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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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The assembly line is the company’s signature innovation. Now it’s trying to one-up itself with the Universal EV Production System.
In 2027, Ford says, it will deliver a $30,000 mid-size all-electric truck. That alone would be a breakthrough in a segment where EVs have struggled against high costs and lagging interest from buyers.
But the company’s big announcement on Monday isn’t (just) about the truck. The promised pickup is part of Ford’s big plan that it has pegged as a “Model T moment” for electric vehicles. The Detroit giant says it is about to reimagine the entire way it builds EVs to cut costs, turn around its struggling EV division, and truly compete with the likes of Tesla.
What lies beneath the new affordable truck — which will revive the retro name Ford Ranchero, if rumors are true — is a new setup called the Ford Universal EV Platform. When car companies talk about a platform, they mean the automotive guts that can be shared between various models, a strategy that cuts costs compared to building everything from scratch for each vehicle. Tesla’s Model 3 and Model Y ride on the same platform, the latter being essentially a taller version of the former. Ford’s rival, General Motors, created the Ultium platform that has allowed it to build better and more affordable EVs like the Chevy Equinox and the upcoming revival of the Bolt. In Ford’s case, it says a truck, a van, a three-row SUV, and a small crossover can share the modular platform.
At the heart of the company’s plan, however, is a new manufacturing approach. The innovation of the original Model T was about the factory, after all — using the assembly line to cut production costs and lower the price of the car. For this “Model T moment,” the company has proposed a sea change in the way it builds EVs called the Ford Universal EV Production System. It will demonstrate the strategy with a $2 billion upgrade to the Ford factory in Louisville, Kentucky, that will build the new pickup.
In brief, Ford has embraced the more minimalist, software-driven version of car design embraced by EV-only companies like Tesla and Rivian. The vehicles themselves are mechanically simpler, with fewer buttons and parts, and more functions are controlled by software through touchscreen interfaces. Building cars this way cuts costs because you need far fewer bits, bobs, fasteners, and workstations in the factory. It also reduces the amount of wiring in the vehicle — by more than a kilometer of the stuff compared to the Mustang Mach-E, Ford’s current most popular EV, the company said.
Ford is in dire need of an electric turnaround. The company got into the EV race earlier than legacy car companies like Toyota and Subaru, which settled on more of a wait-and-see approach. Its Mustang Mach-E crossover has been one of the more successful non-Tesla EVs of the early 2020s; the F-150 Lightning proved that the full-size pickup truck that dominates American car sales could go electric, too.
But both vehicles were expensive to make, and the Lightning struggled to make a dent in the truck market, in part because the huge battery needed to power such a big vehicle gave it a bloated price. When Tesla started a price war in the EV market a few years ago, Ford began hemorrhaging billions from its electric division, struggling to adapt to the new world even as carmakers like GM and Hyundai/Kia found their footing.
The big Detroit brand has been looking for an answer ever since, and Monday’s announcement is the most promising proposal it has put forward. Part of the production scheme is for Ford to build its own line of next-gen lithium-ion phosphate, or LFP batteries in Michigan, using technology licensed from the Chinese giant CATL. Another step is to employ the “assembly tree,” which splits the traditional assembly line into three parallel operations, which Ford says reduces the number of required workstations and cuts assembly time by 15%.
Affordability has always been a bugaboo for the American EV industry, a worry exacerbated by the upcoming demise of the $7,500 tax credit. And while Ford’s manufacturing overhaul will go a long way toward building a light-duty pickup EV that sells for $30,000, so too will a fundamental change in thinking about batteries, weight, and range. The F-150 Lightning isn’t the only pickup with a big battery and an even bigger price. That truck’s power pack comes in at 98 kilowatt-hours; large EV pickups like the Rivian R1T and Chevy Silverado EV have 150 or even 200 kilowatt-hour batteries, necessary to store enough power to give these heavy beasts a decent driving range.
InsideEVs reports, however, that the affordable Ford truck may have a battery capacity of just over 50 kilowatt-hours, which would dramatically reduce its cost to make. The trade-off, then, is range. The Slate small pickup truck that made waves this year for its promised price in the $20,000s would have just 150 miles of range in its cheapest form. Ford hasn’t released any specs for its small EV truck, but even using state-of-the-art LFP chemistry, such a small battery surely won’t deliver many more miles per charge.
