In case you were wondering, this latest missive comes from the desk of your correspondent rather than the overnight sensation that is ChatGPT. Not that we didn’t try to enlist its help! However, ignorant beyond September 2021 for now, ChatGPT remains blissfully unaware not only of Russia’s ‘special military operation’ in Ukraine and its roiling impact on global energy and financial markets, but also the subject of this quarter’s note – the impact of the Inflation Reduction Act on the US oil & gas industry.
ChatGPT: “I'm sorry, but there is no such thing as the "Inflation Reduction Act" currently in effect in the United States. Therefore, it is not possible to determine its specific implications for the US oil and gas industry. Please provide more context or clarify the question.”
For those familiar with the TV comedy series ‘Little Britain’, the equivalent of “Computer says No”.
A Curate’s Egg – ‘Good in Parts’ for The Oil & Gas Industry
The fact that the oil majors – ExxonMobil, Chevron and the like – didn’t kick up a huge fuss about the Inflation Reduction Act (IRA) speaks volumes. Increased access to federal acreage provides an option for E&P players, albeit one that a diminishing number may choose to exercise for oil & gas exploitation. However, federal acreage co-located with substantial industrial carbon-capture opportunities may stimulate renewed interest, but for CO2 storage. The new methane tax only applies to some 2,200 oil & gas facilities but, coupled with increased oversight by the EPA, will drive up equipment, operating and inspection costs. The IRA however provides significant funds to help toward such costs where applicable.
Nascent CCS (carbon capture and storage) and ‘blue’ hydrogen decarbonization technologies currently play a minor part in oil majors’ portfolios. Such technologies could now play a major part given the increased 45Q tax credits now available for CCS. The oil & gas industry is well placed, given its pre-existing subsurface expertise and natural gas infrastructure, to exploit these technologies.
The IRA is primarily about stimulating domestic investment in clean renewable energy sources such as wind, solar and green hydrogen as well as clean transportation. While the growth of clean energy sources will inevitably displace fossil-fuel consumption over the long-term, the expanded 45Q tax credits will provide valuable interim support to the oil & gas industry. Whether perverse or deliberate, the result will be to sustain investment in oil & gas production but deliver lower full-cycle GHG emissions.
What’s good for the goose is good for the gander! The OFS sector is well-placed to capitalize on growing demand for carbon sequestration given its existing capabilities in subsurface data, reservoir modelling, facility engineering and well construction. Increased regulatory oversight of fugitive methane emissions is also generating new albeit modest revenue streams for incumbents and new entrants within the OFS sector with the provision of innovative methane detection technologies and quantification techniques. Substantial federal funding to plug and remediate inactive and orphaned wells should provide strong secular growth to OFS companies that provide reliable, low-cost well decommissioning services.
The Inflation Reduction Act Will Not Reduce Inflation
First things first. The United States’ Inflation Reduction Act (IRA), signed into law mid-August last year, will not do ‘exactly what it says on the can’, namely reduce inflation. Indeed, the IRA will have little to no material impact on inflation, near or medium-term, according to the Wharton School of Business! Moreover, central bank independence surely requires that inflation remains the preserve of Federal Reserve monetary policy, not Congress’ fiscal or regulatory policy. As ever with hard-fought legislation, political horse-trading has resulted in a broad array of special interest spending – US$500 billion in all – and tax breaks, amassed under a clearly topical but misleading ‘Inflation Reduction’ label.
The IRA is less about taming inflation, more a package of industrial subsidies, largely via tax credits: some US$400 billion targeting cleaner energy and a further US$100 billion for improved healthcare.
What’s not to like: cleaner energy, cleaner air and a healthier population? Go ask the U.S.’ competitors.
Such federal generosity comes with strings attached – the clean-energy tax credits only apply to products and parts manufactured or assembled within the United States. Furthermore, at least 40% of the critical minerals used within an EV battery must be extracted, processed or recycled in North America (Canada, Mexico & US) or the 20 countries that have a US free-trade agreement.
Unsurprisingly, political leaders from Brussels to Seoul and beyond have stated that these domestic tax concessions amount to ‘green protectionism’ for US industry, such discrimination violating WTO rules.
