OFAC Sanctions Russia’s Energy Sector
In an effort to reduce Russian energy revenues being used to fund the war against Ukraine, on January 10, 2025, the United States Department of the Treasury’s Office of Foreign Assets Control (OFAC), issued a “determination” that subjects the energy sector of the Russian Federation to significant sanctions.
In parallel, OFAC issued a determination that prohibits exportation of petroleum services to Russia from the United States or by U.S. persons wherever located.
Designation of Russia’s Energy Sector. The determination pursuant to Section 1(a)(i) of Executive Order 14024, which took effect on January 10, 2025, designates the energy sector of the Russian Federation economy as a sanctioned sector. As explained by OFAC in FAQ 1214 (issued in conjunction with the determination), not all persons that operate or that have operated in the energy sector are now sanctioned. Rather, the designation enables the Secretary of the Treasury in consultation with the Secretary of State (or vice versa), to impose sanctions on any person, entity, or vessel determined to be operating, or to have been operating, in the Russian energy sector. Any such person, entity, or vessel is now at sanctions risk, and contractual counterparties are on notice that transactions with or involving anyone in the Russian energy sector may be prohibited or blocked without warning.
Pursuant to the authority thus granted, the Secretary of the Treasury immediately listed as Specially Designated Nationals (SDN) Russia’s two leading energy companies (Gazprom Neft and Surgutneftegas), as well as numerous vessels, vessel owners, oil traders, oilfield service providers, insurance companies, and Russian energy officials. Any property or interest in property of anyone listed as an SDN in the possession or control of a U.S. person, must be blocked (i.e., frozen). Any property or interest in property of any entity owned 50% or more by one or more SDN-listed persons or entities must likewise be blocked. The designations prohibit any U.S. person (including any person in the United States) from providing funds, goods, or services to, and from receiving funds, goods, or services from, any blocked person or entity.
The term “energy sector” will be formally defined in forthcoming OFAC regulations. FAQ 1213 sets out the anticipated definition, which will include “activities such as the procurement, exploration, extraction, drilling, mining, harvesting, production, refinement, liquefaction, gasification, regasification, conversion, enrichment, fabrication, manufacturing, testing, financing, distribution, purchase or transport to, from, or involving the Russian Federation, of petroleum, including crude oil, lease condensates, unfinished oils, natural gas, liquefied natural gas, natural gas liquids, or petroleum products, or other products capable of producing energy, such as coal, wood, or agricultural products used to manufacture biofuels; the development, production, testing, generation, transmission, financing, or exchange of power, through any means, including nuclear, electrical, thermal, and renewable, to, from, or involving the Russian Federation; and any related activities, including the provision or receipt of goods, services, or technology to, from, or involving the energy sector of the Russian Federation economy.”
Prohibition on Petroleum Services. The determination pursuant to Section 1(a)(ii) of Executive Order 14071, titled “Prohibition on Petroleum Services,” will take effect at 12:01 am EST on February 27, 2025. It generally prohibits “[t]he exportation, reexportation, sale, or supply, directly or indirectly, from the United States, or by a United States person, wherever located, of petroleum services to any person located in the Russian Federation.”
The term “petroleum services” will be formally defined in forthcoming OFAC regulations. FAQ 1216 sets out the anticipated definition, which will include “services related to the exploration, drilling, well completion, production, refining, processing, storage, maintenance, transportation, purchase, acquisition, testing, inspection, transfer, sale, trade, distribution, or marketing of petroleum, including crude oil and petroleum products, as well as any activities that contribute to Russia’s ability to develop its domestic petroleum resources, or the maintenance or expansion of Russia’s domestic production and refining. This would include services related to natural gas as a byproduct of oil production in Russia.”
General Licenses. OFAC has also issued several general licenses (GL) that mitigate the immediate impact of the determinations. Existing transactions that fall within the prohibitions may be wound down until either February 27 or March 12, 2025, depending on the Russian entity involved (GL 8L, 117, 118, 119). Activities necessary for the health or safety of crews on sanctioned vessels are authorized until February 27, 2025, as are vessel repairs necessary to protect the environment (GL 120). Petroleum services related to three major energy projects (the Caspian Pipeline Consortium, Tengizchevroil, and Sakhalin-2) are authorized until June 28, 2025 (GL 121).
OFAC’s latest salvo against the Russian Federation mandates heightened caution in dealing with the Russian energy sector. Anyone planning or currently involved in such activity would be well-advised to consult with experienced sanctions counsel. Katten stands ready to assist.
Considerations for Avoiding Waiving Contractual Rights to Collect Liquidated Damages
Liquidated damages clauses are inserted into contracts to establish a pre-determined amount of compensation to the non-breaching party where the damages may be difficult to calculate. A variety of circumstances may trigger liquidated damages, including when (1) a party fails to deliver goods on time (thereby causing a delay in production and/or lost sales); (2) a party abandons a lease before its expiration (thereby causing the owner to suffer lost rents and other costs until it obtains a replacement tenant); and (3) a contractor fails to complete a project on time (thereby delaying a new business location’s opening and causing the owner to incur lost profits).
Like all contract provisions, the non-breaching party’s words and/or conduct can waive liquidated damages provisions. To determine if a party has waived their ability to seek liquidated damages, courts consider (1) the contract’s terms and whether the moving party provided notice of the event that triggered the liquidated damages (if the contract requires notice), (2) the parties’ conduct, (3) contractual compliance for extensions, and (4) evidence of extension agreements.
The case U.S. Pipeline, Inc. v. N. Nat. Gas Co., 930 N.W.2d 460 (Neb. 2019) discusses the circumstances that can result in a waiver of rights to collect liquidated damages. In that case, the owner sought liquidated damages from the contractor after the contractor failed to complete the natural gas pipeline construction by the date of substantial completion specified in the contract. Rather than notify the contractor of its intent to enforce the liquidated damages clause, the owner worked with the contractor to develop a new schedule and directed the contractor to perform additional work after the deadline to achieve substantial completion. Importantly, however, the owner failed to provide the revised plans for the extra work for several weeks, thereby delaying the start of the extra work and causing further delays. The contractor performed the extra work and ultimately completed the project several months after the original deadline.
The owner sued the contractor for its delay in completing the project and sought to recover liquidated damages based on the total number of days the project was delayed (which an expert calculated to be a total of 141 days after the substantial completion date). The trial court denied the owner’s claim for liquidated damages, explaining that the owner waived its right to liquidated damages. The Supreme Court of Nebraska affirmed the trial court’s ruling, explaining that the owner’s decision to request the contractor to perform extra work after the date of substantial completion, combined with the owner’s failure to inform the contractor of its intent to seek liquidated damages, demonstrated that the owner intended to waive its right to these damages.
The court’s ruling serves as a powerful reminder that parties can waive their right to recover liquidated damages. Parties seeking to enforce their rights to collect liquidated damages should consider immediately sending written notice of their intent to collect liquidated damages to the other party after it has breached the contract. However, subsequent communications between the parties concerning requests from the owner to the contractor to perform extra work, or about steps the breaching party plans to take to cure the default and/or to mitigate the non-breaching party’s damages should be carefully drafted to avoid a claim that liquidated damages have been waived.
What Will the New FTC Do With the Green Guides?
The incoming administration will change the Federal Trade Commission leadership. Chair Lina Khan, whose term has expired, is leaving, making way for a new majority of three Republican Commissioners. Andrew Ferguson will become the new Chair and Melissa Holyoak will stay on as a Republican Commissioner. President-Elect Trump has stated that he intends to nominate Mark Meador to occupy the seat of the departing Chair Khan. If confirmed, Meador will become the third Republican Commissioner. Expected to stay on are Democratic Commissioners Slaughter and Bedoya. Thus, following the expected confirmation of Mr. Meador, a Republican majority will control the FTC.
The FTC proposed revisions to its well-known Green Guides two years ago. It subsequently held a workshop on Recycling Claims and an informal hearing regarding the Energy Labeling Rule. Most commentators had expected to see final revisions to the Guides released in 2024. But, this has not happened, begging the questions of “what’s the holdup,” “what changes, if any, to the current draft will Republicans seek,” and “what is the new timetable for release?”
The holdup is most likely a result of the changing administration. Commissioner Ferguson notably dissented from the new, narrowed Junk Fees Rule solely because he did not believe the outgoing Commission should issue new rules. Therefore, we certainly do not believe we will see a revision to the Green Guides before the Inauguration.
One would also not expect to see revised Guides until Commissioner Meador (or whoever takes that seat) assumes office and has an opportunity to review the draft. Assuming he agrees with the proposed Guides, one might expect to see revisions issued in mid-2025. If he or others demand changes, however, that could take longer.
The Guides will probably remain as Guides. Although speculation had circulated that recycling claims might be broken off into a new rule, the change in the composition of the Commission makes new rules less likely in general.
For these reasons, the Guides are likely to be issued in 2025. They provide much-needed clarity to marketers that is welcomed irrespective of political affiliation. However, are there adjustments one might expect from the direction that had been conjectured for the Guides?
Although FTC Staff, who work across administrations, are tight-lipped regarding the Guides’ content, a few areas seem to be more politically fraught than others.
Recycling claims are one of those areas. Although there had been considerable chatter from activists regarding the use of the term “recycling” to refer to thermal reprocessing of plastics, a firm stance in the Guides on the issue now seems less likely. Case law had generally interpreted the term “recyclable” to refer to any material that can be recycled, regardless of whether it is actually recycled, and it seems less likely that the newly constituted Commission would issue guidance attempting to influence the courts’ stance.
Moreover, many states have begun to pass their own recycling laws – often referred to as “Extended Producer Responsibility” (or “EPR”) laws. Therefore, one would expect softer language from the FTC here (or less change to the existing guidance) in favor of allowing states to implement their own rules.
