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Wind-to-Hydrogen Cost Modeling and Project Findings (Text Version)

Below is the text version of the webinar titled "Wind-to-Hydrogen Cost Modeling and Project Findings," originally presented on February 22, 2013. In addition to this text version of the audio, you can access the presentation slides and a recording of the webinar (WMV 97 MB).

Moderator:
Welcome to today's second attempt at the webinar given by NREL today. So we appreciate you guys that were patient with us on Tuesday and are joining us again today.

Just so you know, this webinar is going to be recorded, along with slides. So we will be posting both of those to our website in about ten days. So give us about a week, and we'll have those up on the website—both the recording and the slides.

Just a few housekeeping items. If you have questions throughout the webinar, please submit those via the question box on the GoToMeeting, and we will cover those at the end. We have about 10 or 15 minutes we'll leave at the end for questions.

And also just to keep in mind—this is a monthly series that we do. So please check back to our website. Our next webinar will be on February 12th. So look back there for details. We'll have those up probably in about a week or so as well.

So on that note, I am going to turn it over to Eric Miller, who is the hydrogen production technology development manager for the Fuel Cell Technologies Office. And he is going to present today's speaker. So on that note, I will turn it over to Eric.

Eric Miller:
Thanks, Alli. And welcome, Chris and Genevieve at NREL, and welcome everyone again back to our webinar. Just as a very quick introduction to the topic, water electrolysis powered by renewable electricity is one of our promising near-term pathways to low-carbon hydrogen.

But, of course, there are technical and cost challenges. The DOE research and development has helped reduce the capital costs of electrolyzer stacks, but electricity prices remain a significant barrier to affordable hydrogen through electrolysis.

Low-cost wind electricity could provide regional solutions to this, and Chris and his team at NREL have done a great job exploring the costs of wind-driven electrolysis. Barring any fire drills today, Chris will be discussing this work today. So take it away, Chris.

Chris Ainscough:
Thank you, Eric. And I might add—even if we do have a fire drill, we have a second location set up, so we'll have a short pause, and then we'll pick it back up from there.

Eric Miller:
Perfect.

Chris Ainscough:
So I want to start by thanking all of you who have come back after the issue on Tuesday. So thanks for your patience, and thanks for sticking with us. Yeah. Some things you just can't avoid. So away we go. I also want to thank my team—Genevieve Saur, who is also the line, Kevin Harrison, and Todd Ramsden here at NREL.

[Next Slide]

For acknowledgements, I want to make sure we thank the Fuel Cell Technologies office within EERE, who funded this research. And particularly I want to thank our technology development manager, Sarah Dillich, Eric, who's on the phone with us, Erika Sutherland, and David Peterson, here in the Golden field office. And I also want to acknowledge the indirect support of the DOE Wind program, which sponsored much of the analysis that we referenced in this work.

[Next Slide]

So a brief history of the Wind-to-Hydrogen Project—this started in 2006 as a joint venture between DOE, NREL, and Xcel Energy, which is the local utility for a lot of the states out here in the West. And the project started up at the National Wind Technology Center in Boulder and contained an experimental activity, as well as an analysis activity, of which this analysis is part. The overall aim of the project is to reduce the cost of producing domestically sourced hydrogen.

[Next Slide]

So the pinnacle part of the project looks like this. And you can see we have the ability to tie in a variety of resources into hydrogen generation and production—both photovoltaics that we have onsite and several dedicated wind turbines that we have onsite.

We can direct couple, or through DC conversion, couple those to a variety of electrolyzers. We can then compress and store the hydrogen. And you can see how the station here has evolved over the years. We've got different electrolyzers, different compressions technologies. We then take the hydrogen that we produce, store it, and then use it to fuel vehicles or put it back on the grid, using either a genset or a five-kilowatt fuel cell.

[Next Slide]

And one of the things we're working on seriously right now is improving compressor reliability. Because we've found, through our data gathering activities through other DOE projects, that hydrogen compressors are really a reliability concern when it comes to the hydrogen fueling stations.

[Next Slide]

So the question you might ask is: why would we do this analysis? And just again—so this analysis—we looked at an hour-by-hour cross-modeling of centralized wind-based electrolysis. So as Eric mentioned, cost is a problem. Wind electrolysis production cost estimates were limited geographically before we did this analysis, and we really expanded it to cover more of the country.

System efficiency remains a barrier as well. And that primarily goes into the efficiency of the electrolyzers. So we did a sensitivity analysis to look at what components and what factors have the most impact on the cost of hydrogen produced in this method. And we also wanted to look at the relationships between the size of the wind and the size of the electrolyzer capital that you would be deploying in a case like this.

[Next Slide]

So we wanted to expand the previous analysis that we had done a few years ago, which just focused on the California electricity market—again, to look across the nation, look at the consequences of different configurations and different operations scenarios, understand the sizing implications between the electrolyzers and the wind farms throughout different parts of the country, and identify further analysis and cost reduction areas.

[Next Slide]

So at a glance, this analysis looked at 42 different sites in 11 different states spanning five electricity markets. And for those of you who know anything about the electricity grid in the United States—and we often talk about it as this sort of monolithic thing, but it's not. It's a patchwork of different regional electrical grids and markets operating in each one of those.

