The Brattle Group: 45V could help push green hydrogen costs to parity with gray

There has been no shortage of debate in light of recent Treasury guidance on the green hydrogen tax credits known as 45V. 

But a recent report from The Brattle Group suggests that certain fears about whether the strict production requirements will keep the burgeoning industry from making it off the ground may be overblown.

• The top line: The report found that Inflation Reduction Act tax credits like 45V and other public funding options can offset approximately half of the production costs during a project’s first 10 operating years. As efficiency improves and electrolysis costs continue to fall, overall hydrogen production costs are expected to decrease accordingly. This is good news for the Department of Energy — by 2030, the report found, DOE’s “hydrogen shot” goal of one dollar per kilogram of green hydrogen could be met or even surpassed, putting the price nearly on par with gray hydrogen produced with natural gas. 
• The nuts and bolts: With an expected demand of 30-50 million metric tons of green hydrogen per year in 2040-2025, the report found, up to 700 gigawatts of renewable energy annually will be required to produce it each year. That’s over half of the grid’s current capacity of around 1,300 GW. And storage and transportation present significant technical challenges as well. 

The report — which was produced for the Environmental Defense Fund — highlighted three key federal developments driving hydrogen investment: the hydrogen hubs funded under the infrastructure law, production tax credits like 45V that were introduced or expanded as part of the IRA, and the Environmental Protection Agency’s proposed updates to New Source Performance Standards in 2023. 

The IRA’s incentives have been particularly impactful for the budding industry.  Under 45V, green hydrogen production tax credits can reach up to $3 per kilogram of hydrogen for the first 10 years of a plant’s life, cutting the net costs in half. But as electrolyzer efficiency improves and the costs of both the technology and renewable energy plunge (as they are anticipated to do), overall hydrogen costs are expected to plummet to just a dollar per kilogram over the next decade, the report found.

That price is equivalent to $7.44 per MMBtu, which is close to the price of natural gas, “especially if the latter were penalized by a [carbon dioxide equivalent] emissions charge reflecting the social cost of carbon,” the authors noted. 

Since the policy’s passage, over 25 industrial-scale green hydrogen projects have been announced, many of which suggest significant internal rates of return. 

However, the promising outlook comes with caveats. For instance, many specifics of the IRA remain hazy, which obscures how future hydrogen development will shake out, the report found. Additionality, which requires all electricity used for green hydrogen production to come from a new generation source that comes online within three years of the facility itself, is key for how hydrogen producers conduct their operations and future projects. Without additionality, hourly matching, and deliverability, the report added, connecting new electrolyzers to the grid could actually induce new greenhouse gas emissions instead of the opposite.

The Treasury’s guidance has been met with much controversy on both sides from around the industry; ironing out the specifics of the future regulations appears an uphill battle. Guidance also remains fuzzy regarding if and how different types of energy tax credits could be stacked. 

Still, the authors note, even in a world without 45V, green hydrogen is expected to reach cost parity with or beat gray hydrogen produced using fossil fuels by 2030, assuming that gray hydrogen hovers around $1 to $1.50 per kilogram. Extending the incentives beyond 2030 can actually lead to negative hydrogen production costs for both steady state and intermittent electricity projects, the report found.

Hydrogen’s storage and transportation hurdles

Another challenge facing the hydrogen industry is how and where to store and transport it. Part of the problem is the fact that the small size of the hydrogen molecule hinders remote delivery efforts. 

Ferrying bulk quantities of gaseous hydrogen over long distances is technically risky; leakage, corrosion, and pressure management all present the potential for danger. And the large capex of building the infrastructure presents economic risks as well. 

Though it is technically and theoretically possible for existing natural gas transmission pipelines to be repurposed for hydrogen, the report noted, no major pipelines are seriously considering it. 

The authors also discussed various commercially available hydrogen storage technologies, finding that though “storage may help achieve desired end-use load factors and allow greater use of intermittent production…[there are] many technical and geographic limitations” on which technologies might work. 

Salt dome caverns, for instance, are artificially constructed underground structures in rock salt formations primarily near the Gulf Coast and central and northeastern United States. Their availability is limited and their use adds about 20 cents per kilogram to hydrogen production costs; still, it appears to be the only viable bulk storage option for hydrogen at present, the authors said.

Hard rock caverns are simply too scarce to be of any use in the United States. Above ground storage isn’t suitable for long-term storage, has a low round-trip efficiency, and can be prohibitively expensive. While depleted fields and aquifers have low investment costs, their risks of hydrogen loss and leakage are high; they remain untested for H2 storage.

The report also found that by 2030, blue hydrogen, which couples steam methane reformation with carbon capture and storage, could cost $1.80 kilogram without qualifying for 45Q, and $1.10 per kilogram with it — on par with or below the cost of gray hydrogen.