by Ishaan Goel

The second article in this series on water electrolyzers focused on polymer electrolyte membrane electrolyzers (PEMEs). PEMEs have increasingly captured the interest of industry over recent years, due to favorable technical characteristics. Despite this, the global electrolyzer market today is dominated by a much older model – alkaline electrolyzers (ALKEs). (For details of how both electrolyzers work, refer to the first article in the series).

The graph above shows the investment costs ($/kW) of ALKEs and PEMEs as the technology has advanced over time. In other words, they show the initial capital cost for every 1 kW of electrolyzer capacity. The bubble size represents the total operational lifetime in hours of the technology, which is an indicator of its durability. The costs are mostly for ‘stacks’ – bundles of electrolyzers with higher capacity – rather than individual units. This article will discuss the figures for ALKEs.

Advantages of ALKEs

One reason behind the wider commercialization of ALKEs even today is their edge in pricing. As seen in the graph, ALKEs cost lower than PEMEs on average by almost 20-50% as per data collected. This is largely because ALKEs require cheaper materials and processes in their construction. PEMEs rely on costly precious metals like iridium, platinum and titanium as catalysts and electrodes, and it is expensive to assemble these components as well as the central electrolyte. 

ALKEs also possess other beneficial qualities over PEMEs. They are mature technologies that have already been through multiple phases of optimization and cost reduction, while PEMEs still contend with fundamental developmental problems. Integral components of ALKEs like the electrodes and electrolytes can be effectively made with abundant materials such as nickel, stainless steel or potassium hydroxide. This not only makes ALKEs cheaper, but also enables them to avoid future supply bottlenecks that potentially await PEMEs. Their durability far surpasses PEMEs too, as is evident from the graph, and they are also more resilient to impurities. 

Breaking down ALKE prices

Like with PEMEs, the costs of ALKE systems can be divided in two – the cost of the stack, and the Balance of Plant (BOP) which is the cost of all auxiliary systems and components. As per a report by the International Renewable Energy Agency (IRENA), for an average 1 MW stack, the stack costs are 45% and the BOP is 55% of the total system cost.

Manufacturing the electrodes and central electrolyzer membrane (diaphragm) constitutes ~42% of stack costs, or about a fifth of the overall system cost. While the materials for these components are relatively cheap, their construction often employs expensive methods. State-of-the-art Raney Nickel electrodes, or polybenzimidazole (PBI) membranes for the diaphragm, require complex processes to manufacture which reflects in the final ALKE price. This is noticeably different from PEMEs, where costly metals were the biggest component of stack costs. 

Within BOP, power costs occupy the largest share at about 50% (or ~28% of system costs). Similar to PEMEs, the electricity supplied to the electrolyzer heavily influences not only the system cost, but also the final price of the hydrogen produced. Consequently, system prices for ALKEs can differ greatly depending on region. Other influencers of BOP include inbuilt water circulation systems (22%) and hydrogen processing such as compression and drying (20%).

Researching for better designs, performance

Current research on ALKEs mainly concentrates on electrode and diaphragm design, since the same electrode chemistries have been utilized amongst commercial variants for decades. Redesigning these components may help cut manufacturing costs, while also making systems more compact. The IRENA report envisioned emulating innovations in PEMEs, such as combining electrodes, diaphragms and other layers. 

Some other focus areas include increasing current density and reducing resistance within the cell, and increasing the active surface area of the catalyst. ALKEs do not respond as well to power supply fluctuations as PEMEs, and commercial Raney Nickel catalysts lose effectiveness under such intermittent operating conditions. This is an advantage of PEMEs as it makes them more compatible with variable renewable energy (RE), so research is on to bring ALKEs up to par.  

The need for scaling up

Increased scales of production can bring vital economic gains for ALKEs, by helping slash manufacturing and BOP costs substantially. A study by the National Renewable Energy Laboratory (NREL) in 2014 estimated the effects of increasing the annual production of 1 MW ALKE modules. Going from 10 to 1000 units per year saw the cost of Raney Nickel electrodes fall by 50-80%, PBI membranes by 50% and overall stack costs by nearly 60%. A 1000, 1 MW units translate into 1 GW of electrolyzer capacity produced a year – an achievable goal with Nel Hydrogen (D7G.F, NLLSF, NLLSY) and McPhy (MCPHY.PA) already announcing ALKE ‘gigafactories’ in Norway and France respectively.

Larger stack ‘sizes’ (capacities) can also cause price reductions. As per the previously mentioned IRENA report, increasing individual stack sizes from 1 MW to about 10-15 MW can bring down investment costs by nearly 45%. For reference, the largest ALKEs commercially available today are about 20 MW. Investment costs level off roughly beyond the 15 MW point, implying that focusing on even larger stacks than now might be futile. Instead, modular designs might be favorable, wherein larger capacities are achieved by stringing together smaller units.

Challenges in durability

With regards to durability, ALKEs have system lifetimes of about 60000-100000 hours as per data collected. On average, this is about 30000 hours – or 10-15 years – greater than PEME lifetimes. This significant gap is due to the absence of several factors that damage PEME components, such as acidic internal environments, high current densities and the formation of corrosive gases. ALKEs also undergo their own deprecatory processes over time – dissolution of the catalysts, mechanical degradation and the creation of nickel impurities. 

Certain changes that increase the efficiency or decrease the costs of ALKEs can end up reducing their durability, such as thinning the diaphragm or high-pressure operation. This is an important trade-off – technical innovation can both add and subtract from their operational lifetime. ALKE durability could witness slow growth or even reduce, shrinking their lead over PEMEs on this metric. 

The way forward 

The multinational advisory body Hydrogen Council has estimated that hydrogen prices would have to reach about $0.5-2/kg to compete with fossil fuels. For this to feasibly occur, investment costs for electrolyzers would have to reach well under $200/kW. ALKEs already have a head-start in the journey towards this goal, and deserve the attention of industry and policy-makers. 

For ALKEs to retain their dominant position in the electrolyzer market, their path forward should be twofold – increased production to slash prices of core components, and technical advancements focused on achieving parity with emerging technologies. ALKE manufacturers must strive towards minimizing internal electrical resistance, increasing power-supply responsiveness and current densities, and engineering compact designs. This will allow them to rival the efficiency and renewable compatibility of newer electrolyzers like PEMEs and solid oxide electrolytic cells (SOECs). However, ALKEs must also carefully navigate the trade-off between these improvements and system lifetime, to hold on to their durability advantage. 

As with PEMEs, government assistance may help in the immediate term to ensure that electrolyzer supply and demand experience parallel growth. For instance, firms producing and deploying ALKEs could receive subsidies or other incentives. Investments could be made into direct application areas like refueling stations for hydrogen automobiles, supporting infrastructure like distribution pipelines or complementary industries like fuel cells. Appropriate legislation to ensure that industries like fertilizers or steel transition to green hydrogen could induce overall sectoral growth in electrolyzers. 

