By Tom Konrad Ph.D., CFA

The market for reliable back-up power in homes and businesses is booming.

With more people working from home and increasing news coverage of power outages due to severe weather events and public safety power shutoffs in California (not to mention domestic terrorism), power reliability seems like it’s destined for a long term boom.

New Competition

A decade ago, if you wanted backup power, a generator was the only option.  Now, there are an increasing number of battery-based alternatives beginning to compete with generators to provide back-up power.  While most battery-based solutions are better than gas or propane generators when it comes to carbon emissions, none of them can yet beat traditional generators in every way most homeowners and businesses consider important.  It’s more of a “horses for courses” type scenario with the best solution depending on price, the amount of power needed, the length of power outage the buyer is preparing for, and convenience. 

Here is a list of options a homeowner might consider and how they stack up.

Natural Gas Generators

Traditional gas generators which run off the utility gas network are a relatively inexpensive solution for a homeowner looking to power their entire home for extended power outages lasting days or weeks.  The main downside for such gas generators is that they won’t work if the weather events or other factors cause a gas outage at the same time as an electrical outage.  For example, during the 2021 Texas Power Crisis, one of the major causes was a cascading problem of cold temperatures shutting down both gas supplies and electric generation.  The resulting lack of electricity caused further problems with gas supply leading to further electric shortfalls, and so on.  All in all, gas supply dropped by approximately 56 percent (and production in Texas dropped by approximately 40 percent) during the crisis.  This means that even people who had home gas generators may not have been able to use them when the power went out.

Liquid Propane Generators

Generac and competitors’ propane generators share the low cost and most of the convenience of gas generators but cost more to run because they rely on propane stored in a tank on the premises, and delivered propane fuel costs far more than pipeline gas.  On the other hand, local storage of the fuel makes them more reliable in an electrical outage that lasts a few days even if the crisis also affects the natural gas supply.  On the downside, the generator will eventually use all the fuel in the tank, and a prolonged crisis may interfere with propane deliveries.

Gasoline and Diesel Generators

Gasoline and Diesel generators are typically smaller than the natural gas and propane generators. They typically do not have the capacity to power a whole home and deliver their power through outlets on the generator itself.  Although they are not a solution for whole home power backup, they can be used to power critical loads like the refrigerator to prevent food from spoiling and charging electronics.

They are also commonly used by building contractors to work on sites that are not yet connected to the grid.  Their relatively low price point (hundreds as opposed to thousands of dollars) appeals to people who want some backup power but find that a whole home generator is too much for their budget.

Home Battery Backup

There are now a number of home energy battery brands in addition to the best known Tesla (TSLA) Powerwall.  These include the PWRcell offering from home generator leader Generac (GNR), as well as offerings from Panasonic (Tokyo:6752 or US ADR:PCRFY), microinverter maker Enphase (ENPH), and solar manufacturer SunPower (SPWR).

Until the recent passage of the Inflation Reduction Act (IRA),  the only way to get 24% the US federal Investment Tax Credit (ITC) for a home battery system was to install it with a solar system in such a way that it charged primarily from the solar.  The IRA both extended and raised the ITC to 30%, and made it applicable to stand-alone battery systems.

Now that home battery systems can be installed independently from solar and still qualify for the ITC, we can expect demand to increase as homes and businesses that are not good candidates for solar suddenly see effective prices fall by 30%.

Batteries vs Generators

Even with the tax credit, however, home battery storage is likely to remain relatively expensive compared with generators for the purpose of maintaining power during an outage. 

If a generator has enough power to supply the electricity need, it can continue to supply that need as long as it is connected to a large enough storage tank or to the gas network.  Because of this, increasing the duration that a generator can protect against a power outage costs very little.  In contrast, doubling the duration that a battery system can protect against a power outage requires doubling the size of the battery, which will nearly double the cost.

