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Having a true green hydrogen industry depends on that not happening.
In late December, the Treasury Department proposed draft regulations to implement the Inflation Reduction Act’s generous hydrogen production tax credit. Under Section 45V of the tax code, eligible projects must show that their life cycle greenhouse gas emissions fall below exacting benchmarks. Treasury’s final rules will determine how hydrogen projects are allowed to calculate their emissions and direct the flow of tens of billions of tax dollars — or more.
Most of the discussion that followed focused on the draft rule’s proposed guardrails for green hydrogen, which is produced from water using clean electricity. The climate policy community in particular largely approved of Treasury’s approach, in part because it lays the groundwork for hourly emissions accounting in the electricity sector — essentially, making sure that clean energy is being made and used in real time, a foundational shift needed for deep decarbonization.
But when it comes to producing hydrogen from methane — which is how nearly all hydrogen is made today — Treasury’s draft was incomplete. In place of a concrete proposal, the draft regulations raised detailed technical questions about what should be allowed in the final rule. Among these was the suggestion that hydrogen production from fossil fuels might qualify for tax credits by using methane offsets. This, quite simply, would undermine the tax credit’s entire purpose.
If the final regulations authorize methane offsets, then the 45V tax credit could end up subsidizing fossil fuel projects, stifling the nascent green hydrogen industry and locking in emissions-intensive infrastructure for decades to come. Just as concerning, authorizing offsets for the hydrogen production tax credit would also pave the way for similar treatment in the upcoming implementation of technology-neutral clean energy production ( Section 45Y) and investment tax credits (Section 48E).
To understand how offsets could affect the strategic outlook for the hydrogen industry, we looked at how the Treasury Department calculates the life cycle emissions of hydrogen production from natural gas, which is essentially just methane. Treasury’s draft regulations propose to use a bespoke life cycle analysis model to determine whether hydrogen projects qualify for the tax credit, and if so, what level of support they will receive.
This model has several important features: It accounts for CO2 emitted in the process of producing hydrogen from methane, which is straightforward, as well as methane emissions from upstream gas production, processing, and pipeline transportation, which is not. (Unfortunately, it doesn’t include impacts from hydrogen, which itself is an indirect greenhouse gas that contributes to global warming.)
The model’s treatment of methane emissions is particularly important. Although the academic literature suggests a national average above 2% and finds impacts above 9% in some cases, the model assumes that gas supply chains emit only 0.9% of the methane they deliver. Differences in methane emissions matter a lot, even when they look small. That’s because methane traps about 30 times as much heat as CO2 over a 100-year period, so its calculated CO2-equivalence is that much larger.
As a result, Treasury’s proposed approach undercounts the true climate impacts of hydrogen production, particularly hydrogen made from methane. Even so, fossil hydrogen production faces a narrow path to qualifying for the tax credit. For example, a fossil hydrogen project would have to capture more than 70% of its CO2 emissions and buy enough clean electricity to power all its operations — either directly as energy or indirectly as energy credits — even to qualify for the lower tiers of the tax credit. And even though projects’ actual methane emissions are likely to be undercounted, the model’s assumptions are enough to disqualify fossil projects from the highest tax credit tier, which is substantially more lucrative than any of the others.
Because of the difficulty of achieving high CO2 capture rates, some analysts have argued that fossil hydrogen projects will instead wind up applying for tax credits under Section 45Q of the IRA, which provides incentives for sequestering CO2 underground without the hydrogen tax credit’s exacting emissions standards.
But a fossil hydrogen project can claim totally different outcomes if it’s allowed to buy environmental certificates that claim to avoid methane emissions in the first place, a.k.a. methane offsets. The logic goes like this: If someone else was going to emit methane to the atmosphere, but agrees instead to capture and inject it into a gas pipeline network, then a hydrogen producer can buy a certificate from that other methane producer representing that same captured gas and potentially treat their own fossil gas as negative emissions.
For example, consider a large dairy that sends cow manure to uncovered manure lagoons, which produce significant methane emissions. Suppose the dairy installs a methane capture system and sells credits to a hydrogen producer, which then claims to have avoided the dairy’s methane emissions — even if these emissions could be avoided in other ways, like alternative manure management or flaring. Because methane is considered almost 30 times more impactful than CO2 over a 100-year period, the CO2-equivalence of avoiding methane emissions is larger than the project’s direct CO2 emissions, and therefore the resulting hydrogen production process gets a negative carbon intensity score.
