Below is the text version for the H2IQ Hour: Pathways to Reduce the Cost of Hydrogen Production webinar video, recorded on March 25, 2020. 

Eric Parker, Fuel Cell Technologies Office:

Good day everyone and welcome back to the H2IQ Hour, the U.S. Department of Energy’s Hydrogen and Fuel Cells Program webinar series. It’s great to see so many of you joining us today. We’ve got a great presentation from Strategic Analysis on hydrogen production and delivery pathways. Before we get started, I just wanted to let everyone know we recently relaunched this webinar series to focus the webinars on helping us all enable a better understanding of hydrogen and fuel cells and the work we fund to advance those technologies. If you are active on the social media, we highly encourage you to share anything interesting, surprising, or informative you get from these webinars or elsewhere by using the H2IQ hashtag in your posts.

We’ll be announcing more topics like these soon as well. As a reminder, this WebEx call is being recorded and will be posted on the DOE’s website along with a PDF of this slide deck, so you will have access to it. All attendees will be on mute throughout the webinar so please, please, please submit your questions via the Q&A box that you should see on your WebEx panel in the bottom right. We will cover those Q&A questions at the end of the presentation. And with that I would like to introduce today’s H2IQ Hour host and my colleague James Vickers. Hi James.

James Vickers, Fuel Cell Technologies Office:

Hi Eric. Thanks so much. Thanks everyone for coming to this webinar. I just wanted to briefly introduce the topic and the speakers. Myself, I am James Vickers. I am a technical fellow in the Fuel Cell Technologies Office supporting the hydrogen production program. And this webinar represents a significant portion of work from analysis that we funded with Strategic Analysis looking at the advanced hydrogen production pathways of polymer electrolyte membrane electrolysis and solid oxide electrolyte electrolysis. This work has been carried out by Strategic Analysis, which is led by Brian James, who heads the energy analysis services at Strategic Analysis and has over two decades of experience in conducting techno-economic analysis of emerging energy systems.

He’s participated in the early development of the H2A cost analysis model, which we’ll hear a little bit about today, and has performed dozens of the H2A model case studies covering a wide range of hydrogen production systems. This presentation, however, will be carried out by Dan DeSantis, who is a project engineer at Strategic Analysis. His major focus is on system design and techno-economic analysis of hydrogen production methods. These two have been an absolute pleasure to work with and they have completed a really substantial piece of work here contacting different research institutions as well as manufacturers of these technologies to give the most accurate and up to date cost estimation for hydrogen production for these technologies available. And after that I will say to you Dan, please take it away.

Dan DeSantis, Strategic Analysis:

OK. Thanks James. As mentioned, my name is Dan DeSantis. Been working with Strategic Analysis for a while now on a number of projects, primarily the production and delivery of hydrogen pathways, and as stated I’m joined by Brian James. And I also want to acknowledge Genevieve Saur who is our colleague at NREL who has worked with us on this project for many years. For this project we primarily use the H2A tool that was mentioned before. This website should give you all the information that you need to access, use, and download the tool. You can follow this to the NREL website and download the tool for yourself, review case studies that have been published using the H2A tool, and even follow a user guide on how to use the tool.

H2A is primarily an Excel-based discounted cash flow model to project hydrogen cost. The code is written and maintained by NREL. Primarily there are two technology timeframes, the Current and the Future. Those timeframes get changed depending on when current and future are. Right now, it’s generally 2019 is the current timeframe and 2035 is the technology startup for the future. By default, there’s two production sizes: Distributed sites have 1.5 tons per day of hydrogen production while Central sites have 50 tons per day of hydrogen production.

When you get into H2A you’ll notice there are many inputs that you can follow. Primarily though you’ll be looking at feedstock requirements, energy usage requirements, capital cost of the site, which is where we spend a lot of time collecting data and working to develop accurate models. There are also equipment replacement schedules and a host of other inputs that generally have default values that can be utilized or adjusted as needed. And a nice benefit is you get a levelized cost of hydrogen that’s in a certain dollar year that can be compared with other projects in the same dollar year very easily, so you get more of an apples-to-apples comparison. It also very nicely breaks out the capital cost contribution, feedstock contribution, etc. You’ll see a lot of that as we go along; and there are some sensitivity analyses built right into the tool that you can use.

For this project we have lately been focused on hydrogen production from water splitting by electrolysis. So, we’ve looked at a couple of different technologies. The range of what we have looked at has covered both the Distributed and Central case sizes as well as the current technologies, 2019 technologies, and the future technologies, 2035, what we expect the technology to be at in the future. In both of these cases we were looking for technologies that would be run at a high manufacturing rate. Currently electrolysis units are being produced somewhere in the range of maybe 50 to 100, maybe 300 megawatts per year depending on who we’re talking to. We’ve decided to model this as if we had a more progressed hydrogen economy and have selected our production rate for all of these units to be 700 megawatts per year.

