Bold enough or inadequate? Biden's landmark energy policy two months on

In this October REview, we assess the Inflation Reduction Act (IRA) as seen through the lens of the energy supply chain and conclude that it is suitably bold in its support of renewable energy and emission reduction targets. The result will likely be significant improvements in the energy transition process over in the coming decade, enabling the US to stay within reach of its Paris agreement commitments. At the same time, we think it is inadequate and inconsistent in its support of the oil and gas industry, which remains a vital energy supplier through the current energy crisis, and through the energy transition over the next 20 years.

Despite flaws, the Inflation Reduction Act will change the US energy value chain for the better

In this October REview, we assess the Inflation Reduction Act (IRA) as seen through the lens of the energy supply chain and conclude that it is suitably bold in its support of renewable energy and emission reduction targets. The result will likely be significant improvements in the energy transition process over in the coming decade, enabling the US to stay within reach of its Paris agreement commitments. At the same time, we think it is inadequate and inconsistent in its support of the oil and gas industry, which remains a vital energy supplier through the current energy crisis, and through the energy transition over the next 20 years.

US President Joe Biden’s poll numbers were given a boost after he enacted the IRA into law, as the passage showed that he still musters sufficient political capital to initiate measures tackling big issues such as energy policy and climate change. He also sought to make the case that the US can lead the world from the frontlines again, despite its long polarizing politics, by incentivizing quicker and deeper adoption of low carbon technologies and creating an environment for a ramp-up in manufacturing and supply chain capabilities. But these lofty plans might still fail to impress the median US voter, who is grappling with stubborn inflation that is denting living standards to an extent not seen in 40 years – and this is unfolding less than a month before a crucial mid-term election. Some pundits argue that rising inflation can only be tamed by higher interest rates, and this is where the first hurdle for the IRA is likely to arise.

Borrowing costs are usually higher for smaller companies working with newer unproven technologies, due to the intrinsic higher-than-normal riskiness of such projects. That is why governments often offer tax breaks to new businesses, particularly those working in pivotal sectors such as renewables. But the impact of any tax incentive can be blunted if borrowing costs rise steadily, especially for sectors that will end up getting charged above market rates. With the US Federal Reserve determined to keep a hawkish stance until inflation returns under control, borrowing costs have risen several notches, at times doubling from year-earlier levels. These will weigh on companies’ ability to borrow to build or expand operations. Meanwhile, the dollar index, a measure of the value of the greenback against a basket of currencies, has strengthened to a 20-year high – a direct result of the Fed policy. 

With inflation readings still high, the Fed is widely expected to increase rates further, which could in turn push the value of the dollar even higher. While that is good news for anyone planning a foreign vacation and for companies importing raw materials, goods and services into the US, it is not good news for companies exporting from the US and for oil importing countries. On top of that, the appreciation of the US dollar has historically been associated with lower world GDP growth, and therefore will add another layer of uncertainty for companies that are in expansion or buildout mode. Tapping equity markets may not be a readily available option for many, given the market volatility. Moreover, the extent of the impact does not end there. Companies must forego more in terms of salaries to account for cost-of-living increases. Taken together, companies looking to either set-up manufacturing bases or expand existing facilities will have to deal with these headwinds, along with the shortages in supply of raw materials, equipment and labor. Just how far the administration is ready to go to prevent the souring of the business and investment climate remains anyone’s guess, as it will also depend on how much worse these underlying macro conditions get. Crucially, it will also be contingent on the outcome of the mid-term elections in November.

Against that backdrop of challenges, Rystad Energy has completed a comprehensive assessment of the Inflation Reduction Act across the energy value chain, including renewables, oil and gas markets, upstream, carbon capture, hydrogen and electric vehicles.

