opportunity offered by module price declines to order in bulk. We believe that will lead to a strong upswing in module imports in the final three months of this year and the first three months of 2024. These modules will go into projects in the first part of next year and possibly even further out, depending on how legislation evolves.

Current regulation allows for government-tendered projects to include modules not named on the ALMM list, until March 31, 2024. Modules imported before that deadline but not installed will not be eligible for installation on government-aided projects. Developers are trying to persuade the government to extend that deadline by another three months, to give them more flexibility in terms of orders and imports.

Expanding production

Module manufacturers have ramped up India’s solar panel output, with annual production capacity expansions driven by national local-content policies. Annual module manufacturing capacity in India has already crossed the 20 GW mark but the factory utilization rate remains below 50% to date. That means, with local manufacturers having brought their prices closer to the cost of imported modules (plus basic customs duty), they will not be able to meet demand.

The fall in imported solar cell prices has resulted in a strong spike of cell imports over the past few months, which is likely to boost solar module-assembly factory utilization rates. The share of Indian-manufactured modules in new installations is expected to increase accordingly, especially after March 2024.

The combined generation capacity of imported and locally manufactured modules is still not enough to supply the 60 GW (AC) or so of solar projects that the Central Electricity Authority reports as being at some stage of construction.

Projects corresponding to more than two thirds of this capacity are unlikely to obtain modules before March 31, 2024. Hence, most developers of government-backed projects will need to procure modules included on the ALMM list. Such constraints on module procurement put the solar project pipeline at risk of delays.

In parallel with the government-backed PV project pipeline that dominates the Indian solar market, there is also growing interest among commercial and industrial electricity consumers seeking to procure solar power via on-site systems or private power purchase agreements. As these are not limited by ALMM list requirements, these segments of the solar industry are in position to benefit from possible module inventories in 2024. India’s PV deployment is, hence, set to diversify further across different market segments.

Given the high number of PV projects waiting to be commissioned and the level of module imports expected for the rest of the year, S&P Global Commodity Insights forecasts India will have installed 20 GW of solar this year. Solar installations in 2024 could be even higher than our forecast, depending upon government policy and possible further ALMM relaxations. Deadline extensions are possible, as we have seen previously in India’s solar power market.

About the author: Josefin Berg is an associate director for solar research at S&P Global Commodity Insights, leading a team that covers forecasts, trends, and company strategy in the downstream solar market. Her focus areas include developers and engineering, procurement and construction business strategies, demand for PV in emerging markets, and the role of solar in the power mix. With more than 12 years of industry experience, she writes reports on PV markets and trends and regularly speaks at industry events.

From pv magazine Germany

The downward trend in module prices across the board could not be stopped this month, but it is clearly losing momentum. Manufacturers and dealers of solar modules are still reducing their prices, but only in small steps, and seek to slowly approach the price level accepted by the market. For a long time now, nothing has been earned from products at this price level.

In China too, it's all about minimizing damage, because unsold stocks generate avoidable costs and the risk of progressive depreciation is always present. In order not to have to pay extra for transport costs, export quantities to Europe have been drastically reduced by Asian producers in recent weeks.

Interestingly, module prices on continents other than Europe and Asia are not as affected by the price decline. The price gap is sometimes drastically different – in the United States, it is up to 100% compared to the European prices for modules with comparatively low efficiency, which means with monocrystalline PERC cells.

However, products produced in China cannot easily be redirected to America because there are strict import restrictions there. This keeps prices there high and market volume low. We will be curious to see whether the US Inflation Reduction Act (IRA) really has the desired and needed impact on local PV production capacity. At least with the currently very high purchase and installation costs in the United States, it is rather unlikely.

Transferring this model to other markets is risky, although some non-Chinese manufacturers are already celebrating and shifting their sales focus and scope of operations to the United States. An industry cannot be kept alive permanently through subsidies, we should all have learned that by now.

Chinese photovoltaic manufacturers cannot endure a sustained period of low prices for long and are already trying to stabilize prices again through artificial shortages. If demand picks up again towards the end of the year due to the current price situation, the downward trend could soon be stopped. There is hardly a market participant who is happy with the current situation.

Overview of the price points differentiated by technology in October 2023, including the changes compared to the previous month (as of Oct. 15):

About the author: Martin Schachinger studied electrical engineering and has been active in renewables for more than 20 years. In 2004, he set up pvXchange.com. The online platform allows wholesalers, installers, and service companies to purchase a range of components, including out-of-production PV modules and inverters.

The turbulent weather seen in recent months across Europe and beyond – crippling heatwaves, thunderous storms, and catastrophic floods – has once again highlighted the need to tackle the climate crisis by reducing our carbon footprint, and to transition to net zero as quickly as is humanly possible.

The United Kingdom government’s U-turn on some of its net zero commitments has placed an even greater emphasis on the role local authorities can and must play in creating a cleaner, healthier environment.

Members of the Key Cities network have shown a high level of ambition and proactive action in terms of achieving net zero, with many developing strategies, forming strong partnerships between community and private enterprise, and delivering successful projects across various sectors.

Crucial to these efforts is the development of sustainable energy. One technology which has attracted the attention of our Key Cities members has been solar power. Along with wind, solar offers the promise of renewable, sustainable energy and the creation of the infrastructure needed to collect and channel it is almost certain to lead to the creation of thousands of new, well-paid jobs.

Like many people, members of the Key Cities network were interested to hear, earlier in the year, of government plans to back technology which would, in effect, collect energy from the sun out in space using satellite-mounted panels and beam it back down to Earth.

It will doubtless take years to develop but as scientists work on this and other schemes to develop much-needed sustainable energy security, closer to home, Key Cities members have been making their own contribution toward greening our energy and power networks.

Findings

As spelled out in our “Levelling Up, Emissions Down: Accelerating Net Zero across the Key Cities” report, the United Kingdom has made significant progress in lowering carbon dioxide emissions in the last 30 years, with a reduction of 73.4% between 1990 and 2021, largely as a result of the closure of coal fired power stations and increased investment in low-carbon energy sources such as solar, wind, and nuclear energy.

There is still much work to be done but many of our network members have already embraced the challenge of creating more sustainable energy solutions. As well as having a significant environmental impact in these areas, these examples highlight the potential of solar power, should it be adopted more widely across the country. The English city of Wolverhampton has worked with the its local National Health Service hospital trust to install a 6.9 MW solar farm on a former landfill site to direct renewable energy to the hospital, meeting 70% of its electricity needs. In the English town of Blackpool, a major solar farm located alongside the city’s airport will provide sustainable energy to a nearby business enterprise zone.

In the Welsh city of Newport, a partnership with the Sustainable Communities Wales initiative driven by environmental charity Severn Wye and the Wales Cooperative has ensured 2,000 solar panels will be installed at the Geraint Thomas National Velodrome. This is expected to reduce the city council’s carbon emissions by 348 tons per year and will generate 1,973,MWh of electricity annually.

Funding secured through United Kingdom government body the Public Sector Decarbonisation Scheme (PSDS) has enabled the English metropolitan borough of Salford to install 2,562 solar panels on 21 public buildings across the city, generating 778 MWh per year. Four sites have also had battery energy storage systems installed and the 3.79 hectare Little Hulton solar farm, also funded through the PSDS, will triple energy generation.

These are encouraging examples but challenges remain. According to national electricity network operator National Grid, the United Kingdom government’s target of 50 GW of offshore wind by 2030 will require six times the amount of transmission infrastructure that was delivered in the past 30 years.

Local projects also require changes to the grid. One city in the Key Cities network is aiming to deliver 300 MW of renewable energy to meet its net zero targets; to date it has delivered 50 MW, with another 100 MW in the pipeline. Without an upgrade to the grid, however, it is unable to deliver more than this until post-2028 at the earliest, which will result in the city being unable to meet its net zero targets.

Economic benefits

The path to net zero is not only being driven by a need to address the encroaching climate crisis. Net zero solutions increasingly offer returns to the economy, over and above the economic benefits of preventing global warming. For example, renewable energy generation increasingly competes in cost terms with fossil fuels while the prices of solar and onshore wind have fallen by 88% and 68%, respectively, since 2010.

Investing in net zero solutions will have a range of other economic and social benefits, including job creation, improved energy security, and improved public health due to a fall in air pollution. Clearly, the road to net zero is not only essential to prevent climate change, but also to support the economies of places around the United Kingdom.

While local authorities are making significant contributions to achieve net-zero, greater autonomy through devolved powers and funding would significantly expedite progress and help overcome challenges such as capacity building across councils and the clarification of roles in the national net-zero transition. This is where the power of the network comes in, enabling Key Cities to harness the talents of both the community and the private sector, leading the charge towards a sustainable energy network and a climate-conscious future.

About the author: Cllr John Merry is chair of the Key Cities network and deputy mayor of Labour-led Salford City Council.

Solar photovoltaic, solar thermoelectric and wind energy production

In the week of October 9, solar energy production decreased compared to the previous week in the main European electricity markets. The largest drop, 23%, was registered in the Portuguese market. In the other markets, the drop in solar energy production ranged from 19% in Germany to 8.1% in Italy.

Despite the weekly drop in solar energy production related to the seasonal change, when comparing solar photovoltaic energy production in the first half of October 2023 with the same period in previous years, since 2019, the record was broken in all analyzed markets.

During the first half of October 2023, the highest photovoltaic energy production, 2036 GWh, was registered in the German market, an increase of 5.4% compared to the same period in 2022 and 62% compared to 2019. In Mainland Spain, photovoltaic energy production for the first 15 days of October 2023 was 1613 GWh, an increase of 37% and 286% compared to the same period in 2022 and 2019, respectively. The lowest production, 160 GWh, was registered in Portugal, but still represented an increase of 33% compared to 2022 and 228% compared to 2019. For the week of October 16, according to AleaSoft Energy Forecasting’s solar energy production forecasts, solar energy production is expected to decrease in the analyzed markets.

In the case of wind energy production, the week of October 9 brought a week‑on‑week increase in most of the markets analyzed at AleaSoft Energy Forecasting. The largest increase, 51%, was registered in the French market. In this market, 261 GWh was generated with wind energy on Friday, October 13, which is the highest value registered since the beginning of August. In the other markets, the increase ranged from 8.6% in Germany to 43% in Italy. The exceptions were the markets on the Iberian Peninsula, where overall wind energy production fell by 12% compared to the previous week.

For the week of October 16, AleaSoft Energy Forecasting’s wind energy production forecasts indicate that wind energy production will increase in all analyzed markets, except for Germany.

Electricity demand

During the week of October 9, electricity demand increased compared to the previous week in most of the main European markets. Increases ranged from 0.6% in the Belgian market to 6.2% in the German market. In the case of Germany, the rise was related to the recovery of the labor rate after the previous week’s celebration of Germany’s Unity Day on October 3. Something similar happened in Portugal, where Portugal's Republic Day was celebrated on October 5, which favored a 5.3% increase in demand in that market in the second week of October.

On the other hand, demand fell in only two of the main European electricity markets. In Spain, the drop was 7.6%, and it was related to the celebration of Spain's National Day on Thursday, October 12. Demand also fell in the French market, in this case by 0.6%.

During the same period, average temperatures fell in most of the analyzed markets, ranging from 2.0 C in Great Britain to 0.1 C in Germany and Italy. The exception was France, where average temperatures increased by 0.4 C compared to the first week of October.