If your head is spinning at this point, welcome to the world of offsets. Outcomes depend on counterfactual scenarios that can’t be measured or observed, burning fossil fuels can supposedly reduce pollution, and even the verb tenses are hard to parse.
Vertigo aside, the practical implications of methane offsets for the hydrogen production tax credit are enormous. Without methane offsets, fossil hydrogen projects couldn’t benefit much from the hydrogen tax credit; even with strict carbon capture and storage pollution controls, they can't meet the life cycle requirements for the top tier and would likely prefer to claim a smaller carbon storage tax credit instead. But if projects can use methane offsets, they can easily reduce their calculated emissions to qualify for the top tier of the hydrogen production tax credit.
This would also mean these fossil projects could undercut truly clean hydrogen projects. Green hydrogen projects that comply with the draft guardrails will have to invest in novel electrolyzer technologies and new clean power sources. The top tier of the tax credit provides enough money to make clean hydrogen projects competitive, but methane offsets are a lot less expensive than electrolyzers. If fossil producers can qualify with cheap offsets, they can pocket the difference and outcompete clean producers who have to invest in costly infrastructure.
We set out to estimate the amount of methane offsetting needed to qualify fossil projects for the top production tax credit tier. You can review our calculations here; for the carbon intensity of putatively negative emissions feedstocks, we used a conservative estimate that is about half the level of what other researchers use.
Remarkably, a fossil hydrogen project without carbon capture could qualify for the top production tax credit by offsetting just 25% of its fuel use. And a fossil hydrogen project that abates 90% of its CO2 emissions could earn the top tier of the tax credit if it bought offsets for just 4% of its fuel use.
So far a lot of the discussion about negative carbon intensity scores has focused on methane captured from livestock manure, but Treasury’s draft regulations also make reference to the possibility of capturing “fugitive emissions,” which could include methane emitted from the oil and gas sector or even from coal mines. If methane offsets are made eligible across a wide range of fugitive emissions, the hydrogen tax credit — which was designed as a generous incentive to promote innovation in new technologies — could end up subsidizing incumbent emitters.
Treasury’s hydrogen regulations will also set an important precedent for how offsets are treated in other government policies. The last set of tax credits in the IRA, a pair of technology-neutral investment and production tax credits for clean electricity generation, are under development this year. It’s great news that soon the U.S. federal government will support a full range of clean technologies, not just solar and wind — but not if those policies encourage higher-emitting activities that claim to be clean through the use of offsets. There are a few existing markets for methane offsets already, and certain segments of the economy — particularly the dairy industry — are hungry for more.
At the end of the day, the Biden administration faces a similar set of issues when it comes to producing hydrogen from methane that it did with clean hydrogen produced from electricity and water. If the tax credits encourage green hydrogen projects in places where it is difficult to supply cheap and clean electricity, then those projects risk becoming stranded assets when the tax credits expire. Similarly, if the tax credits encourage hydrogen production from chemical feedstocks and methane offsets, they will prop up fossil fuel infrastructure that could keep operating long after the requirement to buy offsets expires.
For all the complexity, though, one thing is clear: We won’t get a true green hydrogen industry if the Treasury Department decides to subsidize methane offsets — which, when you put it like that, doesn’t make much sense in the first place.
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Packed hearings. Facebook organizing. Complaints about prime farmland and a disappearing way of life. Sound familiar?
Solar and wind companies cite the rise of artificial intelligence to make their business cases after the United States government slashed massive tax incentives for their projects.
But the data centers supposed to power the AI boom are now facing the sort of swift wave of rejections from local governments across the country eerily similar to what renewables developers have been dealing with on the ground over the last decade. The only difference is, this land use techlash feels even more sudden, intense, and culturally diffuse.
What’s happening is simple: Data centers are now routinely being denied by local governments in zoning and permitting decisions after local residents turn against them. These aggrieved denizens organize grassroots campaigns, many with associated Facebook groups, and then flood city council and county commission hearings.