“Carbon claims” is another prominent area in which many had urged the Commission to take action. The GOP has signaled mistrust of collaborations to promote “ESG”, and it seems that mistrust might carry over at the FTC to enhanced scrutiny of non-governmental efforts to promote collective actions regarding carbon emissions reduction. Carbon offsets often fall into this bucket, so we do not believe the new Commission will be particularly friendly to voluntary carbon markets. Thus, one might expect to see a new section of the Guides setting out stringent requirements regarding making carbon neutrality claims. One would also expect the Guides to require rigorous support for aspirational environmental claims relating to carbon reduction and energy savings.
Consistent with the GOP skepticism regarding the efficacy of human efforts to combat climate change, the new Guides will likely spell out the need for competent and reliable scientific evidence to bolster any corporate activity claimed to reduce climate change. That could be a tall order for many companies, so one would expect to see a softer approach to such claims going forward. I have been informed by prominent consultants that the acronym “ESG” is on shaky ground, as it has been frequently invoked to include diversity, equity and inclusion programs. As the pendulum swings back, expect to see the term “environmental” more often used in place of “ESG.”
Claims of “sustainability” are also likely to come in for enhanced scrutiny in any Guide revision. Some activities that had been touted for sustainable features may be questioned by the majority, so the use of the term could be constrained more substantially than originally contemplated. One can expect the new guides to treat “sustainability” claims as general environmental benefit claims, which must be qualified. That has already been the practice among most reputable corporations.
Given the importance of the Green Guides, revisions are long overdue. Canada and the EU have already passed new restrictions on environmental claims, so the United States lags internationally. There is likely to be pressure on the U.S. government to update these “rules for the road,” lest the international standards become the de facto rules by which corporate America must live.
Financing Battery Energy Storage Systems – Meeting the Challenges
Introduction
In this article we consider the role and application of battery energy storage systems (BESSs) in supporting renewable energy power generation and transmission systems and some of the challenges posed in seeking to project finance BESS assets.
The need for energy storage
Not so long ago, someone asked the following question at a conference on the development of African power networks attended by one of the authors: why can’t we just use renewables to meet Africa’s demand for electricity? There is, after all, abundant solar radiation across most of the continent. There are obvious challenges – it is dark at night and the winds do not always blow (and sometimes blow too hard for wind turbines), creating variations in generation capacity and, in deregulated electricity markets, price variation and volatility. BESSs offer a number of attractive solutions for shorter-term energy storage to spread supply capacity over time and to enable electricity price arbitrage.
Batteries are relatively cheap for smaller scale and shorter duration energy storage and prices of cells have historically fallen. They are also well-suited to energy storage in that their “round trip” efficiency is high (around 83 to 86% for conventional lithium ion[1] and up to 93% for lithium iron phosphate (LiFePO4) batteries[2]), which is slightly better than pumped hydro (70 to 80%) and much better than compressed air systems (42 to 67%) or compressed green hydrogen (18 to 46%, depending on the re-conversion method).
There is also a more obscure technical challenge associated with relying predominantly on renewable power generation: the need for “inertia” to ensure grid frequency stability.
What is inertia?
Ignoring HVDC transmission lines and interconnectors, electricity distribution networks operate using alternating current (AC). AC is used because it is easy to transform between different voltages using a transformer: high voltages are needed for transmission lines to minimise energy losses and lower voltages are required by consumers and other users for safety and practical reasons. In order to avoid causing problems with and possible damage to connected equipment, the frequency (typically 50 or 60 Hz), phase and voltage of the grid must be fixed within narrow tolerances.[3]
Traditional power generation systems, such as thermal power stations, utilise turbines and generators with large rotating masses which have significant real inertia, storing large amounts of kinetic energy and physically resisting changes in rotational speed. Once a generator is synchronised to the grid, this inherent inertia helps to stabilise the frequency and voltage and to slow down changes in frequency caused by changing electrical loads or supply disruptions. This property is known as “inertial response”.
If thermal generation systems are replaced by renewables such as wind[4] and solar, and the inertia response of the grid is not replaced by other inertial systems, the grid may become more vulnerable to voltage and frequency deviations that exceed permitted limits; and such excursions may trigger disconnections of generating units or other shutdowns.
In particular, certain types of wind turbine generators have a design which disconnects from the grid when the voltage falls below a minimum threshold. The distributed nature of wind turbine generators makes them vulnerable to a “chain reaction” effect which may result in a cascading disconnection of turbines from the grid.
A striking example was the South Australian blackout that occurred in 2016 following extensive storm damage to the state’s electricity transmission network. Almost the entire state lost its electricity supply as successive transmission lines and wind farms and ultimately the high voltage Heywood interconnector to Victoria tripped out owing to cascading voltage and frequency “events”. It took several days fully to restore the electricity supply to the entire state, relying initially on the Heywood interconnector to establish an initial stable state and to restart the Torrens Island Power Station because local black-start facilities were insufficient.
Synthetic inertia
Battery energy storage systems have a very useful property: using appropriate electronic control systems, high-power inverters and step-up transformers to convert their direct current (DC) output to AC at grid voltage, power can be transferred into the grid in a flexible, actively directed manner, that is able to respond dynamically and almost instantaneously to grid deviations in frequency and voltage. Such systems are in effect a form of “synthetic inertia” but offer greater flexibility than traditional “spinning” systems.[5]
The UK National Energy System Operator is developing a framework to procure a suite of “dynamic response services” from service providers, comprising dynamic containment (DC), dynamic moderation (DM) and dynamic regulation (DR) services which are planned to work together in concert to control grid system frequency and to maintain it within permitted limits, replacing to some extent the traditional inertia provided by thermal power stations. The intention is to create day-ahead frequency response markets for DC, DM and DR.
These new services are expected to be provided by energy storage systems and battery systems are well-suited to perform such roles owing to their fast response times. However, managing the battery state of charge (SoC) in advance and keeping systems within their warranty constraints (see below) poses technical and commercial challenges. Dynamic response products may also need to be “stacked” by providers (with a single BESS providing different services simultaneously, but with each MW of capacity partitioned to provide a single service) to optimise utilisation and revenues, leading to additional complexity.
BESS services more generally
BESS has many potential applications other than dynamic response services which are well suited to commercial exploitation. Notable examples are the following:
provision of additional electrical supply capacity at times of system peak demand;
energy time-shifting (allowing arbitrage between higher and lower energy prices);
transmission system congestion relief (acting as an energy sink to spread the demand on a transmission line over time);
voltage support;
black start services to provide the initial power required to start up larger power plants (for which a provider may be paid for availability, even if their services are rarely used);
transmission/distribution systems upgrade deferral (similar to congestion relief services); and
demand side services, including power reliability/UPS systems and power quality services.
Economics of BESS services
It is important to keep in mind that in economic terms, most BESS revenues are typically derived from time-shifting/price arbitrage, congestion relief and providing security of supply. Other services, including dynamic response/synthetic inertia typically provide a relatively small component of enduring revenue streams, despite their critical role in ensuring grid stability (not least because the volume of these services is relatively low, and even a small volume of market entry by flexible capacity can reduce the market clearing price for these services).
However, time shifting/price arbitrage, congestion relief and even dynamic response services are likely to involve merchant risk. For example, price arbitrage involves active trading in wholesale markets, and the UK is proposing that dynamic response services would be priced by day ahead auctions.
While operators of BESSs may “stack” different merchant revenue streams, it is clear that financing projects which rely on such sources to earn a return may be difficult. Volatility associated with merchant income is, in many jurisdictions, made worse by policy uncertainty. Policy choices drive the level of renewable investment, the extent of grid reinforcement and the extent of demand growth from newer flexible uses of power (such as electric vehicles), all of which influence market prices and the scope for time shifting and price arbitrage.
Set against the difficulty of financing BESSs is their importance to energy transition. As noted above, their ability to absorb excess intermittent renewable generation and provide a new source of synthetic inertia means they will be a fundamental part of any low carbon grid. In the UK, the “Clean Power 2030” plan for a low carbon grid foresees battery capacity between 23 and 27 GW. This may imply the need for further government intervention to support the investments.
As international electricity markets are gradually de-regulated, as is happening in many African jurisdictions, they may look overseas to historical precedents in deciding how to structure their markets and systems of government support. The UK (and to a lesser extent Europe) have historically been leaders in deregulation and electricity market innovation.
The possibility to provide support to low carbon sources of flexibility is explicitly foreseen in European legislation[6], and has been recognised in the UK government’s Review of Electricity Market Arrangements. However, there is less consensus on the design of an appropriate intervention.
In the UK, a cap and floor scheme is proposed for long duration energy storage (principally pumped hydro storage). The scheme would ensure that projects which the regulator recognises as beneficial receive a minimum level of gross margin. This floor is likely to be set at a level which ensures that reasonable levels of debt can be serviced. The quid pro quo is that the returns which plants can make will be capped. A similar regime is applied to interconnectors in the UK. The definition of “long duration” remains to be decided, but it is possible that some very long duration batteries may be eligible for this scheme.
In contrast, for shorter duration storage (more likely to be relevant for batteries), no specific scheme has yet been put forward. The government has indicated that it is considering modifications to the UK’s capacity auction arrangements. These see generators and storage operators offer to sell their availability to a central counterparty, and are designed to ensure that there is sufficient capacity on the grid to meet expected peaks in demand. At the moment the auctions are technologically neutral: fossil and non-fossil capacity competes in the same market (although there are already limits on the running hours of fossil fuelled plants).
But change may be in the air. While the final details are still being debated, the UK government might modify the auctions to ensure a minimum amount of low carbon flexibility is purchased. This would allow the price paid to low carbon flexible plants (such as batteries) to exceed that paid to other capacity (such as thermal generating plants). As with agreements concluded in today’s capacity auctions, the clearing price in such a modified auction would be indexed for 15 years and paid to investors by a central counterparty. The thinking is that this would again provide greater scope for debt financing.
Yet more variation is found in continental Europe. In Greece, the government has proposed a support regime for a pumped hydro plant (PHS Amfilochia). The effect of the arrangement would be that the plant’s investor would secure a regulated rate of return independent of merchant revenues. And in Italy, the Electricity Storage Capacity Procurement Mechanism (MACSE) also envisages provision of a largely regulated return to storage investors. In contrast to the Greek mechanism, the Italian regime would provide the potential for a small upside based on merchant returns.