For the week of October 16, according to AleaSoft Energy Forecasting’s demand forecasts, electricity demand is expected to increase in most of the main European markets, with the exception of Germany.

European electricity markets

During the week of October 9, prices in all European electricity markets analyzed at AleaSoft Energy Forecasting rose compared to the previous week. The largest percentage price rise, 70%, was reached in the Nord Pool market of the Nordic countries, while the smallest increase, 1.7%, was registered in the EPEX SPOT market of the Netherlands. In the other markets, prices increased between 5.0% in the EPEX SPOT market of Germany and 20% in the IPEX market of Italy.

In the second week of October, weekly averages were below €95/MWh in most of the analyzed European electricity markets. The exceptions were the Spanish, Italian and Portuguese markets. The Italian market reached the highest average, €145.30/MWh. In the case of the MIBEL market of Portugal and Spain, the averages were €125.39/MWh and €125.41/MWh, respectively. In contrast, the lowest average price, €9.25/MWh, was reached in the Nordic market. In the rest of the analyzed markets, prices ranged from €77.92/MWh in the German market to €90.55/MWh in the N2EX market of the United Kingdom.

Despite the increases in weekly average prices, in the second week of October, negative hourly prices were registered in the German, Belgian, British, Dutch and Nordic markets, influenced by high wind energy production values. The lowest hourly price, ‑€7.10/MWh, was reached in the Dutch market on Sunday, October 15, from 14:00 to 15:00.

But in the second week of October hourly prices above €200/MWh were also registered on several occasions in most of the analyzed European markets. This was also the case on Monday, October 16 in all analyzed markets, except for the Portuguese and Nordic markets. On that day, the highest hourly prices were registered from 19:00 to 20:00 CET. In the German, Belgian, French, Italian and Dutch markets, a price of €240.00/MWh was reached. In the case of the French and Italian markets, this price was the highest since August 24. On the other hand, in the case of the Spanish market, an hourly price of €220.00/MWh was reached on October 16 from 19:00 to 20:00 CET, which was the highest price since the end of January. On the same day and hour, the British market also reached the highest hourly price since January, at £241.19/MWh.

During the week of October 9, the rise in the average price of gas and CO₂ emission rights, the increase in demand in most markets and the general decline in solar energy production led to higher prices in the European electricity markets. In the case of the MIBEL market, wind energy production in the Iberian Peninsula and nuclear energy production in Spain decreased, contributing to the increase in prices.

AleaSoft Energy Forecasting’s price forecasts indicate that in the third week of October prices in most of the main European electricity markets might continue to rise, influenced by declining solar energy production and increasing demand in most markets. In the case of the German market, the decline in wind energy production might also exert an upward influence on prices.

Brent, fuels and CO₂

Settlement prices of Brent oil futures for the Front‑Month in the ICE market remained above $85/bbl during the second week of October. The weekly minimum settlement price, $85.82/bbl, was registered on October 11. On the other hand, the weekly maximum settlement price, $90.89/bbl, was reached on Friday, October 13. This price was 7.5% higher than the previous Friday.

In the second week of October, concerns about the impact of the Middle East conflict on oil supply and OPEC’s global crude oil demand growth forecasts exerted their upward influence on Brent oil futures prices. However, data showed an increase in crude oil stocks of the United States that exerted some downward pressure. On the other hand, in the second half of the week, the United States started to impose sanctions on tanker owners carrying Russian oil at a price higher than the maximum price imposed by the G7, which might also have an impact on supply.

As for settlement prices of TTF gas futures in the ICE market for the Front‑Month, they increased during the second week of October. On Monday, October 9, the weekly minimum settlement price, €43.95/MWh, was reached. This price was already 12% higher than the previous Monday. The weekly maximum settlement price, 53.98 €/MWh, was reached on Friday, October 13. This price was 41% higher than the previous Friday and the highest since mid‑February.

In the second week of October, prices were influenced upward by supply concerns due to instability in the Middle East, labor disputes at Australian liquefied natural gas export facilities and a pipeline leak in the Baltic Sea. In addition, the forecast of cooler temperatures in Europe also contributed to price increases, as these would favor an increase in gas demand for heating.

Settlement prices of CO₂ emission rights futures in the EEX market for the reference contract of December 2023 remained above €80/t during the second week of October. The weekly minimum settlement price, €81.75/t, was registered on Monday, October 9, and it was 1.2% higher than the previous Monday. Subsequent price increases led to a weekly maximum settlement price of €85.95/t, reached on Friday, October 13. This price was 6.8% higher than the same day of the previous week and the highest since the end of August.

Source: Prepared by AleaSoft Energy Forecasting using data from ICE and EEX.

AleaSoft Energy Forecasting’s analysis on the prospects for energy markets in Europe and the financing and valuation of renewable energy projects

The world of photovoltaic solar energy is rapidly evolving, and at the forefront of this transformation is the International Energy Agency (IEA) Photovoltaic Power Systems Programme (IEA PVPS), a collaboration of hundreds of experts across academia, governments and industry. Task 1 of the IEA PVPS focuses on Strategic PV Analysis and Outreach. For 30 years, the Trends in PV Applications Report offers a comprehensive view of the PV market, policies and key industry developments globally, and the challenges and opportunities that lie ahead. It is designed to assist those who are responsible for developing the strategies of businesses and public authorities, and to support the development of medium-term plans for electricity utilities and other providers of energy services. It also provides guidance to government officials responsible for setting energy policy and preparing national energy plans. has been recently published.

Market Volumes: A Symbolic Milestone

As the PVPS Trends report reveals, the PV industry has achieved a significant milestone, crossing the 1-terawatt (1 183 GW) cumulative capacity mark. This achievement marks a symbolic turning point in the journey towards sustainable energy. Two thirds of all existing PV plants have been installed in the past 5 years.

In 2022, the annual capacity reached an impressive 235.8 GW, a new record, which could have been even higher, with grid connection issues and lack of installers slowing down the development of PV in numerous locations. Notably, China contributed 45% of this capacity, with the European Union following at 17%. The growth was not limited to these regions alone, as strong expansion was witnessed globally, with a 35% increase in annual capacity compared to 2021. Entering the list of the Top 10 annual PV markets wasn't solely confined to large countries or populations, as demonstrated by the Netherlands, which installed more than 3.9 GW of capacity (see Figure 2). However, the PV market is still concentrated in a dozen of countries globally, with a lot of additional potential for market development.

The report shows that PV capacity was evenly spread between distributed and centralized systems, despite variations in different countries and regions. Some countries, (India, the USA, Spain), showed a dominance of centralized systems, while China exhibited a more balanced distribution. Recently developed markets continue to start with utility-scale development while regulations for distributed systems are more complex to put in place. While the global PV market was on an upward trajectory, some countries experienced slowdowns due to supply issues, grid congestion, and labor shortages. These challenges are expected to persist in certain regions, emphasizing the need for strategic planning to address these issues.

Competitiveness Amidst Challenges

Because of the high cost of electricity in Europe and other locations, caused by events including the Ukraine war, the competitiveness of PV continues improving. Some support mechanisms, for example contract-for-difference arrangements, generated revenue for state governments, buoyed by these high electricity market prices. The Trends report also highlights the continued growth of prosumers (consumers, who are producing part – or all – of their own electricity consumption) policies, underlining the resilience of the PV market.

Industry Investments and Challenges

The PV industry witnessed significant investments in new silicon, cell, and module manufacturing capacity, with at least 700 GW of module manufacturing capacity. Governments around the world (USA, Europe, China, India) are actively supporting local manufacturing and trade conflicts and labor concerns are influencing manufacturing support. The rapid scaling of manufacturing outpaced market development, which resulted in significant module price drops in 2023 due to massive oversupply. With markets developing slower than needed, overcapacities in the industry will cause significant damages to many players and delay the roll out of much needed local manufacturing.

Social acceptance and grid Capacity: two Growing Concerns

As PV volumes surge, grid capacity is becoming a concern in some countries. While some nations are responding with substantial investments in transmission infrastructure, others are using curtailment and other measures at the distribution level. This comes in parallel with increased social acceptance, mostly related to centralized systems, issues which are delaying PV uptake in several key countries.

Conclusion: Shaping the Future Together

The IEA PVPS Trends Report not only provides valuable insights into the current state of the PV industry but also highlights the challenges and opportunities that lie ahead. As we celebrate the symbolic milestone of 1 TW of cumulative capacity, market development to reach climate change goals needs more support from policymakers and energy stakeholders. With a wider gap between market and production, a period of lower prices might accelerate PV development, while challenges remain numerous to ensure long term development.

This article is part of a monthly column by the IEA PVPS programme. It was contributed by IEA PVPS Task 1 – Strategic PV Analysis & Outreach. Further information can be found in Task 1’s new Trends in PV Applications 2023 report.

By Gaëtan Masson, Melodie de l’Epine and Bettina Sauer

The fastest energy change in history is underway. New solar PV generation capacity is being deployed faster than everything else put together. The price of PV continues to fall, and PV is essentially unconstrained. Thus, solar PV is growing to dominate not just electricity production, but also all forms of energy production, via the electrification of nearly everything.

How much waste?

Typical electricity consumption in advanced economies is 7-12 MWh per person per year. This will need to double to accommodate the electrification of transport, heating and industry. In some countries, additional electricity will be required to decarbonize the chemical industry: metals, ammonia, plastics, synthetic jet fuel, etc. Most of this electricity will come from solar, with limited support from wind and hydro.

For illustrative purposes, we can take an average per capita solar electricity generation of 20 MWh per year in an affluent fully decarbonized country. Assuming a typical DC capacity factor of 16% (rooftop and ground-mounted), then each person needs 15 kW of solar panels with an area of about 70 m².

The panel lifetime is 20-30 years, and so about 3 m² of solar panel waste per person per year is generated, with a mass of about 30 kg. This is small compared with the solid municipal waste stream in the USA of about 900 kg per person per year, and very small compared with CO₂-equivalent emissions in the USA of 19,000 kg per person per year.

How much of the PV modules is recycled?

The aluminum frame and electrical cables of retiring solar panels are normally recovered because of their value.

Most of the rest of the panel is glass, which is not toxic and the raw materials of which are inexhaustible. The mass of glass in 3 m² of solar panel is about 20 kg. This compares with the current US glass waste stream of 30 kg per person per year. Thus, if entirely discarded as landfill, solar panels would increase the glass waste stream, by two thirds, which is significant but far from overwhelming. The high quality of discarded low-iron solar glass may find specialist applications, including as starting material for new generations of solar panels, and in the road sign paint industry.

The solar panels also contain about 1.2 kg of silicon which is a non-toxic and extremely abundant material (n. 2 in the Earth’s crust). The balance of the panel comprises thin layers of protective plastic and a small mass of conductive metals such as copper (Cu), aluminum (Al) and silver (Ag) that may be recovered and recycled, depending on sufficient volumes to justify investments in recycling equipment.

A growing market in developing countries is the reuse, or second life, of solar panels. Many utility-scale solar power plants are replacing their 15% efficient panels with 22% efficient bifacial double-glass panels. The same trucks that deliver the new panels take back the retiring panels, which are then sorted and sent for a second life in low-power applications elsewhere.

During the early growth of an industry, the logistics to deal with retiring products might not initially keep up. This currently applies to both lithium batteries and solar panels. However, the pace of adoption of both technologies means that this will change quickly. The mature lead-acid battery industry provides a good example of high collection rates.

