Indian consumers have been deploying behind-the-meter generation (predominantly diesel backup, and, more recently, photovoltaic) and storage systems (predominantly lead-acid and other kinds of batteries as uninterrupted power supplies) by the millions for decades (Jaiswal et al. 2017; Seetharam et al. 2013; IFC 2019). These storage systems are used by consumers to address reliability issues within the Indian power system, and their deployment is driven by consumer preference rather than any specific government program or policy. However, the same energy storage systems could provide additional services to the consumer and distribution companies if properly regulated and designed from the outset to be grid interactive. Grid-connected distributed solar PV (DPV), or rooftop solar, has also seen wide deployment in India and features prominently in the Government of India’s plans for a transition to clean, reliable, and affordable energy for all. At the same time, many utilities and state governments, as well as the central government in India are currently funding-constrained for both operational and future capital expenditures in the power sector, and some perceive customer-sited resources as exacerbating existing financial challenges.
In that context, behind-the-meter energy storage systems paired with distributed photovoltaic (DPV)— with the capability to act as both generation and load—represent a potentially unique and disruptive power sector technology capable of providing a range of important services to customers, utilities, and the broader power system in India. Globally, jurisdictions with high penetration of DPV have seen faster uptake of behind-the-meter energy storage systems, such as in California and Hawaii (GTM and Energy Storage Association 2019). India, with more than 4 GW of installed rooftop solar, is primed for the uptake of behind-the-meter energy storage, as consumer economics become more attractive with the fast- falling cost of energy storage systems. A proper framework to coordinate the deployment and operation of these distributed systems can balance stakeholder benefits from their presence on the grid. Without appropriate regulations or technical requirements, however, these systems could potentially 1) cause safety concerns for the utility; 2) exacerbate utility revenue losses; or 3) limit the ability for stakeholders to achieve certain policy goals. This report aims to offer a comprehensive, evidence-based approach to designing customer programs based on experience in the United States that can help regulators, utilities, and policymakers in India manage the range of challenges and opportunities that increased behind-the- meter energy storage deployment will bring to the power system, in particular when these systems are paired with DPV.
This report has been prepared by the National Renewable Energy Laboratory (NREL) with support from the U.S. Agency for International Development (USAID) for discussion purposes with a broad range of stakeholders. These include Indian regulatory agencies (such as the Forum of Regulators, the Central Electricity Regulatory Commission, and various State Electricity Regulatory Commissions), policy makers, utilities, and developers to inform a broader dialogue around the future direction of Indian states’ approach to regulating and facilitating DPV-plus-storage systems. Importantly, this report is intended to offer key regulatory considerations for facilitating DPV-plus-storage programs for retail customers. As the role of regulators is often to convene and balance the interests of a broad range of stakeholders, including policymakers, utilities and customers, this report focuses on their role in the development of behind-the-meter DPV-plus-storage programs. Throughout the report, relevant cases from U.S. states are provided as examples of how novel regulatory issues related to behind-the-meter energy storage systems paired with distributed photovoltaic are being addressed in practice.
“In God we trust, all others must bring data.” – American Statistician W. Edwards Deming Rarely does a single investment yield both significant social and financial benefit. In this way, solar is unique: this rapidly growing asset class offers the promise of substantial returns on investment in both.
While the financial community is—rightfully—focused on newly emergent risks of this asset class, such as managing the merchant tail and basis risk, it’s important that the financial community remains vigilant on the question of solar production risk.
Over the past few years, it’s become in vogue for financial investors and pundits alike to publicly dismiss the possibility of a solar power plant underperforming, with remarks like, “The sun will always shine,” and “Panels always work because they have no moving parts.” Success breeds complacency, and complacency breeds failure.
We are among the industry’s leading experts on the measurement and management of solar production risk, cumulatively representing hundreds of years of experience in our respective fields. Each of us are risk specialists with in-depth data on a specific element of solar production risk.
Rather than publishing “yet another” opinion, we are committed to letting the data speak for itself. Designed intentionally for a non-technical financial community, this report will be refreshed every year to provide investors with the latest insights on the evolution of solar generation risk.
