Mitigating strict 45V
Mitigants for the strict electrolytic 45V case
Last week I posted on how strict 45V is going to make expansion of US electrolysis difficult in nearly all locations. Slow deployment will prevent the US from hitting the golden scenario whereby electrolyzers are inexpensive enough that they become a viable way to build renewables without connecting them to the grid to get clean electrons to hard-to-abate end uses.
If you’re unfamiliar with some terms here, check out my “basics of 45V” page.
The recent and very late release of 45V offers some mitigants – the degree to which they are useful, however, is unclear. I’ve heard from a few contacts that 60%-80% EAC coverage is doable with wind in the Midwest and parts of Texas, but I’ve also heard of many intelligent operators that are contemplating suing the Biden administration’s interpretation of this law.
One thing is clear: the Biden, notably John Podesta, turned 45V into a lever to build out the power grid to expand renewables - not to expand the possibilities of hydrogen electrolysis to bring renewables to hard-to-abate sectors. That being said, some projects will be able to move forward. Here are some mitigants to help get projects across the line. The overall picture is that if you are building projects – you need to move fast.
1. Nuclear power – 200MW per reactor carve-out. Eliminates additionality and time matching
2. Qualifying states – eliminates additionality if the state has effective zero emission targets
3. Regional EAC stacking for higher utilization – making use of weather in a wide area
4. 2030 pushback for hourly matching – some grids might get greener
5. Other tactics – grid services
6. Natural Gas Turbine Carbon Capture and Storage (NGTCSS) with 45Q – with upstream abatement
7. Potentially NGTCCS with renewable natural gas – depending on how GREET treats it
Schematic of the major mitigants for 45V H2. Note that most of the graphics use generative AI
We’ll cover each of these in turn – except for the RNG play which I’ll cover inthe future depending on the new GREET model
What the mitigants are for
Electrolytic hydrogen faces two main issues: it’s much more expensive than natural gas based hydrogen and the intermittency of renewables creates issues for end users who need constant supplies of hydrogen.
The inability to operate 24/7 requires additional hydrogen storage – which adds $1-$4 per kg H2. In the US where H2 is sold for $2/kg for existing use cases, this amount of storage cost would break the bank.
Once we have regional H2 pipelines this becomes less of an issue, but we don’t get regional H2 pipelines without first getting H2 construction. We have several chicken and egg problems here.
The 45V credit will help balance the equation here, but in the early years it will not be quick, easy, or particularly economical.
The major mitigants – and their shortfalls
Nuclear power
Pluses:
mitigates additionality
mitigates hourly matching by merit of being 24/7 available
Constraints
Regionally not available in a lot of areas
Not be cost effective in most places owing to grid prices
45V allowed a carve-out for nuclear power – 200MW per reactor with 94 reactors in the US. There are some major caveats however:
The plant must be “merchant” IE selling into the spot power market at least 50% of the time
Average power price in one of the last two years must be under 4.375 cents per kwh
The project has to either be build “behind the meter” which means a direct power line from the plant to the electrolyzer OR have a 10-year EAC offtake agreement
The helpful part of the nuclear carve-out is that an electrolyzer can connect to the grid and then get nuclear EACs for around-the-clock operations. The major issues are location and price.
I’ve been told by an unreliable source that there is over 10GW available with the constraints above – but this doesn’t account for the price to buy the power from the grid. On top of the price paid to the power generator, a power buyer pays for access to the grid and a flat fee for the amount of power they are asking for. IE a 200MW plant would pay a 200MW demand charge, and then pay for each MWh of power they buy.
I’ve been on 200MW projects where total grid fees ended up being 8 cents per kwh on top of the electricity fee. 4 cents seems pretty standard
So while 10GW of nuclear power may qualify to generate EACs, in many locations it will be cost-prohibitive and the regionality constraint in 45V will prevent the lower cost ones from being sold.
Advice for developers –
Get out there and get your EACs locked down in low-cost areas while you can – there may be a race for them. Hire help like myself or other people experienced in the space so you can move fast without bringing on too many people.
Advice for investors –
Any company or project that talks about using nuclear and hydrogen is not credible until they’ve sighed at least a Memorandum of Understanding. Given that these aren’t binding, it’s still not worth much. Look for actual contracts
Qualifying states
Pluses:
Eliminates additionality
Zero emission goals in qualifying states may create a higher willingness-to-pay for clean hydrogen
Constraints
Only useful in California and Washington currently
In many cases, like Washington, deliverability may be an issue depending on how it is scoped
Electricity on qualifying states is expensive – this will offset some or all of the potential higher willingness to pay for H2
To become a qualifying state, the state must have the following constraints on the power sector
Clear 2050 zero emission goals
Ratcheting emissions caps
A floor price of $25/ton for CO2
A min penalty of $90/ton for going over the emissions cap
The issue here is that in Washington state, power prices are over 8.5 cents per kwh, and then a project needs to pay the EAC fee on top of that. This equals $4/kg variable OpEx to produce the H2 before accounting for fixed OpEx and CapEx. At only $3/kg subsidy, this doesn’t work unless the end users will pay more.
Deliverability will always be an issue. Cities don’t have excess power distribution available – so any H2 infrastructure needs to be built well outside the cities and the H2 transported in. Building new zero-emission powerlines is also quite expensive, so bringing power in isn’t really an option.
Advice for developers and investors
The end use needs to be locked down. This quite likely means an integrated project or high merchant market risk since no offtaker wants to sign long-term contracts. Either some form of state support is required (IE California’s getting rid of diesel at ports), or look for a long term contract. Without either, leave the state and the investment.