As the PV industry grows and matures, businesses will develop for sustainably managing end-of-life solar panels. The amount of PV materials to be recycled will remain comfortably below existing waste and recycling streams and hence no special disposal and recycling technology or logistics is required. Managing retiring solar panels will not be a limitation on the replacement of fossil fuels by solar.

How much avoided CO₂?

Importantly, the 3 m² of solar panels per person that is recycled each year has generated 20 MWh of electricity over its lifetime and displaced 20 tonnes of CO₂ emissions. This is about 1000 times larger than the waste in the panels, and its avoidance is a spectacular environmental gain.

The waste stream of a wind turbine is similarly small compared with the CO₂ displaced during its lifetime. Images of retiring turbine blades and solar panels being buried that periodically circulate on the web in shock articles fail to point out the 1000 larger mass of CO₂ emissions that the turbines and panels have avoided.

Authors: Prof. Andrew Blakers /ANU) & Prof. Ricardo Rüther (UFSC).

Andrew.blakers@anu.edu.au and rruther@gmail.com

ISES, the International Solar Energy Society is a UN-accredited membership NGO founded in 1954 working towards a world with 100% renewable energy for all, used efficiently and wisely.

Anomalous high pressure has delivered clear skies and high irradiance across both Mexico and eastern Canada whilst cloud associated with rain and storms depressed irradiance on the west coast of the US and Canada. Areas across Mexico and southern Texas saw reduced cloud, leading to 120-130% of average September Irradiance, according to data collected by Solcast, a DNV company, via the Solcast API.

Storms and a ‘Bomb” cyclone caused by persistent low pressure over British Columbia delivered cloudier conditions, leading to irradiance as low as 70% of long term averages.

Persistent high pressure reduces large cloud formation and redirects low-pressure cloud fronts, leading to periods of clear skies. In September large high pressure systems remained for longer than normal over both eastern Canada and southwestern US and Mexico.

For solar producers, these large and persistent systems have been especially beneficial with Quebec, Ontario and southern Mexico all seeing areas with 140% of the long term September GHI average.

Months like these bode well for the future of large solar installations in the south, with ERCOT having produced 3,301 GWh of Solar in the month. Mexico is also looking to take advantage of their high solar potential, through large solar projects like the planned 1 GW Puerto Peñasco solar plant.

Conversely, low pressure over western Canada & Alaska pulled in cloud from the Northern Pacific, leading to a significant increase in rainfall. This plus a ‘bomb’ cyclone in late September led to reduced irradiance across all of the Pacific Coast, most noticeable in British Columbia, where some locations saw just 70% of average September Irradiance.

Rainfall across the month was 7 mm/day above the September average, and temperatures were 5 C below average. Interestingly, this pattern of high pressure keeping skies clear and creating unseasonably sunny September conditions was also seen across parts of Europe, which also saw similarly high irradiance levels.

Mexico and the southwestern US can expect these conditions to reverse through winter, as El Nino winters tend to see Mexico and the South West under-perform against non-El Nino winter averages.

Solcast produces these figures by tracking clouds and aerosols at 1-2km resolution globally, using satellite data and proprietary AI/ML algorithms. This data is used to drive irradiance models, enabling Solcast to calculate irradiance at high resolution, with typical bias of less than 2%, and also cloud-tracking forecasts. This data is used by more than 300 companies managing over 150GW of solar assets globally.

Solar wafer prices plummeted to their lowest values ever when trading resumed after China’s Golden Week, according to OPIS data. Extending their downtrend from before the holiday, Mono M10 wafers plunged a substantial 10.29% to $0.34/pc and Mono G12 wafers fell a similar 7.33% to $0.468/pc.

The main factors behind wafer price reductions are the decline in downstream demand and the accumulation of wafer inventories brought on by the high operating rate of wafer producers, concurred numerous sources.

Based on the production schedules of wafer manufacturers, a market observer estimates that China's wafer production output would be around 65 GW in October. This would indicate an increase of around 8% in comparison to the 60–61 GW of wafers produced in September, according to data from the Silicon Industry of the China Nonferrous Metals Industry Association.

Approximately 2.4 billion pieces of wafers, or around 20 GW, are presently in stock on the wafer market, according to a source from a major vertically-integrated player. This figure will likely keep increasing soon due to the high operating rates of wafer factories, the source added.

Based on polysilicon’s current pricing, the cash cost for producing Mono M10 wafers at Tier-1 facilities is approximately CNY2.5 ($0.34)/pc, which means that there is still some room for Mono M10 wafers prices – currently average market price of approximately CNY2.78/pc – to fall further, according to a source from the polysilicon segment.

The sales of wafers has also been hampered by downstream manufacturers' reduced production and wait-and-see attitude, OPIS learnt during its weekly market survey. This week also marks the lowest price ever for solar cells, with Mono M10 and G12 cells falling by 8.35% and 2.39%, respectively, to $0.0746/W and $0.0816/W.

According to another market watcher, cell manufacturers currently have no incentive to maintain high operating rates given their low profit margins, resulting in a decrease in wafer demand. This source therefore anticipates that wafer producers may be forced to reduce their prices on a weekly basis due to the steadily declining demand.

“Wafer producers cut production when wafer prices fall to the point when there is no more room for price reduction,” a source from a developer noted.

OPIS, a Dow Jones company, provides energy prices, news, data, and analysis on gasoline, diesel, jet fuel, LPG/NGL, coal, metals, and chemicals, as well as renewable fuels and environmental commodities. It acquired pricing data assets from Singapore Solar Exchange in 2022 and now publishes the OPIS APAC Solar Weekly Report.

Italy finds itself 10 to 12 years behind other nations when it comes to renewables development and installation figures, thanks to a distrust of renewable energy generation versus more recognized forms of energy production, primarily nuclear, gas, and “clean coal.”

Finally, though, acceptance of the necessity of clean power is dawning. Italy will need to add 50 GW of solar generation capacity by 2030 as part of 70 GW of new clean power facilities needed to meet European targets.

A notoriously sluggish permitting system has resulted in less than 1.5 GW per year of new photovoltaics, with around 800 MW added in 2020 and 940 MW in 2021, rising to around 2.5 GW last year. Residential solar, at least, has advanced markedly in the last two years.

The government has also set a target of sourcing 55% of Italian-generated electricity from renewables by 2050.

Solar has been boosted by regional residential-PV incentives and a move to simplify permitting for clean energy plants under the procedura abilitativa semplificata (PAS), which came into force in April 2022.

Italy’s European Union-funded, post-Covid economic recovery plan, the Piano Nazionale di Ripresa e Resilienza (PNRR) – approved in July 2021 – allocated €1.5 billion ($1.6 billion) for the installation of solar on agricultural buildings, referred to as “agrisolar,” and €1.1 billion for agrivoltaics. None of the PNRR funds were allotted to conventional, ground-mounted solar parks.

That was mainly because of permit delays for conventional ground-mounted solar. While the PNRR millions fired the starting gun on agrivoltaic projects with a generation capacity of more than 1 MW, the drawn-out nature of the “autorizzazione unica” central permitting process for photovoltaics, and the diverse planning policies of local governments, have led to inevitable development hold-ups for ground-mounted solar.

Project clusters

The PAS has at least shaken things up, with many projects that were awaiting autorizzazione unica approval withdrawn and resubmitted as clusters of smaller sites, with generation capacities no larger than 20 MW in order to be eligible for the simpler permitting process. Numerous projects, in fact, have reappeared with a capacity ceiling of 14 MW, as securing connection to the medium-voltage grid is far easier than to the high-voltage network applicable to larger sites.

The raised cost of agrivoltaics reflects the fact panels cannot be as tightly packed as in conventional ground-mounted sites, due to the requirements of the crops planted under and between them.

Expensive

INTEC Energy Solutions' experience is that agrivoltaic installations with panels installed anywhere from 2.1 m to 6 m off the ground require 30% to 60% more expense than ground-mounts, when it comes to their racking and installation cost. That is because more steel is needed and work is performed at height.

Working at height and removing the extra dust generated by farm vehicles adds 20% to 40% to agrivoltaic array operation and maintenance costs, versus ground-mounted sites.

The lower panel density means agrivoltaics require 10% to 40% more expense to generate electricity and an additional €20 to €50 payment per hectare is needed to cover the cost of mandatory statements by the farmer proving the continuation of agricultural production at such facilities.

Those expenses ensure agrivoltaic sites are, on average, around 40% more expensive than ground-mounted facilities.

At INTEC, we are keenly following the progress of agrivoltaic-related legislation in Italy and also monitoring the details of projects our customers have submitted in pursuit of PNRR incentives.

There is great enthusiasm about the potential of agrivoltaics for Italy, and the Russia-Ukraine conflict has emphasized not only the European Union’s dependence on Russian gas – triggering a general energy crisis – but also a reliance on certain foodstuffs sourced from Ukraine.

The two problems must be tackled hand in hand and agrivoltaics represent an ideal method of ensuring agriculture and energy production coexist without imbalance.

Getting the policy right is essential to ensuring the nascent agrivoltaic and agrisolar sectors do not become another missed opportunity, with practically-inaccessible incentives for farmers.

Detail

At the time of writing, we are still awaiting detail of the operating rules for agrivoltaic systems to be eligible for public incentives and PNRR cash. Developers need to know what design, construction, and monitoring requirements will apply and how the PNRR eligibility of such sites will be verified.

Regarding agrisolar, on farm buildings, a tender for such arrays was issued on July 21. Online applications must be submitted to the organization set up for the purpose by government renewables body the Gestore dei Servizi Energetici (GSE), with an application window due to have opened on Sep. 12 and set to close today.

The tender included an increase in PNRR financial aid of up to 80% for companies involved in, or set to switch to primary agriculture; the option of multiple farms sharing consumption of the solar power they generate and of combining as single agrivolatic-project applicants; and a raising of the maximum eligible rooftop array generation capacity to 1 MWp.

The procurement document also doubled the previous maximum PNRR-eligible expenditure, up to €100,000 for accumulation systems, and to €30,000 for recharging devices, with a PNRR total per single project ceiling of €2.33 million.

About the author: Andrea Tedesco is country manager for Italy at INTEC Energy Solutions. He holds an MSc in electronics engineering and has solar industry experience as a senior project, technical, and area manager; sales and marketing director; and business unit manager. His expertise includes new-business and product development, project management, and building alliances and partnerships.

From pv magazine 09/23

Polish PV project permitting, decided on the basis of conditions of development (decyzja o warunkach zabudowy), has long been relatively simple for developers to attain. However, a proposed new system would require developers to pass a local spatial development plan, which could be a considerably longer process.

According to the new law, change-of-land-use permission for solar plants would be offered only on the basis of local spatial development plans, for all arrays located on the most fertile, class I to class III agricultural land, or on forest land. The regime would also apply to arrays larger than 150 kW on less fertile, class IV agricultural land, and for projects larger than 1 MW on any other type of land. The size stipulation would be flexible for sites intended for business power production.

The recent draft legislation would offer developers the chance to secure permission before local plans are finalized, before Jan. 1, 2026. While previous planning decisions would remain valid indefinitely, those issued after the new law came into force would only be valid for five years.

Grid measures

On July 31, the lower house of the Polish parliament and the Senate prepared an amendment to the Energy Act which would oblige large electricity retailers to offer dynamic pricing, in line with EU regulation. The statute is now awaiting presidential sign-off.