The EU has now released its own Green Deal Industrial Plan – widely seen as a direct response to the IRA – early evidence perhaps that this new law may have sparked a clean-energy ‘arms race’, as nations and trading blocs race to offer increasingly generous subsidies for inward clean-energy investment.
Given the scale of media coverage as well as political furor linked to the IRA’s clean-energy subsidies, it is all too easy to miss various initiatives within the IRA that do indeed relate to the oil and gas industry.
Indeed, one of the key architects of the IRA, by virtue of his critical swing-vote within the US Senate, was Senator Joe Manchin. Given his long affiliation with West Virginia – the 2nd-largest coal producing and 4th-largest gas producing state in the US – as both governor and senator, it’s hardly surprising that the IRA in its final form includes various provisions designed to support the US oil and gas industry.
Federal Permitting of Clean Energy Projects Will Drive Continued Federal Oil & Gas Lease Sales
Firstly, several federal oil & gas lease sales, either annulled or suspended by executive order in early 2021, must now be reinstated by year-end 2023. Only Gulf of Mexico lease sales 259 and 261 remain outstanding but these are now scheduled for March and September 2023, respectively.
One of the IRA’s more surprising (and contentious for the green lobby) provisions requires the US government, for the next decade, to regularly auction off sizeable tracts of federal acreage for oil and gas leases as a precondition for any right of way permitting of federal acreage for wind and solar farms.
In detail, no right of way permit can be issued for an onshore wind or solar farm on federal lands unless 1) an onshore oil and gas lease sale has been conducted within the prior four months and 2) the total acreage offered across all onshore oil & gas lease sales within the prior year was at least two million acres.
Likewise, for an offshore wind or solar farm within federal waters, no right of way permit can be issued unless 1) an offshore oil and gas lease sale was conducted within the prior year and 2) the total acreage offered across all offshore oil & gas lease sales within the prior year was at least 60 million acres.
Permitting and development of new wind and solar farms on federal lands and waters can therefore only move ahead in total lockstep with continued auctions of fresh federal oil and gas leases.
The intention of these oil & gas lease-related provisions is twofold: 1) foster more US oil & gas development and thus 2) enhance energy security by sustaining a diverse domestic energy supply mix.
After all, there have been increasingly shrill demands by President Biden and others for the US oil & gas industry to invest far more of its record cashflow to increase domestic production.
The political narrative has truly flipped from “Keep the Oil In the Ground” to “Put More Money In the Ground”.
Increased Access To Federal Acreage Is Unlikely To Stimulate Oil & Gas Production
Increased access to federal acreage is unlikely to prompt a bonanza of fresh oil & gas developments.
Offshore acreage under lease in the Gulf of Mexico has shrunk by two-thirds over the last decade as many E&P players, oil majors and independents, choose not to renew their leases at expiry but instead divert capital and resources to other basins, both domestic and international.
The largest ever federal Gulf of Mexico lease sale was held last November. Just 308 or 2% of the ca. 15,000 open blocks on offer received bids and, with limited competition, typically just one bid at that.
Unsurprisingly, many oil & gas companies have largely shifted their focus toward the prolific onshore shale basins of Texas, New Mexico, Pennsylvania et al. where the majority of land is privately owned.
Federal acreage now accounts for just 24% and 11% of overall US oil, and gas, production, respectively. By contrast, the Permian basin, straddling Texas and New Mexico, provides 40% of US oil production.
Such empirical evidence clearly indicates that access to federal acreage – onshore and offshore – is not the binding constraint on future US oil and gas exploration and development. Rather, the main constraints on further domestic upstream investment are Wall Street and midstream infrastructure. Oil & gas investors now demand better financial returns given the scale of value destruction witnessed during the debt-fuelled US shale boom, while environmental lobbying increasingly delays if not halts the construction of trunklines vital to debottlenecking latent upstream oil & gas production.
… But May Instead Attract Significant Investment In Offshore Carbon Sequestration
Interestingly, the most prolific bidder in that November offshore lease sale was ExxonMobil which secured almost 100 leases not in deepwater – historically their natural preserve – but instead in nearshore shallow waters despite the obvious maturity and low prospectivity of such acreage.