Because of this, generators have a significant economic advantage compared to stand-alone batteries when it comes to ensuring long term power supply.  But while secure power supply may be the main attraction for consumers of home battery storage and generators, batteries are far more attractive to grid operators and utilities because of many services they can provide that generators cannot:

• No direct greenhouse gas (GHG) emissions: Electricity from batteries is as clean as the power used to charge them. Small generators, which rely almost exclusively on fossil fuels produce GHG emissions usually far in excess of other electricity on a utility’s grid.  Any reliance on generators makes it harder for a utility to meet its targets for GHG emissions reduction.  While some utilities have voluntary GHG targets, many also are subject to legally binding targets imposed by their regulators and state governments.
• Load shifting and renewable energy integration: Increasing solar and wind penetration on the grid is rapidly changing net usage patterns for electricity.  This trend is particularly pronounced in states that have been early adopters of solar, like California and Hawaii.  Both have now adopted compensation schemes for solar that give homeowners strong incentives to pair solar with battery systems. Since these battery systems also give the homeowners some protection against power outages, this eats into the market for home generators.
• Utility grid upgrade deferral: Batteries can also be used to delay or replace expensive grid upgrades.  Utility power lines and transformers need to be sized to the peak power usage that passes through them, even if this peak only occurs for a few hours per year.  If controlled by the utility, batteries in homes can help with this: by charging when the local line or transformer is operating well below its peak capacity, and supplying that power to meet local demand when it otherwise would be operating at or above peak.  

Green Mountain Power has an interesting pilot program where it leases home battery systems to customers at a subsidized rate in return for the right to use that battery for both utility upgrade deferral and load shifting so long as it keeps enough charge in the battery to assure the customer that they will have protection from a power outage.  Battery system owners can also enroll in the program in exchange for an upfront payment of up to $9,500.  A payment that large could easily influence a homeowner to prefer a battery backup system over a generator.

I expect similar programs to proliferate around the country as utilities and their regulators become more familiar with the benefits batteries can deliver to the grid.

…And It Also Provides Backup Power

An even larger potential disruptor for the generator market is devices that consumers buy for other reasons, but which can also provide power in a blackout.  A prime example of this is the Ford (F) F-150 Lightning: an all-electric pickup truck which can also power your home with the right electrical upgrades.  Electric cars from Nissan and VW are expected to have similar capabilities soon.

The F-150 is only the most prominent example of battery powered vehicles, devices, and appliances that can also deliver backup power.  Many other electric and plug-in hybrid electric vehicles come equipped with standard 120V outlets, while the Kia EV6 has an adapter which turns the charging port into a functional 120V outlet.  Even if an electric or hybrid vehicle does not come with a 120V outlet, an inverter costing $300 or less plugged into the cigarette lighter or attached to the car’s traditional 12 volt battery can serve much the same purpose.  This ability of an electric or hybrid vehicle to power one or more standard outlets is referred to as “Vehicle to Load” while the F-150 Lightning’s ability to replace a home generator is often called “Vehicle to Home.”

While Vehicle to Load cannot replace the utility of a whole home generator, it can easily replace the functionality of smaller gas and diesel generators.  Homeowners who already have electric cars that can power their refrigerator and charge their electronics will also be less likely to spend thousands of dollars on a generator to power their whole home during infrequent outages.

Energy Storage Equipped (ESE) Appliances 

Nor are cars the only devices that can provide incidental power backup.  Owners of Ego battery lawnmowers, snowblowers, and other devices can buy the Ego Nexus Power Station which uses the batteries from those devices to provide all the functionality of a gasoline or diesel generator that can be used indoors.

Photo: The author and other members of the Marbletown Environmental Conservation Commission and Rondout Valley High School Environmental Club with their all electric entry in a holiday parade. The trailer is being towed by a 2012 Toyota RAV4 EV and the lights and music on the trailer are powered by a Ego Nexus Power station.  Other entries trailers in the parade have lights powered by gas or diesel generators.

Another potential development is the including of batteries in home appliances that have not previously had them.  These Energy Storage Equipped (ESE or “Easy”) Appliances also provide incidental power backup.  The main purpose of the batteries is to enable efficient electric appliances like induction stoves and heat pump water heaters to replace their gas counterparts without expensive electrical upgrades.  The batteries allow them to deliver high power performance (like an induction stove’s unmatched ability to boil a large pot of water in minutes) while plugging in to a typical low-power electric outlet.  The extra cost of the battery is offset by lower installation cost and the new investment tax credit for battery storage, effectively delivering a device that not only delivers high performance cooking at no extra cost, but also provides an external outlet which can power your fridge and other critical loads during a power outage.

While neither the Nexus Power Station nor an ESE appliance can deliver the full performance of a home generator, if someone gets one because they need a new stove or snowblower, they will probably be less willing to pay thousands of dollars for a home generator.