With solar projects held up by grid capacity shortages, the legislation would also relax the rules governing generators installing direct transmission to electricity consumers, without using the grid. The Energy Act already allows direct lines, the key proposed change is a waiving of the obligation to obtain a permit from the President of the Energy Regulatory Office to build such a line. That permit requirement effectively blocks such projects because it may be issued only if the energy customer has no option of receiving electricity from the public grid.

The legislation would liberalize the construction of such direct lines and set out specific requirements. First, electricity could be supplied only from a separate production unit, that is, from a unit that has a total output going to one consumer. It would, therefore, be impossible to connect 25% of a PV plant’s nominal power output to the grid and supply the remaining power directly to a dedicated consumer. Secondly, all of the electricity supplied would have to be consumed by a dedicated consumer, that is, a user that is not connected to the power grid or is connected in a way that prevents the feeding of electricity produced at the third-party production site, to the grid. The amended statute would, however, allow the feed of excess electricity not consumed by the dedicated consumer into the grid. Any such arrangement would have to be agreed with the grid operator.

The new law would impose charges on grid-connected energy consumers for using electricity supplied via a direct line from a generator, with the fee payable to the local grid operator. The fee would not apply to customers who are not connected to the public grid and who create a type of “power island” together with the generator.

With such off-grid direct lines expected to be rare, it is anticipated most energy consumers that establish a line to a dedicated generator would have to pay the, so-called “solidarity fee,” which the statute would require to be calculated on the basis of the quantity of power supplied via the direct line. The charge would be meant to cover the maintenance costs of grid system-quality standards and ensuring the reliability of ongoing power supply. In other words, the consumer’s share of the fixed costs of transmission and distribution of grid electricity. The solidarity fee would be calculated by local grid operators.

Cable pooling

Another approach to enable the connection of new clean energy plants to the grid without waiting for infrastructure upgrades is also worth mentioning. This is cable pooling: adding new renewables sites to the grid via existing connections.

The Senate has proposed such an option by adding a comprehensive legislative amendment to this effect, to the bill amending the Renewable Energy Sources Act and Certain Other Acts. Cable pooling is about sharing a connection between more than one generation site. Such pooling makes sense for plants with different production profiles, especially PV projects sharing connections with wind farms, as they often produce electricity at different times of the day and neither uses their full connection capacity most of the time. Cable pooling will rely on physical security measures to prevent overuse of any connection capacity assigned. The cable pooling amendment put forward by the Senate is yet to be approved by parliament.

Last but not least, the trade in PV projects in Poland shows no sign of slowing down. The market is getting more and more professional. Buyers and project developers are increasingly seeking business partners on industry portals and classified advertisement websites.

About the author: Piotr Mrowiec is an associate partner at Rödl & Partner. He is head of the office in Gdansk, Poland and leader of the renewables team. As a specialist in renewable energy regulation, he advises numerous clients and conducts legal due diligence for PV and wind projects. Mrowiec has also been involved in studies for dozens of solar and wind projects.

Solar photovoltaic, solar thermoelectric and wind energy production

In the week of October 2, solar energy production decreased in all analyzed markets compared to the previous week. The German market registered the largest drop, which was 28%. In the other markets, the decrease in solar energy production ranged from 9.1% in Portugal to 4.3% in France.

Solar energy production is expected to decrease in all analyzed markets except the Spanish market, according to AleaSoft Energy Forecasting’s solar energy production forecasts for the week of October 9.

The week of October 2 brought a week‑on‑week increase in wind energy production in most of the markets analyzed. The largest increase, 108%, was registered in the German market. In this market, 753 GWh of wind energy was generated on Tuesday, October 3, the highest value since March 25. In the other markets, the increase ranged from 7.5% in France to 55% in Portugal. The exception was the Italian market, where wind energy production fell by 59% compared to the previous week.

For the week of October 9, AleaSoft Energy Forecasting’s wind energy production forecasts indicates that wind energy production will decrease in all analyzed markets.

Electricity demand

In the week of October 2, the evolution of electricity demand compared to the previous week did not show a common trend in the analyzed European markets. In some cases, demand increased compared to the previous week. The Spanish market registered the largest increase, 2.1%. It was followed by the British and French markets with corresponding increases of 0.7% and 0.2%. In the Belgian market, demand remained similar to that of the previous week. In the other analyzed markets, demand decreased. The largest declines – 2.2% and 2.0% – were registered in Germany and Portugal, respectively. During the week, both countries celebrated national holidays: Germany’s Unity Day on October 3 and Portugal’s Republic Day on October 5. Italy and the Netherlands registered smaller declines, 0.8% and 0.2%, respectively.

During the same period, average temperatures decreased between 1.6 °C—0.2 °C in most analyzed markets. The exception was Spain, where temperatures rose by 0.1 °C.

According to AleaSoft Energy Forecasting’s demand forecasts for the week of October 9, electricity demand is expected to increase in most analyzed European markets, with the exception of Spain, where the Spanish National Day will be celebrated on October 12.

European electricity markets

During the week of October 2, prices in most European electricity markets analyzed at AleaSoft Energy Forecasting decreased compared to the previous week. The exceptions were the IPEX market of Italy and the Nord Pool market of the Nordic countries, where the price increased by 3.9% and 43%, respectively. On the other hand, the EPEX SPOT market in Germany registered the largest decline, 30%. In the other markets, prices fell between 6.8% in the MIBEL market of Spain and 21% in the EPEX SPOT market of Belgium.

In the first week of October, weekly averages were below €85/MWh in most of the analyzed European electricity markets. The exceptions were the Spanish, Portuguese and Italian markets, where the averages were €105.23/MWh, €105.41/MWh and €120.79/MWh, respectively. On the other hand, the lowest average price, €5.45/MWh, was reached in the Nordic market. In the other analyzed markets, prices ranged from €74.20/MWh in the German market to €82.61/MWh in the Dutch market.

In terms of hourly prices, on October 3, negative prices were registered in the German, Belgian and French markets, while, on October 4—7, negative prices were registered in the Nordic market. The lowest hourly price, ‑€11.07/MWh, was reached in the German market on October 3, from 13:00 to 14:00. This was the lowest price in the German market since the first half of August.

On the other hand, in the first week of October, prices above €200/MWh were also registered in the German, Belgian, Italian and Dutch markets. The highest hourly price, €250.28/MWh, was reached in the German market on October 5, from 19:00 to 20:00. In addition, on Monday, October 9, hourly prices above €200/MWh were registered in the German, Belgian, French, Italian and Dutch markets. On that day, in the Spanish and Portuguese markets, from 20:00 to 21:00, a price of €184.50/MWh was reached, the highest price registered in these markets since March. In the N2EX market of the United Kingdom, on Monday, October 9, from 19:00 to 20:00, a price of £184.24/MWh was registered, the highest since August.

During the week of October 2, the decrease in the average price of gas and CO₂, as well as the increase in wind energy production in most markets, led to lower prices in European electricity markets. However, in the Italian market, wind energy production decreased, contributing to the price increase in that market.

In the second week of October, prices might increase in most of the analyzed European electricity markets, influenced by the general decline in wind energy production and the increase in demand in most markets, AleaSoft Energy Forecasting’s price forecasts indicate.

Brent, fuels and CO₂

Brent oil futures for the Front‑Month in the ICE market reached the weekly maximum settlement price, $90.92/bbl, on Tuesday, October 3. This price was 3.2% lower than the previous Tuesday. Subsequently, prices decreased and in the last two sessions of the first week of October settlement prices remained below $85/bbl. The weekly minimum settlement price, $84.07/bbl, was registered on Thursday, October 5. This price was 12% lower than the previous Thursday and the lowest since August.

In the first week of October, concerns about the evolution of the global economy and demand exerted their downward influence on Brent oil futures prices. However, fears of supply problems related to growing instability in the Middle East might exert an upward influence on prices in the second week of October.

As for settlement prices of TTF gas futures in the ICE market for the Front‑Month, during the first week of October, they remained below €40/MWh. On Monday, October 2, the weekly maximum settlement price, €39.33/MWh, was reached. This price was 11% lower than the previous Monday. The weekly minimum settlement price, €36.21/MWh, was registered on October 5 and it was 8.9% lower than the previous Thursday. But on Friday prices increased again until registering a settlement price of €38.23/MWh, which was still 8.7% lower than the previous Friday.

The high level of European reserves and the forecast of mild temperatures contributed to prices being below €40/MWh during the first week of October – but the possibility of strikes at Australian liquefied natural gas export facilities led to the price increase registered at the end of the week.

CO₂ emission rights futures in the EEX market for the reference contract of December 2023 reached the weekly maximum settlement price, €81.67/t, on October 4. This price was 0.8% lower than the same day of the previous week. On the other hand, the weekly minimum settlement price, €79.65/t, was registered on Tuesday, October 3, and it was 4.0% lower than the previous Tuesday. This price was the lowest since the beginning of June.

The high level of renewable energy production reduced the demand for emission rights associated with fossil fuel electricity production. This had a downward impact on prices in the first week of October.

From pv magazine 09/23

In 2021, India’s annual solar manufacturing capacity stood at 14 GW. While superficially an impressive figure, much of this capacity was sub-scale and technologically obsolete, with Chinese imports meeting more than 80% of Indian demand. Even though module manufacturing capacity has now grown to 26 GW, actual production remains low, at around 8 GW annually.

There are multiple policies that have driven solar manufacturing expansion. In April 2022, the Indian Ministry of Finance levied hefty 40% and 25% border customs duties – plus a 10% surcharge – on imports of all solar modules and cells, respectively. As a result, module imports fell sharply from a monthly average of slightly more than 1.6 GW, in 2021-22, to just 175 MW in the last fiscal year.

An additional policy, the Approved List of Models and Manufacturers (ALMM) has also had an effect. Under the ALMM, all grid connected projects, including rooftop solar systems, are required to use government-certified cells and modules, made by approved manufacturers. While the scheme does not formally discriminate between suppliers on the basis of nationality, approvals have so far only been granted to Indian companies.

The scheme was meant to be applicable from March 2021 but the implementation timeline was shifted to April 2024, due to lack of sufficient domestic capacity. By July of this year, 19.2 GW of module manufacturing capacity had been approved across 78 manufacturers.

The government has allocated capital subsidies of $2.2 billion to 12 companies setting up a total manufacturing capacity of 48.3 GW under its Production Linked Incentive (PLI) scheme. Subsidy amounts will be differentiated based on parameters such as the extent of upstream integration, local value addition, capacity, and solar module efficiency. It is estimated PLI funding will amount to around 25% of investment capital costs. Notable companies to win subsidies include Reliance, Shirdi Sai, Adani, First Solar, ReNew, Tata Power, Avaada, JSW, AMP, Waaree, and Vikram Solar.

Tax and zoning

The Ministry of Finance has also reduced the corporate tax rate from 25.2% to 17.2% for manufacturing companies incorporated after September 2019, provided they go into operation before April 2024.

The government is setting up three dedicated renewables equipment manufacturing zones with capital assistance of INR 10 billion ($121 million). These zones are being selected through a competitive bidding process based on the lowest power and land costs for the manufacturing businesses. The government of the state of Madhya Pradesh has been awarded the first tranche, with a capital assistance of INR 4 billion.

Local and regional funds are also available to manufacturers. Most states offer multiple benefits including capital and operating-cost subsidies, lower general sales tax rates, cheap land, and so on. The central government is also encouraging public and private lenders to support manufacturing projects.