Exxon’s game-plan for these leases is likely to be carbon sequestration rather than oil & gas exploitation. These newly acquired blocks provide a dominant position in a geographically and geologically advantaged area for large-scale carbon capture and sequestration (CCS), close to the CO2 emissions of the many refineries and chemical plants located along the Houston Ship Channel and Gulf Coast.
This lease sale may be the first but likely not the last example of federal acreage being leased for CCS.
Substantial Increases To 45Q CCUS Tax Credits May Ultimately Prove A Big Win For Big Oil & OFS
Given the oil industry’s strategic imperative to decarbonize, the biggest win for the oil industry within the IRA may perversely prove to be the expanded tax credits for CCUS announced within the IRA.
The IRA provides significant upgrades to the 45Q tax credits already available for the utilization and storage (CCUS) of captured CO2, in terms of both value and breadth of application across industry.
Just one catch – the full value of these increased 45Q tax credits is only available to those companies that adopt industry-relevant prescribed wage and apprenticeship practices – which sounds a lot like unionization of labor.
For CO2 captured from industrial processes & power generation:
• Subsurface CO2 storage: US$85/tonne CO2 (up from US$50/tonne CO2);
• CO2 utilization: US$60/tonne CO2 (up from US$35/tonne CO2);
For direct air capture (DAC) of CO2:
• Subsurface CO2 storage: US$180/tonne CO2 (up from US$50/tonne CO2);
• CO2 utilization: US$130/tonne CO2 (up from US$50/tonne CO2);
The scale of facilities that can now qualify for 45Q tax credits has shrunk dramatically. The CO2 capture thresholds (tonnes of CO2 per annum) now stand at:
• Power generation facilities: 18,750 (down from 500,000)
• Industrial facilities: 12,500 tonnes (down from 100,000)
• DAC facilities: 1,000 (down from 100,000)
The twin improvements to the pricing and qualifying scale for 45Q tax credits should allow CCUS to better penetrate those industrial sectors with hard-to-abate yet significant ‘point-source’ CO2 emissions, such as steel, cement, refineries, petrochemicals and power generation. Similarly, industrial facilities that previously lacked the required scale to economically decarbonize may now prove more likely to adopt CCUS technologies. The substantial increase in 45Q support for DAC technologies should also help to underpin their buildout from ‘proof of concept’ pilot-scale toward commerciality.
What’s this got to do with the oil & gas industry? A lot actually. Subsurface CO2 injection was pioneered by the oil industry, albeit not for storage but to enhance hydrocarbon recovery, and the world’s first fully-integrated CCUS project operates on a Norwegian offshore oil & gas production platform.
Big Oil already pumps billions of dollars into CCUS projects and related proprietary technologies. Early mover Occidental now joined by ExxonMobil, Equinor, Shell, Total Energies and many other oil majors.
As the world transitions toward net-zero emissions, some observers believe that the oil industry should adopt a ‘full-cycle carbon management’ strategy, somewhat akin to CaaS (carbon as a service).
ExxonMobil appears to be moving in this direction and clearly views CCUS as a substantial new business opportunity, with “interest from companies across a whole range of industries, a whole range of sectors, a whole range of geographies.”, according to ExxonMobil Low-Carbon Solutions president Dan Ammann.
Last October, ExxonMobil inked a deal to capture, transport and sequester CO2 from an ammonia factory in Louisiana. This deal – the first between an oil company and a 3rd-party industrial facility (and a 3rd-party pipeline) – will benefit from the IRA’s higher level of 45Q CCUS tax credits to the tune of US$70 million per annum.
Dan Ammann of ExxonMobil points to a “very big backlog of similar projects”. The higher 45Q tax credits are likely to ‘unlock’ many similar CCS projects.
Alongside the oil majors, the oilfield service sector has also invested heavily in CCUS technologies and services in order to better meet their clients’ needs in addressing the energy transition and Net Zero.
Schlumberger, a name forever linked with the global oil and gas industry, is now rebranded as SLB with ‘Accelerating decarbonization’ a key tenet of its strategy, as highlighted on its website.
Alongside much investment in innovative and scalable carbon-capture chemistry by both incumbent and new entrants, many of the OFS sector’s existing capabilities in subsurface measurements, reservoir modelling, facility engineering and well construction naturally lend themselves to the emerging needs of carbon sequestration: subsurface geology, site selection, well integrity, long-term CO2 monitoring etc.