So we looked at wind classes that ranged from Class 3 to Class 6. If you get below Class 3, it definitely doesn't make any economic sense, so we didn't look at those. And the higher class wind sites are pretty rare and located in special geographic locations, so we didn't really look at those either. We looked at size ranges from 1,000 to 50,000 kilograms per day.

An independent panel analysis in 2009 among electrolyzer producers found that in that region, the costs of scaling up are fairly linear. You don't get huge economies of scale in that range. And we also updated the analysis to harmonize with current DOE targets, which use 2007 as a reference here.

So you can see down here, the electricity markets. We have an after—California ISO refreshed that data. We also added Midwest ISO, ISO New England, ERCOT, which is in Texas, and PJM, which covers Pennsylvania, New Jersey, and Maryland. We updated the wind cost as well. As you can see, there was a slight reduction in wind capital cost from our previous announcement in 2011 to what we've done in 2012.

[Next Slide]

As far as scope for the analysis, in order to focus on what we were doing, we had to limit the scope to just looking at the interactions of a wind farm, the electrolyzers, and the grid. All these things you can do with hydrogen once you've produced it—you can put it into the petrochemical market. You can compress, store, and dispense it for vehicle fuel. You could use it for grid arbitrage or ancillary support services. We didn't look at those. Because we really wanted to focus on this piece. And there are other activities looking at things like that.

[Next Slide]

So at each of these sites that we analyzed—each of these 42 sites—we've developed an 8,760-hour, which is an entire year, profile based on NREL's H2A production and fuel cell power models.

So we used hourly electricity, market pricing, and hourly wind data. There are public data sources that are available. And you can see—this is an example of one site that ended up being—basically $4.50 per kilogram at a Class 4 wind site.

The green here shows hour-by-hour grid power that's going to the electrolyzer. Blue shows wind power that's going to the electrolyzer. And in the case where you have more wind power than the electrolyzers need, the model was sped up to export that power to the grid at the locational marginal price, which we'll get into in a minute.

[Next Slide]

We looked at four different scenarios for the production—for controlling this type of plant. Scenario A is a cost-balanced approach, where the dollars of grid energy that you purchase equals the amount of wind that you sell back to the grid on a dollar basis. Scenario B is a power balanced basis, where we looked at the kilowatt hours purchased versus kilowatt hours sold and balanced it that way.

C and D are the same as A and B respectively, except that we look at the impact of not purchasing peak summer grid electricity, which can be very expensive. The net effect of that is, of course, that you may have a hydrogen production shortfall. But your hydrogen cost can be slightly lower. And, again, I'll point out that—so B and D being the two that are energy balanced scenarios—those represent net green hydrogen, so there's no net grid electricity used in those scenarios.

[Next Slide]

Some of the parameters of our analysis—so we looked at a nominal design capacity—51,000 kilograms a day, with a 98% capacity factor on the electrolyzers, not on the wind, 106 megawatt-hour electricity requirements at 50 kilowatt hours per kilogram, which is a fairly decent number for large scale—primarily outgoing electrolyzers of the size we're talking about—$53.2 million total depreciable capital costs.

We included replacement and O&M costs, and we also included, in the analysis of the life of the plant, a 10% internal rate of return. So somebody doing this would actually be making some money at it, which is, of course, key to having success in any kind of new energy technology.

The wind farms—we looked at multiples of three-megawatt turbines, which are generally the largest size that can be based on land these days. The general design performance was based on a Class 4 wind site. Though as I mentioned before, we did scale up from 3- to 6-class wind sites.

We updated, based on a report from Wiser and Bollinger, some colleagues here also at NREL working in the wind program—updated the costs for the wind turbine capital and the O&M costs—the operation and maintenance costs. And you can see the wind capital costs went down slightly to $2,067 a kilowatt, whereas the O&M costs went up slightly. So we countered for that.

[Next Slide]

Here you can see a typical input from the eastern and western wind data sets. These are published data sets that show what the wind classes and wind resources are like in different locations. So you can see the capacity factor of your wind turbines has a huge impact on the cost of your wind electricity.

And as Eric mentioned, the cost of electricity is really one of the primary barriers for having low-cost electrolyzer based hydrogen. So to the extent that we can get to a higher wind capacity factor—and generally, capacity factor goes along with higher-class winds—you get lower cost electricity, which results in lower cost hydrogen.

And I will add—we do talk later about the effects of the investment tax credit, the production tax credit, and the Treasury grant, which—the Treasury grant was offered as an alternative to the ITC for companies that didn't have any kind of reasonable tax liability. So they would just have a grant equivalent, on a cash basis, to the investment tax credit.

So this particular chart looks at the wind cost without those impacts. And then as we'll see later on, the ITC, PTC, and Treasury grant have a huge impact on the cost of hydrogen you can produce in this manner.

[Next Slide]

So for grid pricing, you can see here in the chart, in the lower right—we have—this is for the PJM market. These are locational marginal prices, which were used for all five electricity markets, except for ERCOT, for which we used market clearing price, since in the middle of the analysis year, they switched their pricing methods.