Fundamentally, it is our hope that this report will serve as a guide for investors who recognize the importance of allowing data-based insights to inform the deployment of capital.
We look forward to the shared work of advancing our solar industry.
kWh Analytics: The “1-in-100 Years” Worst Case Scenario? It Occurs More than 1-in-20 Years
DNV GL: Narrowing the Performance Gap: Reconciling Predicted and Actual Energy Production
PV Evolution Labs: Over 5% of Commercial PV Modules Fail IEC Testing
Borrego Solar: Thoughtful Inverter Procurement Can Prevent 25% of Lost Revenue: Inverter Warranty Management
Clean Power Research: Understanding Irradiance Value in Solar Project Bankability: How to Sniff Out Irradiance Shoppers
Heliolytics: Recoverable Degradation: How to avoid 0.1%/yr Losses Clean Energy Associates: Aggregate Factory Report Shows High Levelsof Major (35.5%) and Critical (1.3%) Findings Among Suppliers
Strata Solar: Force Majeure & Energy Modeling: 1 Hurricane, 81 PV Plants Down
Wood Mackenzie Power & Renewables: Solar O&M Pricing has Dropped ~60% with More to Come
SunPower: Incomplete EPC Punch-listing Results in 1.2% Performance Loss in Year 1 Operations
Solar assets are underperforming far more frequently than official energy estimates would suggest, validating an industry-wide bias towards overly optimistic pricing, according to the industry experts who contributed to KwH Analytics’ 2020 solar risk assessment report. “From a business standpoint, this means that smart investors need to take a step back and adjust to reality,” Richard Matsui, CEO and founder of kWh Analytics said.
“P90 downside events occur so often that they have nearly become P50,” kWh Analytics said in this year’s Solar Risk Assessment report. By definition, P90 events should occur once every 10 years, but they are now at least three times more frequent because of the unreliable energy estimates that have been baked into projections.
The situation is fueled, in part, by the fact that it is a seller’s market; buyers need to be competitive to get the best solar assets.
“Many projects perform up to the rosy expectations but, on average, projects are underperforming their financial expectations,” Jackson Moore, head of DNV GL’s solar section said, noting that the data-driven insights in the report make this clear. “We want data to be as accurate as possible, so it can support a sustainable solar industry,” Dana Olson, global solar segment leader at DNV GL added. Accuracy means avoiding a correction, he added, noting that the solar industry’s optimistic projections problem will not be solved without transparent insight into the sources of underperformance being experienced in the field today.
According to Matsui, the structural setup that underpins the aggressive solar production predictions bias exacerbates the situation. Like the big three credit rating agencies pre-financial crisis, the independent engineers that are hired by solar developers to give solar production estimates have an inherent profit motive for giving an aggressive projection, Matsui explained. “It’s a way to gain market share,” he said.
The data is hard to dispute, however. The report noted that for commercial scale solar projects optimistic irradiance assumptions contributed to a 5% underperformance on a weather-adjusted basis and that “weather-adjustment bias” is responsible for up to 8% bias in measured underperformance.
The report goes on to highlight O&M cost variation issues, disappointing inverter performance and the increasing frequency of diode and string anomalies after the first year.
Abstract: In this work, the impact of component reliability on large scale photovoltaic (PV) systems’ performance is demonstrated. The analysis is largely based on an extensive field-derived dataset of failure rates of operation ranging from three to five years, derived from different large-scale PV systems. Major system components, such as transformers, are also included, which are shown to have a significant impact on the overall energy lost due to failures. A Fault Tree Analysis (FTA) is used to estimate the impact on reliability and availability for two inverter configurations. A Failure Mode and Effects Analysis (FMEA) is employed to rank failures in different subsystems with regards to occurrence and severity. Estimation of energy losses (EL) is realised based on actual failure probabilities. It is found that the key contributions to reduced energy yield are the extended repair periods of the transformer and the inverter. The very small number of transformer issues (less than 1%) causes disproportionate EL due to the long lead times for a replacement device. Transformer and inverter issues account for about 2/3 of total EL in large scale PV systems (LSPVSs). An optimised monitoring strategy is proposed in order to reduce repair times for the transformer and its contribution to EL.
