Eric Parker, Hydrogen and Fuel Cell Technologies Office: Hello everyone and welcome to our April is H2IQ Hour, part of our monthly educational webinar series that highlights research and development activities funded by the US Department of Energy's Hydrogen and Fuel Cell Technologies Office, or HFTO, within the Office of Energy Efficiency and Renewable Energy. My name is Eric Parker, I'm the HFTO webinar lead.
As always, this WebEx call is being recorded and will be posted on the DOE's website and used internally. All attendees will be on mute throughout the webinar. Please, submit your questions via the Q&A box that you should see in the bottom right of your WebEx panel. Please use the Q&A box, not the chat box that will help us get to as many questions as we can during the Q&A portion at the end of the presentation.
With that, I'd like to introduce our NREL lead here for the webinar to get things going, Mark Ruth. Mark Ruth is the manager of the industrial systems and fields group in the Strategic Energy Analysis Center at the National Renewable Energy Laboratory, or NREL, in Golden Colorado. In that role, Mark leads a group of analysts investigating opportunities to improve energy use in the industrial and transportation sectors.
Mark is also leading a multi-laboratory effort to analyze the technical and economic potential of the H2@Scale concept. Mark has also led efforts to identify opportunities to reduce carbon emission intensity of the industrial sector, including quantifying demand for heat and opportunities for hydrogen and steel production.
In over Mark's 20 years at NREL, he has an extensive history developing methods to value opportunities in the energy sector and technical analyses of hydrogen and bioenergy systems. With that, I'll turn it over to you, Mark, to speak to us today.
Mark Ruth, National Renewable Energy Laboratory: Thanks, Eric. I appreciate to be able to speak to all of you about the work that William and I have been doing, thinking about electrolytic hydrogen production and connecting it to the System Advisor Model, or SAM, as we call it. William, this work really developed out of a question around, how would combining electrolysis to solar generation, especially concentrating solar generation.
What are the opportunities for that economically? How might that work? Where might it work best? Our desire to then use a model and tool that is very well considered and heavily utilized within the solar community, specifically the System Advisor Model.
William is going to go through the process or go through some of his work to be able to connect the electrolyzer technologies, both high temperature and low temperature electrolyzers, to the System Advisor Model and some of the results of the analysis coming out of that. William Xi is my colleague at NREL. He has been working, has been the primary performer on this project.
He is also very interested in other ways to do techno-economic assessment of hydrogen production, and hydrogen utilization, including in steel production. He's got a nice project on that that he's performing as well. William joined us from the University of California at Berkeley several years ago. He's a chemical engineer that is trained in this space and has done some great work in it.
William, I'm going to turn it over to you and let you present on concentrating solar as a pathway for electrolytic hydrogen production, what the opportunities are and what some of the challenges are.
William Xi, National Renewable Energy Laboratory: Right. Thanks, Mark. Thanks, Mark, for that introduction. Before I go into the meat of the presentation, I just like to give a quick outline of what we'll be covering today. First off, I'll give a bit of motivation and a couple of questions that we're trying to answer in a project overview.
Afterwards, I'll be going over some of the technologies that we use in analysis, as we're unsure if everyone here is familiar with all the technologies that are mentioned. Afterwards, I'll go over the four solar hydrogen systems that we're looking at in this project, followed by system specific results for each project such as hydrogen device costs and components sizing.
And followed by the last set of results, which is focused on the system performance across 50 locations in the continental US. Then we have a couple of key takeaways and conclusions and we'll be opening up the floor for Q&A. Why are we interested in hydrogen techno-economics in the first place?
Well, one of the main reasons is hydrogen grow as an intermediate energy carrier in an integrated energy system, which is one of the core concepts of the DOE initiative H2@Scale. As you see in the H2@Scale figure on the right, hydrogen can be produced from a variety of energy sources both conventional and renewable.
At the same time be used in variety of end users in chemical industrial processes, metals production, and heat. Currently, hydrogen is produced primarily through steam methane reforming, which isn't carbon neutral, so there really is a need to understand what the techno-economics and opportunities basis for hydrogen production via carbon neutral pathways such as solar hydrogen systems are.
With that in mind, there were several questions that we strove to answer in this project. Firstly, what is the opportunity space for Solar Hydrogen systems? Can we reach $2 per kilogram of hydrogen and in what sort of parameter space does this $2 per kilogram hydrogen target gets achieved?
Secondly, what's the role of concentrating solar power and heat in Solar Hydrogen systems? For example, could we use concentrating solar heat with PV electricity coupled to a higher temperature steam electrolyzer, as a more efficient and cost effective alternative to your typical Solar Hydrogen systems such as PV both temperature electrolysis systems?
Thirdly, which of these systems has the lowest hydrogen levelized costs, both now and in the future? And lastly, can we answer all the questions that we just posed? By connecting industry standards solar simulation environments such as the system advisor model developed by enroll to HTRO hydrogen analyst’s tools such as the HV production models
Before I go into the Solar Hydrogen systems that we looked at in this project, I like to go over some of the technologies. Just very high level overview some of the technologies that we use in these systems. The first technology is the low temperature electrolyzer or specifically the polymer electrolyte membrane pen electrolyzer.