Conclusion

While the market for reliable home power is expanding, companies that sell home generators seem  likely to benefit only in the short term.  Longer term, increasingly ubiquitous electric and hybrid electric vehicles with Vehicle to Home and Vehicle to Load capability, along with Energy Storage Equipped (ESE) appliances and utility programs that subsidize (or give away) home battery storage will disrupt the market for generators in a way with which they cannot compete.  

How will a home generator installer persuade a customer to spend many thousands of dollars on a home generator when they already have most of the resiliency benefits it can supply for much lower cost, or even for free as an extra feature of an appliance they would have bought anyway?

A few people still buy high-end digital cameras for the capabilities that a cell phone can’t yet emulate, but those people (and those capabilities) are becoming fewer and fewer.  Ten years from now, we’ll be saying the same things about home generators’ capabilities and home generator buyers..

DISCLOSURE: No positions in companies mentioned in this article.

DISCLAIMER: Past performance is not a guarantee or a reliable indicator of future results.  This article contains the current opinions of the author and such opinions are subject to change without notice.  This article has been distributed for informational purposes only. Forecasts, estimates, and certain information contained herein should not be considered as investment advice or a recommendation of any particular security, strategy or investment product.  Information contained herein has been obtained from sources believed to be reliable, but not guaranteed.

The post How New Battery Applications Will Disrupt the Home Generator Market appeared first on Alternative Energy Stocks.

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 Tom Konrad, Ph.D., CFA

You don’t have to own mining companies to benefit from rising metals prices.

This is a roundup of first quarter earnings notes shared with my Patreon supporters over the last week. Waste to energy operator Covanta and specialty metals recycler Umicore are both benefiting from skyrocketing metals prices.

Just as renewable energy and energy efficiency stocks have long shown that investors don’t have to own fossil fuel companies to benefit from rising prices of fossil fuels, recyclers like Covanta and Umicore are showing that you don’t have to own environmentally damaging mining companies to benefit from rising metals prices.

Covanta Earnings

Everyone could find something to like in last week’s first quarter earnings at Covanta (CVA).  

Revenue and income all showed strong growth over the prior year.  This was driven by strong pricing trends in metals, waste disposal (“tip”) fees, and energy prices.  These gains were achieved despite higher planned outages for maintenance in 2021 compared to the prior year.  This will reduce the need for additional maintenance outages later in the year.

In addition, the company increased its guidance for the full year, and expects further improvements to come from the strategic review as it renegotiates contracts or closes unprofitable operations.  It seems likely that many of these renegotiations will come at the 19 municipally owned plants in the US that it operates under contract.  The company also anticipates significant savings from overhead.

In short, everything is coming up roses.

• The company is performing well
• The macroeconomic environment is favorable
• New plants will be coming online over the next 3 years in the profitable UK market
• Additional savings are expected from the strategic review.

Covanta is definitely a stock to hold even in this relatively overvalued market.

Umicore and Hydrogen

Umicore (UMICF, UMICY, UMI.BR) released its first quarter update as well as a presentation on its positioning in the hydrogen economy in late April.  

In the business update, they’re driving with fully charged batteries:

• Metals, and especially the precious metals, prices are soaring, boosting their recycling business (which also increased its volumes)
• Automotive production is recovering, helping their catalysis business.  The shift away from light duty diesel vehicles is also helping them increase market share.

Umicore currently expects its 2021 earnings to slightly exceed the guidance released just in February.

Hydrogen

With much talk of the hydrogen economy, especially in Europe, Umicore released a timely presentation on how they have and expect to participate.  The company already has a strong position as a supplier of catalysts for the PEM fuel cells used in Fuel Cell Vehicles (FCVs), and have won a number of supply contracts for future fuel cell vehicle platforms.  As of 2020, Hyundai Motor has produced 6,781 Fuel Cell Vehicles using Umicore as a supplier.

They also announced a new partnership with Anglo American Platinum (AAL.L, ANGPF, ANGPY) to develop a liquid carrier which would be used in hydrogen transportation.  They see significant long term growth potential in both this and as a supplier of catalysts to the electrolyzer market.