The three main technologies, as James mentioned, we’ve been working on proton exchange membranes or polymer exchange membrane technologies, PEM, which have both distributed and central sizes and both current and future technologies that we’ve analyzed. Solid oxide electrolysis, for those of you who are not aware, is much higher temperature operation. And given the capital cost investment and the size of the plants that are envisioned we only looked at a central production size for this, so 50 tons per day of hydrogen. And we’ve looked again at current and future technologies.

In progress is alkaline exchange membrane technologies. This is a relatively new technology, fairly low technology readiness level right now. Given the size and parameters of the information we have, we have looked at a distributed production size only, no central cases. And the only technology is in the future. Because this is in progress, we actually won’t be reviewing this work today, but it is coming out for those of you who are interested. Our general approach, which we’ll get into more, has been to collect data from the industry, review that data, augment it with system models and our own design work, and then use that information to run H2A models with the types of inputs that I mentioned earlier.

For our data collection we rely heavily on industry and research groups. We generally send out questionnaires with detailed questions for them to fill out. And they provide us with a lot of information. When we get that information, we start reviewing it. The more information we have the better. Unfortunately, sometimes it’s so much information in one area or you have to augment it with other things. So, in certain cases where we only have a few responses, we’ve looked into literature review, price quotes. We’ve supplemented our analyses with ground-up DFMA analysis to develop costs and stack prices and equipment costs for different pieces of equipment. As I mentioned, today we’re going to be covering PEM and solid oxide electrolysis where we’ve had a significant number of respondents in both cases, which has been very helpful, and the community’s been very generous in providing some information.

Going through all of this electrolysis work we’ve identified six common key cost parameters for electrolysis. The current density, cell voltage, and electrical usage for the electrolyzer units are something more of a technical parameter but they directly relate to the energy usage that goes into the system. And energy usage is a very key component of the final hydrogen cost. The stack cost, of course this is the electrolyzer cost. Generally, this is reported in dollars per kilowatt. But when you’re looking at several different types of electrolyzers at different technology years you often have different performance capabilities for the electrolyzer that get tied up in that kilowatt number. So, we decoupled the performance by analyzing the production of the stack in a dollars per active area, a dollar per centimeter squared unit.

And that way we could compare stack costs across different electrolyzers without having to worry about the exact performance category when looking at the stack cost. For those of you who are used to dollar per kilowatt we still report it in that later on so you will of course be able to see it that way in the numbers that you’re used to and compare to your own background and numbers. We looked at the mechanical BoP, which mainly consists of pumps and dryers and heat exchangers for each electrolyzer. To scale this in a way that was a little more feasible for the flow rate for the different sizes of systems we looked at the flow rate as a scaling factor, the flow rate of hydrogen. And then the electrical BoP cost. Of course, electrical BoP we’ll have in dollars per kilowatt, and it mostly consists of rectifiers and transformers, some supplemental electrical equipment. So, I’m going to go through how we get all of these numbers eventually to put into the H2A model, so that’s coming up soon.

But I wanted to start off with the proton exchange membrane electrolyzer general operation, which mostly focuses on having water come in on the anode side, split into hydrogen ions, which push across the membrane and form hydrogen on the cathode side of the reaction as they exit the electrolyzer. And you get oxygen, saturated oxygen, out of the anode side with any excess water that’s coming through. That’s how the electrolyzer kind of functions.

This is how the entire PEM system would function. Water is coming in, the system gets cleaned up in a deionizer and filter, flows through a water tank holding tank, gets pumped to operating pressure, fed to the electrolyzer stack, and hydrogen is produced. The hydrogen passes through several cleanup systems including a knockout pot with a condenser, temperature swing absorption subsystem to purify the hydrogen, remove any saturated water, and you get your hydrogen coming out, or near pure hydrogen coming out. The system is running a low temperature, generally 80 degrees C, 70 to 80 degrees C. Most of the water gets recycled, which is a benefit to the system. And what I want to really call your attention to here is the black dotted box around some of this equipment. That’s our mechanical BoP that I mentioned before.

Similarly, the red box around the rectifying transformers are electrical BoP, and that’s going to be something we cover―how we develop these costs exactly―in a couple of slides. It’s also important to point out for the PEM process because we have different production sizes, we envisioned that in the Distributed case you’d have one mechanical BoP module per site, and that would be matched up to an electrolyzer stack appropriate for 1.5 tons per day of hydrogen production. In the Central cases we envision more stacks attached to more mechanical BoP modules. And that way should stacks go offline for replacement or repair or something happened on one of the mechanical BoP modules that needs maintenance or shutdown time, you still have multiple modules running and you’re still producing hydrogen. In the future, given that we expect the stacks to have a longer life, we can actually assume that you don’t need as many full modules. Each module is sized appropriately for the flow rate that it’s handling and costed for that as well as you’ll see.