The working principle of the electrolyzer is as follows. Typically, on hydrogen to the anode side of the electrolyzer where the – sorry, water to the anode side of electrolyzer with water is split into hydrogen ions or protons, oxygen gas and electrons.
The hydrogen ions or protons pass through the proton exchange membrane, which is this orange bar to the cathode, and the electrons pass through external circuit were recombined with the hydrogen ions to produce hydrogen gas.
The overall reaction is essentially using water and electricity to produce hydrogen and oxygen. And the fundamental unit of your electrolyzer stack is an electrolyzer cell, which typically consists of several components with over their own functions, such as remembering electoral assembly, current collectors and separator plates.
And generally to get to the multi megawatt scale, which is what's needed for centralized hydrogen production. You combine multiple cells in series to form a stack and eventually some number of stacks to produce the module. Our assumptions for the low temperature electrolyzer system are in the table below.
And we primarily source these from the x ray production models. So as you can see, we have stack purchase costs for the centralized hydro production models from issue for both the future Central and current central cases, the balance of plant costs and the domino hydrogen production efficiency.
The second and last electrolyzer that we've looked at in this project is the high temperature steam electrolyzer and the main difference between your high temperature steam electrolyzer and your low temperature electrolyzer, which by name is that you perform water electrolysis at elevated temperatures in this technology typically between 700 to 1000 degrees Celsius.
A mixture of hydrogen and steam is usually fed to the electrolyzer stack, which then produces hydrogen and the motivation behind using high temperature electrolyzers is a typically at elevated temperatures.
A larger a larger proportion of your the energy needed for electrolysis can be supplied by heat, which is generally cheaper to supply than electricity or again be used available through heat integration with technologies such as concentrating solar power.
And likewise with a low temperature electrolyzer some of our cost assumptions and system performance assumptions are presented in tables below. For example, at the nominal HSC load, there's roughly about a six to one ratio in the requirement in your electrical load and thermal load.
And the last technology I'd like to go over before I move into systems is your concentrating solar technology and specifically we looked at molten salt towers. So how a molten salt tower typically operates is that tracking mirrors reflect sunlight and concentrate it onto a receiver which is at the top of the tower.
A thermal fluid such as the molten salt is pumped to the top of the receiver and that thermal fluid is heated by the solar energy. The hot thermal fluid then exchanges heat with steam and steam drives the power cycle to produce electricity and light at the same time, you can also store the thermal fluid in a tank to extend the capacity factor of your power tower, typically reaching in about 16 to 20 hours of production a day.
That's all the technologies I wanted to go over and now I'd like to give a high level overview of the four systems that we looked at when it comes to hydrogen techno economics. The first system is your grid electrolysis system, which is your full temperature electrolyzer unit connected to the grid.
The second system is a utility PV system coupled to a low temperature electrolyzer with optional battery storage. Third system is a molten salt tower that produces both heat and electricity for high temperature steam electrolyzer.
And the last system is a combination of system two and system three, which in this case, we're using PV to provide electricity for the high temperature steam electrolyzer and a molten salt tower only provides heat for the high temperature steam electrolyzer, so, there isn't a power block in this tower.
The first system or the grid LTE system, the block flow diagram of the system is in this figure. And typically in our analysis, we operate the system in response to electricity prices. A locational marginal price curve with a price adder of about $20 per megawatt hour, which is youth added to account for bringing electricity from the source to electrolyzer site is used as our electricity price signal.
And then the electrolyzer operates based off of the cost of electricity. So from left to right, on this block flow diagram, you have electricity from the grid and electricity price associated with the electricity from the grid at each hour. And when that electricity price is met, the electricity is rectified and sent to the electrolyzer system to produce hydrogen which is purified and compressed subtly under psi.
And just a no is we're producing hydrogen at 300 psi for all the systems that we're analyzing.
Our second system is our PV LTE system, which is a utility 1x is PV coupled to a low temperature electrolyzer with optional battery storage. This overall system is islanded. And because this overall system this islanded, the battery typically tries to capture a trend electricity and utilizes it when the electrolyzer is bellow nominal load.
From left to right on the bottle diagram, electricity from the PV field is inverted and can either be stored in the battery or rectified to be used in electrolyzer to produce hydrogen which is then purified and compressed to 300 psi.
And when the system components are roughly optimized, the capital cost breakdown of the system is shown in this pie chart on the right. About 72% of the total capital cost of the system is your PV field and about 28% of the total capital cost is your low temperature electrolyzer.
Our cost assumptions for the PV technology in the system are primarily sourced from the annual technology baseline scenarios. And our costs for battery are sourced from the annual technology baseline or a daily earthshot target which shall reduce battery cost by 90%. In the next decade.
The third system Solar Hydrogen system that we are analyzing is a hybrid molten salt tower coupled to high temperature steam electrolyzer. From left to right on the block flow diagram, the molten salt stream from the cell tower is either used in the power block to produce electricity that's rectified for the high temperature steam electrolyzer or to exchange heat with feed water to produce steam, which is used in a high temperature steam electrolyzer.