Policy thrust

The substantial policy thrust has resulted in a flurry of market activity. Bridge to India estimates total domestic polysilicon, cell, and module production capacities will reach 30 GW, 43 GW, and 110 GW, respectively, by 2026. That said, module supply is expected to remain constrained in the short-term until a significant chunk of new capacity comes online, by the end of 2024. Most manufacturers prefer to sell in the overseas market, particularly in the United States, where they can command up to 40% higher prices.

India is on the way to becoming the world’s second largest manufacturer of solar modules but there are still many issues and challenges to consider. There is lingering policy uncertainty as project developers are seeking another extension of ALMM and further import duty petitions are being considered by both upstream and downstream solar manufacturers. There is also the risk of World Trade Organization (WTO) disputes causing uncertainty. China has already flagged the ALMM mandate as a specific trade concern four times at the WTO.

The goal of becoming self-sufficient, as far as solar energy products are concerned, still appears elusive as upstream Indian polysilicon and wafer production capacity is expected to be insufficient to meet demand. Indian manufacturers are critically dependent on China for technology expertise, manufacturing machinery, component supplies, and even engineering skills. In the longer term, there are also concerns that the generous US Inflation Reduction Act may mean Indian modules are not cost competitive in export markets. Indian modules are expected to remain at least 25% to 30% more expensive than their Chinese counterparts.

About the author: Vinay Rustagi is the managing director of Bridge to India, a renewables-focused research company and consultancy. He advises project developers, investors, equipment suppliers, technology companies, and policymakers on a wide range of issues related to business strategy, market environment, policy frameworks, and finance.

From pv magazine Germany

A week ago, Rystad Energy corrected its previous statements about the inventory of Chinese module imports downwards by 60% and assumed 40 GW inventories in the EU at the end of 2023.

Quote: “The market has reacted and companies have significantly reduced their orders,” said a Rystad analyst in an article published by pv magazine on September 29. Relying on export data for modules from China to Europe, he said that inventory levels are stagnating at around 40 GW. Manufacturers would not flood the European market without wholesalers and project developers placing corresponding orders, he also said.

This week, however, Rystad told pv magazine that there are suddenly 80 GW in the EU warehouses, and Rystad assumes that there could be 100 GW by the end of 2023.

Rystad said that the new numbers are based on new figures that have only been available this week, with the assumed decline having not occurred after all.

Bang! From 40 GW to 80 GW within six weeks because of supposedly new numbers.

And what happens next is no longer understandable to me.

From January 2023 to the end of August 2023, around 78 GW were exported from China to the EU. That's right – the official export figures from China are confirming this and it is no secret. The 78 GW probably also includes at least 5 GW to 6 GW of OEM modules that are sold under labels from “EU manufacturers” but come entirely from China.

Anyone can easily check this here for the last few years (csv file, scroll to EU):
https://ember-climate.org/data-catalogue/china-solar-pv-exports/

As I have already described several times, at the end of 2022, with an EU market of 46 GW, we had a “normal” inventory of two to three months, essentially around 8 GW, plus around 33 GW.

How to calculate “module surplus” with a simple Excel table

This is how the year 2023 began, and from here on, it is a simple Excel table with which you can calculate the “module surplus.”

In this table, you will note the official export from China to the EU with a delay of around two months, the EU market development up to the point in time under consideration, and the “normal storage cycle” of two to three months until the modules then appear in the installation statistics.

Based on my long solar experience, these are normal numbers on the way from the port to the customer and the completed installation or its official registration.

With an EU market of 60 GW to 114 GW expected for 2023, 10 GW to 19 GW would be the expected new normal for module inventories.

It's just a different dimension than before, and you have to get used to 10 GW to 19 GW as a “normal” warehouse flow – until recently, the entire EU market was that big per year. But now, it is 20 times larger than it was in the darkest days of the anti-dumping duties.

I'm surprised at how the analysts at Rystad Energy are proceeding. It has been easy all year long to take the Chinese export data, add “normal” warehouse flow, and then follow the EU installations closely. There was “no new data overnight,” only the export data from August of 8 GW, after 7.2 GW in July, and 11.6 GW in May. This doesn't look like a surprise to me.

In Germany, PV capacity is growing considerably, as reported every month by the Federal Network Agency. And in Germany alone, the market is growing by an incredible 85% compared to 2022, and I hear similar things from many other countries. Therefore, EU growth from 46 GW in 2022 to well over 80 GW in 2023 is entirely possible.

I don't know exactly where we stand with EU installations at the end of September. But it's very easy with Excel to enter 60 GW, 80 GW, and 114 GW as an EU market for the entire year 2023, scale it to the period up to the end of October using the rule of three, and calculate the export data plus warehousing against it.

The results for the EU warehouses can be estimated based on the end of October. By then, all of the exporters from August will have arrived here, meaning 78 GW since January. These are the results:

With a 60 GW market in the EU in 2023:
“Normal” inventory: 10 GW
Module consumption in 2023, up to and including October: 50 GW
“Excess” inventory, including excess from 2022: 59 GW

With an 80 GW market in the EU in 2023:
“Normal” inventory: 13 GW
Module consumption in 2023, up to and including October: 67 GW
“Excess” inventory, including excess from 2022: 39 GW

With a 114 gigawatt peak market in the EU in 2023:
“Normal” inventory: 19 GW
Module consumption in 2023, up to and including October: 95 GW
“Excess” inventory, including excess from 2022: 5 GW

I expect at least something quite simple like this from a large analyst firm like Rystad.

One could also say: “It's the real size of the EU installation market.”

Because that's what it's all about in the end: Have manufacturers, retailers, and others overestimated the EU market? Are there a lot of goods there? Or do they not have that, and in some cases, there is very little product?

In any case, it has nothing to do with “dumping” and you have to have strong special interests in order to derive accusations of dumping from the stocks. These would then apply in the same way to OEM modules imported from China, as well as to solar cells from China.

In the end, all the magnificent growth of the EU solar market is “brutally” good news for climate protection in the EU and the entire world.

Author: Karl-Heinz Remmers

Solar cell prices stopped declining this week – arresting three straight weeks of prior decline – due to limited activities during China's Golden Week holiday. According to OPIS data, prices have momentarily stabilized at their lowest levels ever this week – Mono M10 and G12 cell prices stayed unchanged at $0.0814 per W and $0.0836/W, respectively; TOPcon M10 cell price this week likewise remained at $0.0856/W.

The majority of industry sources concurred that following the holiday, new record lows for cell prices can be expected. A seller source predicts that the price of P-type M10 cells will decline to around CNY 0.61 ($0.085)/W after the holiday, while the price of TOPCon M10 cells will continue to carry a CNY0.05 ($0.0069)/W premium over p-type M10 cells.

The pricing differential between p-type and n-type M10 cells is confirmed by a second seller source, who predicts that after the holiday, p-type M10 cells may drop to around CNY0.63 ($0.088)/W while TOPCon M10 cells would drop to CNY0.68 ($0.094)/W

According to a market observer, cell producers are currently maintaining a profit margin of about 10-15%. This source therefore expected that there is still room for cell prices to decrease after the holiday.

Insiders anticipate a fall in cell prices, mostly as a result of a decline in demand for cells from downstream module producers due to certain module makers curtailing production. Additionally, module prices are also in the bearish sentiments due to the severe oversupply, as a result, cell prices will inescapably be influenced by downstream pessimism.

A source from an integrated player, on the other hand, expressed skepticism over the prediction that cell prices will continue decreasing following the holiday. “After all, the price of cells has already decreased by about 14% over the last three weeks, which is a significant amount,” the source explained.

The price of polysilicon has a significant role in determining how much cell price will drop after the holiday, a source from a specialized cell manufacturer concluded. There isn’t much room for wafer and cell prices to decrease at present. More significant price cuts must wait until polysilicon's price drop frees up price reduction space for wafers and cells, the source added.

OPIS, a Dow Jones company, provides energy prices, news, data, and analysis on gasoline, diesel, jet fuel, LPG/NGL, coal, metals, and chemicals, as well as renewable fuels and environmental commodities. It acquired pricing data assets from Singapore Solar Exchange in 2022 and now publishes the OPIS APAC Solar Weekly Report.

Germany and Central Europe saw their highest September irradiances in at least 17 years, due to an “Omega block” weather pattern. These levels reached 130-140% of historical September averages according to data collected by Solcast, a DNV company, via the Solcast API.

The record irradiances were caused by an ‘Omega’ blocking pattern that kept high pressure stuck over Central Europe, leading to consistently clear skies there, but pushed cloud and storms southward. This pattern is similar to other El Nino late summers in the region, but was more persistent, leading to the highest September Irradiance seen over Germany and Central Europe in Solcast’s 17 years of data. This pattern also led to concentrated precipitation further south, causing floods across Greece, Turkey and Spain. Cloud associated with that rain also decreased irradiance in those regions.

These patterns have driven significantly higher irradiance than normal for September from Germany to Russia. Somewhat making up for a cloudier than normal August, solar providers will have seen up to 130% of historical September averages. As can be seen in the below average daily GHI, Germany and Poland received roughly the same irradiance across the month as Spain and Portugal. This pattern is
particularly unusual, especially given the shorter days further north.

While such patterns align with previous El Nino years, the outcome this year stands out. Analysis using the Solcast Historical Time Series indicates a significant surge in September irradiance, surpassing any year in recent history. Major cities like Berlin, Munich, Prague, and Warsaw reported heightened September irradiance levels, with results closer to August averages than September. In contrast, the Iberian Peninsula and Greece saw diminished levels, with Lisbon and Athens capturing only around 80% of their typical September irradiance.

Solcast produces these figures by tracking clouds and aerosols at 1-2km resolution globally, using satellite data and proprietary AI/ML algorithms. This data is used to drive irradiance models, enabling Solcast to calculate irradiance at high resolution, with typical bias of less than 2%, and also cloud-tracking forecasts. This data is used by more than 300 companies managing over 150GW of solar assets globally.

From pv magazine 09/23

This year, solar manufacturers have increased vertical integration and production capacity, and the global industry has attracted new entrants, buoyed by the market outlook and advancing technology. Infolink data shows annual module production capacity grew at an average of 30% to 40% from 2018 to 2022. That rate is expected to double this year, to an unprecedented 80%.

Module oversupply

Technology and competition are driving expansion, prompting legacy manufacturers to modify production lines. For instance, passivated emitter rear contact (PERC) lines must have nine-busbar (BB) to 11 BB stringer machines upgraded to 16 BB devices, and have laminating temperatures controlled, to produce tunnel oxide passivated contact (TOPCon) modules. For heterojunction (HJT) production, busbarless cell interconnection requires dispenser equipment.

InfoLink expects that more than a terawatt of annual module production capacity will be reached this year. Inventory has already started stockpiling, driving buyers to wait. Quarterly module prices have fallen below manufacturer quotes and some solar companies have clawed back their overseas stock at the end of June, as underselling continued into early August.

Module-only manufacturers are thought to have experienced negative gross margins thanks to solar cell costs, and risk management strategy will be critical to survive in a competitive market.

Solar manufacturers with just a single business model will need a risk strategy as competition increases. SMEs could take advantage of flat organizational structures to show flexibility in equipment use and at a managerial decision-making level.