But you can see here the month of the year and the hours of the day. You can see the typical peaks, as you'd expect, in the summer months near the middle of the day for powering air conditioning. And in the winter months, you also see some peaks—probably due to heating demand, things like that.

We did not look at ancillary markets. So these are market clearing prices in the energy markets, not in the ancillary markets. We did, however, as part of the experimental activity with this project, show that electrolyzers are capable of providing demand response that's fast enough to provide ancillary support necessary for a grid operator, an ISO.

[Next Slide]

So you start with the start that we have here, which is kind of messy. And what we did is—we simplified things a little bit to make it make more sense. So if you can look—this chart is for ISO New England in particular. We classified all of the prices as either peak, partial peak, and off peak. And these are defined as one and two standard deviations off of the mean price for the entire summer or winter period. And you can see we defined summer as going from June 1st to September 30th.

[Next Slide]

So the results we've seen, if you look here at the Class 3 through 6 wind sites and the cost of hydrogen—blue bars show you the range of hydrogen cost you have without any effects from the investment tax credit and production tax credit.

When you do have those enabled, the PTC—that's what's here in pink, and you can see those relative to the distributed and the centralized cost targets for DOE for 2015. What this shows you is that there's a huge impact from the ITC and PTC.

So Wiser and Bolinger found that those three things combined just generally reduced the cost of wind power about $0.02 per kilowatt hour. However, we found that $0.02 per kilowatt hour resulted in nearly a $1.00 per kilogram reduction in the cost of hydrogen over all the sites. So you can see that without the PTC and ITC, none of these sites, up to Class 6, actually meets the distributed class target—although some of the Class 6 wind sites come close.

When you add the PTC in, even Class 4 wind can hit the distributed target, and Class 6 wind—the mean is just about at the centralized target. So the thing that we've found here is that these things are really—these incentives are really crucial to making a scenario like this work. And luckily, as we all know, or most people know, the PTC has been renewed for another year by Congress.

[Next Slide]

Going on to the sensitivity analysis, we did look at the base case, which included wind turbine capital costs of $2,000.00 per kilowatt, electrolyzer energy use of 50 kilowatt-hours per kilogram, capital cost at $408.00 per kilowatt, wind form availability at 88%, and an electrolyzer capacity factor of 98%. Again, we want to run the electrolyzers at their full power as much as we can to get the best capital utilization out of them.

So we did a three-level, five-factor sensitivity analysis. And the costs we just varied 20% off of what the nominal was. For some of the energy use values here, rather than sticking with the straight 20%, we used some values that make sense from a physical point of view. Because you're not going to get too much higher than 60 kilowatt-hours per kilogram in a large electrolyzer like this. Although it may be possible someday.

[Next Slide]

So this shows the results of the sensitivity analysis for one particular site in New England that we randomly chose. What you see is that the wind capital costs here—varying the wind capital cost 20% has a relatively large swing in the cost of hydrogen.

So here are our nominal cases here in the middle, which is just over $4.40 per kilogram. And the wind capital costs then—if you decrease the wind capital by 20%, you can be producing hydrogen at $3.80 per kilogram, which gets you a lot closer to the DOE targets, depending on which scenario you're looking at.

The next biggest sensitivity here is, of course, the electrolyzer consumption. So the more efficient we can make the electrolyzers, the lower cost hydrogen you're going to be able to produce. Because the primary feedstock you feed into an electrolyzer—for those of you who aren't familiar with the process—is electricity and water, electricity being the most expensive of those feed stocks. So to the extent we can decrease that cost, you can produce lower-cost hydrogen. Electrolyzer availability and wind availability—we didn't vary those sensitivities very much, but they didn't have very much of an impact either.

[Next Slide]

So for those of you who are following along still, if you go to this URL that I have listed here. What we did was take the results of this analysis. And, initially, we had put it into a paper, which is great. But it's maybe not the most friendly way, the most innovative way to distribute the results to people. So the rest of the presentation today, we're going to focus on the results explore that we created.

So you can go to this URL right now. And it is live. I can, in fact, go there for you.

[Navigates to www.nrel.gov/hydrogen/production_cost_analysis.html.]

So you can see what we did is take the analysis and overlay on top of it a Google map that shows you where all the 42 sites are, and gives you some control over exploring the analysis. So there's some explanation up here.

And the paper that goes along with this is linked right here as well, so you can pull the paper up and see a lot more detail about this analysis—our methodology and some more insight into our results. But this really gives you more control and a better view into what the results are and how you can use them.

And, in fact, we found some surprising things. You can zoom in—all of Google's—the goodness that comes along with their map program is available to you, so you can zoom in, of course. And you can turn on the train view, and you can turn on the street view, and you can see exactly what the wind site that we're looking at looks like.

So in this particular case, it's pretty empty and may be a good place for a wind farm. So let me go back to PowerPoint here. So generally the way this website is set up, you can see red circles are sites that don't meet the DOE targets, depending on the assumption that you've placed on the analysis here, up at the top, in the control panel. Green means it does meet the target.

