April 12, 2021 -
by James M. Berger and Deanne Barrow
Norton Rose Fulbright
Despite widespread excitement at the prospect of green hydrogen being the next multi-trillion dollar commodity, the reality is that a number of challenges will have to be overcome before the gas can reach its full potential. Hydrogen from renewable sources costs two to four times more than fossil fuel-based hydrogen. The United States lacks a comprehensive hydrogen strategy as has been adopted by many European countries. New pipelines will have to be developed or existing infrastructure retrofitted to transport hydrogen. Law and policy will have to adapt to accommodate advances in technology and business structures.
Despite these challenges, the Biden administration has hinted that hydrogen will play a key role in achieving the federal government's decarbonization goals. At the state level, California and New York have stepped into the vanguard with generous incentives and favorable policies. Three experts discussed the prospects for hydrogen in the US during a livestream panel discussion in early March. The panelists are Sheldon Kimber, CEO of Intersect Power, Karen Lee, senior counsel at Southern California Gas Company, and Sanjay Shrestha, chief strategy officer at Plug Power. The moderators are James Berger and Deanne Barrow with Norton Rose Fulbright.
MR. BERGER: Sheldon Kimber, Intersect Power is a solar developer. What is it doing with hydrogen?
MR. KIMBER: Intersect Power is a utility-scale solar and storage developer moving into ownership of its own assets. Our development portfolio is about 2.5 gigawatt-hours of solar PV and 1.5 gigawatt-hours of batteries. After construction, we will become an independent power producer and own our own assets.
We see hydrogen as the next step in our evolution from being a developer of solar to being an owner of solar and then eventually being an owner and operator of clean infrastructure assets. That means hydrogen, carbon-capture-and-sequestration and desalination projects.
Our view is that clean, cost-effective electricity is the nexus for decarbonization. A series of technologies, hydrogen being one of them, will bridge into other segments of the economy that are much harder to decarbonize, such as transportation, fuels, aviation and industrial uses.
Intersect will be a developer and owner not only of the solar and renewable plants that power hydrogen production, but also of hydrogen production.
MR. BERGER: Karen Lee, SoCalGas is the largest natural gas distribution utility in the country, serving more than 20 million consumers. What is it doing with hydrogen?
MS. LEE: We believe that gas distribution companies will be required to provide cost-effective transmission and distribution of hydrogen. We have the gas pipelines and related infrastructure. We think we are well-positioned to help with this energy transition.
We have also been a long-term supporter of research and development on the clean energy front, including research into hydrogen. We are actively working on opportunities for the transportation of hydrogen and for the base-load and resiliency components of hydrogen, including use at our data centers and other locations with high demand for hydrogen fuel cells. We are supporting the protonic exchange membrane – PEM — fuel cell development for transportation and stationary use. We are also looking at the ability of our natural gas pipeline infrastructure to play a role in hydrogen storage.
We have already moved forward with modernization projects at many of our key stations, including our Moreno compressor station, to create opportunities for advanced renewable energy. At Moreno, for example, we added an electrolyzer that can convert curtailed renewable energy into green hydrogen that is then put into on-site hydrogen storage tanks or used to run PEM fuel cells and hydrogen vehicle fueling stations.
We are in the midst of a hydrogen blending demonstration program and are working with our regulators to establish a safe target for blending hydrogen into the natural gas pipelines.
We are working on a demonstration of an "H2 hydrogen home" that will showcase various opportunities for consumers to use hydrogen in their day-to-day lives. We are also field testing various other technologies on the research and development front.
MR. BERGER: Sanjay Shrestha, Plug Power is clearly in the hydrogen business. Tell us what it is doing.
MR. SHRESTHA: We have been at it now for two decades. The real inflection point for the company happened sometime between 2014 and 2015. We believe we have created the first viable commercial market for hydrogen fuel cells. From 2014 to 2020, we experienced a 40% growth rate. We have the highest number of fuel cell systems out in the field: more than 40,000 systems. We have run our systems more than 600 million hours, which, if you assume five miles an hour even from a fork lift, is three billion hours of operating data.
We are taking costs out of the system. We have improved the reliability. We have done all of that with customers like Walmart and Amazon. On top of that, we have built more hydrogen fueling infrastructure than anybody to support material-handling and distributions operations at Amazon, Walmart and other large customer sites we are serving. We are the largest user of liquid hydrogen in the world today. We consume about 40 tons per day.