Conclusion

Since the cost of hydrogen produced by ALKEs is also highly dependent on power prices, low-cost renewable electricity is imperative to achieve hydrogen pricing targets. This is especially important for hydrogen-intensive industries, so that electrolyzers become competitive sources for their raw materials. This will occur as the adoption of renewables grows and technologies like photovoltaic cells become cheaper. More renewables can also potentially directly create more electrolyzer demand for supply-smoothening or energy-storage.

In the short-term, with adequate support, price and durability advantages may carry ALKEs forward. But their long-term survival relies on shedding archaic technologies and producing lower-cost, higher-performance variants in much larger quantities.  

*****

Ishaan Goel is a high school senior from Mumbai, India and an incoming freshman at the University of Chicago. He likes applied mathematics and statistics, especially in relation to economics and finance. He is very interested in green energy and sustainable technologies, because of their potential and increasing relevance for the future. Ishaan’s hobbies include writing, long-distance running, playing the keyboard and coding. 

The post Alkaline Electrolyzers – The Future needs a Metamorphosis appeared first on Alternative Energy Stocks.

by Ishaan Goel

The first article in this series introduced two prominent types of water electrolyzers – alkaline electrolyzers (ALKEs) and polymer electrolyte membrane electrolyzers (PEMEs). Electrolyzers are devices that convert water into hydrogen and oxygen using electricity. They enable energy storage through hydrogen when combined with fuel cells, and can decarbonize hydrogen production for industry if supplied with renewable power. Subsequent articles shall focus on various characteristics of these two electrolyzer variants.

The graph above shows the investment costs ($/kW) of PEMEs and ALKEs as the technology has advanced over time. In other words, they show the initial capital cost for every 1 kW of electrolyzer capacity. The bubble size represents the total operational lifetime in hours of the technology, which is an indicator of its durability. The costs are mostly for ‘stacks’ – bundles of electrolyzers with higher capacity – rather than individual units. This article will discuss the figures for PEMEs.

Advantages of PEMEs

PEMEs have important technological advantages over ALKEs – they are compact, can tolerate higher current densities. They respond faster to changes in power supply which makes them more suitable for fluctuating power sources like solar and wind energy. However, they are yet to be as extensively commercialized, for which their cost is a major reason. As seen in the graph, PEMEs have higher average costs than ALKEs with limited reductions over recent years. 

High Costs

Specialized materials and processes required within PEME stacks contribute greatly to their price. For instance, to withstand the highly acidic internal conditions, platinum and iridium are used as catalysts. Not only are the prices of these metals both expensive and volatile, but their rarity also creates bottlenecks in the expansion of PEMEs. High-priced materials themselves are about 30-40% of total stack costs, with other costs of assembly, such as coating titanium electrodes with platinum or creating the central solid electrolyte, accounting for the balance. 

However, stacks are only one component of the investment costs, the other being Balance of Plant (BOP) – the cost of all auxiliary systems and components. Power prices are the most influential factor in this category, with their share of overall BOP costs exceeding 50% for larger stacks above 1 MW capacity. Other expensive systems include those for gas processing – separating, drying and pressurizing hydrogen – and for the circulation of water and cooling. The BOP itself can range from 40-70% of electrolyzer costs, depending on system size.

Research into PEMEs is focused on developing catalysts and other components that use less costly materials. Compounds of chemically suitable and naturally abundant metals, such as nickel, cobalt and manganese are being investigated for this purpose. Catalysts must also be made more effective to increase the capacity of stacks while keeping prices constant.  

The Benefits of Scale

Beyond technical improvements, increasing the scale of production is critical to slash electrolyzer costs. This would allow suppliers of several BOP components to leverage economies of scale with higher demands. Firms would invest in shifting from manual to automated assembly processes. The lowest cost figures for PEMEs in the graph (around the $750/kW range) are projections assuming annual electrolyzer production capacities in the gigawatts. Estimates suggest that reaching 1 GW/year production of stacks with capacities between 0.2-1 MW could reduce investment costs to $300-400/kW. Such scales may not be far off – ITM Power (ITM.L, ITMPF) has already completed a factory for PEMEs with capacity ~1 GW/year, and models with capacities ~5 MW are in operation today.  

With regards to durability, PEMEs lag well behind ALKEs. They exhibit operational lifetimes of about 30000-60000 hours, about half of their alkaline counterparts. This is due to various factors – unwanted reactions, formation of corrosive gases and high-temperature and high-pressure operating conditions. While PEMEs have the advantage of lower operating and maintenance costs, they will also have to be replaced more frequently due to shorter lifetimes. Resolving this issue is a technical matter, and would require catalysts effective at lower temperatures and materials more resistant to corrosion. 

The multinational advisory body Hydrogen Council has estimated that hydrogen prices would have to reach about $0.5-2/kg to compete with fossil fuels. For this to feasibly occur, investment costs for electrolyzers would have to reach well under $200/kW.

PEMEs can achieve this milestone, but the journey will take time. Innovation must target the crucial challenge of eliminating the need for precious metals and boosting efficiency. Most low-cost alternatives to conventional PEMEs are either theoretical or confined to research laboratories. Firms must now fulfill their electrolyzer production commitments, so that projected cost reductions through scale are realized. 

The Chicken and Egg Problem

Production capacity has to steadily increase year-on-year, but growth may end up with a chicken-and-egg problem. Firms will invest in scaling up only if there is sufficient demand in the market, but demand itself is driven by cheaper electrolyzers. As the European Union Hydrogen Strategy notes, government assistance may therefore be beneficial in the immediate term to evolve supply and demand in parallel. For instance, subsidies could be offered to firms producing and deploying PEMEs, or investments made into direct application areas like refueling stations for hydrogen automobiles. Supporting complementary products, like pipelines for hydrogen distribution or fuel cells, would induce overall sectoral growth and PEME demand.

Conclusion

Given the high dependence of the cost of hydrogen produced by PEMEs on power prices, low-cost renewable electricity is imperative to achieve desired hydrogen costs. This is particularly important in industries where hydrogen is a raw material – if electrolyzers are to become the preferred means of obtaining this hydrogen, then renewable electricity costs must fall significantly. This will come about as the adoption of renewables grows, and production technologies like photovoltaic cells become cheaper. More renewables have the added benefit of potentially inducing more electrolyzer demand for supply-smoothening or energy-storage.

All the above changes will only take shape gradually. In the near future, the PEME market will be shaped by governmental action, in terms of assistance offered to producers and the broader growth trajectory of renewables and other energy-storage technologies. However, major technical breakthroughs that reduce costs may drive strong PEME growth across all their applications. 

*****

Ishaan Goel is a high school senior from Mumbai, India and an incoming freshman at the University of Chicago. He likes applied mathematics and statistics, especially in relation to economics and finance. He is very interested in green energy and sustainable technologies, because of their potential and increasing relevance for the future. Ishaan’s hobbies include writing, long-distance running, playing the keyboard and coding. 