And, furthermore, the sizes of the circles scale with the cost of hydrogen, so the smaller circles equal lower-cost hydrogen, which is great. Right?

[Next Slide]

So some of the controls you have available. As I mentioned, there were four scenarios that we used. There was power-balanced, cost-balanced. And there was the question of whether you purchased peak summer electricity or not—yes or no. So you can pick any one of the four analyses here, and it will update for you.

You can also change the DOE cost target that you're looking at—either the central target or the distributed target—and that will change the color coding on the circles accordingly. You can also turn on and off the PTC, ITC, and Treasury grants.

And as you can see on the map—we can go do that right now—we have the PTC turned on right now, and we're comparing to the distributed target. If you turn the PTC off, all of your green circles go away. So, again, that shows the importance of having those incentives in place for a production like this.

So the other thing—as I mentioned in the scope for this analysis, we didn't include compression, dispensing, and storage cost. Because we really wanted to look at hydrogen production and focus on that.

And CSD—these costs are typically things that people talk about when they talk about using hydrogen as a vehicle fuel, which right now is a very, very small market for hydrogen use in the country. Things like the petrochemical industry, pharmaceuticals, metal refining, things like that are much, much larger uses of hydrogen.

So we did allow people to put in CSD costs they may have done for their own analysis. The $2.00 per kilogram here comes from an independent study, again, that was done in 2009, looking at what CSD costs could be. So you can either click the $2.00 per kilogram and add in sort of the default, or if you have another number you want to put in, you can put that in as well. And it'll show you the results immediately, so you can see what the effects would be.

And we really did this just because it gives the users, the potential audience here, much more power and much more ability to control and explore these results, then ask questions of them, and then get their own answers immediately. I mean of course we're always available for questions. But if you can get the answers yourself right away, then most people prefer that.

So some things that we saw that were interesting—Oh, I will say—when you mouse over a site, you will get a popup that shows you some of the metadata about the site. So you'll see the site ID. And these site IDs go along with the eastern and western wind data set. So you can look up the source wind resource data that goes along with it.

Which scenario was used? In this case, it was power balanced. And we are approaching summer peak electricity. Whether the Treasury grant is on. What the hydrogen cost was. The wind class. The wind capacity factor and the wind cost in dollars per kilowatt-hour. So you can see that for any site that you mouse over—again, giving you a lot more control and insight into it, without having to read a dry, technical paper.

[Next Slide]

So some things we found that were surprising, that we didn't really expect—but when you add all the extra information that comes along with the Google maps API, you really start to see some things that wouldn't necessarily jump out at you before. So this is the case that I zoomed into earlier in southern California. You can see the mountains here are really shading these three potential sites.

And although these are all the same electricity market, and they're nearly the same wind class, the hydrogen cost here in the mountains or behind the mountains is about $4.50 a kilogram. Whereas here, we're at $3.00 kilogram. You sort of have this wind tunnel effect, basically, that's going to give you a much better wind resource, and make the difference between meeting a DOE cost target and not. So that's some of the interesting—

[Break in Audio]

...for the website.

And, again, the URL's up there in the corner. If you want to go to the website and try it out yourself, while we're on the webinar here, you can go ahead. So you see some metadata about each site. You see the identifier.

And that goes along with the identifier in the eastern and western wind data sets, so you can look up that actual wind data that was used, if you want, which analysis scenario was used, whether the Treasury grant, the PTC/ITC, was turned on, the cost of hydrogen, the wind class, the wind capacity factor, and the wind cost. So if you turn that on again, you do see about $1.00 per kilogram at most sites reduction in the cost of hydrogen, just by turning that on.

Again, here in southern California, having the power of being able to look at this stuff geospatially and see all the extra data that comes along essentially for free, with the Google Maps API, you can really see some details that wouldn't reveal themselves otherwise. So, again, in this case, we've got four sites—they're all in the same electricity market, but they're all very close to each other geographically.

But these sites back here are shaded by the adjacent mountains and may not make sense. So these sites are producing hydrogen at about $4.50 a kilogram, whereas this one here, in the valley, is producing at about $3.00 a kilogram.

So, again, as any wind developer will tell you, geography matters. You need to understand your wind resource very well. Things that can disrupt your wind resource are going to be important. And, again, one of the beautiful things of Google—you can zoom right in to street view and just see what's there.

And in this case, in Illinois, this is actually a working wind farm. So you can see the turbine in the back. And if you actually were to zoom into this site and scroll down the street, you can see the substation all the wind turbines are feeding into. It's all there.

[Next Slide]

Again, some of our collaborators in industry that we work with—so, again, there's the Fuel Cell Technologies office. Again, we thank them for supporting this work. Xcel Energy, whose been a really good partner of ours for a very long time. Giner Electrochemical Systems, who makes electrolyzers. We've also worked with testing machines from Avalence and Proton OnSite. These are all domestic companies who make electrolyzers.

[Next Slide]

Again, in summary, with the PTC, ITC, and Treasury grants, you do see about $1.00 per kilogram improvement in the cost of hydrogen. And even though the Treasury grant has expired, that really only went to 12 wind sites across the country anyway—12 wind projects. So having the Treasury grant be gone shouldn't have much of an impact on the results here.