‘Blue’ Hydrogen Economics Also Benefit from Increased 45Q Tax Credits
Increased 45Q tax credits also improve the economics of ‘blue’ hydrogen – hydrogen created from natural gas using the traditional steam methane reformation (SMR) process but with additional CCS equipment installed to ensure the capture and sequestration of the CO2 effluent gas.
Recent independent research indicates the increased 45Q tax credits are now enough to make ‘blue’ hydrogen production cost-competitive with current ‘grey’ SMR-based hydrogen production without CCS.
The oil & gas industry is ideally placed, given its pre-existing expertise and natural gas infrastructure, to make significant investments in ‘blue’ hydrogen production. Furthermore, ‘blue’ hydrogen at economic parity with ‘grey’ hydrogen will provide a scalable route toward the sustainable use of hydrogen in many traditional refining and petrochemicals processes.
While green hydrogen – hydrogen created via electrolysis using renewable electricity – is, for many, an ideal fuel source (neither production nor combustion generates GHG emissions), it remains prohibitively expensive, even with the new 10-year 45V tax credits introduced with the IRA.
Methane Tax – An Unnecessarily Complicated Stick …
Marking the first time that Congress has imposed any direct charge or tax on greenhouse gas emissions, the IRA introduces a ‘waste emissions charge’ i.e. tax for excess methane emissions from the oil & gas industry: US$900/tonne of methane for 2024, US$1,200/tonne for 2025 and US$1,500/tonne thereafter.
Simple in principle but ambiguous and complex details ensure that implementation will not be simple.
This new methane tax will apply to some 2,200 US oil & gas facilities – onshore, offshore, upstream and midstream – that each year emit more than 25,000 tonnes CO2-equivalent of greenhouse gas emissions. Curiously, gas distribution facilities are exempt, despite ranking third amongst nine types of oil & gas facilities by annual tonnage of methane emissions.
These 2,200-odd facilities are subject to one of three different gas sales volume-based ‘waste emissions thresholds’ determined by facility type: production, non-production or transmission. All methane emissions above the relevant threshold are then subject to the US$900 to US$1,500/tonne charge.
But this is where it all gets a bit complicated. These ‘waste emission thresholds’ are tied to the volume ‘of natural gas sent to sale’ and thus the volume of all gas components – not just methane but propane, butane, ethane, even carbon dioxide. But the methane tax is tied to weight not volume and solely excess methane emissions. Such unnecessary misalignment will require regular gas assays to avoid errors.
There are further ambiguities and inconsistencies that will leave this new methane tax open to interpretation. But don’t expect the EPA to be able to resolve such issues. The US Supreme Court’s decision in the 2022 West Virginia vs. EPA case placed strict limits on the EPA’s regulatory powers.
Although this new federal methane tax clearly has some wrinkles to iron out, the direction is clear: for designated oil & gas facilities, excess methane emissions will hit the bottom-line, thus stimulating investment, where economically appropriate, in methane detection technologies and/or improved hardware and procedures to detect, mitigate or eliminate excess methane emissions.
… Accompanied by A Carrot – An Array of Grants, Rebates & Loans
Faced with this new tax on excess methane emissions from 2024, the oil & gas industry faces the costs of upgrading equipment along with new operating and inspection protocols to limit and monitor methane emissions at all affected sites (although not gas distribution facilities!).
But there’s a carrot: The Inflation Reduction Act will provide up to US$850 million to the EPA for grants, rebates and loans to help cover the costs of methane emissions monitoring, deployment of improved or innovative equipment and processes and the permanent plugging of wells on non-Federal lands.
There is also a further US$700 million available to ensure that the many thousands of stripper wells that remain on production are also refurbished and monitored to meet exacting emissions standards.
New EPA Guidelines Will Increase Pressure to Eliminate Fugitive Methane Emissions
This focus on detecting and eliminating excess methane emissions will grow stronger once the EPA finally publishes new operating standards, based on its ambitious proposals announced last November.