The post PEM Electrolyzers – Cracking the Chicken and Egg Problem appeared first on Alternative Energy Stocks.

by Ishaan Goel

Energy is crucial to India’s policy agenda. Millions of households are yet to gain reliable access to electricity, hampering their potential for economic growth. Severe pollution issues create widespread health problems. Renewables are prioritized as viable solutions across the political spectrum, with their low costs and ease of installation in remote regions. The current administration has ambitious plans for renewable energy (RE), targeting an almost 4x increase in installed capacity to 450 GW by 2030 and introducing a spate of tax and investment reforms.

At the heart of the Indian power supply chain lie distribution companies (discoms). The discoms purchase power from power generators, and sell it directly to consumers or businesses. Most discoms are public enterprises owned by the central or individual state governments. They are concentrated in specific regions where they hold monopoly over power supply. 

Discoms have an important role to play in the integration of RE into the grid. However, they are currently ridden with financial and administrative problems. Due to several issues, a large number of them are running large losses and are in severe debt. They are unable to pay power producers, with outstanding payments summing to over $19 billion in November 2020, and numerous government bailouts have failed to alleviate the situation. These problems pose tough barriers against the adoption of RE in India.

SOURCE OF FINANCIAL PROBLEMS

To make power affordable for the masses, governments regularly provide large waivers in electricity tariffs and unpaid electricity bills owed to discoms. This is usually done for certain demographic groups as part of electoral promises, particularly farmers and low-income households. Governments also seek to promote redistributive welfare through the subsidization of agricultural and rural power using higher revenues from industrial and commercial applications. 

All of these provisions are supported by payment guarantees to discoms from state governments, to cover any deficits in revenue. However, governments frequently default from these obligations due to their own financial issues, forcing discoms to operate under loss. Tariffs undergo periodic regulation to ensure that they reflect current costs, but subsidies and other concessions cannot be easily reversed for political and economical reasons.

To make matters worse, a large proportion of discoms are also locked in long-term power purchase agreements with thermal power plants (mostly coal and natural gas). The conditions of these agreements were originally designed to attract private investment into thermal power generation. They usually stipulate that discoms must pay the plant a fixed fee based on its maximum potential output, and a smaller fee for the power actually purchased. 

As a result, discoms tend to have high fixed costs because they pay the same amount to producers regardless of how consumption patterns vary. Base tariff rates are generally set low in India for the benefit of low-income households, and change frequently compared to the terms of the agreements. So, discoms must recover their high, fixed costs from variable and uncertain revenue streams.

Technical losses can also contribute significantly to discom problems. Power theft is a big issue in India, with illicit connections to transmission lines drawing out almost a third of power in some regions. Poor maintenance and tampering of electricity meters and lines, especially in rural areas and small towns, leads to wastage of supplied power too. This reduces the already insufficient revenues of the discoms.

EFFECTS ON RE PROVIDERS

When governments default on payments to discoms, the discoms themselves are unable to pay the electricity providers. This creates a chain of debt across the entire power supply chain, which has particularly pronounced effects for RE providers. 

Tariffs for RE are usually fixed before or during the development of the project, as an assurance to providers to promote investment in the sector. However, such agreements do not provide the same level of protection as the long-term agreements made with thermal power plants. Providers end up operating on thinner margins that are heavily reliant on projected revenues from discoms.

When discoms do not receive their dues, they cannot pay RE providers whose finances are also placed in precarious conditions. Providers are usually given future payment guarantees, but these cannot help sustain them in the short-term. They also find it more difficult to raise funds from other financial institutions due to their increased risk profile. With such uncertainties and barriers to acquiring capital, firms are dis-incentivized or unable to enter the RE sector.

Discom issues also affect the adoption of captive RE – private generation facilities managed by industrial consumers for their own uses. To avoid wastage of excess power produced during peak times, providers usually ‘bank’ it with discoms. This power can be ‘withdrawn’ during off-peak hours to balance out supply. Discoms usually charge sizable fees for banking to add to their revenues, and also require fees for transporting power from production facilities to industries. All of this raises the cost of RE so that any cost benefits over thermal power are negated, which can discourage switching to RE. 

Many governments have established renewable purchase obligations (RPOs) for discoms in their respective states, to promote the integration of RE in the grid. However, adhering to RPOs is cost-inefficient for discoms as they are already paying for capacity from thermal power plants. Discoms also need to spend on upgrading their grid capacity to accept the variable power output of RE. To avoid these issues, many discoms end up curtailing (refusing to accept or pay for) large amounts of electricity from RE generators. This leaves providers with lower revenues than they had planned for when constructing their facilities. This adds yet one more risk to the RE sector. 

SOLUTIONS

Discom issues are major deterrents to the adoption of RE. These could be solved by  improving the health of discoms, or by developing alternative methods of delivering renewable power.

Of the latter, microgrids are promising and have been implemented with some success in remote regions in India. They attract political goodwill because of their ability to boost electrification of households and commerce in underdeveloped regions. Discoms usually face the greatest difficulties in power supply and tariff collection in such regions, so their burden is eased too. 

Private interest in microgrid development is rising. For instance, Tata Power (NSE: TATAPOWER) has partnered with the Rockefeller Foundation to implement 10000 microgrids in India of capacity >2MW by 2026. To promote microgrids, it is important that the government provide greater transparency about grid expansion plans and adequate sources of financing for developers. Awareness also needs to be created amongst target communities to make them more receptive towards the system.

Other alternatives include the promotion of household and community RE projects, particularly in solar energy, which is already underway through numerous government schemes. Captive RE is also gaining ground with several states slashing banking and transmission charges for industrial applications. These measures alone cannot solve discom-related issues, however, as they are mostly applicable in non-urban regions. Larger scale RE projects must be added to the grid and structural issues in discoms must be addressed head-on to boost RE integration in cities and urban industries. 

Governments have introduced several relief packages for discoms in the past, but these have not proven very effective due to the underlying structural issues described above. In its most recent budget, the central government allocated almost $42 billion for reforming electricity distribution over the next 5 years. This will be done through breaking the monopolies of discoms in geographic regions to increase efficiency, and funding rural electrification. The benefits of this cash injections are likely to be transmitted to RE providers.

Smart meters are being pushed forward to reduce transmission and collection-related losses in revenue, with the government hoping to install 250 million. Such meters will allow for better maintenance and monitoring of transmission lines to detect possible power theft. They will also digitize the payment of tariffs to reduce defaults. 

The government is also experimenting with transitioning to real-time markets, where discoms purchase power on energy exchanges just before supplying it, to ensure supply matches demand. This arrangement reduces average input costs for the discoms, and makes the grid more flexible for the integration of RE.