In 2020, we took important strategic steps to expand our presence and role in the green hydrogen ecosystem. We acquired a company that is in the PEM electrolyzer business called Giner ELX. We also acquired the only private company that has successfully built a large-scale liquefier. With those two acquisitions, we have become a vertically integrated green hydrogen generation company.
We are planning to build a first-of-its-kind force-majeure-resistant hydrogen network here in the United States. We are looking to build multiple green hydrogen generation plants throughout the US.
We have also been very busy establishing a global presence. We announced a partnership with Renault that will be our European platform and take us further into the fuel cell vehicle business. There will be a co-branded Renault and Plug Power light commercial vehicle. We have a partnership with the SK Group, one of the largest conglomerates in South Korea, that gives us an Asian platform. We also recently announced a partnership with Acciona that fully expands our hydrogen generation business into the European market.
MR. BERGER: There are three main use cases with a lot of sub-use cases for hydrogen. They are transportation fuel, fuel for heating and cooking, and energy storage. Sanjay Shrestha, talk more about the opportunities for using hydrogen for transportation.
MR. SHRESTHA: In terms of the decarbonization of the transportation industry through electrification, one issue is the kind of electrification that will take place. Is it battery electric vehicles or is it fuel electric vehicles? That answer may depend on whether the need is short- or long-distance transportation.
For example, the reason we have had the kind of success and growth we have had in our distribution center and material-handling business is that there are sustainability, environmental and decarbonization benefits. The use case has also been successful because our customers are saving money. They get labor sayings, better productivity and better asset utilization.
We have also addressed one other critical piece of the puzzle in the material-handling market, which is the infrastructure. We have built fueling infrastructure for the likes of Amazon and Walmart. They can drive across the country by leveraging the network that we built and now manage for them.
If you are back at the depot, if you are looking to do less than 100 kilometers a day, or if you are driving a passenger car and charging is not an issue, then a battery electric vehicle makes all the sense in the world. This should continue at least until we get to a certain level of penetration of battery electric vehicles and charging infrastructure becomes a challenge.
When you start to think about payload, fast fueling and range, that is where hydrogen fuel cell electrification becomes meaningful. Owners of light commercial to class 8, middle-mile to long-haul trucking vehicles that carry cargo have a choice to make. They have to decide whether they want to drive around with a lot of batteries to meet the range or whether they want payload benefit and fast fueling benefit similar to traditional vehicles. It is in these areas that we believe the fuel-cell electric-vehicle value proposition becomes very powerful.
We are building a green hydrogen generation network in the US. We will have at least two plants running by the end of 2022. We believe that we will be able to provide green hydrogen fuel at diesel price parity when you take into consideration the efficiency benefit of a fuel cell system. We think transportation will be a very important market.
We also see a lot of applications in other areas, such as long-duration energy storage. We even see the benefit for some of the industrial market, even though that is not our core focus today.
MR. BERGER: Karen Lee, I am a SoCalGas customer. When will I be burning a little hydrogen along with the natural gas in my home?
MS. LEE: Hopefully fairly soon. We are working with our regulators to determine what is a safe level of hydrogen blending. We began hydrogen blending on a pilot scale recently. The target blend is up to 20%. This is well supported by applications in Europe and globally. In California, safety is our first concern. The application to the regulators, for anyone interested in regulatory issues, is Application A2011004.
We are working separately on a demonstration "hydrogen home" that will use solar panels to generate electricity that can be used to produce green hydrogen via electrolysis.
On the commercial customer side, we have projects focused on steam methane reformation. We are working with many of the large transit agencies to enable on-site conversion of natural gas into hydrogen to power hydrogen fleet vehicles.
MR. BERGER: Sheldon Kimber, talk about the opportunities for use of hydrogen to store energy.
MR. KIMBER: Power-to-gas-to-power is the thing about which we are least bullish. We think that putting hydrogen in gas turbines will happen, but almost all of that value will accrue to the existing asset owners because most of the value will be capacity value and not energy value. Those turbines are not going to run for many hours until you try to solve intra-seasonal issues, and then there might be a higher capacity factor for the hydrogen turbines.
At least in the near term, a very small amount of hydrogen will be burned for a few hours. As the resource develops, there will be green capacity payments from community choice aggregators and others that need to go fully green and require a firm commitment through the night. But these types of deals are going to accrue to people like Calpine who will not need to buy a lot of hydrogen from Sanjay or me.
We see the market breaking down into four areas.
One is decarbonization of the existing market. For example, steam methane reformers that make hydrogen produce something like 3% of all global emissions of carbon dioxide. Ammonia production and de-sulfuring in refining are niche applications, but they have large volumes. They present a huge opportunity for using hydrogen to decarbonize.