Conclusion

It was hard to describe Umicore as a value stock when I added it to the 10 Clean Energy Stocks list at the start of the year, and it’s even harder today, given the 30% appreciation since then, I continue to value it for the exposure it gives to the materials used in clean transportation technologies.  Other ways to get this type of exposure include mining stocks and electric vehicle companies like Tesla (TSLA).  I do not invest in mining companies because of environmental concerns, and I do not invest in “story” stocks like EV manufacturers because I like to focus on “boring” stocks that benefit from the same trends, but not everyone is talking about.

It’s much easier to get an edge in your investment analysis when you are one of the few investors paying attention.  

DISCLOSURE: Long CVA, UMICF.

DISCLAIMER: Past performance is not a guarantee or a reliable indicator of future results.  This article contains the current opinions of the author and such opinions are subject to change without notice.  This article has been distributed for informational purposes only. Forecasts, estimates, and certain information contained herein should not be considered as investment advice or a recommendation of any particular security, strategy or investment product.  Information contained herein has been obtained from sources believed to be reliable, but not guaranteed.

The post Earnings Roundup: Metals Prices Boost Covanta and Umicore 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

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.

The post The Many Shades of Hydrogen appeared first on Alternative Energy Stocks.

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. 

The post PEM Fuel Cells – Hoping to Challenge Internal Combustion appeared first on Alternative Energy Stocks.

by Daryl Roberts

A potentially paradigm-shifting technology has been under development at an R&D firm in NJ called Brilliant Light Power.   For people monitoring the situation, the question currently is about the status of commercialization.   It is not a publicly held firm, but is in mid-stages of private equity capitalization in the range of $100-120M.

I recently read a book  titled “Randall Mills and the Search for Hydrino Energy“, offering a detailed and compelling history of the development of this novel renewable energy technology, authored by an insider, an intern who stayed on to work there for several years (published in 2016, with company data as of end of 2015).  In order to provide some context, this article will summarize the concept, breakthrough achievements, compare its levelized costs to other generation technologies, offer a brief review of validation efforts, and touch on personnel and capitalization.   I will try to be faithful to information presented in the book and website materials, and will try identify my own cautious opinions in context.

Concept

The technology was developed by Randall Mills, whose special talents manifested while still a graduate student in physics at Harvard, when he made a discovery in 1989 while exploring a foundational question in physics about why an orbiting electron did not radiate away its energy.   Quantum mechanics diverged from classical mechanics without ever answering this question.  Mills emerged with a revised classical theory that included the proposition that hydrogen’s ground state can in fact be lower than previously thought, that it can have fractional ground states.

According to Mills’ theory, hydrogen can react with a catalyst in a 2-step process, in which first a small amount of energy is transferred by a process called resonant inductive coupling, in integer increments of 27.2 eV.  When this photon is accepted by the catalyst from the atomic hydrogen, the hydrogen electron then becomes unstable and will decay into a lower, fractional orbital, closer to the nucleus.  This 2^nd step releases a larger increment of energy than would be predicted by any other known chemical reactions,   200x higher than burning hydrogen.  The ending species of hydrogen was dubbed a “hydrino”.

Validation

Mills documents extensive experimental confirmation, which to date has identified hydrino states of 1/2, 1/3, 1/4, down to 1/10 (orbital shell distance below 1.0 ground state).  The theory calculates possible hydrinos with a theoretical limit of 1/137, constrained by relativistic speeds for the electron travel.

The book documents Mills’ 25-year journey of verification, both with collaborators and validation by a growing number of independent investigators who report finding confirmation in a wide range of experimental configurations.  Mills was prolific in publishing his findings in the face of persistent resistance from establishment figures, in progressively more prestigious journals. The reference section of the book documents 96 journal articles with Mills as primary author(as of late 2015, now over 100), 52 journal articles with non-BLP primary authors, and 31 other technical reports regarding hydrino research by various universities, national labs and corporations.

Early lab set ups involved low temperature electrolytic cells, but Mills eventually found that the phenomenon could be triggered and measured more successfully in high temperature plasma conditions.  Subsequently, tests were constructed using various types of instrumentation, & validated by leading experimentalists in this field, experts in thermal measurement.    A summary of the full extent of the verification data discussed in the book and website materials is beyond the scope of this article.   But it’s worth including one slide which shows a list of 29 types of confirming evidence that has been compiled to date, including 7 or  8 types of spectroscopy and 4 or 5 types of calorimetry.