And as I've said, the PTC was renewed by Congress for another year, and the ITC is still intact. Looking at Wind Classes 3 through 6, you can produce hydrogen from $3.74 a kilogram to $5.86 a kilogram unsubsidized. That still doesn't meet the DOE's centralized distributive production targets.

But as we saw in the sensitivity analysis, the biggest effect there is the cost of—the wind capital cost, and then the second is the electrolyzer efficiency. So to the extent that those relative industries are making progress in those things, the cost of doing a plant like this will come down.

[Next Slide]

And, again, there are all of our references.

[Next Slide]

This is me. There's my email address. Feel free to send me any questions that I'm not answering here, online—or if you want further information. And with that, we'll go to Eric for questions.

Moderator:
Eric, are you there? We must have lost him in the shuffle, Chris. I thought he was there.

Chris Ainscough:
He was.

Moderator:
Eric?

Eric Miller:
Can you hear me?

Moderator:
Oh, there you are.

Eric Miller:
Can you hear me?

Moderator:
Now we can.

Eric Miller:
Alright. Sorry. Alright. Sorry. I was yelling at you. Okay. Alright. Thanks. Thanks, Chris. Good job. I have a number of questions. And Alli, you let me know if we're getting close to our time limit.

Moderator:
Alright. Sounds good.

Eric Miller:
And anything we cannot get to, we have an option to address offline. Is that possible?

Moderator:
Yes, that is possible.

Eric Miller:
Terrific. Alright. Let's go through some of the straightforward, easy ones first. Chris, could you put up the URL again and share it with everyone, so they have a chance to write it down. We'll get through that one first.

Chris Ainscough:
That's an easy one.

Eric Miller:
Yeah. Let's take care of that. We'll give them a few seconds on that. Alright?

Chris Ainscough:
It's this URL right here. You can go ahead and type that in to your favorite browser, and go ahead and play around with it while we're here.

And maybe you'll have other questions from using it. Go ahead and submit those to the webinar, and we'll see if we can pick 'em up.

Eric Miller:
Sounds good. Alright. There's another question we had—an earlier question. There was a question regarding Slide 7. I think it was just to review the information on capital cost on Slide 7 again. So could you review that for us again?

Chris Ainscough:
Yeah. Let me switch over to another machine here real quick and pull up Slide 7 for myself, so I can see what we're looking at. Meanwhile, I can leave the URL up, so everybody else can see it.

Eric Miller:
Thanks.

Chris Ainscough:
So Slide 7. Okay. So on Slide 7—and the question is on capital costs?

Eric Miller:
Yeah. I think maybe—could you pull it up again for us? We may have had enough time for the URL.

Chris Ainscough:
Okay. So we'll go that way then. Okay. And what's the question?

Eric Miller:
Well, I think the question was to review the information on capital costs and the hydrogen per megawatt. I think they just needed to look at it again.

Chris Ainscough:
Okay. Yeah. So, again, we're looking at—the wind capital costs come from the annual wind cost summary that Wiser and Bolinger do, which is listed in the references. So you can pull that up from the paper or from the website. So we took those costs directly from there.

The system sizes—the range is from 1,000 to 50,000 kilograms a day. Pretty much the largest industrial electrolyzer that's made today is made by a company called NEL Hydrogen, who makes a unit that's about 1,000 kilograms a day. Slightly over.

And based on a 2009 independent study that was done by electrolyzer manufacturers, they determined—and that's also in the references. You can pull that up as well. They determined that the electrolyzer costs are going to be pretty linear in the 1,000 to 50,000 kilogram a day range.

So if you were to do a 50,000 kilogram a day station, you would have about 50 of these electrolyzer modules, if you were going to use that particular company—which by no means would you have to. Right?

But it's a very modular approach. Things are built into ISO containers. You can drop them onsite, hook them up, and get them running.

Eric Miller:
Great. So this leads into another question, Chris. The question is: what is the size of the electrolyzer being considered, in megawatts? I think that's on the analysis basis. And what units are integrated in that to reach those levels?

Chris Ainscough:
Yeah. So I think I may have answered that, but we're looking at 1,000 kilogram a day unit. And we have the size of the electrolyzer—

[Inaudible]

Yeah. So 106 megawatt electrical requirement they were looking at. And that's for the designed capacity of 51,000 kilograms a day. And, again, the efficiency of the electrolyzer—for the base case, we looked at 50 kilowatt-hours per kilogram.

And, again, the sensitivity analysis—we pushed that up and down. Fifty kilowatt-hours per kilogram, including balance of plant, drying, and things like that is a pretty good number. From smaller units, high purity units, you can get more efficiency.

And you can get more efficiency with PEM generally than alkaline. But alkaline systems scale much larger in general.

Eric Miller:
Right. Chris, that leads to another question, maybe. Do you have, off the top of your head, the conversion from—to a percentage efficiency?