Comparatively I wanted to look at solid oxide electrolysis here. In this case you have water coming in and hydrogen being generated on the same side of the electrolyzer. Oxygen ions are actually crossing the electrolyzer and reforming into oxygen on the other side. And this is important later when we look at a couple different system arrangements for this. Starting with the Current case, it looks a little more complicated than the PEM case. And there’s a couple things I’m going to call out here. First off, you’re at a very high temperature, 700 to 800 degrees Celsius for the operation of the system. The water coming in gets pumped up to pressure for the stack as well. There’s a lot of heat exchangers in here to recover as much heat as possible. Hydrogen that’s produced in the electrolyzer is then fed back through all these heat exchangers and enters a knockout pot to remove any excess water, which you can then recycle.

On the other side of the electrolyzer is an air stream that is used to sweep oxygen out of the electrolyzer and is brought around and again, as much heat as possible is recovered. Similar to the PEM system we have an electrical BoP setup. This is actually almost identical to what’s in PEM, just sized a little differently for the central sizes. And we have a TSA subsystem to clean up our hydrogen. There’s a few differences here that I want to point out. First off, this box around here is actually what we’re calling a stack module. It’s different than the mechanical BoP module that I mentioned in PEM. This is actually a pressure vessel or a series of pressure vessels containing stacks and these heat exchangers. This way, the stack can be at a given pressure inside this pressure vessel and operate without having to worry about seals that are rated for very high pressures and very high temperatures, which those seals can be difficult to produce or find. Because the system is running in the Current case, the stack system is running about 70 psi, 72 psi I think, the hydrogen pressure needs to be lifted at the very end of the system. And so there’s a hydrogen compressor here to bring it up to 300 psi, which is the H2A default.

In the Future case of the solid oxide electrolysis we’ve adjusted a couple of things. First off, you’ll notice there’s no air sweep here. We essentially make the assumption that future technology will have developed to a point where that air sweep isn’t necessary to maintain the same sort of operational parameters that we expect from the solid oxide electrolysis system. The benefit of that is along with removing some equipment and lowering the capital cost, you also have the opportunity to recover oxygen byproduct for sale. Now I want to point out that we did not actually model byproduct credit for our H2A analysis coming up. But it is available if somebody wanted to look into that as well in the future. They could take one of the models that will be published online for this and apply an oxygen byproduct to see what kind of discount they would also be able to receive for that. Also, you’ll notice there’s no hydrogen compression system up here. That’s because we’ve modeled a system in which the water is pressurized in this pump to roughly 375 psia. And after pressure drops throughout this whole system, exits the PSA subsystem at the appropriate 300 psa―psia, excuse me, for H2A’s production value.

The last thing I want to discuss I think before we get into the capital cost development of each of the components is the polarization and degradation of the system. So, these polarization curves represent of course the operating conditions that are achievable in the electrolyzers that we’ve modeled. These curves are for the PEM case, and so we have the Current and the Future. You’ll see the blue line is the beginning of life polarization curve. As the stack is operating and degrades, we assume a constant voltage operation, so you lower the current density to maintain the operation of the stack. However, that stack produces less hydrogen as it degrades. So, we’ve modeled the stacks in such a way that they’re oversized for our targeted hydrogen production from the site.

Over time as they degrade and produce less hydrogen, the total production over the life of the site will average out to our targeted hydrogen production for each site. So, there will be 1.5 tons per day average coming out of our distributed sites and 50 tons per day of hydrogen average coming out of our central sites. These polarization curves were developed by taking data that’s been published, comparing it, or using a mathematical model that was also published in literature, and identifying operating points from our own data that were collected from industry and research experts. Thus we were able to fit the data so that it was done in such a way that the values were representative of the current technology and what we expect the future technology to be while making sure we were at operation points that the experts have told us that they’re running now. And those points― those exact operating points will be listed in a data table a little bit later.

The solid oxide electrolysis polarization curve is similar. We in fact use the same mathematical model to develop the curves that you see here. What you’ll notice is missing is the beginning of life and end of life curve for both the Current and Future cases. That’s because it was suggested to us that one way to handle the degradation of the solid oxide electrolysis systems, which are more prone to degradation than PEM, is to start operating them at a slightly lower temperature. And instead of adjusting current density or voltage to maintain the operation you would continue to increase the heat, the thermal input to the system, in such a way that you can counter the degradation and maintain a constant hydrogen production. So, we actually have modeled a system that follows that kind of a schematic to predict the cost of hydrogen from stacks that essentially will maintain constant hydrogen production.

Now we’re going to start getting into the capital cost estimation, and there’s a lot of data here in these slides, a lot of information that we’re trying to provide to you. But the short version of this is that we started with information coming in about the PEM stack price that was very focused on low manufacturing rate production costs. We expanded on that by collecting data from literature and by building a DFMA model, so a ground-up model that predicts the cost of the stack. This is again going back to our dollars per square centimeter discussion earlier. And we were able to use the combination of data sources to identify baseline stack costs, or excuse me, baseline stack prices, which include manufacturing markups, at $1.30 per centimeter squared for the Current cases and $0.77 per centimeter squared for the Future cases.