A major caveat – new states qualifying
Several states, such as those in Regional Greenhouse Gas Initiative (RGGI, pronounced Reggie IE), are within striking distance of becoming qualifying states.
Regional EAC stacking with renewables
Pluses:
In wide multi-state areas SoCal, the sun is always shining somewhere or the wind is always blowing somewhere
Can work with other low and zero sources of emissions to reach the magical 4kwh/kg annual average
In some regions like the Midwest, wind and solar together can achieve 65% or higher EAC coverage
Constraints
H2 demand doesn’t exist where EACs are in abundance
Areas with demand (LA, for example) will fail the deliverability requirement for the EACs
Very intensive to get all the EACs together – or requires a liquid EAC market
In a liquid market EACs may not be available for every hour– requiring significant overhead for response, a margin for annual average CI, and potential major issues delivering H2
Places where it is easy to stack EACs, like the Midwest with wind and solar, don’t have much H2 demand
There is some viability of finding offtake in ammonia – provided there is geologic storage because ammonia plants can’t turn off.
Generally speaking, renewable EAC stacking only works well in places far from civilization. In most places without grid constraints, it will be far enough that liquid hydrogen is probably necessary – drastically increasing cost and relegating the end use to mobility as the only end use that can pay that high a price.
Nonetheless, pockets of profitability with EAC stacking will exist.
Advice for Developers and Investors
Location will be key, as will be getting in early. End users that want to vertically integrate may be viable in a lot of these locations. Hire the right help and move quickly. If you’re investing in projects, be aware of the risks of not having EACs locked down on long term contracts. Expensive projects near major H2 production centers will be at-risk of being undercut – think liquid hydrogen near the gulf – look for those locked-in contracts.
2030 pushback for hourly matching
The pushback to 2030 will make it easier to have software and trading systems for EACs. It won’t necessarily make it easier to get EACs.
The grid constraint still exists, and anywhere with excess grid capacity will likely lack demand for H2. The grid won’t be well developed in H2 demand areas by 2030, and the hard switch over to hourly matching will render many electrolytic projects non-performing
Recommendations:
Don’t build or invest in places where EACs aren’t locked down. Competition could make stranded assets.
Carbon capture at power plants
Pluses:
24/7 EACs – but not high quality ones
Some types of power – like burning wood waste from places like CA where cleanup is needed – can be carbon negative and really drive some economics
Beyond EACs – electrolyzers may be the best end user for carbon capture plants unused hours, especially at night
This is for another post, but carbon capture equipment is expensive and capitalizing it over more produced MWh always helps bring average costs down (or profits up, often into not being net negative) – H2 may be able to help
Constraints
The EACs aren’t great with nat-gas power and capture– with 90% capture the upstream emissions still are 5kg CO2 per kg H2. Upstream emissions will need to be abated for this to get any credits
Carbon capture is hard and expensive– very few places have pipelines yet
Carbon capture is more expensive outside of the gulf regions
Overall, because carbon capture power plants aren’t yet commercially deployed, this remains more in speculative territory.
Here is where I did a ton of analysis. Short version: building a carbon capture power plant just for 45Q and 45V credits for H2 won’t work, but with high grid power costs (California, Washington, some other states) it may actually be worth it to stack with other end uses.
The numbers: A 1GW CCUS gas plant is $3B in CapEx and at $5/mmbtu will use $2.6B of natural gas over 10 years. If it supports ~1GW of electrolysis producing about 480 tons of H2 per day, or 1.6 million tons over the 10 year lifetime. It would generate $1B-$1.6B in H2 credits over the 10 year credit lifetime, with $0.60/kg and $1/kg credit, respectively. It will generate ~$2B in 45Q credits. This leaves an overhang of ~$2B, implying an additional price of hydrogen on the order of $1/kg, not accounting for grid fees, margin on power, and the CapEx and fixed OpEx of the H2 plant. Despite that we are using 10 year cashflows in on 25-50 year assets, the cost implies that building a CCUS gas turbine solely to power an electrolyzer solely is not workable.
Advice
This remains speculative for now, but for developers on both the carbon capture power side and on the electrolysis side, you should be making friends with each other.
Other tactics – grid services
For another post – purposely adding some storage to turn off electrolyzers during peak demand could be very lucrative.
I will paint a very idealized scenario with high percent of EACs for nearly full uptime.
As the example, a 100MW electrolysis facility generation ~1.5 tons of H2 per hour, foregoing production for three hours (4.5 tons per day x 350 days operation per year) would reduce 1.6 million kg of H2 production – or $5M per year in tax credits.
But for the other 11 million kg produced in the other 21 hours a day for 350 days, it could shave off $0.02 to $0.04 per kwh, saving $11 to $22 million each year for ten years.
Since the extra 4.5 tons of storage is needed as buffer, we need to subtract that cost. At $500,000 per ton of storage now, plus a million dollar compressor, the additional cost comes to $6M including construction.
A one time investment of $6M and some smart negotiations with the grid to do services could net a project $100-$200M in additional margin over ten years.
The parts of this that are unrealistic are that it ignores distribution of hydrogen - the production centers and demand centers are usually physically separated. In addition, it assumed that grid power will provide $3/kg H2, which would require an amount of EACs that don’t exist in most places. There should, however, be opportunities in parts of the US.
Be smart- hire smart help to test and find these opportunities.