Chris Ainscough:
So on a lower heating value basis, 33.3 kilowatt-hours per kilogram is the best you can do. That's the same as the—I think that number's right. Yeah, that sounds about right. That's equivalent of 120 megajoules per kilogram, which is—that's the energy content of hydrogen.

So if you were to have a thermodynamically 100% efficient unit, you would be producing at about 33 kilowatt-hours per kilogram.

Eric Miller:
Great. Another question. Are the sites on the Google Map existing or proposed wind sites?

Chris Ainscough:
It's a mix. Some are existing, as you saw on the street view. Some may be proposed, and some are just sites where we have data on the wind resource.

Eric Miller:
Okay. Continue. This is Genevieve?

Genevieve Saur:
This is Genevieve.

Eric Miller:
Oh, it's Genevieve. Alright.

Genevieve Saur:
The wind sites were actually—they did a lot of—they pulled a lot of data, and then they restricted those sites based on other use, like land usage and stuff. So this is actually a trimmed down set of wind sites that our wind program has put together.

And it tries to say where there are potential wind resources that actually could be developed. So the full list of wind resources has been weaned down quite a bit from everything to what they consider being the most likely areas that could be developed.

Eric Miller:
Alright. Thanks, Genevieve. Several more questions. I think we have some more time to continue. Right?

Chris Ainscough:
Yeah, we're good.

Moderator:
Oh, yeah. We're good on time. We have about 15 minutes.

Eric Miller:
Terrific. I think we can get to many of the questions. Can you answer the question—is high pressure PEM electrolysis being considered, considering the troubles or the challenges with compression of hydrogen?

Chris Ainscough:
We didn't look particularly—again, so the compression piece of this puzzle, we didn't include here. We're looking at hydrogen that was produced at the output pressure of a typical large industrial electrolyzer, which is not high pressure.

So for the audience who may not be familiar, when you're talking about vehicle fueling, the automotive industry is moving toward 700 bar fueling, which is 10,000 PSI. Out of a typical PEM electrolyzer, you can get 400 to 500 PSI without doing anything too special. Out of an alkaline, maybe 200 to 300 PSI—something in that range. So we didn't look at the compression piece in particular.

However, I will say that aside from this project, we are, at NREL, looking at issues with compression. Because, again, we do see, through our technology validation and data collection activities, which I'm also—Genevieve and I also are a part of—we do see that hydrogen compressor reliability is a major issue, in terms of the cost of maintaining any kind of vehicle fueling station. We didn't do it in this work, but there is other work that we're doing to address that.

Eric Miller:
Right. And Chris, I might add some additional information on top of that. The DOE portfolio does have projects that are looking at the potential of producing electrolysis at higher pressure, and looking at the trade off to study—what are the limitations to doing that? And do you get a cost benefit versus doing separate compression?

So it's a good question. And the answer is being determined by current research.

Chris Ainscough:
Yeah. And I will also add that the experimental branch of the wind-to-hydrogen project is slated to test a high pressure electrolyzer—high pressure alkaline electrolyzer, actually, later in the year.

Eric Miller:
Okay. Alright. Let's keep going. Could you explain what wind classification you are referring to? Apparently there's confusion with the IEC. Is it not IEC? Or is there a different classification you're talking about?

Chris Ainscough:
Hmm. Good question.

Genevieve Saur:
Yeah. IEC is turbine ratings. It relates to what kind of wind profile a wind turbine can be in. The wind classes are basically the wind density at a site. I don't remember the figures off the top of my head. But basically, a Class 4 is, I think, 7.5 meters per second average. So.

Eric Miller:
Okay. Thank you for that clarification. Let's keep moving. Can you comment on wind versus solar for hydrogen production analysis?

Chris Ainscough:
So this analysis didn't look at solar. We have seen—again through the experimental arm of this project—we have done work to reduce the cost of producing hydrogen from sun, basically by direct coupling.

So if we go back—I'm going to go back to the overall system layout. Back. Back. Back. Alright. So if we look at this—see, in a typical case, you've got the PV array, and then you have a DC-to-DC converter, which could then go to the electrolyzer.

If you're just using off-the-shelf components, with no modification, you could have something as inefficient as DC-to-AC here, and then AC-to-DC back into the electrolyzer. Because electrolyzers—they're electrochemical systems, and they operate on a DC current. So you need to feed them DC.

So an experiment our colleague Kevin Harrison did was to take this stuff out and literally run a wire from our PV array into our electrolyzer, and get rid of all that stuff. And he found that you actually can, under lower radiance cases, get more energy capture that way, and also lower capital costs.

On the question of large scale, large scale hydrogen production from sun, it's really going to boil down to what your dollars per kilowatt-hour is. You know? How cheaply can you produce the electricity?

And in general, where we're at right now, wind can scale to huge, huge sizes more cost-effectively than solar PV can right now. Does that cover the question?

Genevieve Saur:
If I can just jump in. Yeah. The other thing is that solar can be more easily integrated into the electricity grid in general, just because the sun is shining during the middle of the day, when more electricity is needed on the grid.

Chris Ainscough:
Right.

Genevieve Saur:
So, in general, it's a little easier for them to take that solar energy onto the grid directly, rather than necessarily go through a process like this.