As such, in looking to project finance BESSs in Europe, the scope for either long term bilateral contracts with blue-chip counterparties (e.g. to provide resilience of supply to datacentres) or policy support is likely to be an important factor in determining priority jurisdictions for investors, who will seek greater revenue and price certainty to underpin debt service and fixed operating costs and provide returns to equity. This is not to say that merchant projects are not possible. Many may still obtain financing, but only after careful diligence as to the likely evolution of merchant margins, and where stacking of revenues can provide some diversification and upside.
Key battery parameters and implications for financing BESS projects
In any discussion about structuring BESS projects and their financing, the particular properties and performance characteristics of batteries need to be taken into account.
Manufacturers of batteries define two key indicators which reflect their states and are useful in optimizing battery use and performance:
Stage-of-Charge (SoC) is a measure which compares the current level of charge in the battery as a percentage of its level when fully charged, reflecting the quantity of electrical energy stored as a ratio of the maximum possible stored energy that the battery is capable of holding. As cell health declines the maximum possible charge that may be stored also declines. Another parameter that is sometimes referred to is Depth-of-Discharge (DoD), which is the inverse of SoC, so if the SoC is 80%, the DoD is 20%.
State-of-Health (SoH) compares the maximum capacity of a fresh battery and a battery that has “aged” through use, owing to electrochemical deterioration. SoH is defined as the ratio of the maximum quantity of energy the battery is able to store at any time to its rated capacity, expressed as a percentage. As SoH degrades, the useable capacity of the battery diminishes because it will discharge sooner at a given rate of discharge (i.e. at a given output current).
Degradation in state of health (SoH)
The SoH of a lithium-ion battery declines with increasing number of battery charge and discharge cycles in a reasonably predictable manner, provided the battery is not excessively stressed. A typical rule of thumb is to assume a 10 year useable lifespan for daily charge/discharge cycles, i.e. around 4,000 cycles. However, at the upper end of the range, a well-known manufacturer’s sales literature indicates that its 68Ah cell reaches 80% SoH after 6,000 cycles,[7] representing a little over 16 years of daily cycles.
Cell lifespan may be affected by a number of factors including temperature, depth of discharge and charging current (C-rate); and achieving the upper end of the lifespan range may involve conservative assumptions about DoD and maintaining an optimum temperature within a tight range. SoH degradation curves may be non-linear and exhibit accelerated degradation with increasing number of cycles beyond a threshold point.
Useable lifetime and implications of degradation for system design
Usable battery lifetime (the point at which SoH has declined to a level which compromises the useability of a BESS) depends on the application. SoH degradation and the inherent decrease in capacity over time need to be taken into account in scoping and defining the services that a BESS project company commits to provide to an offtaker, as well as the duration of those services and the charges for those services.
If the project company’s contractual commitment is of sufficient duration, it may be necessary for it to incur capital expenditure to renew or add cells to restore the BESS’s performance; and this would be to be taken into account in calibrating service charges to be paid by the offtaker to the project company. The cost of renewing cells may however be difficult to predict; whilst cell costs have historically fallen over time, potential shortages in lithium and other essential raw materials and constraints on manufacturing capacity or increased demand might cause an unanticipated spike in prices.
In the case of a BESS that is routinely charged and discharged in daily cycles, the system lifetime and its economic life may be reasonably predictable. One example might be a BESS combined with a solar PV power plant that is charged during the daytime and discharged at night to provide power to (for example) a datacentre. Another example might be a BESS at an EV charging station which is charged during periods of low demand (at night) and discharged at times of peak EV charging demand – using such a system could relieve supply line congestion by spreading power supply demands over time.
However, in a more complex use scenario such as providing dynamic grid frequency stabilization services, the frequency of charge/discharge cycles may be more unpredictable as it may depend on more random factors such as wind speed variation/gusting. Consequently, the economic life of the BESS modules may vary widely and depend on the usage pattern.
In economic terms, an unpredictable usage pattern which may result in varying O&M costs (including capital expenditure being incurred at uncertain times to replace degraded cells) suggests a possible need to vary a portion of the charges for provision of the services according to the usage pattern (rather than merely levying a flat availability charge): this could be seen as analogous to the energy charge for a thermal power project which typically involves pass-through of variable operating costs that correlate with usage patterns.
Alternatively, the obligation to provide services could be inherently limited so that cell charge-discharge cycling constraints are respected and maintained within agreed limits.
Such factors are likely to be a key focus for potential lenders to a project who will be concerned if the project company is exposed to excessive risk in relation to the period over which the BESS is able to generate revenue and/or uncertainty over O&M costs. One option that might be considered by lenders is to sculpt the repayment schedule for their debt to take into account the rate of reduction in the system SoH to the extent that project revenues depend on the SoH and decline in tandem.
Battery warranties
Warranties are available from suppliers of batteries which guarantee their useable energy capacity (i.e. the SoH) for a defined period, typically up to ten years, based on defined usage parameters. Not surprisingly, the guaranteed capacity is related to the predicted SoH degradation curve, but it may be possible to modify the guarantee terms for a price so that they are more favourable.
One option that may be explored is an extended supplier’s warranty which artificially extends the SoH and slows the degradation curve for a fee – this is in effect a hybrid warranty/maintenance service as the supplier will inevitably have to replace degraded cells to achieve the extended BESS lifespan.
Mitigating degradation
The rate of degradation may be reduced by limiting maximum charge and depth of discharge (DoD) within a defined SoC window, which may be dynamically altered as the battery ages. Battery management systems may be programmed to manage SoC to increase lifespan at the expense of reducing useability. This is a common approach in EV battery management systems, preserving battery lifespan at the expense of maximum range.
Management of DoD and maintaining it within certain limits may also be required to preserve a valid manufacturer’s warranty or to achieve more favourable warranty terms. This has implications both for the technical design of BESS systems (and in particular battery management systems and software) and for scoping and defining the services that a BESS project company commits to provide to an offtaker and the technical limits of those services.
Environmental conditions
Cell performance and lifespan depend to a large extent on maintaining suitable environmental conditions. If the operating temperature is maintained within a relatively tight range, the cell lifespan may be enhanced and accordingly supplier warranties may be subject to specific environmental conditions being met and maintained such as maximum and minimum temperatures and limitations on the period of any temperature excursions.
In designing their systems, BESS operators will therefore need to consider how best to mitigate the risk of damage being caused to batteries or warranties being invalidated by thermal events, such as building in heating and ventilation system redundancy, incorporating back-up systems and modularization/containerisation of BESS units, so that in the worst case, only one module is compromised by any unplanned thermal excursion.
Other factors
Battery health is affected by charge and discharge rates (C-rates) but such limits should be built into the design of the battery management system and associated systems. Operators of BESSs will however wish to ensure that battery management systems (and their firmware/software) are capable of being supported over the long-term and that if they can no longer be supported, that they are readily able to be upgraded or replaced.
Second life batteries
Electric vehicle batteries that have reached the end of their usable life in mobile applications may have a second life in static BESS applications. The cost of such used batteries should be significantly lower than new batteries and their reduced energy density compared with new batteries might be less of a concern for stationary applications. For example, Nottingham City Council has installed 600kW of second life storage at its EV fleet depot to store excess electricity from on-site solar PV arrays which is then used to charge their EV fleet at peak times. The systems also aims to participate in grid services by trading stored electricity and providing vehicle-to-grid energy supply via bi-directional EV chargers.
Lenders may however have a concern about the remaining economic life of used cells and how predictable it is and may naturally be cautious and reluctant to take a view on the ability to replace such cells should they fail or reach an unacceptably low SOH. That said, the EV market is growing and the supply of used batteries should expand rapidly; and as the use of second life cells increases and the available data on their performance grows, the risks associated with such arrangements may become better understood and more predictable.
Conclusion
Battery energy storage systems represent a keystone for the transition towards a more sustainable energy generation and utilisation. Despite the value and advantages that they offer to enhance grid reliability and stability and to integrate with renewable power sources, significant challenges remain in securing financing for BESS projects. Addressing those challenges will require supportive regulatory frameworks, innovative government price and demand support arrangements, a flexible and innovative approach to project structuring, appropriate sharing of risk between operators and suppliers and technical solutions which mitigate commercial and technical risks. Overcoming these hurdles will allow the full potential of battery storage systems to be unlocked, paving the way for a more resilient and sustainable energy future.
[1] The U.S. Energy Information Administration records an average monthly round trip efficiency of 82% being achieved in 2019. The U.S. National Renewable Energy Laboratory 2021 Annual Technology Baseline figure is 86%.
[2] Data published by GivEnergy for its BESS products.
[3] For example, the UK’s National Energy System Operator has a licence obligation to maintain system frequency within a range of 50Hz +/- 1%, i.e. between 49.5 and 50.5 Hz.
[4] Wind turbines are built to be lightweight and have relatively low inertia. Variable speed wind turbines which utilise doubly fed induction generators (DFIGs) pose particular challenges: during a grid fault condition the power conversion system may be unable to handle the currents in both rotor and stator, leading to the wind turbine being disconnected from the grid.
[5] Even with high levels of synthetic inertia, a grid will still need “real” physical inertia. The UK National Grid ESO has contracted for several sources in the UK (e.g. at Deeside in England and Rassau in Wales) to provide “synchronous condensers” whereby motor-generators use grid power to spin up and maintain large masses in rotation to act as flywheels.
[6] For example, Article 19g of EU/2019/943 as amended, on “non-fossil flexibility support schemes”
[7] Lab test with 100% DoD, 1C/1C charge/discharge rate and at a temperature of 25°C.