The big assumption there is that the stacks are the same at distributed and central sites; there’s just more stacks at the central site. So, you can actually produce stacks for the entire hydrogen economy of electrolyzers, PEM electrolyzers, that are equivalent and thus get more benefits for economies of scale. Using the same data sources, we were also able to identify from low manufacturing rate costs the upper bounds of our errors, and from our predictive models, potential lower bounds for the error in the stack prices. Now the error bars might look a little extreme here, but I will tell you right off that this is just one component of the total capital cost. That’s just one component of the H2A cost for hydrogen. And you’ll see later on in some of the sensitivity analysis, this is not the most significant cost driver that we’ll see. So, these error bars in here don’t throw off the hydrogen price prediction too much.

We carried out the solid oxide stack price in a similar fashion. Here the stack prices were a little lower for production. The Current case stack price had a nominal value of 20 cents per centimeter squared in our baseline and 15 cents per centimeter squared. The error bars here might even look a little larger than in the PEM case. But actually, they’re even less of―the stack price has even less of an impact given that the capital cost of the larger and more complex solid oxide system dominates a lot of the capital cost’s influence on the total hydrogen price.

The PEM mechanical BoP cost, this is that module we were talking about, is shown here on the right. This is actually the cost for the Current Distributed case. As we built up our process flow diagram that you saw earlier we developed this bill of materials as well and through a number of sources such as quotes, our own economic models, and our history collecting data on various components for systems like this we were able to build up a cost model, come up with a total, apply some markups and contingencies, and develop a reasonable approximation of what we expect a system to cost for a Distributed case. When you’re making several hundred of these, we can also apply some discounts to the individual components for buying multiple units and running at economies of scale. As I mentioned before there are actually different sizes of this module for the distributed, central, distributed and central sizes, so that we have these scaled in different locations to account for the flow rate. I just am not showing them all here because it would just be table after table of numbers. But the data will also all be in the published H2A cases that you can find online.

The solid oxide mechanical BoP costs were done in a very similar fashion. In fact, we used the same discount rates when we could. We were still using total electrolyzer production rate of 700 megawatts per year. And we have both a Current and a Future case here. You’ll see some zeros in here. This describes changes in the systems. You can refer to the PFDs that were shown earlier to show which systems were not or which components were not in each system. But that’s why there are zeros there so you can see the cost difference and cost savings of removing certain components from one system or the other.

The electrical BoP cost was based off of quotes from a rectifier and transformer company. We added in some costs for ancillary equipment. We applied some cost reductions for the central plants given that they are larger size and would be essentially “buying in bulk.” Markups were applied to the cases as required and we applied a discount to all our future technology assuming there would be some improvement as we went along that would reduce the costs in the future.

Between all of those things we were able to come up with what is essentially this table, a key technical and cost parameters data table. Most of this information applies directly to the H2A cost inputs or operating inputs, technical parameter inputs. So along with the plant size, the operating pressures, current density, and voltage, you also find the electrical usage and the capital cost inputs in both the units we’ve identified earlier as well as the more traditional dollars per kilowatt. Generally speaking, for PEM, we had very good agreement in our questionnaire responses as to what the current and future current density and voltage would be as well as operating pressures and targeted electrical usages for the stack.

In the solid oxide case, very similar setup. We were able to identify from questionnaire data very consistent numbers in current density and voltage. We were actually able to calculate very specifically the stack and thermal energy usage from the data that we had provided to us by the questionnaire respondents. And again, we’ve identified the capital cost segments in both our identified units and the more traditional dollars per kilowatt units. One thing to point out, the stack costs, or something we found interesting was the stack cost for solid oxide electrolysis is about one fifth the stack cost of PEM systems. Despite that the solid oxide system cost is actually higher than the PEM system cost for a central plant. Largely, in my opinion, due to the larger capital cost segment that is required for solid oxide systems being that it’s operating at high temperature and there’s a lot of heat recovery systems included.

These are the H2A cost results that we developed for the PEM electrolyzer after inputting all those key cost parameters into H2A. We were able to identify that the baseline Current cases would be able to produce hydrogen for roughly $5.00 a kilogram, just under, a little farther under, in the Central case. And for the Future case you can actually reduce that cost down to about $4.50 dollars per kilogram. Now that’s using the electricity price that’s identified by the Annual Energy Outlook report. And that’s important because this big blue bar that dominates this graph in each of these cases, in each of these cases, is the electricity cost contribution to hydrogen.

So, the way the AEO electricity cost is set up is it’s a schedule over the lifetime of the plant that predicts the cost of electricity in every year of operation. And it’s generally running somewhere―for each of these cases, you can see the effect of price―it’s generally running between seven and eight cents per kilowatt hour. There’s been a lot of discussion over what would happen if you could reduce that cost. And some people have suggested that renewable energy prices would be somewhere around three cents a kilowatt hour.