Because solar energy isn't available all hours of the year. We have an auxiliary boiler and a small grid connection to keep the high temperature steam electrolyzer at Hot Standby when solar energy isn't available. The hydrogen from the height from the electrolyzer stack is purified and then compressed to 300 psi.
And our cost assumptions for the molten salt tower are presented in the table below. And they're primarily sourced on the annual technology baseline. And in this particular system when these system sub components are optimized for cost, about 90% of the total capital cost is your molten salt capex and 10% of your total capital costs ensure electrolyzer capex.
And the fourth and final Solar Hydrogen system that we analyze in this project is our PV molten salt high temperature steam electrolyzer system.
It's really just the combination of two-party systems where instead of having a hybrid tower, now we have a molten salt tower without a power block, providing just heat to the high temperature steam electrolyzer in a similar heat integration manner by vaporizing the feed water. And instead of using the tower for electricity, we now have a PV field that provides electricity to the high temperature steam electrolyzer.
Because, thermal storage is generally cheaper electrical storage, we dispatched the salt tower to provide heat in the proportion required by the high temperature steam electrolyzer to the electrical output of the PV field. As you remember, from the high temperature stimulatory side, we need about six times less heat than you do electricity. The cell tower in the system is particularly small, so we updated our cell tower cost curve as credits equation below.
When the system subcomponents are roughly optimized for cost, most of the total capex is from the PV system with about 70% followed by the electrolyzer at about 27%. With that out of the way, I'd like to go over a couple of system specific results that are the key highlights of this project. And before I go into the results, I just want to mention that all the analysis on the following slides was done in Daggett California, which is a location in the US with excellent solar resources.
The first system results center system results are related to the grid connected low temperature electrolysis system. As mentioned in the block flow diagram, we operate the electrolyzer in response to electricity prices. And the particular electricity price curve, at Daggett California that we use is represented by the heat map on the left figure.
And just to walk through this map, the y axis is the hour of the day, so from midnight to midnight, and the x axis is the day of the year, from day one to day 365. Darker blue represents hours of the year where the electricity price is higher, and lighter colors such as lighter yellow represents when the electricity prices lower.
You can typically see the higher electricity prices occur during the evening hours and in winter months. From operating electrolyzer, generally you want to operate when the electricity prices are cheaper such as on this part of the key map. And you don't want to operate the electrolyzer when the electricity prices are high, such as this part of the heat map.
But if you operate the electrolyzer only at a couple of low-price electricity hours, the high capital costs of the electrolyzer is spread over a small amount of hydrogen produced each year, resulting in high hydrogen levelized costs. Vice versa, if you try to operate the electrolytes at high-capacity factor, you end up using higher electricity prices, which also increases the hydrogen ice costs.
There exists an optimal capacity factor between these two extremes, and that's what the figure on the right is trying to show. Just walk through the figure on the right, the y axis is the hydrogen levelized cost in dollars per kilogram hydrogen. And the x axis is the number of hours that the electrolyzer is turned on in the year where it starts from the cheapest electricity price to that particular number of operating hours from zero to 8760.
The orange line represents a stock purchase cost of $783 per kilowatt, the purple line represents the stock purchase costs of $342 per kilowatt, and the black line represents a snack purchase costs of $143 per kilowatt. As you can see, there is an optimal hydrogen levelized cost based off the exact purchase costs.
And the capacity factor is also dependent on the stock purchase costs. When you have a higher initial cost, you need to produce more hydrogen or operate the electrolyzer at a higher capacity factor. And when your stock purchase cost is low, you don't need to operate as the electrolyzer as at as high of a capacity factor.
And given this optimal hydrogen levelized cost approach, we achieve a hydrogen levelized cost of about 250 per kilogram hydrogen for 340 per kilogram hydrogen depending on electrolyzer costs assumption that $143 per kilowatt is the future central H2@ production electrolyzer stack costs assumption and the $342 per kilowatt is the current central issue production model assumption for the electrolyzer stack purchase costs.
Before we can kind of go into analysis for solar haughtiness systems, one of the things we had to address was the sizing of each of the sub components such as the electrolyzer and the thermal load for the high temperature steam electrolyzers. We push this risk by doing a grid search sizing to find the lowest cost system configuration.
For example, we would vary the low temperature electrolyzer capacity in a PV LTE system relative to a baseline PV system size of 100 megawatts. And in the PV, molten salt and HTSE system, we will vary the molten salt towers heat output, and the HTSE system size relative to baseline 100 megawatt PV size.
The table on the top right shows the system capacities at their optimal sizes, and the capital cost assumptions that went into these sizing, and the hydrogen levelized costs at this optimal system size. And the figures on the bottom represent just what the sizing looks like. The figure on the bottom left is our sizing curve for the PV LTE system where we vary the low temperature electrolyzer capacity for a fixed baseline of 100 megawatt PV.
And generally the hydrogen lives cost goes down from about 420 per kilogram hydrogen at the LTE capacity of 45 megawatts to about 390 per kilogram hydrogen and LTE capacity of 55 megawatts.