Just take this past week. Last Thursday, Prince George’s County, Maryland, paused all data center permitting after a campaign against converting an abandoned mall into a data center gained traction online, with a petition garnering more than 20,000 signatures. On Monday, faced with a ferocious public outcry, Google rescinded a proposal to build what would’ve been its second data center in Indiana in Franklin Township, a community in southeastern Indianapolis – a withdrawal requested mere minutes before the township council was reportedly going to reject it.
That same day, the rural Illinois town of DeKalb denied a solar company’s request to build a “boutique data center” on the same site as a previously-permitted solar farm. And on Tuesday, the small city of Howell – located smack between Lansing and Detroit, Michigan – denied a data center proposed by an anonymous Fortune 100 company. Apparently, so many people showed up to voice their opposition to the project that the hearing was held in a high school gymnasium.
Opponents cite many things in their arguments against development, some unique to the sector like energy and water use, and others familiar to the solar and wind industry, like preserving prime farmland or maintaining a way of life.
These arguments are incredibly salient, as polling conducted by Heatmap News has revealed: less than half of Americans would ever support a data center coming near them, and this technology infrastructure is less popular than any form of renewable energy. Digging into the cross-tabs of that poll, data centers are unpopular with essentially all age demographics, and arguments against the facilities – like “they use too much water” or “they consume too much electricity” – get relatively similar agreement from registered Democrats and Republicans alike.
Ben Inskeep, a clean energy advocate in Indianapolis, told me he started fighting data centers last year after he became aware of the total power needed to fuel the rising number of projects in the state. His advocacy organization, Citizens Action Coalition of Indiana, previously weighed in on rate hikes and electricity generation decisions. Now, they’re tracking more than 40 data center projects they say are proposed in the state and getting involved in the fight on the ground against them.
Inskeep told me that, from his point of view, the primary support for data centers comes from local governments and municipally-funded works like schools and health facilities that are facing slashed budgets. In some cases the projects are being rejected despite representing millions – even billions – in capital investments and potential tax revenues so large that municipal governments are put between a rock and a hard place as they’re pressured by a weakening economy and state funding cuts.
That’s what happened in Indianapolis. Earlier this month the school district that would’ve been funded by the now-rejected Google data center came out in support of the project, declaring it would welcome new tax revenue, and said it would also lead to new educational partnerships with the tech giant. But none of that mattered. Some local officials even lambasted their colleagues' support as unwarranted, a lashing out that reminds me of what happens to pro-solar officials in Ohio.
Heatmap News has been tracking contested data center projects since the spring of this year and has found almost 100 projects under development across the country that are being actively fought by local organizers, citizens advocacy groups, and environmental organizations. The data is preliminary and likely an undercount.
Still, there’s lots to glean from it. Crucially, as we’ve seen with renewable energy development, data center opposition crops up most often in tandem with the number of projects proposed and constructed. This is only logical: the more of something that is built in a place, the more likely people are to say, “We’ve built enough of that.” This is why Virginia is the top state when it comes to data centers being opposed – it’s a hub that’s seen development spike for far longer than elsewhere in the United States.
I believe that as data center project proposals continue to rise across the country, we’ll see in parallel rising hostility to their development – potentially much larger than anything renewable energy has ever faced. It will undoubtedly also be a problem for anyone in solar or wind who is riding on an AI boom to add demand for their projects.
And more of the week’s most important news around renewable energy conflicts.
1. Pulaski County, Arkansas – The attorney general of Arkansas is reassuring residents that yes, they can still ban wind farms if they want to.
2. Des Moines County, Iowa – This county facing intense pressure to lock out renewables is trying to find a sweet spot that doesn’t involve capitulation. Whether that’s possible remains to be seen.
3. Fayette County, Tennessee – This county just extended its solar energy moratorium for at least the next 18 months after pressure from residents.
4. McCracken County, Kentucky – It’s not all bad news this week, as a large solar project in Kentucky appears to be moving forward without fomenting difficulties on the ground.
A conversation with Wil Gehl at the Solar Energy Industries Association
This week I chatted with Wil Gehl, the InterMountain West senior manager at the Solar Energy Industries Association. I reached out in the hopes we could chat candidly about the impacts of the current national policy regime on solar development in the American West, where a pause on federal permits risks jeopardizing immense development in Nevada. To my delight, Wil was (pun intended) willing to get into the hot seat with me and get into the mix.