Moving to energy storage, that will not happen quickly.
On use of hydrogen for transportation, I agree with Sanjay. Fuel cell vehicles that people wrote off a long time ago are potentially a big market, but they are a thermal play.
I said in a speech at the University of California Haas School of Business years ago that we cannot assume every single hot spinning thing on earth will be replaced by some solid-state electronic device or a chemical battery.
We have to be able to put fuel into existing equipment. I think you are going to start seeing people try to burn hydrogen in the aviation and marine sectors. You are going to start seeing people try to make e-fuels, whether you put it in a pipeline as a gas substitute, or you add carbon and go to some sort of longer-chain hydrocarbon or even into ammonia. There was an announcement about an ammonia-burning turbine a couple of days ago.
In the thermal area, we think hydrogen is not only going to go into gas pipelines, but we are also going to see it transferred into e-fuels that can be used as drop-in replacements in existing infrastructure. Those are the markets on which we are focused.
We are spending an enormous amount of time trying to figure out where to put the facilities because the timeline and ultimate end-use market are unclear.
MR. BERGER: Karen Lee, you are doing some work with microgrids and reliability.
MS. LEE: Microgrids are an exciting development, particularly here in California where we have periods of high power interruptability due to wildfires. We are looking to learn, particularly from Japan.
We have a partnership with a Japanese manufacturer as well to explore the opportunities for fuel cells. We have also worked with Bloom Energy on fuel cell use for our high-demand important areas such as data centers. Fuel cells are effectively a form of microgrid. They build resiliency as a back-up source, particularly in instances where the larger electrical grid is subject to periodic interruption.
Fuel cells are well established and have an excellent safety record over the past 10 years in Japan. We think this is an area that, although new to California, has strong potential for relatively immediate application to improve the reliability and resiliency of the power grid.
MR. BERGER: Let's talk about some of the obstacles that each of you are seeing in moving to a more hydrogen-based economy. I think of hydrogen as an energy carrier and not really a new source of energy. We do not mine it. We do not drill for it. You have to use energy to get hydrogen out of water or natural gas.
I see a couple big obstacles: cost and transportation. Sanjay, talk about the cost of hydrogen from fossil fuel sources compared to hydrogen produced from renewable energy?
MR. SHRESTHA: I was hoping I would get that question because I think there is an interesting dynamic in the market.
The cost varies from liquid hydrogen, gaseous hydrogen, merchant hydrogen to captive hydrogen.
Some people believe green hydrogen cost parity is 10 years away and that many things have to happen for green hydrogen to be economical. We are thinking about it in a very simple way, which is we know what it costs us today to pick up liquid grey hydrogen from our key suppliers, and we know what our customers are paying for it. Our biggest input cost for green hydrogen is 24/7 renewable electricity. We are the ones making the electrolyzer ourselves. We have a view on the cost-reduction roadmap for that. We have built the liquefier system ourselves. We have a view on how to think about efficiency and how to think about kilowatt-hours per kilogram for liquefaction.
By offering our end customer the same price that it is paying for grey hydrogen today, we can see 30% improvement in our gross margin for our hydrogen-fuel business. That is something that I think is important for everyone to note. The future of green hydrogen is largely dependent on the cost of renewable electricity. The cost will continue to come down. In some of the key markets that we serve today, we can provide green hydrogen at the same price that our customers are paying today for grey hydrogen, so the use case actually makes sense.
The United States will have to add a lot more renewables to decarbonize the grid. Solar can compete today with gas-fired peakers in terms of the levelized cost of electricity. The cost curve will continue to decline. Therefore, the cost of green hydrogen will continue to go down.
It takes 55 kilowatt-hours of electricity to produce one kilogram of hydrogen with Plug Power's PEM electrolyzer that we are building in our giga-factory in Rochester, New York. We will have 500 megawatts a year of production capacity, 400 megawatts of which will be for our own internal use. With this capacity, we are building a network that can deliver green hydrogen at cost parity with grey hydrogen in certain applications today. By the time our network is complete, we will be able to deliver green hydrogen at cost parity with diesel for freight transportation.
We believe the green hydrogen opportunity is here today and only growing and getting bigger.
MR. BERGER: Sheldon Kimber, talk to us about obstacles to use of green hydrogen for transportation.
MR. KIMBER: We believe that building toy projects, if you will, smaller-scale demonstrations, will happen, but that is not where we are focused.