Whatever the final product looks like, the new Ford truck and the infrastructure behind it are another reminder that, no matter the headwinds caused by the Trump administration, EVs are the future. Ford had been humming along through its EV struggles because its gas-burning cars remained so popular in America, and so profitable. But those profits collapsed in the first half of 2025, according to The New York Times. Meanwhile, Ford and every other carmaker are struggling to catch up to the Chinese companies selling a plethora of cheap EVs all over the world. Their very future depends on innovating ways to build EVs for less.
Governors, legislators, and regulators are all mustering to help push clean energy past the starting line in time to meet Republicans’ new deadlines.
Trump’s One Big Beautiful Bill Act put new expiration dates on clean energy tax credits for business and consumers, raising the cost of climate action. Now some states are rushing to accelerate renewable energy projects and get as many underway as possible before the new deadlines take effect.
The new law requires wind and solar developers to start construction by the end of this year in order to claim the full investment or production tax credits under the rules established by the Inflation Reduction Act. They’ll then have at least four years to get their project online.
Those that miss the end-of-year deadline will have another six months, until July 4, 2026, to start construction, but will have to meet complicated sourcing restrictions on materials from China. Any projects that get off the ground after that date will face a severely abbreviated schedule — they’ll have to be completed by the end of 2027 to qualify, an all-but-impossibly short construction timeline.
Adding even more urgency to the time crunch, President Trump has directed the Treasury Department to revise the rules that define what it means to “start construction.” Historically, a developer could start construction simply by purchasing key pieces of equipment. But Trump’s order called for “preventing the artificial acceleration or manipulation of eligibility and by restricting the use of broad safe harbors unless a substantial portion of a subject facility has been built,” an ominous sign for those racing to meet already accelerated deadlines.
While the changes won’t suppress adoption of these technologies entirely, they will slow deployment and make renewable energy more expensive than it otherwise would have been. Some states that have clean energy goals are trying to lock in as much subsidized generation as they can to lessen the blow.
There are two ways states can meet the moment, Justin Backal Balik, the state program director at the nonprofit Evergreen Action, told me. Right now, many are trying to address the immediate crisis by helping to usher shovel-ready projects through regulatory processes. But states should also be thinking about how to make projects more economical after the tax credits expire, Balik said. “States can play a role in tilting the scale slightly back in the direction of some of the projects being financially viable,” he said, “even understanding that they’re not going to be able to make up all of the lost ground the incentives provided.”
In the first category, Colorado Governor Jared Polis sent a letter last week to utilities and independent power producers in the state committing to use “all of the Colorado State Government to prioritize deployment of clean energy projects.”
“Getting this right is of critical importance to Colorado ratepayers,” Polis wrote. The nonprofit research group Energy Innovation estimates that household energy expenses in Colorado could be $170 higher in 2030 than they would have been because of OBBB, and $310 higher in 2035. “The goal is to integrate maximal clean energy by securing as much cost-effective electric generation under construction or placed in service as soon as possible, along with any necessary electricity balancing resources and supporting infrastructure,” Polis continued.
As for how he plans to do that, he said the state would work to “eliminate administrative barriers and bottlenecks” for renewable energy, promising faster state reviews for permits. It will also “facilitate the pre-purchase of project equipment,” since purchasing equipment is one of the key steps developers can take to meet the tax credit deadlines.
Other states are looking to quickly secure new contracts for renewable energy. In mid-July, two weeks after the reconciliation bill became law, utility regulators in Maine moved to rapidly procure nearly 1,600 gigawatt-hours of wind and solar — for context, that’s about 13% of the total energy the state currently generates. They gave developers just two weeks to submit proposals, and will prioritize projects sited on agricultural land that has been contaminated with per- and polyfluoroalkyl substances, the chemicals known as PFAS. (When asked how many applications had been submitted, the Maine Public Utilities Commission said it doesn't share that information prior to project selection.)
Connecticut’s Department of Energy and Environmental Protection is eyeing a similar move. During a public webinar in late July, the agency said it was considering an accelerated procurement of zero-carbon resources “before the tax increase takes effect.” The office put out a request for information to renewable energy developers the next day to see if there were any projects ready to go that would qualify for the tax credits. Officials also encouraged developers to contact the agency’s concierge permit assistance services if they are worried about getting their permits on time for tax credit eligibility. Katie Dykes, the agency’s commissioner, said during the presentation that the concierge will engage with permit staff to make sure there aren’t incomplete or missing documents and to “ensure smooth and efficient review of projects.”