That goes up afterwards back to about 420 procurement hydrogen at LTE capacity of 65 megawatts. And the sizing for system four, which is the PV molten salt HVAC system, we vary the HSC system capacity on the y axis and the molten salt our nominal heat capacity on the x axis.
And the dark blue region of this heat map represents the system capacity combination that results in the lowest hydrogen levelized cost, which is at about a 60 megawatt HTSE system and a 50 megawatt thermal tower for 100 megawatt PV baseline.
And what we have noticed generally from the sizing of the systems is that there's very little electricity that is trimmed, and sometimes some heat trimming is necessary for the optimal system. In our PV LTE system, the 55-megawatt size results in negligible electricity being wasted or trimmed.
Whereas for our PV M so HVAC system, typically the cell tower is oversized so that it's able to dispatch the heat to use as much available PV energy as possible in the year. With that in mind. The next question we strove to answer was. What is the opportunity space for achieving $2 per kilogram hydrogen for each of our Solar Hydrogen systems?
And to do this we did a sensitivity analysis which identified the two parameters that influence the hydrogen levelized cost of each other systems respectively.
And this is represented in a contour plot. So I'll just walk through all the contour plots from left to right. The contour plot on the left represents the PVLTE system where the y axis is PV capex in dollars per watt AC and the x axis is the LTE capital.
LTE purchase cost in dollars per kilowatt, and currently in 2020, the current baseline value is about as shown in the previous slide about 390 per kilogram hydrogen. And in the future, once the stock costs drops about $143 per kilowatt and the PV capex drops about 77 cents per watt AC 100 levelized cost of 230 per kilogram hydrogen is obtained.
To achieve $2 per kilogram hydrogen, we would just need a bit more. Getting down to belts that the 60 cents per watt AC or dropping the SAT costs to $100 per kilowatt would get us $2 become hydrogen. For the PV LTE system $2 per kilogram hydrogen can be achieved with aggressive cost reductions.
And these are both within the cost reduction curves from HTL and the annual technology baseline. In system three, which was our molten salt tower coupled to HTSE. The two key parameters that influence the hydraulics cost or the CSP_capex in dollars per kilowatt on the y axis and the HTSE_capex in dollars per kilowatt on the x axis.
If you recall from the pie chart that I showed on the block flow diagram, the bulk of the capital costs in system three is a CSP_capex, which is the main driver for reducing the marginal levelized costs. Both in 2020 and in our 2050 scenario, this system does not achieve a hydrolyzed cost of $2 per kilogram of hydrogen.
But with aggressive cost reductions, such as the advanced innovation scenario and the annual technology baseline, we can approach close to $2 per kilogram hydrogen, which will be highlighted in our locations based analysis in the next few slides.
And lastly, our fourth system which is the PV-MSALT-HTSE system. The key cost drivers are the PV capital cost in dollars per watt ac and y axis and HTSE capital costs in dollars per kilowatt on the x axis. And currently in the current baseline $2 per kilogram hydrogen isn't achieved, but in the future close to $2 per kilogram hydrogen is achieved at high generalized costs about 250 per kilogram hydrogen for the future baseline system.
And likewise, similar to system two, aggressive cost reductions and other PD capital costs or HC SC capital costs would bring us into this dark green $2 per kilogram hydrogen space.
The next set of results focuses primarily on system two, which is our PV_LTE system. And this set of results is really to highlight another question we had which was, currently we looked at systems without batteries, but can we add batteries to improve the hydrogen levelized cost of our PV_LTE system.
In this slide, we assume that the battery cost target for the daily earthshot was achieved so the battery cost was reduced by about 90%. And we started adding batteries first to our optimized system, which is a 55-megawatt LTE system coupled to 100-megawatt PV system, shown in the figure on the left.
I'll just kind of walk through the figure because there's a lot going on. The y axis is the hydrogen levelized cost, and the x axis is the hours of battery storage. The orange lines represent the stack purchase costs of $782 per kilowatt, the purple lines represent a stack purchase cost of $342 per kilowatt, and the black lines represent the second purchase cost of $143 per kilowatt.
The shape of a line represents the power of the battery, the solid line representing the battery power of 50 megawatts, a dashed line representing battery power 10 megawatts, and the dotted line representing a battery power of one megawatt.
As expected, if you add battery storage to an optimized system with negligible electricity being trimmed or clipped, then adding batteries will increase the hydrogen levelized costs, regardless of the battery configuration, which is what you see in this curve.
What we're more interested in is can we actually reduce our LTE capacity. Let's run a higher capacity LTE and a – sorry, a lower capacity LTE at higher capacity factor by using that, and this is what the figure on the right is trying to address.
The legends and the shapes of the lines and colors of lines are identical to the figure on the left and the y axis is identical as well, so you can kind of compare it to you by moving over from right to left. What we see is when we reduce our LTE capacity to about 25 megawatts and add batteries to increase the capacity factor of the smaller LTE system.
There are cases where the hydrogen levelized cost does drop below the baseline optimized system without storage, which is represented by the intersection of these lines with the y axis on the left figure.