Solar Under Storm Part II is a response to the overwhelming reception of the original report, which provided best practices for ground-mount solar photovoltaic (PV) projects. It is also a response to stakeholder requests for a rooftop-focused report for the growing commercial and residential solar industry in the Caribbean and other vulnerable geographies with exposure to high-wind events.
High wind speeds increase risk factors for solar projects tremendously, but many solar installation companies inadvertently overlook or incorrectly apply low-wind speed designs (borrowed from Europe or the United States) for projects in high-wind zones like the Caribbean. These low-wind mistakes become catastrophic in high-wind events.
Solar PV failure reporting is needed because some failures are highly visible while others are not, either because they are infrequent in occurrence or because they are privately dealt with and not publicly published. Showcasing a wide range of failures has multiple benefits:It provides proof to designers, installers, and customers that solar PV system resilience matters
Ramifications for product and project design, vendor selection, installation, and maintenance become real because they are tangibly connected to real- world failures
It helps solar professionals learn from past mistakes, which is critical as repeating mistakes damages the reputation and credibility of the solar industryLike the first version, this report provides an opportunity to address resilience for both a general and technical audience.
The report disseminates technical information to non-technical readers and creates a more informed solar professional, regulator, government official, utility, and customer. A well-informed customer base will systematically strengthen the PV industry by requiring vendors to incorporate resilience guidelines into their projects.
In an industry that has experienced drastic cost reductions year after year, in the “race-to-the- bottom” aspect of project and product design, it is critical for customers to understand best practices and not accept low-cost shortcuts that could jeopardize project life or energy production. Supplying the customer with a minimum set of guidelines raises the bar, and those guidelines can only be improved through innovation and definitive testing, which in turn creates a stronger industry.
The purpose of this document is to respond to the growing needs of the solar industry and combine field observations, photographic evidence, and expert analysis to provide actionable recommendations aimed at increasing the resilience of current and future rooftop PV systems. This report will touch upon flat- roof and pitched-roof PV power systems containing flat-mounted, tilt-mounted, fully ballasted, and hybrid ballasted/penetrating systems. It excludes canopy PV systems and ground-mounted systems (both fixed and tracking) as the recommendations for rooftop projects are specific to their application. Canopy and tracking systems may be addressed in future versions of the report if interest persists. Ground-mounted systems were addressed in the original Solar Under Storm report, which is still available from Rocky Mountain
This report is organized into five sections:
1. Introduction 2. Root cause identification methodology and findings 3. Failure mode and effects analysis (FMEA) 4. Technical discussion 5. Conclusion
The intended audience for Sections 2, 3, 4, and the Appendix is engineering professionals responsible for PV system design, PV system specifications, and/ or PV system construction oversight and approval. Sections 1 and 5 are intended for a more general audience of customers, governments, utilities, regulators, developers, and PV system installers who are interested in improving PV system survivability to intense wind-loading events.
Solar Under Storm Part II was developed with direct feedback from solar companies in the Caribbean that learned lessons in solar project resilience firsthand during and after Hurricanes Irma, Maria, and Dorian. Continuous feedback from the solar installer community is vital to the success for solar PV resilience. Thus, RMI and the Clinton Foundation’s Clinton Climate Initiative will host workshops and other opportunity for on-going communication on this topic—notably through the forum of the Clinton Global Initiative (CGI) Action Network on Post-Disaster Recovery.
This is not just because of the accelerated development and introduction of new modules that drive the LCOE (levelised cost of electricity) down but because well-known and proven reliability testing sequences still catch out products that fail to meet the required degradation rates of less than 2% to become a recognised ‘Top Performer’.
Granted, PVEL’s testing sequence criteria has evolved over the years, primarily to increase cycle-times that further pushed the ability of modules to meet the Top Performer requirements as part of the lessons learnt during the evolution in module reliability testing.