CONCLUSION

To achieve its targets and foster growth in the RE sector, the government needs to ensure that providers receive guaranteed, regular revenues and operate under low risk to invest and expand further. Despite emerging alternatives to RE provision, creating such an environment is only possible if discoms are streamlined and debt-free. Structural and market-based changes will aid in the recovery process, but it is equally important for state governments to honor payment obligations and minimize defaults across the supply chain.

*****

Ishaan Goel is a high school senior from Mumbai, India and an incoming freshman at the University of Chicago. He likes applied mathematics and statistics, especially in relation to economics and finance. He is very interested in green energy and sustainable technologies, because of their potential and increasing relevance for the future. Ishaan’s hobbies include writing, long-distance running, playing the keyboard and coding. 

The post Discom-fort: Barriers to Renewables in India appeared first on Alternative Energy Stocks.

by Ishaan Goel

Hydrogen has become increasingly prominent as a potential carbon-free fuel, for both automobiles and providing electricity to buildings. It has direct applications in decarbonizing important industries like steel, and can serve as a storage medium for extra renewable energy over seasonal durations too.  

Since hydrogen gas does not occur naturally in our atmosphere, its method of production is an essential component of the hydrogen economy. There are several such methods (discussed in detail here), but the one with least emissions involves using renewable power to run electrolyzers – devices that use electricity to convert water into hydrogen and oxygen gas.

This article introduces a series on electrolyzers which will explore the various technologies, the efforts and challenges to improving them, and their prospects for wide-spread adoption.

While there exist several types of electrolyzers, the two primary kinds today are alkaline electrolyzers (ALKE) and polymer electrolyte membrane electrolyzers (PEME). 

ALKALINE ELECTROLYZERS

ALKEs comprise two solid electrodes containing catalysts, immersed in a liquid, alkaline electrolyte. An electric current passes through these electrodes, which splits water at the negative electrode into hydrogen gas and hydroxide (OH–) ions.  The positive electrode attracts the hydroxide ions, which travel to it within the electrolyte. They combine there to form oxygen gas and electrons, which keeps the reaction going. During this process, they pass through a porous membrane (diaphragm) designed to internally segregate the gases. 

PEM ELECTROLYZERS

Instead of liquid electrolytes, PEMEs utilize solid polymer compounds present within a porous, central layer. This layer is surrounded on either side by electrodes with catalysts, followed by meshy gas diffusion layers, and then by bipolar plates. Water (as steam) is introduced through the bipolar plate, and passes through the diffusion layers towards the positive electrode. Here, it splits into oxygen gas and hydrogen (H+) ions. The ions permeate through the central electrolyte towards the negative electrode, where they combine with free electrons to form hydrogen gas that is collected through the other bipolar plate. In both electrolyzer variants, the catalysts hasten the reaction.

ADVANTAGES OF PEMEs 

Each technology comes with its own tradeoffs. PEMEs are advantageous because their production level responds faster to changes in power supply and they can tolerate higher current densities, making them ideal for fluctuating power sources like solar/wind energy. The layered structure and lack of liquid electrolyte allows for compact designs, so they are effective within space constraints. The solid electrolyte enhances ion conductivity, which boosts the overall efficiency. Any electrical energy lost as heat can be redirected into the conversion of water into steam, which reduces wastage and further increases efficiency. 

WEIGHING UP ALKEs

However, PEMEs have higher capital costs than ALKEs. Their conductivity is highly dependent on factors like hydration of the membrane and temperature, and maintaining optimal operational conditions requires extra components. They also need platinum and iridium-based catalysts, which are not only very expensive, but also limit the scalability of PEMEs based on their availability. 

ALKEs usually use cheaper nickel or stainless steel-based catalysts. Further, their durability will also be higher because of less corrosive environments and the replaceability of the electrolyte after extensive usage. ALKEs also tend to exhibit lower internal mixing of gases, so the produced hydrogen has greater purity. However, nickel-based membranes and separators are being developed for PEMEs too, which may possibly bring down the cost differential in the future. 

OTHER ELECTROLYZER TYPES

To blend the best of both technologies, certain firms have come up with anion exchange membrane electrolyzers (AEMEs). These utilize solid membranes similar to PEMEs, but involve the transfer of hydroxide ions instead of hydrogen ions like ALKEs. As a result, the catalyst can be cheaper nickel or stainless steel instead of platinum/iridium while still preserving efficiency and responsiveness benefits. Companies actively engaged in the area include Enapter and Evonik Industries (EVK.DE, EVKIF, EVKIY). Another alternative is ThyssenKrup’s (TKA.DE, TYEKF, TKAMY) “advanced alkaline electrolysis”, that aims to deliver modules with lower maintenance and capital costs. 

DESIGN INNOVATIONS

Electrolyzers are usually sold as modular “stacks”, which consist of multiple units conjoined together to scale up their joint output. For instance, NEL Hydrogen (D7G.F, NLLSF, NLLSY) produces electrolyzer stacks ranging in production capacity from 1.05-3880 nm3/hour, suitable for large-scale centralized production or household/office-level distributed applications. Some firms also design for the produced hydrogen to have pressures suitable for direct use – for example, Giner ELX (a subsidiary of Plug Power (PLUG)) systems yield hydrogen directly in an ideal range of about 435-580 psi. 

CONCLUSION

With growing interest in the adoption of hydrogen, active research continues into improving existing electrolyzer technologies across various parameters. The next articles in this series will focus on the current status of such parameters, including capital costs, for both ALKEs and PEMEs.  

Disclosure: The author has no interests in any firms mentioned. 

***

The post Introduction to Electrolyzer Technologies appeared first on Alternative Energy Stocks.

by Ishaan Goel

INTRODUCTION

In 2020, hydrogen shot to the forefront of the renewable energy conversation, with stakeholders making major investments in its growth. The European Union has allocated nearly EUR 400 billion to hydrogen within its Covid-19 recovery package, to ramp up production capacity ~150 times by 2030. Globally, hydrogen production projects under development have nearly tripled (by capacity) with several firms announcing ambitious gigawatt-scaled ventures.

The appeal of hydrogen stems from its excellent capabilities as both an energy carrier and storage medium. Beyond its extensive usage in high-temperature industrial processes and manufacturing, it shows potential in areas that have proven difficult to decarbonize. These include central heating systems in buildings and fuel for heavy transportation. Hydrogen can also help solve key problems for powering the electric grid with only renewable power, like long term energy storage to smooth seasonal fluctuations in supply and demand. 

Lowering the cost of hydrogen is important to ensure that it becomes competitive with fossil fuels. The Hydrogen Council estimates that prices have to reach $0.5-2/kg, to compete with natural gas and coal. One key component of this cost is how the hydrogen is actually manufactured.   

Hydrogen gas does not occur naturally in our environment, so it must be obtained from other molecules that contain the element. The most common sources are water (H2O) and methane (CH4) in natural gas.

GREEN AND CLEAN

Electrolyzers pass an electric current through water, splitting it into hydrogen and oxygen. The current can in turn be generated from renewable sources, making the entire process carbon-free. The hydrogen thus obtained is called green hydrogen. 