But the first takeaway is that you firstly need a high power battery. If you look at the low power battery dotted curves, the hydrogen levelized cost decrease is negligible regardless of the hours of storage. The first takeaway is that you really need a utility scale size battery to improve the hydro levelized cost of the PV LTE battery system.
Second takeaway is when you do have high power, increasing the hours of storage significantly decreases the hydrogen levelized cost, as you can see by the slope of the solid curves. And lastly, there is some ratio of electrolyzer to battery costs that determines whether adding batteries would decrease the hydrogen levelized costs.
Starting from the orange solid curve, which is the 50-megawatt battery with up to 12 hours of storage, and a stack purchase cost of $782 per kilowatt and daily earthshot battery costs of 10% of current battery costs. The orange line at 12 hours of battery storage is below the baseline hydrogen levelized cost of the optimized PV LTE system without battery storage.
However, if the stock purchase costs drops about $143 per kilowatt. Having a utility scale battery storage doesn't actually decrease the hydrogen levelized cost significantly relative to the baseline $143 per kilowatt hydrogen levelized costs.
The main takeaway is that, in essence replacing electrolyzer capacity with battery storage, when you're electrolyzer, costs are high and your battery storage costs are low, there are opportunities for PV LTE battery systems to have a lower hydrogen levelized cost than your standard battery storage list system.
But when your stack purchase costs, and your battery costs are low, it is hard to draw a conclusion. And this is what our next set of results tends to highlight. We ran a parametric study on all combinations of battery configurations. LTE sizes, and LTE stack purchase costs and a couple of battery cost scenarios. And what's plotted here in this figure is the minimum hydrogen levelized costs out of all these parametric simulations for a specific LTE sac purchase cost and LTE capacity relative to the 100 megawatt PV array.
Just to go over this quickly, yellow stars represent the ATB 2020 conservative scenario for battery costs. The green stars represent the ATB 2030 Moderate scenario, the blue stars represent the ATB 2040 event scenario, and the purple stars represent the daily earthshot target which is 10% of current battery costs.
And each of these stars represent the minimum hydrogen levelized costs out of all simulations for example, in this case, a 25 megawatt LTE $782 per kilowatt open stack purchase costs.
And what you notice here is that the only cases where adding batteries significantly reduces the hydrogen levelized costs, is when the battery costs reach that earthshot target of 10% of current costs and at a $782 per kilowatt stack purchase costs. And in other cases, adding batteries can only be competitive with your baseline storage lifts hydro device costs represented by the solid horizontal line.
My takeaway is that there is kind of a push and pull between battery capital costs and LTE stack purchase costs that indicates whether adding battery storage would reduce the hydrogen levelized cost of the system. We also did a preliminary investigation into thermal storage for our tower systems. And the general conclusion is that changing the amount of thermal storage beyond six hours for both tower systems has negligible impacts on how generalized costs.
Increasing the amount of storage in the left figure for our MSALT-HTSE systems generally improves the number of hours that the tower is producing electricity and heat which is beneficial for the HTSE system which wants to operate at a normal operating load most of the time.
But beyond 12 hours of thermal storage there is a negligible change in hydrogen levelized costs for our PV molten salt HTSE system changing the number of thermal storage hours did not affect the hydrogen levelized costs significantly for two reasons.
Firstly, the tower size in or baseline system is small, so the overall capital costs of the storage is small compared to the PV capital costs and the HSC capital costs. And secondly, the main reason why there is electricity being trimmed in the system is due to differences in the energy production patterns of your PV system and your cell tower and increasing the hours of storage does not address the dispatch differences.
I just covered a set of system specific results in Daggett California, which is a location with excellent solar resources. But a looming question is how these systems perform across the United States.
And that's what we'll try to answer in this project. We looked at 50 locations across the United States. What we did at each of the 50 locations was read in specific parameters such as electricity prices for each locations, and then run the size optimization or grid search to find the lowest cost system configuration for each location.
And we selected these locations based off a couple factors such as proximity to essential infrastructure such as hydrogen pipelines, variability and solar resources. We wanted to cover the ranges of DNI and GHI in the US more so than just locations with excellent solar resources, and general geographic concerns such as getting a location in most parts of the US.
In our 2020 scenario, our result is that system for our PV, molten salt tower and HTSE system has the lowest hydrogen levelized cost across all locations in our 2020 scenario. And the main reason for this is the relatively cheap PV and HTSE costs and the higher efficiency HTSE system relative to the 2020 assumptions for our PV LTE system.
And the hydrogen levelized cost ranges from about 290 to 549 per kilo of hydrogen were 290 is in the regions with higher solar resources such as the southwest of the US and the 550 is in regions with poor solar resources such as northeast us. When we move to our 2050 scenario, it changes. Now, system two or a PV LTE system has the lowest hydrogen levelized cost across all locations and 2050.
And that's primarily driven by reductions in the LT purchase cost from about 342 to $143 per kilowatt, and PD costs from about 139 to 84 cents per watt AC and hydrogen levelized cost varies from about 213 to $4 per kilogram hydrogen. But in reality it's hard to say whether the PD LTE system or system for our PV molten salt HTSE system is the lowest cost system in our 2050 scenario.