New York’s energy office is planning to do another round of procurement in September, the outlet New York Focus has reported, although the solicitation is late — it had originally been scheduled for June. The state has more than two dozen projects in the pipeline that are permitted but haven’t yet started construction, according to Focus, and some of them are waiting to secure contracts with the state.
Others are simply held up by the web of approvals New York requires, but better coordination between New York agencies may be in the works. “I assembled my team immediately and we are trying to do everything we can to expedite those [renewable energy projects] that are already in the pipeline to get those the approvals they need to move ahead,” Governor Kathy Hochul said during a rally at the State University of New York’s Niagara campus last week. The state’s energy research and development agency has formed a team “to help commercial projects quickly troubleshoot and advance towards construction,” according to the nonprofit Evergreen Action. (The agency did not respond to a request for more information about the effort.)
States and local governments are also planning to ramp up marketing of the consumer-based credits that are set to expire. Colorado, for example, launched a new “Energy Savings Navigator” tool to help residents identify all of the rebate, tax credit, and energy bill assistance programs they may be eligible for.
Consumers have even less time to act than wind and solar developers. Discounts for new, used, and leased electric vehicles will end in less than two months, on September 30. Homeowners must install solar panels, batteries, heat pumps, and any other clean energy or efficiency upgrades before the end of this year to qualify for tax credits.
Many states offer additional incentives for these technologies, and some are re-tooling their programs to stretch the funding. Connecticut saw a rush of demand for its electric vehicle rebate program, CHEAPR, after the OBBB passed. Officials decided to slash the subsidy from $1,500 to $500 as of August 1, and will re-assess the program in the fall. “The budget that we have for the CHEAPR program is finite,” Dykes said during the July webinar. “We are trying to be good stewards of those dollars in light of the extraordinary demand for EVs, so that after October 1 we have the best chance to be able to provide an enhanced rebate, to lessen the significant drop in the total level of incentives that are available for electric vehicles.”
As far as trying to address the longer-term challenges for renewables, Balik highlighted Pennsylvania Governor Josh Shapiro’s proposal to streamline energy siting decisions by passing them through a new state board. “One of the big things states can do is siting reform because local opposition and lawsuits that drag forever are a big drag on costs,” Balik told me.
A bill that would create a Reliable Energy Siting and Electric Transition Board, or RESET Board, is currently in the Pennsylvania legislature. (New York State took similar steps to establish a renewable siting office to speed up deployment in 2020, though so far it’s still taking an average of three years to permit projects, down from four to five years prior to the office’s establishment.) Connecticut officials also discussed looking at ways to reduce the “soft costs” of permitting and environmental reviews during the July webinar.
Balik added that state green banks can also play a role in helping projects secure more favorable financing. Their capacity to do so will be significantly higher if the courts force the federal government to administer the Greenhouse Gas Reduction Fund.
When it comes to speeding up renewable energy deployment, there’s at least one big obstacle that governors have little control over. Wind and solar projects need approval from regional transmission operators, the independent bodies that oversee the transmission and distribution of power, to connect to the grid — a notoriously slow process. The lag is especially long in the PJM Interconnection, which governs the grid for 13 mid-Atlantic States, and has generally favored natural gas over renewables. But governors are starting to turn up the pressure on PJM to do better. In mid July, Shapiro and nine other governors demanded PJM give states more of a say in the process by allowing them to propose candidates for two of PJM’s board seats.
“Can we use this moment of crisis to really impress the urgency of getting some of these other things done — like siting reforms, like interconnection queue fixes, that are all part of the economics of projects,” Balik asked. These steps may help, but lengthy federal permitting processes remain a hurdle. While permitting reform is a major bipartisan priority in Congress, as my colleague Matthew Zeitlin wrote recently, a deal that’s good for renewables might require an about-face from the president on wind and solar.
The Danish government is stepping in after U.S. policy shifts left the company’s New York offshore wind project in need of fresh funds.
Orsted is going to investors — including the Danish government — for money it can’t get for its wind projects, especially in the troubled U.S. offshore wind market.