A good example of this would be the PVEL Damp Heat (DH) test, where it has become well known that under the IEC 61215 electrical safety test, a DH duration of only 1,000 hours is required, which led to relatively few modules experiencing electrical safety issues regardless of the Bill of Materials (BOM) used meeting IEC test conditions.
However, PVEL doubles the number of cycles to 2,000, which has proven to uncover a number of degradation issues that reduce module performance well past the 2% PVEL degradation rule. As such the DH test remains a benchmark for module reliability as the number of BOM variations continue to increase in the pursuit of lower LCOE metrics.
Importantly, in the 2020 report, PVEL has also added a boron-oxygen (BO) stabilisation step to the tough damp heat testing regime as the test’s high temperature and no current environment can also lead to destabilisation of the passivated BO complexes within some PERC cells, according to PVEL. To further explore this problem, PVEL added a post-DH2000 boron-oxygen stabilisation process to its PQP (Product Qualification Program) sequence.
The more recent introduction of Potential Induced Degradation (PID) testing is another development in line with the mass introduction of Passivated Emitter Rear Cell (PERC) technology that can suffer this type of performance degradation, undermining the performance benefits of the cell technology and therefore the claimed lower LCOE.
Although PVEL is also introducing a Light and Elevated Temperature Induced Degradation (LeTID) test, this was only announced in mid-2019 and so more time is required for this new test to be introduced, primarily for mono-PERC cells. As a result, the LeTID susceptibility test highlighting Top Performers did not appear in the current report. This was also true for the new backsheet durability sequence.
In keeping with previous analysis of PVEL’s report we will first look at the four historical reliability tests and the developments noted in the latest report.
In PVEL’s thermal cycling test sequence, modules are placed in an environmental chamber where the temperature is lowered to -40°C, dwelled, then increased to 85°C and dwelled again. Maximum power current is applied to the modules while the temperature is increased and decreased.
A total of 600 cycles, repeated 200 times over three periods is said to equate to about 84 days in the climate chamber. However, PVEL previously ran the TC test with 600 cycles but had increased this to 800 cycles in recent years. DNV GL had noted in the PV Tech-hosted TechTalk webinar and in the report that the lowered number of cycles was due to its analysis that the TC600 test was actually a sufficient test duration with few reliability excursions being meaningful or could introduce non-representative failure mechanisms when undertaking the extended test. It should be noted that IEC 61215 testing requires only 200 cycles, which has proven insufficient.
PVEL had previously noted that thermal cycling performance improved 42% in the 2019 scorecard, even though it used TC800 sequence.
In the 2020 report, PVEL noted strong results from a host of wafer, cell and module varieties such as standard and half-cut cell module types, as well as thin film, shingled cells, multi-bus bar and heterojunction (HJT) modules.
There were nine PV module manufacturers that achieved Top Performer status in the thermal cycling tests in 2019, compared to 17 manufacturers in the 2020 TC tests.
It should be noted that both glass-glass and glass-backsheet bifacial modules achieved Top Performer status in the 2020 TC tests and that a total of 54 different modules were recognised as Top Performers. In 2019 the number of Top Performer modules was 24.
There were nine PV module manufacturers that achieved Top Performer status in the thermal cycling tests in 2019, compared to 17 manufacturers in the 2020 TC tests. Image: PV Tech
In PVEL’s damp heat tests, PV modules are placed in an environmental chamber and held at a constant temperature of 85°C and 85% relative humidity for 2,000 hours (about 84 days in total). The heat and moisture ingress stress the layers of the PV module. In comparison, IEC testing has a duration of only 1,000 hours.
There were six Top Performers in the 2019 damp heat tests, compared to 13 in the 2020 scorecard, a significant increase from previous years.
PVEL noted that this was mainly due to newer bifacial glass-glass and glass-backsheet module BOM shifting from EVA to POE in glass-glass modules, having performed poorly in previous DH tests. A significant number of tested modules in 2018 and 2019 had exhibited greater than 4% degradation, according to previous PVEL reports.
As a result, the number of different modules achieving Top Performer status also increased to 32 in the 2020 scorecard, compared to 16 in the 2019 report.