This map represents the percent difference of the PV voltage so HTSE system from the PV-LTE system. When you see a lighter color, it means that the percent differences are smaller, and when you see a darker color, it means that the PV-MSALT-HTSE system is much more expensive than the PV LTE system.
And as you can tell, it ranges from about 1% to 22% difference between the two system across other locations, with 1% in regions with excellent solar resources and 23% regions with poor solar resources.
And due to uncertainties in our projections and for costs and performance for the two systems, it's really difficult to say which of these two systems would have the lowest hydrogen levelized costs in our 2050 scenario.
And lastly, for a hybrid cell tower, it generally had a higher hydrogen levelized cost and both are PV-LTE and our PV-MSALT-HTSE systems, but we're so interested in whether the system can achieve two or when the system can achieve $2 per kilogram hydrogen. And the general conclusion across our location wide analysis is, you will really only be building these hybrid cell tower Solar Hydrogen systems in locations with excellent solar resources.
And you will need overall tower capital costs including power block of about $2,500 per kilowatt, which is roughly in line with the vast innovation technology scenario and the annual technology basically, for these power towers, which I believe in 2050 is a capital cost of about $2,700 per kilowatt. In conclusion, we've integrated Sam with electrolyzer modules that uses the ATB production model or standard HFTO hydrogen analyst tools.
We have noticed that our optimal system configurations for the solar hybrid systems generally involve some heat trimming, because heat is usually cheaper to produce compared to electricity. You want to utilize as much of available electricity as possible. Aggressive cost reductions are needed for all of deep solar hydro systems to achieve $2 per kilogram hydrogen in Daggett California.
And in our current scenario, we expect that our system for or a PV molten salt HTSE system has a lowest hydrogen levelized cost and in our future scenario, the PV battery LTE system has the lowest hydrogen levelized cost. But due to uncertainty in projections, it is difficult to know whether which of the two systems would be the lowest hydrogen levelized cost in the future due to a percent difference of only one in locations with excellent solar resources.
And lastly, our hybrid cell tower HTSE existence can achieve $2 per kilogram hydrogen and excellent solar resource locations, if cell tower costs are $2,500 per kilowatt, which is what we can get to if advanced technology innovation scenarios at ATB is achieved. Thank you for listening to my presentation. And I'll now open up the floor for Q&A.
Eric Parker: Thank you, William. And thank you Mark, as well. We're going to open to the Q&A now. We do have a lot of questions. We'll get to as many as possible. If you think of any more in the meantime, please add them to the Q&A panel. And we'll make sure to save these afterwards and, conduct any follow up as necessary.
So without any further delay, I'm going to open these up to both of you as relevant and just work my way down the list. For the first question, we have someone asking, why is the DC current inverter to AC in the PV LTE scenario listed?
William Xi: I understand that sometimes there is work on DC to DC connections that in theory is more efficient than going from DC to AC and AC to DC. We generally told this scenario because this is what we typically expected in PV LTE installations to look alike since electrolyzers often come with a rectifier requiring AC electricity. Mark, do you have any other thoughts on this question?
Mark Ruth: The only thing I would add is that the standard designs that we were able to get our hands on have, as William discussed DC to AC and then AC to DC conversion. And everything I know of that direct connection is purely in a research stage at this point in time, so we didn't have design and cost information for that.
Eric Parker: Before I get to any further questions, I've seen a few people asking, just to remind everyone I this recording, and the full presentation will be posted online at the DOE's HFT webinar archive in about a week's time, so please be sure to check back for that. So moving on. Another question regarding this system or scenario. How much does the performance of the PV LTE system improve with the DC coupled battery storage?
Mark Ruth: I think that question was asked early before William showed some of the results that are available on say slide 14, I believe William, and hence I think that covers some of our thinking and our results there.
William Xi: We noticed that usually Chris, when your stock purchase costs are higher and your battery costs are lower, since you're essentially replacing capacity with battery storage.
Eric Parker: Okay, and different topic here. Could you elaborate a little bit on why MSALT system has the hydrogen purification step?
Mark Ruth: We showed hydrogen purification I believe on all the electrolyzer systems that purification is essentially primarily a drying step because essentially what we're getting is wet hydrogen coming off, whether it's high temperature, low temperature electrolysis.
Step purification is a drying step to be able to remove the water. Then the hydrogen gas can be compressed without water dropping out, and it can be used there.
That's the primary role of that and we just wanted to indicate that it's not just an electrolyzer, but that the output is pipeline ready, compressed hydrogen that's dry enough to be able to run through storage and compression.
Eric Parker: Great. I saw a few questions on that topic. So hopefully that addresses those. Another one here. Did you consider the possibility of using some of the steam to generate electricity as well as having only one receiver? But that question makes sense. I hope I'm reading that right.
Mark Ruth: I think that one came in before showing the system three design, and hence you can see there that we do have steam to generate electricity as well as heat for the high Tetra electrolyzer.