So, we went ahead and modeled a flat three cent kilowatt hour electricity cost for all of these cases. So I know this graph might look a little busy, but the quick version of it is that by reducing the electricity cost to three cents a kilowatt hour for the life of the site, you can actually get the Current case cost down into the $2.50 range for hydrogen. And the Future cases could even be producing hydrogen at less than $2.00 a kilogram of hydrogen, which is a pretty big achievement and meets one of the DOE goals for hydrogen production in the future.

For the solid oxide cases, similar setup. You’ll see that the electricity cost is again dominant. The capital cost provides a much larger contribution to the hydrogen price in solid oxide than it did in the PEM as we’ve stated. The cost is somewhere around $4.00 a kilogram for the Current and Future cases. That’s a little less than PEM, so it’s a slightly more optimistic look at the cost of hydrogen maybe from solid oxide. But it’s a big plant that’s running with very high heat, so there’s an initial entry barrier there. In a similar fashion we modeled the cost with three cents a kilowatt hour electricity for each of the cases. And you can see again we’re getting close to $2.00 a kilogram in the future for the hydrogen production price. And comparable $2.36 cents per kilogram of hydrogen in the Current case that’s similar to what PEM has.

Last thing I want to go through here is our sensitivity study. So, the single parameter sensitivity studies take a look at the cost of the system, the cost of hydrogen from a given system, with a series of variables that we’ve changed. The dominant one in every case, as you’ll see, is the electricity price. It is always the biggest cost driver. The second biggest parameter in every case is the stack electrical usage, which is again a direct link to how much electricity is being used in the system and thus potentially reducing the electrical contribution. The third most important one that I wanted to point out in all of these is the stack cost. So those big error bars before do matter, but they are relatively down in the noise for these sensitivity studies showing that even with a little error it doesn’t move the hydrogen cost that much compared to electrical price or electrical usage. The solid oxide cases have similar sensitivity studies. Again, electricity price is the dominant cost. The stack price is one of the top four. Here there is one little addition in between the electrical costs and usage and the stack prices that the thermal energy price that is being used by these solid oxide systems, that has a bit of a cost impact on final hydrogen price that the low temperature PEM system doesn’t have to worry about, but the high thermal energy requirements of the solid oxide system do require enough energy that the price of that energy can make a difference on the final hydrogen cost.

And with that we’re approaching the end of our analysis work for these two projects. So hopefully this has identified a little bit more about the state of electrolyzers in a hydrogen economy for everybody. I really hope that the cost driver information is very useful for everybody. That’s a big part of us doing these techno-economic analyses is to identify what the major cost drivers are for each of these systems. We’ve been very lucky to collaborate with NREL, ANL, and DOE along with all of our technical experts here to create these models for the general public. And hopefully they provide useful information going forward. We’re still working on our AEM model, which should be coming out soon, hopefully at the end of the fiscal year. And cases are regularly being published into the H2A website that I presented earlier, and they will be there for your review and use at your discretion. I think now we can open up to the question and answer segment.

Eric Parker:

Yeah. Thank you, Dan, for that presentation. We have about 23–25 minutes for Q&A. I’m going to let my colleague James lead Q&A. We have a lot of great questions. So, apologies if we don’t get to them all but let’s get started. And we do have our full panelists available here online with Dan to answer questions. So, thanks James.

James Vickers:

Dan, this first one comes from Gary Stotler. It’s regarding the key cost parameters: does the tool have the ability to include maintenance costs? This can be significant. Of course, I’d love to break it down into dollars per kilogram if possible.

Dan DeSantis:

The H2A tool has a couple different ways that incorporates maintenance. There’s a few different categories that it has. It’s possible to break out that cost specifically but it does get wrapped up in I believe in one of the other cost parameters. I believe it’s the capital cost parameter. But you can actually go into the discounted cash flow analysis page of H2A, find out what the maintenance contribution is, and there will be a way to get the dollars per kilogram contribution of just maintenance from that as well.

James Vickers:

Great. And I understand that you also expressed this in sort of a lifetime and a stack replacement interval, which are included in the calculations. Is that correct?

Dan DeSantis:

Yeah. So, there’s a specific page for equipment replacement. And you identify in that page how frequently the equipment is replaced and how much of the total capital cost is required at each interval. So, you can just identify that the stack needs replaced every so often. For example, that’s―in our Central cases for PEM, we have the stack case being, stacks being replaced every few years and a stack cost that goes along with that. But we also at one point, 20 years in I think, we account for a total balance of plant replacement. So, all of the balance of the plant is replaced, and 100 percent of the total capital cost is invested again for balance of plant. And that’s identified in that equipment replacement setup.

James Vickers:

Thank you. I’ll just also just take this moment to remind everyone that the cost record that is mentioned here is available online for your download. And the H2A model itself, which includes the versions that have the case studies that were used in this model, are available for you to download and play around with as you please. OK. So, we have another question here from George Volochuck, who I know is supposed to be at the H-Mat kickoff meeting. He says what is the typical and max hydrogen pressure from PEM and SOE electrolyzers?

Dan DeSantis:

Yeah. James, just to ask is it ok if I scroll back on slides in this?