There were six Top Performers in the 2019 damp heat tests, compared to 13 in the 2020 scorecard. Image: PV Tech
Dynamic mechanical load
In the DML testing, PVEL installs a module according to the manufacturers’ recommended mounting configuration, then subjected to 1,000 cycles of alternating loading at 1,000 Pa. The module is then placed in an environmental chamber and subjected to 50 thermal cycles (-40°C to 85°C) to cause microcrack propagation, then three sets of 10 humidity freeze cycles (85°C temperature and 85% relative humidity for 20 hours followed by a rapid decrease to -40°C) is used to stimulate potential corrosion.
The modules are then characterized and inspected visually to evaluate the status of the module’s frame, edge seal and cell interconnections. The dynamic mechanical loading can induce microcracks that do not necessarily result in significant power loss, according to PVEL, yet only after thermal cycling and humidity freeze testing that metal conductors affected by cell cracks can break, which leads to black inactive areas and increased power degradation.
DML testing sequence had been tweaked in the 2019 Scorecard to include 30 humidity freeze cycles. About 80% of the historical test data included only 10 humidity freeze cycles, according to PVEL.
As a result, the percentage of dynamic mechanical load sequence Top performers fell by 37% in the 2019 results, versus historical results, according to PVEL. There had been nine PV module manufacturers that had achieved Top Performer status in the 2019 DML tests.
However, in the 2020 scorecard that number declined to eight, proving the DML test is proving much more difficult to achieve year-on-year. PVEL put this down to several reasons, including BO destabilisation in PERC cells because of the damp heat conditions during humidity freeze testing.
PVEL also noted that module performance was susceptibility to power loss caused by cell cracking and rapid temperature changes, as part of the new mechanical stress sequence (MSS). PVEL plans to release a separate publication featuring MSS results in the coming months. PVEL also reported that both glass-glass and glass-backsheet bifacial modules had shown similar performance results following the DML sequence.
A total of 16 different modules had achieved DML Top Performer status in the 2019 scorecard, compared to 19 in the 2020 report.
A total of 16 different modules had achieved DML Top Performer status in the 2019 scorecard, compared to 19 in the 2020 report. Image: PV Tech
PVEL’s PID test is carried out in an environmental chamber with voltage bias equal to the maximum system voltage (MSV) rating of the module (-1000 V or -1500V) being applied under 85°C and 85% relative humidity for two cycles of 96 hours. These temperature, moisture, and voltage bias conditions allow PVEL to evaluate degradation related to increased leakage currents.
Results from the 2019 Scorecard showed 15 PV module manufacturers have PID under control, which was lower than the 20 companies achieving Top Performer status in the 2018 test report.
The number of PID Top Performers in the 2020 report stood at 20 out of 22 companies reported to have been in the tests that received at least one Top Performer award from the four historical reliability testing regimes. .
Importantly, a total of 47 different modules achieved Top Performer status in the PID tests in 2020 scorecard, compared to 34 different modules in the 2019 report.
A total of 47 different modules achieved Top Performer status in the PID tests in 2020 scorecard, compared to 34 different modules in the 2019 report. Image: PV Tech
However, PVEL noted in the latest report that the median PID degradation results had been higher than at any time in its ten years of testing.
In reference to PID testing of bifacial modules, PVEL noted that there was both a wide range of front-side and rear-side cell degradation, with bias towards higher degradation on the rear side cell. In one case, PVEL reported power loss of over 30%.
Some of the rear side degradation was said to be due to a reversible polarization effect that could occur in bifacial modules during PID testing, but not all p-type bifacial modules suffered this issue.
New to the Top Performer rankings test is PAN files. This is analysis PVEL has used in its PQP work but is the first time included in benchmarking module energy yields with PVsyst software.
The procedure is to have three identical PV modules tested across a matrix of operating conditions per IEC 61853-1, ranging in irradiance from 100 W/m2 to 1100 W/m2 and ranging in temperature from 15°C to 75°C. Two 1MW PV plant site simulations are undertaken with one site in a temperate climate at a 0° tilt (in Boston, USA), and a 1 MW site in a desert climate at 20° tilt (in Las Vegas, USA). A custom PAN file is then created with PVsyst’s modelling software that enable PVEL to measure the highest kWh/kWp energy generation based on PVEL’s measurements such as temperature losses and low-light conditions.