With virtually no emissions, this is the cleanest way of producing hydrogen. However, green hydrogen is yet to become widespread due to its unviable price. Advancements in electrolyzer technology have caused significant reductions in their capital costs in recent years, but they remain quite expensive. 

These costs can be considerably reduced by expanding the production of electrolyzers to achieve economies of scale. According to a report by the International Renewable Energy Agency (IRENA), reaching 1 GW/year of electrolyzer production (by capacity) can decrease the prices of components between 30-85%. On average, overall production costs can reduce by about 18% every time the total capacity of electrolyzers doubles due to competitive innovation by firms.

Such a drastic increase in capacity must be accompanied by a comparable increase in the supply of renewable electricity. One widely proposed method to minimize these power costs is to produce hydrogen using the surplus power when there is a peak in renewable supply (such as during strong winds or sunlight). This surplus cannot be taken into the grid and would have otherwise been wasted, so is available at very low cost for the electrolyzers.

However, these periods of excess only occur a small fraction of the time. While the electrolyzer units installed would be designed with enough capacity to accommodate these large peaks, they would remain unused a majority of the time. A 2015 study in the IEEJ Energy Journal estimates that the average production would only be 8-17% of the maximum potential.

So, the initial capital investment would be distributed over a much smaller amount of hydrogen produced, which would increase the end-cost of hydrogen. Any reductions in capital costs achieved through scale may be dampened for consumers.

This is seen in the left graph in Figure 1 below. Even when average capital costs are reduced almost 75% by scaling to $200/kW, renewable electricity would have to be cheaply available at $20/MWh for at least 5-6 surplus hours per day to be comfortably within the $0.5-2/kg price range.

Electrolyzers could be made to utilize power throughout the day whenever available, including non-surplus hours. This would only partially alleviate the issue of capital underutilization as renewable sources face large daily fluctuations, which may also degrade the electrolyzers over time. 

Battery storage or grid-electricity could be used to stabilize renewable power and supplement off-peak supply, which will ensure that electrolyzers always operate close to their maximum capacity. Both options decrease the capital investment required to produce each unit of hydrogen, but significantly raise the power purchase cost. The end-cost would now depend more on electricity prices, which can be made cheaper through appropriate policies and market structures. Note that this is not desirable for highly carbonized grid-electricity.

This is shown in the right graph of Figure 1. Assuming capital costs are scaled down substantially to $200/kW, electricity prices between $10-20/MWh are needed for green hydrogen to become competitive with conventional hydrogen. For reference, solar power is now available at $20-60/MWh, depending on the country. 

FOSSIL-FUELLED HYDROGEN 

95% of hydrogen is presently produced through a process called ‘steam methane reformation’ (SMR). Methane and steam react to yield carbon monoxide and hydrogen. The carbon monoxide further reacts with steam to produce more hydrogen and carbon dioxide. Instead of pure methane, industrial processes generally use natural gas (~90% methane). This hydrogen is called grey hydrogen.

From a thermodynamic perspective, it is easier to convert natural gas into hydrogen than into a comparable amount of electrical energy. Hydrogen yields about 33.6 kWh of energy per kilogram. The amount of natural gas required to produce 1 kg of hydrogen comes out to be 2-3 times smaller than the amount required to produce 33.6 kWh of energy. 

With the existing infrastructure and scale of the natural gas industry, the average cost of hydrogen from SMR is about $1-3/kg. In comparison, green hydrogen on average costs 3-5 times more at about $4-8/kg (both ranges were estimated from market sources). 

The advantage of SMR over electrolysis is particularly pronounced in end-use applications like steelmaking, which require hydrogen. Renewable power may not be readily available near industries and produces more expensive hydrogen, so SMR provides the cost-effective option.  

When the end-use application is transportation, the requirement to convert the hydrogen back into electricity using expensive and relatively inefficient fuel cells mean that batteries or direct internal combustion of natural gas are more economical than steam reformation in most situations.

THE COSTS OF CARBON CAPTURE

SMR is not inherently carbon-free, but the carbon dioxide produced can be collected and stored. This is called carbon capture & sequestration (CCS), and hydrogen produced through the SMR-CCS combination is termed blue hydrogen. With appropriate carbon-storage techniques, it can be as clean as green hydrogen.

CCS is essential for decarbonization, but it represents an added capital investment for manufacturers and affects the entire supply chain. As shown in Figure 2, depending on region, it can increase the cost of hydrogen by 30-55%, which reduces its relative advantage over green hydrogen.

Being non-essential to the actual production process, CCS must be promoted through uniform regulation like stringent pollution-control requirements. Low-expense CCS techniques will need to be developed if blue hydrogen is to be competitive with fossil fuels.

Current carbon-management options include injection into underground geological formations, storage as minerals and carbonate compounds or enhancing the recovery of oil. All of these methods are currently very costly. Although cost-effective, using CO2 to enhance oil recovery in oil-wells is also counter to the goal of decarbonization. 

BIG OR SMALL, NEAR OR FAR

Beyond the method, the organization of the production facilities for hydrogen is important for economics. There are 2 primary ways in which to organize the production system for hydrogen.

Centralized production involves extremely large facilities that meet hydrogen demands for vast geographical regions. These can leverage economies of scale and efficient methods to considerably decrease production costs. The facilities may be distant from the target location of the hydrogen, and closer to natural gas processing plants or renewable sources to acquire input materials more easily.

The largest electrolysis plant currently operational is in Fukushima, Japan, which uses a 20 MW solar generation facility to power a 10 MW electrolyzer unit. IRENA has classified plants of this scale in the first stage of electrolyzer deployment, with the last stage envisioning units greater than 100 MW each.

Distributed production involves small, localized facilities close to (or at) the target locations. These cannot achieve economies of scale or the same level of efficiency as centralized systems, which limits their ability to cut down production costs. However, their proximity to target locations considerably reduces the cost of transporting hydrogen, and facilitates integrated production-application systems.

This points towards a key-tradeoff between distributed and centralized facilities – that of electricity transmission and hydrogen distribution costs. Moving hydrogen by road from central facilities to target locations can be quite expensive, because of its low energy per unit volume (4 times lesser than gasoline) and extensive safety requirements for the vehicle. Constructing pipeline networks for hydrogen would be very capital-intensive, with each mile costing an estimated $250,000-1,000,000. However, distributed production requires connections of renewable energy to each facility, and transmission rates are highly dependent on the regional regulations and tariff rates.

The choice between distributed and centralized facilities depends on many other factors. Smaller plants would require lesser capital initially to establish, which would allow them to be set up in greater numbers. For instance, distributed facilities could be placed at every refueling station for hydrogen-based automotives. On the other hand, CCS techniques are cheaper when implemented at larger scales, which might inhibit their use in small facilities. 