James Vickers:

Absolutely.

Dan DeSantis:

Ok. So, they’re actually identified in our data tables, which is why I’m going to do that. Then I can tell you. The Current case PEM stack pressure is running around 350 psi, and that’s so that we can achieve the H2A targeted outlet pressure of 300 psi without extra compression. The Future case PEM systems were identified to have an outlet pressure of 700 psi, which is actually higher than the targeted H2A case. And we even accounted for this and gave them a bit of a credit because they’re coming out of the system at a higher pressure. The stacks have to run a little higher than 700 psi to account for pressure drop to the rest of the system as well. Conversely the solid oxide system is running a little differently.

In the Current case, the stack pressure is low, around 5 bar, which works out to 72.5 psi give or take. And the hydrogen is compressed at the end of the process right after the TSA subsystem is used to clean up the hydrogen, bring it up to the H2A target pressure of 300 psi. In the future I think I mentioned in the PFDs that the―one of the big adjustments we make for the Future case technology is to have the stack pressure at 300 psi essentially pump up the water in the pump to a level where it’s high enough to get into the stack. I think it would actually be a little higher than 300 psi to account for pressure drop. But essentially you pump up the water to a level where it’s above 300 psi. And then by the time it exits the TSA system it’s roughly at 300 psi and thus you don’t need that expensive compressor at the end of the process.

James Vickers:

Great. Thank you. And we have a question here from Thomas Chan about the utilization factors seen here. And also said that you mentioned that renewable power can drive down the levelized cost of electricity or levelized cost of hydrogen in this case. Sorry. I just lost it. But yeah, can you speak to the utilization factor and the utilization factor that you may assume if you have intermittent renewables?

Dan DeSantis:

Yeah. We’re worked with this a little bit and it’s not shown in this presentation. We received information from our questionnaire respondents that had the PEM case having very high capacity factor, utilization factor somewhere around 97 percent. And it was incorporated into some of our sensitivity work, because it’s so high, to analyze what the effect is of lowering it. The solid oxide system, however, being that it’s very high temperature and there aren’t actually any commercial central plants for it at this time that I’m aware of, we had that operating at a 90 percent utilization factor, capacity factor. As for the second part of the question regarding renewable energy costs driving down the levelized cost, it’s more that the electrical cost just has to come down and the information that we were provided suggested that renewable energy costs would be somewhere around three cents a kilowatt hour. And there’s of course variation in that number.

So, we picked three cents a kilowatt hour from some of the information that suggested it would be three cents a kilowatt hour and used that as a guideline for what the cost would be with reduced electrical prices for the operational system. There is of course an intermittent nature to a lot of the renewable energy prices. And you can change the utilization factor in H2A quite easily to account for that. So, we’ve run it where utilization I think for the PEM case was 30 percent or 50 percent and looked at the cost while it was three cents a kilowatt hour. And it definitely comes up from a flat three cents a kilowatt hour during the whole operation, but I think it’s still an improvement on the baseline case using the AEO electricity price schedule.

James Vickers:

Thank you. And I know that you have done some analysis that show with low-cost electricity and even very low utilization rates you can still meet some pretty aggressive cost targets.

Dan DeSantis:

Yes. I think that is presented in the record if I’m not mistaken. So, you can see that by downloading the record from the website, NREL website. I’m trying to remember the numbers, I think we ran a 40 percent utilization and even a 2 cent per kilowatt hour electricity and we were still approaching $2.00 a kilogram hydrogen, if I remember correctly. But please check the DOE record for PEM to confirm those numbers. I think it’s published there.

James Vickers:

Great. OK. And then we have a couple questions about how these costs compare to hydrogen that is produced from fossil feedstocks and if there is a price comparison for dollars per gallon equivalent if you could speak to that.

Dan DeSantis:

I don’t have a lot of those numbers right in front of me and I haven’t looked at them in a while. Maybe Brian might remember some of them more. I know that we’ve done cost analysis for SMR and coal and a few other things. And I think that they were cheaper, somewhere around maybe $1.50 or so compared to―or $1.50 per kilogram of hydrogen or so; I think it was something like that. Brian―do you?

Brian James, Strategic Analysis:

Yeah. That’s my understanding is that SMR technologies are around, in between $1.50 and $2.00 per kilogram of hydrogen. And also, conveniently, a kilogram of hydrogen is very close to a gasoline gallon equivalent in terms of energy.

Dan DeSantis:

It’s almost identical.

Brian James:

And these are—right, and just to remind that these are production costs and not necessarily selling price.

James Vickers:

OK. So, another question here from Maggie Henna. Does―in SOE, why is there no recovery of oxygen?