On the website, most of the Validation Reports are compiled under the technology tab and also under the News/ What’s New tab.  The focus seems to be weighted most heavily on confirming that the energy is generated by the hydrino reaction process.   Business presentations pdf’s, PowerPoints & videos of conference are in the News / Archive tab.   The validation page reports 4 independent studies in 2020, 3 in 2019, 5 in 2016, and an additional 17 earlier reports.

Energy Gain

The specific excess heat generated is not documented uniformly within a single reference system.  As I searched to compile these results, I found various expressions of “gain” cited in PowerPoint slides reporting outcomes from a range of experiments, as follows:

• “energy gain of 200-500x”
• “Optical energy output of 30x input”
• In a table identifying specific experiments showing a gain column, with 3 cases with highest values showing 399x, 279x & 213x
• “peak power 20MW, time-avg power 4.6MW, optical emission energy 250x applied energy”
• “input power 6.68 kW, output 1,260 kW” 1260/6.68 = 188x
• in terms of power density, as “20MW in microliters”, and elsewhere “billions of watts per liter”
• the 2020 validation studies report finding that hydrino plasma produced excess power of 275kW, 340kW, 200kW & 300kW respectively.
• 2019 report power levels of 1000kW & 100kW.
• 2016 studies report 514kW of optical power & 1.3MW peak power; 689kW with 28x gain; thermal power levels of 440kW; & 1.5MW continuous power from 8.6kW input (1500/8.6 = 174x)

It would benefit the company to clarify and reconcile these value, especially when differing by orders of magnitude, ie., in ranges of 10x vs 100x.  This would help to make clear the specific the relationship between these output values and the resulting dramatic reductions in cost of energy production per kW, which are discussed further below.

SunCell

The experimental configurations evolved from demonstrating the effect in single shot events, to systems that could sustain continuous reactions and maintain a stable plasma.  These early events in which a target material was bombarded by a catalyst along with a high current, low voltage electrical discharge to create the plasma conditions, resulted in an excess of energy so hot that even electrodes made of tungsten were vaporized.

The next steps involved engineering design to develop a commercial prototype, and optimization of supporting systems.   The most challenging practical problem was designing an electrode that could withstand the high temperatures.  This was solved by making the electrode entirely liquid, an arcing molten metallic silver electrode with a continuous feed, into which the catalyst was mixed, which enabled a continuous plasma reaction.   The reaction took place in a small containment vessel, with the two feeder systems, one for the liquid silver, the other for moving the atomic oxygen and hydrogen in and hydrinos out.  The plasma is maintained at 400⁰C and generated very high energy photonic radiation in the Extreme Ultra Violet frequency range (EUV), producing excess heat and molecular signatures confirming Hydrino profiles.   Supporting systems were engineered for hydrolysis of the water, for induction pumping the silver, for heat transfer systems, and for electrical offtake.

The system was branded the “SunCell”.

The reaction produces no emissions other than the reduced hydrinos, which are 64x smaller volume than ordinary hydrogen.   Current design captures the hydrino gas in a charcoal trap or a milled halide hydroxide crystalline matrix to which the hydrinos can bind.  If exhausted into the air, it is inert, non-toxic, lighter than helium and would rise to the upper atmosphere.

The power from the plasma can be utilized either directly as heat with heat exchangers or can be converted to electricity by means of two distinct offtake technology configurations, that were developed and patented:

• Concentrating Photovoltaics (CPV) – the EUV can be converted by stepping down the frequency to the visible spectrum by means of “blackbody radiation”. The containment shell is made of refractory materials to optimize this conversion to optical energy which can then be captured with concentrating photovoltaic cells arrayed around the blackbody. The containment sphere is in essence like the filament of a light bulb, capturing multiple suns 24 hours a day, without intermittency.

• MagnetoHydroDynamic (MHD) – the plasma heats an expanding gas seeded with conducting silver nanoparticles is passed through a transverse magnetic field, converting kinetic energy to electricity.

The more detailed engineering diagram of the SunCell PV design gives a better sense of the relatively compact scale of the device, in this instance only about 3ft high from the base platform.

The device has very high power densities, can produce continuous power at 20MW/ liter.   Below is a working demonstrator prototype in 2016.