The Danish developer, which is majority owned by the Danish government, told investors on Monday that it would seek to raise over $9 billion, about half its valuation before the announcement, by selling shares in the company.
Publicly traded companies do not typically raise money by selling stock, which is more expensive for the company, tending instead to finance specific projects or borrow money.
But the offshore wind business is not any industry.
In normal times, Orsted and other wind developers will conduct “farm-downs,” selling stakes in projects in order to help finance the next ones. Due to “recent material adverse development in the U.S. offshore wind market,” however, the early-morning announcement said, “it is not possible for the company to complete the planned partial divestment and associated non-recourse project financing of its Sunrise Wind offshore wind project on the terms which would provide the required strengthening of Orsted’s capital structure” — a long way of explaining that it can’t find a buyer at an acceptable price. Hence the new equity.
While the market had been expecting Orsted to raise capital in some form, the scale of the raise is about twice what was anticipated, according to Bloomberg’s Javier Blas.
About two-thirds of the stock sale will be used to continue financing Sunrise Wind, a 924-megawatt planned offshore wind project off the coast of Long Island, according to Morgan Stanley analysts. Construction began last summer, just days after Orsted took full ownership of the project by buying out a stake held by the utility Eversource.
Despite all the sound and fury around offshore wind in the United States, the company said in its earnings report, also released Monday, that “we successfully installed the first foundations at Sunrise Wind, following completion of the wind turbine foundation installation at Revolution Wind,” a 704-megawatt project off the coasts of Rhode Island and Connecticut. “Construction of our offshore U.S. assets is progressing as expected and according to plan,” the company said.
But the report also said Orsted took a hit of over a billion Danish kroner in the first half of this year due to tariffs and what it gingerly refers to as “other regulatory changes, particularly affecting the U.S.,” a.k.a. President Donald Trump.
The president and his appointees have been on a regulatory and financial campaign against the wind sector, especially offshore wind, attempting to halt work on another in-construction New York project, Empire Wind, before Governor Kathy Hochul was able to reach a deal to continue. All future lease sales for new offshore wind areas have been canceled.
Even before Trump came back into office, the offshore wind industry in the U.S. had been hammered by high interest rates, which raised the cost of borrowed money necessary to fund projects, and spiraling supply chain costs and project delays, which also increased the need for the more expensive financing.
“Because of the sharp rise in construction costs and interest rates since 2021, all the projects turned out to be value-destructive,” Morningstar analyst Tancrede Fulop wrote in a note about the Orsted share issue. The company took large losses on scuttled projects in the U.S. and already cancelled its dividend and announced a plan to partially divest many other projects in order to shore up its balance sheet and fund future projects.
While the start-and-stop Empire Wind project belongs to Equinor, Orsted’s Scandinavian neighbor (majority-owned by the Norwegian government), Orsted management told analysts on its conference call that “the issues surrounding Empire Wind's stop-work order from April 2025 had negatively impacted financing conditions for Sunrise,” according to Jefferies analyst Ahmed Furman.
Equinor, too, has had to take a bigger share of Empire Wind, buying out the stake held by BP in January of this year. BP had bought 50% stakes in three Equinor wind projects in 2020, but last year wrote down its investment in the offshore wind sector in the U.S. by over $1 billion.
Why could Orsted not simply pull out of Sunrise Wind? “Orsted and our industry are in an extraordinary situation with the adverse market development in the U.S. on top of the past years’ macroeconomic and supply chain challenges,” Rasmus Errboe, who took over as the company’s chief executive earlier this year, said in a statement. “To deliver on our business plan and commitments in this environment, we’ve concluded that a rights issue is the best solution for Orsted and our shareholders.”
The Danish government will maintain its 50.1% stake in the company, putting the small Scandinavian country with its low-boiling trade and territorial conflicts against the Trump administration in direct capitalist conflict with the American president and his least favorite form of electricity generation.
In the immediate wake of the announcement, Jefferies analyst Ahmed Farman wrote to clients that the deal would “obviously de-risk the [balance sheet], but near-term dilution risk seems substantial,” citing the unexpected magnitude of the raise and no sign pointing to new growth. “As a result, we expect the initial stock reaction to be quite negative.”
And so it has been: The stock closed down almost 30%, its biggest-ever single-day drop and below the price at which it went public in 2016, according to Bloomberg data.