Final Regulations for New Clean Energy Production and Investment Tax Credits
Last week, the Internal Revenue Service (“IRS”) and Department of the Treasury issued the highly anticipated final regulations for the Clean Electricity Production Tax Credit set forth in Section 45Y of the Internal Revenue Code of 1986, as amended (the “Code”) and the Clean Electricity Investment Tax Credit set forth in Section 48E of the Code (the “Final Regulations”), which may be found here. The Final Regulations follow the issuance of proposed regulations (the “Proposed Regulations”) last June. The Final Regulations provide clarification regarding the definition of “qualified facility” and the mechanism for calculating the greenhouse gas (“GHG”) emissions rates for qualified facilities, although a full analysis of the GHG requirements is beyond the scope of this blog post. Further, we note that with the incoming administration, the executive branch could review and, potentially, rescind, these Final Regulations, although at this point the Trump administration has not publicly indicated support or a the lack thereof.
The Final Regulations generally apply to facilities placed in service after December 31, 2024, and during a taxable year ending on or after January 15, 2025. However, certain rules relating to the “One Megawatt Exception” under Section 1.45Y-3 of the Final Regulations and relating to qualified facilities with integrated operations have a delayed applicability date that is 60 days after publication of the Final Regulations.
When Sections 45Y and 48E of the Code were initially enacted, we posted a blog describing the new statutes, which is available here. The following is a brief, high-level, summary of the Section 45Y and Section 48E rules, but does not describe every requirement for credit qualification. The rules under Sections 45Y and 48E of the Code apply to qualified facilities that both begin construction and are placed in service, each for federal income tax purposes, on or after January 1, 2025. As such, qualified facilities that either begin construction or are placed in service before January 1, 2025, should still generally look towards the rules set forth in Section 45 of the Code for the production tax credit (the “PTC”) or in Section 48 of the Code for the investment tax credit (the “ITC”), as applicable.
The credits under Sections 45Y and 48E are available with respect to any qualified facility that is used for the generation of electricity, which is placed in service on or after January 1, 2025, and has an anticipated GHG emissions rate of not more than zero. In the case of Section 48E, a qualifying energy storage facility is also eligible for the credit. Qualified facilities also include any additions of capacity that are placed in service on or after January 1, 2025.
The credit under Section 45Y generally mirrors the PTC in that it is a credit that is based on electricity produced by a qualified facility, and the credit under Section 48E generally mirrors the ITC in that it is a credit that is based on a taxpayer’s tax basis in a qualified facility, with several differences in each case. The credit amount for each is generally calculated in the same manner as the ITC or PTC, as applicable. However, the credit amount is phased out (as set forth in the chart below) based on when construction of a qualifying facility begins after the “applicable year.” Under Sections 45Y and 48E of the Code, the applicable year means the later of (i) the calendar year in which the annual greenhouse gas emissions from the production of electricity in the United States are reduced by 75% from 2022 levels, or (ii) 2032.
Year After Applicable Year in Which Construction Begins
First
Second
Third
Thereafter
Percent of Credit Remaining
100%
75%
50%
0%
The Final Regulations apply many of the historical rules of Sections 45 and 48 of the Code, including rules surrounding the base credit amount—0.3 cents per kWh of electricity (subject to inflation adjustments) under Section 45Y and 6% under Section 48E. These credit rates may be increased in either case by satisfying either the 1 MW (AC) exception or the prevailing wage requirements—up to 1.5 cents per kWh of electricity (subject to inflation adjustments) under Section 45Y and 30% under Section 48E. Energy community and domestic content bonus credits may also increase these credit rates, although there are important differences in how these rules apply.
The below highlights several notable aspects of the Final Regulations.
Notable Rules Under Section 45Y
Under Section 45Y, a facility that initially operates with greater than zero GHG emissions (and, therefore, is not eligible for the credit under Section 45Y) may later be treated as a qualified facility—and, therefore, eligible for the credit under Section 45Y—if it meets the requirements in any taxable year during the 10-year period beginning on the date the facility was originally placed in service. For example, if an otherwise qualified facility has greater than zero GHG emissions for its first three years of operation (2025-2027, for example), but then is updated in such a way that it satisfies the zero GHG emissions requirement, then the Section 45Y credit may be claimed for years 4 through 10 of operations (2028-2034, in this example).
Similar to the PTC, electricity produced at a qualified facility must be sold by the taxpayer to an unrelated person. However, in a departure from the rules under Section 45, the statute and Final Regulations provide that, in the case of a qualified facility equipped with a metering device that is owned and operated by an unrelated person, the credit under Section 45Y of the Code is available for electricity produced at a qualified facility and sold, consumed, or stored by the taxpayer. Although this rule provides some flexibility to taxpayers, the IRS declined to adopt the Section 45 rule from IRS Notice 2008-60, which provides that electricity sales will be treated as made to an unrelated taxpayer if the producer of electricity sells electricity to a related person for resale to a person unrelated to the producer.
Notable Rules Under Section 48E
Under the Final Regulations, “qualified facilities” and “energy storage technology” (“EST”) are defined, and treated, separately. Accordingly, Section 48E does not permit combined solar and storage facilities—each facility must claim the credit under Section 48E separately as a “qualified facility” or an “EST,” as applicable. This rule could have implications for application of the prevailing wage and apprenticeship requirements, domestic content adder eligibility, and energy community adder eligibility.
Similarly, the Final Regulations define “unit of qualified facility” to include all components of functionally interdependent property, and the term “qualified facility” to mean a unit of qualified facility plus integral parts. This is significant because satisfaction of the prevailing wage and apprenticeship requirements, domestic content adder eligibility, and energy community adder eligibility are each determined on a “qualified facility” basis. To take an example, this means in many cases that prevailing wage and apprenticeship, domestic content, and energy community eligibility would be measured for a solar facility at the inverter level, rather than on a project-wide basis as is required for the ITC under Section 48 of the Code. Although this rule was in the Proposed Regulations, many commenters asked the IRS to permit some form of aggregation (similar to the energy project rules under Section 48) for purposes of Section 48E. The IRS declined this request, and the rules in the Final Regulations now will require very careful planning for prevailing wage and apprenticeship, domestic content adder, and energy community adder purposes.
In addition, under the Final Regulations, the cost of qualified interconnection property (which is similarly defined under the final regulations for Section 48) is only ITC-eligible for “qualified facilities.” For EST, the cost of interconnection property is not eligible for the credit under Section 48E. Again, this is different from the application of the ITC for qualified interconnection property for energy storage technology that is eligible for the ITC under Section 48 of the Code.
Notable Rules for both Section 45Y and 48E
The Final Regulations adopt the rule from the Proposed Regulations that the following types or categories of facilities may be treated as having an emissions rate of not greater than zero: wind, solar, hydropower, marine and hydrokinetic, geothermal, nuclear fission, fusion energy, and certain waste energy recovery property. For types or categories of facilities not listed above, taxpayers must rely on the annual table that sets forth the GHG emissions rates in effect as of the date the facility begins construction or, if not set forth on the annual table, the provisional emissions rate determined by the Secretary for the taxpayer’s particular facility.
In addition, for the types or categories of facilities not listed above, the Final Regulations confirm that certain emissions of GHGs are excluded from the requirement that the GHG rate be not greater than zero, including, for example, emissions that occur before commercial operation commences and emissions from routine operational and maintenance activities.
Both Section 45Y and 48E rely on the existing prevailing wage and apprenticeship rules contained in Sections 45(b)(7) and (8) of the Code and Sections 1.45-7, 1.45-8 and 1.45-12 and 1.48-13 of the Treasury Regulations except, as noted above with respect to Section 48E, prevailing wage and apprenticeship is measured as the qualified facility level rather than the energy project level (as it has been for the ITC).
For the 1 MW (AC) exception under both Sections 45Y and 48E, the Final Regulations incorporate similar rules for calculating nameplate capacity as provided in the final regulations under Section 48. However, the Final Regulations also provide that the nameplate capacity of a qualified facility with “integrated operations” with any other qualified facility must be calculated using the aggregate nameplate capacity of each qualified facility. A qualified facility will be treated as having “integrated operations” with any other qualified facility if the qualified facilities are of the same type of technology and (1) are owned by the same or related taxpayers, (2) placed in service in the same taxable year, and (3) transmit electricity generated by the qualified facilities through the same point of interconnection, if grid-connected, or are able to support the same end user, if not grid-connected or if delivering electricity directly to an end user behind the meter. These rules have a delayed applicability date of March 16, 2025.
Both Sections 45Y and 48E adopt the familiar 80/20 rule, which states that a facility may qualify as originally placed in service even if the unit of qualified facility contains some used components of property provided the fair market value of the used components of the unit of qualified facility is not more than 20% of the total value of the unit of qualified facility (which is determined by adding together the cost of the new components of property plus the value of the used components of property included in the qualified facility).
As the (Customs and Trade) World Turns: January 2025
Welcome to the January 2025 issue of “As the (Customs and Trade) World Turns,” our monthly newsletter where we compile essential updates from the customs and trade world over the past month. We bring you the most recent and significant insights in an accessible format, concluding with our main takeaways — aka “And the Fox Says…” — on what you need to know.
This edition provides essential insights for sectors including International Trade, Aluminum and Steel Industries, Fashion and Retail, E-commerce, Automotive, and Compliance, as well as for in-house counsel, importers, and compliance professionals.
In this January 2025 edition, we cover:
Federal Circuit deliberates on Section 301 tariffs: a landmark case for importers.
Aluminum extrusions import dispute: CIT to review ITC’s negative determination.
CBP’s proposed rule for low-value shipments: CBP’s attempts to enhance efficiency and security.
Forced labor enforcement intensifies: new challenges and strategic shifts.
Mexico’s textile and apparel tariff hikes: navigating new import challenges.
CFIUS controversy: presidential block on Nippon-US Steel deal sparks legal battle.
Temporary sanctions relief: OFAC authorizes limited transactions, maintaining key restrictions.
1. Section 301 Tariffs Appeal: Federal Circuit Hears Oral Argument
On January 8, the US Court of Appeals for the Federal Circuit (CAFC) heard the oral argument in HMTX Industries LLC v. United States, a pivotal case challenging the legality of tariffs imposed on Chinese-origin goods under Lists 3 and 4A of the Section 301 tariff regime. These tariffs, which cover approximately $320 billion in goods, have been challenged by over 4,000 importers.