PVEL noted that its historical PAN file data from all PQPs since 2016, meant that only 4% of modules tested would receive a 2020 Scorecard Top Performer designation.
There are a lot of moving parts in this testing, not least in relation to bifacial modules. The lack of real world data on operating bifacial plus tracker PV power plants has challenged PVsyst modelling accuracy, especially in low-light conditions, according to presentations at the last BiFi workshop in Amsterdam, in September 2019.
PVEL noted that that bifacial modules showed a step-function performance improvement as two thirds of the Top Performers were bifacial modules. The exclusion of inverter clipping at the simulated PV power plant in Las Vegas led to mono-bifacial modules generating 7.7% higher median output higher than monofacial modules. At the simulated horizontal tilt site in Boston the median bifacial energy yield was 3.3% higher than the monofacial median.
Other differentiated yield performances simulated included a heterojunction module, which obviously offered high temperature performance gains, due to having some of the lowest temperature coefficients.
It should be noted that the data presented below is only from PVEL’s PAN testing as part of a PQP where the samples are factory witnessed.
As a result, there were seven 7 PV module manufacturers that achieved Top Performer recognition in the first PAN file test, which included 10 different modules.
7 PV module manufacturers that achieved Top Performer recognition in the first PAN file test, which included 10 different modules. Image: PV Tech
PVEL’s 2020 Top Performers
We should make it clear that in compiling PVEL’s 2020 Top Performer rankings analysis from the historical four key module reliability testing regimes, PVEL has reiterated that not all PV module manufacturers undertaking the scorecard are required to make public the testing results.
Also, it is important to clarify that several PV module manufacturers that achieved Top Performer ratings in some categories, were listed in the 2020 report, yet PVEL had not completed full tests on some of these manufacturer’s modules at the time of the reports publication, which could include some manufacturer’s modules only achieving a few Top Performer rankings but when full testing is completed could have achieved more higher Top Performer rankings.
The chart below is a compilation of the 22 PV module manufacturers that successfully achieved Top Performer status for any number of modules tested in any of the historical module reliability testing regimes in the 2020 Module Reliability Scorecard that have been made public but may also have not completed all test when PVEL published the report.
Basically, this chart is just the total number of Top Performer rankings a company achieved in the 2020 scorecard, regardless of the number of modules entered the testing by any given module manufacturer.
This chart is just the total number of Top Performer rankings a company achieved in the 2020 scorecard, regardless of the number of modules entered the testing by any given module manufacturer. Image: PV Tech
However, the table below also ranks manufacturers by the total number of Top Performer awards, but also breaks out the number of different modules tested from these manufacturers that contributed to each manufacturers total.
Top Performers including the number of PV modules tested. Image: PV Tech
We can note that the first two manufacturers listed, Astroenergy and LONGi Solar achieved the highest number of Top Performer awards with a contrasting number of modules tested.
However, further down the rankings PV manufacturers Top Performer awards coupled to the number of different modules receiving awards is more uniform. This indicates that some companies are outperforming others from the perspective of having achieved Top Performer status in all four historic testing regimes, sometimes for just one module but also for several different modules.
One example of a PV manufacturer achieving Top Performer status in all four historic testing regimes with only one module is REC Group. An example of a PV manufacturer achieving Top Performer status in all four historic testing regimes with more than one module is Silfab.
Although this is hard to detect in the above combined table, breaking out all the PV manufacturers that achieved Top Performer status in all four historic testing regimes, regardless of the number of different modules tested provides the elite group (see table below) of Top Performers from the 2020 scorecard.
There were four manufacturers that achieved this position in the 2020 Scorecard. One more than last year. Image: PV Tech
As noted previously, REC Group is represented in this elite group with its monocrystalline PERC-cell based ‘TWIN PEAKS 2’ module, in case people are not that familiar with their module part numbering system.