The IRA incentives expand existing tax credits for capital investments and production, designed to build and strengthen a domestic supply chain by encouraging manufacturing and raw material sourcing from the US or from countries with which the US has a free trade agreement. Through an extension of the current production tax credit (PTC) and investment tax credit (ITC), sections 45 and 48, and the introduction of technology agnostic credits (45Y), the law will enact base rates of $0.30 per megawatt hour (MWh) for the PTC and 6% for the ITC through 2032. The new bill will provide 10 years of certainty for an industry that has been constantly begging for stability.  

Moreover, the act is set to boost installed solar and onshore wind capacity in the US by 38% by 2030, with an extra 155 GW of capacity expected to come online this decade. It extends and expands upon existing tax credits, improving project economics and encouraging investments in renewable energy projects. The projects added as a result of the new incentives are expected to attract additional investments of more than $270 billion over the next eight years as developers take advantage of the beefed-up tax credits. 

The Act's impact on the solar industry will be significant, but not immediate. The sector is still dealing with lingering effects from the anti-dumping and countervailing investigation into imports of panels from Southeast Asia, a ban on polysilicon from the Chinese province of Xinjiang, and backlogged interconnection queues. As such, the full effect of the new incentives will not be realized until around 2024. Meanwhile, offshore wind development in the US is still plagued by long approval processes and vessel constraints due to the Jones Act.

The energy storage sector has received a major boost as well. Under the Act, an ITC will effectively be made available to storage technologies from 2022 all the way to 2034 at a base rate of 6% – without collocation or renewable charging requirements, which was previously the dominant process for batteries to enter the market. The financial benefits of the credit will bring certainty for short-term storage projects that could be struggling under current battery pack prices, while also inspiring additional capacity to come into the development pipeline in the medium term. We estimate a 15.1% capacity growth on our 2025 current forecast, resulting in 31 GW of operational capacity by the middle of the decade. For context, half of the world’s battery supply is forecast to come from the US, predominantly from California and Texas.

Batteries are not the only beneficiary of the Inflation Reduction Act, as any type of energy storage would be supported by the proposed ITC. For emerging technologies such as gravity-based storage or alternative battery chemistries to lithium-ion – which accounts for about 96% of the operating batteries in the US – deploying proof of concept plants can be costly, as economies of scale have not been achieved yet. The ITC would reduce capital expenditure and help new storage solutions achieve profitability. For mature storage technologies like compressed air and pumped storage, the Act could spawn renewed interest from developers and investors.

The internal rate of return (IRR) – a metric used to evaluate the profitability of project investments – is likely to rise by one or two percentage points for solar and wind projects. The new legislation will also make the PTC available for solar projects, which were previously unable to take advantage of this tax credit. Developers may opt for the PTC, as solar costs have dropped significantly over the past decade. Despite current global supply hiccups, solar will continue to have one of the lowest levelized cost of electricity among energy technologies.

When evaluating the bill’s impact on the net present value of projects, developers will for the first time have multiple incentive options to choose from. We estimate that for a 250-megawatt (MW) utility-scale solar project, the PTC will be the most beneficial tax credit until a 7.5% discount rate is achieved, after which the ITC will be the preferred tax credit. Meanwhile, the PTC will remain the best option for utility wind developers, as it was before the bill. The ITC, which has widely supported the growth of solar PV in the country, helps reduce a project’s overall cost. The same tax credit could now help batteries unlock new markets and allow for the commercialization of emerging storage technologies. Under the latest act, an ITC will effectively be made available to storage technologies from 2022 all the way to 2034 at a base rate of 6% – without collocation or renewable charging.

Oil and Gas
New provisions related to historical and future acreage leasing in the Gulf of Mexico have now come into effect, enabling the reinstatement of high bid awards from Lease Sale 257 held in November of last year. That round marked a shift in approach by offshore operators, with the dominant bidder by acreage – ExxonMobil – securing 94 blocks across shallow federal waters in what we believe indicates plans to grow its presence in the region for carbon capture and storage (CCS) projects. Besides ExxonMobil, operators BP, Chevron and Occidental secured the highest amount of acreage from the sale, largely expanding their existing deep-water, infrastructure-led exploration portfolios. 