Central to the case is whether the US Trade Representative’s (USTR) actions expanding tariffs to the Lists 3 and 4A qualify as a permissible “modification” of the original Section 301 action (covering Lists 1 and 2) under Section 307 of the Trade Act of 1974. The plaintiffs argued that the term “modify” allows only moderate or minor adjustments to the original tariffs, which targeted $50 billion in goods. The judges explored whether the statutory language supports such limits and considered distinctions between this case and prior rulings interpreting a different section of the Trade Act that limited “modification” to smaller adjustments.
The panel also examined whether China’s retaliatory tariffs, which formed the basis for USTR’s tariff increases under Lists 3 and 4A, were sufficiently linked to the intellectual property violations initially investigated under Section 301. The plaintiffs argued these actions were distinct, while the government claimed they were part of the broader context of unfair practices. A final issue was whether USTR’s authority to modify tariffs when an action is “no longer appropriate” could justify broader increases, with the judges probing the potential limits of this provision.
And the Fox Says…: The CAFC is expected to issue a decision before the end of this year, though further appeals could extend the litigation into 2026. A final ruling for the plaintiffs could lead to refunds of tariffs paid under Lists 3 and 4A for those participating in the litigation, and to the end of any Lists 3 and 4A tariffs. More broadly, the decision could constrain future tariff actions, particularly those being contemplated by President-elect Donald Trump in his second term or validate such escalation of tariffs.
2. Challenging the US International Trade Commission’s Decision: Implications of the Appeal on Aluminum Extrusions Imports
On November 26, 2024, the petitioners, US Aluminum Extruders Coalition (USAEC) and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union (USW), filed a summons with the US Court of International Trade (CIT), contesting the US International Trade Commission’s (ITC) final negative determination in the aluminum extrusions’ antidumping and countervailing duty (AD/CVD) proceedings against multiple countries. As we discussed previously, on October 30, 2024, the ITC had reached a negative determination in its final phase of the antidumping and countervailing duty investigations concerning aluminum extrusions from China, Colombia, Ecuador, India, Indonesia, Italy, Malaysia, Mexico, South Korea, Taiwan, Thailand, Turkey, United Arab Emirates, and Vietnam.
The CIT will either affirm the underlying decision by the ITC, which can then be appealed to the US Court of Appeals for the Federal Circuit, or it can remand the decision back to the ITC for further consideration of certain matters. Remand could lead to a new vote from the Commissioners sitting on the Commission at that time. If the decision by the Commission becomes affirmative, and the CIT affirms, AD/CVD orders will be issued. The appeal may be taken to the US Court of Appeals for the Federal Circuit.
And the Fox Says…: Importers should closely monitor the CIT appeal. If the case is remanded and the ITC makes an affirmative determination which is affirmed by the CIT, AD/CVD orders will be imposed and estimated AD/CVD duties will have to be deposited and ultimately collected at liquidation. Please contact the AFS team if you are uncertain whether the product you import containing aluminum extrusions is within the scope of the investigations and therefore potentially subject to AD/CVD duties if the CIT remands the case and the ITC makes an affirmative determination.
3. CBP Proposes Enhanced Entry Process and Other New Rules for De Minimis Shipments
US Customs and Border Protection (CBP) has announced a notice of proposed rulemaking (NPRM) aimed at modernizing the entry process for low-value shipments, specifically those valued under $800. The proposed Entry of Low-Value Shipments (ELVS) rule is intended to increase the efficiency and security of processing these shipments in response to the rise of e-commerce. Through this process, CBP aims to expedite clearance and improve its ability to target high-risk shipments, such as those containing illicit drugs.
The ELVS rule would create a new “Enhanced Entry Process,” based on lessons learned from the Section 321 Data Pilot and Entry Type 86 test, requiring the advance electronic submission of various data elements, including the shipment contents, origin, destination, and a 10-digit Harmonized Tariff Schedule of the United States (HTSUS) classification, amongst others. An HTSUS Waiver Privilege is also included in the proposal, allowing certain filers to bypass the requirement to submit an HTSUS classification, subject to certain requirements, including documented internal controls ensuring certain compliance measures. Goods that are regulated by other federal agencies and mail importations must go through the Enhanced Entry Process.
Additionally, the “Release from Manifest Process” will be renamed the “Basic Entry Process” and revised to include additional data elements for verifying eligibility for duty- and tax-free entry. Another key change is the specification that the “one person” eligible for the de minimis exception is only the owner or buyer of the goods and no longer a consignee receiving the goods. Where a person receives multiple shipments that exceed the $800 threshold in the aggregate on a single day, none of the shipments would be eligible for the de minimis program.
And the Fox Says…: The deadline to file comments to the NPRM is March 15. The ELVS rule is the first of two NPRMs announced by the Biden Administration in September 2024. A second NPRM is expected at a later date and will likely continue to build on CBP’s aggressive multi-pronged strategy. Stay tuned for a more in-depth analysis on the NPRM and its impacts.
4. Forced Labor Enforcement Updates: CIT Case to Challenge Forced Labor Finding, Auto Industry Targeted for Detentions, More Entities Added to UFLPA Entity List, Reports Scrutinize Global Supply Chains, USTR Issues Trade Strategy to Combat Forced Labor
Kingtom Challenges Forced Labor Finding
On December 23, 2024, aluminum extrusions exporter Kingtom Aluminio, a Chinese-owned company based in the Dominican Republic, filed a complaint with CIT to challenge CBP’s forced labor finding, which authorizes CBP to seize the company’s imports of aluminum extrusion and profile products at the port. In filing the suit, the company claims in part that CBP’s issuance of the finding was arbitrary or capricious and that CBP bypassed administrative steps in failing to first issue a Withhold Release Order. See Kingtom Aluminio v. US, CIT # 24-00264.
Auto Industry Targeted for UFLPA Detentions in FY 2025
Significantly, the Uyghur Forced Labor Prevention Act (UFLPA) dashboard statistics for FY 2025 published thus far show that CBP primarily targeted the automotive and aerospace sector, with 1,239 shipments stopped for suspected violation of the UFLPA in December alone, with a total of 2,042 shipments in the first three months of FY 2025. By way of comparison, in the entirety of FY 2024, only 197 shipments in this sector were stopped. This follows scrutiny from US Congress resulting from Sheffield University and Human Rights Watch non-governmental organization (NGO) reports alleging connections to Xinjiang in every part of the auto supply chain. These statistics may reflect a shift in the industries targeted for enforcement, which have historically focused on electronics, apparel and footwear, and industrial and manufacturing materials.
DHS Adds 37 Companies to UFLPA Entity List
On January 14, the US Department of Homeland Security (DHS) announced the addition of 37 companies to the UFLPA Entity List. These entities include companies that grow Xinjiang cotton, manufacture textiles, manufacture inputs for solar modules and the energy industry, and supply critical minerals and metals. The UFLPA Entity List is nearly 150 companies.
Reports Scrutinize Supply Chains for Forced Labor Concerns
Several reports were issued last month discussing supply chains and forced labor risks:
UMASS Amherst Labor Center issued a report covering REI’s published supplier list and alleged connections to forced labor.
Transparentem issued a report covering its investigation into conditions on cotton farms in Madhya Pradesh, India. The report warned that the NGOs could not definitively link the problematic farms to the specific supply chains of brands and retailers.
The Financial Times published a report discussing billions of dollars invested by environmental, social, and governance funds linked to forced labor in Xinjiang.
In its first ever Quadrennial Supply Chain Review, the White House recommended upgrades to trade legislation to strengthen supply chains.
USTR Issues Trade Strategy to Combat Forced Labor
On January 13, USTR issued a trade strategy to combat forced labor that outlines the actions the United States is taking and considering to address forced labor in global supply chains. We will outline the USTR’s strategy in our forthcoming 2025 forced labor guide for global businesses.
And the Fox Says…: Forced labor enforcement has shown no signs of slowing down, and we anticipate that enforcement will remain steady or even increase as the Trump Administration assumes office later this month, particularly due to US Sen. Marco Rubio’s (R-FL) nomination as Secretary of State. Companies in the solar, textile, and apparel industries specifically should review the recent additions to the UFLPA Entity List to confirm whether any entities listed are in their supply chains.
Recent reports have focused on the global supply chains of fashion and apparel brands and critical industries, underscoring the importance for companies in the United States and globally to monitor these reports to ensure their supply chains are not associated with forced labor risks. While companies have been encouraged to release their supplier lists, this comes with some risk, as NGOs have scrutinized the labor practices of publicly disclosed suppliers.
Finally, as we previously discussed, the Kingtom Aluminio CIT litigation joins other cases where importers and affected companies have filed suit against CBP for issues related to forced labor enforcement. As forced labor enforcement efforts intensify, we should continue to expect legal disputes over forced labor allegations in global supply chains. To date, we have not seen a final decision on any of the cases.
5. Mexico Takes Aim at Textile and Apparel Sector With IMMEX Restrictions Focused on E-commerce and Increased Tariffs
Effective December 20, 2024, Mexican President Claudia Sheinbaum Pardo announced a decree imposing significant changes to the import regime for certain apparel and textile products, including tariff increases and restrictions on temporary imports under Mexico’s Manufacturing, Industry, Maquila and Export Services (IMMEX) program.
Mexico applied temporary tariff increases on goods imported into Mexico through April 23, 2026, as follows:
Increase to 35% for 138 Harmonized Tariff Schedule (HTS) codes covering finished textile and apparel products, including items under Chapters 61, 62, 63, and 94.
Increase to 15% for 17 HTS codes covering textile inputs, including items under Chapters 52, 55, 58, and 60.
The decree also imposes restrictions on the temporary importation of certain textile and apparel products under the IMMEX program, which allows companies to defer duties on imported products, raw materials and components, enabling duty-free importation for manufacturing, assembly, export services such as e-commerce sales, or other programs, before re-exporting. The decree imposes restrictions on finished clothing and textile articles classified under HTS Chapters 61, 62, and 63 are excluded from the IMMEX program.