Large, central facilities can be combined with end-use industries to form ‘hydrogen valleys’, where the entire supply chain of hydrogen – from production to final application – is concentrated in one geographical area. This would reduce input costs for all goods produced in the valley, while also largely eliminating hydrogen distribution costs. Further, CO2 from SMR could be managed by channeling it into industries like methanol, cement and indoor agriculture (greenhouses).

The idea of using existing gas pipelines for hydrogen distribution has gained traction because it eliminates the need for large investments in specialized hydrogen transport infrastructure. It is also an efficient way to prolong the utility and lifetime of natural gas infrastructure. However, there would be costs associated with upgrading steel pipes to make them suitable for hydrogen transport, and for the eventual extraction of hydrogen from the gaseous mixture within. 

CONCLUSION

The choice of green and blue hydrogen is important and often difficult, since both colors have differing prospects and considerations. 

Green hydrogen is cleaner and can double as an energy storage medium during peak hours, which makes it more favorable for integration into the grid. Renewable energy is already among the least expensive sources of energy, and economies of scale will continue to push prices down. Coupled with rapidly increasing investments in electrolyzer manufacture, both capital and variable power costs for green hydrogen are likely to decrease. However, capital underutilization will remain an issue unless the demand for hydrogen is built up greatly to justify higher capacity electrolyzers, and/or stabilization measures (like short-term storage) are integrated into the power supply.

Blue hydrogen may find it increasingly difficult to retain its economic advantage. Future viability is dependent on the development of extremely low-cost CCS techniques, which must also show significant improvements in capturing efficiency (from about 65% to 95%). Natural gas prices will always majorly influence end-costs, making them vulnerable to volatility and geopolitical considerations, especially for net gas importers. However, blue hydrogen can be created by repurposing existing pipelines and SMR plants. So, it could serve as an effective transition while renewable capacity for green hydrogen production is stepped up and electrolyzer costs fall. 

As James Watson, secretary-general of Eurogas said, “to realistically limit warming to 1.5° C by 2050”, we are “going to have to use CCS”. Both variants of hydrogen have to be deployed in conjunction, with the eventual goal of complete decarbonization in mind.

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The previous articles in this series focused on the power costs and operational lifetimes of hydrogen fuel cells. These factors are important, as cheaper and long-lasting fuel cells are vital for the adoption of hydrogen as a fuel. (For details of how these cells work, refer to the first article).

Cost and durability are far from being the only characteristics of fuel cells worth consideration. Here we focus on fuel cell efficiency – this is the proportion of the chemical energy stored within the hydrogen supplied to the fuel cell, that is eventually converted into usable electricity.

The graph shows the efficiency (%) of PEMFCs and ALKFCs separately, against their operational lifetime in hours. The bubble size represents the power costs of each type of cell, with larger bubbles indicating more expensive cells. We have only considered the stationary applications of PEMFCs here, as ALKFCs are currently unsuitable for automotive purposes. A variety of efficiency figures were collected from studies and market reports, which were then assigned the average lifetime and power cost figures for the technology from the previous articles (unless the source offered specific information).  

When electricity is produced in fuel cells, heat and water are produced as by-products. The heat is usually lost as it escapes into the surroundings of the cell. When it can be captured for productive purposes, it increases the efficiency of the system.  This is called combined heat and power (CHP), and is also commonly used when generating electricity with coal or natural gas.  Another common example is the cabin heater in gasoline cars: excess heat from the engine is used to heat the passenger cabin.  Because the heat would otherwise be wasted, using a car’s cabin heat does not hurt its mileage, while using its air conditioner (which cannot use waste heat from the engine), does.

To account for the efficiency boost from captured heat, the figures on the graph have been split by the presence of CHP in the system.

Within usual (non-CHP) ALKFCs, efficiencies are usually between 50-65%, while in PEMFCs the efficiencies range from 45-55%. ALKFCs tend to demonstrate slightly higher efficiencies than PEMFCs on average, and the smaller bubble size shows that they also have lower power costs. However, they are more sensitive to corrosion, and have significantly smaller operational lifetimes. Combined with their larger size, it makes them impractical for several applications, especially automotive. However, ALKFCs retain their utility for some stationary applications like backup power.

Adding CHP systems clearly increases the efficiency. In fact, ALKFCs have been shown to demonstrate nearly 87% efficiency as per one estimate (although this is yet to be seen outside a lab). PEMFCs with CHP have been known to reach nearly 70% efficiency. Not all the output is electricity, however, and CHP systems can only boost efficiency to the extent that the heat produced is actually required.

Since the lifetimes and some power costs were derived from averages, it is difficult to draw correlations between either of these factors and the efficiency from the data. For the CHP PEMFC, the cost was estimated at about $5500/kW from the source, which is about three times the average of $1880/kW. This was largely due to the cost of the additional components to capture the heat energy. Although no such estimate could be drawn for the CHP ALKFCs, it is unlikely that increasing the efficiency would translate into an equally sharp rise in costs. This is because ALKFCs generally operate at higher temperatures than PEMFCs, which means they are naturally capable of providing more usable heat energy.

The efficiency has several implications on fuel cell applications. Batteries such as lithium-ion show significantly higher efficiencies than the fuel cells. So, battery electric vehicles have managed to reach commercial scale whereas hydrogen ones have not, despite the latter having the promise of faster refueling times. However, fuel cells could play an important role in powering large buildings, if their wasted heat is harnessed through CHP systems.

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The first article in this series introduced the two prominent types of hydrogen fuel cells – alkaline fuel cells (ALKFCs) and proton-exchange membrane fuel cells (PEMFCs). Fuel cells are devices that convert stored hydrogen into usable energy, and constitute an essential part of the hydrogen economy. Subsequent articles shall focus on various characteristics of these two cells. 

The graph above shows the power costs ($/kW) of PEMFCs and ALKFCs as the technology has advanced over time. In other words, they show the initial capital cost for every 1 kW of fuel cell  capacity (note that this axis is in the log scale). Ideally, these costs have to be extremely low for fuel cells to rival existing fossil fuel technologies. The bubble size represents the total operational lifetime in hours, which indicates the durability of each technology. This article will discuss the figures for PEMFCs. 

The estimates have been segregated into those for stationary and automotive applications. Stationary systems are bigger, made for more intensive, long-lasting uses and estimated to be produced (on average) at scales that are 25-30 times lesser than those of automotive FCs. All of this is naturally accompanied by a significant increase in prices. Stationary systems use larger “stacks”, or bundles, of fuel cells which also raises their cost.

For automotive PEMFCs, the costs are significantly lower and we see a marked downward trend in costs from 2002 with improvements in the technology. Various innovations have been implemented to overcome the issues associated with PEMFCs – restrictive thermal conditions, constant humidification of the central membrane and expensive catalysts and bipolar plates. For example, Ballard (BLDP) has come up with self-humidifying membranes, Impact Coatings (IMPC.ST) helps produce corrosion-resistant bipolar plates and PlugPower (PLUG) has developed easier cooling and pressurization systems. 