To illustrate the comparative power density of the SunCell compared to other stationary concentrating solar applications, they show this slide:Costs

Costs are low because the capital costs to construct the devices are low, one estimate was $60/kW, which is less than 2% of capital costs for solar.  Other operating costs are negligible, for maintenance & fuel, because other than the hydrogen fuel, which is derived from water, all the other materials, recycle within the device, and with few if any moving parts, and so can be expected to have life cycles of 20 years or more.   The resulting energy costs are estimated at $.01/kWh, substantially lower than any other source.In business presentations from 2016, BLP made an attempt to provide more conservative comparisons using the Levelized Cost of Energy tables provided annually from asset manager Lazard considered to be the most reliable & comprehensive surveys are available.  Using the most recent report published 11/7/19, BKP places their LCOE in this context, projecting costs at approximately 50% below the cost of solar & 30% less than Gas Combined Cycle. 

With such low operating & capital costs, the revenue model is based on a flat per diem energy lease transaction rather than a metered price per kWh.  Revenue is modeled based on a “breakthrough rate” below $.05/kWh, which is an arbitrary price sufficiently below market prices of competing sources, but with an enormous built in margin.   Most of the pricing would be based on off-grid provisioning, rather than through the wholesale market auctions through ISOs and other grid operators.  Hence, the capex & operating costs would represent approximately only 2-5%, with net earnings above 90%.

Costs will improve at scale, as the largest costs are for the CPV components.  At production rates of 10GW annually, the estimated costs of the CPV cells are $32 per kW at concentration of 2000 Suns. A cost analysis for parts for a production model of the 2000 suns version show the PV cell assembly constitutes 60%, or $15,000 out of the total of $25,000.  But at higher temperature plasmas, at 10,000 Suns concentration, optimizing output efficiencies, CPV costs drop to less than $6 per kW, or $2800, down to 23%.

Status of Commercialization

If the experimental validation data is accepted, and the resulting production cost calculations are supportable, the pressing question is:  what is the status of commercialization? Why are we not seeing some of these devices appearing in the market yet?  What is holding up the show?  The book doesn’t get into this issue, although the author has communicated his intent to update with a 2^nd edition that explains how this next phase has evolved since 2016.

The website unfortunately does not provide an easily accessible section featuring a sequential history of the  commercialization status, either in a front page or a top line item in a dropdown menu, or a side bar or a featured story.   However, digging deeper, comparing earlier & later website materials, the narrative can be reconstructed.   The two main sources are Business Plan pdfs, & Demonstration Days, found under different tabs.

Business Plan pdf’s:

Earlier commercialization plans indicate the first target market will be industrial thermal energy users.  The SunCell operates 3x more efficiently & 2.5x lower costs if the end product is process heat only, and the electric conversion phase of the system is not included.  BLP envisioned the rollout timeline as shown below, as of 6/14/19. In Phase 1, after industrial users, commercial & residential thermal users are targeted next.  Heat for high GHG generators, steel & concrete are targeted later presumably because those industries are more resistant to change.
Phase 2 targets electricity markets, initially with the SunCell Photovoltaic design scaled to 10kW – 150kW.  The next target would be scaled to 250kW – 2MW, to address Distributed Energy Resources (DERs) for industrial, commercial and multi-tenant residential buildings, providing micro-grid power that can be “islanded” from grid connection, simplifying system designs to eliminate the need for battery storage systems, and eliminating the utility connection costs & queueing time delays.  SunCells can operate continuously, but can also be taken off line without curtailment or the need to redirect current to storage.  They can be simply shutting down with smart controls to smooth peaking and manage very short ramping & re-start times.   Multiple SunCells can be networked with low voltage private grid interconnections, minimizing the need to even interface with the public grid, reducing complications associated with utility permitting.  Further, the potential for micro-grid configurations in rural applications could offer solutions to the wildfire risks in California.

Phase 3 addresses transportation applications in a subsequent phase, for trains, large-scale marine (transport ships that currently burn high emission bunker oil), buses & trucks, and ultimately passenger vehicles and electric aviation.  The MHD version can be scaled down for light vehicles to a size much smaller than either internal combustion engines or EV batteries.

Demonstration Days, found under the News/Archive tab, includes 6 videos of roadshow presentations, with slides, from 1/28/14 – 10/26/16, and 4 additional presentations actually called “Roadshows” (although it is not clear that any of the roadshows are intended to be investor pitches).

Information most relevant to the status of commercialization were a) presentations by two contracted engineering firms, and b) reference in one of the last Demo Day pdfs to a new set of contractors.