The Act has also ensured an established timeline for two previously cancelled lease sales as part of the 2017-2022 outer continental shelf leasing program. Gulf of Mexico Lease Sales 259 and 261 must be held, respectively, by the end of March and September 2023. As part of the Bureau of Ocean Energy Management’s next five-year outer continental shelf leasing plan, which is currently under comment period, any future offshore wind lease sales must now be tied to holding an additional oil and gas lease sale. Additionally, the act lifted a moratorium for leasing offshore wind acreage in the southeastern US and eastern Gulf of Mexico. To issue a future offshore wind lease sale, an oil and gas lease sale covering at least 60 million acres, or the extent of current Gulf of Mexico lease offerings, must be held in the prior year. This established linkage is now in place for the next 10 years. With offshore wind just beginning to take form in the Gulf of Mexico, operators will now be able to acquire acreage for floating wind developments, oil and gas developments, or CCUS projects, which are now supported by an increase of the 45Q tax credit. The act thus ensures that operators can secure additional oil and gas leases, while simultaneously incentivizing new renewable energy developments in the region. 

The Act has lastly ensured that Gulf of Mexico royalty rates are capped for the next 10 years at 12.5% for leases in water depths of less than 200 meters, and at 18.75% for deeper water. In 2019, Gulf of Mexico lease sales accounted for about $5.5 billion worth of revenue, with the previously mentioned royalty rate scheme in place. Production Tax Credits (PTC) for offshore wind have also been extended through at least 2033. One somewhat overlooked component of the Act is reforms related to planning, permitting and execution of offshore wind projects by increasing funding for more staffing at the BOEM and NOAA – an agreement to expedite permitting on major projects through the future passage of permitting reform legislation.

Over the next 10 years – given continued interest in new leasing activity for either CCUS, offshore wind, or hydrocarbon developments – an estimated $50 billion worth of government revenue could be generated. This crucial revenue will be necessary to help offset increased tax incentives for new carbon capture, utilization and storage developments in the deepwater Gulf of Mexico.

Yet, the IRA has also changed the dynamics of future gas and power markets, directly impacting the coal, nuclear and gas sectors’ outlook due to increased interest and value in CCUS technologies in the power sector. Energy sources like coal and nuclear are now more likely to see higher demand in the long term, forcing natural gas demand down to offset balances. Gas demand reductions of up to 2.4 billion cubic feet per day in 2036, averaging 1.5 Bcfd in yearly reductions over the long term, are now expected. [EM1]This lowered outlook for gas is partly attributed to our expectations that most of the rise in investment in the coming decades will focus on coal and nuclear. Power plants aren’t ideal candidates for CCUS because the emission stream isn’t as concentrated as it is in other industrial facilities, but new technologies that help to concentrate carbon emissions will make CCUS more economic. CCUS on coal-fired generation would result in a net negative for gas-fired generation by extending the timeline of coal capacity – ultimately taking market share away from gas.

However, there is some upside potential for gas, with signs of heightened interest in adopting CCUS on gas-powered facilities as a direct result of the Inflation Reduction Act. Last month, Competitive Power Ventures (CPV) announced a new gas-fired power plant in West Virginia that will use CCUS, with the company directly citing the Act and the CCUS credit as key factors that influenced its plans. It is likely that more initiatives will emerge based on new gas-fired power plants and utilizing the CCUS credit – a positive for gas, but probably not enough upside to offset increased investments in coal and nuclear.

In addition, if extended coal and nuclear capacities cause a drop in gas demand, and if US natural gas output continues to see material growth in the medium to long term, the US could face an overbalance that would force operators to rethink their long-term production plans. This would likely lead to lower production and therefore less revenue. Moreover, investments in gas infrastructure would fall, including in pipelines and LNG projects, meaning lower US gas exports and, hence, further upside risk to prices and an extension of the global energy crisis.