Dan DeSantis:

Yeah. So, in previously analyses we’ve had byproduct credits from various different components that we’ve presented. And a number of people have said that it masks, to their opinion it masks, the actual cost of hydrogen even when we try to be very transparent about what the cost and the byproduct credits are. And given that we decided that at this time we would present the hydrogen production price without the byproduct credit and leave it up to the reviewers or anyone who was interested in creating the work to account for their own oxygen byproduct. The other part of that is with oxygen, there’s a fairly diverse market for how you’re going to use the oxygen and what you’re going to do with it. Sometimes it requires some post processing. So, it would probably be more accurate and beneficial to an end user to, who is interested in running something like this to look at their specific case where they think they could find an oxygen byproduct buyer and apply the technology specifically to that application.

James Vickers:

OK, great. We have another question here from Taylor Huff. Does this future PEM stack estimate assume significant R&D advances such as moving away from PGM catalyst and reducing usage of titanium or gold coatings?

Dan DeSantis:

It does contain some advanced technology assumptions that we are looking for, but we were still accounting for titanium plates in our DFMA models and we still had platinum catalysts in there. A large part of the improvements are in the methodologies for producing the stacks. And some of it has to do with the operational conditions that the electrolyzer is running at, such as the higher current density and a lower voltage, which is essentially a better efficiency.

James Vickers:

OK. Thank you. Another question here from Robert Perry. If you can speak on the current state of reversible fuel cells electrolysis technology and would you be able to incorporate any of that into the modeling in the near future?

Dan DeSantis:

I do know that there’s a lot of work being done in reversible fuel cells. I think I’m going to turn that one over to Brian as to his experience there and some of the future plans for it.

Brian James:

Right. So, the conventional wisdom on reversible fuel cells is that they―it is tough to beat the two disparate boxes operating at optimized conditions for each one, one production and one―well, one production of electricity and one production of hydrogen. However, recent advances suggest particularly when the stacks are able to move to very high current densities that there may be merit in that. We’ve done some preliminary investigation but right now we don’t have plans or DOE direction to examine the reversible electrolysis in a full case study.

James Vickers:

Great. OK. Thank you. Another question here from Michael Harenbrock. What would be the typical electrolyzer size in kilowatts for the PEM today and future and centralized versus decentralized?

Dan DeSantis:

I know the Central cases are somewhat―what we’ve modeled for a 50 ton per day plant, the Central cases are roughly 100 megawatts in size for electrical input. And I―the Distributed case is something like 3.3 to 3.5 megawatts, depending, is the numbers I’m remembering.

Brian James:

Yes, I believe those are correct.

James Vickers:

OK. Great. And can you speak to the water consumption that is required to run production of hydrogen on this scale?

Dan DeSantis:

Yeah. A little bit. So first off, let me say that H2A, one of the H2A input parameters that we used is for water, to identify usage for it. It’s not significantly more than the stoichiometry given that you’re recycling a lot of the water. You can actually keep the water costs down and the water usage down pretty significantly because water is both kept in the H2A as a relatively inexpensive component. It doesn’t make up a large cost of the hydrogen. Brian, do you have anything to add on that one?

Brian James:

Yeah. This is an interesting topic that we’ve looked at at various levels of depth over the years, the obvious connection there is, as one wants low cost electricity and solar often comes to mind. Large solar fields are often in arid areas without good access to water. The water consumption is to a large degree a tradeoff between capital cost and water efficiency. If you take―extend the measures to recapture all the wastewater then you can get it down close to the actual stoichiometric ratio that Dan suggested. That’s dictated by how much hydrogen you’re actually producing. And the other issue is the quality of the water going to the electrolysis.

We certainly want it to be pure water so that the choice of water purification at the front end probably has more to do with the amount of hydrogen consumption, excuse me, the water consumption than the water recovery does just because depending on the type of filtration and purification there can be large excess amounts of dirty water, so to speak, required compared to the pure water that is fed into the electrolysis unit. Those numbers are I think available from within the H2A case studies. I don’t have actual magnitudes of water usage in mind but they’re available in the case study.

Dan DeSantis:

Yeah, I would point out too that we put deionizers on the front of our systems so if you can get deionized water from another source inexpensively then maybe that’s a better way to go. But running through an electrolyzer, I think deionized water is your targeted goal. And I don’t have the numbers in front of me either or remember them off the top of my head, but I believe it was three or four gallons per kilogram of hydrogen, seems high even from what I’m remembering. So, I highly suggest you check the actual H2A models that are published online to find that number if you’re interested in it.

James Vickers:

OK. Excellent. Another question here, the system costs do not include installation. Do you have a sense for the costs, maybe dollars per kilowatt for Central and Distributed cases installation?

Dan DeSantis:

So, there are installation costs listed in the H2A models. We apply an installation factor to each of the component costs in the capital cost input page, and so they are adjusted based off of what we expect the installation of the unit to be. So, the electrolyzers have―I think the electrolyzer stack has a ten percent adjustment factor on it. But other components have larger installation costs. A lot of them had something like 46 percent installation markup in the PEM case. And I’m forgetting what a lot of the solid oxide ones were off the top of my head. But again, you can download the model and look and see exactly what we applied to each of those components. And that installation factor gets wrapped up in the capital cost contribution at the end. It can be broken out pretty easily. If it’s not already broken out in the cash flow analysis, you can always set the installation factor across the board to one and then compare the difference to the cost with the installation factor and that should give you a pretty good sense of how much that is making a contribution.