As a smaller developer, with a smaller team, we are focused on projects at scale in the near future, rather than losing time with smaller, early-stage projects. We look for markets where we can rely on policy changes and technical changes that we think will open up very large-scale markets. By large-scale markets, we are talking about thousands of megawatts of renewables generating hydrogen either through electrolysis or through pyrolysis, which we have not talked much about.
I see at least three regulatory changes that need to happen to open up these large markets. The first is pipeline access. The second is harmonization of the different green gas credits. There are credits for renewable natural gas, and there are LCFS credits. The third is we need market structures that allow us to inject hydrogen into the transmission gas grid, and have a different entity pull out different molecules, just like they pull out different electrons on the transmission grid for electricity. We need to create this kind of pathway, not just physically, but also commercially through market structures.
Establishing a physical and a commercial transportation structure that allows the end use to be in a different place from production would blow this market wide open. We need to move from it being customized pathways to being broadly accepted, direct-style pathways.
The exciting long-term outcome of these regulatory changes is that developers will put hydrogen in the best, cheapest renewable spots in the country and change the concentration of hydrogen in the gas system.
MR. BERGER: Karen Lee, SoCalGas owns pipelines. Sheldon is talking about the ability to pump more and more hydrogen into these pipelines. Does that work for you?
MS. LEE: We will need buy-in from the state legislature and other policymakers in California. We are interested in how our existing pipelines and infrastructure be used to maximize customer value in the form of hydrogen blending and storage. We are also interested in how we can help develop new markets, like use of hydrogen for transportation.
The federal and state governments need to help develop a regulatory roadmap. I think 85% of the hydrogen roadmaps in development are being done in Europe, Asia and Australia. We need the US, with California having very aggressive energy policy, to lead the way. It is similar to how wind and solar moved forward due to government guidance and policy.
Some of the challenges we face today are that the rate structures are not in place to incentivize use of hydrogen for storage. California has more renewable electricity than it needs at times. It has to pay neighboring states today to take the excess power.
We see a real opportunity for hydrogen as energy storage and for our pipelines to store that hydrogen. However, the current rate structures do not support that. For example, there is no retail wheeling rate for energy, retail wheeling being the transmission and distribution of power for another entity.
There are no rates that address the different components of the value that hydrogen could offer as a storage vehicle for the excess renewable electricity. We see a lot of development in Europe in particular with respect to the EU hydrogen commitment, where regulatory and the governmental infrastructure exists to facilitate development in this area. SoCalGas hopes to support similar initiatives in the US. We are doing research and development in this area.
We recently partnered with the California Energy Commission on a hydrogen fuel cell demonstration project in the rail and marine application areas known as the H2RAM grant program. There are four projects that have been selected for funding through the CEC. The CEC has provided more than $10 million in funding, and SoCalGas has provided more than $1.3 million, to test various technologies that can provide clean energy in ports, such as fuel-cell marine vessels, hydrogen refueling stations and fuel-cell locomotives.
We also have some promising, recent legislation here in California that I think can be the framework for progress. We have SB 18 by Senator Skinner that makes hydrogen an eligible resource under SB 100. It directs state agencies to develop a plan for big hydrogen. We also have Governor Newsom's recent executive order that included support for hydrogen-fuel-cell vehicles, and sets a target for 200 hydrogen fueling stations by 2025.
We need strong policy signals from the state to move forward. We need a strong California hydrogen roadmap, paired with a strong national roadmap. We are making inroads with existing state legislation, support from the government and partnerships between the utilities and regulatory agencies.
MS. BARROW: Let's talk in more detail about regulatory and policy developments not just at the state level, but also at the federal level.
At the federal level, there is optimism that the Biden administration will be a champion for hydrogen. The president has already laid out a goal of decarbonizing the power sector by 2035. The US has rejoined the Paris climate accord. Last week, we heard the US secretary of energy say that the DOE is revitalizing its loan program and that one of its areas of focus will be hydrogen.
The question for the panel is what would be the most effective policy or regulatory change that could come from the federal government to support hydrogen? Sanjay, you start.
MR. SHRESTHA: The fact that hydrogen reduces greenhouse gas emissions compared to traditional fossil fuels needs to be recognized. Any policy should take a long-term view so that the industry can plan accordingly from that long-term perspective.
One area is re-thinking the DOE loan guarantee program. That program played such a big role in helping to accelerate the adoption of solar energy. Bankability went up, and returns improved to equity investors in new technologies. When the cost of capital started to decline, we saw the levelized cost of solar energy also come down. The DOE loan guarantee program is an important tool that can help with capital formation.