As a result, the current costs of automotive PEMFCs have reached about $40-55/kW. This has brought them nearer to becoming competitive with internal combustion engines (ICEs), which range about $30-35/kW. 

The lifetime refers to the number of hours a fuel cell operates while still delivering satisfactory performance. This is an indicator of the durability of the cell, which should be as high as possible. Automotive PEMFCs currently exhibit lifetimes between 2500-4000 hours. This is about 60-80% of the lifetime of an average ICE, implying that significant technological improvements in durability remain necessary. Automotive PEMFCs usually face greater challenges with durability as the start-stop motion of cars stresses their membrane.

Within stationary PEMFCs, there appears to have been a surprisingly upward trend in the power costs over time.  This can be partially explained by their constantly increasing sophistication. However, different estimates have different scopes – they may choose to include or exclude installation, electricity and balance of plant costs, and assume different scales of production in the overall figures.  Alternatively, early estimates may simply have been too optimistic.

 On average, the power cost for stationary PEMFCs is roughly $1900-2000/kW. This is much higher than diesel-based  generator systems, which cost about $450-1200/kW. Their operational lifetimes are about 40000 hours – far higher than automotive PEMFCs, as they are designed for nearly continuous use with infrequent replacement. 

PEMFCs are still some way from being adaptable on a large-scale worldwide, and replacing ICEs. High power costs and relatively low durability are key barriers for both automotive and stationary applications, but constant efforts persist to bring them up to par with existing technologies. 

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The previous article in this series on hydrogen fuel-cells focused on proton-exchange membranes fuel cells (PEMFCs). These cells have been the interest of the industry in recent years, and make up the majority of the market. However, it is also worth discussing alkaline fuel cells (ALKFCs), an older variety of cells that remain prominent today. (For details on how these cells work, refer to the first article in this series).

The graph shows the power costs ($/kW) of PEMFCs and ALKFCs as the technology has advanced over time. In other words, it plots the initial capital cost for every 1 kW of fuel cell capacity (note that the cost axis is in the log scale). The bubble size represents the total operational lifetime in hours, with larger bubbles indicating more durable fuel cells.

ALKFC costs have remained under $1000 per kW for the most part (the outlier was a cost projection not accounting for scale). However, industry focus has shifted away from these cells in recent years, due to their numerous issues – their electrolyte gets “poisoned” by carbon dioxide so all supplied gases must be purified, their parts get corroded easily and their large size inhibits use in automobiles. 

As a result, ALKFCs tend to have far lesser durability than stationary PEMFCs. This is apparent in the graph – the average operational lifetime of ALKFCs (~6500-8000 hours) is about 5-7 times shorter than that of stationary PEMFCs. Comparison to automotive PEMFCs is redundant due to the added stress these cells face during their use. 

Despite this, ALKFCs do have value for many stationary applications, including charging EVs and off-grid power in remote locations. Unlike PEMFCs, they do not require rigid temperature bands for operation, and can even operate at sub-zero temperatures. They have also demonstrated very high electrical efficiencies of up to 70%. Firms like AFC Energy (AFC.L) and GenCell have introduced features for improving ALKFCs, such as tolerance for impurities in hydrogen and oxygen and the use of “anionic exchange membranes” to increase the power supply. 

ALKFCs fall behind PEMFCs in their level of technological sophistication, and focused research and development is needed to bring them up to par. They need to be made cheaper, more compact and long-lasting, while retaining their high efficiencies, to fully unlock their potential in the fuel cell market. 

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Fuel cell technology is vital to building the hydrogen economy. Fuel cells combine hydrogen and oxygen into water, while generating a current and some heat energy. Thus, they are used to retrieve stored energy from hydrogen as electricity in large-scale stationary applications, and convert hydrogen fuel to power in automobiles. 

This article introduces a series on fuel cell technologies which will explore the various technologies, the efforts and challenges to improving them, and their prospects for wide-spread adoption.

There are a range of fuel cell technologies. The two most prominent are alkaline fuel cells (ALKFC) and proton exchange membrane fuel cells (PEMFC). 

ALKFCs were the earliest fuel cells, and have been used for several applications, from off-grid power for mining operations to spacecraft at NASA. They comprise two electrodes that contain catalysts, immersed in a liquid electrolyte (usually potassium hydroxide). Hydrogen and oxygen are supplied to either of the electrodes, and the catalyst causes the hydrogen to split into hydrogen ions (also called protons) and electrons. The ions transfer to the other electrode via the electrolyte, and combine with oxygen to form water. The electrons are made to transfer between the electrodes through an external pathway, thus generating a current.

PEMFCs do not utilize an electrolyte. They are composed of two platinum layers, separated by a thin membrane. The platinum layers are catalysts, which are in turn surrounded by gas diffusion layers (GDL) and bipolar plates. Hydrogen and oxygen are supplied to the bipolar plates, and transfer through the GDL to the platinum catalysts. Similar to ALKFCs, hydrogen splits into ions (protons) and electrons. The protons permeate through the membrane and combine with oxygen to form water, while the electrons are collected by the bipolar plate and made to generate a current. Individual PEM cells are too small to satiate most power requirements, and are bundled into larger units called “stacks”.

One notable difference between the two cells is that PEMFCs are far more compact than ALKFCs, due to the absence of a liquid electrolyte and their layered, plate structure. So, they are preferred for use in automobiles, which have limited space. However, research continues into the production of newer kinds of ALKFCs that could bridge this gap. For instance, metal hydride fuel cells are capable of storing hydrogen fuel as part of the system, making them more space-efficient. 

The next two articles in this series will focus on the costs and other characteristics of PEMFCs and ALKFCs. 

The post Introduction to Fuel Cell Technologies appeared first on Alternative Energy Stocks.

By Ishaan Goel

India is amongst the largest renewable energy markets in the world, ranking third in solar, fourth in wind and fifth in hydro power capacity. Due to its rapidly growing economy, India’s energy needs are constantly on the rise. Moreover, countering air pollution has become one of the government’s top priorities. To achieve this, it has set out the world’s largest expansion plan for renewable energy – a 5x increase of installed capacity to 450 GW by 2030. 

The Indian renewable energy market can broadly be divided into two categories – private firms and state-owned enterprises (known as public-sector undertakings or PSUs). The latter refers to firms founded and/or owned by the Government of India.

To promote private sector involvement in the growth of renewables, the government has relaxed some restrictive legislation for companies and investors. For instance, they have made obtaining foreign investments far easier, demystified the auction process for renewable projects and cut corporate taxes for renewable energy firms. Consequently, India has become much more attractive for investors. This is evidenced by double-digit market growth rates and doubling of FDI over the last 5 years. 