Shortly after the decree was published, Mexico’s Ministry of Economy revised the decree and exempted the IMMEX restriction for six months for goods classified in HTS chapters 61, 62, 63, and subheadings 9404.40 and 9404.90, as long as certain requirements are met.
And the Fox Says…: These changes are part of Mexico’s broader strategy to bolster its domestic textile and apparel industries, tackle compliance challenges under the IMMEX program, shield its textile and clothing sectors from alleged unfair trade practices, and possibly retaliate against the incoming administration’s proposed tariffs. Mexico’s decree could significantly affect textile and apparel importers utilizing the IMMEX program to bring goods into the United States.
Companies should reassess their import strategies, explore alternative sourcing to mitigate tariff impacts, and collaborate with trade compliance experts to navigate new regulations and optimize supply chain efficiency. The AFS team is well-equipped to assist businesses in adapting to these changes, offering expert guidance on global supply chains and duty mitigation.
6. Nippon No-Go: President Uses CFIUS Authority to Block Nippon-US Steel Acquisition, Parties Sue
On January 4, President Biden issued an executive order prohibiting the acquisition of US Steel by Japanese firm Nippon Steel, pursuant to his Committee on Foreign Investment in the United States (CFIUS) authorities. CFIUS is an interagency committee charged with reviewing certain foreign investments in the United States for national security risks. If CFIUS finds that such a risk arises from a given transaction, it can recommend that the president prohibit the transaction. President Biden’s order follows a contentious CFIUS review process of the approximately $14 billion deal, which resulted in a “split recommendation.” Split recommendations to the president result when CFIUS cannot come to agreement whether a transaction creates national security risks. In response to the order, US Steel and Nippon Steel filed multiple lawsuits alleging, among other things, political interference in the process.
And the Fox Says…: CFIUS has entered into uncharted territory. Presidential prohibitions on their own are extremely rare; “split recommendations” by CFIUS are rarer still; and CFIUS litigation is almost unheard of. Regardless of the outcome, this case is likely to significantly shape CFIUS’ evolving role in the national security and investment space for many years to come. The results are unpredictable: buyer (and seller) beware.
7. General License Gives Temporary Sanctions Relief to Post-Assad Syria
The US Department of Treasury’s Office of Foreign Assets Control (OFAC) issued General License 24 on January 6, authorizing for the next six months:
Transactions with governing institutions in Syria following December 8, 2024.
Transactions in support of the sale, supply, storage, or donation of energy, including petroleum, petroleum products, natural gas, and electricity to or within Syria.
Transactions that are ordinarily incident and necessary to processing the transfer of noncommercial personal remittances to Syria, including through the Central Bank of Syria.
The license — which aims to ensure that US sanctions “do not impede essential governance-related services in Syria following the fall of Bashar al-Assad on December 8, 2024” — covers transactions that are otherwise prohibited under Syria Sanctions Regulations, the Global Terrorism Sanctions Regulations, and the Foreign Terrorist Organizations Sanctions Regulations.
There are several important exceptions to the authorization, including most — but, crucially, not all — financial transfers to blocked persons (like Hay’at Tahrir al-Sham, the organization in control of the post-Assad government) and new investments in Syria. Note that comprehensive export controls against Syria are still very much in place. Check out our full client alert here.
And the Fox Says…: Companies and individuals relying on General License 24 must make sure that their activities are in one of the three approved categories and do not fall into one of the exceptions. In the meantime, OFAC’s wait-and-see approach offers temporary but much-needed sanctions relief to the Syrian people.
William G. Stroupe II, Natalie Tantisirirat, Sylvia G. Costelloe, and Matthew Tuchband contributed to this article.
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Beachfront Boundaries: Regulatory Takings Clarified
Jones v. Town of Harwich involved a dispute over the application of the Wetland Protection Bylaw and Regulations in Harwich, Massachusetts (“Wetland Protection Regulations”). In 1958, Lois H. Jones (“Jones”) purchased two distinct lots separated by a private driveway. The lots were known as 5 and 6 Sea Street Extension (“5 Sea Street” and “6 Sea Street”). 5 Sea Street was, and remains, a vacant lot that abuts the ocean. 6 Sea Street is improved with a four-bedroom house. In 1999, Jones sold 6 Sea Street. The record in the case indicated that Jones long intended to construct a single-family dwelling on 5 Sea Street.
In 2011, Jones filed a Notice of Intent with the Harwich Conservation Commission, proposing construction of a single-family residence on 5 Sea Street. In 2012, the Commission issued a denial Order of Conditions. Later that year, the Massachusetts Department of Environmental Protection issued a Superseding Order of Conditions, denying the project under the Massachusetts Wetlands Protection Act. In 2013, the Town of Harwich changed the tax assessment designation associated with 5 Sea Street to “unbuildable” and reduced the assessed valuation from $1,434,500 to $24,000. In 2015,1 the DEP, Jones, and some abutters, reached a settlement, which included a Final Order of Conditions. Nonetheless, the Harwich Conservation Commission maintained its position that Jones’s proposed construction would violate the Wetlands Protection Regulations, as well as the state wetlands regulations, and denied approval.
Jones filed suit against the Town of Harwich in the U.S. District Court for the District of Massachusetts, alleging that the application of the Wetland Protection Regulations to 5 Sea Street constituted a regulatory taking, entitling her to compensation. The Town argued that Jones could only recover if the Wetland Protection Regulations were the “but for” cause of 5 Sea Street being unbuildable. The Town argued that since state wetlands regulations also precluded developing 5 Sea Street, the local Regulations could not be the but for cause of Jones’s harm, and therefore, she could not recover from the Town. The District Court rejected this argument on summary judgment because the record contained evidence that the DEP’s 2015 decision could be amended, and the project might be allowed under state wetland regulations.
Next, the Court applied the cornerstone Penn Central test to determine whether or not the Town’s application of the Wetlands Regulation could constitute a regulatory taking. Penn Central Transportation Co. v. City of New York, 438 U.S. 104, 124 (1978). The factors applied by the Court include: economic impact of the Regulations on the Plaintiffs; the extent to which the Regulations have interfered with distinct investment-backed expectations; and the character of the governmental action.
The District Court found that the significant decrease in the property’s value supported a substantial economic impact as a result of the Town’s Regulations. Additionally, the extent to which the Regulations interfered with investment-backed expectations was not appropriate for summary judgment because the parties presented competing arguments and evidence as to Jones’ intention to develop the property, and the alleged “windfall” that her estate would receive from development. Id., at 6. Finally, the District Court held that the character of the governmental action could be equivalent to a typical taking because the Regulations prevent any structure on the lot despite being generally applicable to all property.
Jones is a helpful reminder that application of local regulations may constitute a regulatory taking.
1 Jones passed away in 2014, but her estate continued her efforts to develop 5 Sea Street.
Appeals Court Shines Light on Solar Panel Protections
Kearsarge Walpole LLC v. Zoning Board of Appeals of Walpole involved a dispute over where a large-scale solar array could be placed in Walpole, Massachusetts. In Kearsarge, a solar developer (Kearsarge), along with Norfolk County Agricultural High School (Norfolk Aggie), and Norfolk County, entered into an agreement to construct a solar facility on the Norfolk Aggie campus, which is located in Walpole’s rural residential zoning district.
Kearsarge applied to the Walpole building commissioner for a building permit. The commissioner denied the permit, deeming the project a nonconforming use under Walpole’s zoning bylaw. The Walpole Planning Board upheld the commissioner’s decision, finding that the project was a nonconforming use and did not qualify for any exception from the Walpole zoning bylaw, which established that large-scale solar facilities be located within certain overlay districts. Kearsarge appealed to the Land Court, arguing that the project was exempt from Walpole’s restrictions pursuant to the “Solar Energy Provision” of G. L. c. 40A, § 3.1 Kearsarge also argued that the project was exempt under the “Education Provision” of G. L. c. 40A, § 3.2
The Land Court granted summary judgment in favor of Kearsarge, reasoning that the board’s decision indeed violated the Solar Energy Provision. However, the Land Court rejected Kearsarge’s assertion that the project constituted an educational use.
The Appeals Court affirmed the Land Court, applying the doctrine set forth in Tracer Lane II Realty, LLC v. Waltham, 489 Mass. 775, 781 (2022). Under Tracer Lane, the Court’s determination hinged on “whether the interest advanced by the ordinance or bylaw outweighs the burden placed on the installation of solar energy systems.” In Tracer Lane, the Court of Appeals ruled that Waltham’s near total ban on solar facilities (except in “one to two” percent of the city’s land area) constituted a violation of the Solar Energy Provision.
Here, Walpole argued that its zoning bylaw (which also restricted solar facilities to less than 2% of the town) was different than Waltham’s law given that the Waltham bylaw amounted to a blanket ban on solar facilities while the Walpole law allowed for expansion of the overlay districts wherein solar facilities were permitted. The Court rejected this argument holding that a town need not impose a blanket ban on solar facilities to violate the Solar Energy Provision. Rather, the Solar Energy Provision prohibits local ordinances that “unduly restrict . . . solar energy systems.” Walpole’s bylaw, by requiring “discretionary zoning relief” in order to construct solar facilities in all but 2% of the city constituted such an undue restriction – especially where expansion of the overlay districts would require an applicant to “petition to amend the Walpole zoning bylaws [by] submit[ing] their proposed amendment to a public hearing and town vote.” This, in the Court’s view was “a significant hurdle.” The Court also rejected Walpole’s argument that the interests advanced by its bylaw (protecting agriculture) promoted public health, safety, and welfare sufficient to justify that significant burden on solar development. According to the Court, “[t]he record . . . [did] not support a conclusion that a bylaw this stringent is necessary to protect the public health, safety, or welfare interests that Walpole seeks to promote.”
Kearsarge is another instance where the Appeals Court makes clear that Massachusetts courts will not hesitate to reign in local authority in the interest of enforcing the Solar Energy Provision.