James Vickers:

OK, great. So, it’s available there. We have time now just for a couple more. One question here is to find out information about alkaline electrolysis, traditional alkaline electrolysis, not AEM. This person says they have an alkaline system that the cost is currently the lowest for a small scale production. Do you have any sense or anything about the alkaline electrolysis?

Dan DeSantis:

I haven’t spent a lot of time on alkaline electrolysis personally. I kind of briefly covered it when I started looking into the AEM systems to get a grasp for what was different between them. I know that they can―I know there’s a lot of numbers that say they’re relatively cheap. But I also know that, and I know they’re being produced by certain electrolyzer companies, but I also gathered that there were some handling issues with dealing with the alkaline nature and possibly through other things. I think that it’s still a technology people use and consider nothing taking away from that by looking at PEM or solid oxide or AEM even. But I don’t have a lot of information about it.

James Vickers:

OK. Thank you. Question here, are there any safety hazard concerns that are different between the PEM and SOE systems?

Dan DeSantis:

Yes. I believe that would be through―just given right off the bat the extremely high temperatures that you’re working with in the solid oxide system―you’re going to have things that need to be dealt with that. I mean already you have to deal with pressure relief valves and temperature controls and standoff guards for things like that under OSHA requirements. Running at high temperatures does require you to have certain safeguards in place. I think, it’s been a while since I worked at plants, but I think there’s a standoff temperature limit for certain pieces of equipment that are far less than 700 degrees Celsius. So, you will have requirements for safety that get pulled into those solid oxide things. As far as PEM, you’re going to have safety requirements of course―you’re still dealing with hydrogen and oxygen in the same space, even if they’re separated, so you’re going to have explosion requirements on both of those systems. There’s going to be at 300 psi, even 72 psi for the stack operating in solid oxide, you’re going to have pressure relief that is a concern. When we start looking at the PEM case of the future where we are modeling it being 700 psi that gets to be more of a concern. So, there will definitely be safety requirements that have to be met and they will definitely be different between the two systems. I would imagine your biggest concern is going to be temperature.

James Vickers:

OK. And then I think that this will be our last question. We’ll take this and then we’ll do our signoffs. Is there any work being done to develop distributed solid electrolysis production? And what are the main technical challenge and roadblocks for this technology?

Dan DeSantis:

I think Brian can jump in on this one too but I’m not aware of any right now, Brian?

Brian James:

No. Sunfire has systems. They obviously start off small and then get larger with time. There hasn’t been as much focus on the distributed concept for solid oxide as there has been with PEM. They’ve been concentrated mostly on large systems.

Dan DeSantis:

The big problem in my mind is that you have such a high temperature that you have to get it up to that temperature and maintain that temperature. And thermal cycling like that can be quite difficult. I think we were throwing some ideas around the office one time about trying to insulate that. And there are some solid oxide fuel cell applications where they try to keep it insulated for the high temperatures. But I don’t think anyone has really looked into a hydrogen production system for a distributed case with such extreme temperature cycling.

Brian James:

I would note on that that obviously all of the systems, whether they’re going to be PEM or solid oxide, are going to be modular by nature. And the stack size is going to be―it may―I should say the module size might be on the level of a megawatt or so. That being the case then one could take care of the temperature confinement for a megawatt or two megawatt system quite easily because the larger systems are just composed of those size modules. You’re only thinking one each. However, for the solid oxide, the mechanical balance, as Dan illustrated, formed substantial cost added to the system, and you get economies of scale with that so larger is cheaper in that regard. So, the solid oxide would probably be, would be better suited to large installation so as to gain the economies of scale of mechanical BoP systems, and you have a bunch of modules together. So, there’s an economic particular benefit in solid oxide to going large central rather than small distributed.

James Vickers:

OK. Thank you very much. I just wanted to say again thank you Dan for your great presentation and all of your hard work on this production record as well as the modeling work. And thank you to Brian James and Genevieve Saur as well for all of their work on this record, on this model, and thanks for the great presentation. Any final signoffs, Eric?

Eric Parker:

Yeah. Thanks James and everyone else. And thank you to all of you for joining. Turnout was amazing today. So that does include the H2IQ webinar. And we received an amazing amount of questions, I think over 100. So, if we didn’t get to yours, we did save them all and feel free to―Dan, you want to advance to the next slide. We do provide some contact information if you’d like to reach out directly to any of us with your query. And as many of you asked, yes, the slides and this full recording will be available online on the DOE FCTO website. So, if you go to that URL at the bottom there you should be able to navigate to a webinars page. In the next week or so we’ll be posting the PDF and the video file of this recording. And as I mentioned earlier, please join the conversation on social media using the H2IQ hashtag. And let’s keep it going. So, with that, thanks everyone for joining and have a great rest of your week. Bye bye.