Eric Parker: And another one on system two, I'm not sure if this one was already addressed. But when the batteries were added to the stored hydrogen and fuel cells that provided the energy storage with longer dispatch durations is there long, sorry, round trip efficiency gains in that with that configuration.
William Xi: We didn't specifically look at round trip efficiency. But I can come back to that question offline.
Mark Ruth: I think that that question was also around as William starts to show here, the opportunities for battery storage versus hydrogen storage. And I think that the question really kind of start from a paradigm that hydrogen storage is much less expensive and we're finding that is not necessarily the case, for short duration storage until you get to very large size, hydrogen storage units were a small addition is not that big.
It's a really nuanced question and a really important one that I don't think we addressed here because we didn't think as much about hydrogen storage, but it does kind of get into how do you how do you manage all of those things.
As William mentioned low cost electrolyzers are great in terms of being able to do trimming, if they're higher cost they use batteries to be able to not trim though the utilization of those and you can increase those capacity factors.
Eric Parker: We did have a few questions around cost. And what was used to determine cost. We have someone asking, for the cost of electrode are you using today's cost, or we're using the 2050 cost.
William Xi: We used both. We wrote two different scenarios, based off the three production models, a 2020 scenario that uses the 2020 H2@ costs and a 2050 scenario, which is the future central costs. The stock purchase costs and the balance of plant costs are shown in the table here. And we pretty much use the H2@ or in other words, the program record causes some things.
Mark Ruth: Most of our Daggett results were for 2020. We're using the 2020. results.
William Xi: All our results we're in Daggett in 2020. When it came to the content. Well, for the counter plots, obviously we moved into feature costs as well. But the general in this particular table, the high generalized cost is for the 2020 scenario.
Eric Parker: And jumping down to another cost question that's relevant. Where did the electricity price data come for? For the standalone LTE case scenario?
William Xi: It primarily came from the wholesale electricity websites, where they published their location marginal prices for Daggett California.
Mark Ruth: That's historical data. It's 2019 data for Daggett that William used in that case. I know that Tanisha asked a question around what happens in the future? I think that I know that analysis was one that's still underway. And it's challenging.
One of the big issues with that analysis is that future pricing or hourly prices for electricity is very often on a zonal basis, which is an aggregate of a number of nodes.
And so you lose a lot of the volatility, that is the actual price of the nodes. The reason why it's done zonally is because of tractability issues.
And if you try to do a nodal analysis of the entire US, that becomes an intractable problem, especially as you start to look at high penetration of solar and wind. There's a lot of work being done in that area. We chose, in this case, to use historical data, because it was the best example in terms of what we could do.
In other projects, we are looking at future costs, but again, zonal is you know, not as volatile, it doesn't have some of the spikes, it doesn't get into some of the other pieces that that normal data does.
Eric Parker: And if you go, one slide forward, actually, we had a question asking what optimizer was used to determine the system configuration here.
William Xi: We did specifically use the optimizer, we just did a grid search. So you can think about the parametric simulation where you would just simulate all the combinations of different systems subcomponents sizes, and then identifying the lowest costs, system configuration.
Mark Ruth: We that for two reasons. One was that adding an optimizer would add some more work. And we've had some discussions with folks at NREL, who are doing some of that, using the hop optimization and others so we didn't have the scope to be able to do that.
The second reasoning behind doing it this way was to give us like this figure on the left, it gives us an opportunity to understand not just what the optimum is, but what the implications are from being a distance away from the optimum.
Oftentimes, when optimum results are reported, you only get that one point you don't have a feel for whether it's a spike, or whether it's a long plateau, that can be done. And we really want to try to understand some of the implications of some of those variations.
Eric Parker: Bit of a scenario here, someone asking when power sources do become dominantly, solar and wind, maybe there's an assumption that price of electricity could change quite a bit. What would the impact be to the grid LTE scenario in this case? And maybe as a follow on? Do you have any plans?
Or is there are an ongoing study about future electricity pricing schemes? I think we touched a little bit on this, but I want to see if you want to elaborate on that.
William Xi: I did do a different project where we had access to the electricity providers, internal projections of future electricity prices in a high renewable scenario. If I remember correctly in that case, and I'll get back to you, since it's been a while since I've done that project, but generally speaking when you do have more volatility in electricity prices, your capacity factor generally goes down.
And one of the hydrogen base cost really depends on the volatility. I don't think there was a clear cut conclusion. But I can get back to that question offline. Once I go back to the project and check the conclusions.
Mark Ruth: We've used some publicly available zonal data and done some of that, there are some real questions, because there some zones that are projected using future data in the standard scenarios. They get to 50-60% a year with zero cost electricity, that definitely brings the price down, there's a lot of opportunities there.
That's an ongoing study and an ongoing piece of work in a different area, but becomes really important. Now it doesn't get into nodal and it doesn't get into what appears to be a missing money problem.
Where, or price suppression problem where it's going to be really hard to get investors to invest in wind and solar at very high penetrations, because they just won't make money off of the electricity and enough hours during the year. There's some real questions and issues there that are being addressed, not just from a hydrogen viewpoint, but from a grid development viewpoint that are underway.