Eric Miller:
Okay. Thanks. I think we still have a few more minutes. And we have some more questions. Could you address this topic? What plans, if any, are there for hydrogen fuel production from wind power to supply the expansion to 68 hydrogen car refueling stations in California by 2015?

Chris Ainscough:
That's a good question. I don't know that wind is a central part of any of those. So another one of the activities we do at NREL that's also sponsored by DOE is to collect data on the infrastructure that's being put into California.

And those stations that are either working or being proposed or built rely on a variety of technologies. There's one station that uses digester gas. There are some that use delivered liquids. Some use electrolysis. There's one in Torrance that uses the pipeline that actually runs near the station.

So the stations really use a variety of technologies, and it all boils down to what makes sense at that station—at that location. So I'm not aware of any plans to incorporate wind into any of them at this point.

Eric Miller:
Well, I mean it's interesting. You do show a number of points in the Southern California area where this would make sense. So there certainly are options to integrate the wind-to-hydrogen as a part of this overall portfolio.

Chris Ainscough:
Right. And, again, we were looking at big—this analysis looked at big, centralized plants, which you're not going to put in a retail location—although you could.

As I said, you could with a single wind turbine, if you can get past the "not in my backyard" issues. If you can get that wind turbine close to your hydrogen station, it can produce enough hydrogen to really satisfy the near-term need for vehicles.

Eric Miller:
Okay. Well, we have a little bit going in a different direction. We talked about the solar as an optional analysis or alternative analysis. Is NREL also looking into ocean energy-based hydrogen production costs? For example, OTEC or Wave?

Chris Ainscough:
We are not. I know there is other work going at NREL looking at producing electricity that way. But we haven't looked at wave-based hydrogen yet. Although, I will say there's a project we're involved with in Hawaii, looking at hydrogen production from geothermal, however. You know?

Hawaii's a place that is unique, in that every island—those of you who know Eric—he comes from Hawaii. Right? Spent a lot of time there. Each island is on its own electrical grid.

And Hawaii has a lot of natural resources to bring to bear—solar, wind, and geothermal. So there is geothermal activity that's going on there to produce hydrogen from that—again, for vehicle fuel.

Eric Miller:
Uh-huh. That's right. You know, wherever there's cheap electricity, or wherever something could be curtailed to render geothermal, that makes a lot of sense—to produce hydrogen.

Chris Ainscough:
Right.

Eric Miller:
Okay. Got a few more questions here. Okay. Sorry. I'll keep going now. Have you done a similar analysis based on hydropower? And I'm thinking that must just be pretty much grid electricity at this point. Hydropower? Is that the baseline for grid electricity in many places?

Chris Ainscough:
It is. Again, if you go to FERC's website, you can see the way the electric grid is broken up in the country. And the availability of cheap hydro-based power is going to be in places near the resources. Right? The Hoover Dam. Up in the Buffalo/Niagara area, electricity's very cheap because of hydropower.

So, again, we haven't looked at a specific analysis of hydropower. But, again, it all boils down to how cheap your feedstock is. And, again, your most expensive feedstock is electricity.

Eric Miller:
Right.

Chris Ainscough:
You need water, of course. Of course, in places where there's hydropower, water's generally pretty abundant. So hydropower could actually make a good case. Because the electricity tends to be cheap.

It tends to run—you know, hydropower's a great renewable resource because it's not subject to the vagaries of day-to-day variations and hour-to-hour variations, like wind and solar are. So you can get a lot more stable profile than you would out of wind. And the costs tend to be generally pretty low. So that could make a lot of sense.

Eric Miller:
Uh-huh. Okay. I think we have time for a few more of these questions. Have you compared the wind variability with electricity load? Averaged over a given time period, how much wind electricity can be used to meet electrical load? And it continues—over days, over months, over weeks, etcetera.

Chris Ainscough:
So we can go into one of the profiles. Pull up one of the profiles again. And it doesn't give you exact percentages of what amount of electricity you're using for hydrogen versus what you're exporting.

But you can see sort of an eyeball average here for this particular site. A fair amount of your electricity is coming from your wind turbine to go to hydrogen production. But you're also exporting some too.

Eric Miller:
Right. Well, questions are actually still coming in. So we'll just keep going. Okay. Genevieve, I'm sorry to interrupt. Continue.

Genevieve Saur:
I was just going to add. I think in the paper, there's also a chart that looks at kind of the percentage of wind that's going into the electrolysis versus onto the grid for all the sites.

Chris Ainscough:
Okay.

Eric Miller:
Very good. Have you done any volume of water consumption analysis as a part of this?

Chris Ainscough:
We didn't look at that specifically. You know, the water volume consumed is—I don't have a slide here. We can talk about it. But the volunteer consumed is a very linear function of the amount of hydrogen you're producing.

Because it's all conservation of moles. Right? All conservation of mass. So, of course, having water—that is a feedstock you have to have. So if you're in a place that doesn't have water, or water's very expensive, then that's going to add to your cost.