While private firms are assuming larger roles, PSUs have been spearheading the renewable movement in India for decades now. A lot of these firms are listed on the stock market. This is usually due to the government’s attempts to disinvest and reduce its expenses. It also makes these firms accountable to the public, which introduces some discipline and efficiency within them and makes them more competitive. So, publicly listed PSUs are generally comparable to private firms in terms of investability.

The government needs an estimated $72 billion by 2022 and $350 billion from 2023-2030 for its expansion plans. On an annual basis, this translates to about $30 billion of investment opportunities – almost thrice the current amount of $11 billion. At the same time, corporate and public interest is increasingly turning towards environmentally-compatible investments. 

Thus, the market has potential for strong overall growth in the decade to come. Investors hoping to profit from India’s renewable growth should begin their research with the companies detailed below (there are several more listed on various exchanges).

PRIVATE COMPANIES 

By far, the best-performing stock in the private (non-governmental) renewables market in India is Adani Green Energy (NSE: ADANIGREEN) (AGE). It is a subsidiary of the infrastructure-oriented Adani conglomerate, which is also India’s largest private power company.

AGE has almost 14 GW of capacity under construction or installed, and it intends to grow to 25 GW by 2025. It holds the ambition of becoming the largest solar company worldwide. Although its primary focus lies on solar and wind, AGE is looking for partners to diversify into equipment manufacturing and other renewables. To achieve this, it has planned to invest an additional $15 billion over the next five years into expansion operations. 

The stock has performed exceptionally well over the past 5 years, growing almost 800% over the last year alone. It has also been virtually unscathed by the Covid situation. AGE currently has a market cap of about $7.1 billion.

A similar firm is the Tata Power Company (NSE: TATAPOWER) (TPC). This is a subsidiary of the Tata Group, one of the biggest and oldest business conglomerates in the world. TPC is the largest integrated power company in India.

TPC operates primarily in solar, wind and hydro, and has a generation portfolio of about 3.8 GW, which accounts for about 30% of its total power generation. It is also India’s largest exporter of solar cells and modules, and one its largest installers of rooftop solar. Apart from this, it also produces solar pumps and filtration systems. 

The company has expressed its intentions to expand the proportion of its renewable generation in the coming years. TPC has a market cap of about $1.8 billion and annual revenues exceeding $1.2 billion.

Another subsidiary firm in the renewables sector is JSW Energy (NSE: JSWENERGY), part of the JSW conglomerate. Its parent company is India’s largest private steel manufacturer, and is also prominent in the cement and infrastructure sectors.

JSW presently has a portfolio of 1.5 GW in hydropower and a singular solar power project, which together constitute about 25% of its total capacity. It has diversified abroad by investing in natural resource companies in South Africa. 

However, the company is targeting a portfolio of 20 GW by 2025, and has committed to making renewables the core of this expansion. It recently called off a large 1 GW thermal power deal, and has pulled the plug on all expansions in the conventional sector for the time being. JSW has a market cap of about $1.17 billion and annual revenues exceeding $1.3 billion. 

Azure Power Global Ltd. (NYSE: AZRE) is the first Indian energy company with a US stock market listing. Azure is focused on bringing solar energy to India, and emphasises on its pursuit of low cost energy production. 

It has a portfolio of about 3 GW, and up to 6 GW more of projects lined up. Azure has a market cap of about $1 billion, and recorded quarterly revenue growth between 30-40% in FY19-20.

Further, it is also the first pure-play solar company in the world to offer Green Bonds under the Climate Bonds Initiative framework. Two such bonds, maturing in 2022 and 2024, have been issued to date.

INDIAN RENEWABLE ENERGY LEADERS – STATE

A list of power PSUs in India would be incomplete without the National Thermal Power Corporation (NSE: NTPC). This is the largest energy producer in India, with a total installed capacity of about 62 GW and about the same under development. 

Presently, it has a portfolio of about 4 GW in renewables, mainly focused in hydro. However, it has undertaken a commitment to increase this to 32 GW by 2030, out of a target of 130 GW. This would make renewable energy responsible for 25% of its total generated output.

NTPC recently committed $6.7 billion to renewable expansion, exhibiting massive growth potential in the sector. It currently has a market cap of about $11.5 billion, and is amongst the most profitable PSUs. 

The equivalent of NTPC in the hydropower sector is the National Hydro Power Corporation (NSE: NHPC). This venture was founded by the government in 1975, with the specific objective of promoting and developing the use of water as a renewable source. 

Since then, it has come a long way – it now has a portfolio of about 11 GW and assets worth $9 billion. NHPC has revenues exceeding $1.4 billion, and a market cap of $2.45 billion. Its fundamentals have recorded a strong growth in recent years.

Another major hydropower player is Satluj Jal Vidyut Nigam Limited (NSE: SJVN), commonly referred to as SJVN. Starting from a single large project in one state in India, it has expanded substantially since then. SJVN has diversified into power transmission, solar power and wind power, and even operates in neighbouring nations like Nepal and Bhutan. Now, it is making forays into thermal power.

The current portfolio of SJVN is about 8 GW. 2.6 GW of this is installed, whilst another 2.4 GW is under active development. The firm is targeting an installed capacity of 12 MW by 2030. Its market cap is close to $1.2 billion, and its net worth is about $1.5 billion.

The Nevyeri Lignite Corporation India (NSE: NLCINDIA), founded by the government in 1956, is unique because it was initially a coal mining operation. It then expanded into thermal power generation. Recently, it has become a substantial producer of renewable energy too. 

Its portfolio is currently sized at 1.5 GW, and it plans to expand this almost threefold to 4.2 GW over the next 5 years. NLC has a market cap of about $930 million. It has assets exceeding $7.5 billion, and annual revenues of nearly $1.6 billion.

Bharat Heavy Electricals Limited (NSE: BHEL) is the country’s largest power equipment manufacturer. As the firm of choice for most government renewable projects, it has produced equipment for solar, wind, hydro, nuclear and geothermal plants.

BHEL has a portfolio of more than 1 GW in solar farms, 30 GW in hydroelectric plants under construction, and large-scale wind and geothermal projects. It is a leading exporter of renewable equipment, with installations in over 80 countries. It also has significant holdings in cell and panel manufacturing. 

The company has several possible growth prospects. It is a leading producer of solar-powered water pumps and spacecraft solar modules, which are growing industries. Moreover, it is likely to be heavily involved in most governmental renewable operations, making it well poised for the future. BHEL currently has a market cap of around $1.7 billion and revenues exceeding $3 billion. 

CONCLUSION

The companies listed above represent the strongest and/or largest players in the Indian renewable market. There has been an encouraging commitment to green energy from companies, governments and the public alike. These factors promise investors multiple opportunities to participate in India’s renewable growth journey.

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Ishaan Goel is a high school senior studying in the Dhirubhai Ambani International School, India. He likes applied mathematics and statistics, especially their relation to economics and finance. He is very interested in green energy and sustainable technologies, because of their potential and rising relevance for the future. Ishaan’s hobbies include writing, long-distance running, playing the keyboard and coding.

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