Standing out

Manufacturers can utilize the production of medium and low-efficiency products to control costs while also accepting special-specification or, unbranded, original equipment manufacturer (OEM) orders to manage monthly output. This allows for efficient capacity utilization and the maintenance of a stable utilization rate, which can be lowered to regulate inventory level. Based on historical expense data, the average gross margin level for OEM and dual-channel distribution may be lower than for direct sales. During periods of high market volatility, however, maintaining conservative gross margins can provide flexibility in continuing minimum operational conditions.

As the industry moves toward competitive convergence on identical or similar module technology, product differentiation strategies will help SMEs by increasing module diversity and market opportunities to create demand. Using differentiated products, such as flexible thin-film and small-format specialty modules – to expand product ranges and cater to different applications based on customer need – can foster the development of potential markets.

In addition, diversification of suppliers and customers can reduce reliance on certain clients, suppliers, and markets. As regional risks have been steadily increasing in recent years, particularly within the volatile environment of the solar industry, SMEs could become vulnerable to market fluctuation. Expansion overseas and developing diversified products will help spread risk and build solid customer relationships to ensure long-term business cooperation.

Vertical expansion

Manufacturers can also adopt supply chain integration strategies to manage the manufacturing capability of their upstream and downstream segments. Such vertical integration enhances cost management capability and retains transaction space by having in-house production capacity of other segments, thereby maintaining flexibility and mitigating risk during periods of greater volatility. Taking the example of cell manufacturers expanding into module production, if the cell inventory cycle extends, in-house module capacity can consume a portion of the cell output, ensuring better risk control.

The significance of vertical integration is growing for manufacturers. This involves expanding into project development, system design, integrated products, and after-sales operation and maintenance services. Such an approach can effectively address product usage and consumption issues. Moreover, manufacturers can gain a better grasp of real-time market information downstream through collaboration with clients.

The S word

With sustainability requirements tightening – in the form of environmental, social, and corporate governance (ESG) reporting guidelines set to become obligatory in the European Union and with new standards planned in the United States and internationally – PV manufacturers powered by non-renewable energy, for example, will face greater risk. At the same time, this will provide all players with more opportunities for differentiation. Manufacturers can seize this chance.

Long-term oversupply has become a key issue in the PV industry. Given the resource and financial constraints faced by SMEs, companies should deploy a combination of strategies to establish presence in a market that is marked by a convergence of competition. This includes exploring potential markets via differentiated products and adopting strategies such as OEM and dual-channel distribution to mitigate operational risk. With sustainability becoming a corporate imperative, manufacturers should also be prepared for future policy dynamics in regional markets, thereby seizing businesses opportunities. Adapting risk strategies will be a crucial factor for the survival of manufacturers with a single business model.

About the author: Amy Fang is an InfoLink analyst who focuses on the solar cell and module segment of the PV supply chain, working across price trend forecasting and production data.

Solar photovoltaic, solar thermoelectric and wind energy production

In the week of September 25, solar energy production increased in all analyzed markets compared to the previous week. The Italian market registered the largest increase at 38%. In the rest of the markets, the increase in solar energy production was very homogeneous, ranging from 15% in Spain to 18% in Germany. Furthermore, although solar radiation decreases as winter approaches, the Iberian Peninsula produced 163 GWh of solar energy on Monday, September 25, a volume of solar energy production not seen since September 1.

For the week of October 2, according to AleaSoft Energy Forecasting’s solar energy production forecasts, solar energy production is expected to decline in the analyzed markets.

As for wind energy production, there was a decrease in production from the week of September 25 in all markets analyzed by AleaSoft Energy Forecasting. The largest fall, 55%, was registered in the French market and the smallest decrease, 2.4%, in the Italian market. In the remaining markets, the decline in wind energy production ranged from 44% in Germany to 49% in Portugal.

For the week of October 2, AleaSoft Energy Forecasting’s wind energy production forecasts indicate that wind energy production will continue to fall in Italy and France, but it will increase in the rest of the analyzed markets.

Electricity demand

In the week of September 25, electricity demand increased in most European markets analyzed compared to the previous week. The largest increase, 5.6%, was observed in the Dutch market, followed by a 2.3% increase in the Spanish market. The smallest increase, 0.5%, was registered in Great Britain. Electricity demand fell in only two of the analyzed markets, by 4.5% in Italy and 3.4% in Belgium.

Over the period, average temperatures increased in most markets, ranging from 0.7 °C in the Netherlands to 3.0 °C in Portugal. However, in Italy and Germany, average temperatures decreased by 1.8 °C and 0.1 °C, respectively.

For the week of October 2, according to AleaSoft Energy Forecasting’s demand forecasts, electricity demand is expected to continue to increase in most European markets analyzed, except France, Germany and Italy.

European electricity markets

During the week of September 25, prices in almost all European electricity markets analyzed by AleaSoft Energy Forecasting increased compared to the previous week. While in the week of September 18, daily prices were often below €100/MWh, on several days in the week of September 25, daily prices exceeded this amount and even €120/MWh in some markets, resulting in higher weekly averages in most of the analyzed markets, in many cases above €100/MWh. The exception was the IPEX market of Italy, where the price fell slightly, by 1.7%.

On the other hand, the highest percentage price increase, 46%, was reached in the Nord Pool market of the Nordic countries. Although daily prices remained below €10/MWh, they increased compared to the previous week, when a negative daily price was registered.

In the remaining markets, prices increased between 11% in the MIBEL market of Portugal and the N2EX market of the United Kingdom and 35% in the EPEX SPOT market of Belgium and France.

In the fourth week of September, weekly averages were above €90/MWh in most of the European electricity markets analyzed. The exception was the Nordic market, where the lowest average price, €3.82/MWh, was reached. On the other hand, the highest weekly average, €116.21/MWh, was reached in the Italian market. In the rest of the analyzed markets, prices ranged from €91.68/MWh in the British market to €113.67/MWh in the Portuguese market.

In the Nordic market, negative hourly prices were registered on September 25, 26 and 30 and October 1. In the British market, negative prices were registered on September 25 and 28. The lowest hourly price in this market, ‑£19.78/MWh, was reached on Thursday, September 28, between 5:00 and 6:00. This was the lowest price in this market since July 16. In addition, negative prices were registered in the German, Belgian, French and Dutch markets on Sunday, October 1.

However, in the fourth week of September, hourly prices above €200/MWh were also reached in several markets. On Monday, September 25, this amount was exceeded for two hours in the Belgian market. In the German and Dutch markets, in addition to the 25^th, prices above €200/MWh were registered on September 26, 27 and 28. The highest price, €379.59/MWh, was registered on Monday, September 25, from 19:00 to 20:00 in Germany and the Netherlands.

During the week of September 25, the increase in the average gas price, the rise in electricity demand in most markets and the general decline in wind energy production led to higher prices in the European electricity markets.

AleaSoft Energy Forecasting’s price forecasts indicate that in the first week of October prices in most European electricity markets analyzed might decrease, influenced by increased wind energy production in some markets.

Brent, fuels and CO₂

Brent oil futures for the Front‑Month in the ICE market registered their weekly minimum settlement price, $93.29/bbl, on Monday, September 25. This price was 1.2% lower than the previous Monday, but $0.02/bbl higher than the previous Friday. Increases continued until reaching the weekly maximum settlement price, $96.55/bbl, on September 27. This price was 3.2% higher than the previous Wednesday and the highest since November 7, 2022. Subsequently, prices declined slightly but remained above $95/bbl. The settlement price on Friday, September 29, was $95.31/bbl, 2.2% higher than the previous Friday.

In the fourth week of September, production cuts by Saudi Arabia and Russia, along with data on declining US crude stockpiles, pushed settlement prices of Brent crude oil futures higher to $96.55/bbl on September 27. However, concerns about economic evolution led to slight price declines in the last sessions of the week. Data released on Saturday, September 30, on the evolution of the Chinese economy might support price increases in the first days of October. The increase in demand associated with aviation due to increased travel during the holiday period in China might also exert an upward influence on prices.

As for TTF gas futures in the ICE market for the Front‑Month, on Monday, September 25, they reached the weekly maximum settlement price, of 44.44 €/MWh. This price was 29% higher than the previous Monday and the highest since early April. In contrast, the weekly minimum settlement price, €39.30/MWh, was registered on September 27. Despite the decline, this price was still 5.4% higher than on the previous Wednesday. In the last sessions of the week, prices increased again. As a result, on Friday, September 29, the settlement price was €41.86/MWh, 5.2% higher than the previous Friday.

In the fourth week of September, expectations of higher demand due to the approaching winter and the decline in renewable energy production led to the highest price in recent months on Monday. However, high levels of European stocks and the prospect of mild temperatures and higher supply levels allowed lower prices to be registered subsequently.

As for CO₂ emission rights futures in the EEX market for the reference contract of December 2023, the weekly maximum settlement price, €85.27/t, was reached on Monday, September 25. This price was 5.5% higher than on the previous Monday. However, this price was already slightly lower than the previous Friday’s price, €85.48/t. Price declines were registered in most sessions of the fourth week of September. As a result, the weekly minimum settlement price, €81.67/t, was registered on Friday, September 29, and it was 4.5% lower than the previous Friday.

AleaSoft Energy Forecasting’s analysis on the prospects for energy markets in Europe and the financing and valuation of renewable energy projects.

The perennial top three countries – China, the United States, and India – continue to account for some two-thirds of global utility scale solar generation capacity. Look beyond those simple totals, however, and you find some impressive relative results by many of those countries in the remaining one-third.

From Wiki-Solar’s comprehensive database of more than 22,000 utility scale solar projects around the world, it is possible to derive a wide range of comparators, including site performance ratios, average yield, and land utilization. This article looks at national achievements and rates of progress.

Solar contribution

Firstly, we have assessed the nominal annual output of the large solar capacity in each country and compared it with national electricity consumption. On that basis, five countries now meet more than 10% of their electric power demand from utility scale solar. Most of these figures would be significantly higher if rooftop and other small scale solar arrays were factored in.

Chile tops the list, thanks in part to its exceptional yield from so many high-altitude desert sites. El Salvador and Jordan feature strongly, with solar contributing substantially to their more modest electricity demand. Spain carries the banner for Europe while Australia has progressed strongly after a slow start.

The UAE owes much of its elevated position to a single huge project, the Mohammed Bin Rashid Al Maktoum Solar Park in Dubai. India may be only number three, in terms of total generation capacity, but leads the United States and China in relative terms, with 8.6% of its electricity from utility scale solar, and 13.2% from overall solar capacity.

An extended list which shows most of the countries with significant utility scale solar capacity is available on the Wiki-Solar website. There you will find Germany, with 3.2% of its electricity demand met by big solar, a few places above China, which sits at number 29, with 2.6%

Leading contenders

The rate of progress is another key indicator. We have evaluated this by looking at the change over the five-year period from 2017 to last year.

For comparison, we have extended this rate forward until utility scale solar would meet 100% of electricity demand. This is, of course, a theoretical exercise. No nation would, in practice, generate all of its power this way and neither the growth of solar nor the trend in electricity consumption will continue as a straight line. The results of the exercise are, nonetheless, illuminating.

Chile again tops the list and would need just 25 years to achieve that notional 100% utility scale solar coverage. Spain has seen outstanding renewed growth in recent years, taking it to number two on this list, with El Salvador and Jordan not far behind. In theory, the top ten countries for solar progress would all reach 100% solar, from utility-scale alone, before the end of the century.