Another useful tool is the investment tax credit, which has been helpful for the broader fuel cell industry. If an investment tax credit were available for the green hydrogen generation facility or a production tax credit were offered for the green hydrogen output, that would help.
The reason we are in the green hydrogen business is because of feedback from our key customers. We see the potential to make green hydrogen economical versus grey hydrogen. From Plug Power's perspective, fortunately we are not cannibalizing our existing customer base to move to green hydrogen, a classic innovator's dilemma. We do not have an existing asset that will become a lot less valuable as more and more of the green hydrogen infrastructure gets built. Others may have that concern, but we do not.
MS. BARROW: Sheldon Kimber, same question. What is on your federal government wish list?
MR. KIMBER: I agree with Sanjay. I definitely want the government to look at tax credits. We are currently looking for $1 billion in tax equity financing. I think the right move is a technology-neutral tax credit along the lines that Senator Ron Wyden is expected to propose and that we are hoping will be part of the "Build Back Better" infrastructure plan the federal government is planning to roll out this summer. It would be an absolute game changer.
In addition to a tax credit, the industry would be helped by interstate and intrastate pipeline access and some sort of structure that allows companies to take advantage more easily of the low-carbon fuel standard or LCFS in California.
Another issue is grid charging. The federal government should allow hydrogen electrolyzers to be considered industrial loads. It is not as though the load is being used for making widgets. Something close to the non-generator resource rules that the California Independent System Operator has established for batteries could be appropriate. Those rules allow batteries to charge at wholesale rather than retail electricity rates. Grid energy consumption by the facility could be limited to certain days, and the utility could have the right to direct the electrolyzer to reduce its electricity consumption or turn off completely if necessary. We could do those sorts of things to make charging at wholesale rates more amenable to the utilities.
MS. BARROW: Sheldon, to stay with you, you mentioned easing the path for hydrogen companies to take advantage of the LCFS. California's LCFS is one of the most progressive clean energy programs in the world. LCFS credits are generated when hydrogen is used in vehicles in California.
However, you identified a pitfall that developers might run into in terms of chain of custody. What is the issue and what do you think regulators should do to ease the path to using LCFS for hydrogen that is transported in pipelines?
MR. KIMBER: LCFS is the renewable portfolio standard of the future. California passed an aggressive RPS, and the rest of the nation followed. I believe that a number of climate-conscious states will adopt LCFS programs similar to California's because federal lawmakers cannot seem to do anything but argue with each other on CNN.
We have heard that there is a chain-of-custody issue under the LCFS when an independent power generator puts renewable power on the grid and sells the renewable energy credits or RECs associated with the power to a refinery, for example, that uses the electricity to make clean fuels. The issue is that the refinery cannot show physical ownership of the same electrons that were generated by the renewable power plant.
The same chain-of-custody issue potentially applies to hydrogen injected into pipelines. If I inject hydrogen gas into a pipeline somewhere and a refinery elsewhere takes the hydrogen out and uses it to make fuel, it is not straightforward to claim LCFS credits. To do so, the refinery must file what is called a "tier 2 pathway" application for the California Air Resources Board to bless the pathway. If we can establish a standardized pathway, it would make claiming LCFS credits much more efficient.
MS. BARROW: We have talked about law and policy at the federal level and in California. Let us move to New York, which is Plug Power's home state.
New York has a keen and growing interest in supporting green hydrogen. In your introductory remarks, Sanjay, you said that Plug Power plans to construct multiple green hydrogen facilities, including in New York. Plug Power also has plans for the first giga-factory for PEM also in New York. Why choose New York?
MR. SHRESTHA: Plug Power has been a New York company since its founding more than 20 years ago. We have had a very big supporter in Senator Chuck Schumer. He has been an advocate of Plug Power, of hydrogen, and of fuel cell industry. He played a very big role in terms of us deciding to build our giga-factory in Rochester.
We received a lot of support from the county where we are building the plant and from the New York Power Authority. The site is strategically located in NYPA's low-cost hydropower zone.
The decision to site the project came down simply to the cost of the renewable electricity, which will allow us to produce green hydrogen at a price point that is economical. It will let us provide the hydrogen to our end customers at a similar price to what they were paying for grey hydrogen.
New York also makes sense because of the "Climate Leadership and Community Protection Act," which is the law that establishes an aggressive target of 70% renewable energy by 2030 and 100% emissions-free energy by 2040. New York's goals are more aggressive than even the Paris accord.
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