The following conversation was lightly edited for clarity.
So for starters, walk me through how solar development out west has changed since the start of this year.
Certainly been a lot of changes. I think there’s sort of a confluence of lots of uncertainty and change in the industry. The impending tax credit deadlines and safe harbor and commence construction deadlines, all of that combined with the sort of things that have been ongoing in the West for a while — public lands, siting issues — I think those have made a relatively difficult development environment for folks.
But that said, we’re also seeing unprecedented load growth across the West, and Nevada’s a really good example of that. So the demand for solar and storage remains super high. But I think now we’re navigating even more difficulty in getting projects both sited and also over the finish line.
How has the pause on federal permitting impacted projects in this area of the country?
Nevada is 80% public land, give or take, so those changes at the federal level, particularly, the Department of Interior … it’s pretty difficult if you’re looking at utility-scale solar in the state to avoid a sort of federal lands nexus. Those policy changes are really being felt on the ground in Nevada.
We don’t do a ton of engagement at the county level but I’ve been tracking those developments across the state, in Nevada, and others around the West. Whether they’re moratoriums or consideration on moratoriums, or new siting restrictions… in most states in the West, the land use decisions rest at the local level, either the county or the municipal jurisdiction. The patchwork of changing ordinances, that [has a] pace that has intensified a little bit this year as well.
How is SEIA trying to get those projects unstuck? I think about Esmeralda 7 for example, which hasn’t seen its permitting timeline updated online in half a year. What’s the process for trying to get these projects to move forward at this juncture?
I guess I don’t have project by project specific information but in general, I think the example with Nevada Gov. Joe Lombardo’s letter is how we’ve been approaching this issue. Trying to make the case for states like Nevada with really high load growth that projects like this are critical to meeting energy demand and serving customers reliably. Trying to tie the really near-term challenge of serving load together with these issues of federal land so that people on the ground at the state level are aware of it and can use the influence they have with federal officials and other folks to make this situation known, that this has real practical effects with states and their economic development.
When it comes to transmission for these solar projects, what’s the status? Is the scope of the pause just limited to the scope of solar generation or also transmission lines connected to them?
I think the kind of more recent challenges have been more focused on the generation side. The pace of the transmission and associated queue bottlenecks, I feel like that situation has not improved by any means but I don’t get the sense there’s any near-term changes that have impacted that. I’d be curious if other folks who work more closely on the transmission side have a different perspective, but that’s kind of what I’m seeing.
Is there from your vantage point a clip or an end here? If these projects are unable to be unstuck, do you expect developers to try and wait out this limbo with public lands? Or do you expect developers to rethink how they site their projects?
I think in general for projects already under the development process, folks have already invested a lot of time, energy, and capital to get those projects to this point. Particularly those in the West really necessary to serve as growing load, I would expect folks to really be pursuing every angle they can to get those projects over the finish line.
That said, I’m sure there is some point. I just don’t have a good sense of when this becomes totally unpalatable or you’re not able to move forward.
NV Energy recently had a filing at the Federal Energy Regulatory Commission that allowed projects previously in their queue an escape route out if they were not able to maintain their queue position. I do think that’s a sign of the siting difficulties, the people re-evaluating their project portfolio. I’m not a developer but if you’re looking on private land or federal land, signs are pointing to a smoother path forward on private land but in states like Nevada where 80% plus is public land, even for a project fully sited on private land, it’s really difficult to avoid interconnection or transmission. There are pretty much always going to be federal impacts. That’s just going to be a challenge that industry’s facing at this point.
What’s your message to developers who are anxious in this moment?
That’s a good question. I share the anxiety.
I also think there’s a lot of effort being undertaken by developers to explain the situation on the ground to their elected officials and I really think that’s the kind of message that needs to get out there. These real tangible impacts of projects that were already invested in, in some cases already under construction, that are being hindered by these policy decisions that I don’t think are serving the public interests and are going to limit economic development if they don’t come online in time. Ultimately energy is needed to meet the growing demand. There’s not a great alternative to these projects not getting done.