• Columbia Tech which is a mid-sized management firm in Boston, not a GE or Siemens, but does $200M/yr revenues, has 500 employees, was selected by BLP to manage transitional processes moving from the development engineering being done at BLP to the production engineering which may be further farmed out. They presented slides indicating where it thinks BLP is in the process.

This is a nice schematic infographic, but there was little in the content of the presenter’s material that disclosed that CT had actually started doing any work, or that there was an expected date for BLP to begin handing off tasks for CT to execute on its path to production development.   Later in that same Demo Day, the in-house marketing director showed his own similar schematic, which added some detail but no new information about actual developments.

• Masimo (formerly Spire, a PV manufacturer) contracted to develop a custom CPV system. However, Masimo also has disappeared, no further reference to either progress on their assigned contract, or that they are even still an industrial partner.  Instead, in some later pdf slides, there is indication in some indication that BLP has reconsidered using non-concentrating PV, that they have been making a closer cost benefit analysis.

In the last roadshow pdf 9/12/17, slides #42 – #47 indicated new progress:

• TMI Climate Solutions (subsidiary of MiTek, a Berkshire-Hathaway company) appears to have been engaged to develop designs for boilers to offtake heat for thermal applications;
• Re Columbia Tech, they announce: “SunCell Commercialization engineering is mature enough to be outsourced to CT. Equipment is being fabricated, procured, shipped”.  It seems to be associated with updated injector design solutions.   Despite this promising indication, there was no further updates about CT after this report. 
• PV development progress: indicates changes in design parameters, & perhaps a change from Masimo to SpectroLab (a Boeing company) to complete the development of the triple junction concentrator cells.

6/14/19 is the most recent update in a Business Presentation pdf.  However, the material merely refined prior messaging, with some updates of prototyping and engineering solutions of SunCell system components, some new validation experiments conducted by independent scientists, and another review of 17 out of the 29 methods for verification of the Hydrino explanation.   However, there were no further updates from ColumbiaTech, Spectrolab or Masimo, TMI Climate Solutions, or any other development partner about component status or overall system fabrication design status.

Advisory Board:   Most have relevant experience in renewable energy development, seem to be well chosen to facilitate the development goals, and some have very high level backgrounds, such as James Woolsey, former Director of the CIA.   This is at least a hopeful indicator that people with both management talent and influence consider the technology to have potential, & whose presence would tend to exert pressure for development progress.

$100 -120m of investment capital is mentioned in scattered references, all of which is from private equity offerings, but investors are NOT disclosed anywhere in the website.  In another reference, there was an indication that some of the other investors were utilities, including a rural electric coop in NM, which may have participated by placing pre-orders rather than taking equity.

The Wikipedia page, which is very one-sided & antagonistic, states:   “…Investors include PacifiCorp, Conectiv, retired executives from Morgan Stanley^[12] and several former BLP board members:

1. Shelby Brewer who was the top nuclear official for the Reagan Administration and CEO of ABB-Combustion Engineering Nuclear Power^[17][18] ,
2. Michael H. Jordan(1936 – 2010), CEO of PepsiCo , Westinghouse Electric Corporation, CBS Corporation and Electronic Data Systems.^[17]”.

Conclusion

With so much potential for triggering transformation with a technology that leaps forward in efficiency & costs and significantly reduces GHG emissions both in fabrication and operation, one can only hope that Brilliant Light Power will be able to accelerate their commercial development process, and upgrade their website to be able to make updates more transparent and accessible.

The post Brilliant Light Power – Commercialization Status appeared first on Alternative Energy Stocks.

by Blackridge Research

The latest trend is that power transmission companies around the world are increasingly looking at energy storage technology to defer or replace transmission system upgrades. How this works is energy storage is placed along a transmission line and operated to inject or absorb power, mimicking transmission line flows. Going with names like “virtual transmission” in Australia and “GridBooster” in Germany, projects totaling over 3 GW of capacity are poised to increase system efficiency and reliability across the world.

Storage as transmission offers an array of benefits over traditional transmission infrastructure. They are faster to deploy, have smaller footprint, flexibility, and relocatability, and they offer other additional services including the ability to provide reactive power, frequency and voltage control and special protection schemes. They also act as revenue streams, while concurrently offering network support.