1 Pursuant to Mass. Gen. Laws Ann. c. 40A, § 3, Ninth Paragraph, “[n]o zoning ordinance or by-law shall prohibit or unreasonably regulate the installation of solar energy systems or the building of structures that facilitate the collection of solar energy, except where necessary to protect the public health, safety or welfare.”
2 Under Mass. Gen. Laws Ann. c. 40A, § 3, Second Paragraph, “[n]o zoning ordinance or by-law shall regulate or restrict the interior area of a single-family residential building nor shall any such ordinance or by-law prohibit, regulate or restrict the use of land or structures for religious purposes or for educational purposes . . .”
New Extended Producer Responsibility Requirements for Companies Selling Tobacco and Nicotine Products in Single-Use Packaging
A wave of new “Extended Producer Responsibility” or “EPR” programs is beginning to impact companies placing packaged products, including tobacco products, on the market in U.S. states, including California, Colorado, Maine, Minnesota, and Oregon.
The five EPR programs for packaging enacted thus far have different facets. However, at their core, each of the EPR programs requires companies that sell packaged products (with some limited exceptions) to join a newly formed, state-recognized organization (typically called a “Producer Responsibility Organization” or “PRO”) and pay annual dues based on the amount and type of packaging placed on the market in that state. California’s PRO, for one, must collect $500,000,000 annually from producers of covered products, like single-use packaging. Producers also will need to eventually meet certain sustainability goals for single-use packaging, such as ensuring compostability or recyclability of packaging or meeting minimum post-consumer recycled content targets. What is more, the EPR programs encompass not just primary packaging that directly contacts a good, but often shipping and display packaging as well.
As noted above, the EPR program obligations typically fall on the “producer” of the covered product. In the case of single-use packaging, the states have generally defined producer to mean the brand owner that places a packaged good on the market. For example, an e-cigarette or nicotine pouch company that sells or distributes its branded (tobacco-flavored) e-cigarette or pouch in California would be considered the “producer” of any single-use packaging associated with the finished product, even if the e-cigarette or pouch company did not manufacture the packaging itself. Accordingly, it is the companies marketing the finished products, not packaging companies, that will need to register as producers of tobacco product packaging in the states with packaging EPR programs.
Certain state EPR programs – including Colorado’s and Minnesota’s – also include “paper products” as a covered product. While tobacco companies making roll-your-own (RYO) papers and other such paper-based products may be able to avail themselves of certain exemptions, they must assess this on a case-by-case basis.
In this regard, the state EPR programs include various exemptions for producers and covered products, such as exemptions for small-volume producers and exemptions for certain types of packaging, like infant formula packaging. However, the existing EPR laws do not include any explicit exemptions for tobacco product packaging or paper used in tobacco products. Accordingly, absent another applicable exemption, tobacco product manufacturers are likely to meet the producer definition under the state EPR laws, and thus will need to register with applicable state PROs, pay dues based on the product packaging sold in the state, and eventually meet certain goals for the packaging.
In complying with the state EPR schemes, the tobacco and nicotine product industries can expect to face not only supply chain challenges (e.g., the availability of post-consumer recycled content), but also possibly significant regulatory hurdles under the Family Smoking Prevention and Tobacco Control Act. Under the EPR programs, producers may need to make changes to product packaging to meet sustainability targets. Changes to the container-closure system for a legally marketed tobacco product may well require a new premarket authorization from the U.S. Food and Drug Administration (FDA), which can be a costly and timely endeavor.
In terms of implementation timelines, the states will be rolling out their EPR requirements on differing schedules. The deadline for producers to register with Colorado’s PRO occurred on October 1, 2024, while in California, a deadline to register with the PRO has not been established, but the state has proposed a rule that would require producers to register with CalRecycle later this year. Eventually, producers of covered products will be prohibited from selling in states with EPR programs unless they are registered and participating in the programs.
EPR programs for packaging are likely to spread. Numerous other states have considered or are now considering EPR bills, including New York and New Jersey.
Biden Administration Releases Executive Order Advancing Artificial Intelligence
Highlights
The Biden administration’s latest executive order represents a transformative step in the U.S.’ approach to AI, integrating innovation with sustainability and security
Businesses will have an opportunity to align with this strategic vision, contribute to an ecosystem that will sustain U.S. leadership, and encourage economic competitiveness
The principles outlined in the executive order will guide federal agencies to ensure AI infrastructure supports national priorities while fostering innovation, sustainability, and inclusivity
On Jan. 14, 2025, President Biden issued an executive order on advancing the United States’ position as a leader in the creation of artificial intelligence (AI) infrastructure.
AI is a transformative technology with critical implications for national security and economic competitiveness. Recent advancements highlight AI’s growing role in industries and areas including logistics, military capabilities, intelligence analysis, and cybersecurity. Developing AI domestically could be essential in preventing adversaries from exploiting powerful systems, maintaining national security, and avoiding reliance on foreign infrastructure.
The executive order posits that to secure U.S. leadership in AI development, significant private sector investments are needed to build advanced computing clusters, expand energy infrastructure, and establish secure supply chains for critical components. AI’s increasing computational and energy demands necessitate innovative solutions, including advancements in clean energy technologies such as geothermal, solar, wind, and nuclear power.
The executive order notes:
National Security and Leadership
AI infrastructure development should enhance U.S. national security and leadership in AI, including collaboration between the federal government and the private sector; ensuring safeguards for cybersecurity, supply chains, and physical security; and managing risks from future frontier AI capabilities.
The Secretary of State, in coordination with key federal officials and agencies, will create a plan to engage allies and partners in accelerating the global development of trusted AI infrastructure. The plan will focus on advancing collaboration on building trusted AI infrastructure worldwide.
Economic Competitiveness
AI infrastructure should also strengthen U.S. economic competitiveness by fostering a fair, open, and innovative technology ecosystem by supporting small developers, securing reliable supply chains, and ensuring that AI benefits all Americans.
Clean Energy Leadership
The U.S. aims to lead in operating AI data centers powered by clean energy to help ensure that new data center electricity demands do not take clean power away from other end users or increase grid emissions. This involves modernizing energy infrastructure, streamlining permitting processes, and advancing clean energy technologies, ensuring AI infrastructure development aligns with new clean electricity generation.
The Department of Energy, in coordination with other agencies, will expand research and development efforts to improve AI data center efficiency, focusing on building systems, energy use, cooling infrastructure, software, and wastewater heat reuse. A report will be submitted to the president with recommendations for advancing industry-wide efficiency, including innovations like server consolidation, hardware optimization, and power management.
The Secretary of Energy will provide technical assistance to state public utility commissions on rate structures, such as clean transition tariffs, to enable AI infrastructure to use clean energy without raising electricity or water costs unnecessarily.
Cost and Community Considerations
Because building AI in the U.S. requires enormous private-sector investments, the AI infrastructure must be developed without increasing energy costs for consumers and businesses. Companies participating in AI development, clean energy technology, and grid and semiconductor development can work with federal agencies to strategically further these initiatives that align with broader ethical and operational standards.
The Secretaries of Defense and Energy will each identify at least three federally managed sites suitable for leasing to non-federal entities for the construction and operation of frontier AI data centers and clean energy facilities. These sites should aim to be fully permitted for construction by the end of 2025 and operational by the end of 2027.
Priority will be given to locations that 1) have appropriate terrain, land gradients, and soil conditions for AI data centers; 2) minimize adverse impacts on local communities, natural or cultural resources, and protected species; and 3) are near communities seeking to host AI infrastructure, supporting local employment opportunities in design, construction, and operations.
Worker and Community Benefits
AI infrastructure projects should uphold high labor standards, involve close collaboration with affected communities, and prioritize safety and equity, ensuring the broader population benefits from technological innovation.
The Director of the Office of Management and Budget, in consultation with the Council on Environmental Quality, will evaluate best practices for public participation in siting and energy-related infrastructure decisions for AI data centers. Recommendations will be made to the Secretaries of Defense and Energy, who will incorporate these into their decision-making processes to ensure effective governmental engagement and meaningful community input on health, safety, and environmental impacts.
Relevant agencies will prioritize measures to keep electricity costs low for households, consumers, and businesses when implementing AI infrastructure on Federal sites.
Takeaways
The U.S. is committed to enabling the development and operation of AI infrastructure, including data centers, guided by five key principles: 1) national security and leadership; 2) economic competitiveness; 3) leadership in clean energy; 4) cost and community consideration; and 5) workforce and community benefits.
The Biden administration’s latest initiative aims to foster a competitive technology ecosystem, enable small and large companies to thrive, keep electricity costs low for consumers, and ensure that AI infrastructure development benefits workers and their local communities.
How Employers Can Aid Employees Impacted by the Los Angeles Wildfires
Over the past two weeks, wildfires have caused substantial loss and damage to homes and communities in Los Angeles, California, and the surrounding areas. In the wake of such devastation, employers may seek opportunities to provide financial assistance to impacted employees. Fortunately, the Internal Revenue Service (IRS) has outlined various ways for employers to provide much-needed assistance to employees impacted by natural disasters like the wildfires, including tax-free qualified disaster relief payments, leave donation programs, and other tax-efficient options.
In Depth
QUALIFIED DISASTER RELIEF PAYMENTS
Generally, payments made by an employer to, or for the benefit of, an employee must be included in the employee’s taxable gross income unless excluded under another provision. One such exclusion is “qualified disaster relief payments” under Section 139 of the Internal Revenue Code. Employers can make “qualified disaster relief payments” to employees who are victims of many disasters, including the Los Angeles wildfires, on a tax-free basis.
Qualified disaster relief payments include both reimbursements and cash advances and are not treated as taxable income/wages subject to payroll taxes (e.g., Federal Insurance Contributions Act and Federal Unemployment Tax Act) for employees. In addition, employers can deduct these payments as ordinary and necessary business expenses.
A payment qualifies as a “qualified disaster relief payment” if the following requirements are satisfied:
There has been a “qualified disaster” (e.g., a federally declared disaster issued by the president of the United States).