Again, the full list is available online and features a strong European contingent – Portugal, Greece, the Netherlands and Denmark – just outside the top ten. Some countries where recent progress in utility scale solar has been slow would need several centuries to reach 100%, by this measure.

The large solar power stations we are considering here are not, of course, for individuals or households. Another measure of comparative achievement is relative solar generation capacity per person.

Inevitably this is quite similar to the first table above but this time the UAE and Australia leapfrog Chile. The United States has a much higher ranking in this table because its power consumption per capita – from all generation sources – is substantially higher than most other nations. Again, the full table is available online.

The land question

Wiki-Solar has accurate site footprints for the majority of utility scale plants, enabling us to assess the land area typically used for big solar sites in different parts of the world. When this number is related to the land area of each country, it is no surprise to find that land usage is seldom an issue.

The most that any country currently devotes to utility scale solar is just over one tenth of 1%. Only two, relatively small and energy intensive countries – Taiwan and South Korea – would need to allocate more than 3% of their land for PV, even to achieve the theoretical 100% solar paradigm.

The full list shows the United States down among the countries that would need to devote around 0.5% of total surface area for 100% solar. The use of building-mounted systems and the growth of agrivoltaics, of course, means that the land allocated can also be productive for other purposes.

Disclaimer

The expression “nominal output” refers to the design or expected annual output of solar power stations. Actual output in practice will vary with solar radiation and other climatic and site factors, such as grid constraints.

The 100% solar paradigm is used for illustrative and comparative purposes. A 100% renewables scenario featuring wind, hydro, and biomass alongside solar is more realistic.

National power consumption figures are mainly taken from French data company Enerdata and the International Energy Agency; population data is mainly taken from the United Nations. Utility scale solar figures come from the Wiki-Solar database. For consistency, generation capacity is quoted in MW/TW (AC) to enable direct comparison between PV and concentrating solar power plants and other forms of generation.

On October 14, North and South America are set to experience an annular eclipse.

Some states could lose up to 17% of their daily solar energy production, according to data collected by Solcast, a DNV company, via the Solcast API. The path of the eclipse tracks across the southwestern United States, from Oregon to Texas, before continuing through Mexico, Central America and ending in Brazil, though impacts will be seen across all of the contiguous US and the top of South America.

This eclipse is an annular eclipse, meaning that the moon will not appear big enough to completely block the sun, as it does in a total eclipse. This means irradiance will not drop to 0%, and the sky will not darken completely. As the ‘eye’ of the eclipse passes over an area, the total clearsky irradiance will drop to 9.5% of normal clearsky levels. The total duration of the eclipse effect will be 3 hours in some locations, though the peak will only last for seconds.

This image shows the total loss in clearsky irradiance across the day, where blue represents the areas that will see the greatest losses on October 14th.

At the time of writing, the eclipse is 14 days away, which is too far for accurate cloud predictions. However, it is possible to calculate the maximum irradiance losses, i.e. the impact in the absence of clouds.

As can be seen in this image the path of the eclipse peak impact will hit Oregon first, at 0920 local time, before passing over Northern California, Nevada, Utah, Arizona, New Mexico and reaching Texas at 1150 local time. Texas will be hit hardest by the eclipse. The event occurs in the middle of the day when solar energy production is at its peak. As a result, some areas in Texas will experience losses of up to
17% in solar energy production.

The eclipse could significantly impact power grids like CAISO and ERCOT in the U.S. According to data from the U.S. Energy Information Administration, the most affected states had 40.756 GW of operational large-scale solar assets as of August 2023. This includes 13.046 GW in Texas, and represents a significant proportion of the 80.368 GW total nameplate capacity of large scale Solar PV in the US.

The total difference can be seen in the above comparison, contrasting total daily irradiance with and without the effects of the eclipse. The largest net impacts are over Texas, the Gulf of Mexico, Central America and Columbia. Whilst Texas will suffer losses up to 17%, the peak loss will reach 20% in Central America.

In South America, the eclipse will make its way in the afternoon and evening. It will track over the Yucatan Peninsula and Central America before reaching Colombia and finally ending in western Brazil at 1620 local time. As the eclipse will pass at or near the middle of the day, when irradiance peaks, losses will be greatest from Texas to Columbia, and proportional daily losses will be lower in Oregon at the start of their day, and Brazil at the end of theirs.

Solcast will continue to track the impacts of the eclipse, including calculating solar impacts once accurate cloud forecasting is possible.

Solcast produces these figures by tracking clouds and aerosols at 1-2km resolution globally, using satellite data and proprietary AI/ML algorithms. This data is used to drive irradiance models, enabling Solcast to calculate irradiance at high resolution, with typical bias of less than 2%, and also cloud-tracking forecasts. This data is used by more than 300 companies managing over 150GW of solar assets globally.

At the 40th edition of the EU PVSEC conference, which took place in Lisbon last week, the mood was upbeat within the PV community. And why shouldn’t it be? As Nancy Haegel from NREL pointed out in her closing presentation, 2022 marked the first time in history that, on a global scale, solar power accounted for more than 50% of the net expansion of electricity capacity. In terms of global electricity generation, solar still only contributed 4% last year while fossil fuels stood for more than 66%. By 2035 wind and solar together could account for roughly 50% of the global electricity generation, if all countries finally realize the enormous social, environmental and economic gains that a rapid transition to renewables would entail.

Which brings us to the hottest topic discussed on the exhibition floor and during the coffee breaks in between the presentations: which countries outside of China will benefit from the massive growth in demand for photovoltaic hardware?

Manufacturing support

Both India and the US have already implemented ambitious support schemes to ensure that there will be a renaissance of solar manufacturing in their respective countries. First successes from these policies can already be observed this year, with local champions like Tata, Reliance and First Solar significantly increasing their domestic production capacities.

Europe has also formulated the ambitious goal that it wants to re-establish the entire crystalline photovoltaic value chain on its continent, with the aim that roughly 40% of the European PV demand can be supplied by domestic manufacturers going forward.

Yet until now the corresponding supportive measures have not been put into place to match these ambitions. This is why Europe thus far has had to settle for the more symbolic victories in this respect: this year’s Becquerel Prize was awarded to Gunter Erfurt, the CEO of Meyer Burger for his engagement in re-establishing advanced manufacturing of silicon solar cells and modules in Europe. Erfurt was bestowed the award at the opening ceremony of EU PVSEC.

Meyer Burger manufactures heterojunction solar cells and modules built on their own equipment in factories in Germany. Driven by the lure of a generous support mechanism available in the US, namely the Inflation Reduction Act (IRA), Meyer Burger has halted all of its European capacity expansion plans and now fully concentrates on establishing a 2 GW cell and module factory in the US instead.

In the run up to EU PVSEC in Lisbon, prices for crystalline PV modules have seen a pronounced drop in key markets, fueling the fear that the European PV industry, which was just beginning to re-establish itself might get crushed as a collateral victim of the infight between the leading Chinese PV manufacturers. The latter have aggressively expanded their production capacities over the past 18 months which has resulted in an increasingly pronounced oversupply situation. The extent of module oversupply became truly apparent in May of this year.

Module prices

On average module prices have declined by more than €0.06/Wp in just three months, with the effect that a number of European manufacturers had to scale back their production as it became increasingly difficult to bridge the rising price gap between modules manufactured in China and those assembled in Europe.

Both Solar Power Europe as well as the European Solar Manufacturing Council (ESMC) have turned to the European Commission asking for immediate relief actions in order to avoid another wave of bankruptcies, which they fear for their members, should prices continue to remain at levels between €0.15/Wp and €0.17/Wp – as have been observed in the market lately.

The biggest threat the current price deterioration causes is the consequence that it will be virtually impossible to attract any equity funding for the numerous hopeful European plans to re-establish the photovoltaic value chain. If the impression persists that the photovoltaic industry, namely the leading Chinese manufacturers, are again willing to sacrifice margins over market share and expand their capacities at a faster rate than is met by the rising demand.

This would equate to a fatal blow to all European dreams to re-establish the photovoltaic industry domestically. Every day of the week in Lisbon there were panel discussions and how this worst case scenario could still be avoided. One fraction of the industry voiced the conviction that without protective measures that would directly or indirectly reserve a certain market volume for European manufacturers they would stand no chance to survive. By contrast a second fraction suggested that convincing the leading Chinese manufacturers to establish joint venture PV production facilities in Europe could avoid trade disputes with China and ensure that the benefits of the incredible growth and success story of photovoltaics is more evenly spread around the world.

When it comes to its own ecosystem, the EU PVSEC event was able to demonstrate that it is possible to have an even split between different stakeholder groups even if they do not have equal starting conditions. As an example, both of the poster awards as well as the awards for the oral presentations by students – the so called student awards – were evenly split between the genders, despite female authors accounting for less than a quarter of the abstract submissions.

The strength of attendance at EU PVSEC 2023 was also encouraging. More than 1850 scientists and researchers from more than 60 countries had gathered in Lisbon. There were more than 1050 oral and visual presentations, discussing the latest findings in cell technology, module reliability and renewable policies around the globe.

In 2024 EU PVSEC will be held in Vienna, Austria from September 23 through 27.

Götz Fischbeck is a consultant and contributor to the pv magazine global editorial team.

Solar wafer prices declined this week. This is the first time this quarter that wafer prices have decreased across the board.

The price of Mono M10 wafers dropped by 7.79% to $0.379 per piece (pc), while the price of Mono G12 wafers fell by 5.43% to $0.505/pc when compared to the previous week.

Wafer prices have decreased earlier than anticipated, multiple industry sources claimed. The increase in wafer output has outpaced demand to an excessive degree, which is the primary reason that has pushed wafer prices downwards, they concurred.

After the two leading wafer producers, Longi and TCL Zhonghuan dropped their list pricing for Mono M10 wafers to CNY3.1/pc in succession on September 25 and 26, an influential Tier-2 specialized wafer manufacturer reportedly offered Mono M10 wafers for CNY3.05/pc, according to a source.

This source stated that the market price will probably approach the price of this producer, adding that “this manufacturer has a certain market pricing power due to the expansion of production capacity; its newly expanded 40 GW wafer production capacity is currently being installed with manufacturing equipment on site.”

For another source, wafer inventory levels right now are still under control. However, because wafer prices are declining, wafer producers are concerned that, as they create more wafers, future wafer price declines may cause them to lose more money, the source said.

“However, this loss seems inevitable given that cell manufacturers have curtailed their wafer orders out of concern that wafer prices would continue to fall. Wafer stockpiles would build up as a result,” the source continued.

Looking ahead, the degree of the drop in wafer pricing may largely depend on the manufacturing strategies of cell makers and their enthusiasm for buying wafers, a source stated.

OPIS, a Dow Jones company, provides energy prices, news, data, and analysis on gasoline, diesel, jet fuel, LPG/NGL, coal, metals, and chemicals, as well as renewable fuels and environmental commodities. It acquired pricing data assets from Singapore Solar Exchange in 2022 and now publishes the OPIS APAC Solar Weekly Report.

Solar photovoltaic, thermoelectric energy production and wind energy production

In the week of September 18, solar energy production decreased in almost all analyzed markets compared to the previous week. The German market registered the largest decrease of 22%. Other markets where solar energy production decreased included France, down 2.0%, and Italy, down 18%. The exception to this trend was the Iberian Peninsula, where production increased by 12% week‑on‑week. In addition, on Sunday, September 24, the Spanish market reached the highest solar thermoelectric energy production since the beginning of September with 22 GWh, and on Wednesday, September 20, the second highest photovoltaic energy production in the same period with 126 GWh. The Portuguese market also generated 13.8 GWh of photovoltaic energy on September 23, the highest value since the end of August.