The Act increases the value of credits for projects looking to permanently store CO2 or use it for enhanced oil recovery (EOR). This could incentivize EOR and, crucially, shift Scope 1 emissions[1] to Scope 3 in a region – the United States – with little carbon pricing coverage. The main law regulating CCUS, known as the 45Q tax credit, was initially launched in 2008, with a $20 per tonne credit for storage and $10 per tonne credit for EOR for industrial facilities with annual emissions over 0.5 million tonnes until a cap of 75 million tonnes has been reached. With the IRA, CO2 capture projects starting between 2023 and 2033 that meet certain labor requirements can claim significantly higher credits than previously – more than double in the case of direct air capture (DAC) projects. Based on Rystad Energy’s levelized cost model, this lowers costs significantly, with the cost per tonne of CO2 captured and stored turning negative in some projects. As a result, where CO2 is easily captured from high purity streams, such as in ethanol production or gas processing, projects can be paid to store their CO2 permanently, and even in the case of EOR, gas processing would generally pay. As the Act does not mention quotas for the different credit categories, this could result in a situation where existing projects that can easily capture CO2 (gas processing and ethanol) could quickly attain most of the credits. There is, however, a caveat: If all storage projects that qualified for the maximum credit were to go ahead with their planned injection capacities of over 60 Mtpa by 2030, the entire budget of $3.2 billion over 10 years would be used up by 2026, based on current levels of planned EOR. This suggests the bill is either assuming a high rate of cancellations in the coming years, or that projects will fail to fulfill the labor requirement to meet the higher credit band.

While penetration of carbon capture into the power sector will remain limited, there is little doubt that, in absolute terms, this will be the biggest CCUS sector in the country. Many other industrial and energy sectors are expected to raise their carbon capture penetration in a post-IRA world, including:

  • 155-160 million tpa (or 45% penetration) of capture capacity in ethanol, ammonia and other chemicals

  • 75 million tpa (63% penetration) of capture capacity into gas processing, including LNG

  • 65-70 million tpa of capture capacity from the blue hydrogen sector

  • Significant CCUS penetration into the domestic metals industry, with some cement projects also moving forward

  • 40 million tpa of direct air capture potential by 2035, assuming that ongoing pilot efforts (such as those by Occidental) prove to be successful, while special treatment of DAC is maintained from a tax credit perspective and participants from hard-to-abate sectors embrace the DAC value proposition as a scale generator for the carbon offset market.

As such, in a consistent policy scenario, nationwide capture capacity could reach 600 million tpa by 2035 (up from less than 25 million tpa currently), with permanent storage overtaking EOR as the dominant utilization sector. We note that our most aggressive decarbonization scenario, where the average global temperature increase is limited to 1.6 degrees Celsius (from pre-industrial levels until the end of the 21st century), requires about 1.5 Gt of global capture capacity by 2035 and almost 8 Gt by 2050. Hence, in a consistent policy environment the US is positioned for about 40% of the global CCUS market in 2035 (if the world is to deliver on a 1.6°C carbon budget). This corresponds roughly to the market share of CCUS within the existing global pipeline of projects.

The US will have to experience a boom in CCUS spending levels to get to 600 million tpa capacity by 2035. Under a consistent policy environment, the CCUS market is poised for rapid growth starting in 2024 or 2025, with an annual capex potential of between $12 billion and $14 billion in the late 2020s – from less than $1.5 billion at present. We argue that the post-IRA policy environment can generate $77 billion of incremental capex through 2035 across the capture, transportation and storage sectors. Around $18 billion of incremental cumulative capex will likely come from the accelerated development of the current pipeline of CCUS projects, while $6 billion would stem from increased small-scale capture pilot activity (largely thanks to a significant reduction in the 45Q eligibility capture threshold), and $53 billion would come from a future project pipeline dominated by ensuing phases of pilot schemes in the current pipeline across major industrial hubs in the country. 