But generally—I mean water—if you were to take a bucket and fill it with water, and take the same size bucket and fill it with liquid hydrogen, the bucket with water in it would actually have more hydrogen in it than the bucket of liquid hydrogen. So water is a very, very good carrier of hydrogen.

Eric Miller:
Okay. And you're right. We can back out those numbers. I'm sure the water costs are integrated into cost analysis in general.

Chris Ainscough:
Right.

Eric Miller:
Did you consider sites near existing hydrogen pipelines and production sites? The distance of the site in your study to users may have significant impact on costs, and defines the point of the DOE targets to do with transportation cost.

So I guess that's a good question. Does the analysis allow for that to reduce transportation cost by siting near existing productions or pipelines?

Chris Ainscough:
We didn't look at that in particular—although the question is absolutely correct that to the extent that you can locate a site like this near an existing hydrogen pipeline, you're going to drastically reduce your costs.

Because your compression, storage, and dispensing costs are essentially none or very little. Right? So that is something we could consider for future analysis, if we carry on with this. So it absolutely makes sense.

To the extent you can get the generation close to the point of consumption for anything, really, but definitely for hydrogen, you're going to reduce your costs.

Eric Miller:
Right. Okay. Maybe one or two more questions, Alli?

Moderator:
Yeah. We have about four or five minutes. Yeah. That'd be perfect.

Eric Miller:
We've had quite a good variety of good questions. Let me throw it in a different direction to see—this is an older one, so let me paraphrase it, since I can't read my own writing.

Have you done analysis of energy storage—using hydrogen as energy storage versus pumped hydro, for example—what the overall cost or effectiveness would be—efficiency using this as an energy storage mechanism—using hydrogen versus pumped hydro from the electricity from the wind?

Chris Ainscough:
So NREL had done those studies. Those were not part of this study. And jump in if I'm wrong, Genevieve. But I think Mark Melaina had done something like that recently, or possibly Darlene Steward. So those studies are out there, and we have done them. But they weren't part of this.

Genevieve Saur:
I think it was Darlene.

Eric Miller:
Okay. So there's a separate NREL study that will address that question explicitly?

Chris Ainscough:
Yeah. And I think beyond looking at pumped hydro, they also looked at compressed air energy storage, some other—sodium sulfur batteries, other big ideas for storing grid power and doing wind arbitrage. You know?

I will say that the round trip efficiency of doing hydrogen storage en masse, like this, is not—it's not really good. But the fact that you can use the hydrogen for many other things—you can produce a valuable feedstock that you can sell in a variety of different markets—is one thing that puts that sort of solution separate from a battery solution or a pumped hydro case or anything like that.

So there are a lot of co-products you could get out of a situation like that, where you're producing hydrogen for arbitrage.

Eric Miller:
Uh-huh. Okay. I'm trying to look up one final question here. And we've got several left. I apologize. We will not be getting to all of them. Okay. This is probably an easy question. I think I could even answer this one. What is the value of curtailed wind?

Chris Ainscough:
The value of curtailed wind? Well, it very much depends on the market. So the way the energy markets work—and depending on which part of the grid you're in, which part of the country, there are different markets.

And the markets generally are defined by the length of the market, in terms of how fast the market responds. So you have energy markets, which are slower markets. You have ancillary support markets and regulation markets, which tend to be very fast—minute-by-minute or five minute—they may settle the market every five minutes.

So it really, really very much depends on what the consumption is nearby and what other resources are there. So when the wind comes up in the Dakotas, it comes up pretty much everywhere. So you have a lot of wind capacity come up.

And as Genevieve pointed out, the nice thing about sun and solar power is: generally, the consumption tracks along with the production. Right? I mean the sun is up. People are up. That's when the consumption is highest.

But wind often is higher at night. So it really depends on where you're at. But we do know that there's a lot more wind power that we could be using, that we're not because the grid doesn't need it. So to the extent we can find ways to execute arbitrage effectively, we can recover that much more stranded capital that's really not doing anything. Could be a big economic benefit.

Eric Miller:
Great. Yeah. I think that's a good benefit for the electrolysis of water using wind electricity, especially curtailed wind. On that note, Alli, I'll hand it back to you. I think we've reached the end of our hour. I'll give it to you for closing notes.

Moderator:
We have. Thank you so much. And you guys, I'm so sorry. The beauty of technology—it either works with you or against you. In this case, for this webinar, it's working against us. So I appreciate your patience as we work through that.

And just as a reminder—the slides, as well as the recording webinar, which was probably affected a little bit by the Internet disconnect, will be posted to our website in about a week—hopefully sooner than later. So I will also send an email to everyone that registered for the webinar, when those have posted to the website, with the link.

So thanks again. And just a reminder—our next webinar is Tuesday, February 12th. So we just encourage you to check back and see if that is something that you'd be interested in. So thanks, Chris, and thanks, Eric, and thanks, Genevieve for your patience as we went through this.

Chris Ainscough:
Thank you, everybody.

Eric Miller:
Thanks, Alli.

Moderator:
Alright. Bye-bye.

Chris Ainscough:
Bye.

Genevieve Saur:
Thank you.

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Content Last Updated: 07/19/2013