The DEFR Follies — Cost Of Hydrogen Storage

From the MANHATTAN CONTRARIAN

Francis Menton

Here in New York we have our own unique and special acronym for how we think we are going to make our future emissions-free electrical grid work with predominantly wind and solar generation. The acronym is DEFR — the “Dispatchable Emissions-Free Resource.” When the sun goes down and the wind stops blowing in the dead of winter, we will crank up the DEFR to keep us all warm and cozy. There will of course be zero carbon emissions, because by definition the DEFR is “emissions-free.”

Unfortunately nobody is quite sure what this DEFR might be. There are only a few options. Nuclear could work, but in New York it is completely blocked by regulatory obstruction and the certainty of decades of litigation. Batteries are wildly too expensive and physically not up to the job. That leaves many green energy advocates grasping at hydrogen as the last remaining option. Granted, we don’t yet have any meaningful production of hydrogen from carbon-free sources. But it seems so simple: just use wind and solar generators to run electrolyzers to make hydrogen from water; then store the hydrogen in some big caverns, and burn it when you need it. No carbon is involved. Problem solved!

I’ve had a few posts over the past couple of years commenting on some of the many issues that make this “green” hydrogen fantasy infeasible. This post from June 2022 noted that the cost of making hydrogen from water is unlikely ever to fall below, or even close to, the cost of getting new natural gas out of the ground; this post from August 2024 discussed numerous other problems with hydrogen, like its lower energy density compared to natural gas, and the prospective need for a whole new infrastructure of pipelines, power plants, delivery trucks and consumer appliances.

Now comes along a new study focusing on a different piece of the costs of using hydrogen as a main energy source for the economy. The issue is the cost of storing the hydrogen from the time of its production until it is needed for use. The new study appeared in the scientific journal Joule on October 8 with the title “Carbon abatement costs of green hydrogen across end-use sectors.” (The link goes just to a lengthy introduction and abstract. You’ll need to pay $35 to get the whole article, but the introduction at the link tells you what you need to know.)

Perhaps most significant about this new study is the authors. They are Roxana Shafiee and Daniel Schrag, both of whom work at Harvard and have impeccable climate cult credentials, including multiple appointments at various Harvard sub-schools and institutes (Harvard University Center for the Environment, Harvard Department of Earth and Planetary Sciences, Harvard Paulson School of Engineering and Applied Sciences, Harvard Kennedy School Belfer Center for Science and International Affairs — you get the idea). These are not people who can be dismissed as “climate deniers.”

Shafiee and Schrag correctly recognize that the cost of producing hydrogen from water is just a piece, and possibly a small piece, of the cost of getting useful hydrogen to a consumer at point of use. They criticize green hydrogen enthusiasts for paying insufficient attention to other costs, and particularly to the costs of “storage and distribution”:

Hydrogen generated via electrolysis using renewable energy (green hydrogen) has gained prominence as a potential strategy in decarbonizing hard-to-abate sectors of the economy, in which electrification is technically challenging or prohibitively expensive. Many governments have set policy targets and, in some cases, financial incentives for green hydrogen production, with the expectation that production costs will fall rapidly in the coming decades, providing low-cost carbon abatement opportunities across many sectors. Yet, many recent analyses do not consider the storage and distribution costs of delivering green hydrogen to different sectors or how these costs may vary across end uses.

So Shafiee and Schrag set out to correct those deficiencies. To their credit, S&S have figured out that the costs of distribution and storage infrastructure are highly dependent on how intensely that infrastructure is used. (As far as I can determine, not one of the thousands of people in the vast New York energy regulatory bureaucracies has yet figured out this simple principle.) The more often the storage gets cycled, the lower the charge for each unit of energy stored and then used. S&S note that some sectors, particularly industries like petrochemicals and steel, can cycle hydrogen storage many times per month, thus driving down costs. Unfortunately, the same does not apply to the power sector:

Although low costs of hydrogen storage and distribution (<$1/kgH2) are possible through economies of scale, this requires high utilization of storage and distribution infrastructure, which is not applicable to all end-use sectors. If storage and distribution infrastructure is used at a low rate, costs increase significantly. Salt cavern storage costs increase from less than $0.50/kgH2 to $6/kgH2, on average, if stores are cycled fewer than 10 times per year, for example, in the context of seasonal changes in demand (e.g., heating or electricity generation).

That’s right: hydrogen produced and stored for purposes of home heating only gets cycled once per year at most. To understand the significance of the costs cited, recall that the energy-equivalence conversion factor from $/kgH2 to $/MMBTU (the units in which natural gas prices are customarily quoted) is 8. $6/kgH2 converts to $48/MMBTU. And that’s just for the intra-year storage. Meanwhile, the current price for Henry Hub natural gas is $3.06/MMBTU, and most of it does not need to be stored for any significant period because it gets produced roughly as needed to meet demand.

So kudos to S&S for figuring out that cost of storage for hydrogen is a big and unrecognized issue. But unfortunately, they only go as far as considering intra-year storage. There is also a huge issue of multi-year storage if green hydrogen is to become the backup for a grid powered mostly by wind and sun. In a post on September 28, 2023, I covered a Report then just out from Britain’s Royal Society dealing with issues of long-term energy storage to back up wind and solar generators. The Royal Society had collected weather data for Britain for some 37 years, which had revealed that there are worst-case wind and sun “droughts,” comparable to rain droughts, that may occur only once every 20 years or more. A storage solution to back up wind and solar electricity generation without fossil fuel back-up needs to cover these worst-case droughts.

The Royal Society Report includes the following graph of potentially needed withdrawals from storage to cover these worst case droughts:

The graph shows that of the storage needed for full back-up over the 37 year period of data, fully half would only have been called on twice, and about a quarter would only have been called on once. Perhaps S&S should go back to their laptops to figure out how much salt cavern storage costs per unit of energy stored when it only gets called on once in 37 years. If storage that gets cycled once per year costs $6/kgH2, does storage that gets cycled once per 37 years cost $222/kgH2? The blended cost — between the storage that gets cycled once per year and the rarely-used part that gets cycled only once every 10 or 20 or even 37 years — would look to be around $100/kgH2, equivalent to $800/MMBTU of natural gas. That’s more than 250 times the current price of natural gas, and of course is only the cost of storage. The cost of actually producing the hydrogen would be additional.

I understand that there are people moving forward on setting up some of this hydrogen infrastructure, funded with government subsidies. It’s almost impossible to imagine how much subsidies it would take to make such a system fully functional. It will never happen.