The payment is intended to cover reasonable and necessary personal, family, living, or funeral expenses, or reasonable and necessary expenses incurred for repairing or replacing a personal residence or its contents, provided the expenses were incurred as a result of the qualified disaster and are not covered by insurance or other resources.
The payment is not income replacement (i.e., a payment for lost wages, lost business income, or unemployment benefits).
Qualified disaster relief payments do not need to be paid pursuant to a plan document. In fact, a formal written plan document is not required or recommended. Nevertheless, given the benefits of tax-free status for qualified disaster relief payments, employers that choose to provide such payments should consider adopting an administrative process to validate such payments meet the necessary legal requirements. Such a process can include a short application form for assistance that validates the disaster for which relief is sought, contains an affirmative statement from the employee that the requested funds are necessary for expenses associated with the Los Angeles wildfires, and confirms that such expenses are not reimbursable by insurance.
In addition, employees are not required to account for actual expenses in order to qualify for the exclusion, provided that the amount of the payments can be reasonably expected to be commensurate with the expenses incurred. Although substantiation is not required, a simple application/attestation statement from the employee is recommended to provide the employer with assurance regarding its compliance with the legal requirements for offering these payments on a tax-free basis.
LEAVE DONATION PROGRAMS
Since the wildfires have been federally declared a natural disaster, an employer may establish “leave banks” for employees to donate accrued but unused leave to other employees who may be affected by the wildfires. Employees who donate their accrued leave are exempt from taxes on those amounts, but those who receive the leave will incur payroll and income taxes for the time given. Employer-sponsored leave banks programs must be written and must meet certain requirements under IRS Notice 2006-59 to receive favorable tax treatment for both the donor and recipient employee.
RETIREMENT PLAN OPTIONS
An employer-sponsored defined contribution retirement plan can provide additional relief to “qualified individuals” impacted by a qualified disaster. A “qualified individual” is an individual whose principal residence during the incident period of any qualified disaster is in the qualified disaster area and the individual has sustained an economic loss by reason of that qualified disaster. Employer-provided retirement plans can provide the following options:
Distributions up to $22,000 per federally declared disaster, with no early withdrawal penalty. Such distributions must be taken within 180 days of the date the disaster was declared.
Increased maximum loan amounts equal to 100% of a participant’s account balance, up to $100,000.
Extended repayment period of one year for current outstanding loans (as of date such natural disaster was declared). In this case, employers can extend repayment of loans to January 8, 2026.
Employers will need to amend their retirement plans if their plans do not already have such disaster-related provisions. Such amendments must be made by the end of this year for employees to take advantage of these provisions.
SUMMARY
Employers seeking to provide financial assistance to employees should consider the various tax-advantaged programs made available by the IRS. Since the requirements of each program vary, it is important that employers properly structure these programs to comply with the necessary legal requirements.
Climate Reporting in 2025: Looking Ahead
In this alert, we reflect on recent climate reporting updates and analyze expectations for 2025 that are relevant for international businesses.
The global landscape is becoming increasingly uncertain in relation to climate reporting following litigation and a change of management at the SEC in the U.S., an expected rise of Blue State climate reporting requirements, combined with the UK and other jurisdictions’ adoption of the global standard setter ISSB’s climate reporting standards and the EU’s implementation of the Corporate Sustainability Reporting Directive (“CSRD”), amongst other initiatives. A worldwide rollout of climate change disclosure requirements has always been uneven, but these uncertainties create the potential for even greater fragmentation.
Businesses should carry out regular horizon scanning to keep abreast with the range of legislation and regulation that could impact them.
California Climate Disclosure Law 2024 Year End Developments
As we noted in detail in our prior Client Alerts, California Climate Disclosure Laws – New Developments, Old Timelines and California – First State to Enact Climate Reporting Legislation, the California climate disclosure laws (SB 253 and SB 261) were passed in October 2023 and amended by SB 219 in September 2024. SB 253 requires covered entities to disclose their Scope 1 and Scope 2 greenhouse gas (GHG) emissions by an unspecified date in 2026 for the prior fiscal year and by an unspecified date in 2027 for Scope 3 emissions, and SB 261 requires covered entities to report on their climate-related financial risks on or before January 1, 2026. California Air Resources Board (CARB) is required to promulgate regulations by July 1, 2025, to implement SB 253 (but is not required to promulgate implementing regulations for SB 261).
On December 5, 2024, CARB issued an enforcement notice to advise entities required to comply with SB 253 that CARB will exercise its enforcement discretion for the first reporting cycle in 2026 if the reporting entity demonstrates good faith efforts to comply with the requirements of SB 253. More specifically, a covered entity may disclose its Scope 1 and Scope 2 GHG emissions based on information the entity already possesses or is already collecting and CARB will not take enforcement action against any entity that makes incomplete Scope 1 and Scope 2 GHG emissions disclosures in 2026 if the entity makes a good faith effort to retain all data relevant to its GHG emissions reporting for its prior fiscal year.
To better inform CARB’s implementation of SB 253 and SB 261, on December 16, 2024, CARB issued a solicitation to gather responses from stakeholders to 13 questions. CARB’s questions cover applicability, including what should constitute “doing business in California,” how to minimize duplication of reporting efforts for entities required to report under other programs, whether to standardize certain aspects of Scope 1, 2 and 3 reporting under SB 253 and what is an appropriate timeframe within a reporting year for biennial reporting under SB 261, among others. CARB also expressly opened the solicitation to any additional feedback that should be considered by CARB in its implementation of SB 253 and SB 261. The comment period is open until February 14, 2025 and comments can be submitted to CARB here.
SEC Developments
It is no secret that the incoming Republican Administration has been skeptical of the federal government’s climate change measures, which brings further uncertainty to the SEC’s new climate change rules. To be sure, there was already uncertainty surrounding litigation in the U.S. Court of Appeals for the 8th Circuit over the rules’ validity.
The new SEC rules for many companies were scheduled to take effect for their 2025 fiscal years, resulting in disclosure in annual reports on Forms 10-K and 20-F filed in 2026. The SEC has voluntarily stayed the effectiveness of its new rules in light of the litigation. Since certain U.S. filers will be subject to the rules based on their operations this year if the stay is lifted, the SEC will undoubtedly announce a delay in the rules’ effective dates of at least one year even if the SEC is successful in the 8th Circuit.
The new Administration will have a few options. For example:
it can await the outcome of the litigation before deciding what, if anything, to do with the rules;
it could decide to leave the rules intact in light of domestic and international pressure. As the SEC clarified in adopting the rules that disclosure is triggered only by “material climate risks,” many U.S. public companies may not have to provide disclosure under the new rules;
it could modify the rules to eliminate more controversial elements but otherwise leave the rules intact; or
the new Administration could decide to vacate the rules.
The President-Elect had been critical of climate change measures in his campaign, but not all members of his team are necessarily against all climate change measures, there is international pressure to have some level of disclosure, and therefore it is challenging to make any general, sweeping prediction. We will potentially see some additional color on the President-Elect’s plans when the nominee for SEC Chairman testifies at Senate confirmation hearings.
We recommend that companies continue to prepare for the new requirements, perhaps at a slower pace. Even if the courts invalidate the SEC’s rules, or the SEC vacates them, certain states in addition to California are likely to ramp up their own requirements in order to fill the gap, and institutional investors may strengthen their proxy voting guidelines on the subject. Companies with operations in the EU may be subject to those disclosure requirements, which overlap significantly with the SEC’s requirements.
EU Unrest on Corporate Sustainability Reporting
The first reports under the CSRD will be published in 2025. There is a phased scoping of CSRD and the first reports, predominantly by EU companies that had been subject to the Non-Financial Reporting Directive, will be read with great interest to review how they have approached the CSRD’s complex double materiality assessment and the number of sustainability topics reported on, which businesses in scope of later phases of CSRD may be able to leverage before making their own reports. Challenges remain with CSRD reporting as further guidance and expectations are published on a piecemeal basis, and national transposing law of CSRD remains incomplete in a number of EU jurisdictions.
Businesses with international headquarters that may be subject to the 2028 year CSRD reporting (to be reported on in 2029) should be aware that there is a consultation expected imminently in 2025 on the global standards for such reporting. The signals sent so far suggest the potential availability of an opt-out mechanism for global businesses, enabling them to focus disclosures on the EU footprint of products and services, rather than on global operations. For further information, please see here: A Step Closer to CSRD’s Non-EU Group Reporting Standards.
There is also political turmoil in the EU that could impact climate reporting requirements in the EU; for example, the German Chancellor, Olaf Scholz, has called for a two-year delay to CSRD (despite the timeline having already been triggered). Furthermore, there have been calls for a simplification of corporate sustainability obligations for EU businesses, with the EU currently considering simplifying various existing sustainability-related regulations into a “single omnibus regulation” (“Omnibus Regulation”). This is being led by the European Commission President, Ursula von der Leyen, after criticism that the sustainability legislation is impacting the EU’s competitiveness. Proposals on the Omnibus Regulation, alongside other streamlining proposals for businesses, are expected to be proposed by the European Commission by mid-2025.
Businesses are recommended to keep careful track of CSRD developments and how it may shape their own approach to reporting or trigger the need to re-visit key areas.
UK – and Global – Momentum Towards ISSB
The UK government has been openly supportive of the International Sustainability Standards Board (“ISSB”) International Financial Reporting Standards (“IFRS”). On 18 December 2025, the UK’s Sustainability Disclosure Technical Advisory Committee published final recommendations to the UK government to endorse the IFRS S1 General Requirements for Disclosure of Sustainability-related Financial Information and IFRS S2 Climate-related Disclosures for used in the UK, with some minor amendments.
A consultation is expected in Q1 2025, with any eventual roll out of the ISSB standards likely to mirror the phased implementation of TCFD, with UK-listed companies being subject to the requirements first.
There is broader global momentum towards ISSB adoption – including in Canada, Hong Kong and Japan. With the fragmented political landscape on ESG and competing sustainability regulatory requirements, it is likely that 2025 sees the continued rise of ISSB and it increasingly establishing itself as a common global standard following it subsuming responsibility for TCFD in 2023.