Eric Parker: Do you have a system lifetime assumption for the levelized cost or fixed charge rate assumptions in here? And are you able to share any info on that?
William Xi: I believe we used the default SAM assumptions for the charge rates, etc. I don't remember these off the top of my head, but we do have the Financial Assumptions listed offline, and I can provide that.
Eric Parker: And another one here, could you share how the HTSE was modeled in terms of thermal integration?
William Xi: What the block diagrams show is that we're essentially vaporizing feed water using the cell tower and heat exchanger. And the HTSE integration model was provided by INL, Idaho National Laboratories work on their integration with nuclear heat. And that was primarily provided in the form of aspen ISIS outputs.
Mark Ruth: If you go back to the slide with that HTSE in it, William, the GSEs system itself up here, you can see that there's a lot of, I'm sorry about the small size of the slide, but there's a lot of economizing and that is the main heat, heat use.
There's also use of heat for evaporation of liquid and then electricity is actually used for the topping heat. And as William said, this is based on a high SIS analysis done by the Idaho National Laboratory that we then leveraged.
Eric Parker: We have another kind of scenario being asked about here. This person is wondering if you could eliminate battery storage by assuming GH to pipeline gathering transmission pipelines with large scale packing storage in the total system. If that's available everywhere, and could that work be integrated into other GH two pipeline systems work.
Mark Ruth: There's a lot of work in that space. Our use of battery storage really allowed us to increase the capacity factor of the low temperature electrolyzer itself, we did not have a constant hydrogen output requirement within this project.
So we didn't get into that packing opportunity, we assume that that is that or some other systematic type storage opportunity would be available. However, even with that, you may still want battery storage if your electrolyzer is of a high enough cost that you need to increase the capacity factor for.
Eric Parker: Moving on here we have another, for the HLC, are you including any environmental costs related to water use? In this scenario? Is that factored in at all?
William Xi: The water consumption itself is costed, but the biggest environmental permitting regulations with being able to draw for example, a certain amount of water, that's not captured in the cost.
Eric Parker: And on the question on the price front? Are you calculating any price per ton for green ammonia anywhere in here?
William Xi: Ammonia production wasn't part of our analysis. But there is some ongoing work in interest in ammonia at NROL. And Mark, are you aware of any, I guess projects regarding green ammonia.
Mark Ruth: I would point people back to the H2@Scale technical and economic potential report that we published a year and a half ago that has some estimates around a hydrogen and ammonia costing there.
But there's a number of other things, I'd also recommend that participants join the annual merit review in June, because my belief is it's probably going to be at least one or two ammonia presentations at that. So there's a number of things going on just outside of this project.
Eric Parker: Definitely check that out. Another question here, Is the power needed for compression taken to account in these scenarios?
William Xi: For a compression of 300 psi, yes, the power needed for compression 300 psi is included in all of these systems for all the scenarios.
Eric Parker: Let's see. We have a question here, hoping you could elaborate a little more on the drying step they understand the need but wondering exactly how it's accomplished, is this cooling power followed by a desiccant, or some other message or method rather.
Mark Ruth: Going with details of it yet the low temperature electrolyzer. My memory is off use what was in the H2@ design. So if folks go to the H2@ model website, they can find the design there. My memory of that is that it was a pressure swing, absorption, drying step. So use a desiccant and then use pressure swing to be able to remove it.
Although it might be temperature swing absorption, I can't recall. I don't recall what was in the high temperature electrolyzer design from Idaho National Laboratory, they did have a drying step in there. But I would have to go back and try to find that I think that was a temperature swing, we actually drop out the liquid. And then we go from there.
William Xi: I can respond to offline, but we have the process for the IL that we used.
Eric Parker: I'll just get to one more, I guess and then we'll have to wrap up. But could you elaborate a little more on the key siting criteria used for these projects.
William Xi: We mostly select these locations based off proximity to hydro pipeline infrastructure was about within 100 kilometers of 100 pipelines. And I believe we mostly looked at that in the Gulf Coast. And the other siting criteria was mostly related to solar resources. I'm just trying to get to the map slide, but was mostly related to solar resources or just covering the geographic I guess, continental US.
So we wanted to make sure that at least we had a couple of resources that are considered class 10 in ATB or accent, so real resources with a couple that are lower class since I think it's like class three, I believe in the ATB just to cover the range of what you would expect for a DNI and GHI in the US.
Eric Parker: Well, it is the top of the hour, I realized I was not able to get to everyone's questions. I'm sorry, we had quite a few. As William and Mark said, we're going to capture all these and do our best to connect offline where it's helpful to address some of the extra ones we didn't get to.
But thank you for all the great questions and for attending today's H2IQ hour. Thanks to our presenters, William and Mark, for this awesome topic. And be sure to check back soon for the recording and slides on our website and make sure you're signed up for a newsletter so you get notifications of future topics like these. And with that, I'll wish everyone a great rest of their week and goodbye.
Mark Ruth: Thanks very much, Eric. Thanks for this opportunity. And thank you for participating all of you participants out there. We appreciate your time
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