LONGi Solar’s HiMO 1 module, which is a mono PERC based module, is also listed as it achieved Top Performer status in all four historic testing regimes.
North American based PV manufacturer, Silfab punched well above its manufacturing weight (capacity) with two mono PERC-based modules achieving Top Performer status in all four historic testing regimes.
Finally, we have China-based Astronergy that had four modules out of six different product offerings receive Top Performer status in all four historic testing regimes. These elite Top Performer modules include Astronergy’s Astro Twins half-cut mono PERC, half module designed product offering.
The company was also amongst the few manufacturers to achieve Top Performer status in the new PAN file performance analysis. As such, Astronergy has set the bar very high for next year.
Indeed, PVEL indicated that in the 2020 scorecard testing, several tests, notably DML may have been the toughest test to achieve Top Performer status but there were a number of PV manufacturers modules that were very close to the 2% deviation rule. Therefore, the number of manufacturers with a clean sweep of the historical testing regimes could have been much higher than in previous years.
That said, the 2021 scorecard should include the planned new testing categories and so in many respects will be a new class of Top Performers from that point onwards.
The PV Module Reliability Scorecard, now in its 6th edition, ranks commercially available PV modules by their performance in PV Evolution Labs’ Product Qualification Program (PQP), a comprehensive, rigorous test regime that assesses reliability and performance of PV modules. The 2020 rankings will be released on live webinars.
Tristan Erion-Lorico, head of PV module business at PV Evolution Labs (PVEL), will share this year’s top-performing PV modules and discuss key findings from PVEL’s PQP testing, with a special focus on the performance of bifacial PV modules. He will be joined by Dr. Dana Olson, global solar segment leader at DNV GL. Dr. Olson will offer an analysis of trends in PV module quality and discuss how PVEL’s test data is used by DNV GL as part of a module useful life analysis. Mark Osborne of PV Tech will also join the webinar to cover his top highlights from the 2020 Scorecard as compared to the previous editions.
To register for the free to attend ‘PV Tech TechTalk’ webinar, entitled “Top-Performing PV Modules: The 2020 PV Module Reliability Scorecard”, click here.
Webinar timings – local time zones
Webinar 2 – San Francisco (UTC -7): 5/28 at 09:00 New York (UTC -4): 5/28 at 12:00 London (UTC +1): 5/28 at 17:00 Munich (UTC +2): 5/28 at 18:00 Singapore (UTC+8): 5/28 at 24:00
The 2020 Off-Grid Solar Market Trends is an in-depth analysis on current market dynamics, projections for the coming five years, and a blueprint for how actors in this market can compete in a swiftly evolving industry ecosystem. This year’s edition finds that the industry has made tremendous strides in the past decade in helping developing countries reach their energy access goals, accelerating the global Sustainable Development goal (SDG) 7. To date, more than 180 million off-grid solar units have been sold worldwide and the sector saw $1.5 billion in investments since 2012. The report estimates that the off-grid solar sector currently provides lighting and other energy services to 420 million people.
Click below to download the full report and summary.
The 2017 hurricane season was one of the most active in history.1 Hurricanes Harvey, Irma, and Maria brought widespread destruction throughout the Caribbean. In addition to the emotional toll these severe storms had on people in the region, the disruption of critical infrastructure left many communities without such basic services as electricity for prolonged periods of time.
Over the past decades, electricity in the Caribbean has been primarily generated centrally by fuel oil or diesel-fired engines and distributed across the island by overhead lines. However, in recent years, electricity has been supplemented in homes, businesses, industries, government facilities, and utilities by solar photovoltaics (PV). In fact, over half of Caribbean electric utilities already own or operate solar PV as part of their generation mix. Over 225 MW of solar is installed across rooftops, parking canopies, and large tracts of land. Solar PV is the most rapidly growing source of power for many Caribbean islands.2
Renewable energy in India has taken centre stage when it comes to the significant development of energy infrastructure required to achieve India’s economic goals.