Industry consultation may well temper some of these initiatives but, for example, zero-emission pneumatic pumps may be enforced across the entire industry; gas flaring could also be prohibited unless all alternatives at a particular facility are certified as unfeasible on technical or safety grounds.
Protocols for emissions monitoring will likely be extended across all wellsites and compressor stations, alongside EPA approval of a new range of technologies for site monitoring and methane detection.
The development of viable methane detection technologies and AI-based quantification techniques remains a fertile ground for investment by both incumbent and new entrants within the OFS sector.
The oil & gas industry, particularly the oil majors, are somewhat ahead of the regulatory curve when it comes to reducing the methane intensity of their operations – part regulatory anticipation, part good PR/business since fugitive methane emissions are bad PR and lost revenue.
Indeed, all manner of methane detection technologies and platforms are being trialed worldwide as oil & gas companies seek to validate and optimize the suite of technologies appropriate to their own needs.
Most E&P players will ultimately deploy the lowest-cost range of products and services that satisfy regulatory requirements and minimize their methane tax burden. Given the range of technologies, platforms and competitors, we expect pressure on product pricing and service margins within this niche and remain somewhat sceptical with regard to the ultimate degree of emission quantification required.
Increased Federal Royalties Are Unlikely To Seriously Hinder US Oil & Gas Production …
Royalty rates for onshore and offshore oil & gas production on federal lands and waters have remained unchanged at 12.5% since their introduction over a century ago. The IRA now increases the royalty rates for new onshore leases to 16.7%, and new offshore leases to between 16.7% and 18.75%. Royalties must also be paid on all gas produced from federal leases on federal lands, even that lost to flaring or venting in all but emergency situations.
No doubt the target of some lobbying, increased federal royalties are unlikely to hinder US oil & gas production. Indeed, royalties levied by private landowners already range from 18% – 20% within the key unconventional Permian and Bakken Basins of Texas/New Mexico and North Dakota respectively.
… But Streamlined Permitting Of Major Infrastructure Projects Was A Missed Opportunity
A federal Permitting Council exists to streamline and accelerate all permitting and review processes – long viewed as opaque, interminable roadblocks to getting key infrastructure projects off the ground.
However, the Senate rejected an IRA amendment that sought to set maximum time limits for environmental reviews and any court challenges of at least 25 energy infrastructure projects deemed to be of ‘strategical national importance’, including the expansion of oil & gas trunkline and CCUS capacity.
This was a missed opportunity to match the rhetoric of increased energy security with clear action.
The Permitting Council ‘talking shop’ remains funded but lacks any claws. Without legally-backed backstops, major energy infrastructure projects of all forms will continue to face challenges and delays.
By way of example, production growth in the Marcellus/Utica – by far the largest US gas basin in the US – has now stalled, largely due to the many regulatory and legal challenges to the completion and permitting of the new Mountain Valley gas trunkline.
Bipartisan Infrastructure Law Allocates US$4.7 billion For Plugging & Remediation Of Orphaned Wells
Beyond our discussion of the IRA, we should not overlook the prior Bipartisan Infrastructure Law (BIL) of November 2021. At least this prior law sets out to achieve ‘exactly what it says on the can’, namely investment in infrastructure, and at US$1.2 trillion a truly staggering level of investment.
With regard to US oil & gas infrastructure, the BIL sets out to eliminate fugitive methane emissions and contaminants leaching into soil and aquifers from orphaned wells (uncapped wells for which no existing or solvent operator can be located) across the US on federal as well as state, private and tribal acreage.
US$4.7 billion is set aside to plug and remediate these orphaned wells, well pads and related facilities.
Last year, the EPA estimated that there are 3.5 million abandoned oil and gas wells across the US, of which just 39% have been plugged. Of the remaining 2.1 million wells that remain uncapped, just 123,000 are documented, although this population will no doubt grow as BIL funding enables better research in the records and on the ground. Per recent empirical research, median costs of US$14,500 for well plugging alone and US$52,600 for well plugging & site remediation indicate that the US$4.7 billion of BIL funding will barely scratch the surface of this problem.
Well decommissioning and site remediation may not be glamorous but, given the intense regulatory focus on fugitive methane emissions, offers strong secular growth for both incumbent OFS providers and those new entrants that provide a reliable, differentiated low-cost alternative solution.
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