For the week of September 25, according to AleaSoft Energy Forecasting’s solar energy production forecasts, an increase is expected in all analyzed markets.

As for wind energy production, in the week of September 18, a week‑on‑week increase was registered in most of the markets analyzed at AleaSoft Energy Forecasting. The largest increase, 295%, was registered in the Italian market, followed by 210% in the German market. The smallest increase, 28%, was registered in the Spanish market. The exception was the Portuguese market with a fall in wind energy production of 38%.

In the third week of September, daily wind energy production reached levels not seen since spring or summer in several markets. In Spain, for example, 290 GWh was generated on September 21, the highest value since May of this year. In the German market, 653 GWh was generated on September 19, the highest wind energy production in this market since the second week of August. One day later, on September 20, 191 GWh was generated in the French market, a level not reached since August 6.

For the week of September 25, AleaSoft Energy Forecasting’s wind energy production forecasts indicate that it will decrease in all analyzed markets.

Electricity demand

In the week of September 18, electricity demand decreased in all analyzed markets compared to the previous week. The largest decrease of 9.2% was registered in the Dutch market, followed by the Spanish market with a decrease of 5.1%. The smallest decrease was registered in Germany, with a decline of 0.3%. In the other analyzed markets, the decline in demand ranged from 1.8% in Belgium to 4.2% in Portugal.

During the same period, average temperatures decreased in all analyzed markets compared to the previous week. The smallest decrease was registered in Italy with 0.3 ºC. In the rest of the analyzed markets, average temperatures decreased from 1.5 ºC in Portugal to 3.4 ºC in France.

According to AleaSoft Energy Forecasting’s demand forecasts, for the week of September 25, electricity demand is expected to continue to decline in most of the European markets analyzed, with the exception of France and the Iberian Peninsula.

European electricity markets

In the week of September 18, prices in all European electricity markets analyzed at AleaSoft Energy Forecasting fell compared to the previous week. The largest drop, 87%, was reached in the Nord Pool market of the Nordic countries, while the smallest decline, 1.5%, was registered in the MIBEL market of Portugal. Elsewhere, prices fell between 4.2% of the Spanish market and 31% of the EPEX SPOT market of Germany, Belgium and the Netherlands.

In the third week of September, weekly averages were below €100/MWh in almost all European electricity markets. The exceptions were the Portuguese market and the IPEX market of Italy, which reached €102.26/MWh and €118.27/MWh, respectively. On the other hand, the Nordic market had the lowest average price at €2.62/MWh. In the rest of the markets analyzed, prices ranged from €68.42/MWh in the French market to €99.43/MWh in the Spanish market.

Negative hourly prices were registered on September 19, 20 and 24 in the German, Belgian, French and Dutch markets. In the Nordic market, in addition to these days, negative hourly prices were reached on September 21, 25 and 26. Likewise, on the 19^th, the Nord Pool market price was below zero, averaging ‑€0.60/MWh. In the case of the British market, negative hourly prices were registered on September 19, 20 and 25. The lowest hourly price of ‑€5.74/MWh was reached in the German market on September 19, from 14:00 to 15:00. This price was the lowest since the first half of August in this market.

On the other hand, in the Spanish market, on Sunday, September 24, from 12:00 to 16:00, the price was €0/MWh. In the Italian market, that day, from 13:00 to 15:00, a price of €10.00/MWh was registered, the lowest since May.

During the week of September 18, despite the increase in the average price of gas and CO₂ emission rights, the general decline in electricity demand and the significant increase in wind energy production in most of the analyzed markets led to the fall in European electricity market prices.

AleaSoft Energy Forecasting’s price forecasts indicate that in the fourth week of September European electricity market prices might increase, influenced by the decrease in wind energy production, as well as by increases in demand in some markets.

Brent, fuels and CO₂

In the third week of September, settlement prices of Brent oil futures for the Front‑Month in the ICE market remained above $93/bbl. The weekly minimum settlement price, $93.27/bbl, was registered on Friday, September 22 and it was 0.7% lower than the previous Friday. On the other hand, the weekly maximum settlement price, $94.43/bbl, was reached on Monday, September 18. This price was 4.2% higher than the previous Monday and the highest since the first half of November 2022.

In the third week of September, production cuts in Saudi Arabia and Russia led Brent oil futures settlement prices to reach values above $93/bbl. However, concerns about the evolution of the economy and expectations of high-interest rates for a longer period of time exerted their downward influence on prices, contributing to their decline during the week.

As for TTF gas futures in the ICE market for the Front‑Month, on Monday, September 18, they registered a settlement price of €34.47/MWh, 3.8% lower than the previous Monday. But, starting on Tuesday, September 19, prices began to increase. This growing trend continued on Monday, September 25, when a settlement price of €44.44/MWh was reached. This price was 29% higher than that of Monday, September 18, and the highest since the beginning of April.

In the third week of September, the proximity of the coldest months led to an increase in TTF gas futures prices, despite the high levels of European reserves. The alterations in the gas flow from Norway, which will be extended to the month of October, also exerted an upward influence on prices. Meanwhile, the labor conflict at Australian liquefied natural gas export plants continues.

The weekly minimum settlement price for CO₂ emission rights futures in the EEX market, for the reference contract of December 2023, on Monday, September 18, was registered at €80.84/t. This price was 1.0% lower than the previous Monday and the lowest since early June. However, during the rest of the sessions of the third week of September, prices increased. As a consequence, the weekly maximum settlement price of €85.48/t was reached on Friday, September 22 and it was 3.9% higher than the previous Friday.

AleaSoft Energy Forecasting’s analysis on the prospects for energy markets in Europe and the financing and valuation of renewable energy projects

The next webinar in the monthly webinar series of AleaSoft Energy Forecasting and AleaGreen will be held on Thursday, October 19. Speakers from Deloitte will participate in the webinar for the fourth time. In addition to the prospects for European energy markets for the winter of 2023‑2024, the financing of renewable energy projects and the importance of forecasting in audits and portfolio valuation will be analyzed.

In 2012, as a board member of the Association of Alternative Fuel and Energy Market Participants of Ukraine, I took part in a meeting of renewables companies with the leadership of energy regulator the National Commission for State Regulation of Energy and Utilities. The main topic was the development of home solar in Ukraine.

The regulator was not receptive. Our decentralization arguments were met with skepticism, to put it mildly, by representatives of the old Soviet centralized power generation system. One of the commission members said the idea home solar could be a useful market segment was delusional, therefore there was no point developing it.

Exactly 10 years later, home solar arrays became almost the only source of energy for Ukrainians left without electricity due to the centralized energy infrastructure destroyed by Russian missiles and bombs.

As the world becomes increasingly reliant on technology and digital systems, the need for secure and reliable energy becomes ever more pressing. While traditional, fossil fuel-based systems have long been the mainstay of global energy, growing awareness of their negative environmental impact, the finite nature of such resources, and the rising potential for geopolitical conflict has prompted a renewed focus on decentralized, renewable energy systems.

Obvious targets

Ukraine has become a vivid example of how the centralization and monopolization of an energy system can lead to tragic political, environmental, and economic consequences. The nation's chronic dependence on Russian energy sources, in particular, oil, gas, and nuclear fuel, created the prerequisites for almost 100% Russian control over the Ukrainian economy. A similar situation has developed in many European countries.

After more than a decade of advocating for the decentralization of Ukraine's energy system, I was pleased to see president Volodymyr Zelensky declare the such an aim will be a state priority. It is essential that governments and private sector actors prioritize the development and deployment of decentralized renewable energy systems in order to ensure a secure and sustainable energy future. Action must not be blocked by fossil fuel energy lobbyists or short-sighted thinking. In Ukraine, for example, the development of decentralized renewable energy systems has been held up for over a decade by various energy lobbies, including the Russian nuclear industry. As a result, only 70,000 households have been able to benefit from the security and resilience of decentralized systems, rather than the millions that could have done so.

Warnings

Energy dependence has created very dangerous conditions for military aggression. In 2014, my consultancy and cleantech thinktank the Innovative Business Centre (IB Centre), together with former German Green Party MP Hans-Josef Fell, organized the EuroSEF 2014 event in Brussels. The energy security forum saw industry experts and members of the European Parliament discuss the new energy configuration of Europe in the context of dependence on Russia. Unfortunately, not everyone understood the scale of the threat then.

The leadership of Russia, the largest supplier of energy carriers to the countries of the European Union, expected that during its invasion of Ukraine, Europe would pretend the war did not concern them and would instead choose economic stability based on Russian gas, oil, and nuclear fuel. We cannot say all European countries passed this test.

What is the solution in such a situation? Diversification of energy supply and decentralization. Furthermore, decentralization also holds paramount strategic significance.

A centralized system is an easy target for cruise missiles. In the case of Ukraine last year, the Russian military purposely destroyed the country's energy system by bombing transformers, leading to widespread blackouts. Ukrainian households and companies that had installed autonomous renewable energy systems, such as solar panels and biofuel heating and electricity systems, were able to continue to have access to electricity and heating, demonstrating the inherent resilience and security of decentralized systems.

In 2011, the IB Centre started a pilot project within the framework of the Ukrainian Association of Renewable Energy. We decided to lobby for the opening up of the solar energy market to households.

The renewable energy association was the first such body in the Ukrainian cleantech industry, which at that time united more than 75% of players in the clean energy market. We communicated the aims of our project through the resources of the IB Centre, which at that time managed the leading new energy industry information platform, had its own news agency, and produced industry publications from the cleantech sector.

We immediately found ourselves at the epicenter of lively discussion, which mainly centered on the fact that representatives of legacy energy systems were inventing reasons why individuals could not become solar energy generators. Those disputes continued until 2015, when the Ukrainian parliament finally adopted amendments to a law enabling a green tariff for individuals – homeowners.

Trigger for change

The war in Ukraine became the trigger for radical change in the European energy paradigm. Today, most of the countries of Central Europe and Eastern Europe quickly adopt legislative changes aimed at the development of decentralization of energy, in particular solar energy, without too much delay and prevarication.

A great example of a rapid pivot to green, decentralized energy is Romania. In July, the country’s Ministry of Energy announced a finance program for solar arrays on social infrastructure facilities that is worth more than €500 million ($535 million). At the beginning of this month, the Ministry of Agrarian Policy of Romania announced the launch of a finance package for solar panels for farmers worth almost €1 billion. A little earlier, Romania had already announced an intent to install 160,000 solar roofs in the next two years.

That is why we have chosen Bucharest as the venue for CISOLAR 2023, the 11th Solar Energy Conference and Trade Show of Central and Eastern Europe, which will take place in the Romanian capital on Oct. 30-31. We want to write a new page of energy transformation in the region and demonstrate that even the most centralized systems in Europe can be transformed into green, decentralized ones with the help of solar energy. After all, there are simply no other options for the evolution of our energy systems.

About the author: Julia Daviy-Berezovska is co-founder of US-based organizations the IB Centre and the Sustainable Innovations Council. She has received worldwide recognition as a pioneer in technology for sustainability and a leading advocate for the progression of clean technology in developing economies. Julia was instrumental in liberalizing Ukraine's solar energy sector for independent organizations and private households.