In 2016, the Indian government set a target of 175 gigawatts (GW) of renewable energy by financial year (FY) 2021/22 and 275GW by FY2026/27 to transform the power sector from an expensive, unreliable, and polluting fossil fuels-based system into a low-cost, reliable, and low-emission system. In February 2019, the Central Electricity Authority increased the target to 450GW of renewable energy by 2030’.1
So far, India’s electricity sector transition has had a promising start, assisted by lower costs for solar and wind energy generation equipment, cheaper financing, and a favourable policy environment.
In March 2020, India’s on-grid renewable energy capacity stood at 87GW. Of the 30GW of renewable energy capacity installed since the beginning of FY2017/18, coupled with an additional 50GW awarded to date, more than 90% has been contracted at tariffs ranging between Rs2.43-2.80/kilowatt hour (kWh) (~US$35- 40/MWh) with zero indexation for 25 years. This is 60% to70% less than the first- year tariff set for proposed new non-mine mouth coal-fired power plants in India.
As much as the scale and execution of a large-scale solar park exemplifies India’s technological ingenuity to mobilise capital at scale and at the least cost, it must be acknowledged that it comes with its own set of negative externalities.
Solar parks are land-intensive, and they pose a resource availability challenge for a densely populated country. However, we note the total land required for solar parks is equivalent to the total land required for coal-fired power plants and associated coal mines.
The government should carefully study all options before making plans for new solar parks in future. Wastelands, low-utility non-agricultural land, or reclaimed coal mines should ideally be used for large-scale solar projects.
The Indian solar construction industry is highly dependent on low-skilled interstate migrant labour and informal employment most of the time. The government could progressively look to execute industry-specific labour reforms for the renewable
26 Mercom India. Gujarat Invites Bids for 950 MW of Projects to be Developed Across Two of its Solar Parks. 25 June 2019. 27 Mercom India, Gujarat Reissues 700 MW from its 1 GW Solar Tender for Dholera Solar Park, 18 March 2020. 28 ET EnergyWorld, NTPC plans 5,000MW ultra-mega solar plant in Kucth worth Rs20,000 crore investment, 20 August 2019. 29 ET EnergyWorld, Gujarat leads India in approved capacity of solar parks, 7 August 2018.
India Is Home to the World’s Largest Utility-Scale Solar Installations 12
energy industry to reap long-term benefits from the growth industry of the decade.
Large-scale solar parks are not as easy to operate as decentralised solar systems for grid operators. Large-scale input of power from utility-scale generators is harder for grid stability management from the perspective of the grid operator as it must deal with large voltage and frequency fluctuations because of the intermittent nature of renewables. India’s rooftop solar market has been slower to reach scale in the Indian market, but is finding its feet with more than 5GW of total installed capacity to date.
India has actively looked into various solution to expand its decentralised solar capacity. There have been gigawatt-scale planning and some small installations of floating solar. In addition, government-owned buildings such as offices, hospitals and education facilities are being used to accommodate rooftop solar projects.
India has been growing its grid capacity roughly in step with new generation capacity. India’s grid network successfully managed reduction and consequent increase of 31GW demand within a period of 9 minutes during the recent ‘lights off’ event on 5th April 2020.30 31 This demonstration of grid management supports the argument that with the right planning and additional investment in firming capacity, India’s robust national electricity grid could be further developed to handle large- scale renewable integration.
It is worth looking back over the last four years to see just how far the Indian renewable energy industry has advanced. Indian utility-scale solar parks have been effective in kickstarting India’s energy sector transition. The ultra-mega solar parks have attracted foreign capital as well as top global developers to India, and in return have provided investors with an opportunity to join a US$500-700bn renewable energy and grid infrastructure investment boom in the coming decade.
India’s power industry and the government should make good use of the coronavirus lockdown period to resolve long-standing problems and to be fully prepared for a green infrastructure investment stimulus as India comes out of this pandemic. India should rightly take pride in being able to execute world-leading renewable energy projects and continue to work to resolve short-term policy impediments to achieving its long-term renewable energy aspirations.
The government must also address development-related negative social and economic externalities. It must avoid the mistakes made in the past with large-scale coal mine and thermal power plant development, particularly in terms of development on key agricultural lands and critical forestry reserves.