• RTE, a French utility company, is considering a 40 MW “virtual transmission line” project called RINGO. The project seeks to attain grid integration of renewable energy and optimize electricity currents on its network.
• The German grid development plan, developed by the utilities who own the transmission lines in the country, includes a massive 1.3 GW of energy storage to achieve grid stability and lower network costs.
• In India, the public-owned utility company based in the new state of Andhra Pradesh—the Andhra Pradesh Transmission Company—has proposed in January 2019 between 250 and 500 MW of energy storage to add capacity on its transmission network.
• In the US, Pacific Gas & Electric (PCG) is following through on a 10 MW energy storage project as part of a portfolio of transmission solutions during its regional transmission planning process. This undertaking will be the first one in the country to provide congestion relief in the market.

Blackridge Research is a pure play energy research company covering the Global Energy Transformation.

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by Debra Fiakas, CFA

Last week management of energy storage developer BioSolar, Inc. (BSRC:  OTC/PK) provided an update on the company lithium-ion battery design.  The company’s engineers along with a manufacturing partner are still making changes to the design called the 21700 cell.  Additionally, the company recently decided to take greater control over raw materials supply, potentially sourcing and processing materials in the U.S.  

Engineers at BioSolar have been trying to increase the storage capacity of lithium-ion batteries by improving the anode component.  The plan is to sell ‘super anodes’ to battery manufacturers to make existing lithium-ion batteries work like super batteries.  Prototypes were tested in July 2019, to build a database of performance metrics that will guide the next round of design adjustments.

The BioSolar anode relies on silicon additives to boost energy and power performance.  Indeed, silicon anodes are thought to potentially have a capacity as much as 4,200 milliamp hours per gram (mAh/g), which provides a measure of the amount of charge or electronics per gram of anode material. This compares to the most commonplace anode made from graphite with a capacity of 350 mAh/g.

That tenfold increase in power has some battery manufacturers salivating despite the many negatives associated with silicon anodes.  First, silicon is an expensive material.  Additionally, silicon does not behave well as the battery is charged and then discharges, expanding by as much as 300% in volume.  This can cause the silicon to crack and trap lithium electrolyte in the silicon material.

BioSolar engineers think they have some know-how that could overcome silicon’s worst failings.   They have designed silicon-alloy materials that could have a capacity of 1,500 mAh/g.  Incorporated in a battery of the sort used by Tesla for its all-electric cars, the resulting battery could have a volumetric energy density of 1,000 weight per liter or Wh/L.  This compares to a volumetric energy density of 676 Wh/L for the battery currently used in the Tesla Model S.

It will be a great anode if BioSolar is successful.  No doubt Tesla would be first in line to buy a few.  Nonetheless, the company has a more modest commercial target in batteries for power tools, which is nearly as large a market as vehicle batteries.  Those performance numbers are still goals for BioSolar and not yet accomplishments.  There is still considerable work to be done to bring a silicon anode to the commercial market.

For investors the BioSolar story can be a bit confusing.  While the company has been prolific over the last year in releasing updates and memos on its progress in developing energy storage technology, the annual report published in March 2019, still chatters on about solar energy and the photovoltaic technology that had been the company’s historic business focus.  A patent related to the company’s BioBacksheet for silicon solar modules remains among assets listed on the balance sheet.  Nonetheless, BioSolar’s experience with silicon for solar cells has been a boon to figuring out how to use silicon in battery anodes.

BioSolar’s patent is among just a few assets on the company’s balance sheet.  The company held $73,167 in cash in the bank at the end of June 2019.  Given that it has been using about $60,000 a month in cash to support operations, the cash kitty does not provide much of a cushion against the bumps and bruises of the battery market.  Since the quarter close, the company has raised $53,000 through the issuance of a convertible promissory note with a 10% interest rate.

Should investors take a stake in a tiny company with big dreams?  Perhaps.  However, BioSolar is likely to be palatable only for those with a very long investment horizon and willingness to wait for years to see revenue.  It is noteworthy that in the past few weeks holders of convertible notes totaling $67,645 converted into common stock and accepted additional shares for payment of accrued interest.  Conversion of debt to equity is not only conserving cash that would have otherwise been used for interest payments, it also demonstrates some level of confidence that management is executing according to plan.

Neither the author of the Small Cap Strategist web log, Crystal Equity Research nor its affiliates have a beneficial interest in the companies mentioned herein.

This article was first published on the Small Cap Strategist weblog on 8/27/19 as “What Do Investors Get With BioSolar?”.

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