Prior to the Inflation Reduction Act, the US market was virtually frozen. On the one hand, the US was uniquely positioned to become a significant player in both the blue and green hydrogen sectors[2]. On the other hand, both regulatory uncertainty and general concerns about the incremental domestic demand for hydrogen in the medium-term were preventing developers from tangible project advancements. The IRA significantly improved the business case for green hydrogen through the introduction of 45V production credits, while improved 45Q credits and the latest Department of Energy hydrogen hub funding announcement provided rationale for tangible progress on the blue hydrogen pipeline. 

Power, long-haul trucking and shipping are expected to drive the growth in domestic consumption of hydrogen and ammonia. This consistent policy could unlock up to $40 billion of incremental hydrogen spending through 2035, excluding carbon capture capex on blue projects. As such, the capex run rate for domestic hydrogen might soar from an average of about $800 million per year in 2015-2022 to more than $5 billion per year in 2030-2035. Around $10 billion of incremental expenditure (versus pre-IRA forecasts) will come from the accelerated development and improved economics of the existing hydrogen pipeline, which is quite balanced across blue and green projects. Yet we argue that the US hydrogen pipeline will gradually shift towards renewable driven water electrolysis – including some nuclear-powered pink projects. Thus, the future pipeline is expected to deliver about $7 billion in incremental capex from blue hydrogen and as much as $20 billion from green and pink hydrogen.

Passenger vehicles assembled in North America will qualify for the $7,500 federal EV tax incentive, leaving approximately 30 models eligible. Although 10 of those models have already met the manufacturers cap (200,000 vehicles sold), the IRA removed that cap starting 1 January 2023. The Act makes eligibility for the full $7,500 incentive contingent on two new requirements, with each valued at $3,750: 

  • Materials: Minerals used in EV batteries must meet a gradually increasing percentage of components extracted, processed or recycled in North America or in countries with which the US has a free trade agreement, starting at 40% in 2023 and increasing by 10% each year, up to 80% in 2026. Starting in 2025, vehicles will not qualify for the tax credit if the battery’s critical minerals were extracted, processed or recycled by a “foreign entity of concern”, which encompasses specifically designated nations and organizations owned by, controlled by or under the jurisdiction of such nations.

  • Components: An EV battery’s components must be manufactured or assembled in North America – 50% beginning in 2023, rising by 10 percentage points each year, up to 100% in 2028. Starting in 2024, vehicles will not qualify if the battery components were manufactured or assembled by a foreign entity of concern.

In summary, the IRA replaces stop-go tax credits with tax credits that are designed to ensure 10 years of energy policy certainty. This is already a towering achievement, given the recent US political history. Moreover, these changes represent a bold and credible plan to accelerate renewables adoption, decrease CCUS costs, reduce methane emissions from oil and gas operations, support EV penetration in passenger road transport, kick-start green hydrogen production, and extend the service life of many nuclear plants. US emissions are thus expected to decrease at a relatively rapid clip and give the country a chance to fulfill its Paris agreement commitments. Most crucially, the IRA appears to be politically robust to changes in the White House, as its reforms have gathered support from voters in both parties, although its repeal cannot be ruled out under a Republican president. Having said that, the Act is also inconsistent in its support to the oil and gas industry. On the one hand, it helps to reduce CCUS costs, which is a solid step forward, but it also fails to remove the shadow of uncertainty that hangs over the Gulf of Mexico lease market. We maintain our argument that the US and the world need steady investments in the oil and gas sector in coming decades to ensure a smooth energy transition and to avoid another energy crisis. 

In essence, the Inflation Reduction Act is an imperfect law, but still one that will change the US energy value chain for the better in the next 10 years.

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Claudio Galimberti  

Senior Vice President of Oil Markets, Head of Americas Research

Emily McClain

Vice President of North America Gas Markets Research 

Artem Abramov

Head of Global Energy Systems

Geoffrey Hebertson

Senior Analyst, Renewables

Colin White


(The data and forecasts contained in this column are Rystad Energy’s and the opinions are of the authors.)